CVR Energy Annual Report 2012

Plain-text annual report

Corporate Proﬁle CVR Energy, Inc. (NYSE: CVI) Headquartered in Sugar Land, Texas, CVR Energy, Inc. is a diversiﬁed holding company primarily engaged in the petroleum reﬁning and nitrogen fertilizer manufacturing industries through its holdings in two limited partnerships, CVR Reﬁning, LP and CVR Partners, LP, which own and operate facilities in the Midcontinent. CVR Energy, through its subsidiaries, serves as the general partner of and owns a majority interest in CVR Reﬁning and CVR Partners. CVR Energy became a holding company in early 2013 after it took its petroleum business public in the largest initial public offering of a master limited partnership to date. CVR Reﬁning began trading on the New York Stock Exchange on Jan. 17, 2013, under the ticker “CVRR.” This IPO, which is similar to the variable rate structure of CVR Partners, unlocked the value of our petroleum business. The CVR Energy portfolio of companies employs approximately 1,100 employees and is driven by strong operating performance, a commitment to safe, reliable and environmentally responsible operations and products, and an experienced management team that remains focused on building value for stockholders. CVR Reﬁning, LP (NYSE: CVRR) CVR Reﬁning is an independent downstream energy limited partnership formed by CVR Energy to own, operate and grow its reﬁning and related logistics businesses. CVR Reﬁning’s petroleum business includes a 115,000 barrel per day complex full coking, medium-sour crude oil reﬁnery operated by Coffeyville Resources Reﬁning & Marketing in Coffeyville, Kan., a 70,000 barrel per day medium complexity crude oil reﬁnery operated by Wynnewood Reﬁning Company in Wynnewood, Okla., approximately 350 miles of pipelines, more than 125 crude oil transports, a network of strategically located crude oil gathering tank farms, and more than six million barrels of owned and leased crude oil storage capacity. CVR Reﬁning’s crude gathering business, Coffeyville Resources Crude Transportation, operates a 50,000 barrel per day, crude oil gathering and trucking system located in Bartlesville and Wynnewood, Okla., and Plainville and Winﬁeld, Kan. The gathering business purchases crude from independent crude oil producers in Kansas, Missouri, Oklahoma, Nebraska and Texas. CVR Partners, LP (NYSE: UAN) CVR Partners is a growth-oriented limited partnership formed by CVR Energy to own, operate and grow its nitrogen fertilizer business. CVR Partners’ fertilizer business includes Coffeyville Resources Nitrogen Fertilizers, a wholly owned subsidiary that owns and operates a nitrogen fertilizer manufacturing facility in Coffeyville, Kan. The plant produces ammonia and urea ammonium nitrate (UAN) fertilizers and is the only such operation in North America that uses a petroleum coke gasiﬁcation process to make hydrogen, a key ingredient in its manufacturing process, and produces about 5 percent of total UAN demand in the U.S. In 2012, Coffeyville Resources Nitrogen Fertilizers produced 124,600 tons of ammonia and 643,800 tons of UAN available for sale. On the cover: A section of the CVR Partners nitrogen fertilizer facility in Coffeyville, Kan. Inside cover: CVR Reﬁning’s 70,000 barrel per day reﬁnery in Wynnewood, Okla. Headquartered in Sugar Land, Texas, CVR Energy, Inc. is a diversiﬁed holding company primarily engaged in the petroleum reﬁning and nitrogen fertilizer manufacturing industries through its holdings in two limited partnerships, CVR Reﬁning, LP and CVR Partners, LP. Financial Highlights FINANCIAL DATA (Dollars in millions except per share data and as otherwise indicated) Years ended Dec. 31, Net Sales Operating Income Net Income Diluted Earnings Per Share Total Assets Stockholders’ Equity 2012 2011 2010 $ 8,567.3 $ 5,029.1 $ 4,079.8 1,034.9 566.6 $ 378.6 $ 345.8 $ 4.33 $ 3.94 $ $ 93.1 14.3 0.16 $ 3,610.9 $ 3,119.3 $ 1,740.2 1,525.2 1,151.6 689.6 Net Cash Provided by Operating Activities $ 762.6 $ 278.6 $ 225.4 Net Cash Used in Investing Activities Net Cash Provided by (Used in) Financing Activities (210.7) (44.3) (674.4) 584.1 (31.3) (31.0) Employees 1,091 996 695 PETROLEUM BUSINESS Net Sales Operating Income Total Crude, Feed & Blendstocks Throughput (Barrels per day) Gross Proﬁt Per Crude Oil Throughput Barrel NITROGEN FERTILIZER BUSINESS Net Sales Operating Income Ammonia (Net available for sale – thousands of tons) Ammonia Pricing (Plant gate) (Dollars/ton) UAN Production (Thousands of tons) UAN Pricing (Plant gate) (Dollars/ton) $ 8,281.5 $ 4,751.8 $ 3,903.8 1,012.5 180,147 17.42 465.7 108,933 13.41 104.6 123,715 3.54 $ 302.3 $ 302.9 $ 180.5 115.8 124.6 613 643.8 303 136.2 116.8 579 714.1 284 20.4 155.6 361 578.3 179 2 Dear Fellow Dear Fellow Stockholders Stockholders A MESSAGE FROM JACK LIPINSKI Strategy moves us forward, but ultimately we are measured by our results. I am proud to say that our results were impressive in 2012. We generated record net income of $378.6 million, or $4.33 per fully diluted share, on revenues of $8.6 billion. Our full year operating income was $1,034.9 million, which is nearly double our 2011 operating income of $566.6 million. Our outstanding results were driven by continued investment in our petroleum business, strong operating performance across all of our business units and attractive market conditions. In 2013, we are sharing this success with you, our stockholders, by initiating quarterly dividends. OUR ACCOMPLISHMENTS We achieved several notable milestones in 2012 and early 2013. These achievements include: ■ THE LARGEST INITIAL PUBLIC OFFERING OF A MASTER LIMITED PARTNERSHIP TO DATE. Similar to the variable rate structure of our nitrogen fertilizer business, we placed our petroleum business into a master limited partnership (MLP), which went public in January 2013 in the largest initial public offering (IPO) of a MLP to date. CVR Reﬁning, LP trades on the New York Stock Exchange under the symbol “CVRR.” This IPO unlocked the value of our petroleum business, which beneﬁts our stockholders. CVR Energy, through its subsidiaries, serves as the general partner of and owns a majority interest in CVR Reﬁning. 3 3 ADJUSTED NET INCOME* $660.1 $345.7 $41.1 ‘10 ‘11 ‘12 In millions of U.S. dollars * A reconciliation of Adjusted Net Income to Net Income Attributable to CVR Energy Stockholders can be found on page 11 of this report. Our 2012 ﬁnancial results reafﬁrm the strength of our businesses. 4 Left: The Reﬁnery Operations Control Center at the Coffeyville reﬁnery in Coffeyville, Kan. Right: The crude unit vacuum tower at the Wynnewood reﬁnery. ■ SPECIAL CASH DIVIDEND. Our strong returns throughout 2012 coupled with proceeds from the CVR Reﬁning IPO allowed us to build signiﬁcant cash on our balance sheet. Earlier this year, we were pleased to return cash to stockholders in the form of a special cash dividend. The CVR Energy Board of Directors approved a special dividend of $5.50 per share in January, which was paid on Feb. 19, 2013, to stockholders of record on Feb. 5, 2013. ■ NEW QUARTERLY CASH DIVIDEND POLICY. Based on strong anticipated cash ﬂows from CVR Partners, LP and CVR Reﬁning, LP, we initiated a new quarterly cash dividend policy. This policy was adopted by the CVR Energy Board of Directors in early January 2013. The company’s initial quarterly dividend is expected to be 75 cents per share, or $3.00 per share on an annualized basis, which the company plans to begin paying in the second quarter of 2013. ■ STRENGTHENED BALANCE SHEET AND INCREASED FINANCIAL FLEXIBILITY. In October, as we prepared for our CVR Reﬁning IPO, we reﬁnanced our corporate debt through the issuance of $500 million in new unsecured notes. These notes replaced our ﬁrst and second lien senior secured notes and provided a signiﬁcant improvement in our interest rates. We also entered into an amended and restated asset-backed credit facility with an aggregate principal amount of up to $400 million. These initiatives signiﬁcantly lowered our borrowing costs. CASH DIVIDENDS CVR Energy adopted a new quarterly cash dividend policy in 2013. ■ FULL INTEGRATION OF THE WYNNEWOOD REFINERY. 2012 marks the inclusion of the ﬁrst full year of results from the Wynnewood reﬁnery, which was acquired in December 2011. As expected, this strategic acquisition has provided a meaningful increase in the scale and diversity of our reﬁning operations. We now have 185,000 barrels per day of combined crude processing capacity at two locations in the attractive and historically underserved PADD II, Group 3 region. Further capitalizing on the synergies between the two reﬁneries, we expanded our crude gathering operations in Oklahoma and opened a new crude gathering ofﬁce in Wynnewood. Also, Wynnewood now enjoys deeper discounts on crude purchases. 5 5 Wynnewood reﬁnery and employees. Our commitment to our newest reﬁnery is impressive as well. We have invested approximately $200 million to repair, upgrade and install new equipment and improve the environmental, health and safety performance of the Wynnewood reﬁnery. Part of this investment includes a $102 million major scheduled turnaround that was completed in the 2012 fourth quarter. We are seeing the beneﬁts of our investment in 2013. During the ﬁrst quarter of 2013, the Wynnewood reﬁnery achieved record processing rates surpassing its 70,000 barrel per day nameplate capacity. ■ CONTINUED GROWTH IN OUR CRUDE OIL GATHERING AND LOGISTICS BUSINESS. In 2012, our crude gathering business continued its year-over- year growth with an average of 46,000 barrels per day gathered for the year. Our crude gathering business also set a new record in 2012 with an average of approximately 48,000 barrels per day gathered in the fourth quarter. These locally gathered barrels provide an important cost advantage to our Coffeyville and Wynnewood reﬁneries. ■ COMPLETING VALUE-ADDED CAPITAL PROJECTS IN OUR FERTILIZER SEGMENT. CVR Partners completed its $130 million urea ammonium nitrate (UAN) plant expansion at its Coffeyville fertilizer facility in February 2013. The plant now has the ﬂexibility to convert all ammonia production into UAN, which sells at a premium to ammonia. The expansion increases the plant’s annual production capacity to more than one million tons of UAN, which is approximately 50 percent higher than previous levels. In 2012, CVR Partners completed the construction of its fertilizer storage and distribution facility in Phillipsburg, Kan. This strategically located facility allows CVR Partners to store product and take advantage of the historical arbitrage between the higher price planting season and the lower price ﬁll season. CVR Partners will look to capitalize on more organic growth projects in the future. 6 Our commitment to our newest reﬁnery is impressive... we have invested approximately $200 million to repair, upgrade and install new equipment and improve the environmental, health and safety performance of the Wynnewood reﬁnery. OPERATIONAL RESULTS Our 2012 ﬁnancial results reafﬁrm the strength of our businesses. The signiﬁcant historical capital investments we have made to upgrade and modernize our facilities further paid off for us this past year as we were able to take advantage of strong market conditions present in both of our business segments. PETROLEUM BUSINESS Our reﬁning operations were positively impacted by strong crack spreads, high operating throughputs and access to attractively priced crudes. Both reﬁneries are located near Cushing, Okla., the home of one of the largest crude oil trading and storage hubs in the United States and the hub through which we supply our non-gathered barrels to our reﬁneries. Our one million barrels of owned tankage and three million barrels of leased storage at Cushing give us the ﬂexibility to beneﬁt from the wide range of crudes available at this location. Our petroleum business, which includes the Coffeyville and Wynnewood reﬁneries, reported 2012 operating income of $1,012.5 million on net sales of $8,281.5 million, a signiﬁcant increase from operating income of $465.7 million on net sales of $4,751.8 million for the full year 2011. Adjusted petroleum EBITDA was $1,178.9 million for the full year 2012 versus $580.9 million for 2011. (A reconciliation of adjusted EBITDA to segment operating income can be found on page 12 of this report.) Our tremendous gains in our petroleum businesses in 2012 were achieved despite the expense and decreased production from a major planned turnaround at the Wynnewood reﬁnery and the completion of the second phase of a major planned turnaround at the Coffeyville reﬁnery. The next major turnaround for the Coffeyville reﬁnery will be a bifurcated turnaround scheduled for the fall of 2015 and the spring of 2016. Wynnewood’s next scheduled major turnaround will occur in the fall of 2016. 7 48,000 BPD Our crude gathering business gathered a record 48,000 barrels per day in the 2012 fourth quarter. Top: CVR Partners’ recently expanded urea ammonium nitrate plant. Bottom: CVR Partners’ nitrogen fertilizer facility. Our 2012 record-setting performance could not have been possible without the dedication of our employees. NITROGEN FERTILIZER BUSINESS Financial performance for the fertilizer business was steady throughout 2012. CVR Partners reported 2012 operating income of $115.8 million on net sales of $302.3 million, compared to 2011 operating income of $136.2 million on net sales of $302.9 million. Full year 2012 adjusted EBITDA for the fertilizer business was $148.2 million compared to 2011 adjusted EBITDA of $162.6 million. In 2012, the fertilizer plant produced 124,600 tons of ammonia and 643,800 tons of UAN available for sale. (A reconciliation of adjusted EBITDA to segment operating income can be found on page 12 of this report.) CVR Partners’ cumulative cash distributions paid or declared for the 2012 full year were $1.81 per common unit, which exceeded the company’s full year distribution guidance of $1.70 to $1.80 per common unit. CVR Energy owns approximately 70 percent of the common units of CVR Partners, and therefore receives a proportional amount of distributions from CVR Partners. CVR Partners’ solid results in 2012 were achieved despite the downtime and expense associated with a major scheduled turnaround at the fertilizer plant in the 2012 fourth quarter. The fertilizer plant undergoes an approximate two-week turnaround every two years. The next turnaround is expected to occur in the fall of 2014. UAN EXPANSION The UAN plant expansion increases annual production capacity by 50 percent. STOCKHOLDER CHANGES On May 4, 2012, afﬁliates of Icahn Enterprises L.P. completed a tender offer for the outstanding shares of CVR Energy common stock. As a result of the tender and subsequent purchases, Icahn Enterprises and its afﬁliates own approximately 82 percent of the outstanding shares of CVR Energy common stock. The entire CVR Energy management team was retained after the stock purchase and remains in place today. 8 ADJUSTED PETROLEUM EBITDA* ADJUSTED NITROGEN FERTILIZER EBITDA* $1,178.9 $580.9 $142.3 $154.7 $109.1 $162.6 $148.2 $129.9 $70.8 $52.6 ‘08 ‘09 ‘10 ‘11 ‘12 ‘08 ‘09 ‘10 ‘11 ‘12 In millions of U.S. dollars In millions of U.S. dollars * Adjusted EBITDA is a non-GAAP ﬁnancial measure which can be useful in understanding CVR Energy’s businesses. For a more complete discussion and reconciliation of Adjusted EBITDA to operating income by segment, see the end note on page 12 of this report. We will continue to look for opportunities that provide long-term earnings growth for our stockholders. 9 Left: An employee checks the product level in a holding tank at the Wynnewood reﬁnery. Right: The continuous catalytic reforming unit at the Coffeyville reﬁnery. LOOKING AHEAD Our 2012 record-setting performance could not have been possible without the dedication of our employees. Their commitment to achieving our goals provides us with a strong foundation for growth in the years to come. The management team at CVR Energy greatly appreciates the support received from Chairman Carl C. Icahn and his team at Icahn Enterprises in helping the company reach its objectives. Their conservative approach to leverage, willingness to grow our businesses and continued support of management initiatives has allowed us to outperform our peers and grow stockholder value. With the recent CVR Reﬁning IPO, CVR Energy is now a diversiﬁed holding company primarily engaged in the petroleum reﬁning and nitrogen fertilizer manufacturing industries through its holdings in CVR Partners and CVR Reﬁning. Moving forward, we will continue to look for opportunities that provide long-term earnings growth for our stockholders. As always, thank you for your support of and belief in our company. Respectfully, JOHN J. LIPINSKI President and Chief Executive Ofﬁcer April 2013 10 In this report, we refer to “Adjusted Net Income.” Discussions and reconciliations for how we arrived at these measures follow: FROM PAGE 4 – ADJUSTED NET INCOME Use of Non-GAAP Financial Measures To supplement the actual results in accordance with GAAP for the applicable periods, the company also uses non-GAAP measures as discussed below, which are reconciled to GAAP-based results. These non- GAAP ﬁnancial measures should not be considered an alternative for GAAP results. The adjustments are provided to enhance an overall understanding of the company’s ﬁnancial performance for the applicable periods and are indicators management believes are relevant and useful for planning and forecasting future periods. Adjusted Net Income is not a recognized term under GAAP and should not be substituted for net income as a measure of our performance. Management believes that adjusted net income provides relevant and useful information that enables external users of our ﬁnancial statements, such as industry analysts, investors, lenders and rating agencies to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall ﬁnancial, operational and economic performance. Below is a reconciliation of net income to adjusted net income for the years ended December 31, 2012, 2011 and 2010: Year ended December 31, (Unaudited) (In millions, except per share data) 2012 2011 2010 RECONCILIATION OF NET INCOME TO ADJUSTED NET INCOME Net income attributable to CVR Energy stockholders $ 378.6 $ 345.8 $ 14.3 Adjustments (all net of taxes): FIFO impact (favorable) unfavorable Share-based compensation Loss on extinguishment of debt Loss on disposition of ﬁxed asset Major scheduled turnaround expense Unrealized (gain) loss on derivatives agreements, net Expenses associated with proxy matters Expenses associated with the acquistion of Gary-Williams 35.5 22.5 22.8 -- 77.2 90.0 26.8 6.7 (15.5) 18.6 1.3 1.5 40.2 (51.7) -- 5.5 (19.1) 30.1 10.0 1.6 2.9 1.3 -- -- Adjusted Net Income $ 660.1 $ 345.7 $ 41.1 Adjusted Net Income, per diluted share $ 7.55 $ 3.94 $ 0.47 11 In this report, we refer to “Adjusted EBITDA.” Discussions and reconciliations for how we arrived at these measures follow: FROM PAGE 9 – ADJUSTED EBITDA BY OPERATING SEGMENT Adjusted Petroleum and Nitrogen Fertilizer EBITDA represents operating income adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, major scheduled turnaround expenses, realized gain (loss) on derivatives, net, loss on disposition of ﬁxed assets, depreciation and amortization and other income (expense). Adjusted EBITDA by operating segment is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance. Management believes that adjusted EBITDA by operating segment provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in the reviewing of our overall ﬁnancial, operational and economic performance. Below is a reconciliation of operating income to adjusted EBITDA for the petroleum and nitrogen fertilizer segments for the years ended December 31, 2012, 2011, 2010, 2009 and 2008: Year ended December 31, (Unaudited) (In millions) 2012 2011 2010 2009 2008 PETROLEUM Petroleum operating income $ 1,012.5 $ 465.7 $ 104.6 $ 170.2 $ 31.9 (25.6) (31.7) (67.9) 102.5 FIFO impacts (favorable) unfavorable Share-based compensation Depreciation and amortization Major scheduled turnaround expenses Loss on disposition of assets 58.4 13.5 107.6 123.7 -- 8.7 69.9 66.4 2.5 Realized gain (loss) on derivatives, net (137.6) (7.2) Goodwill impairment Other income (expense) -- 0.8 -- 0.5 11.5 66.4 1.2 1.3 0.7 -- 0.7 (3.7) 64.4 -- -- (10.8) 62.7 -- -- (21.0) (121.0) -- 0.3 42.8 1.0 Adjusted Petroleum EBITDA $ 1,178.9 $ 580.9 $ 154.7 $ 142.3 $ 109.1 (Unaudited) (In millions) 2012 2011 2010 2009 2008 NITROGEN FERTILIZER Nitrogen fertilizer operating income $ 115.8 $ 136.2 $ 20.4 $ 48.9 $ 116.8 Share-based compensation Depreciation and amortization Major scheduled turnaround expenses Loss on disposition of assets Other income (expense) 6.8 20.7 4.8 -- 0.1 7.3 18.9 -- -- 0.2 9.0 18.5 3.5 1.4 (0.2) 3.2 18.7 -- -- -- (10.6) 18.0 3.3 2.3 0.1 Adjusted Nitrogen Fertilizer EBITDA $ 148.2 $ 162.6 $ 52.6 $ 70.8 $ 129.9 12 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K (Mark One) (cid:2) (cid:2) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2012 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 (State or Other Jurisdiction of Incorporation or Organization) 2277 Plaza Drive, Suite 500 Sugar Land, Texas (Address of Principal Executive Offices) 61-1512186 (I.R.S. Employer Identification No.) 77479 (Zip Code) Registrant’s Telephone Number, including Area Code: (281) 207-3200 Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Name of Each Exchange on Which Registered Common Stock, $0.01 par value per share Series A Preferred Stock Purchase Right, par value $0.01 per share The New York Stock Exchange The New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:2) No (cid:2) Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:2) No (cid:2) 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 (cid:2) No (cid:2) 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 or 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 (cid:2) No (cid:2) Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (cid:2) 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 (cid:2) Smaller reporting company (cid:2) Non-accelerated filer (cid:2) Accelerated filer (cid:2) (Do not check if a smaller reporting company) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:2) No (cid:2) The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed based on the New York Stock Exchange closing price on June 29, 2012 (the last business day of the registrant’s second fiscal quarter) was $415,507,358. Shares of the registrant’s common stock held by each executive officer and director and by each entity or person that, to the registrant’s knowledge, owned 10% or more of the registrant’s outstanding common stock as of June 29, 2012 have been excluded from this number in that these persons may be deemed affiliates of the registrant. This determination of possible affiliate status is not necessarily a conclusive determination for other purposes. Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date. Class Common Stock, par value $0.01 per share Outstanding at March 11, 2013 86,831,050 shares Proxy Statement for the 2013 Annual Meeting of Stockholders Items 10, 11, 12, 13 and 14 of Part III Document Parts Incorporated Documents Incorporated By Reference TABLE OF CONTENTS PART I Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1. Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 2. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 3. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 4. Item 5. Item 6. Item 7. PART II Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 8. Changes in and Disagreements With Accountants on Accounting and Financial Item 9. Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART III Item 10. Item 11. Item 12. Item 13. Item 14. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Certain Relationships and Related Transactions, and Director Independence . . . . . . . Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART IV Page 5 24 57 57 58 58 59 62 64 114 117 184 184 184 185 185 185 185 185 Item 15. Exhibits, Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 186 1 GLOSSARY OF SELECTED TERMS The following are definitions of certain terms used in this Annual Report on Form 10-K for the year ended December 31, 2012 (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 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. Brent—Brent crude oil, a light sweet crude oil characterized by an API gravity of approximately 38 degrees, and a sulfur content of approximately 0.4 weight percent. 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 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 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. coker unit—A refinery unit that utilizes the lowest value component of crude oil remaining after all higher value products are removed, further breaks down the component into more valuable products and converts the rest into pet coke. contango market—Market situation in which prices for future delivery are higher than the current or spot market price of the commodity. The opposite of backwardation market. 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. 2 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 NCRA’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. independent petroleum refiner—A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstock 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 and are products of the refining process. Common NGLs used include propane, isobutane, normal butane and natural gasoline. Nitrogen Fertilizer Partnership IPO—The initial public offering of 22,080,000 common units representing limited partner interests of CVR Partners, LP (the ‘‘Nitrogen Fertilizer Partnership’’), which closed on April 13, 2011. 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. plant gate price—The unit price of fertilizer, in dollars per ton, offered on a delivered basis and excluding shipment costs. prepaid sales—Represents customer payments under contracts to guarantee a price and supply of fertilizer in quantities expected to be delivered in the next twelve months. Revenue is not recorded for such sales until the product is considered delivered. Prepaid sales are also referred to as deferred revenue. 3 petroleum coke (pet coke)—A coal-like substance that is produced during the refining process. 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 (which includes the underwriters’ subsequently-exercised option to purchase additional common units) common units representing limited partner interests of CVR Refining, LP (the ‘‘Refining Partnership’’), which closed on January 23, 2013. 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 years for the nitrogen fertilizer plant. UAN—An aqueous solution of urea and ammonium nitrate used as a fertilizer. wheat belt—The primary wheat producing region of the United States, which includes Oklahoma, Kansas, North Dakota, South Dakota and Texas. 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. WEC—Gary-Williams Energy Corporation, subsequently converted to Gary-Williams Energy Company, LLC and now known as Wynnewood Energy Company, LLC. WRC—Wynnewood Refining Company, LLC, the owner of the 70,000 bpd Wynnewood, Oklahoma refinery and related assets. WTI—West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity, between 39 and 41 degrees and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils. 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. Wynnewood Acquisition—The acquisition by the Company of all the outstanding shares of WEC and its subsidiaries, which owned the 70,000 bpd Wynnewood, Oklahoma refinery and 2.0 million barrels of storage tanks, on December 15, 2011. As of January 2013, WRC is a wholly-owned subsidiary of CVR Refining, LLC. It was previously a wholly-owned subsidiary of WEC. yield—The percentage of refined products that is produced from crude oil and other feedstocks. 4 Item 1. Business PART I CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries (‘‘CVR Energy,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us,’’ or ‘‘our’’) 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 ammonia and UAN. We own the general partner and a majority of the common units representing limited partner interests in each of the Refining Partnership and the Nitrogen Fertilizer Partnership. CVR Energy’s common stock is listed on the New York Stock Exchange (‘‘NYSE’’) under the symbol ‘‘CVI’’, the Refining Partnership’s common units are listed on the NYSE under the symbol ‘‘CVRR’’ and the Nitrogen Fertilizer Partnership’s common units are listed on the NYSE under the symbol ‘‘UAN.’’ The petroleum business consists of a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and, as of December 15, 2011, a 70,000 bpd crude oil unit refinery in Wynnewood, Oklahoma. In addition to the refineries, the petroleum business owns and operates: • a crude oil gathering system with a gathering capacity of approximately 50,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas which is supported by approximately 350 miles of owned and leased pipeline; • a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and to customers at throughput terminals on Magellan Midstream Partners, L.P. (‘‘Magellan’’) and NuStar Energy, LP’s (‘‘NuStar’’) refined products distribution systems; and • a 145,000 bpd pipeline system that transports crude oil to the Coffeyville refinery with 1.2 million barrels of associated company-owned storage tanks, 0.5 million barrels of company- owned crude oil storage tanks in Wynnewood, Oklahoma, 1.0 million barrels of company owned crude oil storage capacity in Cushing, Oklahoma and an additional 3.3 million barrels of leased crude oil storage capacity located at Cushing. The nitrogen fertilizer business consists of a nitrogen fertilizer facility in Coffeyville, Kansas that is the only operation in North America that uses a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer. The nitrogen fertilizer facility includes a 1,225 ton-per-day ammonia unit, a 2,025 ton-per-day UAN unit and a gasifier complex with built-in redundancy having a capacity of 84 million standard cubic feet per day of hydrogen. A majority of the ammonia produced by the nitrogen fertilizer plant is further upgraded to UAN, which has historically commanded a premium price over ammonia. The nitrogen fertilizer business completed construction on a UAN expansion in February 2013 which will enable it to increase UAN production capacity by 400,000 tons per year, or approximately 50%. We have two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2012, 2011 and 2010, we generated consolidated net sales of $8.6 billion, $5.0 billion and $4.1 billion, respectively, and operating income of $1,034.9 million, $566.6 million and $93.1 million, respectively. The petroleum business generated $8.3 billion, $4.8 billion and $3.9 billion of net sales and the nitrogen fertilizer business generated $302.3 million, $302.9 million and $180.5 million of net sales, in each case, for the years ended December 31, 2012, 2011 and 2010, respectively. The petroleum business generated operating income of $1,012.5 million, $465.7 million and $104.6 million and the nitrogen fertilizer business generated operating income of $115.8 million, $136.2 million and 5 $20.4 million, in each case, for the years ended December 31, 2012, 2011 and 2010, respectively. Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and, therefore, are not a sum of the operating results of the petroleum and nitrogen fertilizer businesses. Our History The Coffeyville refinery, which began operations in 1906, and the nitrogen fertilizer plant, built in 2000, were operated as components of Farmland Industries, Inc. (‘‘Farmland’’) until March 3, 2004, the date on which Coffeyville Resources, LLC (‘‘CRLLC’’) completed the acquisition of these assets through a bankruptcy court auction. On June 24, 2005, Coffeyville Acquisition LLC (‘‘CALLC’’), which was formed by certain funds affiliated with Goldman, Sachs & Co. and Kelso & Company, L.P. (the ‘‘Goldman Sachs Funds’’ and the ‘‘Kelso Funds,’’ respectively), acquired these businesses. CALLC operated our business from June 24, 2005 until CVR Energy’s initial public offering in October 2007. CVR Energy was formed in September 2006 as a subsidiary of CALLC in order to consummate an initial public offering of its businesses. CVR Energy consummated its initial public offering on October 26, 2007. The Goldman Sachs Funds and the Kelso Funds completely sold their ownership interests by February 2011 and May 2011, respectively. On April 13, 2011, the Nitrogen Fertilizer Partnership completed the Nitrogen Fertilizer Partnership IPO. The Nitrogen Fertilizer Partnership sold 22,080,000 common units at a price of $16.00 per common unit, resulting in gross proceeds of $353.3 million. The Nitrogen Fertilizer Partnership’s common units are listed on the NYSE and are traded under the symbol ‘‘UAN.’’ In connection with the Nitrogen Fertilizer Partnership IPO, the Nitrogen Fertilizer Partnership paid approximately $24.7 million in underwriting fees and incurred approximately $4.4 million of other offering costs. As a result of the Nitrogen Fertilizer Partnership IPO, CVR Energy indirectly owns approximately 70% of the Nitrogen Fertilizer Partnership’s outstanding common units and 100% of the Nitrogen Fertilizer Partnership’s general partner with its non-economic general partner interest. On December 15, 2011, CVR Energy acquired all of the issued and outstanding shares of WEC for $593.4 million, consisting of an initial cash payment of $525.0 million, capital expenditure adjustments of $1.8 million and $66.6 million for working capital (the ‘‘Wynnewood Acquisition’’). Assets acquired include a 70,000 bpd refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of company-owned storage tanks. On April 18, 2012, CVR Energy entered into a Transaction Agreement (the ‘‘Transaction Agreement’’) with certain affiliates of Icahn Enterprises and Carl C. Icahn. Pursuant to the Transaction Agreement, a wholly-owned subsidiary of Icahn Enterprises offered (the ‘‘Offer’’) to purchase all of the issued and outstanding shares of CVR Energy’s common stock for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment (‘‘CCP’’) right for each share, which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy is executed on or before August 18, 2013 and such transaction closes. In May 2012, affiliates of Icahn Enterprises acquired a majority of the common stock of CVR Energy through the Offer. As a result of shares tendered into the Offer during the initial offering period and subsequent additional purchases, Icahn Enterprises and its affiliates owned approximately 82% of CVR Energy’s outstanding common stock as of December 31, 2012. 6 In contemplation of an initial public offering, in September 2012, CRLLC formed CVR Refining Holdings, LLC (‘‘CVR Refining Holdings’’), which in turn formed CVR Refining GP, LLC. CVR Refining Holdings and CVR Refining GP, LLC formed CVR Refining, LP which issued them a 100% limited partnership interest and a non-economic general partner interest, respectively. CVR Refining Holdings formed CVR Refining, LLC (‘‘Refining LLC’’) and CRLLC contributed its petroleum and logistics subsidiaries, as well as its equity interests in Coffeyville Finance Inc. (‘‘Coffeyville Finance’’) to Refining LLC in October 2012. CVR Refining Holdings contributed Refining LLC to the Refining Partnership on December 31, 2012. On January 23, 2013, the Refining Partnership completed the Refining Partnership IPO. The Refining Partnership sold 24,000,000 common units at a price of $25.00 per common unit, resulting in gross proceeds of $600.0 million. Of the common units issued, 4,000,000 units were purchased by an affiliate of Icahn Enterprises. Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per common unit resulting in gross proceeds of $90.0 million. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol ‘‘CVRR.’’ In connection with the Refining Partnership IPO, the Refining Partnership paid approximately $32.5 million in underwriting fees and incurred approximately $3.9 million of other offering costs. Following the Refining Partnership IPO, CVR Energy indirectly owns approximately 81% of the Refining Partnership’s outstanding common units and 100% of the Refining Partnership’s general partner, which holds a non-economic general partner interest. As of December 31, 2012, CVR Energy owned 100% of CVR Refining. Accordingly, our financial statements for the year ended December 31, 2012 contained in this Report do not reflect any noncontrolling interest in the Refining Partnership. We operate under two business segments: petroleum (the petroleum and related businesses operated by the Refining Partnership) and nitrogen fertilizer (the nitrogen fertilizer business operated by the Nitrogen Fertilizer Partnership). Throughout the remainder of this document, our business segments are referred to as the ‘‘petroleum business’’ and the ‘‘nitrogen fertilizer business,’’ respectively. 7 Organizational Structure and Related Ownership The following chart illustrates our organizational structure and the organizational structure of the Refining Partnership and the Nitrogen Fertilizer Partnership as of the date of this Report. Public Icahn Enterprises, L.P. (NASDAQ: IEP) 18% 82% CVR Energy, Inc. (NYSE: CVI) Coffeyville Resources, LLC 3% 100% 70% 100% CVR Refining Holdings, LLC CVR GP, LLC (the “Nitrogen General Partner”) 100% 81% CVR Refining GP, LLC (the “Refining General Partner”) Non-economic general partner interest Public 30% Non-economic general partner interest CVR Refining, LP (NYSE: CVRR) (the “Refining Partnership”) Guarantor of 2022 Notes 100% 16% Public CVR Partners, LP (NYSE: UAN) (the “Nitrogen Partnership”) Coffeyville Resources Nitrogen Fertilizers, LLC CVR Partners Fertilizer Business CVR Refining, LLC Co-Issuer of 2022 Notes Amended & Restated ABL Credit Facility Borrower 100% Petroleum Refining & Logistics Operating Subsidiaries Amended & Restated ABL Credit Facility Borrowers Wynnewood Energy Company, LLC Wynnewood Refining Company, LLC Coffeyville Resources Refining and Marketing, LLC Coffeyville Resources Crude Transportation, LLC Coffeyville Resources Terminal, LLC Coffeyville Resources Pipeline, LLC Coffeyville Finance, Inc. (Co-Issuer of 2022 Notes) 13MAR201304444025 8 Petroleum Business The petroleum business includes a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and, as of December 15, 2011, a 70,000 bpd crude oil unit refinery in Wynnewood, Oklahoma capable of processing 20,000 bpd of light sour crude oil (within its 70,000 bpd capacity). The combined crude capacity represents approximately 22% of the region’s refining capacity. The Coffeyville refinery is situated on approximately 440 acres in southeast Kansas, approximately 100 miles from Cushing, Oklahoma, a major crude oil trading and storage hub. The Wynnewood refinery is situated on approximately 400 acres located approximately 65 miles south of Oklahoma City, Oklahoma and approximately 130 miles from Cushing, Oklahoma. For the year ended December 31, 2012, the Coffeyville refinery’s product yield included gasoline (mainly regular unleaded) (50%), diesel fuel (primarily ultra-low sulfur diesel) (42%), and pet coke and other refined products such as natural gas liquids (‘‘NGL’’) (propane and butane), slurry, sulfur and gas oil (8%). The Wynnewood refinery’s product yield included gasoline (51%), diesel fuel (primarily ultra-low sulfur diesel) (32%), asphalt (8%), jet fuel (5%) and other products (4%). The petroleum business also includes the following auxiliary operating assets: • Crude Oil Gathering System. The petroleum business owns and operates a crude oil gathering system serving Kansas, Nebraska, Oklahoma, Missouri and Texas. The system has field offices in Bartlesville, Oklahoma, Plainville, Kansas and Winfield, Kansas. The system is comprised of approximately 350 miles of feeder and trunk pipelines, approximately 140 crude oil transports, and associated storage facilities for gathering crude oils purchased from independent crude oil producers in our gathering area. The petroleum business also leases a section of a pipeline from Magellan, which is incorporated into our crude oil gathering system. The crude oil gathering system has a gathering capacity of approximately 50,000 bpd. Gathered crude oil provides an attractive and competitive base supply of crude oil for the Coffeyville and Wynnewood refineries. During 2012, the petroleum business gathered an average of approximately 46,000 bpd. • Pipelines and Storage Tanks. The petroleum business owns a proprietary pipeline system capable of transporting approximately 145,000 bpd of crude oil from its Broome Station tank farm located near Caney, Kansas to its Coffeyville refinery. Crude oils sourced outside of the proprietary gathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and then delivered to the Broome Station tank farm via a pipeline owned by Plains Pipeline L.P. (‘‘Plains’’). The petroleum business also controls associated crude oil storage tanks with a capacity of approximately 1.2 million barrels located outside the Coffeyville refinery, 0.5 million barrels of crude oil storage capacity at Wynnewood, Oklahoma, 1.0 million barrels of crude oil storage capacity in Cushing, Oklahoma and leases an additional 3.3 million barrels of crude oil storage capacity located at Cushing. In addition to crude oil storage, the petroleum business owns approximately 4.5 million barrels of combined refinery related storage capacity. The refineries’ complexity allows the petroleum business to optimize the yields (the percentage of refined product that is produced from crude oil and other feedstocks) of higher value transportation fuels (gasoline and diesel). Complexity is a measure of a refinery’s ability to process lower quality crude oil in an economic manner. The two refineries’ capacity weighted average complexity is 11.5. As a result of key investments in its refining assets, the Coffeyville refinery’s complexity score increased to 12.9 in 2012 from 12.2 in 2010, and the petroleum business has achieved significant increases in its refinery crude oil throughput rate over historical levels. The Wynnewood refinery has a complexity of 9.3 and is capable of processing a variety of crudes, including West Texas sour, West Texas Intermediate, sweet and sour Canadian and U.S. Gulf Coast crudes. The petroleum business’ higher complexity provides it the flexibility to increase its refining margin over comparable refiners with lower complexities. 9 Crude and Feedstock Supply The Coffeyville refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil. Currently, the Coffeyville refinery crude oil slate consists of a blend of mid-continent domestic grades, various Canadian medium and heavy sours and sweet synthetics. The early June 2012 reversal of the Seaway Pipeline that now flows from Cushing, Oklahoma to the U.S. Gulf Coast has eliminated the ability to source foreign waterborne crude from around the world, as well as deepwater U.S. Gulf of Mexico produced sweet and sour crude oil grades. While crude oil has historically constituted over 90% of the Coffeyville refinery’s total throughput over the last five years, other feedstock inputs include normal butane, natural gasoline, alkylation feeds, naphtha, gas oil and vacuum tower bottoms. 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 isobutane, gasoline components, and normal butane are also typically used. Historically most of the Wynnewood refinery’s crude oil has been acquired domestically, mainly from Texas and Oklahoma. Crude oil is supplied to the Coffeyville and Wynnewood refineries through our wholly-owned gathering system and by pipeline. The petroleum business has continued to increase the number of barrels of crude oil supplied through its crude oil gathering system in 2012 and it now has the capacity of supplying approximately 50,000 bpd of crude oil to the refineries. For the year ended December 31, 2012, the gathering system supplied approximately 36% of the Coffeyville refinery’s crude oil demand and 12% of the Wynnewood refinery’s crude oil demand, respectively. Locally produced crude oils are delivered to the refineries at a discount to WTI, and although slightly heavier and more sour, offer good economics to the refineries. These crude oils are light and sweet enough to allow the refineries to blend higher percentages of lower cost crude oils such as heavy sour Canadian crude oil while maintaining their target medium sour blend with an API gravity of between 28 and 36 degrees and between 0.9% and 1.2% sulfur. Crude oils sourced outside of the proprietary gathering system are delivered to Cushing, Oklahoma by various pipelines including Basin, Keystone and Spearhead pipelines, and subsequently to the Broome Station tank farm via the Plains pipeline. From the Broome Station tank farm, crude oil is delivered to the Coffeyville refinery via our own 145,000 bpd proprietary pipeline system. Crude oils are delivered to the Wynnewood refinery by two separate pipelines, and received into storage tanks at terminals located on or near the refinery. For the year ended December 31, 2012, the Coffeyville refinery’s crude oil supply blend was comprised of approximately 80% light sweet crude oil, 5% light/medium sour crude oil and 15% heavy sour crude oil. For the year ended December 31, 2012, the Wynnewood refinery’s crude oil supply blend was comprised of approximately 71% sweet crude oil and 29% light/medium sour crude oil. The light sweet crude oil supply blend includes its locally gathered crude oil. The Coffeyville refinery is connected to the mid-continent natural gas liquids commercial hub of Conway, Kansas by the inbound Enterprise Pipeline Blue Line. Natural gas liquids feedstock supplies such as butanes and natural gasoline are sourced and delivered directly into the refinery. In addition, Coffeyville’s proximity to Conway provides access to the natural gas liquid and liquid petroleum gas (‘‘LPG’’) fractionation and storage capabilities as well as the commercial markets available at Conway. The outbound Enterprise Pipeline Red Line provides Coffeyville with access to the NuStar Refined Products Pipeline system. This allows gasoline and ultra-low sulfur diesel (‘‘ULSD’’) product sales from Kansas up to North Dakota. Crude Oil Supply Agreement In August 2012, the petroleum business entered into a Crude Oil Supply Agreement (the ‘‘Vitol Agreement’’) with Vitol Inc. (‘‘Vitol’’). The Vitol Agreement amends and restates the Crude Oil Supply 10 Agreement between the petroleum business and Vitol dated March 30, 2011, as amended. Under the agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us to reduce our inventory position and mitigate crude oil pricing risk. The Vitol Agreement has an initial term commencing August 31, 2012 and extending through December 31, 2014. Following the initial term, the Vitol Agreement will automatically renew for successive one-year terms unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of the initial Term or any renewal term. Notwithstanding the foregoing, the petroleum business has an option to terminate the Vitol Agreement effective December 31, 2013 by providing written notice of termination to Vitol on or before May 1, 2013. Marketing and Distribution The petroleum business focuses its Coffeyville petroleum product marketing efforts in the central mid-continent area, because of its relative proximity to the refinery and pipeline access. Coffeyville also has access to the Rocky Mountain area. Coffeyville engages in rack marketing, which is the supply of product through tanker trucks directly to customers located in close geographic proximity to the refinery and to customers at throughput terminals on the refined products distribution systems of Magellan and NuStar. Coffeyville also make bulk sales (sales into third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar. The Wynnewood refinery ships its finished product via pipeline, rail car, and truck. It focuses its efforts in the southern portion of the Magellan system which covers all of Oklahoma, parts of Arkansas as well as eastern Missouri, and all other Magellan terminals. The pipeline system is also able to flow in the opposite direction, providing access to Texas markets as well as some adjoining states with pipeline connections. Wynnewood also sells jet fuel to the U.S. Department of Defense via its segregated truck rack and can offer asphalts, solvents and other specialty products via both truck and rail. Customers Customers for the refined petroleum products primarily include retailers, railroads, and farm cooperatives and other refiners/marketers in Group 3 of the PADD II region because of their relative proximity to the refineries and pipeline access. The petroleum business sells bulk products to long-standing customers at spot market prices based on a Group 3 basis differential to prices quoted on the New York Mercantile Exchange (‘‘NYMEX’’), which are reported by industry market related indices such as Platts and Oil Price Information Service. The petroleum business also has a rack marketing business supplying product through tanker trucks directly to customers located in proximity to the Coffeyville and Wynnewood refineries, as well as to customers located at throughput terminals on refined products distribution systems run by Magellan and NuStar. Rack sales are at posted prices that are influenced by competitor pricing and Group 3 spot market differentials. Additionally, the Wynnewood refinery supplies jet fuel to the U.S. Department of Defense. For the year-ended December 31, 2012, the two largest customers accounted for approximately 10% and 9% of the petroleum business sales and approximately 48% of the petroleum business sales were made to its ten largest customers. Competition The petroleum business competes primarily on the basis of price, reliability of supply, availability of multiple grades of products and location. The principal competitive factors affecting its refining operations are cost of crude oil and other feedstock costs, refinery complexity, refinery efficiency, refinery product mix and product distribution and transportation costs. The location of the refineries 11 provides the petroleum business with a reliable supply of crude oil and a transportation cost advantage over its competitors. The petroleum business primarily competes against five refineries operated in the mid-continent region. In addition to these refineries, the refineries compete against trading companies, as well as other refineries located outside the region that are linked to the mid-continent market through an extensive product pipeline system. These competitors include refineries located near the Gulf Coast and the Texas panhandle region. The petroleum business refinery competition also includes branded, integrated and independent oil refining companies, such as Phillips 66, HollyFrontier, NCRA, Valero, Flint Hills Resources and CHS. Seasonality The petroleum business experiences seasonal effects as demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Demand for diesel fuel is higher during the planting and harvesting seasons. As a result, the petroleum business’ results of operations for the first and fourth calendar quarters are generally lower than for those for the second and third calendar quarters. In addition, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the markets in which the petroleum business sells its petroleum products can impact the demand for gasoline and diesel fuel. The demand for asphalt is also seasonal and is generally higher during the months of March through October. Nitrogen Fertilizer Business The nitrogen fertilizer business, operated by the Nitrogen Fertilizer Partnership, is the only nitrogen fertilizer plant in North America that utilizes a pet coke gasification process to produce nitrogen fertilizer. Raw Material Supply The nitrogen fertilizer facility’s primary input is pet coke. On average, during the past five years, over 70% of the nitrogen fertilizer business’ pet coke requirements were supplied by CVR Refining’s adjacent crude oil refinery pursuant to a renewable long-term agreement. Historically the nitrogen fertilizer business has obtained the remainder of its pet coke requirements from third parties such as other Midwestern refineries or pet coke brokers at spot-prices. During 2012, the Nitrogen Fertilizer Partnership entered into a pet coke supply agreement with HollyFrontier Corporation. The initial term ends in December 2013 and is subject to renewal. If necessary, the gasifier can also operate on low grade coal as an alternative. Linde LLC (‘‘Linde’’) owns, operates, and maintains the air separation plant that provides contract volumes of oxygen, nitrogen, and compressed dry air to the gasifiers for a monthly fee. The nitrogen fertilizer business provides and pays for all utilities required for operation of the air separation plant. The agreement with Linde expires in 2020. The nitrogen fertilizer business imports start-up steam for the nitrogen fertilizer plant from the adjacent Coffeyville crude oil refinery, and then exports steam back to the adjacent crude oil refinery once all units in the nitrogen fertilizer plant are in service. Monthly charges and credits are recorded with steam valued at the natural gas price for the month. Nitrogen Production Process The nitrogen fertilizer plant was completed in 2000 and is the newest nitrogen fertilizer plant built in North America. The nitrogen fertilizer plant has two separate gasifiers to provide redundancy and reliability. The plant uses a gasification process to convert pet coke to high purity hydrogen for subsequent conversion to ammonia. The nitrogen fertilizer plant is capable of processing approximately 12 1,400 tons per day of pet coke from the Coffeyville crude oil refinery and third-party sources and converting it into approximately 1,200 tons per day of ammonia. A majority of the ammonia is converted to approximately 2,000 tons per day of UAN. Typically 0.41 tons of ammonia is required to produce one ton of UAN. The nitrogen fertilizer business completed construction on the UAN expansion in February and it is scheduled to be at full operating rates in March 2013. The expansion is designed to increase its UAN production capacity by 400,000 tons per year, or approximately 50%. The nitrogen fertilizer business schedules and provides routine maintenance to its critical equipment using its own maintenance technicians. Pursuant to a Technical Services Agreement with an affiliate of the General Electric Company (‘‘General Electric’’), which licenses the gasification technology to the nitrogen fertilizer business, General Electric experts provide technical advice and technological updates from their ongoing research as well as other licensees’ operating experiences. The pet coke gasification process is licensed from General Electric pursuant to a license agreement that is fully paid. The license grants the nitrogen fertilizer business perpetual rights to use the pet coke gasification process on specified terms and conditions. Distribution, Sales and Marketing The primary geographic markets for the nitrogen fertilizer business’ fertilizer products are Kansas, Missouri, Nebraska, Iowa, Illinois, Colorado and Texas. The nitrogen fertilizer business markets the ammonia products to industrial and agricultural customers and the UAN products to agricultural customers. The demand for nitrogen fertilizers occurs during three key periods. The highest level of ammonia demand is traditionally in the spring pre-plant, from March through May. The second-highest period of demand occurs during fall pre-plant in late October and November. The summer wheat pre-plant occurs in August and September. In addition, smaller quantities of ammonia are sold in the off-season to fill available storage at the dealer level. Ammonia and UAN are distributed by truck or by railcar. If delivered by truck, products are sold on a freight-on-board basis, and freight is normally arranged by the customer. The nitrogen fertilizer business leases and owns a fleet of railcars for use in product delivery, and also negotiates with distributors that have their own leased railcars to utilize these assets to deliver products. The nitrogen fertilizer business operates two truck loading and four rail loading racks for each of ammonia and UAN, with an additional four rail loading racks for UAN. The nitrogen fertilizer business owns all of the truck and rail loading equipment at the nitrogen fertilizer facility. The nitrogen fertilizer business utilizes a two million gallon UAN storage tank and related truck and rail car load-out facilities located in Phillipsburg, Kansas. The property that this terminal was constructed on is owned by a subsidiary of CVR Refining, which operates the terminal. The purpose of the UAN terminal is to distribute approximately 20,000 tons of UAN fertilizer annually. The UAN terminal is complete and operational. The nitrogen fertilizer business markets agricultural products to destinations that produce strong margins. The UAN market is primarily located near the Union Pacific Railroad lines or destinations that can be supplied by truck. The ammonia market is primarily located near the Burlington Northern Santa Fe or Kansas City Southern Railroad lines or destinations that can be supplied by truck. The nitrogen fertilizer business uses forward sales of fertilizer products to optimize its asset utilization, planning process and production scheduling. These sales are made by offering customers the opportunity to purchase product on a forward basis at prices and delivery dates that it proposes. The nitrogen fertilizer business uses this program to varying degrees during the year and between years depending on market conditions and has the flexibility to increase or decrease forward sales depending on management’s view as to whether price environments will be increasing or decreasing. Fixing the selling prices of nitrogen fertilizer products months in advance of their ultimate delivery to customers typically causes the nitrogen fertilizer business reported selling prices and margins to differ from spot market prices and margins available at the time of shipment. Cash received as a result of prepayments is recognized as deferred revenue on the balance sheet upon receipt; revenue and resultant net income and EBITDA are recorded as the product is actually delivered to the customer. 13 Customers The nitrogen fertilizer business sells ammonia to agricultural and industrial customers. Based upon a three-year average, the nitrogen fertilizer business has sold approximately 87% of the ammonia it produces to agricultural customers primarily located in the mid-continent area between North Texas and Canada, and approximately 13% to industrial customers. Agricultural customers include distributors such as MFA, United Suppliers, Inc., Brandt Consolidated Inc., Gavilon Fertilizer LLC, Transammonia, Inc., Agri Services of Brunswick, LLC, Interchem, and CHS Inc. Industrial customers include Tessenderlo Kerley, Inc., National Cooperative Refinery Association, and Dyno Nobel, Inc. The nitrogen fertilizer business sells UAN products to retailers and distributors. Given the nature of its business, and consistent with industry practice, the nitrogen fertilizer business does not have long-term minimum purchase contracts with any of its customers. For the year ended December 31, 2012, the top five ammonia customers in the aggregate represented 63.0% of the nitrogen fertilizer business’ ammonia sales and the top five UAN customers in the aggregate represented 38.7% of the nitrogen fertilizer business’ UAN sales. The nitrogen fertilizer business’ top two customers on a consolidated basis, Gavilon Fertilizer, LLC and United Suppliers, Inc., accounted for approximately 10.5% and 9.8%, respectively of the nitrogen fertilizer business’ net sales. Competition Competition in the nitrogen fertilizer industry is dominated by price considerations. However, during the spring and fall application seasons, farming activities intensify and delivery capacity is a significant competitive factor. The nitrogen fertilizer business maintains a large fleet of leased and owned rail cars and seasonally adjusts inventory to enhance its manufacturing and distribution operations. Domestic competition, mainly from regional cooperatives and integrated multinational fertilizer companies, is intense due to customers’ sophisticated buying tendencies and production strategies that focus on cost and service. Also, foreign competition exists from producers of fertilizer products manufactured in countries with lower cost natural gas supplies. In certain cases, foreign producers of fertilizer who export to the United States may be subsidized by their respective governments. The nitrogen fertilizer business’ major competitors include Agrium, Koch Nitrogen, Potash Corporation and CF Industries. Based on third-party expert data regarding total U.S. demand for UAN and ammonia, we estimate that the nitrogen fertilizer plant’s UAN production in 2012 represented approximately 5% of total U.S. UAN use and that the net ammonia produced and marketed at Coffeyville represented less than 1% of the total U.S. ammonia use. Seasonality Because the nitrogen fertilizer business primarily sells agricultural commodity products, its business is exposed to seasonal fluctuations in demand for nitrogen fertilizer products in the agricultural industry. As a result, the nitrogen fertilizer business typically generates greater net sales in the first half of each calendar year, which we refer to as the planting season, and its net sales tend to be lower during the second half of each calendar year, which we refer to as the fill season. Environmental Matters The petroleum and nitrogen fertilizer businesses 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, the storage, handling, use and transportation of petroleum and nitrogen products, and the 14 characteristics and composition of gasoline and diesel fuels. These laws and regulations, their underlying regulatory requirements and the enforcement thereof impact the petroleum business and operations and the nitrogen fertilizer business and operations by imposing: • restrictions on operations or the need to install enhanced or additional controls; • the need to obtain and comply with permits, licenses and authorizations; • requirements for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and liability for off-site waste disposal locations; and • specifications for the products marketed by the petroleum business and the nitrogen fertilizer business, primarily gasoline, diesel fuel, UAN and ammonia. Our operations require numerous permits, licenses and authorizations. Failure to comply with these permits or environmental laws and regulations could result in fines, penalties or other sanctions or a revocation of our permits. In addition, the laws and regulations to which we are subject are often evolving and many of them have become more stringent or have become subject to more stringent interpretation or enforcement by federal or state agencies. The ultimate impact on our business 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. The principal environmental risks associated with our businesses are outlined below. The Federal Clean Air Act The federal Clean Air Act and its implementing regulations, as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air, affect the petroleum business and the nitrogen fertilizer business both directly and indirectly. Direct impacts may occur through the federal Clean Air Act’s permitting requirements and/or emission control requirements relating to specific air pollutants, as well as the requirement to maintain a risk management program to help prevent accidental releases of certain regulated substances. The federal Clean Air Act indirectly affects the petroleum business and the nitrogen fertilizer business by extensively regulating the air emissions of sulfur dioxide (‘‘SO2’’), volatile organic compounds, nitrogen oxides and other substances, including those emitted by mobile sources, which are direct or indirect users of our products. Some or all of the standards promulgated pursuant to the federal Clean Air Act, or any future promulgations of standards, may require the installation of controls or changes to the petroleum business or the nitrogen fertilizer facilities in order to comply. If new controls or changes to operations are needed, the costs could be material. These new requirements, other requirements of the federal Clean Air Act, or other presently existing or future environmental regulations could cause us to expend substantial amounts to comply and/or permit our facilities to produce products that meet applicable requirements. The regulation of air emissions under the federal Clean Air Act requires that we obtain various construction and operating permits and incur capital expenditures for the installation of certain air pollution control devices at the petroleum and nitrogen fertilizer operations when regulations change or we add new equipment or modify existing equipment. Various regulations specific to our operations have been implemented, such as National Emission Standard for Hazardous Air Pollutants, New Source Performance Standards and New Source Review/Prevention of Significant Deterioration (‘‘NSR’’). We have incurred, and expect to continue to have to make, substantial capital expenditures to attain or maintain compliance with these and other air emission regulations that have been promulgated or may be promulgated or revised in the future. 15 On September 12, 2012, the U.S. Environmental Protection Agency (the ‘‘EPA’’) published in the Federal Register final revisions to its New Source Performance Standards for process heaters and flares at petroleum refineries. The EPA originally issued final standards in June 2008, but the portions of the rule relating to process heaters and flares were stayed pending reconsideration of certain provisions. The final standards regulate emissions of nitrogen oxide from process heaters and emissions of SO2 from flares, as well as require certain work practice and monitoring standards for flares. We are reviewing the rule and will make any required capital expenditure necessary to comply with the new requirements. We do not believe that the costs of complying with the rule will be material. On August 14, 2012, the EPA sent both the Wynnewood and Coffeyville refineries letters regarding the EPA’s recently issued enforcement alert entitled EPA Enforcement Targets Flaring Efficiency Violations signaling the agency’s intention to begin a national enforcement program to conduct compliance evaluations and take enforcement actions against petroleum refining companies that operate flares that are not in compliance with standards articulated in the Enforcement Alert. The Enforcement Alert identified new standards that refiners are required to meet for combustion efficiency. The EPA has already commenced enforcement against several refining companies and we understand that other settlement negotiations are underway. Because the EPA has not specifically told us that our operations are not in compliance, we cannot say with certainty whether or when we may become an enforcement target under this new initiative. In March 2004, Coffeyville Resources Refining & Marketing, LLC (‘‘CRRM’’) and Coffeyville Resources Terminal, LLC (‘‘CRT’’) entered into a Consent Decree (the ‘‘2004 Consent Decree’’) with the EPA and the Kansas Department of Health and Environment (the ‘‘KDHE’’) to resolve air compliance concerns raised by the EPA and KDHE related to Farmland’s prior ownership and operation of the Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. Under the 2004 Consent Decree, CRRM agreed to install controls to reduce emissions of SO2, nitrogen oxides and particulate matter from its fluid catalytic cracking unit (‘‘FCCU’’) by January 1, 2011. In addition, pursuant to the 2004 Consent Decree, CRRM and CRT assumed clean-up obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities. In March 2012, CRRM entered into a second consent decree (the ‘‘Second Consent Decree’’) with the EPA, which replaces the 2004 Consent Decree, as amended (other than certain financial provisions associated with corrective action at the refinery and terminal under the Resource Conservation and Recovery Act (‘‘RCRA’’). The Second Consent Decree gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a ‘‘global settlement’’ under the EPA’s ‘‘National Petroleum Refining Initiative.’’ Under the National Petroleum Refining Initiative, the EPA identified industry-wide non-compliance with four ‘‘marquee’’ issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees imposing civil penalties and requiring the installation of pollution control equipment and enhanced operating procedures. The EPA has indicated that it will seek to have all refiners enter into ‘‘global settlements’’ pertaining to all ‘‘marquee’’ issues. Under the Second Consent Decree, the Company was required to pay a civil penalty of approximately $0.7 million, complete the installation of FCCU controls required under the 2004 Consent Decree, add controls to certain heaters and boilers and enhance certain work practices relating to wastewater and fugitive emissions. The remaining costs of complying with the Second Consent Decree are expected to be approximately $41.0 million, of which approximately $39.0 million is expected to be capital expenditures. CRRM also agreed to complete a voluntary environmental project that will reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. The incremental capital expenditures associated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The Second Consent Decree was entered by the U.S. District Court for the District of Kansas on April 19, 2012. 16 Wynnewood Refining Company, LLC (‘‘WRC’’) has not entered into a global settlement with the EPA and the Oklahoma Department of Environmental Quality (the ‘‘ODEQ’’) under the National Petroleum Refining Initiative, although it had discussions with the EPA and ODEQ about doing so. Instead, WRC entered into a Consent Order with ODEQ in August 2011 (the ‘‘Wynnewood Consent Order’’). The Wynnewood Consent Order addresses some, but not all, of the traditional marquee issues under the National Petroleum Refining Initiative and addresses certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. A substantial portion of the costs of complying with the Wynnewood Consent Order were expended during the last turnaround. The remaining costs are expected to be approximately $2.0 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for the matters described in the ODEQ order. On September 23, 2011, the United States Department of Justice (‘‘DOJ’’), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking recovery from CRRM related to alleged non-compliance with the Clean Air Act’s Risk Management Program (‘‘RMP’’), the Clean Water Act (‘‘CWA’’) and the Oil Pollution Act (‘‘OPA’’) (in addition to other matters described below, (see ‘‘— Environmental Remediation’’). DOJ’s CWA and OPA claims related to a flood and oil spill at the refinery that occurred on June 30/July 1, 2007. CRRM has reached an agreement with the DOJ to resolve the DOJ’s claims under the CWA and OPA. The agreement is memorialized in a Consent Decree that was filed with the Court on February 12, 2013 (the ‘‘2013 Consent Decree’’). If the 2013 Consent Decree is approved and entered by the Court, CRRM will pay a civil penalty in the amount of $0.6 million for CWA violations and reimburse the Coast Guard for oversight costs under OPA in the amount of $1.7 million for clean-up costs after a July 2007 crude oil discharge from the Coffeyville refinery as a result of flooding of the Verdigris River. The 2013 Consent Decree also requires CRRM to make upgrades to the Coffeyville refinery, including flood control measures, the installation of river modeling and monitoring procedures, the implementation of a wet weather plan, and training employees on proper shutdown procedures during a flood. The parties also reached an agreement to settle DOJ’s RMP claims, but DOJ has re-opened the negotiations. Any liability to DOJ related to the RMP claims is not expected to be material. Both the Wynnewood refinery and the Coffeyville refinery’s Clean Air Act Title V operating permits have expired, and have not yet been re-issued. Both refineries submitted an application for renewal and currently operate under a permit shield, which authorizes permittees who timely submit their renewal application, to continue operations until the permit is re-issued. The permit renewal process has begun, and capital costs or expenses, if any, related to changes to these permits are not known yet, but are not expected to be material. The Federal Clean Water Act The federal Clean Water Act and its implementing regulations, as well as the corresponding state laws and regulations that regulate the discharge of pollutants into the water, affect the petroleum business and the nitrogen fertilizer business. Direct impacts occur through the federal Clean Water Act’s permitting requirements, which establish discharge limitations based on technology standards, water quality standards, and restrictions on the total maximum daily load (‘‘TMDL’’) of pollutants that may be released to a particular water body based on its use. In addition, water resources are becoming and in the future may become scarcer, and many refiners, including CRRM and WRC, are subject to restrictions on their ability to use water in the event of low availability conditions. Both CRRM and WRC have contracts in place to receive additional water during low-flow conditions, but these conditions could change over time if water becomes scarce. 17 The Wynnewood refinery’s Clean Water Act permit (‘‘OPDES permit’’) has expired. The refinery currently operates under a permit shield, which authorizes permittees who timely submit their renewal application to continue discharging under an expired permit until the permitting authority re-issues the permit. Capital costs or expenses related to changes to this permit, if any, are not expected to be material. WRC has entered into a series of Clean Water Act consent orders with ODEQ. The latest Consent Order (the ‘‘CWA Consent Order’’), which supersedes other consent orders, became effective in September 2011. The CWA Consent Order addresses alleged non-compliance by WRC with its OPDES permit limits. The CWA Consent Order requires WRC to take corrective action steps, including undertaking studies to determine whether the Wynnewood refinery’s wastewater treatment plant capacity is sufficient. The Wynnewood refinery may need to install additional controls or make operational changes to satisfy the requirements of the CWA Consent Order. The cost of additional controls, if any, cannot be predicted at this time. However, based on our experience with wastewater treatment and controls, we do not anticipate that the costs of any required additional controls or operational changes would be material. Release Reporting The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting requirements under federal and state environmental laws. Our facilities periodically experience releases of hazardous substances and extremely hazardous substances. For example, the nitrogen fertilizer facility periodically experiences minor releases of hazardous and extremely hazardous substances from our equipment. It experienced more significant releases in August 2007 due to the failure of a high pressure pump and in August and September 2010 due to a heat exchanger leak and a UAN vessel rupture. Our facilities periodically have excess emission events from flaring and other planned and unplanned start-up, shutdown and malfunction events. Such releases are reported to the EPA and relevant state and local agencies. From time to time, the EPA has conducted inspections and issued information requests to us with respect to our compliance with release reporting requirements under the Comprehensive Environmental Response, Compensation and Liability Act (‘‘CERCLA’’) and the Emergency Planning and Community Right-to-Know Act (‘‘EPCRA’’). If we fail to timely or properly report a release, or if the release violates the law or our permits, it could cause us to become the subject of a governmental enforcement action or third-party claims. Government enforcement or third-party claims relating to releases of hazardous or extremely hazardous substances could result in significant expenditures and liability. Fuel Regulations Tier II, Low Sulfur Fuels. In February 2000, the EPA promulgated the Tier II Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline that were required to be met by 2006. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which required a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. The refineries are in compliance with the EPA’s low sulfur gasoline and diesel fuel standards. Tier III. The EPA is expected to propose ‘‘Tier 3’’ gasoline sulfur standards in 2013. If the EPA were to propose a standard at the level currently being discussed in the pre-proposal phase by the EPA, CRRM will need to make capital expenditures to install controls in order to meet the anticipated new standard. It is not anticipated that the Wynnewood refinery will require additional controls or capital expenditures to meet the anticipated new standard. We believe that the costs associated with the EPA’s proposed Tier III rule will not be material. 18 Mobile Source Air Toxic II Emissions In 2007, the EPA promulgated the Mobile Source Air Toxic II (‘‘MSAT II’’) rule that requires the reduction of benzene in gasoline by 2011. CRRM and WRC each were considered to be ‘‘small refiners’’ under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. However, the change in control resulting from the Icahn Enterprises acquisition in 2012 triggered the loss of small refiner status. Accordingly, the MSAT II projects have been accelerated by three months. Capital expenditures to comply with the rule are expected to be approximately $59.0 million for CRRM and $94.0 million for WRC. Renewable Fuel Standards In 2007, the EPA promulgated the Renewable Fuel Standard (‘‘RFS’’), which requires refiners to blend ‘‘renewable fuels’’ in with their transportation fuels or purchase renewable energy credits, known as renewable identification numbers (‘‘RINs’’) in lieu of blending. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 of the prior year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. In 2012, about 9% of all fuel used was required to be ‘‘renewable fuel.’’ About 9.6% of all transportation fuel is required to be ‘‘renewable fuel’’ in 2013. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. motor fuel market, there may be a decrease in demand for petroleum products. The petroleum business currently purchases RINs for some fuel categories on the open market as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with RFS. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. The Wynnewood refinery is required to comply beginning in 2013. In the future, the petroleum business likely will be required to purchase additional RINs on the open market or waiver credits from the EPA to comply with RFS. Recently the price of RINs has been extremely volatile with pricing increases. The petroleum business cannot predict the future prices of RINs or waiver credits, but the costs to obtain the necessary number of RINs and waiver credits could likely be material. Additionally, the Coffeyville and Wynnewood refineries may be impacted by increased operating expenses and production costs to meet the mandated renewable fuel volumes to the extent that these increased costs cannot be passed on to the consumers. Greenhouse Gas Emissions Various regulatory and legislative measures to address greenhouse gas emissions (including carbon dioxide (‘‘CO2’’), methane and nitrous oxides) are in different phases of implementation or discussion. In the aftermath of its 2009 ‘‘endangerment finding’’ that greenhouse gas emissions pose a threat to human health and welfare, the EPA has begun to regulate greenhouse gas emissions under the authority granted to it under the federal Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of greenhouse gases to inventory and report their greenhouse gas emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting our greenhouse gas emissions and are reporting the emissions to the EPA. In May 2010, the EPA finalized the ‘‘Greenhouse Gas Tailoring Rule,’’ which established new greenhouse gas emissions thresholds that determine when stationary sources, such as the refineries and the nitrogen fertilizer plant, must obtain permits under the New Source Review/Prevention of Significant Deterioration (‘‘PSD’’) and Title V programs of the federal Clean Air Act. In cases where a new source is constructed or an existing major source undergoes a major modification, the facility is required to undergo PSD review and evaluate and implement and install best available control technology (‘‘BACT’’) for its greenhouse gas emissions. Phase-in permit requirements began for the largest stationary sources in 2011. A major modification resulting in a significant expansion of production and a significant increase in greenhouse gas emissions at the nitrogen fertilizer plant or the refineries may require the installation of BACT as part of the permitting process. 19 In the meantime, in December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate New Source Performance Standards (‘‘NSPS’’) to regulate greenhouse gas emissions from petroleum refineries. The EPA may propose the NSPS in 2013. During a State of the Union address in February 2013, President Obama indicated that the United States would take action to address climate change. At the federal legislative level, this could mean Congressional passage of legislation adopting some form of federal mandatory greenhouse gas 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 CO2 and other greenhouse gas emissions. In 2007, a group of Midwestern states, including Kansas (where the Coffeyville refinery and the nitrogen fertilizer facility are located), formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control greenhouse gas 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, and it is unclear whether Kansas still intends to do so. Alternatively, the EPA may take further steps to regulate greenhouse gas emissions. The implementation of EPA regulations will 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 greenhouse gas emissions program. Increased costs associated with compliance with any current or future legislation or regulation of greenhouse gas emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and cash flows. 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. RCRA Our operations are subject to the RCRA requirements for the generation, transportation, treatment, storage and disposal of solid and hazardous wastes. When feasible, RCRA-regulated materials are recycled instead of being disposed of on-site or off-site. RCRA establishes standards for the management of solid and hazardous wastes. Besides governing current waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal practices, the recycling of wastes and the regulation of underground storage tanks containing regulated substances. Waste Management. There are two closed hazardous waste units at the Coffeyville refinery and eight other hazardous waste units in the process of being closed pending state agency approval. There is one closed hazardous waste unit and one active hazardous waste storage tank at the Wynnewood refinery. In addition, one closed interim status hazardous waste land farm located at the now-closed Phillipsburg terminal is under long-term post closure care. Impacts of Past Manufacturing. The 2004 Consent Decree that CRRM signed with the EPA and KDHE required us to assume two RCRA corrective action orders issued to Farmland, the prior owner of the Coffeyville refinery. We are subject to a 1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville refinery. In accordance with the order, we have documented existing soil and groundwater conditions, which require investigation or remediation projects. The now-closed Phillipsburg terminal is subject to a 1996 EPA administrative order related to investigation of releases of hazardous materials to the environment at the Phillipsburg terminal, which operated as a refinery until 1991. Remediation at both sites, if 20 necessary, will be based on the results of the investigations. The Wynnewood refinery operates under a RCRA permit. A RCRA facility investigation has been completed in accordance with the terms of the permit. Based on the facility investigation and other available information, the ODEQ has required further investigations of groundwater conditions. Remediation, if necessary, will be based upon the results of further investigation. The anticipated investigation and remediation costs through 2016 were estimated, as of December 31, 2012, to be as follows: Facility Site Investigation Costs Capital Costs Total Operation & Maintenance Costs Through 2016 Total Estimated Costs Through 2016 Coffeyville Refinery . . . . . . . . . . . . . . . . . . . . . . . . Phillipsburg Terminal . . . . . . . . . . . . . . . . . . . . . . . Wynnewood Refinery . . . . . . . . . . . . . . . . . . . . . . . Total Estimated Costs . . . . . . . . . . . . . . . . . . . . . . . $0.5 1.0 — $1.5 (in millions) $0.8 1.2 0.3 $2.3 $— — — $— $1.3 2.2 0.3 $3.8 These estimates are based on current information and could increase or decrease as additional information becomes available through our ongoing remediation and investigation activities. At this point, we have estimated that, over ten years starting in 2013, we will spend approximately $4.9 million to remedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the now-closed Phillipsburg terminal and Wynnewood refinery. It is possible that additional costs will be required after this ten year period. We spent approximately $0.4 million in 2012 associated with related remediation. Financial Assurance. We are required under the 2004 Consent Decree to establish financial assurance to secure the projected clean-up costs posed by the Coffeyville and the now-closed Phillipsburg facilities in the event we fail to fulfill our clean-up obligations. In accordance with the 2004 Consent Decree as modified by a 2010 agreement between CRRM, CRT, the EPA and the KDHE, this financial assurance is currently provided by a bond in the amount of $4.8 million for clean-up obligations at the Phillipsburg terminal and additional self-funded financial assurance of approximately $1.8 million and $2.2 million for clean-up obligations at the Coffeyville refinery and Phillipsburg terminal, respectively. The $4.8 million bond amount is reduced each year based on actual expenditures and corrective actions and the self-funded mechanisms are re-evaluated and adjusted on an annual basis. Current RCRA financial assurance requirements for the Wynnewood refinery total $0.3 million for hazardous waste storage tank closure and post-closure monitoring of a closed storm water retention pond. Environmental Remediation Under the CERCLA, RCRA, and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons 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 OPA of 1990 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. 21 On September 23, 2011, the DOJ, acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas related to a flood and oil spill that occurred at the refinery on June 30/July 1, 2007. The DOJ was seeking recovery of governmental oversight costs under the OPA and a civil penalty under the CWA (as amended by the OPA). DOJ also asserted unrelated claims under the Clean Air Act’s Risk Management Program. CRRM has reached a settlement with DOJ resolving its claims under CWA and OPA, which has been memorialized in the 2013 Consent Decree. See ‘‘— The Federal Clean Air Act’’ above. As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, personal injury or property damage allegedly caused by crude oil or hazardous substances that we manufactured, handled, used, stored, transported, spilled, disposed of or released. We cannot assure you that we will not become involved in future proceedings related to our release of hazardous or extremely hazardous substances or crude oil or that, if we were held responsible for damages in any existing or future proceedings, such costs would be covered by insurance or would not be material. Environmental Insurance We are covered by premises pollution liability insurance policies with an aggregate limit of $50.0 million per pollution condition, subject to a self-insured retention of $5.0 million. The policies include business interruption coverage, subject to a 10-day waiting period deductible. This insurance expires on July 1, 2013. The policies insure specific covered locations, including the refineries and the nitrogen fertilizer facility. The policies insure (i) claims, remediation costs, and associated legal defense expenses for pollution conditions at or migrating from a covered location and (ii) the transportation risks associated with moving waste from a covered location to any location for unloading or depositing waste. The policies cover any claim made during the policy period as long as the pollution conditions giving rise to the claim commenced on or after March 3, 2004. The premises pollution liability policies contain exclusions, conditions, and limitations that could apply to a particular pollution condition claim, and there can be no assurance such claim will be adequately insured for all potential damages. In addition to the premises pollution liability insurance policies, we benefit from casualty insurance policies having an aggregate and occurrence limit of $150.0 million, subject to a self-insured retention of $2.0 million. This insurance provides coverage for claims involving pollutants where the discharge is sudden and accidental and first commenced at a specific day and time during the policy period. Coverage under the casualty insurance policies for pollution does not apply to damages at or within our insured premises. The pollution coverage provided in the casualty insurance policies contains exclusions, definitions, conditions and limitations that could apply to a particular pollution claim, and there can be no assurance such claim will be adequately insured for all potential damages. Safety, Health and Security Matters We operate a comprehensive safety, health and security program, with participation by employees at all levels of the organization. We have developed comprehensive safety programs aimed at preventing OSHA recordable incidents. Despite our efforts to achieve excellence in our safety and health performance, there can be no assurances that there will not be accidents resulting in injuries or even fatalities. We routinely audit our programs and consider improvements in our management systems. The Wynnewood refinery has been the subject of a number of OSHA inspections since 2006. As a result of these inspections, the Wynnewood refinery has entered into four OSHA settlement agreements in 2008, pursuant to which it has agreed to undertake certain studies, conduct abatement activities, and revise and enhance certain OSHA compliance programs. The remaining costs associated 22 with implementing these studies, abatement activities and program revisions are not expected to exceed $1.0 million. Process Safety Management. We maintain a process safety management (‘‘PSM’’) program. This program is designed to address all aspects of the OSHA guidelines for developing and maintaining a comprehensive PSM program. We will continue to audit our programs and consider improvements in our management systems as well as our operations. Emergency Planning and Response. We have an emergency response plan that describes the organization, responsibilities and plans for responding to emergencies in our facilities. This plan is communicated to local regulatory and community groups. We have on-site warning siren systems and personal radios. We will continue to audit our programs and consider improvements in our management systems and equipment. Employees As of December 31, 2012, 832 employees were employed by the petroleum business, 139 were employed by the nitrogen fertilizer business and 120 employees were employed by the Company at our offices in Sugar Land, Texas, Kansas City, Kansas and Oklahoma City, Oklahoma. These employees are covered by health insurance, disability and retirement plans established by the Company. As of December 31, 2012, the Coffeyville refinery employed approximately 570 of the petroleum business employees, about 53% of whom were covered by a collective bargaining agreement. These employees are affiliated with six unions of the Metal Trades Department of the AFL-CIO (‘‘Metal Trade Unions’’) and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO-CLC (‘‘United Steelworkers’’). A new collective bargaining agreement, which covers union members who work directly at the Coffeyville refinery, was entered into with the Metal Trade Unions effective December 2012 and is effective through March 2017. No substantial changes were made to the prior agreement. In addition, a new collective bargaining agreement, which covers the balance of the Company’s unionized employees who work in the terminalling and related operations, was entered into with the United Steelworkers in March 2012. The United Steelworkers collective bargaining agreement is effective through March 2015 and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date. There were no substantial changes to the prior agreement. As of December 31, 2012, the Wynnewood refinery employed approximately 260 people, about 62% of whom were represented by the International Union of Operating Engineers. The collective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2015. We believe that our relationship with our employees is good. Available Information Our website address is www.cvrenergy.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports, are available free of charge through our website under ‘‘Investor Relations,’’ as soon as reasonably practicable after the electronic filing of these reports is made with the Securities and Exchange Commission (the ‘‘SEC’’). In addition, our Corporate Governance Guidelines, Codes of Ethics and Charters of the Audit Committee, the Nominating and Corporate Governance Committee and the Compensation Committee of the Board of Directors are available on our website. These guidelines, policies and charters are also available in print without charge to any stockholder requesting them. Our SEC filings, including exhibits filed therewith, are also available at the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, DC 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, 23 upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, DC 20549. Trademarks, Trade Names and Service Marks This Report may include our and our affiliates’ trademarks, including the CVR Energy logo, Coffeyville Resources, the Coffeyville Resources logo, the CVR Refining, LP logo and the CVR Partners, LP logo, each of which is registered or for which we are applying for federal registration with the United States Patent and Trademark Office. This Report may also contain trademarks, service marks, copyrights and trade names of other companies. Item 1A. Risk Factors You should carefully consider each of the following risks together with the other information contained in this Report and all of the information set forth in our filings with the SEC. If any of the following risks and uncertainties develops into actual events, our business, financial condition or results of operations could be materially adversely affected. Risks Related to the Petroleum Business The price volatility of crude oil and other feedstocks, refined products and utility services may have a material adverse effect on the petroleum business’ earnings, profitability and cash flows. The petroleum business’ financial results are primarily affected by the relationship, or margin, between refined product prices and the prices for crude oil and other feedstocks. When the margin between refined product prices and crude oil and other feedstock prices tightens, the petroleum business’ earnings, profitability and cash flows are negatively affected. Refining margins historically have been volatile and are likely to continue to be volatile, as a result of a variety of factors including fluctuations in prices of crude oil, other feedstocks and refined products. Continued future volatility in refining industry margins may cause a decline in the petroleum business’ results of operations, since the margin between refined product prices and crude oil and other feedstock prices may decrease below the amount needed for the petroleum business to generate net cash flow sufficient for its needs. Although an increase or decrease in the price for crude oil generally results in a similar increase or decrease in prices for refined products, there is normally a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on the petroleum business’ results of operations therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, or a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, could have a significant negative impact on the petroleum business’ earnings, results of operations and cash flows. Profitability is also impacted by the ability to purchase crude oil at a discount to benchmark crude oils, such as WTI, as the petroleum business does not produce any crude oil and must purchase all of the crude oil it refines. Crude oil differentials can fluctuate significantly based upon overall economic and crude oil market conditions. Declines in crude oil differentials can adversely impact refining margins, earnings and cash flows. For example, infrastructure and logistical improvements could result in a reduction of the WTI-Brent differential that has recently provided the petroleum business with increased profitability. In addition, the petroleum business’ purchases of crude oil, although based on WTI prices, have historically been at a discount to WTI because of the proximity of the refineries to the sources, existing logistics infrastructure and quality differences. Any change in the sources of crude oil, infrastructure or logistical improvements or quality differences could result in a reduction of the petroleum business’ historical discount to WTI and may result in a reduction of the petroleum business’ cost advantage. 24 Refining margins are also impacted by domestic and global refining capacity. Downturns in the economy reduce the demand for refined fuels and, in turn, generate excess capacity. In addition, the expansion and construction of refineries domestically and globally can increase refined fuel production capacity. Excess capacity can adversely impact refining margins, earnings and cash flows. During 2011 and 2012, favorable crack spreads and access to a variety of price-advantaged crude oils resulted in higher Adjusted EBITDA and cash flow generation that was greater than usual. There can be no assurance that these favorable conditions will continue and, in fact, crack spreads, refining margins and crude oil prices could decline, possibly materially, at any time. In particular, Enbridge Inc.’s purchase of 50% of the Seaway crude oil pipeline and the recent reversal of the pipeline to make it flow from Cushing to the U.S. Gulf Coast and the Seaway capacity expansion project may contribute to the decline of such favorable conditions by providing mid-continent producers with the ability to transport crude oil to Gulf Coast refiners in an economic manner. Crude oil began flowing through the Seaway Pipeline from Cushing to the Gulf Coast in May 2012, and an expansion project increasing total capacity from 150,000 bpd to 400,000 bpd was completed in January 2013. Moreover, the planned construction of a loop (twin) of the Seaway Pipeline, a new pipeline designed to parallel the existing right-of-way from Cushing to the Gulf Coast, is expected to more than double Seaway’s capacity to 850,000 bpd by mid-2014. A significant deterioration of the current favorable conditions would have a material adverse effect on the petroleum business’ earnings, results of operations and cash flows. Volatile prices for natural gas and electricity also affect the petroleum business’ manufacturing and operating costs. Natural gas prices reached ten-year lows in 2012. Natural gas and electricity prices have been, and will continue to be, affected by supply and demand for fuel and utility services in both local and regional markets. If the petroleum business is required to obtain its crude oil supply without the benefit of a crude oil supply agreement, its exposure to the risks associated with volatile crude oil prices may increase and its liquidity may be reduced. Since December 31, 2009, the petroleum business has obtained substantially all of its crude oil supply for the Coffeyville refinery, other than the crude oil it gathers, through the Vitol Agreement. The Vitol Agreement was amended and restated on August 31, 2012 to include the provision of crude oil intermediation services to the Wynnewood refinery. The agreement, whose initial term expires on December 31, 2014, minimizes the amount of in-transit inventory and mitigates crude oil pricing risks by ensuring pricing takes place close to the time when the crude oil is refined and the yielded products are sold. If the petroleum business were required to obtain its crude oil supply without the benefit of a supply intermediation agreement, its exposure to crude oil pricing risks may increase, despite any hedging activity in which it may engage, and its liquidity would be negatively impacted due to increased inventory and the negative impact of market volatility. Disruption of the petroleum business’ ability to obtain an adequate supply of crude oil could reduce its liquidity and increase its costs. For the Coffeyville refinery, in addition to the crude oil the petroleum business gathers locally in Kansas, Oklahoma, Missouri, and Nebraska, it purchased an additional 70,000 to 75,000 bpd of crude oil to be refined into liquid fuels in 2012. Although the Wynnewood refinery has historically acquired most of its crude oil from Texas and Oklahoma, it also purchases crude oil from other regions. Coffeyville obtains a portion of its non-gathered crude oil, approximately 17% in 2012, from foreign sources and Wynnewood obtained approximately 7% of its non-gathered crude oil from foreign sources as well. The majority of these foreign sourced crude oil barrels were derived from Canada. The actual amount of foreign crude oil the petroleum business purchases is dependent on market conditions and will vary from year to year. The petroleum business is subject to the political, geographic, and economic 25 risks attendant to doing business with foreign suppliers. Disruption of production in any of these regions for any reason could have a material impact on other regions and the petroleum business. In the event that one or more of its traditional suppliers becomes unavailable, the petroleum business may be unable to obtain an adequate supply of crude oil, or it may only be able to obtain crude oil at unfavorable prices. As a result, the petroleum business may experience a reduction in its liquidity and its results of operations could be materially adversely affected. If our access to the pipelines on which the petroleum business relies for the supply of its crude oil and the distribution of its products is interrupted, its inventory and costs may increase and it may be unable to efficiently distribute its products. If one of the pipelines on which either of the Coffeyville or Wynnewood refineries relies for supply of crude oil becomes inoperative, the petroleum business would be required to obtain crude oil through alternative pipelines or from additional tanker trucks, which could increase its costs and result in lower production levels and profitability. Similarly, if a major refined fuels pipeline becomes inoperative, the petroleum business would be required to keep refined fuels in inventory or supply refined fuels to its customers through an alternative pipeline or by additional tanker trucks, which could increase the petroleum business’ costs and result in a decline in profitability. The geographic concentration of the petroleum business’ refineries and related assets creates an exposure to the risks of the local economy and other local adverse conditions. The location of its refineries also creates the risk of increased transportation costs should the supply/demand balance change in its region such that regional supply exceeds regional demand for refined products. As the refineries are both located in the southern portion of Group 3 of the PADD II region, the petroleum business primarily markets its refined products in a relatively limited geographic area. As a result, it is more susceptible to regional economic conditions than the operations of more geographically diversified competitors, and any unforeseen events or circumstances that affect its operating area could also materially adversely affect its revenues and cash flows. These factors include, among other things, changes in the economy, weather conditions, demographics and population, increased supply of refined products from competitors and reductions in the supply of crude oil. Should the supply/demand balance shift in its region as a result of changes in the local economy, an increase in refining capacity or other reasons, resulting in supply in the region exceeding demand, the petroleum business may have to deliver refined products to customers outside of the region and thus incur considerably higher transportation costs, resulting in lower refining margins, if any. If sufficient RINs are unavailable for purchase or 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 Renewable Fuels Standard mandates, the petroleum business’ financial condition and results of operations could be materially adversely affected. Pursuant to the Energy Independence and Security Act of 2007, the EPA, has promulgated the RFS, which requires refiners to blend ‘‘renewable fuels,’’ such as ethanol, with their petroleum fuels or purchase renewable energy credits, known as RINs, in lieu of blending. Under the RFS, the volume of renewable fuels refineries like Coffeyville and Wynnewood are obligated to blend into their finished petroleum products increases annually over time until 2022. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. The Wynnewood refinery is required to comply beginning in 2013. The petroleum business currently purchases RINs for some fuel categories on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. Existing laws or regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum products may increase. In the future, the petroleum business may be required to purchase additional 26 RINs on the open market and waiver credits from EPA in order to comply with the RFS. Recently the price of RINs has been extremely volatile with pricing increases. The petroleum business cannot predict the future prices of RINs or waiver credits, but the costs to obtain the necessary number of RINs and waiver credits could likely be material. Additionally, because the petroleum business does not produce renewable fuels, increasing the volume of renewable fuels that must be blended into its products displaces an increasing volume of the refineries’ product pool, potentially resulting in lower earning and materially adversely affecting the petroleum business’ cash flows. If the petroleum business is unable to pass the costs of compliance with RFS on to customers, the petroleum business’ profits would be significantly lower. Moreover, if sufficient RINs are unavailable for purchase or 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. The petroleum business faces significant competition, both within and outside of its industry. Competitors who produce their own supply of crude oil or other feedstocks, have extensive retail outlets, make alternative fuels or have greater financial resources than it does may have a competitive advantage. The refining industry is highly competitive with respect to both crude oil and other feedstock supply and refined product markets. The petroleum business may be unable to compete effectively with competitors within and outside of the industry, which could result in reduced profitability. The petroleum business competes with numerous other companies for available supplies of crude oil and other feedstocks and for outlets for its refined products. The petroleum business is not engaged in the petroleum exploration and production business and therefore it does not produce any of its crude oil feedstocks. It does not have a retail business and therefore is dependent upon others for outlets for its refined products. It does not have any long-term arrangements (those exceeding more than a twelve- month period) for much of its output. Many of its competitors obtain significant portions of their crude oil and other feedstocks from company-owned production and have extensive retail outlets. Competitors that have their own production or extensive retail outlets with brand-name recognition are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. A number of the petroleum business’ competitors also have materially greater financial and other resources than it does. These competitors may have a greater ability to bear the economic risks inherent in all aspects of the refining industry. An expansion or upgrade of its 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 and may add additional competitive pressure. In addition, the petroleum business competes with other industries that provide alternative means to satisfy the energy and fuel requirements of its industrial, commercial and individual customers. There are presently significant governmental incentives and consumer pressures to increase the use of alternative fuels in the United States. The more successful these alternatives become as a result of governmental incentives or regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the negative impact on pricing and demand for the petroleum business’ products and profitability. Changes in the petroleum business’ credit profile may affect its relationship with its suppliers, which could have a material adverse effect on its liquidity and its ability to operate the refineries at full capacity. Changes in the petroleum business’ credit profile may affect the way crude oil suppliers view its ability to make payments and may induce them to shorten the payment terms for purchases or require 27 it to post security prior to payment. Given the large dollar amounts and volume of the petroleum business’ crude oil and other feedstock purchases, a burdensome change in payment terms may have a material adverse effect on the petroleum business’ liquidity and its ability to make payments to its suppliers. This, in turn, could cause it to be unable to operate the refineries at full capacity. A failure to operate the refineries at full capacity could adversely affect the petroleum business’ profitability and cash flows. The petroleum business’ commodity derivative contracts may limit its potential gains, exacerbate potential losses and involve other risks. The petroleum business enters into commodity derivatives contracts to mitigate crack spread risk with respect to a portion of its expected refined products production. However, its hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including its failure to have adequate hedging contracts, if any, in effect at any particular time and the failure of its hedging arrangements to produce the anticipated results. The petroleum business may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit its ability to benefit from favorable changes in margins. In addition, the petroleum business’ hedging activities may expose it to the risk of financial loss in certain circumstances, including instances in which: • the volumes of its actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedging arrangement; • the counterparties to its futures contracts fail to perform under the contracts; or • sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement. As a result, the effectiveness of the petroleum business’ risk mitigation strategy could have a material adverse impact on the petroleum business’ financial results and cash flows. The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on the petroleum business’ ability to hedge risks associated with its business. The U.S. Congress has adopted the Dodd-Frank Act, comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market, and requires the Commodities Futures Trading Commission (‘‘CFTC’’) to institute broad new position limits for futures and options traded on regulated exchanges. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation. The rulemaking process is still ongoing, and the petroleum business cannot predict the ultimate outcome of the rulemakings. New regulations in this area may result in increased costs and cash collateral requirements for derivative instruments the petroleum business may use to hedge and otherwise manage its financial risks related to volatility in oil and gas commodity prices. Existing design, operational, and maintenance issues associated with acquisitions may not be identified immediately and may require unanticipated capital expenditures that could adversely impact our financial condition, results of operations or cash flows. Our due diligence associated with asset acquisitions may result in assuming liabilities associated with unknown conditions or deficiencies, as well as known but undisclosed conditions and deficiencies that we may have limited, if any, recourse for cost recovery. Many acquisition agreements have similar terms, conditions and timing of cost recovery that may not become evident until sometime after cost recovery provisions, if any, have expired. 28 The petroleum business must make substantial capital expenditures on its refineries and other facilities to maintain their reliability and efficiency. If the petroleum business is unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in project economics deteriorate, the petroleum business’ financial condition, results of operations or cash flows could be adversely affected. Delays or cost increases related to the engineering, procurement and construction of new facilities, or improvements and repairs to the petroleum business’ existing facilities and equipment, could have a material adverse effect on the petroleum business’ financial condition, results of operations or cash flows. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond its control, including: • denial or delay in obtaining regulatory approvals and/or permits; • unplanned increases in the cost of equipment, materials or labor; • disruptions in transportation of equipment and materials; • severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting the petroleum business’ facilities, or those of its vendors and suppliers; • shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; • market-related increases in a project’s debt or equity financing costs; and/or • nonperformance or force majeure by, or disputes with, the petroleum business’ vendors, suppliers, contractors or sub-contractors. The Coffeyville and Wynnewood refineries have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. For example, the petroleum business spent approximately $88.8 million on the most recently completed turnaround at the Coffeyville refinery and incurred approximately $102.5 million associated with the turnaround for the Wynnewood refinery, which the petroleum business completed in December 2012. These costs do not result in increases in unit capacities, but rather are focused on trying to maintain safe, reliable operations. Any one or more of these occurrences noted above could have a significant impact on the petroleum business. If the petroleum business was unable to make up the delays or to recover the related costs, or if market conditions change, it could materially and adversely affect the petroleum business’ financial position, results of operations or cash flows. The petroleum business’ plans to expand the gathering assets making up part of its supporting logistics businesses, which assist it in reducing costs and increasing processing margins, may expose it to significant additional risks, compliance costs and liabilities. The petroleum business plans to continue to make investments to enhance the operating flexibility of its refineries and to improve its crude oil sourcing advantage through additional investments in gathering and logistics operations. If it is able to successfully increase the effectiveness of the supporting logistics businesses, including the crude oil gathering operations, the petroleum business believes it will be able to enhance crude oil sourcing flexibility and reduce related crude oil purchasing and delivery costs. However, the acquisition of infrastructure assets to expand gathering operations may expose the petroleum business to risks in the future that are different than or incremental to the risks it faces with respect to its refineries and existing gathering and logistics operations. The storage and transportation of liquid hydrocarbons, including crude oil and refined products, are subject to stringent 29 federal, state, and local laws and regulations governing the discharge of materials into the environment, operational safety and related matters. Compliance with these laws and regulations could adversely affect the petroleum business’ operating results, financial condition and cash flows. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, the issuance of injunctions that may restrict or prohibit the petroleum business’ operations, or claims of damages to property or persons resulting from its operations. Any businesses or assets that the petroleum business may acquire in connection with an expansion of its crude oil gathering operations could expose it to the risk of releasing hazardous materials into the environment. These releases would expose the petroleum business to potentially substantial expenses, including clean-up and remediation costs, fines and penalties, and third-party claims for personal injury or property damage related to past or future releases. Accordingly, if the petroleum business does acquire any such businesses or assets, it could also incur additional expenses not covered by insurance which could be material. More stringent trucking regulations may increase the petroleum business’ costs and negatively impact its results of operations. In connection with the trucking operations conducted by its crude gathering division, the petroleum business operates as a motor carrier and therefore is subject to regulation by the U.S. Department of Transportation and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. Furthermore, from time to time, various legislative proposals are introduced, such as proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase the petroleum business’ costs or adversely impact the recruitment of drivers. The petroleum business cannot predict whether, or in what form, any increase in such taxes will be enacted or the extent to which they will apply to the petroleum business and its operations. Risks Related to the Nitrogen Fertilizer Business The nitrogen fertilizer business is, and nitrogen fertilizer prices are, cyclical and highly volatile, and the nitrogen fertilizer business has experienced substantial downturns in the past. Cycles in demand and pricing could potentially expose the nitrogen fertilizer business to significant fluctuations in its operating and financial results and have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. The nitrogen fertilizer business is exposed to fluctuations in nitrogen fertilizer demand in the agricultural industry. These fluctuations historically have had and could in the future have significant effects on prices across all nitrogen fertilizer products and, in turn, our results of operations, financial condition and cash flows. 30 Nitrogen fertilizer products are commodities, the price of which can be highly volatile. The prices of nitrogen fertilizer products depend on a number of factors, including general economic conditions, cyclical trends in end-user markets, supply and demand imbalances, and weather conditions, which have a greater relevance because of the seasonal nature of fertilizer application. If seasonal demand exceeds the projections on which the nitrogen fertilizer business bases production, customers may acquire nitrogen fertilizer products from competitors, and the profitability of the nitrogen fertilizer business will be negatively impacted. If seasonal demand is less than expected, the nitrogen fertilizer business will be left with excess inventory that will have to be stored or liquidated. Demand for nitrogen fertilizer products is dependent on demand for crop nutrients by the global agricultural industry. Nitrogen-based fertilizers are currently in high demand, driven by a growing world population, changes in dietary habits and an expanded use of corn for the production of ethanol. Supply is affected by available capacity and operating rates, raw material costs, government policies and global trade. A decrease in nitrogen fertilizer prices would have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. The costs associated with operating the nitrogen fertilizer plant are largely fixed. 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 nitrogen fertilizer business has largely fixed costs that are not dependent on the price of natural gas because it uses pet coke as the primary feedstock in the nitrogen fertilizer plant. As a result of the fixed cost nature of our 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, which reached ten-year lows in 2012, is a large component of the total production cost for natural gas-based nitrogen fertilizer manufacturers. The dramatic increase in nitrogen fertilizer prices in recent years has not been the direct result of an increase in natural gas prices, but rather the result of increased demand for nitrogen-based fertilizers due to historically low stocks of global grains and a surge in the prices of corn and wheat, the primary crops in the nitrogen fertilizer business’ region. This increase in demand for nitrogen-based fertilizers has created an environment in which nitrogen fertilizer prices have disconnected from their traditional correlation with natural gas prices. 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. Continued low natural gas prices could impair the nitrogen fertilizer business’ ability 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. In addition, if low natural gas prices in the United States were to prompt those U.S. producers who have permanently or temporarily closed production facilities to resume fertilizer production, this would likely contribute to a global supply/demand imbalance that could negatively affect nitrogen fertilizer prices and therefore have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. 31 Any decline in U.S. agricultural production or limitations on the use of nitrogen fertilizer for agricultural purposes could have a material adverse effect on the sales of nitrogen fertilizer, and on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. Conditions in the U.S. agricultural industry significantly impact the operating results of the nitrogen fertilizer business. The U.S. agricultural industry can be affected by a number of factors, including weather patterns and field conditions, current and projected grain inventories and prices, domestic and international population changes, demand for U.S. agricultural products and U.S. and foreign policies regarding trade in agricultural products. State and federal governmental policies, including farm and biofuel subsidies and commodity support programs, as well as the prices of fertilizer products, may also directly or indirectly influence the number of acres planted, the mix of crops planted and the use of fertilizers for particular agricultural applications. Developments in crop technology, such as nitrogen fixation (the conversion of atmospheric nitrogen into compounds that plants can assimilate), could also reduce the use of chemical fertilizers and adversely affect the demand for nitrogen fertilizer. In addition, from time to time various state legislatures have considered limitations on the use and application of chemical fertilizers due to concerns about the impact of these products on the environment. Unfavorable state and federal governmental policies could negatively affect nitrogen fertilizer prices and therefore have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. A major factor underlying the current high level of demand for nitrogen-based fertilizer products is the production of ethanol. A decrease in ethanol production, an increase in ethanol imports or a shift away from corn as a principal raw material used to produce ethanol could have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. A major factor underlying the current high level of demand for nitrogen-based fertilizer products produced by the nitrogen fertilizer business is the production of ethanol in the United States and the use of corn in ethanol production. Ethanol production in the United States is highly dependent upon a myriad of federal statutes and regulations, and is made significantly more competitive by various federal and state incentives, mandated usage and production of ethanol pursuant to the RFS, such as E10 and E15, gasoline blends with 10% and 15% ethanol, respectively. However, a number of factors, including the drought, the continuing ‘‘food versus fuel’’ debate and studies showing that expanded ethanol usage may increase the level of greenhouse gases in the environment as well as be unsuitable for small engine use, have resulted in calls to reduce subsidies for ethanol, allow increased ethanol imports and to repeal or adopt temporary waivers of the current renewable fuel standard, any of which could have an adverse effect on corn-based ethanol production, planted corn acreage and fertilizer demand. The nation’s fiscal crisis also establishes a situation in which all tax incentives, treatments and credits are being reevaluated as a means to resolve the deficit situation. Therefore, ethanol incentive programs may not be renewed, or if renewed, they may be renewed on terms significantly less favorable to ethanol producers than current incentive programs. For example, on December 31, 2011, Congress allowed both the 45 cents per gallon ethanol tax credit and the 54 cents per gallon ethanol import tariff to expire. In other action, the EPA’s proposed E15 RFS will continue to be challenged in court and legislative action. These actions could have a material adverse effect on ethanol production in the United States, which could have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. Further, while most ethanol is currently produced from corn and other raw grains, such as milo or sorghum, the current RFS mandate requires a portion of ethanol production and usage in the United States to come from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste and energy crops (plants grown for use to make biofuels or directly exploited for their energy content). 32 The federal act to implement the RFS required oil companies to blend 250 million gallons of cellulosic ethanol into their gasoline in 2011. The mandate doubled this amount for 2012, and by 2022 it will be 16 billion gallons. Very little cellulosic ethanol is available in the commercial market, and on January 25, 2013, the U.S. Court of Appeals for the District of Columbia ruled that the mandate needs to be revised. Congress will consider legislation to revise the cellulosic ethanol mandate. Notwithstanding the foregoing, the trends to move to products other than corn and raw grains for ethanol production. If this trend is successful, the demand for corn may decrease significantly, which could reduce demand for nitrogen fertilizer products and have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. Nitrogen fertilizer products are global commodities, and the nitrogen fertilizer business faces intense competition from other nitrogen fertilizer producers. The nitrogen fertilizer business is subject to intense price competition from both U.S. and foreign sources, including competitors operating in the Persian Gulf, the Asia-Pacific region, the Caribbean, Russia and the Ukraine. Fertilizers are global commodities, with little or no product differentiation, and customers make their purchasing decisions principally on the basis of delivered price and availability of the product. Furthermore, in recent years the price of nitrogen fertilizer in the United States has been substantially driven by pricing in the global fertilizer market. The nitrogen fertilizer business competes with a number of U.S. producers and producers in other countries, including state-owned and government-subsidized entities. Some competitors have greater total resources and are less dependent on earnings from fertilizer sales, which makes them less vulnerable to industry downturns and better positioned to pursue new expansion and development opportunities. The nitrogen fertilizer business’ competitive position could suffer to the extent it is not able to expand its resources either through investments in new or existing operations or through acquisitions, joint ventures or partnerships, or otherwise compete successfully in the global nitrogen fertilizer market. An inability to compete successfully could result in a loss of customers, which could adversely affect the sales, profitability and the cash flows of the nitrogen fertilizer business and therefore have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. The nitrogen fertilizer business is seasonal, which may result in it carrying significant amounts of inventory and seasonal variations in working capital. Our inability to predict future seasonal nitrogen fertilizer demand accurately may result in excess inventory or product shortages. The 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. The strongest demand for nitrogen fertilizer products typically occurs during the planting season. In contrast, the nitrogen fertilizer business and other nitrogen fertilizer producers generally produce products throughout the year. As a result, the nitrogen fertilizer business and its customers generally build inventories during the low demand periods of the year in order to ensure timely product availability during the peak sales seasons. The seasonality of nitrogen fertilizer demand results in sales volumes and net sales being highest during the North American spring season and working capital requirements typically being highest just prior to the start of the spring season. If seasonal demand exceeds projections, the nitrogen fertilizer business will not have enough product and its customers may acquire products from its competitors, which would negatively impact profitability. If seasonal demand is less than expected, the nitrogen fertilizer business will be left with excess inventory and higher working capital and liquidity requirements. The degree of seasonality of the nitrogen fertilizer business can change significantly from year to year due to conditions in the agricultural industry and other factors. As a consequence of such 33 seasonality, it is expected that the distributions we receive from the nitrogen fertilizer business will be volatile and will vary quarterly and annually. Adverse weather conditions during peak fertilizer application periods may have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows, because the agricultural customers of the nitrogen fertilizer business are geographically concentrated. The nitrogen fertilizer business’ sales to agricultural customers are concentrated in the Great Plains and Midwest states and are seasonal in nature. The nitrogen fertilizer business’ quarterly results may vary significantly from one year to the next due largely to weather-related shifts in planting schedules and purchase patterns. For example, the nitrogen fertilizer business generates greater net sales and operating income in the first half of the year, which is referred to herein as the planting season, compared to the second half of the year. Accordingly, an adverse weather pattern affecting agriculture in these regions or during the planting season could have a negative effect on fertilizer demand, which could, in turn, result in a material decline in the nitrogen fertilizer business’ net sales and margins and otherwise have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. The nitrogen fertilizer business’ quarterly results may vary significantly from one year to the next due largely to weather-related shifts in planting schedules and purchase patterns. As a result, it is expected that the nitrogen fertilizer business’ distributions to holders of its common units (including us) will be volatile and will vary quarterly and annually. The nitrogen fertilizer business’ operations are dependent on third-party suppliers, including Linde, which owns an air separation plant that provides oxygen, nitrogen and compressed dry air to its gasifiers, and the City of Coffeyville, which supplies the nitrogen fertilizer business with electricity. A deterioration in the financial condition of a third- party supplier, a mechanical problem with the air separation plant, 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. The operations of the nitrogen fertilizer business 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, operations 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 nitrogen fertilizer plant was disrupted. Additionally, this air separation plant in the past has experienced numerous short-term interruptions, causing interruptions in gasifier operations. With respect to electricity, in 2010, the nitrogen fertilizer business settled litigation with the City of Coffeyville regarding the price they sought to charge the nitrogen fertilizer business for electricity and entered into an amended and restated electric services agreement which gives the nitrogen fertilizer business an option to extend the term of such agreement through June 30, 2024. Should Linde, the City of Coffeyville or any of its other third-party suppliers fail to perform in accordance with existing contractual arrangements, operations could be forced to halt. Alternative sources of supply could be difficult to obtain. Any shutdown of operations at the nitrogen fertilizer plant, even for a limited period, could have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. 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 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 nitrogen fertilizer business in the manufacture of nitrogen fertilizer products. If pet coke 34 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 nitrogen fertilizer business 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 currently purchases 100% of the pet coke the Coffeyville refinery produces. Accordingly, if the nitrogen fertilizer business increases production, it will be more dependent on pet coke purchases from third-party suppliers at open market prices. The nitrogen fertilizer business entered into a pet coke supply agreement with HollyFrontier Corporation which became effective on March 1, 2012. The initial term ends in December 2013 and the agreement is subject to renewal. There is no assurance that the nitrogen fertilizer business would be able to purchase pet coke on comparable terms from third parties or at all. 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 its customers. The nitrogen fertilizer business also leases railcars from railcar owners in order to ship its finished products. 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. 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. The nitrogen fertilizer business’ results of operations are highly dependent upon and fluctuate based upon business and economic conditions and governmental policies affecting the agricultural industry. These factors are outside of our control and may significantly affect our profitability. The nitrogen fertilizer business’ results of operations are highly dependent upon business and economic conditions and governmental policies affecting the agricultural industry, which we cannot control. The agricultural products business can be affected by a number of factors. The most important of these factors in the United States are: • weather patterns and field conditions (particularly during periods of traditionally high nitrogen fertilizer consumption); • quantities of nitrogen fertilizers imported to and exported from North America; 35 • current and projected grain inventories and prices, which are heavily influenced by U.S. exports and world-wide grain markets; and • U.S. governmental policies, including farm and biofuel policies, which may directly or indirectly influence the number of acres planted, the level of grain inventories, the mix of crops planted or crop prices. International market conditions may also significantly influence its operating results. The international market for nitrogen fertilizers is influenced by such factors as the relative value of the U.S. dollar and its impact upon the cost of importing nitrogen fertilizers, foreign agricultural policies, the existence of, or changes in, import or foreign currency exchange barriers in certain foreign markets, changes in the hard currency demands of certain countries and other regulatory policies of foreign governments, as well as the laws and policies of the United States affecting foreign trade and investment. Ammonia can be very volatile and extremely hazardous. Any liability for accidents involving ammonia or other products we produce or transport 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 nitrogen fertilizer facility periodically experiences minor releases of ammonia related to leaks from its equipment. It experienced more significant ammonia releases in August 2007 due to the failure of a high-pressure pump and in August and September 2010 due to a heat exchanger leak and a UAN vessel rupture. 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 we produce or transport 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 36 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. Environmental laws and regulations on fertilizer end-use and application and numeric nutrient water quality criteria could have a material adverse impact on fertilizer demand in the future. Future environmental laws and regulations on the end-use and application of fertilizers could cause changes in demand for the nitrogen fertilizer business’ products. In addition, future environmental laws and regulations, or new interpretations of existing laws or regulations, could limit the ability of the nitrogen fertilizer business to market and sell its products to end users. From time to time, various state legislatures have proposed bans or other limitations on fertilizer products. In addition, a number of states have adopted or proposed numeric nutrient water quality criteria that could result in decreased demand for fertilizer products in those states. For example, on November 30, 2012, EPA formally approved Florida’s numeric nutrient limits pertaining to streams, spring vents, lakes, and south Florida estuaries and proposed tow new rules to limit nutrients in water bodies not covered under the Florida rules. If such laws, rules, regulations or interpretations to significantly curb the end-use or application of fertilizers were promulgated in our marketing areas, it could result in decreased demand for our products and have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. 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 it uses 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 nitrogen 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. The nitrogen fertilizer business may face third-party claims of intellectual property infringement, which if successful could result in significant costs. Although there are currently no pending claims relating to the infringement of any third party intellectual property rights, in the future the nitrogen fertilizer business may face claims of infringement that could interfere with its ability to use technology that is material to its business operations. Any litigation of this type, whether successful or unsuccessful, could result in substantial costs and diversions of resources, which could have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. In the event a claim of infringement against the nitrogen fertilizer business is successful, it may be required to pay royalties or license fees for past or continued use of the infringing technology, or it may be prohibited from using the infringing technology altogether. If it is prohibited from using any technology as a result of such a claim, it may not be able to obtain licenses to alternative technology adequate to substitute for the technology it can no longer use, or licenses for such alternative technology 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 the nitrogen fertilizer business to make substantial changes to its manufacturing processes or equipment or to its products, and could have a material adverse effect on the nitrogen fertilizer business’ results of operations, financial condition and cash flows. 37 There can be no assurance that the transportation costs of the nitrogen fertilizer business’ competitors will not decline. The nitrogen fertilizer plant is located within the U.S. farm belt, where the majority of the end users of its nitrogen fertilizer products grow their crops. Many of its 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. 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 revolving credit facility 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. • 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. • 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 facility face operating hazards and interruptions, including unplanned maintenance or downtime. We could face potentially significant costs to the extent these hazards or interruptions cause a material decline in production and are not fully covered by our existing insurance coverage. Insurance companies that currently insure companies in the energy industry may cease to do so, may change 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 facilities, including the Coffeyville or Wynnewood refineries or the nitrogen fertilizer plant, experiences a major accident or fire, is damaged by severe weather, flooding or other natural disaster, or is otherwise forced to significantly curtail its operations or shut down, we could incur significant losses which could have a material adverse effect on our results of operations, financial condition and cash flows. Conducting the majority of our refining operations and all of our fertilizer manufacturing at a single location compounds such risks. 38 Operations at either or both of the refineries and the nitrogen fertilizer plant could be curtailed or partially or completely shut down, temporarily or permanently, as the result of a number of circumstances, most of which are not within our control, such as: • unplanned maintenance or catastrophic events such as a major accident or fire, damage by severe weather, flooding or other natural disaster; • labor difficulties that result in a work stoppage or slowdown; • environmental proceedings or other litigation that compel the cessation of all or a portion of the operations; • state and federal agencies changing interpretations and enforcement of historical environmental rules and regulations; and • increasingly stringent environmental regulations. The magnitude of the effect on us of any shutdown will depend on the length of the shutdown and the extent of the plant operations affected by the shutdown. The refineries require a planned maintenance turnaround every four to five years for each unit, and the nitrogen fertilizer plant requires a planned maintenance turnaround every two years. A major accident, fire, flood, or other event could damage our facilities or the environment and the surrounding community or result in injuries or loss of life. For example, the flood that occurred during the weekend of June 30, 2007 shut down the Coffeyville refinery for seven weeks, shut down the nitrogen fertilizer facility for approximately two weeks and required significant expenditures to repair damaged equipment. In addition, the nitrogen fertilizer business’ UAN plant was out of service for approximately six weeks after the rupture of a high pressure vessel in September 2010 which required significant expenditures to repair. The Coffeyville refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit on December 28, 2010, which led to reduced crude oil throughput for approximately one month and required significant expenditures to repair. Similarly, the Wynnewood refinery experienced a small explosion and fire in its hydrocracker process unit due to metal failure in December 2010. In addition, on September 28, 2012, a boiler explosion occurred at the Wynnewood refinery, fatally injuring two employees. We have completed an internal investigation into the cause of the boiler explosion, which occurred as operators were restarting a boiler that had been temporarily shut down as part of the refinery’s turnaround process. Damage at the refinery was limited to the boiler. This matter is currently under investigation by OSHA and the Oklahoma Department of Labor (‘‘ODL’’), which could impose penalties if they determine that a violation of OSHA standards has occurred. Scheduled and unscheduled maintenance could reduce our net income and cash flows during the period of time that any of our units is not operating. Any unscheduled future downtime could have a material adverse effect on our results of operations, financial condition and cash flows. If we experience significant property damage, business interruption, environmental claims or other liabilities, our business could be materially adversely affected to the extent the damages or claims exceed the amount of valid and collectible insurance available to us. Our property and business interruption insurance policies (that cover the Coffeyville refinery and the nitrogen fertilizer plant) have a $1.25 billion limit, with a $2.5 million deductible for physical damage and a 45- to 60-day waiting period (depending on the insurance carrier) before losses resulting from business interruptions are recoverable. We are fully exposed to all losses in excess of the applicable limits and sub-limits and for losses due to business interruptions of fewer than 45 to 60 days. The Wynnewood refinery, effective November 1, 2012, is insured with a $1.0 billion limit, a $10.0 million property damage deductible and a 75 days waiting period deductible for business interruption. The property and business interruption insurance policies insuring Coffeyville and Wynnewood assets contain various sub-limits, exclusions, and conditions that could have a material adverse impact on the insurance indemnification of any particular catastrophic loss occurrence. For example, our current property policy contains varying specific 39 sub-limits of $128.5 million (for Coffeyville assets) and $115.3 million (for Wynnewood assets) for damage caused by flooding. Insurance policy language and terms maintained by us are generally consistent with standards for the energy and fertilizer manufacturing industries. The insurance market for the energy and nitrogen fertilizer manufacturing industries is highly specialized with a finite aggregate capacity of insurance. It is currently not feasible to purchase insurance limits up to the maximum foreseeable loss occurrence due to insurance capacity constraints. Our insurance program is renewed annually, and our ability to maintain current levels of insurance is dependent on the conditions and financial stability of the commercial insurance markets serving our industries. 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. The energy insurance market underwrites many refineries having coastal hurricane risk exposure and off shore platforms, thus a significant hurricane occurrence could impact a number of refineries and have a catastrophic impact on the financial results of the entire insurance and reinsurance market serving our 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. Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities. Our operations are subject to a variety of federal, state and local environmental laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the environment, product specifications and the generation, treatment, storage, transportation, disposal and remediation of solid and hazardous wastes. Violations of these laws and regulations or permit conditions can result in substantial penalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations and/or facility shutdowns. In addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement of laws and regulations or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. These expenditures or costs for environmental compliance could have a material adverse effect on our business’ results of operations, financial condition and profitability. Our facilities operate under a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Non-compliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. Additionally, due to the nature of our manufacturing and refining processes, there may be times when we are unable to meet the standards and terms and conditions of our permits, licenses and approvals due to operational upsets or malfunctions, which may lead to the imposition of fines and penalties or operating restrictions that may have a material adverse effect on our ability to operate our facilities and accordingly our financial performance. For a discussion of environmental laws and regulations and their impact on our business and operations, please see ‘‘Business — Environmental Matters.’’ 40 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 plant 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. Three of our facilities, including the Coffeyville refinery, the now-closed Phillipsburg terminal (which operated as a refinery until 1991), and the Wynnewood refinery 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 Wynnewood refinery is required to conduct investigations to address potential off-site migration of contaminants from the west side of the property. Other known areas of contamination at the Wynnewood refinery 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. If significant unknown liabilities are identified at 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. We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business. Our businesses hold numerous environmental and other governmental permits and approvals authorizing operations at our facilities. Future expansion of our operations is predicated upon securing the necessary environmental or other permits or approvals. A decision by a government agency to deny or delay issuing a new or renewed material permit or approval, or to revoke or substantially modify an 41 existing permit or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations and cash flows. For example, WRC’s OPDES permit has expired and is in the renewal process. At this time, the Wynnewood refinery is operating under expired permit terms and conditions (called a permit shield) until the state regulatory agency renews the permit. The renewal permit may contain different terms and conditions that would require unplanned or unanticipated costs. Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows. Various regulatory and legislative measures to address greenhouse gas emissions (including CO2, methane and nitrous oxides) are in different phases of implementation or discussion. In the aftermath of its 2009 ‘‘endangerment finding’’ that greenhouse gas emissions pose a threat to human health and welfare, the EPA has begun to regulate greenhouse gas emissions under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of greenhouse gases to inventory and report their greenhouse gas emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting our greenhouse gas emissions and are reporting the emissions to the EPA. In May 2010, the EPA finalized the ‘‘Greenhouse Gas Tailoring Rule,’’ which established new greenhouse gas emissions thresholds that determine when stationary sources, such as the refineries and the nitrogen fertilizer plant, must obtain permits under PSD and Title V programs of the federal Clean Air Act. In cases where a new source is constructed or an existing major source undergoes a major modification, the facility is required to undergo PSD review and evaluate and implement and install best available control technology BACT for its greenhouse gas emissions. Phase-in permit requirements began for the largest stationary sources in 2011. A major modification resulting in a significant expansion of production and a significant increase in greenhouse gas emissions at the nitrogen fertilizer plant or the refineries may require the installation of BACT as part of the permitting process. In the meantime, in December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate NSPS to regulate greenhouse gas emissions from petroleum refineries. The EPA may propose the NSPS in 2013. During a State of the Union address in February 2013, President Obama indicated that the United States would take action to address climate change. At the federal legislative level, this could mean Congressional passage of legislation adopting some form of federal mandatory greenhouse gas 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 CO2 and other greenhouse gas emissions. In 2007, a group of Midwestern states, including Kansas (where the Coffeyville refinery and the nitrogen fertilizer facility are located), formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control greenhouse gas 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, and it is unclear whether Kansas still intends to do so. Alternatively, the EPA may take further steps to regulate greenhouse gas emissions. The implementation of EPA regulations will 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 greenhouse gas emissions program. Increased costs associated with compliance with any current or future legislation or regulation of greenhouse gas emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and cash flows. 42 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. We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability. We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers, and the proper design, operation and maintenance of the refinery equipment. In addition, OSHA and certain environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees and state and local governmental authorities. Failure to comply with these requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, may result in significant fines or compliance costs, which could have a material adverse effect on our results of operations, financial condition and cash flows. Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer. In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers and suppliers, and personally identifiable information of our employees, in our facilities and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, disrupt our operations, damage our reputation, and cause a loss of confidence, which could adversely affect our business. Deliberate, malicious acts, including terrorism, could damage our facilities, disrupt our operations or injure employees, contractors, customers or the public and result in liability to us. Intentional acts of destruction could hinder our sales or production and disrupt our supply chain. Our facilities could be damaged or destroyed, reducing our operational production capacity and requiring us to repair or replace our facilities at substantial cost. Employees, contractors and the public could suffer substantial physical injury for which we could be liable. Governmental authorities may impose security or other requirements that could make our operations more difficult or costly. The consequences of any such actions could adversely affect our operating results, 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 36% of its petroleum sales for the year ended December 31, 2012. The five largest customers of the nitrogen fertilizer business represented approximately 63% of its ammonia sales for the year ended December 31, 2012 and the five largest UAN customers of the nitrogen fertilizer business represented approximately 39% of its 43 UAN sales for the year ended December 31, 2012. Several significant ammonia and UAN customers each account for more than 10% of ammonia and UAN sales, respectively. Given the nature of our businesses, and consistent with industry practice, we do not have long-term minimum purchase contracts with any of 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. The acquisition and expansion strategy of the petroleum business and the nitrogen fertilizer business involves significant risks. Both the petroleum business and the nitrogen fertilizer business will consider pursuing acquisitions and expansion projects in order to continue to grow and increase profitability. However, we may not be able to consummate such acquisitions or expansions, due to intense competition for suitable acquisition targets, the potential unavailability of financial resources necessary to consummate acquisitions and expansions, difficulties in identifying suitable acquisition targets and expansion projects or in completing any transactions identified on sufficiently favorable terms and the failure to obtain requisite regulatory or other governmental approvals. In addition, any future acquisitions and expansions may entail significant transaction costs and risks associated with entry into new markets and lines of business. The nitrogen fertilizer business is in the process of expanding its nitrogen fertilizer plant, which is expected to allow it the flexibility to upgrade all of its ammonia production to UAN. This expansion is premised in large part on the historically higher margin that UAN has received compared to ammonia. If the premium that UAN currently earns over ammonia decreases, this expansion project may not yield the economic benefits and accretive effects that are currently anticipated. In addition to the risks involved in identifying and completing acquisitions described above, even when acquisitions are completed, integration of acquired entities can involve significant difficulties, such as: • unforeseen difficulties in the integration of the acquired operations and disruption of the ongoing operations of our business; • failure to achieve cost savings or other financial or operating objectives contributing to the accretive nature of an acquisition; • strain on the operational and managerial controls and procedures of the petroleum business and the nitrogen fertilizer business, and the need to modify systems or to add management resources; • difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies; • assumption of unknown material liabilities or regulatory non-compliance issues; • amortization of acquired assets, which would reduce future reported earnings; • possible adverse short-term effects on our cash flows or operating results; and • diversion of management’s attention from the ongoing operations of our business. In addition, in connection with any potential acquisition or expansion project, the Refining Partnership or the Nitrogen Fertilizer Partnership (as applicable) will need to consider whether a business they intend to acquire or expansion project they intend to pursue could affect their tax treatment as a partnership for federal income tax purposes. If the petroleum business or the nitrogen fertilizer business is otherwise unable to conclude that the activities of the business being acquired or the expansion project would not affect its treatment as a partnership for federal income tax purposes, it may elect to seek a ruling from the Internal Revenue Service (‘‘IRS’’). Seeking such a ruling could be 44 costly or, in the case of competitive acquisitions, place the business in a competitive disadvantage compared to other potential acquirers who do not seek such a ruling. If the petroleum business or the nitrogen fertilizer business is unable to conclude that an activity would not affect its treatment as a partnership for federal income tax purposes, and is unable or unwilling to obtain an IRS ruling, the petroleum business or the nitrogen fertilizer business may choose to acquire such business or develop such expansion project in a corporate subsidiary, which would subject the income related to such activity to entity-level taxation, which would reduce the amount of cash available for distribution to the unitholders and would likely cause a substantial reduction in the value of its common units. Failure to manage these acquisition and expansion growth risks could have a material adverse effect on our results of operations, financial condition and cash flows. There can be no assurance that we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities, or generate positive cash flow at any acquired company or expansion project. We are a holding company and depend upon our subsidiaries for our cash flow. Our two principal subsidiaries are publicly traded partnerships, and a portion of their common units trade on the NYSE. We are a holding company, and these subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or to pay dividends or make other distributions in the future will depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of distributions on their common units. The ability of the Refining Partnership and the Nitrogen Fertilizer Partnership to make any payments to us will depend on, among other things, their earnings, the terms of their indebtedness, tax considerations and legal restrictions. In particular, the indenture governing the Refining Partnership’s 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 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 credit facility 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. Internally generated cash flows and other sources of liquidity may not be adequate for the capital needs of our businesses. Our businesses are capital intensive, and working capital needs may vary significantly over relatively short periods of time. For instance, crude oil price volatility can significantly impact working capital on a week-to-week and month-to-month basis. If we cannot generate adequate cash flow or otherwise secure sufficient liquidity to meet our working capital needs or support our short-term and long-term capital requirements, we may be unable to meet our debt obligations, pursue our business strategies or comply with certain environmental standards, which would have a material adverse effect on our business and results of operations. 45 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, 2012, approximately 53% of the employees at the Coffeyville refinery and 62% of the employees at the Wynnewood refinery were represented by labor unions under collective bargaining agreements. At Coffeyville, the collective bargaining agreement with six Metal Trades Unions (which covers union members who work directly at the Coffeyville refinery) is effective through March 2017, and the collective bargaining agreement with United Steelworkers (which covers the balance of the Company’s unionized employees, who work in the terminal and related operations) is effective through March 2015, 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 2015. 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 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 nitrogen fertilizer facility relies on gasification technology that requires special expertise to operate efficiently and effectively. 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 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. New regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities could result in higher operating costs. The costs of complying with future regulations relating to the transportation of hazardous chemicals and security associated with the refining and nitrogen fertilizer facilities may have a material adverse effect on our results of operations, financial condition and cash flows. Targets such as refining and chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. As a result, the petroleum and chemical industries have responded to the issues that arose due to the terrorist attacks on September 11, 2001 by starting new initiatives relating to the security of petroleum and chemical industry facilities and the transportation of hazardous chemicals in the United States. Future terrorist attacks could lead to even stronger, more costly initiatives that could result in a material adverse effect on our results of operations, financial condition and cash flows. Compliance with and changes in the tax laws could adversely affect our performance. We are subject to extensive tax liabilities, including United States and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and withholding taxes. New tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. 46 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 the date of this Report, the Refining Partnership had outstanding $500.0 million aggregate principal amount of 6.5% senior notes due 2022 and total borrowing capacity of up to $400.0 million under its ABL credit facility and up to $150.0 million under the intercompany credit facility, and the Nitrogen Fertilizer Partnership had $125.0 million of outstanding term loan borrowings, with availability of up to $25.0 million under its revolving credit facility. 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 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 credit facilities and other credit facilities 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 47 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 Refining Partnership’s business and financial condition and, as a result, its ability to make distributions to common unitholders (including us). 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 revolving credit facility, 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 revolving credit facility, 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 ABL Amended and Restated ABL Credit Facility and the indenture governing its notes and the Nitrogen Fertilizer Partnership’s credit facility 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 ABL Amended and Restated ABL Credit Facility and intercompany credit facility and the Nitrogen Fertilizer Partnership’s revolving credit facility 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. 48 Covenants in our debt instruments could limit our 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 notes and the Amended and Restated ABL Credit Facility and the Nitrogen Fertilizer Partnership’s credit facility 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 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 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 credit facility 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 notes and lenders under the Refining Partnership’s Amended and Restated ABL Credit Facility and the Nitrogen Fertilizer Partnership’s credit facility 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. 49 Despite their significant indebtedness, the Refining Partnership and the Nitrogen Fertilizer Partnership may still be able to incur significantly more debt, including secured indebtedness. This could intensify the risks described above. The Refining Partnership and the Nitrogen Fertilizer Partnership may be able to incur substantially more debt in the future, including secured indebtedness. Although the Refining Partnership’s ABL credit facility and the notes and the Nitrogen Fertilizer Partnership’s credit facility contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions may not prevent them from incurring obligations that do not constitute indebtedness. To the extent such new debt or new obligations are added to their existing indebtedness, the risks described above could substantially increase. Mr. Carl C. Icahn exerts significant influence over the Company and his interests may conflict with the interest of the Company’s other stockholders. Mr. Carl C. Icahn indirectly controls approximately 82% of the voting power of the Company’s capital stock and, by virtue of such stock ownership, is able to control or exert substantial influence over the Company, including: • the election and appointment of directors; • business strategy and policies; • mergers or other business combinations; • acquisition or disposition of assets; • future issuances of common stock, common units or other securities; • incurrence of debt or obtaining other sources of financing; and • the payment of dividends on the Company’s common stock and distributions on the common units of the Refining Partnership and the Nitrogen Fertilizer Partnership. The existence of a controlling stockholder may have the effect of making it difficult for, or may discourage or delay, a third party from seeking to acquire a majority of the Company’s outstanding common stock, which may adversely affect the market price of the stock. Mr. Icahn’s interests may not always be consistent with the Company’s interests or with the interests of the Company’s other stockholders. Mr. Icahn and entities controlled by him may also pursue acquisitions or business opportunities in industries in which we compete, and there is no requirement that any additional business opportunities be presented to us. We also have and may in the future enter into transactions to purchase goods or services with affiliates of Mr. Icahn. To the extent that conflicts of interest may arise between the Company and Mr. Icahn and his affiliates, those conflicts may be resolved in a manner adverse to the Company or its other stockholders. In addition, if Mr. Icahn were to sell, or otherwise transfer, some or all of his interests in us to an unrelated party or group, a change of control could be deemed to have occurred under the terms of the indentures governing the Refining Partnership’s notes, which would require it to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued interest to the date of repurchase, and the Refining Partnership’s Amended and Restated ABL Credit Facility, which would constitute an event of default under the ABL credit facility and would allow lenders to accelerate indebtedness owed to them. However, it is possible that the Refining Partnership will not have sufficient funds at the time of the change of control to make the required repurchase of notes or repay amounts outstanding under the Refining Partnership’s Amended and Restated ABL Credit Facility, if any. 50 The Company’s stock price may decline due to sales of shares by Mr. Carl C. Icahn. Sales of substantial amounts of the Company’s common stock, or the perception that these sales may occur, may adversely affect the price of the Company’s common stock and impede its ability to raise capital through the issuance of equity securities in the future. Mr. Icahn could elect in the future to request that the Company file a registration statement to enable him to sell shares of the Company’s common stock. If Mr. Icahn were to sell a large number of shares into the public markets, Mr. Icahn could cause the price of the Company’s common stock to decline. We are a ‘‘controlled company’’ within the meaning of the NYSE rules and, as a result, qualify for, and are relying on, exemptions from certain corporate governance requirements. A company of which more than 50% of the voting power is held by an individual, a group or another company is a ‘‘controlled company’’ within the meaning of the NYSE rules and may elect not to comply with certain corporate governance requirements of the NYSE, including: • the requirement that a majority of our board of directors consist of independent directors; • the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors; and • the requirement that we have a compensation committee that is composed entirely of independent directors. We are relying on all of these exemptions as a controlled company. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. In addition, both the Refining Partnership and the Nitrogen Fertilizer Partnership are relying on exemptions from the same NYSE corporate governance requirements described above. Risks Related to Our Common Stock We have various mechanisms in place to discourage takeover attempts, which may reduce or eliminate our stockholders’ ability to sell their shares for a premium in a change of control transaction. Various provisions of our certificate of incorporation and bylaws and of Delaware corporate law may discourage, delay or prevent a change in control or takeover attempt of our company by a third party that our management and board of directors determines is not in the best interest of our Company and its stockholders. Public stockholders who might desire to participate in such a transaction may not have the opportunity to do so. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change in our management and board of directors. These provisions include: • preferred stock that could be issued by our board of directors to make it more difficult for a third party to acquire, or to discourage a third party from acquiring, a majority of our outstanding voting stock; • limitations on the ability of stockholders to call special meetings of stockholders; • limitations on the ability of stockholders to act by written consent in lieu of a stockholders’ meeting; and • advance notice requirements for nominations of candidates for election to our board of directors or for proposing matters that can be acted upon by our stockholders at stockholder meetings. 51 We are authorized to issue up to a total of 350 million shares of Common Stock and 50 million shares of Preferred Stock, potentially diluting equity ownership of current holders and the share price of our Common Stock. We believe that it is necessary to maintain a sufficient number of available authorized shares of our Common Stock and Preferred Stock in order to provide us with the flexibility to issue Common Stock or Preferred Stock for business purposes that may arise as deemed advisable by our board of directors. These purposes could include, among other things, (i) to declare future stock dividends or stock splits, which may increase the liquidity of our shares; (ii) the sale of stock to obtain additional capital or to acquire other companies or businesses, which could enhance our growth strategy or allow us to reduce debt if needed; (iii) for use in additional stock incentive programs and (iv) for other bona fide purposes. Our board of directors may issue the available authorized shares of Common Stock or Preferred Stock without notice to, or further action by, our stockholders, unless stockholder approval is required by law or the rules of the NYSE. The issuance of additional shares of Common Stock or Preferred Stock may significantly dilute the equity ownership of the current holders of our Common Stock. Risks Related to the Limited Partnership Structures Through Which We Currently Hold Our Interests in the Refinery Business and the Nitrogen Fertilizer Business Both the Refining Partnership and the Nitrogen Fertilizer Partnership currently have in place a policy to distribute all of the ‘‘available cash’’ each generates on a quarterly basis, which could limit their ability to grow and make acquisitions. The current policy of the board of directors of the Refining Partnership’s general partner is to distribute an amount equal to the available cash the Refining Partnership generates each quarter to its unitholders, beginning with the quarter ending March 31, 2013, and the current policy of the board of directors of the Nitrogen Fertilizer Partnership’s general partner is to distribute to Nitrogen Fertilizer Partnership unitholders all of the available cash the Nitrogen Fertilizer Partnership generates on a quarterly basis. As a result of their respective cash distribution policies, the Refining Partnership and the Nitrogen Fertilizer Partnership will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. As such, to the extent they are unable to finance growth externally, their respective cash distribution policies will significantly impair their ability to grow. The board of directors of the general partner of either the Refining Partnership or the Nitrogen Fertilizer Partnership may modify or revoke its cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of available cash they generate. Each board of directors will determine the cash distribution policy it deems advisable for them on an independent basis. In addition, because of their respective distribution policies, their growth, if any, may not be as robust as that of businesses that reinvest their available cash to expand ongoing operations. To the extent either issues additional units in connection with any acquisitions or expansion capital expenditures or as in-kind distributions, current unitholders will experience dilution and the payment of distributions on those additional units will decrease the amount each distributes in respect of each of its outstanding units. There are no limitations in their respective partnership agreements on either the Refining Partnership’s or the Nitrogen Fertilizer Partnership’s ability to issue additional units, including units ranking senior to the outstanding common units. The incurrence of additional commercial borrowings or other debt to finance their growth strategy would result in increased interest expense, which, in turn, would reduce the available cash they have to distribute to unitholders (including us). 52 The Refining Partnership may not have sufficient available cash to pay any quarterly distribution on its common units, and the Nitrogen Fertilizer Partnership may not have sufficient available cash to pay any quarterly distribution on its common units. Furthermore, neither is required to make distributions to holders of its common units on a quarterly basis or otherwise, and both may elect to distribute less than all of their respective available cash. Either or both of the Refining Partnership or the Nitrogen Fertilizer Partnership may not have sufficient available cash each quarter to enable the payment of distributions to common unitholders. The Refining Partnership and the Nitrogen Fertilizer Partnership are separate public companies, and available cash generated by one of them will not be used to make distributions to common unitholders of the other. Furthermore, the partnership agreements do not require either to pay distributions on a quarterly basis or otherwise. The board of directors of the general partner of either the Refining Partnership or the Nitrogen Fertilizer Partnership may at any time, for any reason, change its cash distribution policy or decide not to make any distribution. The amount of cash they will be able to distribute in respect of their common units principally depends on the amount of cash they generate from operations, which is directly dependent upon the margins each business generates. Please see ‘‘— Risks Related to the Petroleum Business — The price volatility of crude oil and other feedstocks, refined products and utility services may have a material adverse effect on our profitability and our ability to pay distributions to unitholders’’ and ‘‘— Risks Related to the Nitrogen Fertilizer Business — The nitrogen fertilizer business is, and nitrogen fertilizer prices are, cyclical and highly volatile, and the nitrogen fertilizer business has experienced substantial downturns in the past. Cycles in demand and pricing could potentially expose the nitrogen fertilizer business to significant fluctuations in its operating and financial results and have a material adverse effect on our results of operations, financial condition and cash flows.’’ If either of the Refining Partnership or the Nitrogen Fertilizer Partnership were to be treated as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if either partnership were otherwise subject to entity-level taxation, such entity’s cash available for distribution to its common unitholders, including to us, would be reduced, likely causing a substantial reduction in the value of such entity’s common units, including the common units held by us. Current law requires the Refining Partnership and the Nitrogen Fertilizer Partnership to derive at least 90% of their respective annual gross income from certain specified activities in order to continue to be treated as a partnership, rather than as a corporation, for U.S. federal income tax purposes. One or both of them may not find it possible to meet this qualifying income requirement, or may inadvertently fail to meet this qualifying income requirement. If either the Refining Partnership or the Nitrogen Fertilizer Partnership were to be treated as a corporation for U.S. federal income tax purposes, they would pay U.S. federal income tax on all of their taxable income at the corporate tax rate, which is currently a maximum of 35%, they would likely pay additional state and local income taxes at varying rates, and distributions to their common unitholders, including to us, would generally be taxed as corporate distributions. If the Refining Partnership and the Nitrogen Fertilizer Partnership were to be treated as corporations, rather than as partnerships, for U.S. federal income tax purposes or if they were otherwise subject to entity-level taxation, their cash available for distribution to its common unitholders, including to us, and the value of their common units, including the common units held by us, could be substantially reduced. 53 Increases in interest rates could adversely impact the price of the Nitrogen Fertilizer Partnership’s common units and the Nitrogen Fertilizer Partnership’s ability to issue additional equity to make acquisitions, incur debt or for other purposes. We expect that the price of the Nitrogen Fertilizer Partnership’s common units will be impacted by the level of the Nitrogen Fertilizer Partnership’s quarterly cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in the Nitrogen Fertilizer Partnership’s common units, and a rising interest rate environment could have a material adverse impact on the price of the Nitrogen Fertilizer Partnership’s common units (and therefore the value of our investment in the Nitrogen Fertilizer Partnership) as well as the Nitrogen Fertilizer Partnership’s ability to issue additional equity to make acquisitions or to incur debt. We may have liability to repay distributions that are wrongfully distributed to us. Under certain circumstances, we may, as a holder of common units in the Refining Partnership and the Nitrogen Fertilizer Partnership, have to repay amounts wrongfully returned or distributed to us. Under the Delaware Revised Uniform Limited Partnership Act, a partnership may not make distributions to its unitholders if the distribution would cause its liabilities to exceed the fair value of its assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the company for the distribution amount. Public investors own approximately 30% of the nitrogen fertilizer business through the Nitrogen Fertilizer Partnership and approximately 19% of the petroleum business through the Refining Partnership. Although we own the majority of the common units and the general partner of both the Refining Partnership and the Nitrogen Fertilizer Partnership, the general partners owe a duty of good faith to public unitholders, which could cause them to manage their respective businesses differently than if there were no public unitholders. Public investors own approximately 30% of the Nitrogen Fertilizer Partnership’s common units and approximately 19% of the Refining Partnership’s common units. We are no longer entitled to receive all of the cash generated by the nitrogen fertilizer business or the petroleum business or freely transfer money from the nitrogen fertilizer business to finance operations at the petroleum business or vice versa. Furthermore, although we continue to own the majority of the common units and the general partner of both the Refining Partnership and the Nitrogen Fertilizer Partnership, the general partners are subject to certain fiduciary duties, which may require the general partners to manage their respective businesses in a way that may differ from our best interests. The general partners of the Refining Partnership and the Nitrogen Fertilizer Partnership have limited their liability, replaced default fiduciary duties and restricted the remedies available to common unitholders, including us, for actions that, without these limitations and reductions might otherwise constitute breaches of fiduciary duty. The respective partnership agreements of the Refining Partnership and the Nitrogen Fertilizer Partnership limit the liability and replace the fiduciary duties of their respective general partner, while also restricting the remedies available to each partnership’s common unitholders, including us, for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. Delaware partnership law permits such contractual reductions of fiduciary duty. The partnership 54 agreements contain provisions that replace the standards to which each general partner would otherwise be held by state fiduciary duty law. For example, the partnership agreements: • permit each partnership’s general partner to make a number of decisions in its individual capacity, as opposed to its capacity as general partner. This entitles its general partner to consider only the interests and factors that it desires, and means that it has no duty or obligation to give any consideration to any interest of, or factors affecting, any limited partner. • provide that each partnership’s general partner will not have any liability to unitholders for decisions made in its capacity as general partner so long as (i) in the case of the Nitrogen Fertilizer Partnership, it acted in good faith, meaning it believed that the decision was in the best interest of the Nitrogen Fertilizer Partnership and (ii) in the case of the Refining Partnership, it did not make such decisions in bad faith, meaning it believed that the decisions were adverse to the Refining Partnership’s interests. • provide that each partnership’s general partner and the officers and directors of its general partner will not be liable for monetary damages to common unitholders, including us, for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that (i) in the case of the Nitrogen Fertilizer Partnership, the general partner or its officers or directors acted in bad faith or engaged in fraud or willful misconduct, or in, the case of a criminal matter, acted with knowledge that the conduct was criminal and (ii) in the case of the Refining Partnership, such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or with respect to any criminal conduct, with the knowledge that its conduct was unlawful. In addition, the Refining Partnership’s partnership agreement provides that its general partner will not be in breach of its obligations thereunder or its duties to the Refining Partnership or its limited partners if a transaction with an affiliate or the resolution of a conflict of interest is either (i) approved by the conflicts committee of its board of directors of the general partner, although the general partner is not obligated to seek such approval; or (ii) approved by the vote of a majority of the outstanding units, excluding any units owned by the general partner and its affiliates. In addition, the Nitrogen Fertilizer Partnership’s partnership agreement (i) generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of its general partner and not involving a vote of unitholders must be on terms no less favorable to the Nitrogen Fertilizer Partnership than those generally being provided to or available from unrelated third parties or be ‘‘fair and reasonable’’ to the Nitrogen Fertilizer Partnership, as determined by its general partner in good faith, and that, in determining whether a transaction or resolution is ‘‘fair and reasonable,’’ the general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to affiliated parties, including us and (ii) provides that in resolving conflicts of interest, it will be presumed that in making its decision, the general partner or its conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any holder of common units, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. With respect to the common units that we own, we have agreed to be bound by the provisions set forth in each partnership agreement, including the provisions described above. The Nitrogen Fertilizer Partnership and the Refining Partnership are managed by the executive officers of their general partners, some of whom are employed by and serve as part of the senior management team of the Company and its affiliates. Conflicts of interest could arise as a result of this arrangement. The Nitrogen Fertilizer Partnership and the Refining Partnership is each managed by the executive officers of their general partners, some of whom are employed by and serve as part of the senior management team of the Company. Furthermore, although both the Nitrogen Fertilizer Partnership and 55 the Refining Partnership have entered into services agreements with the Company under which they compensate the Company for the services of its management, the Company’s management is not required to devote any specific amount of time to the nitrogen fertilizer business or the petroleum business and may devote a substantial majority of their time to the business of the Company. Moreover the Company may terminate the services agreement with the Nitrogen Fertilizer Partnership at any time, subject to a 180-day notice period, and commencing with the first anniversary of the Refining Partnership’s IPO, may terminate the services agreement with the Refining Partnership, at any time, subject to a 180-day notice period. In addition, key executive officers of the Company, including its chief operating officer, chief financial officer and general counsel, will face conflicts of interest if decisions arise in which the Nitrogen Fertilizer Partnership or the Refining Partnership and the Company have conflicting points of view or interests. As a stand-alone public company, the Refining Partnership is exposed to risks relating to evaluations of controls required by Section 404 of the Sarbanes-Oxley Act. The Refining Partnership is in the process of evaluating its internal controls systems to allow management to report on, and our independent auditors to audit, its internal control over financial reporting. It will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, and under current rules will be required to comply with Section 404 for the year ended December 31, 2013. Upon completion of this process, the Refining Partnership may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board (‘‘PCAOB’’) rules and regulations that remain unremediated. Although the Refining Partnership produces financial statements in accordance with accounting principles generally accepted in the United States (‘‘GAAP’’), internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. As a publicly traded partnership, it will be required to report, among other things, control deficiencies that constitute a ‘‘material weakness’’ or changes in internal controls that, or that are reasonably likely to, materially affect internal control over financial reporting. A ‘‘material weakness’’ is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. If the Refining Partnership fails to implement the requirements of Section 404 in a timely manner, it might be subject to sanctions or investigation by regulatory authorities such as the SEC. If it does not implement improvements to its disclosure controls and procedures or to its internal controls in a timely manner, its independent registered public accounting firm may not be able to certify as to the effectiveness of its internal control over financial reporting pursuant to an audit of its internal control over financial reporting. This may subject the Refining Partnership to adverse regulatory consequences or a loss of confidence in the reliability of its financial statements. It could also suffer a loss of confidence in the reliability of its financial statements if its independent registered public accounting firm reports a material weakness in its internal controls, if it does not develop and maintain effective controls and procedures or if it is otherwise unable to deliver timely and reliable financial information. Any loss of confidence in the reliability of its financial statements or other negative reaction to its failure to develop timely or adequate disclosure controls and procedures or internal controls could result in a decline in the price of its common units, which would reduce the value of our investment in the Refining Partnership. In addition, if the Refining Partnership fails to remedy any material weakness, its financial statements may be inaccurate, it may face restricted access to the capital markets and the price of its common units may be adversely affected, which would reduce the value of our investment in the Refining Partnership. 56 The Refining Partnership will incur increased costs as a result of being a publicly traded partnership. As a result of the Refining Partnership’s IPO, it will incur significant incremental legal, accounting and other expenses that did not incur when it was operated as a wholly-owned non-public subsidiary of CVR Energy. In particular, the Refining Partnership is now subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the ‘‘Exchange Act’’). SEC reporting requirements will increase its legal and financial compliance costs and make compliance activities more time-consuming and costly. In addition, the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and the NYSE, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. As a result, the amount of cash the Refining Partnership has available for distribution to its unitholders (including us) will be affected by its expenses, including the costs associated with being a publicly traded partnership. The Refining Partnership estimates that it will incur approximately $5.0 million of estimated incremental costs per year, some of which will be direct charges associated with being a publicly traded partnership, and some of which will be allocated to the Refining Partnership by CVR Energy; however, it is possible that the actual incremental costs of being a publicly traded partnership will be higher than currently estimated. Item 1B. Unresolved Staff Comments None. Item 2. Properties The following table contains certain information regarding our principal properties: Location Acres Own/Lease Use Coffeyville, KS . . . . . . . . . . . . . . . . . . . 440 Own Refining Partnership: oil refinery and office buildings Nitrogen Fertilizer Partnership: fertilizer plant Wynnewood, OK . . . . . . . . . . . . . . . . . . 400 Own Oil refinery, office buildings, refined oil Montgomery County, KS (Coffeyville Station) . . . . . . . . . . . . . . . . . . . . . . . 20 Own Crude oil storage Montgomery County, KS (Broome Station) . . . . . . . . . . . . . . . . . . . . . . . Cowley County, KS (Hooser Station) . . . Cushing, OK . . . . . . . . . . . . . . . . . . . . . 20 80 138 Own Own Own Crude oil storage Crude oil storage Crude oil storage storage We also lease property for our executive office which is located at 2277 Plaza Drive in Sugar Land, Texas. Additionally, other corporate office space is leased in Kansas City, Kansas and Oklahoma City, Oklahoma. As of December 31, 2012, we had crude oil storage tanks with a capacity of approximately 1.2 million barrels located outside the Coffeyville refinery, 0.5 million barrels of crude oil storage capacity at Wynnewood, Oklahoma, 1.0 million barrels of crude oil storage capacity in Cushing, Oklahoma and lease an additional 3.3 million barrels of crude oil storage capacity located at Cushing. In addition to crude oil storage, we own approximately 4.5 million barrels of combined refinery related storage capacity. 57 Item 3. Legal Proceedings We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business, including matters such as those described under ‘‘Business — Environmental Matters.’’ We also incorporate by reference into this Part I, Item 3 of this Report, the information regarding the lawsuits and proceedings described and referenced in Note 15, ‘‘Commitments and Contingencies’’ to our Consolidated Financial Statements as set forth in Part II, Item 8 of this Report. In accordance with GAAP, we record a liability when it is both probable that a liability has been incurred and the amount of the loss 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. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations or claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations. Item 4. Mine Safety Disclosures None. 58 Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of PART II Equity Securities Market Information Our common stock is listed on the NYSE under the symbol ‘‘CVI’’ and commenced trading on October 23, 2007. The table below sets forth, for the quarter indicated, the high and low sales prices per share of our common stock: 2012: High Low First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $30.11 31.71 38.35 49.63 $19.19 23.54 26.53 34.52 2011: High Low First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $23.18 25.03 29.61 27.95 $14.55 18.30 19.20 16.62 Holders of Record As of March 11, 2013, there were 143 stockholders of record of our common stock. Because many of our shares of common stock are held by brokers and other institutions on behalf of stockholders, we are unable to estimate the total number of beneficial owners represented by these record holders. CVR Energy, Inc. Dividend Policy On January 24, 2013, the board of directors of the Company adopted a quarterly cash dividend policy. Subject to declaration by its Board of Directors, CVR Energy’s initial quarterly dividend is expected to be $0.75 per share, or $3.00 per share on an annualized basis, which the Company plans to begin paying in the second quarter of 2013. In addition, the Board of Directors of CVR Energy declared a special dividend of $5.50 per share which was paid on February 19, 2013, to stockholders of record at the close of business on February 5, 2013. The total amount of the special dividend payment was approximately $477.6 million. CVR Partners, LP Cash Distribution Policy The current policy of the board of directors of the general partner of the Nitrogen Fertilizer Partnership is to distribute all available cash the Nitrogen Fertilizer Partnership generates each quarter. Available cash for each quarter is determined by the board of directors of the general partner following the end of such quarter. Available cash for each quarter through the end of 2012 was calculated based on the cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of the general partner deems necessary or appropriate. Additionally, the Nitrogen Fertilizer Partnership also retained the cash on hand associated with prepaid sales at each quarter end, which is recorded on the balance sheet as deferred revenue, for future distributions to common unitholders as it is recognized into income. Beginning with the first quarter of 2013, the board of directors of the general partner has adopted an amended policy to calculate available cash starting with Adjusted Nitrogen Fertilizer EBITDA reduced for cash needed for maintenance capital expenditures, debt service and other contractual obligations, major scheduled turnaround expense incurred, 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. The Nitrogen Fertilizer 59 Partnership does not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in its quarterly distribution or otherwise to reserve cash for distributions, nor does the Nitrogen Fertilizer Partnership intends to incur debt to pay quarterly distributions. As of the date of this Report, we own approximately 70% of the Nitrogen Fertilizer Partnership’s common units, and are entitled to a pro rata percentage of the Nitrogen Fertilizer Partnership’s distributions in respect of its common units. The following is a summary of cash distributions paid by the Nitrogen Fertilizer Partnership to unitholders during the years ended December 31, 2012 and 2011 for the respective quarters to which the distributions relate: December 31, 2011 March 31, 2012 June 30, 2012 September 30, 2012 Total Cash Distributions Paid in 2012 Amount paid CRLLC . . . . . . . . . Amounts paid to public unitholders . . . . . . . . . . . . . . . Total amount paid . . . . . . . . . . . Per common unit . . . . . . . . . . . $ $ $ ($ in millions except per unit data) 29.9 $ 26.6 $ 30.5 $ 25.3 $112.4 13.0 42.9 0.588 $ $ 11.6 38.2 0.523 $ $ 13.3 43.8 0.600 $ $ 10.9 36.2 0.496 48.8 $161.2 $2.207 Common units outstanding . . . . . 73,030,936 73,030,936 73,043,356 73,046,498 December 31, March 31, 2010 2011 June 30, 2011 September 30, 2011 ($ in millions except per common units amounts) Total Cash Distributions Paid in 2011 Amount paid CRLLC . . . . . . . . . . . . Amounts paid to public unitholders . . Total amount paid . . . . . . . . . . . . . . Per common unit . . . . . . . . . . . . . Common units outstanding . . . . . . . . $— — $— $— — $— — $— $— — $ $ $ 20.7 9.0 29.7 0.407 $ $ $ 29.1 12.7 41.8 0.572 $ 49.8 21.6 $ 71.5 $0.979 73,002,956 73,002,956 On February 14, 2013, the Nitrogen Fertilizer Partnership paid out a cash distribution to the Nitrogen Fertilizer Partnership’s unitholders of record at the close of business on February 7, 2013 for the fourth quarter of 2012 in the amount of $0.192 per common unit, or $14.0 million in aggregate. Total cash distributions paid based upon available cash for 2012 were $1.81 per common unit. CVR Refining, LP Cash Distribution Policy The board of directors of the general partner of the Refining Partnership adopted a policy in connection with the completion of its initial public offering on January 23, 2013, pursuant to which it will distribute all of the available cash it generates each quarter, beginning with the quarter ending March 31, 2013. For the quarter ended March 31, 2013, available cash will be adjusted to exclude the period prior to the Refining Partnership IPO from January 1, 2013 through January 22, 2013. Available cash for each quarter will be determined by the board of directors of the general partner following the end of such quarter and is expected to be distributed within 60 days of quarter end. The Refining Partnership expects that available cash for each quarter will be calculated based on its Adjusted EBITDA for the quarter, less cash needed for debt service, reserves for maintenance and environmental capital expenditures, and reserves for expenses associated with major scheduled turnarounds. The board of directors may also determine that it is appropriate to reserve cash for future operating or capital needs. The Refining Partnership does not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in its quarterly distribution or otherwise to reserve cash for distributions, nor do they intend to incur debt to pay quarterly distributions. Further, it 60 is the Refining Partnership’s intent, subject to market conditions, to finance growth capital externally, and not to reserve cash for unspecified potential future needs. As of the date of this Report, we own approximately 81% of the Refining Partnership’s common units, and are entitled to a pro rata percentage of the Refining Partnership’s distributions in respect of its common units. Stock Performance Graph The following graph sets forth the cumulative return on our common stock between January 1, 2008 and December 31, 2012, as compared to the cumulative return of the Russell 2000 Index and an industry peer group consisting of Alon USA Energy, Inc., Delek US Holdings, Inc., HollyFrontier Corporation, Tesoro Corporation, Valero Energy Corporation and Western Refining, Inc. The graph assumes an investment of $100 on January 1, 2008 in our common stock, the Russell 2000 Index and the industry peer group, and assumes the reinvestment of dividends where applicable. The closing market price for our common stock on December 31, 2012 was $48.79. The stock price performance shown on the graph is not intended to forecast and does not necessarily indicate future price performance. COMPARISON OF CUMULATIVE TOTAL RETURN BETWEEN JANUARY 1, 2008 AND DECEMBER 31, 2012 among CVR Energy, Inc., Russell 2000 Index and a peer group Peer Group Russell 2000 Index CVR Energy $250.00 $200.00 $150.00 $100.00 $50.00 $0.00 Jan-08 Mar-08 13MAR201307004757 This performance graph shall not be deemed ‘‘filed’’ for purposes of Section 18 of the Exchange Sep-08 Dec-08 Mar-09 Jun-09 Sep-09 Dec-09 Mar-10 Jun-10 Sep-10 Dec-10 Sep-12 Dec-12 Sep-11 Dec-11 Mar-11 Mar-12 Jun-08 Jun-12 Jun-11 Act or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended (the ‘‘Securities Act’’), or the Exchange Act. Mar ‘08 Jun ‘08 Sep ‘08 Dec ‘08 Mar ‘09 Jun ‘09 Sep ‘09 Dec ‘09 Mar ‘10 Jun ‘10 CVR Energy, Inc. . . . . . . . 92.34 Russell 2000 Index . . . . . . 89.81 Peer Group . . . . . . . . . . . . 65.57 77.19 90.03 52.18 34.16 88.71 45.75 16.04 22.21 65.20 55.19 31.55 41.90 29.39 66.35 33.40 49.88 78.88 37.00 27.51 81.64 31.35 35.08 88.59 34.32 30.15 79.56 31.88 Sep ‘10 Dec ‘10 Mar ‘11 Jun ‘11 Sep ‘11 Dec ‘11 Mar ‘12 Jun ‘12 Sep ‘12 Dec ‘12 CVR Energy, Inc. 98.72 84.76 Russell 2000 Index . . . . . . 88.27 102.30 110.12 108.02 84.09 72.98 52.75 Peer Group . . . . . . . . . . . 32.67 . . . . . . 33.08 44.47 71.26 60.87 92.86 75.10 107.26 106.58 147.35 195.63 96.72 108.39 104.24 109.32 110.88 77.31 102.86 112.15 55.72 72.21 Purchases of Equity Securities by the Issuer We did not repurchase any of our common stock during the fiscal quarter ended December 31, 2012. 61 Item 6. Selected Financial Data You should read the selected historical consolidated financial data presented below in conjunction with ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ and our consolidated financial statements and the related notes included elsewhere in this Report. The selected consolidated financial information presented below under the caption ‘‘Statements of Operations Data’’ for the years ended December 31, 2012, 2011 and 2010 and the selected consolidated financial information presented below under the caption ‘‘Balance Sheet Data’’ as of December 31, 2012 and 2011 has been derived from our audited consolidated financial statements included elsewhere in this Report, which financial statements have been audited by KPMG LLP, our independent registered public accounting firm. The consolidated financial information presented below under the caption ‘‘Statements of Operations Data’’ for the years ended December 31, 2009 and 2008 and the consolidated financial information presented below under the caption ‘‘Balance Sheet Data’’ at December 31, 2010, 2009 and 2008, is derived from our audited consolidated financial statements that are not included in this Report. Operating income . . . . . . . . . $ 1,034.9 $ 566.6 $ Statements of Operations Data: Net sales . . . . . . . . . . . . . . . . . . Cost of product sold(2) . . . . . . . Direct operating expenses(2) . . . Insurance recovery-business interruption . . . . . . . . . . . . . . Selling, general and administrative expenses(2) . . . Depreciation and amortization . . Goodwill impairment(3) . . . . . . . Interest expense and other financing costs . . . . . . . . . . . . Gain (loss) on derivatives, net Realized . . . . . . . . . . . . . . . . Unrealized . . . . . . . . . . . . . . . Loss on extinguishment of debt . Other income, net . . . . . . . . . . . Income before income tax expense . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . Net income . . . . . . . . . . . . . . Less: Net income attributable to noncontrolling interest . . Net income attributable to CVR Energy stockholders(4) . . . . . . . . . . Basic earnings per share . . . . . . Diluted earnings per share . . . . . Weighted-average common shares outstanding: Basic . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . $ $ $ $ Year Ended December 31, 2012 2011(1) 2010 2009 2008 (in millions, except share data) $ $ 8,567.3 6,696.9 522.1 5,029.1 3,943.5 334.1 $ 4,079.8 3,568.1 239.8 $ 3,136.3 2,547.7 226.6 $ 5,016.1 4,461.8 245.4 — 183.4 130.0 — (3.4) 98.0 90.3 — (75.4) (55.8) (137.6) (148.0) (37.5) 1.8 (7.2) 85.3 (2.1) 1.3 $ 638.2 (225.6) 412.6 588.1 (209.5) 378.6 (34.0) (32.8) 378.6 4.36 4.33 $ $ $ 345.8 4.00 3.94 $ $ $ $ — 92.0 86.8 — 93.1 (50.3) 0.7 (2.2) (16.6) 3.4 28.1 (13.8) 14.3 — 14.3 0.17 0.16 — 68.9 84.9 — — 35.2 82.2 42.8 $ 208.2 $ 148.7 (44.2) (22.5) (42.8) (2.1) 2.0 98.6 (29.2) 69.4 — 69.4 0.80 0.80 $ $ $ $ (40.3) (128.5) 253.8 (10.0) 4.1 227.8 (63.9) 163.9 — 163.9 1.90 1.90 $ $ $ $ 86,822,913 87,392,270 86,493,735 87,766,573 86,340,342 86,789,179 86,248,205 86,342,433 86,145,543 86,224,209 62 Balance Sheet Data: Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Working capital Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total debt, including current portion . . . . . . . . . . Total CVR stockholders’ equity/members’ equity . Cash Flow Data: Net cash flow provided by (used in): Year Ended December 31, 2012 2011(1) 2010 2009 2008 (in millions) $ 896.0 1,135.4 3,610.9 898.2 1,525.2 $ 388.3 769.2 3,119.3 863.8 1,151.6 $ 200.0 333.6 1,740.2 477.0 689.6 $ 36.9 235.4 1,614.5 491.3 653.8 $ 8.9 128.5 1,610.5 495.9 579.5 Operating activities . . . . . . . . . . . . . . . . . . . . . Investing activities . . . . . . . . . . . . . . . . . . . . . . Financing activities . . . . . . . . . . . . . . . . . . . . . 762.6 (210.7) (44.3) 278.6 (674.4) 584.1 Net cash flow . . . . . . . . . . . . . . . . . . . . . . . . . 507.6 188.3 225.4 (31.3) (31.0) 163.1 85.3 (48.3) (9.0) 28.0 83.2 (86.5) (18.3) (21.6) Other Financial Data: Capital expenditures for property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . 212.2 91.2 32.4 48.8 86.5 (1) We acquired WEC on December 15, 2011 and its results of operations are included from the date of acquisition. In addition, we incurred approximately $11.0 million and $5.2 million of transaction and integration costs related to the acquisition in fiscal years 2012 and 2011, respectively. These transactions impact the comparability of the Selected Financial Data. (2) Amounts are shown exclusive of depreciation and amortization. (3) Upon applying the goodwill impairment testing criteria under existing accounting rules during the fourth quarter of 2008, we determined that the goodwill in the petroleum segment was impaired, which resulted in a goodwill impairment loss of $42.8 million. This represented a write-off of the entire balance of the petroleum segment’s goodwill. (4) The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature: Loss on extinguishment of debt(a) . . . . . . . . . . . . Letter of credit expense not included in interest expense(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . Major scheduled turnaround expense(c) . . . . . . . . Unrealized (gain) loss on derivatives . . . . . . . . . . Share-based compensation(d) . . . . . . . . . . . . . . . Goodwill impairment(e) . . . . . . . . . . . . . . . . . . . Year Ended December 31 2012 2011 2010 2009 2008 $ 37.5 (in millions) $16.6 $ 2.1 $ 2.1 $ 10.0 1.3 128.5 (148.0) 39.1 — 1.5 66.4 (85.3) 27.2 — 4.7 4.8 2.2 37.2 — 13.4 — 42.8 8.8 — 7.4 3.3 (253.8) (42.5) 42.8 (a) Represents (1) for 2012, the write-off of previously deferred financing costs, unamortized premium/discount and premiums paid upon the extinguishment of the First Lien Notes, which contributed to $33.4 million of the loss on extinguishment. Additionally, $4.1 million of the loss on extinguishment of debt was attributable to the write-off of a portion of previously deferred financing costs associated with ABL credit facility, which was replaced with an 63 Amended and Restated ABL Credit Facility; (2) for 2011, the write-off of a portion of previously deferred financing costs upon the replacement of the first priority credit facility with the ABL credit facility contributed to $1.9 million of the loss on extinguishment. Additionally, $0.2 million of the loss on extinguishment of debt was attributable to the write-off of previously deferred financing costs and unamortized original issue discount associated with the repurchase of $2.7 million of First Lien Notes; (3) for 2010, a premium of 2.0% paid in connection with unscheduled prepayments and payoff of our tranche D term loan contributing $9.6 million of the loss on extinguishment. Additionally, $5.4 million of the loss on extinguishment of debt was attributable to the write-off of previously deferred financing costs associated with the payoff of the tranche D term loan. Concurrent with the issuance of the senior secured notes, $0.1 million of third-party costs were immediately expensed. In December 2010, we made a voluntary unscheduled principal payment on our senior secured notes resulting in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling $1.6 million; (4) for 2009, the write-off of $2.1 million of previously deferred financing costs in connection with the reduction, effective June 1, 2009, and eventual termination of the first priority funded letter of credit facility on October 15, 2009; and (5) for 2008, the write-off of $10.0 million of previously deferred financing costs in connection with the second amendment to our first priority credit facility on December 22, 2008. (b) Consists of fees which are expensed to selling, general and administrative expenses in connection with our letters of credit outstanding and the first priority funded letter of credit facility issued in support of the Cash Flow Swap until it was terminated effective October 15, 2009. (c) Represents expense associated with a major scheduled turnaround at the nitrogen fertilizer plant, the Coffeyville refinery and Wynnewood refinery. (d) Represents the impact of share-based compensation awards. (e) Upon applying the goodwill impairment testing criteria under existing accounting rules during the fourth quarter of 2008, we determined that the goodwill in the petroleum segment was impaired, which resulted in a goodwill impairment loss of $42.8 million. This represented a write-off of the entire balance of the petroleum segment’s goodwill. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations You should read the following discussion and analysis of our financial condition and results of operations in conjunction with our financial statements and related notes included elsewhere in this Report. Forward-Looking Statements This Report, including, without limitation, the sections captioned ‘‘Business’’ and ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations,’’ contains ‘‘forward-looking statements’’ as defined by the SEC. Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These 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 performance, future capital sources and other matters; 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. 64 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 that 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 under the section captioned ‘‘Risk Factors’’ and contained elsewhere in this Report. All forward-looking statements contained in this Report only speak 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 as may be required by law. Overview and Executive Summary We are 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 ammonia and UAN. We own the general partner and a majority of the common units representing limited partner interests in each of the Refining Partnership and the Nitrogen Fertilizer Partnership. We operate under two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2012, 2011 and 2010, we generated consolidated net sales of $8.6 billion, $5.0 billion and $4.1 billion, respectively, and operating income of $1,034.9 million, $566.6 million and $93.1 million, respectively. The petroleum business generated net sales of $8.3 billion, $4.8 billion and $3.9 billion, and the nitrogen fertilizer business generated net sales of $302.3 million, $302.9 million and $180.5 million in each case for the years ended December 31, 2012, 2011 and 2010, respectively. The petroleum business generated operating income of $1,012.5 million, $465.7 million and $104.6 million in each case, for the years ended December 31, 2012, 2011 and 2010, respectively. The nitrogen fertilizer business generated operating income of $115.8 million, $136.2 million and $20.4 million in each case for the years ended December 31, 2012, 2011 and 2010, respectively. Petroleum business. The petroleum business consists of our interest in the Refining Partnership. We own the general partner and approximately 81% of the common units of the Refining Partnership. The petroleum business consists of a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and, as of December 15, 2011, a 70,000 bpd medium complexity crude oil unit refinery in Wynnewood, Oklahoma capable of processing 20,000 bpd of light sour crude oil (within its 70,000 bpd capacity). In addition, its supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 50,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas, (2) a rack marketing business supplying refined petroleum product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and at throughput terminals on Magellan and NuStar’s refined petroleum products distribution systems, (3) a 145,000 bpd pipeline system (supported by approximately 350 miles of Company owned and leased pipeline) that transports crude oil to the Coffeyville refinery and associated crude oil storage tanks with a capacity of 1.2 million barrels, (4) crude oil storage tanks with a capacity of 0.5 million barrels in Wynnewood, Oklahoma (5) 1.0 million barrels of company owned crude oil storage capacity 65 in Cushing, Oklahoma (6) an additional 3.3 barrels of leased crude oil storage capacity located in Cushing and (7) approximately 4.5 million barrels of combined refinery related 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. The early June 2012 reversal of the Seaway pipeline that now flows from Cushing, Oklahoma to the U.S. Gulf Coast has eliminated the ability to source foreign waterborne crude oil, as well as deep water U.S. Gulf of Mexico produced sweet and sour crude oil grades. 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 to its Broome Station tank farm. The petroleum business maintains capacity on the Spearhead and Keystone pipelines from Canada to Cushing. It also maintains leased and owned storage in Cushing to facilitate optimal crude oil purchasing and blending. The Coffeyville refinery blend consists of a combination of crude oil grades, including domestic grades and various Canadian medium and heavy sours and sweet synthetics. Crude oil is supplied to the Wynnewood refinery through two third-party pipelines operated by Sunoco Pipeline and Excel Pipeline and historically has mainly been sourced from Texas and Oklahoma. The Wynnewood refinery is capable of processing a variety of crudes, including West Texas sour, West Texas Intermediate, sweet and sour Canadian and other U.S. domestically produced crude oils. The petroleum business expects to spend approximately $50 million on a hydrocracker project that will increase the conversion capability and the ULSD yield of the Wynnewood refinery. The access to a variety of crude oils coupled with the complexity of the refineries allows the petroleum business to purchase crude oil at a discount to WTI. The consumed crude oil cost discount to WTI for 2012 was $2.26 per barrel compared to $3.98 per barrel in 2011 and $3.39 per barrel in 2010. Nitrogen fertilizer business. The nitrogen fertilizer business consists of our interest in the Nitrogen Fertilizer Partnership. We own the general partner and approximately 70% of the common units of the Nitrogen Fertilizer Partnership. The nitrogen fertilizer business consists of a nitrogen fertilizer manufacturing facility that is the only operation in North America that utilizes a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer. The facility includes a 1,225 ton-per-day ammonia unit, a 2,025 ton-per-day UAN unit and a gasifier complex having a capacity of 84 million standard cubic feet per day of hydrogen. The gasifier is a dual-train facility, with each gasifier able to function independently of the other, thereby providing redundancy and improving reliability. In 2012, the nitrogen fertilizer business produced 390,017 tons of ammonia, of which approximately 68% was upgraded into 643,813 tons of UAN. The Nitrogen Fertilizer Partnership will continue to expand the nitrogen fertilizer business’ existing asset base to execute its growth strategy. The Nitrogen Fertilizer Partnership’s growth strategy included expanding production of UAN and acquiring additional infrastructure and production assets. In February 2013, the Nitrogen Fertilizer Partnership completed a significant two-year plant expansion designed to increase its UAN production capacity by 400,000 tons, or approximately 50%, per year. The UAN expansion is expected to be at full operating rates in March 2013. The primary raw material feedstock utilized in the nitrogen fertilizer production process 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 and pet coke prices have been more stable when compared to natural gas prices. We believe the nitrogen fertilizer business has historically been a lower cost producer and marketer of ammonia and 66 UAN fertilizers in North America. The nitrogen fertilizer business currently purchases most of its pet coke from the Refining Partnership pursuant to a long-term agreement having an initial term that ends in 2027, subject to renewal. During 2012, the Nitrogen Fertilizer Partnership entered into a pet coke supply agreement with HollyFrontier Corporation. The initial term ends in December 2013 and is subject to renewal. On average, during the past five years, over 70% of the pet coke utilized by the nitrogen fertilizer plant was produced and supplied by the Refining Partnership’s crude oil refinery in Coffeyville. Transaction Agreement On April 18, 2012, CVR Energy entered into a Transaction Agreement (the ‘‘Transaction Agreement’’) with certain affiliates of Icahn Enterprises and Carl C. Icahn. Pursuant to the Transaction Agreement, a wholly-owned subsidiary of Icahn Enterprises offered (the ‘‘Offer’’) to purchase all of the issued and outstanding shares of CVR Energy’s common stock for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment (‘‘CCP’’) right for each share, which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy is executed on or before August 18, 2013 and such transaction closes. In May 2012, affiliates of Icahn Enterprises acquired a majority of the common stock of CVR Energy through the Offer. As a result of shares tendered into the Offer during the initial offering period and subsequent additional purchases, Icahn Enterprises owned approximately 82% of CVR Energy’s outstanding common stock as of December 31, 2012. Pursuant to the Transaction Agreement, all employee restricted share awards scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. Nitrogen Fertilizer Partnership Shelf Registration Statement On August 29, 2012, the Nitrogen Fertilizer Partnership’s registration statement on Form S-3 was declared effective by the SEC enabling us to offer and sell from time to time, in one or more public offerings or direct placements, up to 50,920,000 common units. Refining Partnership Initial Public Offering On January 23, 2013, the Refining Partnership completed the Refining Partnership IPO. The Refining Partnership sold 24,000,000 common units at a price of $25.00 per common unit, resulting in gross proceeds of $600.0 million. Of the common units issued, 4,000,000 units were purchased by an affiliate of Icahn Enterprises. Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per common unit resulting in gross proceeds of $90.0 million. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol ‘‘CVRR.’’ In connection with the Refining Partnership IPO, the Refining Partnership paid approximately $32.5 million in underwriting fees and incurred approximately $3.9 million of other offering costs. Following the Refining Partnership IPO, CVR Energy indirectly owns approximately 81% of the Refining Partnership’s outstanding common units and 100% of the Refining Partnership’s general 67 partner, which holds a non-economic general partner interest. As of December 31, 2012, CVR Energy owned 100% of CVR Refining. Accordingly, our financial statements for the year ended December 31, 2012 contained in this Report do not reflect any noncontrolling interest in the Refining Partnership. Petroleum Business Major Influences on Results of Operations 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 its 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. 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 is 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 the refinery 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 refinery 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 68 the price of the delivered crude oil and the price of WTI. The spread is referred to as the consumed crude oil differential. The refinery 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 West Canadian Select (‘‘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 our 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 petroleum business benefits from the fact that its marketing region consumes more refined products than it produces resulting in prices that reflect the logistics cost for U.S. Gulf Coast refineries to ship into its region. The result of this logistical advantage and 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 that prices the petroleum business realizes are different than those used in determining the 2-1-1 crack spread. The difference between its price 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 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 year ended December 31, 2012, a $1.00 change in natural gas prices would have increased or decreased the petroleum business’ natural gas costs by approximately $7.8 million. 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 it is able to maintain significantly reduces the impact of commodity price volatility on its petroleum product inventory position relative to other refiners. This target inventory position is generally not hedged. To the extent its inventory position deviates from the target level, the petroleum business considers risk mitigation activities usually through the purchase or sale of futures contracts on the NYMEX. Its hedging activities carry customary time, location and product grade basis risks generally associated with hedging activities. Because most of its titled inventory is valued under the FIFO costing method, price fluctuations on our target level of titled inventory have a major effect on its financial results. Safe and reliable operations at the refineries are key to the petroleum business’ financial performance and results of operations. Unplanned downtime at the refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The petroleum business seeks to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The Coffeyville refinery completed the first phase of a two phase turnaround during the fourth quarter of 2011. The second phase was completed during the first quarter of 2012, and its next turnaround is scheduled to begin in late 2015. The Wynnewood Refinery completed a turnaround in December 2012. Its next turnaround is scheduled to begin in late 2016. 69 The Coffeyville refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit (the ‘‘FCCU’’) on December 28, 2010, which led to reduced crude oil throughput and repair costs of approximately $2.2 million net of insurance receivable for the year ended 2011. The petroleum business used the resulting downtime to perform certain turnaround activities which had otherwise been scheduled for later in 2011, along with opportunistic maintenance, which cost approximately $4.0 million in total. The refinery returned to full operations on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. The petroleum business estimates that approximately 1.9 million barrels of crude oil processing were lost in the first quarter of 2011 due to this incident. The Coffeyville refinery also experienced a small fire at its continuous catalyst reformer (the ‘‘CCR’’) in May 2011, which led to reduced crude oil throughput for the second quarter of 2011. Repair costs, net of the insurance receivable, recorded for the year ended December 31, 2011 approximated $2.5 million. The interruption adversely impacted the production of refined products for the second quarter of 2011. The Wynnewood refinery experienced an unplanned maintenance event upon turnover of the facility to the Company. Operating deficiencies associated with the fluidized catalytic cracking unit required a 27-day outage to repair damage to the unit at a cost of $1.7 million. The outage required cutting the crude rate during the fourth quarter of 2011. On September 28, 2012, the Wynnewood refinery experienced an explosion in a boiler unit that had been temporarily shut down as part of the turnaround process. Two employees were fatally injured. Damage at the refinery was limited to the boiler; process units and other areas of the facility were unaffected and there was no evidence of environmental impacts. The petroleum business has completed its investigation of the incident and continues to cooperate with OSHA and ODL investigations. 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. Unlike its competitors, the nitrogen fertilizer business does not use natural gas as a feedstock and uses a minimal amount of natural gas as an energy source in its operations. As a result, changes in natural gas prices have a minimal impact on its results of operations. Instead, the adjacent Coffeyville refinery supplies the nitrogen fertilizer business with most of the pet coke feedstock it needs pursuant to a long-term 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, international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products. In addition, the demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted. 70 Natural gas is the most significant raw material required in our competitors’ production of nitrogen fertilizers. Over the past several years, natural gas prices have experienced high levels of price volatility although natural gas prices are currently at a ten year low. This pricing and volatility has a direct impact on our competitors’ cost of producing nitrogen fertilizer. In order to assess the operating performance of the nitrogen fertilizer business, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of nitrogen fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs. We and other competitors in the U.S. farm belt share a significant transportation cost advantage when compared to our out-of-region competitors in serving the U.S. farm belt agricultural market. In 2012, approximately 54% of the corn planted in the United States was grown within a $45 per UAN ton freight train rate of the nitrogen fertilizer plant. We are therefore able to cost-effectively sell substantially all of our products in the higher margin agricultural market, whereas a significant portion of our competitors’ revenues are derived from the lower margin industrial market. Our products leave the plant either in trucks for direct shipment to customers or in railcars for destinations located principally on the Union Pacific Railroad, and we do not currently incur significant intermediate transfer, storage, barge freight or pipeline freight charges. We estimate that our plant enjoys a transportation cost advantage of approximately $15 per UAN ton for transportation of UAN over competitors located in the U.S. Gulf Coast. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability. The value of nitrogen fertilizer products is also an important consideration in understanding our results. During 2012, the nitrogen fertilizer business upgraded approximately 68% of its ammonia production into UAN, a product that presently generates greater profit than ammonia. During 2011 and 2010, the nitrogen fertilizer business upgraded approximately 72% and 60%, respectively, of its ammonia production into UAN. UAN production is a major contributor to our profitability. The nitrogen fertilizer business’ largest raw material expense is pet coke, which it purchases from the petroleum business and third parties. In the years ended December 31, 2012, 2011 and 2010, the nitrogen fertilizer business spent approximately $16.2 million, $16.8 million and $7.4 million, respectively, for pet coke, which equaled an average cost per ton of $33, $33 and $17, respectively. The high fixed cost of the nitrogen fertilizer business’ direct operating expense structure also directly affects its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These fixed costs averaged approximately 87% of direct operating expenses over the 24 months ended December 31, 2012. The average annual operating costs over the 24 months ended December 31, 2012 have approximated $91.0 million. The nitrogen fertilizer business obtains most (over 70% on average during the last five years) of the pet coke it needs from the adjacent Coffeyville crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder on the open market. The price the nitrogen fertilizer business pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for UAN, or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton. Safe and reliable operations at the nitrogen fertilizer plant are critical to its financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plant may result in lost margin 71 opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The nitrogen fertilizer plant generally undergoes a facility turnaround every two years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately $3.0 million to $5.0 million per turnaround. The nitrogen fertilizer plant underwent a turnaround in the fourth quarter of 2012, at a cost of approximately $4.8 million. The next turnaround is currently scheduled for the fourth quarter of 2014. Agreements With the Refining Partnership and the Nitrogen Fertilizer Partnership In connection with our initial public offering and the transfer of the nitrogen fertilizer business to the Nitrogen Fertilizer Partnership in October 2007, we entered into a number of agreements with the Nitrogen Fertilizer Partnership that govern the business relations among the Nitrogen Fertilizer Partnership and its affiliates on the one hand and us and our other affiliates on the other hand. In connection with the Nitrogen Fertilizer Partnership IPO, we directly or through our subsidiaries amended and restated certain of the intercompany agreements and entered into several new agreements with the Nitrogen Fertilizer Partnership. In connection with the Refining Partnership IPO, 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 we lease 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 $150.0 million intercompany credit facility between CRLLC and the Refining Partnership and (ii) a services agreement, pursuant to which our management operates the petroleum business. Crude Oil Supply Agreement On August 31, 2012, CRRM and Vitol entered into the Vitol Agreement. The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended (the ‘‘Previous Supply Agreement’’). Under the agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us to reduce our inventory position and mitigate crude oil pricing risk. The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the ‘‘Initial Term’’). Following the Initial Term, the Vitol Agreement will automatically renew for successive one-year terms (each such term, a ‘‘Renewal Term’’) unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of the Initial Term or any Renewal Term. Notwithstanding the foregoing, CRRM has an option to terminate the Vitol Agreement effective December 31, 2013 by providing written notice of termination to Vitol on or before May 1, 2013. 72 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 discussed below. Factors Affecting Comparability Transaction Expenses In February 2012, Icahn commenced a tender offer to acquire all of the outstanding shares of common stock of our Company. On April 18, 2012, we entered into a transaction agreement and on May 7, 2012, Icahn announced that control of the Company had been acquired. CVR incurred related costs of approximately $44.2 million for the year ended December 31, 2012 related to the proxy contest. We are currently challenging a majority of the expenses charged and, if we are successful, such expenses would be reversed and have a favorable impact to our results of operations. Wynnewood Acquisition On December 15, 2011, we acquired all of the issued and outstanding shares of WEC for $593.4 million, consisting of an initial cash payment of $525.0 million, capital expenditure adjustments of $1.8 million and $66.6 million for working capital. The assets acquired include the 70,000 bpd refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of storage tanks. The financial results of WEC have been included in the results of the petroleum business since the date of the Wynnewood Acquisition. New and Refinanced Indebtedness ABL Credit Facility. On February 22, 2011, CRLLC and certain of its subsidiaries entered into a $250.0 million asset-backed revolving credit agreement (the ‘‘ABL credit facility’’). The ABL credit facility replaced an earlier first priority credit facility. As a result of the termination of the first priority credit facility, a portion of our previously deferred financing costs of approximately $1.9 million were written off. This expense is reflected on the Consolidated Statement of Operations as a loss on extinguishment of debt for the year ended December 31, 2011. On December 15, 2011, CRLLC entered into an incremental commitment agreement to increase availability under the ABL credit facility by an additional $150.0 million. In connection with entering into and then expanding the ABL credit facility, approximately $9.9 million of fees were incurred that were deferred and are to be amortized over the term of the credit facility on a straight-line basis. On December 20, 2012, CRLLC, CVR Refining, Refining LLC and each of the operating subsidiaries of CVR Refining (collectively, the ‘‘credit parties’’) entered into an amended and restated ABL credit agreement (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 is a senior secured asset based revolving credit facility in 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 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. The Amended and Restated ABL Credit Facility replaced the ABL credit facility described above. As a result of the amendment and restatement of the ABL credit facility, we expensed a portion of our previously deferred financing costs of approximately $4.1 million. This expense is reflected on the Consolidated Statement of Operations as a loss on extinguishment of debt for the year ended December 31, 2012. In connection with the Amended and Restated ABL Credit Facility, we also incurred approximately $2.1 million of fees that were deferred and are to be amortized over the term of the Amended and Restated ABL Credit Facility on a straight-line basis. 73 Notes. In April 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance, issued $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the ‘‘First Lien Notes’’) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the ‘‘Second Lien Notes’’ and together with the First Lien Notes, the ‘‘Old Notes’’). We used the proceeds from the sale of the Old Notes to pay off $453.0 million of term loans as described below under ‘‘— First Priority Credit Facility.’’ In December 2010, CRLLC made a voluntary unscheduled payment of $27.5 million on the First Lien Notes, resulting in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling approximately $1.6 million, which was recognized as a loss on extinguishment of debt in our Consolidated Statements of Operations. On December 15, 2011, CRLLC and Coffeyville Finance issued an additional $200.0 million of the First Lien Notes to partially fund the Wynnewood Acquisition. Financing and other third-party costs incurred at the time of $6.0 million were deferred to be amortized over the remaining term of the First Lien Notes. In connection with the Wynnewood Acquisition, in November 2011, we received a commitment for a one year bridge loan, which remained undrawn and was terminated as a result of the issuance of the First Lien Notes. Fees and other third-party costs related to the bridge loan totaling $3.9 million were expensed in December 2011. On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the ‘‘2022 Notes’’). The 2022 Notes were issued at par. A portion of the net proceeds from the offering approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. A portion of the remaining net proceeds from the 2022 Notes offering were used to fund the redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount. Previously deferred financing charges and unamortized original issuance premium related to the First Lien Notes totaled approximately $8.1 million and $6.3 million, respectively. As a result of these transactions, a loss on extinguishment of debt of $33.4 million was recorded in the Consolidated Statement of Operations in the fourth quarter of 2012, which includes the total premiums paid of $31.6 million and write-off of previously deferred financing charges of $8.1 million, partially offset by the write-off of the unamortized original issuance premium of $6.3 million. Nitrogen Fertilizer Partnership Credit Facility. On April 13, 2011, CRNF, as borrower, and the Nitrogen Fertilizer Partnership, as guarantor, entered into a new credit facility with a group of lenders. The credit facility includes 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 is no scheduled amortization and the credit facility matures in April 2016. The Nitrogen Fertilizer Partnership, upon the closing of the credit facility, made a special distribution of approximately $87.2 million to CRLLC, in order to, among other things, fund the offer to purchase CRLLC’s Old Notes required upon consummation of the Nitrogen Fertilizer Partnership IPO. The revolving credit facility is used to finance on-going working capital, capital expenditures, letter of credit issuances and other general needs of CRNF. See Note 12 for more information regarding the credit facility. 74 First Priority Credit Facility. In December 2006, CRLLC entered into a credit facility (the ‘‘first priority credit facility) consisting of $775.0 million of tranche D term loans (the ‘‘tranche D term loans’’), a $150.0 million revolving credit facility and a $150.0 million first priority funded letter of credit in support of a cash flow swap. The first priority credit facility was repaid in full in connection with the issuance of the Old Notes in April 2010. In January 2010, we made a voluntary unscheduled principal payment of $20.0 million on our tranche D term loans. In addition, we made a second voluntary unscheduled principal payment of $5.0 million in February 2010, reducing our tranche D term loans’ outstanding principal balance to $453.3 million. In connection with these voluntary prepayments, we paid a 2.0% premium totaling $0.5 million to the lenders of our first priority credit facility. We used the proceeds from the issuance of our Old Notes in April 2010 to pay off the remaining $453.0 million term loans. On March 12, 2010, CRLLC entered into a fourth amendment to the first priority credit facility. In connection with this amendment, CRLLC incurred lender fees of approximately $4.5 million. These fees were recorded as deferred financing costs in the first quarter of 2010. In addition, CRLLC incurred third-party costs of approximately $1.5 million primarily consisting of administrative and legal costs. Of the third-party costs incurred we expensed $1.1 million in 2010 and the remaining $0.4 million was recorded as additional deferred financing costs. In April 2010, upon issuance of the Old Notes and repayment of the first priority credit facility, previously deferred financing costs totaling approximately $5.4 million associated with the first priority credit facility term debt were written off at that time. In connection with the payoff, we paid a 2.0% premium totaling approximately $9.1 million. Share-Based Compensation Through the Company’s Long-Term Incentive Plan (‘‘LTIP’’), equity compensation awards may be awarded to the Company’s employees, officers, consultants, advisors and directors including, but not limited to, shares of non-vested common stock. Prior to the acquisition by IEP Energy, LLC and the related change of control, restricted shares, when granted, were valued at the closing market price of CVR Energy’s common stock at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. The change of control and related Transaction Agreement in May 2012 triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. Additional share-based compensation of approximately $12.4 million was incurred to revalue the awards upon modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards, the classification changed from equity awards to liability awards. For the years ended December 31, 2012, 2011 and 2010, we incurred compensation expense of $36.9 million, $9.8 million and $2.4 million, respectively, related to non-vested share-based compensation awards related to the LTIP. Through the CVR Partners, LP Long-Term Incentive Plan (‘‘CVR Partners LTIP’’), shares of non-vested common units and phantom units may be awarded to (1) employees of the Nitrogen Fertilizer Partnership, (2) employees of the general partner and (3) members of the board of directors of the general partner. In December 2012, the board of directors of the general partner of the Nitrogen Fertilizer Partnership approved an amendment to modify the terms of certain phantom unit awards previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. The 75 amendment triggered a modification to the awards by providing that the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. Additional share-based compensation incurred to revalue the unvested units upon modification was not material. For awards vesting subsequent to amendment, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity-classified award to a liability-classified award. For the years ended December 31, 2012, 2011 and 2010, we incurred compensation expense of $2.2 million, $1.2 million and $0, respectively, related to non-vested share-based compensation awards related to the CVR Partners LTIP. Through CRLLC, we had two Phantom Unit Appreciation Plans (the ‘‘Phantom Unit Plans’’), whereby directors, employees, and service providers had been eligible to be awarded phantom points at the discretion of our board of directors or compensation committee. The Phantom Unit Plans provided for two classes of interests: phantom service points and phantom performance points (collectively referred to as ‘‘phantom points’’). The phantom points represented a contractual right to receive a payment when a payment was made in respect of certain profits interests in the entities through which our former sponsors held their equity interests in us. We accounted for awards under our Phantom Unit Plans as liability based awards. In accordance with FASB ASC Topic 718, Compensation — Stock Compensation, the expense associated with these awards was based on the current fair value of the awards which was derived from a probability-weighted expected return method. The Phantom Unit Plans were terminated in December 2012. Our executive officers were also compensated through the issuance of common units and override units in the entities through which our former sponsors held their equity in us. In conjunction with our initial public offering in October 2007, the override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment by an investor for stock-based compensation granted to employees of an equity method investee. In addition, these awards are subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment for equity instruments that are issued to recipients other than employees for acquiring or in conjunction with selling goods or services. In accordance with this accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived under the same methodology as the Phantom Unit Plans, as remeasured at each reporting date until the awards vest. Certain override units became fully vested during the second quarter of 2010. As such, there was no additional expense incurred, subsequent to vesting, with respect to these share-based compensation awards. Due to the divestiture of all ownership of CVR Energy by CALLC and CALLC II in 2011, there was no further share-based compensation expense associated with override units subsequent to 2011. In association with the divestiture of ownership and the distributions to the override unitholders of CALLC and CALLC II, the holders of phantom units received the associated payments in 2011. As a result, there was no further share-based compensation expense recorded for the Phantom Unit Plans subsequent to 2011. For the years ended December 31, 2011 and 2010, we recorded compensation expense of $16.2 million and $34.8 million, respectively, related to the phantom and override unit share-based compensation awards. Noncontrolling Interest Prior to the Nitrogen Fertilizer Partnership IPO, the noncontrolling interests reflected in our consolidated financial statements represented the incentive distribution rights (‘‘IDRs’’) of CVR GP, LLC, an entity owned directly by our former sponsors and senior management, which owned the Nitrogen Partnership’s general partner. In April 2011, in connection with the Nitrogen Fertilizer Partnership IPO, the IDRs were purchased by the Nitrogen Fertilizer Partnership and were 76 subsequently extinguished, eliminating the associated noncontrolling interest related to the IDRs. As a result of the Nitrogen Fertilizer Partnership IPO, CVR Energy recorded a noncontrolling interest for the common units sold into the public market, which represented an approximately 30% interest in the net book value of the Nitrogen Fertilizer Partnership at the time of the Nitrogen Fertilizer Partnership IPO. Effective with the Nitrogen Fertilizer Partnership IPO, CVR Energy’s noncontrolling interest reflected on the consolidated balance sheet will be impacted by approximately 30% of the net income of the Nitrogen Fertilizer Partnership and related distributions for each future reporting period. The revenue and expenses from the Nitrogen Fertilizer Partnership will continue to be consolidated with CVR Energy’s statement of operations based upon the fact that the general partner is owned by CRLLC, a wholly-owned subsidiary of CVR Energy, and therefore CVR Energy has the ability to control the activities of the Nitrogen Fertilizer Partnership. However, the percentage of ownership held by the public unitholders will be reflected as net income attributable to noncontrolling interest in our consolidated statement of operations and will reduce consolidated net income to derive net income attributable to CVR Energy. Publicly Traded Partnership Expenses Our general and administrative expenses increased in 2012 and 2011 in part due to the costs of the Nitrogen Fertilizer Partnership operating as a publicly traded company, including costs associated with SEC reporting requirements (including annual and quarterly reports to unitholders), tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees. We estimate that these incremental general and administrative expenses, which also include increased personnel costs, approximate $5.5 million per year, excluding the costs associated with the initial implementation of the Nitrogen Fertilizer Partnership’s Sarbanes-Oxley Section 404 internal controls review and testing. These increased costs have been paid by the Nitrogen Fertilizer Partnership. Our historical consolidated financial statements prior to 2011 do not reflect the impact of these expenses, which affects the comparability of the post- Nitrogen Fertilizer Partnership IPO results with our financial statements from periods prior to the completion of the Nitrogen Fertilizer Partnership IPO. September 2010 UAN Vessel Rupture On September 30, 2010, the nitrogen fertilizer plant experienced an interruption in operations due to a rupture of a high-pressure UAN vessel. All operations at the nitrogen fertilizer facility were immediately shut down. No one was injured in the incident. Total gross costs related to the incident were approximately $11.7 million for repairs and maintenance and other associated costs. Of the costs incurred, approximately $4.9 million were capitalized. Approximately $8.0 million of insurance proceeds were received related to the property damage insurance claim. The Nitrogen Fertilizer Partnership received approximately $1.0 million in 2012, $2.7 million in 2011 and $4.3 million in 2010 related to the property damage insurance claim. We also recognized income of approximately $3.4 million during 2011 from insurance proceeds received related to our business interruption policy. As of December 31, 2012, the Nitrogen Fertilizer Partnership had received the final insurance payments under applicable insurance policies and those insurance policy claims are closed. Distributions to CVR Partners and CVR Refining 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 each quarter will be determined by the board of directors of the Nitrogen Fertilizer Partnership’s general partner following the end of such quarter. Available cash for each quarter through the end of 2012 generally equals the Nitrogen Fertilizer Partnership’s cash flow from 77 operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of its general partner deems necessary or appropriate. Additionally, the Nitrogen Fertilizer Partnership retains cash on hand associated with prepaid sales at each quarter end for future distributions to common unitholders based upon the recognition into income of the prepaid sales. Beginning with the first quarter of 2013, the board of directors of the general partner has adopted an amended policy to calculate available cash starting with Adjusted Nitrogen Fertilizer EBITDA reduced for cash needed for maintenance capital expenditures, debt service and other contractual obligations, major scheduled turnaround expenses incurred, and reserves for future operating or capital needs that the board of directors of its general partner deems necessary or appropriate. The board of directors of the Nitrogen Fertilizer Partnership may modify the cash distribution policy at any time, and the partnership agreement does not require the Nitrogen Fertilizer Partnership to make distributions at all. The following is a summary of cash distributions paid to Nitrogen Fertilizer Partnership unitholders during the years ended December 31, 2012 and 2011 for the respective quarters to which the distributions relate: December 31, 2011 March 31, 2012 June 30, 2012 September 30, 2012 Amount paid CRLLC . . . . . . . . . Amounts paid to public unitholders . . . . . . . . . . . . . . . Total amount paid . . . . . . . . . . . Per common unit . . . . . . . . . . . $ $ $ 29.9 13.0 42.9 0.588 ($ in millions except per common units amounts) 25.3 $ 30.5 26.6 $ $ 11.6 38.2 0.523 $ $ 13.3 43.8 0.600 $ $ 10.9 36.2 0.496 $ $ Common units outstanding . . . . . 73,030,936 73,030,936 73,043,356 73,046,498 Total Cash Distributions Paid in 2012 $112.4 48.8 $161.2 $2.207 December 31, March 31, 2011 June 30, 2011 September 30, 2011 Total Cash Distributions Paid in 2011 Amount paid CRLLC . . . . . . . . . . . . Amounts paid to public unitholders . . Total amount paid . . . . . . . . . . . . . . Per common unit . . . . . . . . . . . . . Common units outstanding . . . . . . . . 2010 $ — — $ — $ — — ($ in millions except per common units amounts) $ — — $ — $ — — $ $ $ 20.7 9.0 29.7 0.407 $ $ $ 29.1 12.7 41.8 0.572 $ 49.8 21.6 $ 71.5 $0.979 73,002,956 73,002,956 On February 14, 2013, the Nitrogen Fertilizer Partnership paid out a cash distribution to the Nitrogen Fertilizer Partnership’s unitholders of record at the close of business on February 7, 2013 for the fourth quarter of 2012 in the amount of $0.192 per common unit, or $14.0 million in aggregate. We received $9.8 million in respect of our common units. Total cash distributions paid based upon available cash for 2012 were $1.81 per common unit. The board of directors of the general partner of the Refining Partnership adopted a policy in connection with the completion of its initial public offering on January 23, 2013, pursuant to which it will distribute all of the available cash it generates each quarter, beginning with the quarter ending March 31, 2013. For the quarter ended March 31, 2013, available cash will be adjusted to exclude the period prior to the Refining Partnership IPO from January 1, 2013 through January 22, 2013. Available cash for each quarter will be determined by the board of directors of the general partner following the end of such quarter. The Refining Partnership expects that available cash for each quarter will be 78 calculated based on its Adjusted EBITDA for the quarter, less cash needed for debt service, reserves for maintenance and environmental capital expenditures, and reserves for expenses associated with major scheduled turnarounds. The board of directors may also determine that it is appropriate to reserve cash for future operating or capital needs. The Refining Partnership does not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in its quarterly distribution or otherwise to reserve cash for distributions, nor do they intend to incur debt to pay quarterly distributions. Further, it is the Refining Partnership’s intent, subject to market conditions, to finance growth capital externally, and not to reserve cash for unspecified potential future needs. As of the date of this Report, we own approximately 81% of the Refining Partnership’s common units, and are entitled to a pro rata percentage of the Refining Partnership’s distributions in respect of its common units. Nitrogen Fertilizer Partnership Interest Rate Swap Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates by using interest rate derivatives to convert some or all of the interest rates the Nitrogen Fertilizer Partnership pays for the $125.0 million of term loan borrowings from a floating rate to a fixed rate. On June 30 and July 1, 2011, CRNF entered into two Interest Rate Swap agreements with J. Aron & Company. These Interest Rate Swap agreements commenced on August 12, 2011. We have determined that the Interest Rate Swaps qualifies for hedge accounting treatment. The impact recorded for the years ended December 31, 2012 and 2011 is $1.0 million and $0.4 million, respectively, in interest expense. For the years ended December 31, 2012 and 2011, the Nitrogen Fertilizer Partnership recorded a decrease in fair market value on the Interest Rate Swap agreements of $0.4 million and $2.4 million, respectively, which is unrealized in accumulated other comprehensive income. Commodity Swaps — Petroleum Segment Beginning in September 2011, we entered into commodity swap contracts with effective periods beginning in January 2012. 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 Consolidated Balance Sheets with changes in fair value currently recognized in the Consolidated Statements of Operations. At December 31, 2012 and 2011, we had open commodity hedging instruments consisting of 23.3 million barrels and 13.0 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production. None of these swap contracts were designated as cash flow hedges, and all changes in fair market value will be reported in earnings in the period in which the value change occurs. For the years ended December 31, 2012 and 2011, we recognized a realized loss of $126.6 million and $0, respectively, and an unrealized loss of $147.3 million and an unrealized gain of $80.4 million, respectively. Turnaround Projects The Coffeyville refinery completed the second phase of a two-phase turnaround project during the first quarter of 2012. The first phase was completed during the fourth quarter of 2011. The Coffeyville refinery has incurred costs of approximately $21.2 million, $66.4 million and $1.2 million for the years ended December 31, 2012, 2011 and 2010, respectively, associated with the 2011/2012 turnaround. The Wynnewood refinery completed a turnaround in the fourth quarter of 2012. The Wynnewood refinery incurred costs of approximately $102.5 million for the year ended December 31, 2012 associated with the 2012 turnaround. During the fourth quarters of 2012 and 2010, the nitrogen fertilizer business completed scheduled major turnarounds of the nitrogen fertilizer plant at a total cost of approximately $4.8 million and $3.5 million, respectively, the majority of which was expensed in the fourth quarter of 79 each year. In connection with the nitrogen fertilizer plant turnaround in 2010, we also wrote off approximately $1.4 million of fixed assets for the year ended December 31, 2010. Costs associated with turnaround projects are recorded in direct operating expense (exclusive of depreciation and amortization) on the Consolidated Statements of Operations. Petroleum Business Industry Factors Earnings for the petroleum business depend largely on its refining margins, which have been and continue to be volatile. Refining margins are impacted primarily by the relationship between crude oil and refined product prices which are influenced by factors beyond its control. The marketing region continues to be undersupplied and is a net importer of transportation fuels. Crude oil discounts also contribute to the petroleum business earnings. Discounts for sour and heavy sour crude oil compared to sweet crude oil continue to fluctuate widely. The worldwide production of sour and heavy sour crude oil, continuing demand for light sweet crude oil, and the increasing volumes of Canadian sour crude oil to the mid-continent will continue to cause wide swings in discounts. As a result of an expansion project, the petroleum business increased its ability to process higher volumes of heavy sour crude oil, primarily Canadian crude oil, and this ability provides it the flexibility to reduce the dependence on typically more expensive light sweet crude oil. Additionally, the relationship between current spot prices and future prices can impact profitability. As such, the petroleum business believes that its 6.0 million barrels of crude oil storage in Cushing, Oklahoma and other locations allows it to take advantage of the contango market when such conditions exist. Contango markets are generally characterized by prices for future delivery that are higher than the current, or spot, price of a commodity. This condition provides economic incentive to hold or carry a commodity in inventory. Nitrogen Fertilizer Business Global demand for fertilizers is driven primarily by population growth, dietary changes in the developing world and increased consumption of bio-fuels. According to the International Fertilizer Industry Association, from 1972 to 2010, global fertilizer demand grew 2.1% annually. Fertilizer use is projected to increase by 45% between 2005 and 2030 to meet global food demand according to a study funded by the Food and Agricultural Organization of the United Nations. Currently, the developed world uses fertilizer more intensively than the developing world, but sustained economic growth in emerging markets is increasing food demand and fertilizer use. As an example, China’s grain production increased 55% between 2001 and 2012, but still failed to keep pace with increases in demand, prompting China to grow its grain imports by more than 140% over the same period, according to the United States Department of Agriculture. World grain demand has increased 6% over the last five years leading to a tight grain supply environment and significant increases in grain prices, which is highly supportive of fertilizer prices. During this same time period, average corn belt UAN prices increased 26% from $290 per ton to $365 per ton. Nitrogen fertilizer prices have decoupled from their historical correlation with natural gas prices and are now driven primarily by demand dynamics. During the last five years, corn prices in Illinois have averaged $5.05 per bushel, an increase of 100% above the average price of $2.52 per bushel during the preceding five years. At existing grain prices and prices implied by futures markets, farmers are expected to generate substantial profits, leading to relatively inelastic demand for fertilizers. The United States is the world’s largest exporter of coarse grains, accounting for 22% of world exports and 26% of total world production, according to the USDA. Fertecon estimates the United States is the world’s third largest consumer of nitrogen fertilizer and historically the world’s first or 80 second largest importer of nitrogen fertilizer, importing approximately 41% of its nitrogen fertilizer needs. North American producers have a significant and sustainable cost advantage over European producers that export to the U.S. market. Over the last decade, the North American nitrogen fertilizer market has experienced significant consolidation through plant closures and corporate consolidation. Unlike ammonia and urea, UAN can be applied throughout the growing season and can be applied in tandem with pesticides and fungicides, providing farmers with flexibility and cost savings. As a result of these factors, UAN commands a premium price to urea and ammonia, on a nitrogen equivalent basis. Results of Operations In this ‘‘Results of Operations’’ section, we first review our business on a consolidated basis, and then separately review the results of operations of each of our petroleum and nitrogen fertilizer businesses on a standalone basis. Consolidated Results of Operations The period to period comparisons of our results of operations have been prepared using the historical periods included in our financial statements. This ‘‘Results of Operations’’ section compares the year ended December 31, 2012 with the year ended December 31, 2011 and the year ended December 31, 2011 with the year ended December 31, 2010. Net sales consist principally of sales of refined fuel and nitrogen fertilizer products. For the petroleum business, net sales are mainly affected by crude oil and refined product prices, changes to the input mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value light products, such as gasoline, rather than lower value finished products, such as pet coke. In the nitrogen fertilizer business, net sales are primarily impacted by manufactured tons and nitrogen fertilizer prices. Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred to as crack spreads. See ‘‘ — Major Influences on Results of Operations.’’ We discuss the results of the petroleum business in the context of per barrel consumed crack spreads and the relationship between net sales and cost of product sold. Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and therefore do not equal the sum of the operating results of the petroleum and nitrogen fertilizer businesses. The following table provides an overview of our results of operations during the past three fiscal years: Consolidated Financial Results Year Ended December 31, 2012 2011 2010 Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of product sold(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance recovery — business interruption . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expense(1) . . . . . . . . . . . . . . . . . . . Depreciation and amortization(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Net income attributable to noncontrolling interest . . . . . . . . . . . . Net income attributable to CVR Energy Stockholders . . . . . . . . . . . . . (1) Amounts are shown exclusive of depreciation and amortization. $8,567.3 6,696.9 522.1 — 183.4 130.0 $1,034.9 412.6 34.0 $ 378.6 (in millions) $5,029.1 3,943.5 334.1 (3.4) 98.0 90.3 $ 566.6 378.6 32.8 $ 345.8 81 $4,079.8 3,568.1 239.8 — 92.0 86.8 93.1 14.3 — 14.3 $ $ Depreciation and amortization is comprised of the following components as excluded from cost of product sold, direct operating expense and selling, general and administrative expense: Consolidated Financial Results Depreciation and amortization excluded from cost of product sold . . . Depreciation and amortization excluded from direct operating Year Ended December 31, 2012 2011 2010 (in millions) $ 2.5 3.7 $ $ 2.8 expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124.1 86.0 81.9 Depreciation and amortization excluded from selling, general and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 1.8 2.1 Total depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . $130.0 $90.3 $86.8 (2) The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature. Positive amounts represent expenses which should be added to reported operating income for comparability, while negative amounts should be subtracted for comparability: Consolidated Financial Results Loss on extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . . . . . . Letter of credit & interest rate swap expense included in selling, general and administrative expenses . . . . . . . . . . . . . . . . . . . . . . Major scheduled turnaround expense . . . . . . . . . . . . . . . . . . . . . . . Unrealized (gain) loss on derivatives, net . . . . . . . . . . . . . . . . . . . . Share-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . Acquisition and integration expenses — Gary-Williams(a) . . . . . . . . Year Ended December 31, 2012 2011 2010 (in millions) $ 2.1 $ 37.5 $16.6 1.3 128.5 (148.0) 39.1 11.0 1.5 66.4 (85.3) 27.2 9.1 4.7 4.8 2.2 37.2 — (a) On December 15, 2011, CRLLC acquired the stock of WEC (formerly known as Gary-Williams Energy Corporation) and its wholly-owned subsidiaries which owned a 70,000 barrel per day refinery in Wynnewood, Oklahoma. Included in Acquisition and integration expenses — Gary-Williams are legal and other professional fees associated with the acquisition and certain costs incurred beginning in 2011 associated with the preliminary integration of the acquired business. In conjunction with the acquisition, the Company also incurred approximately $3.9 million of costs associated with a bridge loan that was committed but undrawn. The costs were immediately expensed and not deferred. Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011(Consolidated) Net Sales. Consolidated net sales were $8,567.3 million for the year ended December 31, 2012 compared to $5,029.1 million for the year ended December 31, 2011. The increase of $3,538.2 million was primarily due to an increase in petroleum net sales of $3,529.7 million that resulted from significantly higher sales volumes due to the inclusion of a full year of sales for the Wynnewood refinery and higher product prices. Our average sales price per gallon for the year ended December 31, 2012 of $2.86 for gasoline and $3.08 for distillates increased by 1.5% and 1.8% respectively, as compared to the year ended December 31, 2011. Nitrogen fertilizer segment net sales decreased by $0.6 million primarily as the result of lower UAN sales volumes, which were negatively impacted by the downtime associated with the scheduled major turnaround during 2012. 82 Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $6,696.9 million for the year ended December 31, 2012, as compared to $3,943.5 million for the year ended December 31, 2011. The increase of $2,753.4 million primarily resulted from an increase in crude oil throughputs due to the inclusion of a full year of consumption at the Wynnewood refinery. Decreases in crude oil prices also caused fluctuations in the inventory valuation, thereby resulting in an unfavorable FIFO inventory impact for the year ended December 31, 2012 compared to a favorable FIFO impact for the year ended December 31, 2011. Our total increase included higher cost of product sold (exclusive of depreciation and amortization) by the nitrogen fertilizer business. This was primarily the result of higher costs of transactions with external parties totaling $3.8 million due to higher rail car and freight costs, partially offset by lower costs of transaction with affiliates of $0.2 million due to lower pet coke and hydrogen costs. Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $522.1 million for the year ended December 31, 2012, as compared to $334.1 million for the year ended December 31, 2011. The increase of $188.0 million was due primarily to increased petroleum segment expenses resulting from a full year of expenses at the Wynnewood refinery, including expenses for the turnaround in the fourth quarter of 2012. Other increases included insurance, catalyst and chemicals, and energy and utility costs. Our total increase included the higher direct operating expenses (exclusive of depreciation and amortization) by the nitrogen fertilizer business of $9.1 million. This increase was primarily the result of expenses related to the scheduled major turnaround during 2012. Insurance Recovery — Business Interruption. During the year ended December 31, 2011, we recorded and received business interruption proceeds of $3.4 million related to the September 30, 2010 UAN vessel rupture. No business interruption proceeds were received during the year ended December 31, 2012. Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $183.4 million for the year ended December 31, 2012, as compared to $98.0 million for the year ended December 31, 2011. This $85.4 million increase was primarily the result of higher payroll-related costs due to growth in staff, integration costs related to the Wynnewood Acquisition, overall higher costs associated with the Wynnewood Acquisition and costs incurred related to the tender offer and transaction agreement with certain entities affiliated with Carl Icahn. Operating Income. Consolidated operating income was $1,034.9 million for the year ended December 31, 2012, as compared to operating income of $566.6 million for the year ended December 31, 2011, an increase of $468.3 million. Petroleum segment operating income increased $546.8 million primarily as a result of an increase in refining margin, partially offset by an increase of direct operating expenses. Nitrogen fertilizer segment operating income decreased $20.4 million primarily as a result of the decrease in nitrogen fertilizer margin and the increase in costs related to the scheduled major turnaround in 2012. Interest Expense. Consolidated interest expense for the year ended December 31, 2012 was $75.4 million as compared to $55.8 million for the year ended December 31, 2011. This $19.6 million increase resulted primarily from higher interest cost due to the additional $200.0 million of First Lien Notes issued in December 2011 prior to their extinguishment in the fourth quarter of 2012, the $500.0 million of 2022 Notes issued in October 2012, along with increased amortization to interest expense for deferred financing costs and original issue discount associated with the Old Notes and 2022 Notes. 83 Gain (Loss) on Derivatives, Net. For the year ended December 31, 2012, we recorded a $285.6 million net loss on derivatives. This compares to a $78.1 million net gain on derivatives for the year ended December 31, 2011. The change in gain (loss) on derivatives was primarily attributable to the realized and unrealized losses on our commodity swaps in the petroleum segment. We entered into several over-the-counter commodity swaps to fix the margin on a portion of our future gasoline and distillate production beginning in the fourth quarter of 2011 and continuing throughout 2012. Loss on Extinguishment of Debt. For the year ended December 31, 2012, we incurred a $37.5 million loss on extinguishment of debt compared to $2.1 million for the year ended December 31, 2011. The increase in the loss on extinguishment of debt was primarily the result of the extinguishment of the First Lien Notes, which resulted in a loss of $31.6 million as a result of the write-off of previously deferred financing costs, unamortized original issuance premium as well as premiums paid to tender and redeem the First Lien Notes. The increase was also due to the write-off of deferred financing costs of $4.1 million associated with the amendment of the ABL credit facility in the fourth quarter of 2012. Income Tax Expense. Income tax expense for the year ended December 31, 2012, was $225.6 million or 35.3% of income before income taxes, as compared to an income tax expense for the year ended December 31, 2011 of $209.6 million or 35.6% of income before income taxes. This is in comparison to a combined federal and state expected statutory rate of 39.2% for 2012 and 39.4% for 2011. Our 2012 effective tax rate is lower than the expected statutory rate primarily due to benefits related to the domestic production activities deduction and the reduction of income subject to tax associated with our noncontrolling ownership interest in the Nitrogen Fertilizer Partnership. We also recognized a state income tax benefit net of federal expense of approximately $1.7 million in 2012 related to a reduction to our overall state effective tax rate and recognized state income tax credits, net of federal expense, of approximately $5.4 million. Net Income Attributable to Noncontrolling Interest. Net income attributable to noncontrolling interest represents the approximately 30% interest in the Nitrogen Fertilizer Partnership held by public unitholders. Net Income Attributable to CVR Stockholders. For the year ended December 31, 2012, net income attributable to CVR stockholders increased to $378.6 million as compared to net income of $345.8 million for the year ended December 31, 2011. Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010 (Consolidated) Net Sales. Consolidated net sales were $5,029.1 million for the year ended December 31, 2011 compared to $4,079.8 million for the year ended December 31, 2010. The increase of $949.3 million was primarily due to an increase in petroleum net sales of $848.0 million that resulted from higher product prices which were partially offset by lower overall sales volumes. Our average sales price per gallon for the year ended December 31, 2011 of $2.82 for gasoline and $3.03 for distillates increased by 33.9% and 38.0% respectively, as compared to the year ended December 31, 2010. Overall sales volumes of refined fuels and propane for the year ended December 31, 2011 decreased by 11.5% as compared to the year ended December 31, 2010. The lower overall sales volumes were primarily the result of the major maintenance turnaround at the Coffeyville refinery in the fall of 2011. Nitrogen fertilizer segment net sales increased by $122.4 million as the result of higher UAN sales volumes coupled with increased ammonia and UAN plant gate prices, partially offset by lower ammonia sales volumes. Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $3,943.5 million for the year ended December 31, 2011, as compared to $3,568.1 million for the year ended December 31, 2010. The increase of $375.4 million primarily resulted from a significant increase in crude oil prices. On a year-over-year 84 basis, our consumed crude oil prices increased approximately 21.0% from an average price of $76.13 per barrel in 2010 to an average price of $92.09 per barrel in 2011. The increase in crude oil prices was partially offset by an 8.5% decrease in crude oil throughput in 2011 compared to 2010. Our total increase included the increase in cost of product sold (exclusive of depreciation and amortization) by the nitrogen fertilizer business. This increase was primarily the result of higher costs of transactions with affiliates totaling $5.9 million and external parties totaling $2.3 million. These increased costs were partially offset by a decrease in costs associated with lower ammonia sales and a decrease in hydrogen costs. Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $334.1 million for the year ended December 31, 2011, as compared to $239.8 million for the year ended December 31, 2010. The increase of $94.3 million was due primarily to increased petroleum segment expenses for the turnaround, environmental compliance, repairs and maintenance and other expenses. Insurance Recovery — Business Interruption. During the year ended December 31, 2011, we recorded and received business interruption proceeds of $3.4 million related to the September 30, 2010 UAN vessel rupture. Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $98.0 million for the year ended December 31, 2011, as compared to $92.0 million for the year ended December 31, 2010. This $6.0 million increase was primarily the result of higher payroll-related costs due to growth in staff and integration costs related to the Wynnewood Acquisition, offset in part by lower share-based compensation expenses resulting from the change in the composition of our long-term incentive plans. Operating Income. Consolidated operating income was $566.6 million for the year ended December 31, 2011, as compared to operating income of $93.1 million for the year ended December 31, 2010, an increase of $473.5 million. Petroleum segment operating income increased $361.1 million primarily as a result of an increase in refining margin, partially offset by an increase of direct operating expenses. Nitrogen fertilizer segment operating income increased $115.8 million primarily as a result of the increase in nitrogen fertilizer margin. Interest Expense. Consolidated interest expense for the year ended December 31, 2011 was $55.8 million as compared to $50.3 million for the year ended December 31, 2010. This $5.5 million increase resulted primarily from higher interest cost by having a full year of interest on the $500.0 million of Old Notes issued in April 2010 along with increased amortization to interest expense for deferred financing costs and original issue discount associated with the Old Notes. Gain (Loss) on Derivatives, Net. For the year ended December 31, 2011, we recorded a $78.1 million net gain on derivatives. This compares to a $1.5 million net loss on derivatives for the year ended December 31, 2010. The change in gain (loss) on derivatives was primarily attributable to the realized and unrealized gains on our commodity swaps in the Petroleum segment. Loss on Extinguishment of Debt. For the year ended December 31, 2011, we incurred a $2.1 million loss on extinguishment of debt compared to $16.6 million for the year ended December 31, 2010. The decrease in the loss on the extinguishment of debt was primarily the result of a 2.0% premium paid in connection with unscheduled prepayments and payoff of our tranche D term loan in 2010, which contributed $9.6 million of the loss on extinguishment. Additionally, $5.4 million of the loss on extinguishment of debt was attributable to the write-off of previously deferred financing costs associated with the payoff of the tranche D term loan. Concurrent with the issuance of the Old Notes, $0.1 million of third-party costs were immediately expensed. In December 2010, we made a voluntary unscheduled principal payment on our Old Notes resulting in a premium payment of 3.0% and a 85 partial write-off of previously deferred financing costs and unamortized original issue discount totaling $1.6 million. Income Tax Expense. Income tax expense for the year ended December 31, 2011, was $209.6 million or 35.6% of income before income taxes, as compared to an income tax expense for the year ended December 31, 2010 of $13.8 million or 49.1% of income before income taxes. This is in comparison to a combined federal and state expected statutory rate of 39.4% for 2011 and 39.7% for 2010. Our effective tax rate decreased primarily due to a reduction in non-deductible share-based compensation expense in conjunction with higher pre-tax income, as well as the reduction of income subject to tax associated with our noncontrolling ownership interest in CVR Partners beginning April 13, 2011. We also recognized a state income tax benefit net of federal expense, of approximately $2.8 million in 2011 related to a reduction to our overall state effective tax rate. In addition, state income tax credits, net of federal expense, approximating $3.2 million were earned and recorded in 2011 that related to Kansas HPIP credits, compared to $2.4 million earned and recorded in 2010. Net Income Attributable to Noncontrolling Interest. Net income attributable to noncontrolling interest represents the approximately 30% interest in the Nitrogen Fertilizer Partnership held by public unitholders. Net Income Attributable to CVR Stockholders. For the year ended December 31, 2011, net income attributable to CVR stockholders increased to $345.8 million, as compared to net income of $14.3 million for the year ended December 31, 2010. Petroleum Business Results of Operations The petroleum business includes the operations of both the Coffeyville and Wynnewood refineries. The Wynnewood results are included from the post-acquisition period beginning on December 16, 2011. Refining margin 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 (exclusive of depreciation and amortization) that we are 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) can be taken directly from the petroleum business’ Statement of Operations. The petroleum business’ calculation of refining margin may differ from similar calculations of other companies in its industry, thereby limiting its usefulness as a comparative measure. The following table shows selected information about the petroleum business including refining margin: Consolidated Petroleum Business Financial Results Year Ended December 31, 2012 2011 2010 Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of product sold(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses(1)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Major scheduled turnaround expenses . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $8,281.5 6,667.3 302.8 123.7 107.6 (in millions) $4,751.8 3,926.6 181.3 66.4 69.9 $3,903.8 3,538.0 151.9 1.2 66.4 Gross profit(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,080.1 $ 507.6 $ 146.3 Plus direct operating expenses and major scheduled turnaround expenses(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Plus depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . 426.5 107.6 247.7 69.9 153.1 66.4 Refining margin(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjusted Petroleum EBITDA(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,614.2 $1,012.5 $1,178.9 $ 825.2 $ 465.7 $ 580.9 $ 365.8 $ 104.6 $ 154.7 86 Key Operating Statistics Per crude oil throughput barrel: Year Ended December 31, 2012 2011 2010 (dollars per barrel) Refining margin(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses and major scheduled turnaround $ 26.04 17.42 $ 21.80 13.41 $ expenses (1)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.88 6.54 8.84 3.54 3.70 Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Barrels sold (barrels per day)(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.26 186,035 6.38 106,397 3.30 127,142 Year Ended December 31, 2012 2011 2010 Refining Throughput and Production Data (bpd) Throughput: Sweet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Medium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Heavy sour . . . . . . . . . . . . . . . . . . . . . . . . . . Total crude oil throughput . . . . . . . . . . . . . . Feedstocks and blendstocks . . . . . . . . . . . . . . . 130,414 21,334 17,608 169,356 10,791 % 72.4 11.8 9.8 94.0 6.0 83,538 1,704 18,460 103,702 5,231 % 76.7 1.6 16.9 95.2 4.8 89,746 8,180 15,439 113,365 10,350 % 72.5 6.6 12.5 91.6 8.4 Total throughput . . . . . . . . . . . . . . . . . . . . . 180,147 100.0 108,933 100.0 123,715 100.0 Production: Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distillate . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other (excluding internally produced fuel) . . . . 89,787 72,804 17,262 49.9 40.6 9.5 48,486 45,535 15,385 44.3 41.6 14.1 61,136 50,439 12,978 49.1 40.5 10.4 Total refining production (excluding internally produced fuel) . . . . . . . . . . . . . 179,853 100.0 109,406 100.0 124,553 100.0 Average product sale price (dollars per gallon): Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distillate . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2.86 $3.08 $2.82 $3.03 $2.10 $2.20 Market Indicators (dollars per barrel) West Texas Intermediate (WTI) NYMEX . . . . . . . . . . . . . . . . . . . . . . . . . . Crude Oil Differentials: WTI less WTS (light/medium sour) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . WTI less WCS (heavy sour) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NYMEX Crack Spreads: Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Heating Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NYMEX 2-1-1 Crack Spread . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PADD II Group 3 Basis: Year Ended December 31, 2012 2011 2010 $94.15 $95.11 $79.61 5.40 22.53 28.55 32.94 30.75 2.06 16.54 23.54 29.12 26.33 2.15 15.07 9.62 10.53 10.07 Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ultra-Low Sulfur Diesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3.11) 2.17 (1.09) 1.98 (1.49) 1.35 PADD II Group 3 Product Crack Spread: Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ultra-Low Sulfur Diesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PADD II Group 3 2-1-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.45 35.11 30.28 22.44 31.10 26.77 8.13 11.88 10.01 (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 the total direct 87 operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period. (3) In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period. (4) Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating the refineries’ performance as a general indication of the amount above the cost of product sold that it is able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from the petroleum business’ Statements of Operations. The petroleum business’ calculation of refining margin may differ from similar calculations of other companies in its industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate our ongoing operating results and for greater transparency in the review of our overall business, financial, operational and economic financial performance. (5) Adjusted Petroleum EBITDA represents operating income for the petroleum segment adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, major scheduled turnaround expenses, realized gain (loss) on derivatives, net, loss on disposition of fixed assets, depreciation and amortization and other income (expense). Adjusted Petroleum EBITDA is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance but should be utilized as a supplemental measure of performance in evaluating our business. Management believes that Adjusted Petroleum EBITDA provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in the reviewing of our overall financial, operational and economic performance. Below is a reconciliation of operating income for the petroleum segment to Adjusted Petroleum EBITDA for the years ended December 31, 2012, 2011 and 2010: Petroleum: Petroleum operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIFO impacts (favorable), unfavorable(a) . . . . . . . . . . . . . . . . Share-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . Major scheduled turnaround expenses(b) . . . . . . . . . . . . . . . . . Realized gain (loss) on derivatives, net . . . . . . . . . . . . . . . . . . Loss on disposition of assets(c) . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . Other income (expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2012 2011 2010 (unaudited) $1,012.5 58.4 13.5 123.7 (137.6) — 107.6 0.8 $465.7 (25.6) 8.7 66.4 (7.2) 2.5 69.9 0.5 $104.6 (31.7) 11.5 1.2 0.7 1.3 66.4 0.7 Adjusted Petroleum EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,178.9 $580.9 $154.7 (a) FIFO is the petroleum business’ basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the FIFO impact per crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period. 88 (b) Represents expense associated with a major scheduled turnaround at the Coffeyville refinery in 2011 and Wynnewood refinery in 2012. (c) During the second quarter of 2010, the Company wrote-off an amount associated with a capital project. During the second quarter of 2011, the Company wrote-off an amount associated with the closure of the Phillipsburg terminal. (6) Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize direct operating expenses, which does not include depreciation or amortization expense, and divide the applicable number of barrels sold for the period to derive the metric. Coffeyville Refinery Financial Results Year Ended December 31, 2012 2011 2010 Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of product sold (exclusive of depreciation and amortization) . . . . . Direct operating expenses (exclusive of depreciation and amortization) . Major scheduled turnaround expense . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5,632.9 4,506.5 189.1 21.2 69.6 (in millions) $4,643.9 3,823.5 177.1 66.4 66.0 $3,901.5 3,538.4 151.9 1.2 63.6 Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Plus direct operating expenses and major scheduled turnaround $ 846.5 $ 510.9 $ 146.4 expenses (exclusive of depreciation and amortization) . . . . . . . . . . . . Plus depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . 210.3 69.6 243.5 66.0 153.1 63.6 Refining margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,126.4 $ 820.4 $ 363.1 Year Ended December 31, 2012 2011 2010 (dollars per barrel) Coffeyville Refinery Key Operating Statistics Per crude oil throughput barrel: Refining margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses and major scheduled turnaround $ 26.81 20.15 $ 22.34 13.91 $ expenses (exclusive of depreciation and amortization) . . . . . . . . . 5.01 6.63 8.78 3.54 3.70 Direct operating expenses and major scheduled turnaround expenses per barrel sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Barrels sold (barrels per day) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.52 127,122 6.45 103,430 3.30 127,142 89 Year Ended December 31, 2012 % 2011 % 2010 % Coffeyville Refinery Throughput and Production Data (bpd) Throughput: Sweet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Medium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Heavy sour . . . . . . . . . . . . . . . . . . . . . . . . . . 91,580 5,601 17,608 Total crude oil throughput . . . . . . . . . . . . . . Feedstocks and blendstocks . . . . . . . . . . . . . . . 114,789 8,412 74.3 4.6 14.3 93.2 6.8 80,835 1,323 18,460 100,618 4,921 76.5 1.3 17.5 95.3 4.7 89,746 8,180 15,439 113,365 10,350 72.5 6.6 12.5 91.6 8.4 Total throughput . . . . . . . . . . . . . . . . . . . . . 123,201 100.0 105,539 100.0 123,715 100.0 Production: Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distillate . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other (excluding internally produced fuel) . . . . 61,998 52,429 10,629 49.6 41.9 8.5 46,707 44,414 15,000 44.0 41.9 14.1 61,136 50,439 12,978 49.1 40.5 10.4 Total refining production (excluding internally produced fuel) . . . . . . . . . . . . . 125,056 100.0 106,121 100.0 124,553 100.0 Year Ended December 31, 2012 (in millions) Wynnewood Refinery Financial Results Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of product sold (exclusive of depreciation and amortization) . . . . . . . . . . . . . . . Direct operating expenses (exclusive of depreciation and amortization) . . . . . . . . . . . Major scheduled turnaround expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Plus direct operating expenses (exclusive of depreciation and amortization) and major scheduled turnaround expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Plus depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,647.1 2,160.9 113.7 102.5 34.5 $ 235.5 216.2 34.5 Refining margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 486.2 Wynnewood Refinery Key Operating Statistics Per crude oil throughput barrel: Refining margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses (exclusive of depreciation and amortization) and major scheduled turnaround expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses and major scheduled turnaround expenses per barrel sold . Barrels sold (barrels per day) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 24.34 11.79 10.83 9.76 60,496 Year Ended December 31, 2012 (dollars per barrel) 90 Year Ended December 31, 2012 Wynnewood Refinery Throughput and Production Data (bpd) Throughput: Sweet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Medium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Heavy sour . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total crude oil throughput . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Feedstocks and blendstocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,834 15,733 — 54,567 2,379 % 68.2 27.6 — 95.8 4.2 Total throughput . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56,946 100.0 Production: Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distillate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other (excluding internally produced fuel) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27,789 20,375 6,633 50.6 37.2 12.2 Total refining production (excluding internally produced fuel) . . . . . . . . . . . . . 54,797 100.0 Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011(Petroleum Business) Net Sales. Petroleum net sales were $8,281.5 million for the year ended December 31, 2012 compared to $4,751.8 million for the year ended December 31, 2011. The increase of $3,529.7 million was the result of significantly higher overall sales volume and higher product prices. The higher sales volume is due to the inclusion of a full year of sales for the Wynnewood refinery for the year ended December 31, 2012. The average sales price per gallon for the year ended December 31, 2012 for gasoline of $2.86 and distillate of $3.08 increased by approximately 1.5% and 1.8%, respectively, as compared to the year ended December 31, 2011. Year Ended December 31, 2012 Year Ended December 31, 2011 Total Variance Volume(1) $ per barrel Sales $(2) Volume(1) $ per barrel Sales $(2) Volume(1) Sales $(2) Variance Variance Volume Price Gasoline . . Distillate . . 35.6 27.5 $120.14 $4,283.1 $129.51 $3,563.9 19.7 16.6 $118.38 $2,337.7 $127.27 $2,115.3 15.9 10.9 $1,945.4 $1,882.3 $63.1 $1,448.6 $1,387.1 $61.5 (in millions) (1) Barrels in millions (2) Sales dollars in millions Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $6,667.3 million for the year ended December 31, 2012 compared to $3,926.6 million for the year ended December 31, 2011. The increase of $2,740.7 million was primarily the result of an increase in crude oil throughputs. The increase in crude oil throughputs is due to the inclusion of a full year of consumption at the Wynnewood refinery. Sales volume of refined fuels increased by approximately 75.9%. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under the FIFO accounting method, 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 inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the year ended December 31, 91 2012, the petroleum business had an unfavorable FIFO inventory impact of $58.4 million compared to a favorable FIFO inventory impact of $25.6 million for the year ended December 31, 2011. Refining margin per barrel of crude oil throughput increased from $21.80 for the year ended December 31, 2011 to $26.04 for the year ended December 31, 2012. Refining margin adjusted for FIFO impact was $26.98 per crude oil throughput barrel for the year ended December 31, 2012, as compared to $21.12 per crude oil throughput barrel for the year ended December 31, 2011. Gross profit per barrel increased to $17.42 for the year ended December 31, 2012 as compared to gross profit per barrel of $13.41 in the equivalent period in 2011. The increase in the petroleum business’ refining margin per barrel is due to an increase in the average sales prices of its produced gasoline and distillates and a decrease in its cost of consumed crude oil. The petroleum business’ average sales price of gasoline increased approximately 1.5% and its average sales price for distillates increased approximately 1.8% for the year ended December 31, 2012 over the comparable period of 2011. Consumed crude oil costs decreased due primarily to a 1.0% decrease in WTI for the year ended December 31, 2012 over the year ended December 31, 2011. 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 (exclusive of depreciation and amortization) plus major scheduled turnaround expenses were $426.5 million for the year ended December 31, 2012 compared to direct operating expenses plus major scheduled turnaround expenses of $247.7 million for the year ended December 31, 2011. The increase of $178.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011 was the result of a full year of expenses for the Wynnewood refinery ($212.0 million), which was partially offset by a decrease at the Coffeyville refinery of $33.2 million. The $212.0 million of expense at the Wynnewood refinery included $102.5 million for major schedule turnaround expense. The decrease at the Coffeyville refinery is primarily related to decreases in turnaround expense ($45.2 million), environmental compliance ($3.0 million), and flood related costs ($2.4 million). Decreases in direct operating expenses at the Coffeyville refinery were partially offset by increases related to insurance ($4.1 million), catalyst and chemicals ($4.2 million), energy and utility costs ($4.6 million), labor ($2.5 million) operating supplies ($1.2 million) and other operating expenses ($0.9 million). Direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2012 increased to $6.88 per barrel as compared to $6.54 per barrel for the year ended December 31, 2011. Operating Income. Petroleum operating income was $1,012.5 million for the year ended December 31, 2012 as compared to operating income of $465.7 million for the year ended December 31, 2011. This increase of $546.8 million was the result of an increase in the refining margin ($789.0 million) and the inclusion of a full year of refining margin related to Wynnewood. The increase in refining margin was partially offset by an increase in direct operating expenses ($178.8 million), an increase in depreciation and amortization ($37.7 million) and an increase in selling, general and administrative expenses ($25.7 million). The increase in depreciation and amortization was primarily the result of a full year of expense for the Wynnewood refinery. Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010 (Petroleum Business) Net Sales. Petroleum net sales were $4,751.8 million for the year ended December 31, 2011, compared to $3,903.8 million for the year ended December 31, 2010. The increase of $848.0 million was primarily the result of higher product prices which were partially offset by lower overall sales volumes. Overall sales volumes of refined fuels and propane decreased 11.5%. The lower overall sales volumes were primarily the result of the major maintenance turnaround at the Coffeyville refinery in 92 the fall of 2011. The petroleum business’ average sales price per gallon of $2.82 for gasoline and $3.03 for distillates increased by 33.9% and 38.0% respectively. Year Ended December 31, 2011 Year Ended December 31, 2010 Total Variance Volume(1) $ per barrel Sales $(2) Volume(1) $ per barrel Sales $(2) Volume(1) Sales $(2) Variance Variance Volume Price Gasoline . . . . Distillate . . . . 19.7 16.6 $118.37 $2,337.7 $127.27 $2,115.3 23.1 18.6 $88.38 $2,038.2 $92.22 $1,718.3 (3.4) (2.0) $299.5 $(292.7) $592.2 $397.0 $(185.6) $582.6 (in millions) (1) Barrels in millions (2) Sales dollars in millions Cost of Products Sold (Exclusive of Depreciation and Amortization). Cost of products sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of products sold (exclusive of depreciation and amortization) was $3,926.6 million for the year ended December 31, 2011, compared to $3,538.0 million for the year ended December 31, 2010. The increase of $388.6 million was primarily the result of a significant increase in crude oil prices. The petroleum business’ average cost per barrel of crude oil consumed for the year ended December 31, 2011 was $92.09, compared to $76.13 for the year ended December 31, 2010, an increase of approximately 21.0%. Partially offsetting the rise in crude oil consumed cost was the decrease of sales of refined fuels by approximately 11.5%. In addition, under the FIFO accounting method, 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. For the year ended December 31, 2011, we had a favorable FIFO impact of $25.6 million compared to a favorable FIFO impact of $31.7 million for the year ended December 31, 2010. Refining margin per barrel of crude oil throughput increased from $8.84 for the year ended December 31, 2010 to $21.80 for the year ended December 31, 2011. Refining margin adjusted for FIFO impact was $21.12 per barrel of crude oil throughput for the year ended December 31, 2011, as compared to $8.07 per crude oil throughput barrel for the year ended December 31, 2010. Gross profit per barrel increased to $13.41 for the year ended December 31, 2011, as compared to gross profit per barrel of $3.54 in the equivalent period in 2010. The increase in the petroleum business’ refining margin per barrel is due to an increase in the average sales prices of its produced gasoline and distillates, partially offset by an increase in its cost of consumed crude oil. The petroleum business’ average sales price for gasoline increased approximately 33.9% and its average sales price for distillates increased approximately 38.0%. Consumed crude oil costs rose due to a 19.5% increase in WTI for the year ended December 31, 2011 over the year ended December 31, 2010. Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the petroleum operations include costs associated with the actual operations of the refineries, such as energy and utility costs, property taxes, catalyst and chemicals, repairs and maintenance, turnaround maintenance, labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were $247.7 million for the year ended December 31, 2011, compared to direct operating expenses of $153.1 million for the year ended December 31, 2010. The increase of $94.6 million was the result of increases in expenses primarily related with turnaround maintenance ($65.2 million), environmental compliance ($7.8 million), repairs and maintenance ($6.4 million), labor ($6.2 million), outside services ($2.5 million), catalyst and chemicals ($2.4 million), operating supplies ($2.2 million), rent ($1.3 million) and other direct operating expenses ($0.6 million). On a per barrel of crude oil throughput basis, direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2011 increased to $6.54 per barrel as compared to $3.70 per barrel for the year ended December 31, 2010, principally due to the net dollar increase in expenses from year to year as detailed above. 93 Operating Income. Petroleum operating income was $465.7 million for the year ended December 31, 2011 as compared to operating income of $104.6 million for the year ended December 31, 2010. This increase of $361.1 million was primarily the result of an increase in refining margin ($459.4 million). The increase in refining margin was partially offset by an increase in direct operating expenses ($94.6 million), an increase in depreciation and amortization ($3.5 million) and an increase in selling, general and administrative expense ($0.2 million). Nitrogen Fertilizer Business Results of Operations The tables below provide an overview of the nitrogen fertilizer business’ results of operations, relevant market indicators and its key operating statistics during the past three years: Nitrogen Fertilizer Business Financial Results Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of product sold(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Major scheduled turnaround expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance recovery — business interruption . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjusted Nitrogen Fertilizer EBITDA(2) . . . . . . . . . . . . . . . . . . . . . . . . . . Key Operating Statistics Production (thousand tons): Ammonia (gross produced)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ammonia (net available for sale)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . UAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pet coke consumed (thousand tons) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pet coke (cost per ton) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales (thousand tons)(4): Ammonia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . UAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Product pricing (plant gate) (dollars per ton)(3): Year Ended December 31, 2012 2011 2010 (in millions) $302.9 42.5 86.5 — (3.4) 22.2 18.9 136.2 162.6 $302.3 46.1 90.8 4.8 — 24.1 20.7 115.8 148.2 $180.5 34.3 83.2 3.5 — 20.6 18.5 20.4 52.6 Year Ended December 31, 2012 2011 2010 390.0 124.6 643.8 487.3 33 $ 127.8 643.5 771.3 411.2 116.8 714.1 517.3 33 $ 112.8 709.3 822.1 392.7 155.6 578.3 436.3 17 $ 164.7 580.7 745.4 Ammonia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . UAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 613 $ 303 $ 579 $ 284 $ 361 $ 179 On-stream factor(5): Gasification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ammonia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . UAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92.6% 99.0% 89.0% 91.1% 97.7% 87.7% 86.4% 95.5% 80.8% Reconciliation to net sales (dollars in millions): Sales net plate gate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Freight in revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hydrogen revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $273.5 22.4 6.4 $266.6 22.1 14.2 $163.4 17.0 0.1 Total net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $302.3 $302.9 $180.5 94 Market Indicators Natural gas NYMEX (dollars per MMBtu) . . . . . . . . . . . . . . . . . . . . . . . Ammonia — Southern Plains (dollars per ton) . . . . . . . . . . . . . . . . . . . . . UAN — Mid Cornbelt (dollars per ton) . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2012 $2.83 $ 647 $ 369 2011 $4.03 $ 619 $ 379 2010 $4.38 $ 437 $ 266 (1) Amounts are shown exclusive of depreciation and amortization. (2) Adjusted Nitrogen Fertilizer EBITDA represents operating income adjusted for share-based compensation, major scheduled turnaround expenses, depreciation and amortization and other income (expense). We present Adjusted Nitrogen Fertilizer EBITDA because it is a key measure used in material covenants in the Partnership’s credit facility. Adjusted Nitrogen Fertilizer EBITDA is not a recognized term under GAAP and should not be substituted for operating income or net income as a measure of liquidity. Management believes that Adjusted EBITDA provides relevant and useful information that enables investors to better understand and evaluate our liquidity and our compliance with the covenants contained in the Partnership’s credit facility. Below is a reconciliation of operating income to Adjusted EBITDA for the nitrogen fertilizer segment for the years ended December 31, 2012, 2011 and 2010: Nitrogen Fertilizer: Nitrogen fertilizer operating income . . . . . . . . . . . . . . . . . . . . . . Share-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on disposition of assets(a) . . . . . . . . . . . . . . . . . . . . . . . . Major scheduled turnaround expenses(b) . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . Other income (expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2012 2011 2010 (unaudited) $115.8 6.8 — 4.8 20.7 0.1 $136.2 7.3 — — 18.9 0.2 $20.4 9.0 1.4 3.5 18.5 (0.2) Adjusted Nitrogen Fertilizer EBITDA . . . . . . . . . . . . . . . . . . . . $148.2 $162.6 $52.6 (a) During the fourth quarter of 2010, the Company wrote-off approximately $1.4 million of assets in connection with the biennial major scheduled turnaround completed by the nitrogen fertilizer business. (b) Represents expense associated with a major scheduled turnaround at the nitrogen fertilizer plant. (3) The gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. The net tons available for sale represent the ammonia available for sale that was not upgraded into UAN. (4) Plant gate sales per ton represent net sales less freight costs and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry. (5) On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period and is included as a measure of operating efficiency. Excluding the impact of the major scheduled turnaround, the Linde air separation unit outage and the UAN vessel rupture, (i) the on-stream factors in 2012 adjusted for the major scheduled turnaround and the Linde air separation unit outage would have been 98.1% for gasifier, 97.1% for ammonia and 92.8% for UAN, (ii) the on-stream factors in 2011 adjusted for these events would have been 99.2% for gasifier, 98.0% for ammonia and 95.7% for UAN and (iii) the on-stream factors in 2010 adjusted 95 for the Linde air separation unit outage and the UAN vessel rupture would have been 97.6% for gasifier, 96.8% for ammonia and 96.1% for UAN. Year Ended December 31, 2012 compared to the Year Ended December 31, 2011 (Nitrogen Fertilizer Business) Net Sales. Nitrogen fertilizer net sales were $302.3 million for the year ended December 31, 2012, compared to $302.9 million for the year ended December 31, 2011. For the year ended December 31, 2012, ammonia, UAN and hydrogen made up $80.8 million, $215.1 million and $6.4 million of the nitrogen fertilizer business’ net sales, respectively. This compared to ammonia, UAN and hydrogen net sales of $67.2 million, $221.5 million and $14.2 million for the year ended December 31, 2011, respectively. Sales of both UAN and ammonia for the year ended December 31, 2012 were negatively impacted by the downtime associated with the major scheduled turnaround during 2012. The net sales decrease of $0.6 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011 was the result of lower UAN and hydrogen sales volumes. This decrease was largely offset by increased ammonia and UAN plant gate prices and higher ammonia sales volumes. The following table demonstrates the impact of changes in sales volumes and sales price for ammonia, UAN and hydrogen for the year ended December 31, 2012 compared to the year ended December 31, 2011. Year Ended December 31, 2012 Year Ended December 31, 2011 Volume Volume(1) $ per ton(2) Sales $(3) Volume(1) $ per ton(2) Sales $(3) Volume(1) Sales $(3) Variance Variance Price Total Variance Ammonia . . . 127,843 UAN . . . . . . 643,514 Hydrogen . . . 624,242 $632 $334 $ 10 $ 80.8 $215.1 $ 112,775 709,280 6.4 1,389,796 (in millions) $596 $312 $ 10 $13.6 15,068 $ 67.2 (65,766) $ (6.4) $221.5 $ 14.2 (765,554) $ (7.8) $ 9.0 $ 4.6 $(20.6) $14.2 $ (0.1) $ (7.7) (1) Ammonia and UAN sales volumes are in tons. Hydrogen sales volumes are in MSCF. (2) Includes freight charges. (3) Sales dollars in millions. In regard to product sales volumes for the year ended December 31, 2012, the nitrogen fertilizer operations experienced a decrease of 9.3% in UAN sales unit volumes and an increase of 13.4% in ammonia sales unit volumes. On-stream factors (total number of hours operated divided by total hours in the reporting period) for 2012 compared to 2011 were lower for all units of the nitrogen fertilizer operations, primarily due to the major scheduled turnaround in 2012. It is typical to experience brief outages in complex manufacturing operations such as the nitrogen fertilizer plant which result in less than one hundred percent on-stream availability for one or more specific units. Plant gate prices are prices at the designated delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful measure because we sell products both at our plant gate (sold plant) and delivered to the customer’s designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or year to year. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices for ammonia increased approximately 6.0% for the year ended December 31, 2012 as compared to the year ended December 31, 2011 and plant gate prices for UAN increased approximately 6.8% for the year ended December 31, 2012 as compared to the year ended December 31, 2011. Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the year ended December 31, 2012 was $46.1 million, compared to $42.5 million for the year ended December 31, 2011. The $3.6 million increase resulted from a $3.8 million in higher cost from transactions with third parties offset by lower costs from transactions with affiliates of $0.2 million. Increased costs were also 96 the result of higher ammonia sales volumes, an increase in rail car cost of $1.2 million and higher freight costs of $0.3 million. These costs were partially offset by lower pet coke costs of $0.6 million and lower hydrogen costs of $0.8 million. Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer plant, such as repairs and maintenance, energy and utility costs, property taxes, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2012 were $95.6 million, as compared to $86.5 million for the year ended December 31, 2011. The total increase of $9.1 million for the year ended December 31, 2012, as compared to the year ended December 31, 2011, was comprised of a $8.0 million increase in costs from transactions with third parties, coupled with $1.1 million increased direct operating costs from affiliates. The $9.1 million net increase was primarily due to increases in expenses associated with the 2012 biennial turnaround ($4.8 million), labor ($2.6 million), utilities ($1.6 million), insurance ($1.0 million) and decreased insurance reimbursements ($1.5 million). The increases in direct operating expenses were partially offset by decreases in repairs and maintenance ($1.2 million) and catalysts ($1.0 million). Insurance Recovery — Business Interruption. During the year ended December 31, 2011, we recorded and received insurance proceeds under insurance coverage for interruption of business of $3.4 million related to the September 30, 2010 UAN vessel rupture. No business interruption proceeds were received during the year ended December 31, 2012 Operating Income. Nitrogen fertilizer operating income was $115.8 million for the year ended December 31, 2012, as compared to operating income of $136.2 million for the year ended December 31, 2011. The decrease of $20.4 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011 was primarily the result of the decrease in nitrogen fertilizer margins ($4.2 million), increased direct operating costs ($9.1 million), both of which were negatively impacted by the major scheduled turnaround in 2012. Additional decreases in operating income were due to business interruption recoveries in 2011 ($3.4 million), higher depreciation and amortization ($1.8 million) and increased selling, general and administrative expenses (exclusive of depreciation and amortization) ($1.9 million). Year Ended December 31, 2011 compared to the Year Ended December 31, 2010 (Nitrogen Fertilizer Business) Net Sales. Nitrogen fertilizer net sales were $302.9 million for the year ended December 31, 2011, compared to $180.5 million for the year ended December 31, 2010, an increase of $122.4 million. For the year ended December 31, 2011, ammonia, UAN and hydrogen made up $67.2 million, $221.5 million and $14.2 million of the nitrogen fertilizer business’ net sales, respectively. This compared to ammonia, UAN and hydrogen net sales of $63.0 million, $117.4 million and $0.1 million for the year ended December 31, 2010, respectively. The increase of $122.4 million was the result of higher UAN sales volumes coupled with increased ammonia and UAN plant gate prices. This increase was partially offset by lower ammonia sales volumes. Both UAN and ammonia sales for the year ended December 31, 2010 were negatively impacted by the downtime associated with the major scheduled turnaround; however, UAN production and sales were impacted additionally by the downtime 97 associated with the September 30, 2010 rupture of a high-pressure UAN vessel. The following table demonstrates the impact of changes in sales volumes and sales price for ammonia, UAN and hydrogen. Year Ended December 31, 2011 Year Ended December 31, 2010 Volume Volume(1) $ per ton(2) Sales $(3) Volume(1) $ per ton(2) Sales $(3) Volume(1) Sales $(3) Variance Variance Price Total Variance 112,775 Ammonia . . UAN . . . . . 709,280 Hydrogen . . 1,389,796 $596 $312 $ 10 $ 67.2 $221.5 $ 14.2 164,668 580,684 20,583 (in millions) $382 $202 7 $ $ 63.0 $117.4 $ (51,894) $ 4.2 128,595 $104.1 0.1 1,369,213 $ 14.1 $35.2 $63.9 $ 0.1 $(31.0) $ 40.2 $ 14.0 (1) Ammonia and UAN sales volumes are in tons. Hydrogen sales volumes are in MSCF. (2) Includes freight charges. (3) Sales dollars in millions. In regard to product sales volumes for the year ended December 31, 2011, the nitrogen fertilizer operations experienced a decrease of 31.5% in ammonia sales unit volumes and an increase of 22.1% in UAN sales unit volumes. On-stream factors (total number of hours operated divided by total hours in the reporting period) for 2011 compared to 2010 were higher for all units of the nitrogen fertilizer operations, primarily due to the 2010 major scheduled turnaround, the rupture of a high pressure UAN vessel and unscheduled downtime associated with the Linde air separation unit outage. It is typical to experience brief outages in complex manufacturing operations such as the nitrogen fertilizer plant which result in less than one hundred percent on-stream availability for one or more specific units. Plant gate prices are prices at the designated delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both at our plant gate (sold plant) and delivered to the customer’s designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or year to year. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices for the year ended December 31, 2011 for ammonia were higher than plant gate prices for the year ended December 31, 2010 by approximately 60.3% and plant gate prices for UAN were approximately 58.6% higher during the year ended December 31, 2011 than the plant gate prices for the year ended December 31, 2010. Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the year ended December 31, 2011 was $42.5 million, compared to $34.3 million for the year ended December 31, 2010. Of this $8.2 million increase, $5.9 million resulted from higher costs from transactions with affiliates and $2.3 million from higher costs from third parties. Besides increased costs associated with higher UAN sales volumes and $4.8 million of increased freight expenses, we experienced an increase in pet coke costs of $9.5 million ($6.7 million from transactions with affiliates). These increased costs were partially offset by a decrease in costs associated with lower ammonia sales and a decrease in hydrogen costs ($0.8 million). Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer plant, such as repairs and maintenance, energy and utility costs, property taxes, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2011 were $86.5 million, as compared to $86.7 million for the year ended December 31, 2010. The decrease of $0.2 million was due to a $1.1 million decrease in costs from transactions with affiliates, coupled with a $0.9 million increase in direct operating costs from third parties. The $0.2 million net decrease was primarily the result of 98 decreases in expenses associated with the turnaround ($3.5 million), net UAN reactor repairs and maintenance expense ($3.4 million), equipment rent ($0.5 million), labor ($0.4 million) and increased reimbursed expenses ($1.5 million). The turnaround expenses for 2010 are the result of the nitrogen fertilizers business’ biennial turnaround. These decreases in direct operating expenses were partially offset by increases in expenses associated with energy and utilities ($5.4 million), repairs and maintenance ($3.1 million), catalyst ($0.3 million) and environmental ($0.3 million). Insurance Recovery — Business Interruption. During the year ended December 31, 2011, we recorded and received insurance proceeds under insurance coverage for interruption of business of $3.4 million related to the September 30, 2010 UAN vessel rupture Operating Income. Nitrogen fertilizer operating income was $136.2 million for the year ended December 31, 2011, as compared to operating income of $20.4 million for the year ended December 31, 2010. The increase of $115.8 million was the result of the increase in nitrogen fertilizer margins ($114.3 million) coupled with business interruption recoveries recorded ($3.4 million) and decreased direct operating costs ($0.2 million). These favorable increases were partially offset by an increase in selling, general and administrative expenses (exclusive of depreciation and amortization) ($1.6 million) and depreciation and amortization ($0.4 million). 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. Since the Nitrogen Fertilizer Partnership’s IPO in April 2011, with the exception of cash distributions paid to us by the Nitrogen Fertilizer Partnership, the cash needs of the Nitrogen Fertilizer Partnership have been met independently from the cash needs of CVR Energy and the refining business with a combination of existing cash and cash equivalent balances, cash generated from operating activities and credit facility borrowings. Prior to December 31, 2012, CVR Energy provided cash as needed to support the Refining Partnership’s operations. As of December 31, 2012, CVR Energy and the Refining Partnership also operate with independent capital structures. The Refining Partnership’s and the Nitrogen Fertilizer Partnerships’ 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 existing credit facilities as necessary, will be sufficient to satisfy the anticipated cash requirements associated with their existing operations for at least the next twelve months, and that we have sufficient cash resources to fund our operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, the ability to generate sufficient cash from operating activities depends on future performance, which is subject to general economic, political, financial, competitive, and other factors. Cash Balances and Other Liquidity As of December 31, 2012, we had consolidated cash and cash equivalents of $896.0 million. Of that amount, $615.1 million was cash and cash equivalents of CVR Energy, $153.1 million was cash and cash equivalents of the Refining Partnership and $127.8 million was cash and cash equivalents of the Nitrogen Fertilizer Partnership. During 2012, our consolidated cash position increased approximately $507.6 million primarily as a result of increased operating and financing cash flows at the petroleum 99 business. As of March 11, 2013, we had consolidated cash and cash equivalents of approximately $1,054.1 million. 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 11, 2013, the Refining Partnership had $372.1 million available under the Amended and Restated ABL Credit Facility. The Nitrogen Fertilizer Partnership credit facility includes 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 credit facility matures in April 2016. The Nitrogen Fertilizer Partnership credit facility is used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF. As of March 11, 2013, the Nitrogen Fertilizer Partnership had $25.0 million available under the credit facility. The Refining Partnership and Nitrogen Fertilizer Partnership have a distribution policy in which they will generally distribute all of their available cash each quarter, within 60 days after the end of each quarter for the Refining Partnership and 45 days after the end of each quarter for the Nitrogen Fertilizer Partnership. The Refining Partnership’s distribution will begin with the quarter ending March 31, 2013 and will include available cash generated from the date of the Refining Partnership IPO (January 23, 2013) through March 31, 2013. The distributions will be made to all common unitholders. We currently hold approximately 81% and 70% 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 will receive our applicable percentage of the distribution of funds within 60 days or 45 days, respectively, 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, Refining LLC and its wholly-owned subsidiary, Coffeyville Finance, issued $500.0 million aggregate principal amount of the 2022 Notes. A portion of the net proceeds from the offering approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to pay related fees and expenses. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. The remaining proceeds from the offering were used to fund a completed and settled redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount. Previously deferred financing charges and unamortized original issuance premium related to the First Lien Notes totaled approximately $8.1 million and $6.3 million, respectively. As a result of these transactions, a loss on extinguishment of debt of $33.4 million was recorded in the Consolidated Statement of Operations in the fourth quarter of 2012, which includes the total premiums paid of 100 $31.6 million and write-off of previously deferred financing charges of $8.1 million, partially offset by the write-off of the unamortized original issuance premium of $6.3 million. The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and will be amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. As of December 31, 2012, the 2022 Notes had an aggregate principal balance and a net carrying value of $500.0 million. The 2022 Notes were issued at 100% of their principal amount pursuant to an indenture (the ‘‘New Indenture’’), dated October 23, 2012, among Refining LLC and Coffeyville Finance, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the ‘‘2022 Notes Trustee’’). The Notes were fully and unconditionally guaranteed by CRLLC and substantially all of Refining LLC’s subsidiaries (the ‘‘Guarantors’’ and, together with the Issuers, the ‘‘Credit Parties’’). CRLLC was released as a guarantor in connection with the closing of the Refining Partnership’s IPO on January 23, 2013, and CVR Refining subsequently became a guarantor. The obligations under the 2022 Notes and the related guarantees were initially secured by liens on substantially all of the assets of the issuers and the guarantors. The security interests were released upon satisfaction and discharge of the indenture governing the outstanding Second Lien Notes in connection with the closing of the Refining Partnership IPO. 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, in each case, plus any accrued and unpaid interest. Prior to November 1, 2015, up to 35% of the 2022 Notes may be redeemed with the proceeds from certain equity offerings at a redemption price of 106.5% of the principal amount thereof, plus 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 (1) the direct or indirect sale or transfer (other than by a merger) of all or substantially all of the assets of Refining LLC to any person other than qualifying owners (as defined in the indenture), (2) liquidation or dissolution of Refining LLC, or (3) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the voting stock of Refining LLC. 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 subordinated or unsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, 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. 101 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. We were in compliance with the covenants as of December 31, 2012. Amended and Restated Asset Backed (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 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 swing line 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 borrowing-base components, advance rates, prepayment provisions, collateral provisions, affirmative covenants and negative covenants in the Amended and Restated ABL Credit Facility are substantially similar to the corresponding provisions in the ABL credit facility. The Amended and Restated ABL Credit Facility permits the payment of distributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability and projected excess availability at all times during the 3-month period following the distribution exceeds 20% of the lesser of the borrowing base and the total commitments; provided, that, if excess availability and projected excess availability for the 6-month period following the distribution is greater than 25% at all times, then the following condition 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 will also be 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. 102 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, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility. The Refining Partnership was in compliance with the covenants of the Amended and Restated ABL Credit Facility as of December 31, 2012. Old Notes. On April 6, 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance completed the private offering of $275.0 million aggregate principal amount of First Lien Notes and $225.0 million aggregate principal amount of Second Lien Notes. The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 30, 2010, we made a voluntary unscheduled principal payment of $27.5 million on our First Lien Notes. As a result of this payment, we were required to pay a 3.0% premium totaling approximately $0.8 million. Additionally, an adjustment was made to our previously deferred financing costs, underwriting discount and original issue discount of approximately $0.8 million. The premium payment and write-off of previously deferred financing costs, underwriting discount and original issue discount were recognized as a loss on extinguishment of debt. On May 16, 2011, we repurchased $2.7 million of the Notes at a purchase price of 103% of the outstanding principal amount. On December 15, 2011, we issued an additional $200.0 million aggregate principal amount of First Lien Notes to partially fund the Wynnewood Acquisition. The additional First Lien Notes were issued at 105% of their principal amount. On October 23, 2012, we repurchased approximately $323.0 million of our First Lien Notes pursuant to a tender offer and redeemed the remaining $124.1 million of outstanding First Lien Notes not tendered, on November 23, 2012, as discussed above. As of December 31, 2012, the outstanding Second Lien Notes had an aggregate principal balance $222.8 million and a net carrying value of $220.9 million. On January 23, 2013, a portion of the proceeds from the Refining Partnership IPO was used to satisfy and discharge the indenture governing the Second Lien Notes. 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 includes 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 is no scheduled amortization and the Nitrogen Fertilizer Partnership credit facility matures in April 2016. The Nitrogen Fertilizer Partnership, upon the closing of the credit facility, made a special distribution of approximately $87.2 million to CRLLC, in order to, among other things, fund the offer to purchase CRLLC’s Old Notes required upon consummation of the Nitrogen Fertilizer Partnership IPO. The Nitrogen Fertilizer Partnership credit facility is used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF. Borrowings under the Nitrogen Fertilizer Partnership credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the Nitrogen Fertilizer Partnership credit facility is the Eurodollar rate plus a margin of 3.50%, or for base rate loans, or the prime rate plus 2.50%. Under its terms, the lenders under the Nitrogen Fertilizer Partnership credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Nitrogen Fertilizer Partnership and all of the capital stock of CRNF and each domestic subsidiary owned by the Nitrogen Fertilizer Partnership or CRNF. CRNF is the borrower under the Nitrogen Fertilizer Partnership credit facility. All obligations under the Nitrogen Fertilizer Partnership credit facility are unconditionally 103 guaranteed by the Nitrogen Fertilizer Partnership and substantially all of its future, direct and indirect, domestic subsidiaries. Borrowings under the credit facility are non-recourse to the Company and its direct subsidiaries. As of December 31, 2012, no amounts were drawn under the Nitrogen Fertilizer Partnership’s $25.0 million revolving credit facility. The acquisition of common stock of CVR Energy by Carl Icahn and related entities and the related change of control at CVR Energy did not trigger an event of default under the Nitrogen Fertilizer Partnership credit facility. However, an event of default will be triggered if CVR Energy or any of its subsidiaries (other than the Nitrogen Fertilizer Partnership and CRNF) terminates or violates any of its covenants in any of the intercompany agreements between the Nitrogen Fertilizer Partnership and CVR Energy and its subsidiaries (other than the Nitrogen Fertilizer Partnership and CRNF) and such action has a material adverse effect on the Nitrogen Fertilizer Partnership. If an event of default occurs, the administrative agent under the Nitrogen Fertilizer Partnership credit facility would be entitled to take various actions, including the acceleration of amounts due under the credit facility and all actions permitted to be taken by a secured creditor. Nitrogen Fertilizer Partnership Interest Rate Swap On June 30 and July 1, 2011, the Nitrogen Fertilizer Partnership’s CRNF subsidiary entered into two Interest Rate Swap agreements with J. Aron & Company. These Interest Rate Swap agreements commenced on August 12, 2011. We have determined that the Interest Rate Swaps qualifies for hedge accounting treatment. The impact recorded for the year ended December 31, 2012 and 2011 is $1.0 million and $0.4 million, respectively, in interest expense. For the year ended December 31, 2012 and 2011, the Nitrogen Fertilizer Partnership recorded a decrease in fair market value on the Interest Rate Swap agreements of $0.4 million and $2.4 million, respectively, which is unrealized in accumulated other comprehensive income. 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. The following table summarizes the Refining Partnership’s and the Nitrogen Fertilizer Partnership’s total actual capital expenditures for 2012 and current estimated capital expenditures in 2013 by 104 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: Petroleum Business (the Refining Partnership): Coffeyville refinery: Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coffeyville refinery total capital excluding turnaround expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wynnewood refinery: Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wynnewood refinery total capital excluding turnaround expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Petroleum: Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other petroleum total capital excluding turnaround expenditures . Year Ended December 31, 2012 Actual 2013 Estimate (in millions) $ 40.4 2.0 $ 81.7 14.3 42.4 51.6 0.8 52.4 6.2 19.0 25.2 96.0 96.2 19.9 116.1 6.3 13.3 19.6 Petroleum business total capital excluding turnaround expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120.0 231.7 Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership): Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen fertilizer business total capital excluding turnaround expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corporate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.7 74.5 82.2 10.0 7.8 41.5 49.3 1.7 Total capital spending . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $212.2 $282.7 During the first quarter of 2012, we completed the second phase of a two-phase turnaround project at the Coffeyville refinery. The first phase was completed during the fourth quarter of 2011. We incurred costs of approximately $21.2 million, $66.4 million and $1.2 million for the years ended December 31, 2012, 2011 and 2010, respectively, associated with the 2011/2012 turnaround. The Wynnewood refinery completed a turnaround in the fourth quarter of 2012. The Wynnewood refinery incurred costs of approximately $102.5 million for the year ended December 31, 2012 associated with the 2012 turnaround. 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 our capital projects. For example, we 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 plant. Capital spending for the Nitrogen Fertilizer Partnership’s nitrogen fertilizer business has been and will be determined by the board of directors of its general partner. Capital spending for the Refining Partnership’s petroleum business will be determined by the board of directors of its general partner. 105 The UAN expansion, which provides the nitrogen fertilizer business with the flexibility to upgrade all of its ammonia production to UAN, was completed in February and is scheduled to be at full operating rates in March 2013. Inclusive of capital spent prior to the Nitrogen Fertilizer Partnership IPO, we anticipate that the total capital spend associated with the UAN expansion will approximate $130.0 million, excluding capitalized interest. As of December 31, 2012, approximately $106.1 million was spent, including $64.5 million, which was spent during the year ended December 31, 2012. In January 2013, the nitrogen fertilizer business completed the UAN terminal project at an estimated cost of $1.8 million. The UAN terminal project included the construction of a two million gallon UAN storage tank and related truck and rail car load-out facilities located in Phillipsburg, Kansas, to enable it to distribute up to approximately 20,000 tons of UAN fertilizer annually. The property that this terminal was constructed on is owned by a subsidiary of the Refining Partnership, Coffeyville Resources Terminal, LLC, who operates the terminal. During the fourth quarter of 2012, the nitrogen business completed a scheduled major biennial turnaround of the nitrogen fertilizer plant at a total cost of approximately $4.8 million, the majority of which was expensed in the fourth quarter of 2012. The next turnaround is scheduled for the fourth quarter of 2014. The following table sets forth our consolidated cash flows for the periods indicated below: Cash Flows Year Ended December 31, 2012 2011 2010 (in millions) Net cash provided by (used in): Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 762.6 (210.7) (44.3) $ 278.6 (674.4) 584.1 $225.4 (31.3) (31.0) Net increase (decrease) in cash and cash equivalents . . . . . . . . . . $ 507.6 $ 188.3 $163.1 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 year ended December 31, 2012 were $762.6 million. The positive cash flow from operating activities generated over this period was primarily driven by $412.6 million of net income before noncontrolling interest and non-cash adjustments for depreciation and amortization ($130.0 million) and unrealized loss on derivatives ($148.0 million). This positive net income was primarily due to the operating margins for the period. Favorable changes in trade working capital during 2012 were largely offset by unfavorable changes in other working capital. Trade working capital for the year ended December 31, 2012 resulted in a cash inflow of $25.5 million which was primarily attributable to the decrease in inventories ($108.0 million), which were partially offset by a decrease in accounts payable of $54.4 million and an increase in accounts receivable of $28.1 million. Other working capital activities resulted in net cash outflow of $20.4 million and were primarily related to a decrease in other current liabilities ($17.3 million), a decrease in deferred revenue ($8.1 million), an increase in prepaid expenses and other current assets ($9.3 million) and an increase in due from parent ($9.2 million), which was partially offset by a decrease in income taxes receivable ($23.6 million). 106 Net cash flows provided by operating activities for the year ended December 31, 2011 were $278.6 million. The positive cash flow from operating activities generated over this period was primarily driven by $378.6 million of net income before noncontrolling interest. This positive net income was primarily due to the operating margins for the period. The positive operating cash flow for the period was offset by unfavorable changes in trade working capital. Trade working capital for the year ended December 31, 2011 resulted in a reduction of cash flows of $114.3 million which was primarily attributable to the increase in inventories ($175.5 million) and an increase in accounts receivable ($55.4 million), both of which were partially offset by an increase in accounts payable of $5.8 million. Other working capital activities resulted in net cash outflow of $85.0 million and are primarily related to an increase in accrued income taxes ($35.8 million) and other current liabilities ($27.3 million). Significant uses of cash for the year ended December 31, 2011 included payments of income tax of approximately $182.6 million. In addition, we received insurance proceeds of approximately $10.1 million related to the UAN reactor rupture and refinery incidents. Approximately $7.4 million is included in cash flows from operating activities and the remaining balance is included in cash flows from investing activities Net cash flows provided by operating activities for the year ended December 31, 2010 were $225.4 million. The positive cash flow from operating activities generated over this period was partially driven by $14.3 million of net income, favorable changes in trade working capital and other working capital. Trade working capital for the year ended December 31, 2010 resulted in a cash inflow of $41.6 million, primarily attributable to a decrease in inventory of $27.7 million, and an increase in accounts payable of $47.9 million, partially offset by an increase in accounts receivable of $34.0 million. Other working capital activities resulted in a net cash inflow of $23.8 million. This inflow was primarily driven by an increase in other accrued income taxes of $28.8 million, increased deferred revenue of $8.4 million associated with the nitrogen fertilizer business’ prepaid sales orders and the receipt of income tax refunds and related interest of approximately $21.5 million. Additionally we received insurance proceeds of approximately $4.3 million related to the repairs, maintenance and other associated costs of the UAN vessel rupture, of which approximately $3.2 million is included in cash flows from operating activities and the remaining balance is included in cash flows from investing activities. These increases were offset by an outflow for monthly payments totaling $9.4 million related to our insurance premium financing arrangement. Also impacting other working capital is the decrease in prepaid assets and other current assets of $13.0 million. Cash Flows Used In Investing Activities Net cash used in investing activities for the year ended December 31, 2012 was $210.7 million compared to $674.4 million for the year ended December 31, 2011. The decrease in cash used in investing activities was the result of $586.0 million cash consideration paid for the Wynnewood Acquisition during the year ended December 31, 2011. For the year ended December 31, 2012 compared to the year ended December 31, 2011, capital expenditures increased by $121.0 million. For the year ended December 31, 2012, capital expenditures associated with the petroleum business totaled $120.0 million compared to $68.6 million for the year ended December 31, 2011. This $51.4 million increase was coupled with a $63.1 million increase in the nitrogen fertilizer business from $19.1 million for the year ended December 31, 2011 to $82.2 million for the year ended December 31, 2012. Significant capital expenditures for the year ended December 31, 2012 included expenditures for the nitrogen business’ UAN expansion project, construction of crude oil storage in Cushing, Oklahoma, projects at the Coffeyville refinery, and incremental spending at the Wynnewood refinery. Net cash used in investing activities for the year ended December 31, 2011 was $674.4 million compared to $31.3 million for the year ended December 31, 2010. The increase in investing activities was primarily the result of $586.0 million cash consideration paid for the Wynnewood Acquisition. In addition, capital expenditures increased by $58.8 million primarily related to the petroleum business. 107 For the year ended December 31, 2011, capital expenditures associated with the petroleum business totaled $68.6 million compared to $19.8 million for the year ended December 31, 2010. This $48.8 million increase was coupled with a $9.0 million increase in the nitrogen fertilizer business from $10.1 million for the year ended December 31, 2010 to $19.1 million for the year ended December 31, 2011. Significant capital expenditures for the year ended December 31, 2011 included expenditures for the expansion of the nitrogen fertilizer facility’s UAN plant, construction of crude oil storage in Cushing, Oklahoma and repairs and maintenance performed on various units at the Coffeyville refinery. Net cash used in investing activities for the year ended December 31, 2010 was $31.3 million compared to $48.3 million for the year ended December 31, 2009. The decrease in investing activities was the result of decreased capital expenditures primarily related to the petroleum business. For the year ended December 31, 2010, capital expenditures associated with the nitrogen fertilizer business totaled $10.1 million compared to $13.4 million for the year ended December 31, 2009. This decrease was coupled with a decrease of $14.2 million in petroleum capital expenditures for the comparable period. For the year ended December 31, 2010, petroleum capital expenditures totaled approximately $19.8 million compared to $34.0 million for the year ended December 31, 2009. Significant capital expenditures for the year ended December 31, 2010, included expenditures for the petroleum business’ ultra-low sulfur gasoline unit and the nitrogen fertilizers business’ UAN secondary reactor. Capital expenditures were partially offset by approximately $1.1 million of insurance proceeds received in connection with the rupture of the high-pressure UAN vessel. Cash Flows Provided by (Used In) Financing Activities Net cash used in financing activities for the year ended December 30, 2012 was approximately $44.3 million as compared to net cash provided by financing activities of $584.1 million for the year ended December 31, 2011. The net cash used in financing activities for the year ended December 31, 2012 was primarily attributable payments of $478.7 million to extinguish the First Lien Notes, distributions to noncontrolling interest holders at the Nitrogen Fertilizer Partnership of $48.8 million, payment of financing costs of approximately $12.8 million and deferred costs associated with the Refining Partnership IPO of approximately $3.1 million. These cash uses were largely offset by the net proceeds received of $491.3 million from the issuance of the 2022 Notes. For the year ended December 31, 2012, there were no borrowings or repayments under the Amended and Restated ABL credit facility or the Nitrogen Fertilizer Partnership credit facility. As of December 31, 2012, there were no short-term borrowings outstanding under the Amended and Restated ABL credit facility. Net cash provided by financing activities for the year ended December 30, 2011 was approximately $584.1 million as compared to net cash used in financing activities of $31.0 million for the year ended December 31, 2010. The net cash provided by financing activities for the year ended December 31, 2011 was primarily attributable to the net proceeds received of $324.8 million from the Nitrogen Fertilizer Partnership IPO. Additionally, $125.0 million of proceeds was received by the Nitrogen Fertilizer Partnership from the issuance of long-term debt and $206.0 million was received upon issuance of additional Old Notes. These proceeds were partially offset by cash outflows of $26.0 million by the Nitrogen Fertilizer Partnership to purchase CVR GP, LLC’s incentive distribution rights. Financing costs of approximately $15.1 million paid during the period were primarily associated with the ABL credit facility, the credit facility of CRNF and the issuance of the additional Old Notes. We repurchased $2.7 million of our Old Notes in accordance with the terms of a tender offer associated with the Nitrogen Fertilizer Partnership IPO. Additionally, we paid approximately $4.9 million toward our capital lease obligations primarily related to exercising our purchase option related to a corporate asset. 108 For the year ended December 31, 2011, there were no borrowings or repayments under our first priority credit facility or ABL credit facility. As of December 31, 2011, there were no short-term borrowings outstanding under the ABL credit facility. Net cash used in financing activities for the year ended December 31, 2010, was $31.0 million as compared to net cash used in financing activities of $9.0 million for the year ended December 31, 2009. For the year ended December 31, 2010, we paid a $1.2 million scheduled principal payment in January 2010 on long-term debt and then made two voluntary unscheduled principal payments totaling $25.0 million in the first quarter of 2010 related to our long-term debt. On April 6, 2010, we paid off the remaining $453.3 million balance of our outstanding long-term debt under our first priority credit facility. This payoff was made possible by the issuances of the Old Notes that resulted in net proceeds of $485.7 million. In addition, we paid $8.8 million of financing costs in connection with the amendment to our first priority credit facility and issuance of the Old Notes. In connection with the Nitrogen Partnership IPO, $0.7 million of deferred costs were paid. In December 2010, we made a principal payment on our First Lien Notes of $27.5 million. The primary uses of cash for the year ended December 31, 2009 were $4.8 million of scheduled principal payments in long-term debt and $4.0 million for the payment of financing costs associated with the amendment to our outstanding first priority credit facility. For the year ended December 31, 2010, we borrowed and repaid $60.0 million in short-term borrowings. These borrowings were made from our first priority revolving credit facility and were for the purpose of facilitating our working capital needs. There were no short-term borrowings made in the fourth quarter of 2010. As of December 31, 2010, we had no short-term borrowings outstanding. Capital and Commercial Commitments In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of December 31, 2012 relating to long-term debt outstanding on that date, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the five-year period following December 31, 2012 and thereafter. As of December 31, 2012, there were no amounts outstanding under the Amended and Restated ABL Credit Facility. Subsequent to December 31, 2012, we redeemed all of the outstanding Second Lien Notes. Contractual Obligations Payments Due by Period Total 2013 2014 2015 2016 2017 Thereafter (in millions) Long-term debt(1) . . . . . . . . . . . . . . . . . . . $ 847.8 $ — $ — $ — $125.0 $222.8 $ 500.0 6.5 39.4 Operating leases(2) . . . . . . . . . . . . . . . . . . 45.1 52.3 Capital lease obligations(3) . . . . . . . . . . . . 930.7 1,446.1 Unconditional purchase obligations(4) . . . . . 1.1 2.5 Environmental liabilities(5) . . . . . . . . . . . . 162.6 450.6 Interest payments(6) . . . . . . . . . . . . . . . . . 10.0 1.1 123.4 0.7 62.1 7.8 1.3 110.0 0.3 61.4 3.2 1.8 90.8 0.1 45.0 6.4 1.4 99.1 0.2 61.4 5.5 1.6 92.1 0.1 58.1 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,838.7 $197.3 $180.8 $168.5 $282.4 $363.7 $1,646.0 Other Commercial Commitments Standby letters of credit(7) . . . . . . . . . . . . . $ 27.7 $ — $ — $ — $ — $ — $ — (1) Consists of the 2022 Notes, the Second Lien Notes and the Nitrogen Fertilizer Partnership’s term loan facility outstanding on December 31, 2012. As discussed above, all of the outstanding Second Lien Notes were satisfied and discharged on January 23, 2013, with a combination of the proceeds from the Refining Partnership IPO and cash on hand. Accordingly, as of the date of this Report, our long-term debt consisted solely of (i) $500.0 million aggregate principal amount of 2022 Notes 109 at the Refining Partnership and (ii) a $125.0 million term loan facility due 2016 at the Nitrogen Fertilizer Partnership. (2) The Refining Partnership and the Nitrogen Fertilizer Partnership lease various facilities and equipment, including railcars and real property, under operating leases for various periods. (3) The amount includes commitments under capital lease arrangements for equipment and for two leases associated with pipelines and storage and terminal equipment associated with the Wynnewood Acquisition. (4) The amount includes (a) commitments under several agreements for the petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments under an electric supply agreement with the city of Coffeyville, (c) a product supply agreement with Linde and (d) a pet coke supply agreement with HollyFrontier Corporation having an initial term that ends in December 2013, subject to renewal and (e) approximately $1,007.8 million payable ratably over eighteen years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP (‘‘TransCanada’’). Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada’s Keystone pipeline system. We began receiving crude oil under the agreements in the first quarter of 2011. (5) Environmental liabilities represents (a) our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and (b) our estimated remaining costs to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleaning and Redevelopment Program. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See ‘‘Business — Environmental Matters.’’ (6) Interest payments are based on stated interest rates for our long-term debt outstanding on December 31, 2012. Giving effect to the redemption in full of the Second Lien Notes, total interest payments would have been $350.7 million. (7) Standby letters of credit issued against our Amended and Restated ABL Credit Facility include $0.2 million of letters of credit issued in connection with environmental liabilities, $26.3 million in letters of credit to secure transportation services for crude oil, a $0.6 million letter of credit issued to guarantee a portion of our insurance policy, $0.1 million issued for the purpose of providing support during the transition of letters of credit assumed during the Wynnewood Acquisition and $0.5 million issued for the purpose of providing support during the transition of the Amended and Restated ABL Credit Facility to Wells Fargo. 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, which in recent periods have been extremely volatile. This, to a certain extent, is subject to refining spreads (for the Refining Partnership), fertilizer margins (for the Nitrogen Fertilizer Partnership) and general economic financial, competitive, legislative, regulatory and other factors they are unable to control. Our businesses may not generate sufficient cash flow from operations, and future borrowings may not be available to the Nitrogen Fertilizer Partnership under its revolving credit facility, or the Refining Partnership under the Amended and Restated ABL Credit Facility (or other credit facilities our businesses may enter into in the future) in an amount sufficient to enable them to pay indebtedness or to fund other liquidity needs. They may seek to sell assets to fund liquidity needs but may not be able to do so. They may also need to refinance all or a portion of their indebtedness on or before maturity, and may not be able to refinance such indebtedness on commercially reasonable terms or at all. 110 We do not have any ‘‘off-balance sheet arrangements’’ as such term is defined within the rules and regulations of the SEC. Off-Balance Sheet Arrangements Recent Accounting Pronouncements In May 2011, the Financial Accounting Standards Board (‘‘FASB’’) issued Accounting Standards Update (‘‘ASU’’) No. 2011-04, ‘‘Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,’’ (‘‘ASU 2011-04’’). ASU 2011-04 changed the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between GAAP and International Financial Reporting Standards (‘‘IFRS’’). ASU 2011-04 also expanded the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance was to be applied prospectively. The provisions of ASU 2011-04 were effective for interim and annual periods beginning after December 15, 2011. We adopted this standard as of January 1, 2012. The adoption of this standard did not impact the consolidated financial statement footnote disclosures. In June 2011, the FASB issued ASU No. 2011-05, ‘‘Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income,’’ (‘‘ASU 2011-05’’) which amended current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, we must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. ASU 2011-05 was effective for interim and annual periods beginning after December 15, 2011 and was to be applied retrospectively. In December 2011, FASB issued ASU No. 2011-11, which deferred the effective date of the changes in ASU 2011-05 that related to the presentation of reclassification adjustments to again consider whether to present the effects of reclassifications out of accumulated other comprehensive income on the face of the financials. We adopted this standard as of January 1, 2012. The adoption of this standard expanded the consolidated financial statements and footnote disclosures. In December 2011, the FASB issued ASU No. 2011-11, ‘‘Disclosures about Offsetting Assets and Liabilities’’ (‘‘ASU 2011-11’’). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under IFRS. On January 31, 2013, the FASB issued ASU No. 2013-04, ‘‘Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities’’ (‘‘ASU 2013-04’’). ASU 2013-04 limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards will be effective for interim and annual periods beginning January 1, 2013 and should be applied retrospectively. We believe these standards will expand our consolidated financial statement footnote disclosures. In February 2013, the FASB issued ASU No. 2013-02, ‘‘Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income’’ (‘‘ASU 2013-02’’). ASU 2013-02 requires us to present information about reclassification adjustments from accumulated other comprehensive income in our financial statements in a single footnote or parenthetically on the face of the financial statements based on the source and the income statement line items affected by the reclassification. The standard will be effective for interim and annual periods beginning January 1, 2013 and should be applied prospectively. We believe the standard will expand our consolidated financial statement footnote disclosures. Critical Accounting Policies We prepare our consolidated financial statements in accordance with GAAP. In order to apply these principles, management must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the notes to our audited 111 financial statements included elsewhere in this Report. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our financial statements. Goodwill To comply with ASC 350, Intangibles — Goodwill and Other (‘‘ASC 350’’), we perform a test for goodwill impairment annually, or more frequently in the event we determine that a triggering event has occurred. Our annual testing is performed in the fourth quarter of each year. Goodwill and other intangible accounting standards provide that goodwill and other intangible assets with indefinite lives are not amortized but instead are tested for impairment on an annual basis. In accordance with these standards, we complete our annual test for impairment of goodwill as of November 1 each year. For the years ended December 31, 2012, 2011 and 2010, the annual test of impairment indicated that goodwill was not impaired. In accordance with ASC 350, we identified our reporting units based upon our two key operating segments. These reporting units are our petroleum and nitrogen fertilizer segments. For 2012, 2011 and 2010, the nitrogen fertilizer segment was the only reporting unit that had goodwill. In testing our goodwill for impairment, we have applied the guidance in ASU 2011 — 08, which allows an alternative in certain situations that simplifies the impairment testing of goodwill. This guidance allows an entity the option to first perform a qualitative evaluation to determine whether it is necessary to perform the quantitative two-step goodwill impairment analysis. We began the qualitative assessment by analyzing the key drivers and other external factors that impact the business in order to determine if any significant events, transactions or other factors had occurred or are expected to occur that would impair earnings or competitiveness therefore impairing the fair value of the nitrogen fertilizer segment. The key drivers that were considered in the evaluation of the nitrogen fertilizer segment’s fair value included: • general economic conditions; • fertilizer pricing; • input costs; and • customer outlook. After assessing the totality of events and circumstances, it was determined that it was not more likely than not that the fair value of the nitrogen fertilizer segment was less than the carrying value, and so it was not necessary to perform the two-step valuation. Long-Lived Assets We calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. When assets are placed in service, we make estimates of what we believe are their reasonable useful lives. We account for impairment of long-lived assets in accordance with ASC Topic 360, Property, Plant and Equipment — Impairment or Disposal of Long-Lived Assets (‘‘ASC 360’’). In accordance with ASC 360, we review long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. No impairment charges were recognized for any of the periods presented. 112 Derivative Instruments and Fair Value of Financial Instruments We use futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices, finished goods product prices and interest rates to provide economic hedges of inventory positions and anticipated interest payments on long-term debt. Although management considers these derivatives economic hedges, these derivative instruments do not qualify as hedges for hedge accounting purposes under ASC Topic 815, Derivatives and Hedging (‘‘ASC 815’’), and accordingly are recorded at fair value in the balance sheet. Changes in the fair value of these derivative instruments are recorded into earnings as a component of other income (expense) in the period of change. The estimated fair values of forward and swap contracts are based on quoted market prices and assumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. The Company recorded net gains (losses) from derivative instruments of $(285.6) million, $78.1 million and $(1.5) million for the years ended December 31, 2012, 2011 and 2010, respectively. Share-Based Compensation For the years ended December 31, 2012, 2011 and 2010, we account for share-based compensation in accordance with ASC Topic 718, Compensation — Stock Compensation (‘‘ASC 718’’). ASC 718 requires that compensation costs relating to share-based payment transactions be recognized in a company’s financial statements. ASC 718 applies to transactions in which an entity exchanges its equity instruments for goods or services and also may apply to liabilities an entity incurs for goods or services that are based on the fair value of those equity instruments. Through the Company’s LTIP, shares of non-vested common stock may be awarded to the Company’s subsidiaries’ employees, officers, consultants, advisors and directors. Prior to the acquisition by IEP Energy, LLC and the related change of control, restricted shares, when granted, were valued at the closing market price of CVR Energy’s common stock at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. The change of control and related Transaction Agreement in May 2012 triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. Additional share-based compensation of approximately $12.4 million was incurred to revalue the awards upon modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards, the classification changed from equity awards to liability awards. In December 2012, restricted stock units were granted to certain employees of CVR. Each restricted stock unit represents the right to receive, upon vesting, a cash payment equal to (a) the fair market value of one share of the Company’s common stock, plus (b) the cash value of all dividends declared and paid by the Company per share of the Company’s common stock from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest. For the years ended December 31, 2012, 2011 and 2010, we incurred compensation expense of $36.9 million, $9.8 million and $2.4 million, respectively, related to non-vested share-based compensation awards related to the LTIP. Through the CVR Partners, LP Long-Term Incentive Plan, shares of non-vested common units and phantom units may be awarded to (1) employees of the Nitrogen Fertilizer Partnership and its subsidiaries, (2) employees of the general partner, and (3) members of the board of directors of the general partner. In December 2012, the board of directors of the general partner of the Nitrogen Fertilizer Partnership approved an amendment to modify the terms of the certain phantom unit awards 113 previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. The amendment triggered a modification to the awards by providing the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. Additional share-based compensation incurred to revalue the unvested units upon modification was not material. For awards vesting subsequent to amendment, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity-classified award to a liability-classified award. For the years ended December 31, 2012, 2011 and 2010, we incurred compensation expense of $2.2 million, $1.2 million and $0, respectively, related to non-vested share-based compensation awards related to the CVR Partners LTIP. Our executive officers were also compensated through the issuance of common units and override units in the entities through which our former sponsors held their equity in us. In conjunction with the initial public offering in October 2007, override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to the accounting standards issued by the FASB regarding the treatment of share-based compensation granted to employees of an equity method investee, as well as the accounting treatment for equity investments that are issued to individuals other than employees for acquiring or in conjunction with selling goods or services. As such, there was no additional expense incurred, subsequent to vesting, with respect to these share-based compensation awards. For the year ending December 31, 2011 and 2010, we increased compensation expense by $16.2 million and $34.8 million, respectively, as a result of the phantom and override unit share-based compensation awards. No compensation expense was recognized for the year ended December 31, 2012. Income Taxes We provide for income taxes in accordance with ASC Topic 740, Income Taxes (‘‘ASC 740’’), accounting for uncertainty in income taxes. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets and if we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments which requires numerous judgments and assumptions. We record contingent income tax liabilities, interest and penalties, based on our estimate as to whether, and the extent to which, additional taxes may be due. Item 7A. 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. None of our market risk sensitive instruments are held for trading. Commodity Price Risk The petroleum business, as a manufacturer of refined petroleum products, and the nitrogen fertilizer business, as a manufacturer of nitrogen fertilizer products, all of which are commodities, have exposure to market pricing for products sold in the future. In order to realize value from our processing capacity, a positive spread between the cost of raw materials and the value of finished products must be achieved (i.e., gross margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable. The petroleum business uses a crude oil purchasing intermediary, Vitol, to purchase the majority of its non-gathered crude oil inventory for the Coffeyville refinery, and as of August 2012, the Wynnewood refinery, which allows it to take title to and price its crude oil at locations in close 114 proximity to the refineries, as opposed to the crude oil origination point, reducing its risk associated with volatile commodity prices by shortening the commodity conversion cycle time. The commodity conversion cycle time refers to the time elapsed between raw material acquisition and the sale of finished goods. In addition, the petroleum business seeks to reduce the variability of commodity price exposure by engaging in hedging strategies and transactions that will serve to protect gross margins as forecasted in the annual operating plan. Accordingly, the petroleum business uses commodity derivative contracts to economically hedge future cash flows (i.e., gross margin or crack spreads) and product inventories. With regard to its hedging activities, the petroleum business may enter into, or have entered into, derivative instruments which serve to: • lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreads that generate positive cash flows; • hedge the value of inventories in excess of minimum required inventories; and • manage existing derivative positions related to change in anticipated operations and market conditions. Further, the petroleum business intends to engage only in risk mitigating activities directly related to its businesses. The nitrogen fertilizer business has not historically hedged for commodity prices. Basis Risk. The effectiveness of our derivative strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors including time or location differences between the derivative instrument and the underlying physical commodity. Our selection of the appropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure. Examples of our basis risk exposure are as follows: • Time Basis — In entering over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underlying physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periods, then weighted-average physical prices will be weighted differently than the swap price as the result of timing. • Location Basis — In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area. Price and Basis Risk Management Activities. In the event inventories exceed the petroleum business’ target base level of inventories, it may enter into commodity derivative contracts to manage price exposure to inventory positions that are in excess of its base level. Excess inventories are typically the result of plant operations, such as a turnaround or other plant maintenance. To reduce the basis risk between the price of products for Group 3 and that of the NYMEX associated with selling forward derivative contracts for NYMEX crack spreads, the petroleum business may enter into basis swap positions to lock the price difference. If the difference between the price of products on the NYMEX and Group 3 (or some other price benchmark as we may deem appropriate) is different than the value contracted in the swap, then it will receive from or owe to the counterparty the difference on each unit of product contracted in the swap, thereby completing the locking of its margin. An example of the petroleum business’ use of a basis swap is in the winter heating oil season. The risk associated with not hedging the basis when using NYMEX forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX while Group 3 pricing remains flat or decreases then we would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on the Group 3 pricing. 115 From time to time, the petroleum business also holds various NYMEX positions through a third- party clearing house. On December 31, 2012, the Refining Partnership had the following open commodity derivative contracts whose unrealized gains and losses were included in gain (loss) on derivatives in the Consolidated Statements of Operations. At December 31, 2012, the Refining Partnership was net short 50 WTI crude oil contracts and short 50 unleaded gasoline contracts. At December 31, 2012, the Refining Partnership’s account balance maintained at the third-party clearing house totaled approximately $5.8 million, of which $5.0 million is reflected on the Consolidated Balance Sheet in cash and cash equivalents and $0.8 million is reflected in other current assets. The Refining Partnership’s NYMEX positions were in an unrealized loss position of approximately $0.8 million as of December 31, 2012. NYMEX transactions conducted throughout 2012 resulted in realized loss of approximately $10.9 million. In addition, the Refining Partnership entered into several commodity swap contracts with effective periods beginning in January 2012. 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 Consolidated Balance Sheet with changes in fair value currently recognized in the Consolidated Statements of Operations. At December 31, 2012, the Refining Partnership had open commodity hedging instruments consisting of 23.3 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production. The fair value of the outstanding contracts at December 31, 2012 was a net unrealized loss of $66.8 million, comprised of both short-term and long-term unrealized gains and losses. A change of $1.00 per barrel in the fair value of the crack spread swaps would result in an increase or decrease in the related fair values of commodity hedging instruments of $23.3 million. Interest Rate Risk On June 30 and July 1, 2011, CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of the nitrogen fertilizer business’ $125.0 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements, which commenced on August 12, 2011 and expires on February 12, 2016, totals $62.5 million (split evenly between the two agreement dates). Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit agreement. At December 31, 2012, the effective rate was approximately 4.58%.The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) (‘‘AOCI’’), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense. The Nitrogen Fertilizer Partnership still has exposure to interest rate risk on 50% of its $125.0 million floating rate term debt. 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 $625,000 on an annualized basis, thus decreasing net income by the same amount. 116 Item 8. Financial Statements and Supplementary Data CVR Energy, Inc. and Subsidiaries INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Audited Financial Statements: Page Number Report of Independent Registered Public Accounting Firm — Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118 Report of Independent Registered Public Accounting Firm — Internal Control Over Financial Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Balance Sheets at December 31, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . 119 120 Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121 Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122 Consolidated Statements of Changes in Equity for the years ended December 31, 2012, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123 Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124 126 117 Report of Independent Registered Public Accounting Firm The Board of Directors and Stockholders CVR Energy, Inc.: We have audited the accompanying consolidated balance sheets of CVR Energy, Inc. and subsidiaries (the Company) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of CVR Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. /s/ KPMG LLP Houston, Texas March 14, 2013 118 Report of Independent Registered Public Accounting Firm The Board of Directors and Stockholders CVR Energy, Inc.: We have audited CVR Energy, Inc. and subsidiaries’ (the Company’s) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report On Internal Control Over Financial Reporting under Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of CVR Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated March 14, 2013 expressed an unqualified opinion on those consolidated financial statements. /s/ KPMG LLP Houston, Texas March 14, 2013 119 CVR Energy, Inc. and Subsidiaries CONSOLIDATED BALANCE SHEETS December 31, 2012 2011 (in thousands, except share data) Current assets: ASSETS Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable, net of allowance for doubtful accounts of $1,999 and $1,282, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Due from parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant, and equipment, net of accumulated depreciation . . . . . . . . . . . . . . . . . Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred financing costs, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other long-term assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 895,965 $ 388,328 210,579 528,070 54,486 1,260 4,134 57,423 9,162 1,761,079 1,782,918 284 40,969 16,639 4,042 4,964 182,619 636,221 117,509 1,939 30,167 — — 1,356,783 1,672,961 312 40,969 20,319 4,076 23,871 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,610,895 $3,119,291 Current liabilities: LIABILITIES AND EQUITY Note payable and capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Personnel accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued taxes other than income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term liabilities: Long-term debt and capital lease obligations, net of current portion . . . . . . . . . . . . . Accrued environmental liabilities, net of current portion . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,140 440,113 51,154 36,693 — — 965 95,566 625,631 897,078 1,597 386,940 39,511 $ 9,880 466,559 20,849 35,147 2,400 9,271 9,026 34,427 587,559 853,903 1,459 357,473 19,194 Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,325,126 1,232,029 Commitments and contingencies Equity: CVR stockholders’ equity: Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 and 86,906,760 shares issued, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additional paid-in-capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Treasury stock, 98,610 as of December 31, 2012 and 2011, at cost . . . . . . . . . . . . . . . Accumulated other comprehensive loss, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . 869 582,287 945,460 (2,303) (1,158) 869 587,199 566,855 (2,303) (1,008) Total CVR stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,525,155 1,151,612 Noncontrolling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134,983 148,091 Total equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,660,138 1,299,703 Total liabilities and equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,610,895 $3,119,291 See accompanying notes to consolidated financial statements. 120 CVR Energy, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2012 2011 2010 Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating costs and expenses: Cost of product sold (exclusive of depreciation and (in thousands, except share data) $ 5,029,113 $ 8,567,327 $ 4,079,768 amortization) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,696,912 3,943,514 3,568,118 Direct operating expenses (exclusive of depreciation and amortization) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance recovery — business interruption . . . . . . . . . . . Selling, general and administrative expenses (exclusive of depreciation and amortization) . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . 522,075 — 183,420 130,005 334,052 (3,360) 239,791 — 97,990 90,321 92,034 86,761 Total operating costs and expenses . . . . . . . . . . . . . . . . 7,532,412 4,462,517 3,986,704 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,034,915 566,596 93,064 Other income (expense): . . . . . . . . . . . . Interest expense and other financing costs Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Realized gain (loss) on derivatives, net . . . . . . . . . . . . . . . Unrealized gain (loss) on derivatives, net . . . . . . . . . . . . . Loss on extinguishment of debt . . . . . . . . . . . . . . . . . . . . Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total other income (expense) . . . . . . . . . . . . . . . . . . . . Income before income taxes . . . . . . . . . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Net income attributable to noncontrolling interest Net income attributable to CVR Energy Stockholders . . . . . . Basic earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . . . Weighted-average common shares outstanding: $ $ $ (75,435) 867 (137,565) (148,027) (37,540) 960 (396,740) 638,175 225,584 412,591 33,986 378,605 4.36 4.33 $ $ $ (55,809) 489 (7,182) 85,262 (2,078) 844 21,526 588,122 209,563 378,559 32,783 345,776 4.00 3.94 $ $ $ (50,268) 2,211 (2,139) 634 (16,647) 1,218 (64,991) 28,073 13,783 14,290 — 14,290 0.17 0.16 Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86,822,913 87,392,270 86,493,735 87,766,573 86,340,342 86,789,179 See accompanying notes to consolidated financial statements. 121 CVR Energy, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other comprehensive income (loss): Unrealized gain (loss) on available-for-sale securities, net of tax of Year Ended December 31, 2012 2011 2010 $412,591 (in thousands) $378,559 $14,290 $5, $(1), and $2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 (1) Change in fair value of interest rate swap, net of tax of $(359), $(1,235) and $0 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (963) (1,899) Reclass of gain/loss to income on settlement of interest rate swap, net of tax of $263, $109 and $0 . . . . . . . . . . . . . . . . . . . . . . . . . . 696 167 2 — — Total other comprehensive income (loss) . . . . . . . . . . . . . . . . . . . Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (260) 412,331 (1,733) 376,826 2 14,292 Less: Comprehensive income attributable to noncontrolling interest . 33,876 32,060 — Comprehensive income attributable to CVR Energy Stockholders . $378,455 $344,766 $14,292 See accompanying notes to consolidated financial statements. 122 CVR Energy, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY Common Stockholders $0.01 Par Value Common Stock Additional Paid-In Capital Shares Issued Accumulated Other Total CVR Retained Treasury Comprehensive Stockholders’ Noncontrolling Earnings Income (loss) Interest Equity Stock Total Equity . . . . . . . 86,344,508 — . $863 — $446,263 21,698 $206,789 — $ (100) — $ — — $ 653,815 21,698 $ 10,600 — $ 664,415 21,698 (in thousands, except share data) . Balance at December 31, 2009 . Share-based compensation . . . Excess tax benefit from share-based . . . . . . . . . . . . . . . . . . compensation . . . Issuance of common stock to Directors . . Vesting of non-vested stock awards . . . . Issuance of stock from treasury . . . . . Purchase of treasury stock . . . . . . . . Net income . Net unrealized gain on available-for-sale . securities, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 29,128 62,036 — — — — — — 1 — — — — 141 — — (231) — — — — — — — 14,290 — — — 231 (374) — — — — Balance at December 31, 2010 . . . . . . . . . 86,435,672 $864 $467,871 $221,079 $ (243) $ Impact from the issuance of CVR Partners . common units to the public . Purchase of Managing General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . holders compensation . Partnership Interest and incentive . distribution rights . Distributions to noncontrolling interest . . . . . . . . Share-based compensation . Excess tax benefit of share-based . . . . Issuance of common stock to directors . . . Issuance of stock from treasury . . Purchase of treasury stock . . . . Vesting of non-vested stock awards . . . Redemption of common units . Net income . . . . . . . Net unrealized loss on available-for-sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . securities, net of tax . . Net loss on interest rate swaps, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — 831 — — 470,257 — — — — — — — — — — — — 5 — — — — 118,213 (15,401) — 15,842 — — — — — — — — 2,270 — (1,475) — — (121) — — — — — 1,475 — (3,535) — — — — — — 345,776 — — — — — — 2 2 — — — — — — — — — — — 141 — 1 — (374) 14,290 2 — — — — — — — 141 — 1 — (374) 14,290 2 $ 689,573 $ 10,600 $ 700,173 118,213 136,893 255,106 (15,401) (10,600) (26,001) — 15,842 2,270 — — (3,535) 5 (121) 345,776 (1) (1,009) (21,630) 768 — — — — — — 32,783 — (723) (21,630) 16,610 2,270 — — (3,535) 5 (121) 378,559 (1) (1,732) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . holders . Balance at December 31, 2011 . . Distributions to noncontrolling interest . . . . . . Share-based compensation . . Modification and reclassification of equity share-based compensation award to . liability based award . . Modification and reclassification of subsidiary equity share-based compensation award to liability based . . award . . . Excess tax benefit of share-based . . . . . . . . Exercise of stock options . . . Redemption of common units . Net income . . . . . . Net unrealized gain on available-for-sale . securities, net of tax . compensation . . Net loss on interest rate swaps, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86,906,760 $869 $587,199 $566,855 $(2,303) $(1,008) $1,151,612 $148,091 $1,299,703 — — — — — — (1) (1,009) — — — — — 22,900 — — — — — — — — — — — — — — — 5,174 (9,924) — — — (343) — (19) 413 (213) — — — — 378,605 — — — — — — — — — — — — — — — — — — — — — — 7 (157) — 5,174 (48,814) 2,071 (48,814) 7,245 (9,924) — (9,924) (343) (149) (492) (19) 413 (213) 378,605 7 (157) — — (92) 33,986 — (110) (19) 413 (305) 412,591 7 (267) Balance at December 31, 2012 . . . . . . . . . 86,929,660 $869 $582,287 $945,460 $(2,303) $(1,158) $1,525,155 $134,983 $1,660,138 See accompanying notes to consolidated financial statements. 123 CVR Energy, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS Cash flows from operating activities: Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Allowance for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of original issue discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of original issue premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Excess income tax benefit of share-based compensation . . . . . . . . . . . . . . . . . . . . Loss on disposition of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Share-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unrealized (gain) loss on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in assets and liabilities: Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Due from parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance proceeds for UAN reactor rupture . . . . . . . . . . . . . . . . . . . . . . . . . Business interruption insurance proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance proceeds on Coffeyville Refinery incident . . . . . . . . . . . . . . . . . . . . . Other long-term assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued environmental liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other long-term liabilities Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2012 2011 2010 (in thousands) $ 412,591 $ 378,559 $ 14,290 130,005 717 7,360 513 (2,848) (17,254) (19) 1,556 37,540 39,096 148,027 (28,132) 108,021 (9,326) (1,016) (9,162) — — 703 342 (54,445) 23,633 (8,061) (17,314) 138 (41) 762,624 90,321 561 4,566 512 (148) 62,688 (2,270) 3,452 2,078 27,173 (85,262) 55,435 (175,543) (8,776) (12,325) — — 3,360 4,000 (1,649) 5,805 (35,750) (9,659) (27,253) (1,093) (227) 86,761 (414) 3,356 356 — (770) (141) 3,536 16,647 37,244 (634) (34,026) 27,666 (13,080) (7,070) — 3,161 — — 105 47,938 28,841 8,396 3,588 (276) (46) 278,555 225,428 Cash flows from investing activities: Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance proceeds for UAN reactor rupture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition of Gary-Williams (212,194) 467 1,026 — (91,224) 57 2,745 (585,987) Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (210,701) (674,409) Cash flows from financing activities: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revolving debt payments Revolving debt borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds, gross of original issue premium on issuance of senior notes . . . . . . . . . . . Proceeds, net of original issue discount on issuance of senior notes . . . . . . . . . . . . . Proceeds, gross on issuance of CVR Refining’s senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Principal payments on long-term debt Principal payments on senior secured notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payment of capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payment of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repurchase of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Excess tax benefit of share-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . Deferred costs of CVR Partners’ initial public offering . . . . . . . . . . . . . . . . . . . . . Deferred costs of CVR Refining’s initial public offering . . . . . . . . . . . . . . . . . . . . Purchase of managing general partner interest & incentive distribution rights . . . . . . Proceeds from issuance of CVR Partners’ long-term debt . . . . . . . . . . . . . . . . . . . Proceeds from CVR Partners initial public offering, net of offering costs . . . . . . . . . Distributions to noncontrolling interest holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise of stock options Redemption of common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — 500,000 — (478,679) (1,054) (12,793) — 19 — (3,073) — — — (48,814) 413 (305) Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . (44,286) Net increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . 507,637 388,328 — — 206,000 — — — (2,700) (4,897) (15,133) (3,535) 2,270 — — (26,001) 125,000 324,880 (21,630) — (121) 584,133 188,279 200,049 (32,409) 37 1,114 — (31,258) (60,000) 60,000 — 485,693 — (507,003) — (193) (8,775) (215) 141 (674) — — — — — — — (31,026) 163,144 36,905 Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 895,965 $ 388,328 $ 200,049 124 CVR Energy, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued) Supplemental disclosures Cash paid for income taxes, net of refunds (received) . . . . . . . . . . . . . . . . . . . . . . . Cash paid for interest net of capitalized interest of $10,797, $3,877 and $1,827 for the $ 228,367 $ 182,622 $ (14,285) years ended December 31, 2012, 2011 and 2010, respectively . . . . . . . . . . . . . . . . . $ 73,886 $ 45,230 $ 45,352 Year Ended December 31, 2012 2011 2010 (in thousands) Non-cash investing and financing activities: Accrual of construction in progress additions . . . . . . . . . . . . . . . . . . . . . . . . . . . Assets acquired through capital lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reduction of proceeds for underwriting discount and financing costs . . . . . . . . . . . . Receipt of marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 26,399 $ $ $ 7,500 — $ $ — $ $ 19,054 $ — $ 4,000 — $ 653 415 $ 10,287 23 See accompanying notes to consolidated financial statements. 125 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Organization and History of the Company Organization The ‘‘Company’’ or ‘‘CVR’’ may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries. Any references to the ‘‘Company’’ as of a date prior to October 16, 2007 (the date of the restructuring as further discussed in this Note) and subsequent to June 24, 2005 are to Coffeyville Acquisition LLC (‘‘CALLC’’) and 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 ammonia and UAN. The Company’s operations include two business segments: the petroleum segment and the nitrogen fertilizer segment. CALLC formed CVR Energy, Inc. as a wholly-owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering. The initial public offering of CVR was consummated on October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (‘‘CALLC II’’). CVR’s common stock is listed on the NYSE under the symbol ‘‘CVI.’’ As of December 31, 2010, approximately 40% of its outstanding shares were beneficially owned by GS Capital Partners V, L.P. and related entities (‘‘GS’’ or ‘‘Goldman Sachs Funds’’) and Kelso Investment Associates VII, L.P. and related entities (‘‘Kelso’’ or ‘‘Kelso Funds’’). On February 8, 2011, GS and Kelso completed a registered public offering, whereby GS sold into the public market its remaining ownership interests in CVR and Kelso substantially reduced its interest in the Company. On May 26, 2011, Kelso completed a registered public offering, whereby Kelso sold into the public market its remaining ownership interest in CVR Energy. On May 7, 2012, Carl C. Icahn and certain of his affiliates (collectively, ‘‘Icahn’’) announced that they had acquired control of CVR pursuant to a tender offer for all of the Company’s common stock. As of December 31, 2012, Icahn owned approximately 82% of all outstanding shares. Prior to Icahn’s acquisition, the Company was owned 100% by the public. See further discussion in Note 3 (‘‘Change of Control’’). On December 15, 2011, CVR acquired all of the issued and outstanding shares of Gary-Williams Energy Corporation (subsequently converted to ‘‘WEC’’). Assets acquired include a 70,000 bpd refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of company-owned storage tanks. See Note 4 (‘‘Wynnewood Acquisition’’) for additional information regarding the Wynnewood Acquisition. CVR Partners, LP In conjunction with the consummation of CVR’s initial public offering in 2007, CVR transferred Coffeyville Resources Nitrogen Fertilizers, LLC (‘‘CRNF’’), its nitrogen fertilizer business, to CVR Partners, which at the time was a newly created limited partnership, in exchange for a managing general partner interest (‘‘managing GP interest’’), a special general partner interest (‘‘special GP interest,’’ represented by special GP units) and a de minimis limited partner interest (‘‘LP interest,’’ represented by special LP units). CVR concurrently sold the managing GP interest, including the associated incentive distribution rights (‘‘IDRs’’), to Coffeyville Acquisition III LLC (‘‘CALLC III’’), an 126 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) entity owned by its then controlling stockholders and senior management, for $10.6 million. On April 13, 2011, the Nitrogen Fertilizer Partnership completed its initial public offering of 22,080,000 common units (the ‘‘Nitrogen Fertilizer Partnership IPO’’) priced at $16.00 per unit. The common units, which are listed on the NYSE, began trading on April 8, 2011 under the symbol ‘‘UAN’’. In connection with the Nitrogen Fertilizer Partnership IPO, the IDRs were purchased by the Nitrogen Fertilizer Partnership for $26.0 million and subsequently extinguished. In addition, the noncontrolling interest representing the managing GP interest was purchased by Coffeyville Resources, LLC (‘‘CRLLC’’), a subsidiary of CVR for a nominal amount. The consideration for the IDRs was paid to the owners of CALLC III, which included the Goldman Sachs Funds, the Kelso Funds and members of CVR senior management. In connection with the Nitrogen Fertilizer Partnership IPO, the Company recorded a noncontrolling interest for the common units sold into the public market which represented approximately a 30% interest in the Nitrogen Fertilizer Partnership at the time of the Nitrogen Fertilizer Partnership IPO. The Company’s noncontrolling interest reflected on the consolidated balance sheet of CVR is impacted by the net income of, and distributions from the Nitrogen Fertilizer Partnership. At December 31, 2012, the Nitrogen Fertilizer Partnership had 73,065,143 common units outstanding, consisting of 22,145,143 common units owned by the public, representing approximately 30% of the total Nitrogen Fertilizer Partnership units and 50,920,000 common units owned by CRLLC, representing approximately 70% of the total Nitrogen Fertilizer Partnership 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 gross proceeds to the Nitrogen Fertilizer Partnership from the Nitrogen Fertilizer Partnership IPO were approximately $353.3 million, before giving effect to underwriting discounts and commissions and offering expenses. In connection with the Nitrogen Fertilizer Partnership IPO, the Nitrogen Fertilizer Partnership paid approximately $24.7 million in underwriting fees and incurred approximately $4.4 million of other offering costs. Approximately $5.7 million of the underwriting fee was paid to an affiliate of GS, which was acting as a joint book-running manager for the Nitrogen Fertilizer Partnership IPO. Until completion of CVR’s February 2011 secondary offering, an affiliate of GS was a stockholder and related party of the Company. In connection with the Nitrogen Fertilizer Partnership IPO, the Nitrogen Fertilizer Partnership’s limited partner interests were converted into common units, the Nitrogen Fertilizer Partnership’s special general partner interests were converted into common units, and the Nitrogen Fertilizer Partnership’s special general partner was merged with and into CRLLC, with CRLLC continuing as the surviving entity. In addition, as discussed above, the managing general partner sold its IDRs to the Nitrogen Fertilizer Partnership for $26.0 million, these interests were extinguished, and CALLC III sold the managing general partner to CRLLC for a nominal amount. As a result of the Nitrogen Fertilizer Partnership IPO, the Nitrogen Fertilizer Partnership has two types of partnership interests outstanding: • common units representing limited partner interests; and • a general partner interest, which is not entitled to any distributions, and which is held by the Nitrogen Fertilizer Partnership’s general partner. The proceeds from the Nitrogen Fertilizer Partnership IPO were utilized as follows: • approximately $18.4 million was distributed to CRLLC to satisfy the Nitrogen Fertilizer Partnership’s obligation to reimburse it for certain capital expenditures made on behalf of the nitrogen fertilizer business prior to October 24, 2007; 127 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) • approximately $117.1 million was distributed to CRLLC through a special distribution in order to, among other things, fund the offer to purchase CRLLC’s Old Notes required upon the consummation of the Nitrogen Fertilizer Partnership IPO; • $26.0 million was used by the Nitrogen Fertilizer Partnership to purchase and extinguish the IDR’s owned by the general partner; • approximately $4.8 million was used to pay financing fees and associated legal and professional fees resulting from the Nitrogen Fertilizer Partnership’s credit facility; and • the balance of the proceeds are being utilized by the Nitrogen Fertilizer Partnership for general partnership purposes, including the funding of the UAN expansion that will require an investment of approximately $130.0 million, excluding capitalized interest, of which approximately $106.1 million had been spent as of December 31, 2012. 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 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, CVR GP, LLC, manages the operations and activities of the Nitrogen Fertilizer Partnership, subject to the terms and conditions specified in the partnership agreement. The operations of the general partner in its capacity as general partner are managed by its board of directors. Actions by the general partner that are made in its individual capacity are made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The general partner is not elected by the common unitholders and is 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. On August 29, 2012, the Nitrogen Fertilizer Partnership’s registration statement on Form S-3 was declared effective by the Securities and Exchange Commission (‘‘SEC’’) enabling CVR Energy to offer and sell from time to time, in one or more public offerings or direct placements, up to 50,920,000 common units. Formation and Initial Public Offering of CVR Refining, LP In contemplation of an initial public offering, in September 2012, CRLLC formed CVR Refining Holdings, LLC (‘‘CVR Refining Holdings’’), which in turn formed CVR Refining GP, LLC. CVR Refining Holdings and CVR Refining GP, LLC formed the Refining Partnership, which issued them a 100% limited partnership interest and a non-economic general partner interest, respectively. CVR Refining Holdings formed CVR Refining, LLC (‘‘Refining LLC’’) and CRLLC contributed its petroleum and logistics subsidiaries, as well as its equity interests in Coffeyville Finance Inc. 128 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) (‘‘Coffeyville Finance’’) to Refining LLC in October 2012. CVR Refining Holdings contributed Refining LLC to the Refining Partnership on December 31, 2012. On January 23, 2013, the Refining Partnership completed its initial public offering of its common units representing limited partner interests (the ‘‘Refining Partnership IPO’’). See Note 22 (‘‘Subsequent Events’’) for further discussion on Refining Partnership IPO. (2) Summary of Significant Accounting Policies Principles of Consolidation The accompanying CVR consolidated financial statements include the accounts of CVR Energy, Inc. and its majority-owned direct and indirect subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. The ownership interests of noncontrolling investors in its subsidiaries are recorded as noncontrolling interests. Prior to the Nitrogen Fertilizer Partnership IPO, management had determined that the Nitrogen Fertilizer Partnership was a variable interest entity (‘‘VIE’’) and as such evaluated the qualitative criteria under Accounting Standards Codification (‘‘ASC’’) Topic 810-10 — Consolidations-Variable Interest Entities (‘‘ASC 810-10’’), to make a determination whether the Nitrogen Fertilizer Partnership should be consolidated on the Company’s financial statements. ASC 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 that evaluation, CVR’s management had determined to consolidate the Nitrogen Fertilizer Partnership in CVR’s consolidated financial statements for the periods presented prior to the Nitrogen Fertilizer Partnership IPO. Subsequent to the Nitrogen Fertilizer Partnership IPO, the Nitrogen Fertilizer Partnership is no longer considered a VIE. The consolidation of the Nitrogen Fertilizer Partnership is based upon the fact that the general partner is owned by CRLLC, a wholly-owned subsidiary of CVR; and, therefore, CVR has the ability to control the activities of the Nitrogen Fertilizer Partnership. Additionally, 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. The limited rights of the common unitholders of the Nitrogen Fertilizer Partnership are demonstrated by the fact that the common unitholders have no right to elect the general partner or the general partner’s directors on an annual or other continuing basis. The general partner can only be removed by a vote of the holders of at least 662⁄3% of the outstanding common units, including any common units owned by the general partner and its affiliates (including CRLLC, a wholly-owned subsidiary of CVR) voting together as a single class. 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 officers of the general partner manage the day-to-day affairs of the business. The majority of the officers of the general partner are also officers of CVR. Based upon the general partner’s role and rights as afforded by the partnership agreement and the limited rights afforded to the limited partners, the consolidated financial statements of CVR will include the assets, liabilities, cash flows, revenues and expenses of the Nitrogen Fertilizer Partnership. 129 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Cash and Cash Equivalents For purposes of the Consolidated Statements of Cash Flows, CVR considers all highly liquid money market accounts and debt instruments with original maturities of three months or less to be cash equivalents. Under the Company’s cash management system, checks issued but not presented to banks frequently result in book overdraft balances for accounting purposes and are classified as accounts payable in the Consolidated Balance Sheet. The change in book overdrafts are reported as a component of operating cash flow for accounts payable as they do not represent bank overdrafts. The amount of these checks included in accounts payable as of December 31, 2012 and 2011 was $21.3 million and $13.4 million, respectively. Accounts Receivable, net CVR grants credit to its customers. Credit is extended based on an evaluation of a customer’s financial condition; generally, collateral is not required. Accounts receivable are due on negotiated terms and are stated at amounts due from customers, net of an allowance for doubtful accounts. Accounts outstanding for longer than their contractual payment terms are considered past due. CVR determines its allowance for doubtful accounts by considering a number of factors, including the length of time trade accounts are past due, the customer’s ability to pay its obligations to CVR, and the condition of the general economy and the industry as a whole. CVR writes off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. Amounts collected on accounts receivable are included in net cash provided by operating activities in the Consolidated Statements of Cash Flows. At December 31, 2012 and 2011, no customers individually represented greater than 10% of the total accounts receivable balance. The largest concentration of credit for any one customer at December 31, 2012 and 2011 was approximately 9.8% and 9.4%, respectively, of the accounts receivable balance. 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. Inventories are valued at the lower of the first-in, first-out (‘‘FIFO’’) cost, or market for fertilizer products, refined fuels and by-products for all periods presented. 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. Prepaid Expenses and Other Current Assets Prepaid expenses and other current assets consist of prepayments for crude oil deliveries to CVR’s refineries for which title had not transferred, non-trade accounts receivable, current portions of prepaid insurance, deferred financing costs, derivative agreements and other general current assets. Property, Plant, and Equipment Additions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, are recorded at cost. Capitalized interest is added to any capital project over $1.0 million in cost which is expected to take more than six months to complete. Depreciation is computed using principally the straight-line method over the estimated useful 130 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) lives of the various classes of depreciable assets. The lives used in computing depreciation for such assets are as follows: Asset Improvements to land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Machinery and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Automotive equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Furniture and fixtures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Range of Useful Lives, in Years 15 to 30 20 to 30 5 to 30 5 to 15 3 to 10 Railcars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 to 40 Leasehold improvements and assets held under capital leases are depreciated or amortized on the straight-line method over the shorter of the contractual lease term or the estimated useful life of the asset. Expenditures for routine maintenance and repair costs are expensed when incurred. Such expenses are reported in direct operating expenses (exclusive of depreciation and amortization) in the Company’s Consolidated Statements of Operations. Goodwill and Intangible Assets Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized, and intangible assets with finite useful lives are amortized. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. CVR uses November 1 of each year as its annual valuation date for its goodwill impairment test. The Company performed its annual impairment review of goodwill for 2012, 2011 and 2010, which is attributable entirely to the nitrogen fertilizer segment and concluded there were no impairments. See Note 8 (‘‘Goodwill’’) for further discussion. Deferred Financing Costs, Underwriting and Original Issue Discount Deferred financing costs associated with debt issuances are amortized to interest expense and other financing costs using the effective-interest method over the life of the debt. Additionally, the underwriting and original issue discount and premium related to debt issuances have been amortized to interest expense and other financing costs using the effective-interest method over the life of the debt. Deferred financing costs related to the Amended and Restated ABL Credit Facility and CRNF credit facility are amortized to interest expense and other financing costs using the straight-line method through the termination date of the respective facility. Planned Major Maintenance Costs The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense when maintenance services are performed. Planned major maintenance activities for the nitrogen plant generally occur every two years. The required frequency of the maintenance varies by unit for the refineries, but generally is every four to five years. 131 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The Coffeyville refinery completed the second phase of a two-phase turnaround project during the first quarter of 2012. The first phase was completed during the fourth quarter of 2011. Costs of approximately $21.2 million, $66.4 million and $1.2 million associated with the Coffeyville refinery’s 2011/2012 turnaround were included in direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2012, 2011 and 2010, respectively. The Wynnewood refinery completed a turnaround in the fourth quarter of 2012. Costs of approximately $102.5 million were included in direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2012. During the year ended December 31, 2012 and 2010, the nitrogen fertilizer plant completed a scheduled major turnaround. Costs of approximately $4.8 million and $3.5 million, respectively, associated with the nitrogen fertilizer plant’s turnaround were included in direct operating expenses (exclusive of depreciation and amortization) for the years ended December 31, 2012 and 2010. Cost Classifications Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, pet coke expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $3.7 million, $2.5 million and $2.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. 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. Direct operating expenses exclude depreciation and amortization of approximately $124.1 million, $86.0 million and $81.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate and administrative office in Texas and the administrative offices in Kansas and Oklahoma. Selling, general and administrative expenses exclude depreciation and amortization of approximately $2.2 million, $1.8 million and $2.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Income Taxes CVR accounts for income taxes utilizing the asset and liability approach. Under this method, deferred tax assets and liabilities are recognized for the anticipated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 11 (‘‘Income Taxes’’) for further discussion. Impairment of Long-Lived Assets CVR accounts for long-lived assets in accordance with accounting standards issued by the Financial Accounting Standards Board (‘‘FASB’’) regarding the treatment of the impairment or disposal of long-lived assets. As required by these standards, CVR reviews long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the 132 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. Revenue Recognition Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has the assumed risk of loss, and when payment has been received or collection is reasonably assured. Deferred revenue represents customer prepayments under contracts to guarantee a price and supply of nitrogen fertilizer in quantities expected to be delivered in the next 12 months in the normal course of business. Excise and other taxes collected from customers and remitted to governmental authorities are not included in reported revenues. Nonmonetary product exchanges and certain buy/sell crude oil transactions which are entered into in the normal course of business are included on a net cost basis in operating expenses on the Consolidated Statement of Operations. The Company also engages in trading activities, whereby the Company enters into agreements to purchase and sell refined products with third parties. The Company acts as a principal in these transactions, taking title to the products in purchases from counterparties, and accepting the risks and rewards of ownership. The Company records revenue for the gross amount of the sales transactions, and records costs of purchases as an operating expense in the accompanying consolidated financial statements. Shipping Costs Pass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of product sold (exclusive of depreciation and amortization). Derivative Instruments and Fair Value of Financial Instruments The Company uses futures contracts, options, and forward swap contracts primarily to reduce the exposure to changes in crude oil prices, finished goods product prices and interest rates and to provide economic hedges of inventory positions. These derivative instruments have not been designated as hedges for accounting purposes. Accordingly, these instruments are recorded in the Consolidated Balance Sheets at fair value, and each period’s gain or loss is recorded as a component of gain (loss) on derivatives, net in accordance with standards issued by the FASB regarding the accounting for derivative instruments and hedging activities. On June 30 and July 1, 2011, CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of the nitrogen fertilizer business’ $125.0 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements, which commenced on August 12, 2011 and expires on February 12, 2016, totals $62.5 million (split evenly between the two agreement dates). Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit agreement. The agreements were designated as cash flow hedges at inception and accordingly, the 133 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) (‘‘AOCI’’), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense. Financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value, as a result of the short-term nature of the instruments. See Note 12 (‘‘Long-Term Debt’’) for further discussion of the extinguishment of the first priority credit facility long-term debt, issuance of First Lien Notes and Second Lien Notes, subsequent settlement of the First Lien Notes and issuance of the 2022 Notes. The First Lien Notes and Second Lien Notes were carried at the aggregate principal value less the unamortized original issue discount or premium. The 2022 Notes were issued at par value. See Note 12 (‘‘Long-Term Debt’’) for the fair value of the debt securities. Share-Based Compensation CVR accounts for share-based compensation in accordance with standards issued by the FASB regarding the treatment of share-based compensation and historically utilized guidance regarding the accounting for share-based compensation granted to employees of an equity method investee in conjunction with allocated non-cash share-based compensation expense to CVR from CALLC, CALLC II and CALLC III. As a result of the sale of the shares of CVR stock owned by CALLC and CALLC II during the year ended December 31, 2011 and the sale of the general partner and IDRs in connection with the Nitrogen Fertilizer Partnership IPO, no further amounts will be allocated by CALLC, CALLC II or CALLC III. Prior to the acquisition by Icahn and the related change of control, restricted shares, when granted, were valued at the closing market price of CVR Energy’s common stock at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. The change of control and related Transaction Agreement in May 2012 triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards, the classification changed from equity awards to liability awards. In December 2012, restricted stock units were granted to certain employees of CVR. Each restricted stock unit represents the right to receive, upon vesting, a cash payment equal to (a) the fair market value of one share of the Company’s common stock, plus (b) the cash value of all dividends declared and paid by the Company per share of the Company’s common stock from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest. The Nitrogen Fertilizer Partnership grants certain awards out of its CVR Partners Long-Term Incentive Plan (‘‘CVR Partners LTIP’’) to (1) employees of the Nitrogen Fertilizer Partnership and its subsidiaries, (2) employees of the general partner and (3) members of the board of directors of the general partner. In December 2012, the board of directors of the general partner of the Nitrogen 134 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Fertilizer Partnership approved an amendment to modify the terms of certain phantom unit awards previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. Prior to the amendment, the phantom units, when granted, were valued at the closing market price of the Nitrogen Fertilizer Partnership’s common units on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the units. The amendment triggered a modification to the awards by providing the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. For awards vesting subsequent to amendment, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity- classified award to a liability-classified award. Treasury Stock The Company accounts for its treasury stock under the cost method. To date, all treasury stock purchased was for the purpose of satisfying minimum statutory tax withholdings due at the vesting of non-vested stock awards. Environmental Matters Liabilities related to future remediation costs of past environmental contamination of properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, internal and third party assessments of contamination, available remediation technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties. Environmental expenditures are capitalized at the time of the expenditure when such costs provide future economic benefits. Use of Estimates The consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles, using management’s best estimates and judgments where appropriate. These estimates and judgments affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from these estimates and judgments. Subsequent Events The Company evaluated subsequent events, if any, that would require an adjustment to the Company’s consolidated financial statements or require disclosure in the notes to the consolidated financial statements through the date of issuance of the consolidated financial statements. See Note 22 (‘‘Subsequent Events’’) for further discussion. New Accounting Pronouncements In May 2011, the FASB issued Accounting Standards Update (‘‘ASU’’) No. 2011-04, ‘‘Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,’’ (‘‘ASU 2011-04’’). ASU 2011-04 changed the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information 135 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) about fair value measurements to ensure consistency between GAAP and International Financial Reporting Standards (‘‘IFRS’’). ASU 2011-04 also expanded the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance was to be applied prospectively. The provisions of ASU 2011-04 were effective for interim and annual periods beginning after December 15, 2011. The Company adopted this ASU as of January 1, 2012. The adoption of this standard did not impact the consolidated financial statement footnote disclosures. In June 2011, the FASB issued ASU No. 2011-05, ‘‘Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income,’’ (‘‘ASU 2011-05’’) which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. In December 2011, the FASB issued ASU No. 2011-12 which defers the requirement in ASU 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The Company adopted this standard as of January 1, 2012. The adoption of this standard expanded the Company’s consolidated financial statements and related footnote disclosures. In December 2011, the FASB issued ASU No. 2011-11, ‘‘Disclosures about Offsetting Assets and Liabilities’’ (‘‘ASU 2011-11’’). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under IFRS. On January 31, 2013, the FASB issued ASU No. 2013-04, ‘‘Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities’’ (‘‘ASU 2013-04’’). ASU 2013-04 limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards will be effective for interim and annual periods beginning January 1, 2013 and should be applied retrospectively. The Company believes these standards will expand its consolidated financial statement footnote disclosures. In February 2013, the FASB issued ASU No. 2013-02, ‘‘Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income’’ (‘‘ASU 2013-02’’). ASU 2013-02 requires the Company to present information about reclassification adjustments from accumulated other comprehensive income in the financial statements in a single footnote or parenthetically on the face of the financial statements based on the source and the income statement line items affected by the reclassification. The standard will be effective for interim and annual periods beginning January 1, 2013 and should be applied prospectively. The Company believes the standard will expand its consolidated financial statement footnote disclosures. (3) Change of Control On April 18, 2012, IEP Energy LLC (‘‘IEP Energy’’), a majority owned subsidiary of Icahn Enterprises, L.P. (‘‘Icahn Enterprises’’), and certain other affiliates of Icahn Enterprises and Carl C. Icahn (collectively, the ‘‘IEP Parties’’), entered into a Transaction Agreement (the ‘‘Transaction Agreement’’) with CVR, with respect to IEP Energy’s tender offer (the ‘‘Offer’’) to purchase all of the issued and outstanding shares of CVR’s common stock for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one CCP, which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR is executed on or prior to August 18, 2013 and such transaction closes. 136 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) In May 2012, the IEP Parties announced that a majority of CVR’s common stock had been acquired through the Offer. As a result of the shares tendered into the Offer and subsequent additional purchases, the IEP Parties owned approximately 82% of CVR’s outstanding common stock at December 31, 2012. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. Additional share-based compensation was incurred due to the modification of the awards and the fair value upon the date of modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. See further discussion at Note 5 (‘‘Share-Based Compensation’’). (4) Wynnewood Acquisition On December 15, 2011, the Company completed the acquisition of all the issued and outstanding shares of WEC, including its two wholly-owned subsidiaries, (the ‘‘Wynnewood Acquisition’’), for a preliminary purchase price of $592.3 million from The Gary-Williams Company, Inc. (the ‘‘Seller’’). This consisted of $525.0 million in cash, plus approximately $65.8 million for working capital and approximately $1.5 million for a capital expenditure adjustment. The Wynnewood Acquisition was partially funded by proceeds received from the issuance of Additional First Lien Notes. See Note 12 (‘‘Long-Term Debt’’) for further discussion of the issuance. The Wynnewood Acquisition was accounted for under the purchase method of accounting and, as such, the Company’s results of operations on the Consolidated Statement of Operations for the year ended December 31, 2011 include WEC’s revenues and loss before taxes of approximately $115.7 million and $2.3 million, respectively, for the period from December 16, 2011 through December 31, 2011. WEC owned a 70,000 bpd refinery in Wynnewood, Oklahoma that includes approximately 2.0 million barrels of company-owned storage tanks. Located in the PADD II Group 3 distribution area, the Wynnewood refinery is a dual crude oil unit facility that processes a variety of crudes and produces high-value fuel products (including gasoline, ultra-low sulfur diesel, jet fuel and solvent) as well as liquefied petroleum gas and a variety of asphalts. Purchase Price Allocation Under the purchase method of accounting, the total preliminary purchase price was allocated to WEC’s net tangible assets based on their fair values as of December 15, 2011. An independent appraisal of the net assets acquired was completed. The purchase price included a preliminary net working capital amount, which was finalized in the first quarter of 2012. At December 31, 2011, this difference was estimated at approximately $15.8 million and was recorded in prepaid expenses and other current assets in the Consolidated Balance Sheet. In accordance with the Stock Purchase and Sale Agreement, (the ‘‘Purchase Agreement’’), the Company provided a Post-Closing Statement to the Seller on February 13, 2012, which reflected the difference between the cash paid at closing for the estimated working capital as compared to the actual net working capital acquired. In March 2012, the preliminary purchase price was increased by $1.1 million, following settlement of the estimated cash paid for working capital in excess of actual working capital. 137 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The following table, set forth below, displays the total final purchase price allocated to WEC’s net tangible assets based on their fair values as of December 15, 2011 (in millions): Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt $ 6.3 159.0 213.5 6.0 577.0 (316.1) (52.3) Total fair values of net assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 593.4 Less: cash acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3 Total consideration transferred, net of cash acquired . . . . . . . . . . . . . . . . . . . . $ 587.1 Unaudited Pro Forma Financial Information The summary pro forma condensed consolidated financial information presented below for the years ended December 31, 2010 and 2011 give effect to the Wynnewood Acquisition as if it had occurred at the beginning of the periods presented. The pro forma adjustments are based upon available information and certain assumptions that CVR believes are reasonable. The pro forma net income has been adjusted to reflect amortization and depreciation expense, interest expense, income tax expense and other accounting policy election differences, such as turnaround costs, as if those adjustments had been applied on January 1, 2010. The summary pro forma condensed consolidated financial information is for informational purposes only and does not purport to represent what the Company’s consolidated results of operation actually would have been if the Wynnewood Acquisition had occurred at any date, and such data does not purport to project CVR’s results of operations for any future period. Years Ended December 31, 2011 2010 (in millions) (unaudited) Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $7,674.5 468.8 $6,220.8 22.0 Acquisition Costs For the years ended December 31, 2012 and 2011, CVR recognized approximately $11.0 million and $5.2 million, respectively, in transaction fees and integration expenses that are included in selling, general and administrative expense in the Consolidated Statement of Operations. In 2012, these costs primarily relate to accounting and other professional consulting fees incurred associated with post-closing transaction matters and continued integration of various processes, policies, technologies and systems of WEC. In 2011, these costs primarily relate to legal, accounting, initial purchaser discounts and commissions, and other professional fees incurred since the announcement of the Wynnewood Acquisition in November 2011. In addition, the Company entered into a commitment letter for a senior secured one-year bridge loan to ensure that financing would be available for the Wynnewood Acquisition in the event that the additional offering of First Lien Notes was not closed by 138 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) the date of the Wynnewood Acquisition. The bridge loan was subsequently undrawn. A commitment fee and other third-party costs totaling $3.9 million are included in selling, general and administrative expenses associated with the undrawn bridge loan. (5) Share-Based Compensation Prior to CVR’s initial public offering, CVR’s subsidiaries were held and operated by CALLC, a limited liability company. Management of CVR held an equity interest in CALLC. CALLC issued non-voting override units to certain management members who held common units of CALLC. There were no required capital contributions for the override operating units. In connection with CVR’s initial public offering in October 2007, CALLC was split into two entities: CALLC and CALLC II. In connection with this split, management’s equity interest in CALLC, including both their common units and non-voting override units, was split so that half of management’s equity interest was in CALLC and half was in CALLC II. In addition, in connection with the transfer of the managing general partner of the Nitrogen Fertilizer Partnership to CALLC III in October 2007, CALLC III issued non-voting override units to certain management members of CALLC III. For the years ended December 31, 2011 and 2010, CVR, CALLC, CALLC II accounted for share- based compensation in accordance with standards issued by the FASB regarding the treatment of share- based compensation, as well as guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. CVR was allocated non-cash share-based compensation expense from CALLC, CALLC II and CALLC III. In February 2011, CALLC and CALLC II sold into the public market 11,759,023 shares and 15,113,254 shares, respectively, of CVR’s common stock, pursuant to a registered public offering. In May 2011, CALLC sold into the public market its remaining shares of CVR’s common stock, pursuant to a registered public offering. As a result, CALLC and CALLC II ceased to be stockholders of the Company. Subsequent to CALLC II’s divestiture of its ownership interest in the Company in February 2011 and CALLC’s divestiture of its ownership interest in the Company in May 2011, no additional share-based compensation expense was incurred with respect to override units and phantom units. The final fair values of the override units of CALLC and CALLC II were derived based upon the values resulting from the proceeds received associated with each entity’s respective divestiture of its ownership in CVR. These values were utilized to determine the related compensation expense for the unvested units. The final fair value of the CALLC III override units was derived based upon the proceeds received by CVR GP, LLC upon the purchase of the IDR’s by the Nitrogen Fertilizer Partnership. These proceeds were subsequently distributed to the owners of CALLC III, which included the override unitholders. This value was utilized to determine the related compensation expense for the unvested units. No additional share-based compensation was incurred with respect to override units of CALLC III subsequent to June 30, 2011 due to the complete distribution of the value prior to July 1, 2011. 139 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II, and CALLC III. Award Type Benchmark Value (per Unit) Original Awards Issued *Compensation Expense for the Year Ended December 31, Grant Date 2011 2010 Override Operating Units . . . . . . . . . . . . Override Operating Units . . . . . . . . . . . . Override Value Units(a) . . . . . . . . . . . . . Override Value Units(b) . . . . . . . . . . . . . Override Units(c) . . . . . . . . . . . . . . . . . . $11.31 $34.72 $11.31 $34.72 $10.00 1,839,265 919,630 June 2005 72,492 December 2006 June 2005 144,966 December 2006 February 2008 642,219 (in thousands) $ — $ — 4,960 451 184 338 13 17,586 581 772 Total $5,595 $19,290 * As CVR Energy’s common stock price increased or decreased, compensation expense associated with the unvested CALLC and CALLC II override units increased or was reversed in correlation with the calculation of the fair value under the probability-weighted expected return method. Due to the divestiture of all ownership in CVR by CALLC and CALLC II and due to the purchase of IDRs from the general partner and the distribution to CALLC III, there is no associated unrecognized compensation expense as of December 31, 2012. Valuation Assumptions Significant assumptions used in the valuation of the Override Value Units (a) and (b) were as follows: Estimated forfeiture rate . . . . . . . . . . . . . . . . . . . . . . . . . Derived service period . . . . . . . . . . . . . . . . . . . . . . . . . . CVR Energy’s closing stock price . . . . . . . . . . . . . . . . . . Estimated fair value (per unit) . . . . . . . . . . . . . . . . . . . . Marketability and minority interest discounts . . . . . . . . . . Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (a) Override Value Units December 31, (b) Override Value Units December 31, 2010 None 6 years $ 15.18 $ 22.39 20.0% 43.0% 2010 None 6 years $ 15.18 $ 6.56 20.0% 43.0% (c) Override Units — Using a probability-weighted expected return method that utilized CALLC III’s cash flow projections which includes expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. As a non-contributing investor, CVR Energy also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. Of the 140 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 642,219 units issued, 109,720 were immediately vested upon issuance and the remaining units were subject to a forfeiture schedule. Significant assumptions used in the valuation were as follows: December 31, 2010 Estimated forfeiture rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . None Derived Service Period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeiture schedule Estimated fair value (per unit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Marketability and minority interest discounts . . . . . . . . . . . . . . . . . . . . Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2.60 10.0% 47.6% Phantom Unit Plans CVR, through CRLLC, had two Phantom Unit Appreciation Plans (the ‘‘Phantom Unit Plans’’) whereby directors, employees, and service providers were eligible to be awarded phantom points at the discretion of CVR’s board of directors or its compensation committee. Holders of service phantom points received distributions when CALLC and CALLC II holders of override operating units received distributions. Holders of performance phantom points received distributions when CALLC and CALLC II holders of override value units receive distributions. In November 2010, through a registered offering of CVR common stock, CALLC and CALLC II sold into the public market common shares of CVR. As a result of this offering, the Company made a payment to phantom unit holders totaling approximately $3.6 million. As described above, in February 2011, CALLC and CALLC II completed a sale of CVR common stock into the public market pursuant to a registered public offering. As a result of this offering, the Company made a payment to phantom unitholders of approximately $20.1 million in the first quarter of 2011. As described above, in May 2011, CALLC completed an additional sale of CVR common stock into the public market pursuant to a registered public offering. As a result of this offering, the Company made a payment to phantom unitholders of approximately $9.2 million in the second quarter of 2011. There was no compensation expense for the year ended December 31, 2012 related to the Phantom Unit Plans. Compensation expense for the years ended December 31, 2011 and 2010 related to the Phantom Unit Plans was approximately $10.6 million and $15.5 million, respectively. The Phantom Unit Plans were terminated in December 2012. Due to the divestiture of all ownership of CVR by CALLC and CALLC II and the associated payments to the holders of service and phantom performance points, there is no unrecognized compensation expense at December 31, 2012. Using the Company’s closing stock price at December 31, 2010, to determine the Company’s equity value, through an independent valuation process, the service phantom interest and performance phantom interest were valued as follows: December 31, 2010 Service Phantom interest (per point) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Performance Phantom interest (per point) . . . . . . . . . . . . . . . . . . . . . . . . . $14.64 $21.25 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 December 31, 2012, only restricted shares of CVR common stock, restricted stock units and stock options had been granted under the LTIP. Individuals who are eligible to receive awards and grants under the LTIP include the Company’s employees, officers, consultants, advisors and directors. A summary of the principal features of the LTIP is provided below. 141 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Shares Available for Issuance. The LTIP authorizes 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. Whenever any outstanding award granted under the LTIP expires, is canceled, is settled in cash or is otherwise terminated for any reason without having been exercised or payment having been made in respect of the entire award, the number of shares available for issuance under the LTIP is increased by the number of shares previously allocable to the expired, canceled, settled or otherwise terminated portion of the award. As of December 31, 2012, 6,787,341 shares of common stock were available for issuance under the LTIP. Restricted Shares A summary of restricted stock and restricted stock units (collectively ‘‘restricted shares’’) grant activity and changes during the years ended December 31, 2012, 2011 and 2010 is presented below: Restricted Shares Weighted- Average Grant-Date Fair Value Non-vested at December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . 177,060 $ 6.59 Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,307,378 (113,457) (1,799) 11.42 9.79 4.14 Aggregate Intrinsic Value (in thousands) $ 1,215 Non-vested at December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . 1,369,182 $10.94 $20,784 Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 826,959 (557,355) (4,632) 18.79 11.83 8.67 Non-vested at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . 1,634,154 $14.61 $30,608 Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 318,508 (740,811) (66,240) 43.66 13.59 16.54 Non-vested at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . 1,145,611 $23.24 $55,894 Through the LTIP, restricted shares have been granted to employees of the Company. Prior to the change of control as discussed in Note 3, the restricted shares, when granted, were historically valued at the closing market price of CVR’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. These restricted shares generally vest over a three-year period. The change of control and related Transaction Agreement discussed in Note 3 triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. Additional share-based compensation of approximately $12.4 million was incurred to revalue 142 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) the awards upon modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards, the classification changed from equity awards to liability awards. In December 2012, restricted stock units were granted to certain employees of CVR. The non-vested restricted stock units are expected to vest over three years on the basis of one-third of the award each year with the exception of awards granted to certain executive officers that vest over one year. Each restricted stock unit represents the right to receive, upon vesting, a cash payment equal to (a) the fair market value of one share of the Company’s common stock, plus (b) the cash value of all dividends declared and paid by the Company per share of the Company’s common stock from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest. Additionally, the Company approved a discretionary award of up to 62,920 restricted stock units to Mr. Lipinski, Chief Executive Officer and President of the Company, on or before December 31, 2013. This discretionary award remains subject to the review and recommendation of the Compensation Committee and approval of the board of directors of the Company, and is conditioned on Mr. Lipinski continuing to be employed by the Company through December 31, 2013. As such, no expense related to this discretionary award was recorded during the year ended December 31 2012. To the extent awarded, the discretionary award will vest immediately, and include dividend equivalent rights for the time period commencing on December 28, 2012 through the date of the award. As of December 31, 2012, there was approximately $19.9 million of total unrecognized compensation cost related to non-vested restricted shares to be recognized over a weighted-average period of approximately one year. The aggregate fair value at the grant date of the shares that vested during the year ended December 31, 2012 was approximately $10.1 million. As of December 31, 2012, 2011 and 2010, unvested restricted shares outstanding had an aggregate fair value at grant date of approximately $26.6 million, $23.9 million and $15.0 million, respectively. Total compensation expense for the years ended December 31, 2012, 2011 and 2010 was approximately $36.9 million, $9.8 million and $2.4 million, respectively, related to the LTIP. As of December 31, 2012, the Company has a liability of $19.5 million for unvested restricted share awards, which is recorded in personnel accruals on the Consolidated Balance Sheet. For the year ended December 31, 2012, the Company paid cash of $22.2 million to settle liability-classified awards upon vesting. No cash was paid to settle restricted share awards in 2011 and 2010. 143 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Stock Options Activity and price information regarding CVR’s stock options granted are summarized as follows: Weighted- Average Exercise Price Weighted- Average Remaining Contractual Term Shares Outstanding, December 31, 2009 . . . . . . . . . . . . . . . . . . . . . 32,350 $19.08 8.21 Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — (3,149) (6,301) — — 21.61 21.61 Outstanding, December 31, 2010 . . . . . . . . . . . . . . . . . . . . . 22,900 $18.03 8.35 Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — — — — Outstanding, December 31, 2011 . . . . . . . . . . . . . . . . . . . . . 22,900 $18.03 7.35 Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (22,900) — — Outstanding, December 31, 2012 . . . . . . . . . . . . . . . . . . . . . — — — — — — There were no grants of stock options in 2012, 2011 and 2010. In May 2012, all outstanding stock options equaling an equivalent of 22,900 common shares were exercised. No unexercised stock options remain as of December 31, 2012. Total compensation expense for the years ended December 31, 2012, 2011 and 2010, related to the stock options was $0, $8,000 and $9,000, respectively. Long-Term Incentive Plan — CVR Partners In April 2011, the board of directors of its general partner adopted the CVR Partners, LP Long-Term Incentive Plan (‘‘CVR Partners LTIP’’). Individuals who are eligible to receive awards under the CVR Partners LTIP include (1) employees of the Nitrogen Fertilizer Partnership and its subsidiaries, (2) employees of its general partner, and (3) members of the board of directors of its general partner. The CVR Partners LTIP provides for the grant of options, unit appreciation rights, distribution equivalent rights, restricted units, phantom units and other unit-based awards, each in respect of common units. The maximum number of common units issuable under the CVR Partners’ LTIP is 5,000,000. Through the CVR Partners LTIP, phantom and common units have been awarded to employees of the Nitrogen Fertilizer Partnership and its general partner and to members of the board of directors of its general partner. In December 2012, the board of directors of its general partner of the Nitrogen Fertilizer Partnership approved an amendment to modify the terms of certain phantom unit awards previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. Prior the amendment, the phantom units, when granted, were valued at the closing market price of the Nitrogen Fertilizer Partnership’s common units on the date of issuance and amortized to compensation expense 144 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) on a straight-line basis over the vesting period of the units. These units generally vest over a three-year period. The amendment triggered a modification to the awards by providing the employee the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. Additional share-based compensation incurred to revalue the unvested units upon modification was not material. For awards vesting subsequent to amendment, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity-classified award to a liability-classified award. A summary of common units and phantom units (collectively ‘‘units’’) activity and changes under the CVR Partners LTIP during the years ended December 31, 2012 and 2011 is presented below: Weighted- Average Grant-Date Fair Value Units Non-vested at April 13, 2011 . . . . . . . . . . . . . . . . . . . . . . — $ — Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200,647 (36,076) — 22.34 19.36 — Aggregate Intrinsic Value (in thousands) $ — Non-vested at December 31, 2011 . . . . . . . . . . . . . . . . . . 164,571 $22.99 $4,085 Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95,370 (58,129) — 24.53 23.08 — Non-vested at December 31, 2012 . . . . . . . . . . . . . . . . . . 201,812 $23.70 $5,094 As of December 31, 2012, there were 4,748,893 common units available for issuance under the CVR Partners LTIP. Unrecognized compensation expense associated with the unvested phantom units as of December 31, 2012 was approximately $3.6 million and is expected to be recognized over a weighted- average period of 1.6 years. Compensation expense recorded for the years ended December 31, 2012 and 2011 related to the awards under the CVR Partners LTIP was approximately $2.2 million and $1.2 million, respectively. Compensation expense related to the awards issued to employees and members of the board of directors of its general partner under the CVR Partners LTIP has been recorded in selling, general and administrative expenses (exclusive of depreciation and amortization). As of December 31, 2012, the Company has a liability of $0.2 million for unvested phantom unit awards related to employees of the Nitrogen Fertilizer Partnership and its subsidiaries for the CVR Partners LTIP, which is recorded in personnel accruals on the Consolidated Balance Sheet. For the year ended December 31, 2012, the Nitrogen Fertilizer Partnership paid cash of $0.3 million to settle liability-classified awards upon vesting. 145 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) (6) Inventories Inventories consisted of the following: Finished goods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Raw materials and precious metals . . . . . . . . . . . . . . . . . . . . . . . . . . . In-process inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Parts and supplies $275,169 164,287 42,767 45,847 $323,315 157,931 115,372 39,603 December 31, 2012 2011 (in thousands) (7) Property, Plant, and Equipment A summary of costs for property, plant, and equipment is as follows: Land and improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Machinery and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Automotive equipment Furniture and fixtures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Leasehold improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Railcars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $528,070 $636,221 December 31, 2012 2011 (in thousands) $ 30,992 40,617 2,089,545 14,969 13,658 2,483 2,496 189,291 2,384,051 601,133 $ 26,136 37,289 1,967,269 10,217 12,349 1,445 2,496 94,085 2,151,286 478,325 $1,782,918 $1,672,961 Capitalized interest recognized as a reduction in interest expense for the years ended December 31, 2012, 2011 and 2010 totaled approximately $10.8 million, $3.9 million and $1.8 million, respectively. Land, building and equipment that are under a capital lease obligation had an original carrying value of approximately $25.1 million, $24.9 million and $5.2 million as of December 31, 2012, 2011 and 2010. Amortization of assets held under capital leases is included in depreciation expense. (8) Goodwill Goodwill and other intangible assets accounting standards provide that goodwill and other intangible assets with indefinite lives are not amortized but instead are tested for impairment on an annual basis. In accordance with these standards, CVR completed its annual test for impairment of goodwill as of November 1 each year. CVR’s annual review was performed only at the nitrogen fertilizer segment, as this is the only reporting unit that has goodwill recorded. For the years ended December 31, 2012, 2011 and 2010, the annual test of impairment indicated that the goodwill, attributable to the nitrogen fertilizer segment, was not impaired. As of December 31, 2012 and 2011, goodwill included on the Consolidated Balance Sheets totaled approximately $41.0 million. 146 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) In testing goodwill for impairment, the Company applied the guidance in ASU 2011-08, which allows an alternative in certain situations that simplifies the impairment testing of goodwill. This guidance allows an entity the option to first perform a qualitative evaluation to determine whether it is necessary to perform the quantitative two-step goodwill impairment analysis. The nitrogen fertilizer segment began the qualitative assessment by analyzing the key drivers and other external factors that impact the business in an attempt to determine if any significant events, transactions or other factors had occurred, or were expected to occur, that would impair earnings or competitiveness; therefore impairing the fair value of the nitrogen fertilizer segment. The key drivers that were considered in the evaluation of the nitrogen fertilizer segment’s fair value included: • general economic conditions; • fertilizer pricing; • input costs; and • customer outlook. After assessing the totality of events and circumstances, it was determined that it was not more likely than not that the fair value of the nitrogen fertilizer segment was less than the carrying value, and so it was not necessary to perform the two-step valuation. (9) Note Payable and Capital Lease Obligations The Company entered into an insurance premium finance agreement in November 2011 to finance a portion of the purchase of its 2011/2012 property insurance policies. The original balance of the note provided by the Company under such agreement was $9.9 million. The Company began to repay this note in equal installments commencing December 1, 2011. As of December 31, 2011, the Company owed approximately $8.8 million related to this note. There were no amounts outstanding as of December 31, 2012. From time to time the Company enters lease agreements for purposes of acquiring assets used in the normal course of business. The majority of the Company’s leases are accounted for as operating leases. As a result of the Wynnewood Acquisition, the Company assumed two leases accounted for as capital leases related to the Magellan Pipeline Terminals, L.P. and Excel Pipeline LLC. The two arrangements have remaining terms of 201 and 202 months, respectively. As of December 31, 2012, the outstanding obligation associated with these arrangements totaled approximately $52.3 million, of which $51.2 million is included in long-term liabilities and $1.1 million is included in current liabilities in the Consolidated Balance Sheet. See Note 12 (‘‘Long-Term Debt’’) for additional information. (10) Insurance Claims Nitrogen Fertilizer Incident On September 30, 2010, the nitrogen fertilizer plant experienced an interruption in operations due to a rupture of a high-pressure UAN vessel. Total costs due to the incident were approximately $11.7 million for repairs and maintenance and other associated costs; approximately $0.3 million, $0.9 million, and $10.5 million of these costs were recognized during the years ended December 31, 2012, 2011 and 2010, respectively, of which approximately $4.9 million were capitalized. The remaining amounts are included in direct operating expenses (exclusive of depreciation and amortization). Approximately $8.0 million of insurance proceeds were received under the property damage insurance claim related to this incident. Approximately $1.0 million, $2.7 million and $4.3 million of these proceeds were received during the years ended December 31, 2012, 2011 and 2010, respectively. 147 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The recording of the insurance proceeds resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization) when received. Total proceeds received for insurance indemnity under the business interruption insurance policy related to the incident were approximately $3.4 million, which was reported in the year ended December 31, 2011. Business interruption insurance proceeds were included in the Consolidated Statements of Operations under Insurance recovery-business interruption. As of December 31, 2012, all property damage and business interruption claims had been fully settled with all claims closed. Coffeyville Refinery Incidents On December 28, 2010 the Coffeyville crude oil refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit (‘‘FCCU’’), which led to reduced crude oil throughput. The refinery returned to full operations on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. Total gross repair and other costs recorded related to the incident as of December 31, 2011 were approximately $8.0 million. No costs were recorded in 2012. The Company maintains property damage insurance policies which have an associated deductible of $2.5 million. As of December 31, 2012 and 2011, the Company had received $4.0 million in insurance proceeds. As of December 31, 2012 and 2011, the Company had recorded an insurance receivable related to the incident of approximately $1.3 million and $1.2 million, respectively. The insurance receivable is included in other current assets in the Consolidated Balance Sheet. The recording of the insurance proceeds and receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization). In February 2013, all insurance claims associated with the FCCU incident were fully settled and closed. Substantially all repair costs incurred in excess of the associated $2.5 million deductible were recovered by insurance. The Coffeyville crude oil refinery experienced a small fire at its continuous catalytic reformer (‘‘CCR’’) in May 2011. Total gross repair and other costs related to the incident that were recorded during the year ended December 31, 2011 approximated $3.2 million. No costs were recorded in 2012. The Company anticipates that substantially all of the costs in excess of the $2.5 million deductible should be covered by insurance under its property damage insurance policy. Approximately $0.7 million of insurance proceeds were received for the year-ended December 31, 2012. As of December 31, 2011, the Company had recorded an insurance receivable of approximately $0.7 million. The insurance receivable is included in other current assets in the Consolidated Balance Sheet. The recording of the insurance receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization). As of December 31, 2012, all insurance claims associated with the fire at the CCR have been fully settled and closed. Substantially all repair costs incurred in excess of the associated $2.5 million deductible were recovered by insurance. (11) Income Taxes On May 19, 2012, CVR became a member of the consolidated federal tax group of American Entertainment Properties Corporation (‘‘AEPC’’), a wholly-owned subsidiary of Icahn Enterprises, 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. 148 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) As of December 31, 2012, the Company has an overpayment of approximately $9.2 million for federal income taxes due to AEPC under the Tax Allocation Agreement, to be applied as a credit against the Company’s estimated tax to be paid during the first quarter of 2013. This amount is recorded as due from affiliate in the Consolidated Balance Sheet. During the year ended December 31, 2012, the Company paid $150.7 million to AEPC under the Tax Allocation Agreement. Income tax expense (benefit) is comprised of the following: Year Ended December 31, 2012 2011 2010 (in thousands) Current Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $237,349 25,369 $141,305 7,972 $13,434 1,262 Total current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 262,718 149,277 14,696 Deferred Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (39,857) 2,723 Total deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (37,134) 40,350 19,936 60,286 808 (1,721) (913) Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . $225,584 $209,563 $13,783 The following is a reconciliation of total income tax expense (benefit) to income tax expense (benefit) computed by applying the statutory federal income tax rate (35%) to pretax income (loss): Tax computed at federal statutory rate . . . . . . . . . . . . . . . . . State income taxes, net of federal tax benefit . . . . . . . . . . . . State tax incentives, net of federal tax expense . . . . . . . . . . . Domestic production activities deduction . . . . . . . . . . . . . . . Non-deductible share-based compensation . . . . . . . . . . . . . . . Non-deductible transaction costs . . . . . . . . . . . . . . . . . . . . . . IRS interest (income)/expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Noncontrolling interest Partnership basis adjustment . . . . . . . . . . . . . . . . . . . . . . . . Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2012 2011 2010 $223,361 23,910 (5,355) (16,467) 7,256 4,208 93 (11,895) — 473 (in thousands) $205,843 20,600 (3,174) (10,562) 2,000 — 34 (11,474) 4,174 2,122 $ 9,826 1,923 (2,382) (2,025) 6,747 — (814) — — 508 Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . $225,584 $209,563 $13,783 The Company earns Kansas High Performance Incentive Program (‘‘HPIP’’) credits for qualified business facility investment within the state of Kansas. CVR recognized a net income tax benefit of approximately $4.5 million, $3.2 million and $2.4 million on a credit of approximately $6.9 million, $4.9 million and $3.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. The Company earns Oklahoma Investment credits for qualified manufacturing facility investment within the state of Oklahoma. CVR recognized a net income tax benefit of approximately $0.9 million on a credit of approximately $1.3 million for the year ended December 31, 2012. 149 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The income tax effect of temporary differences that give rise to significant portions of the deferred income tax assets and deferred income tax liabilities at December 31, 2012 and 2011 are as follows: Deferred income tax assets: Allowance for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . Personnel accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unrealized derivative losses, net . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State tax credit carryforward, net of federal expense . . . . . . . . . . . . Contingent liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total gross deferred income tax assets . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2012 2011 (in thousands) $ 751 12,925 3,606 26,206 2,080 14,425 10,845 — 2,050 72,888 $ 475 6,437 2,097 — 101 17,682 — 76 2,695 29,563 Deferred income tax liabilities: Unrealized derivative gains, net . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant, and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . Investment in CVR Partners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (282,219) (109,701) (1,046) (9,439) (31,990) (224,452) (134,920) — (4,945) Total gross deferred income tax liabilities . . . . . . . . . . . . . . . . . . (402,405) (396,307) Net deferred income tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . $(329,517) $(366,744) At December 31, 2012, CVR has Kansas state income tax credits of approximately $9.8 million, which are available to reduce future Kansas state regular income taxes. These credits, if not used, will expire in 2027 to 2028. Additionally, CVR has Oklahoma state income tax credits of approximately $3.8 million which are available to reduce future Oklahoma state regular income taxes. These credits have an indefinite life. In assessing the realizability of deferred tax assets including credit carryforwards, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Although realization is not assured, management believes that it is more likely than not that all of the deferred tax assets will be realized and thus, no valuation allowance was provided as of December 31, 2012 and 2011. 150 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) A reconciliation of the unrecognized tax benefits for the years ended December 31, 2012, 2011 and 2010 is as follows: Year Ended December 31, 2012 2011 2010 Balance beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Increase based on prior year tax positions . . . . . . . . . . . . . . . . . . Decrease based on prior year tax positions . . . . . . . . . . . . . . . . . . Increases and decrease in current year tax positions . . . . . . . . . . . Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reductions related to expirations of statute of limitations . . . . . . . $ (in thousands) $ — 245 — 245 — — — 17,467 — — — — $17,712 4,755 (30) 14,705 — (193) Balance end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $36,949 $17,712 $245 Included in the balance of unrecognized tax benefits as of December 31, 2012 are $10.4 million of tax benefits that, if recognized, would affect the effective tax rate. The balance of unrecognized tax benefits as of December 2011 and 2010 include no amounts that, if recognized, would affect the effective tax rate. CVR recognizes interest expense (income) and penalties on uncertain tax positions and income tax deficiencies (refunds) in income tax expense. CVR recognized interest expense of $0.5 million and penalties of $0.2 million during 2012. As of December 31, 2012, CVR has recognized a liability for interest of $0.5 million and penalties of approximately $0.2 million. CVR recognized in 2011 approximately $0.1 million of federal and state interest expense and penalties and in total, as of December 31, 2011, had recognized no liability for interest or penalties. CVR recognized interest income in 2010 of approximately $1.3 million related to 2005 and 2006 amended returns to carryback 2007 losses and in total, as of December 31, 2010, had recognized no liability for interest or penalties CVR believes that it is reasonably possible that a decrease of up to $1.5 million in unrecognized tax benefits related to state exposures may be necessary within the coming year. At December 31, 2012, the Company’s tax filings are generally open to examination in the United States for the tax years ended December 31, 2009 through December 31, 2011 and in various individual states for the tax years ended December 31, 2008 through December 31, 2011. 151 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) (12) Long-Term Debt Long-term debt was as follows: 9.0% First Lien Senior Secured Notes, due 2015, net of unamortized premium of $9,003(1) as of December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.875% Second Lien Senior Secured Notes, due 2017, net of unamortized discount of $1,840 and $2,159 as of December 31, 2012 and December 31, 2011, respectively(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5% Second Lien Senior Secured Notes, due 2022 . . . . . . . . . . . . . . . . . . . . . . CRNF credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2012 2011 (in thousands) $ — $456,053 220,910 500,000 125,000 51,168 220,591 — 125,000 52,259 Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $897,078 $853,903 (1) Net unamortized premium of $9.0 million represents an unamortized discount of $0.9 million on the original First Lien Notes and a $9.9 million unamortized premium on the additional First Lien Notes issued in December 2011. (2) All of the Second Lien Notes due 2017 were repaid as of February 2013. Senior Secured Notes On April 6, 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance completed a private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the ‘‘First Lien Notes’’) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the ‘‘Second Lien Notes’’ and together with the First Lien Notes, the ‘‘Old Notes’’). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. The associated original issue discount of the Old Notes was amortized to interest expense and other financing costs over the respective terms of the Old Notes. CRLLC received total net proceeds from the offering of approximately $485.7 million, net of underwriter fees of $10.0 million and original issue discount of approximately $4.0 million and certain third-party fees of $287,000. In addition, CRLLC incurred additional third-party fees and expenses, totaling $3.6 million associated with the offering. Of the underwriters fees and third-party costs, approximately $76,000 and $30,000, respectively were immediately expensed and the remaining approximately $9.9 million and $3.9 million were deferred and amortized as interest expense using the effective-interest method. CRLLC applied the net proceeds to prepay all of the outstanding balance of its tranche D term loan under its first priority credit facility in an amount equal to approximately $453.3 million and to pay related fees and expenses. In accordance with the terms of its first priority credit facility, CRLLC paid a 2.0% premium totaling approximately $9.1 million to the lenders of the tranche D term loan upon the prepayment of the outstanding balance. This amount was recorded as a loss on extinguishment of debt during the second quarter of 2010. This premium was in addition to the 2.0% premium totaling $0.5 million paid in the first quarter of 2010 for voluntary unscheduled prepayments of $25.0 million on CRLLC’s tranche D term loan. This premium was recognized as a loss on extinguishment of debt in the first quarter of 2010. As a result of the extinguishment, CRLLC wrote off $5.4 million of previously deferred financing costs. 152 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) On December 30, 2010, CRLLC made a voluntary unscheduled principal payment of approximately $27.5 million on the First Lien Notes that resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling approximately $1.6 million, which was recognized as a loss on extinguishment of debt in the Consolidated Statements of Operations for the year ended December 31, 2010. On May 16, 2011, CRLLC repurchased $2.7 million of the First Lien Notes at a purchase price of 103.0% of the outstanding principal amount. In connection with the repurchase, CRLLC wrote off a portion of previously deferred financing costs and unamortized original issue discount of approximately $89,000 which is recorded as a loss on extinguishment of debt for the year ended December 31, 2011. CRLLC also recorded additional losses on extinguishment of debt of $81,000 in connection with premiums paid for the repurchase. On December 15, 2011, CRLLC and Coffeyville Finance issued an additional $200.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (‘‘Additional First Lien Notes’’). The Additional First Lien Notes were sold at an issue price of 105.0%, plus accrued interest from October 1, 2011 of $3.7 million. The associated original issue premium of $10.0 million for the Additional First Lien Notes has been amortized to interest expense and other financing costs over the term of the Additional First Lien Notes. The Additional First Lien Notes were offered in connection with CRLLC’s acquisition of WEC. Proceeds of the Additional First Lien Notes were used to partially fund the Wynnewood Acquisition. On November 2, 2011, CRLLC entered into a commitment letter with certain lenders regarding a senior secured one year bridge loan (‘‘the bridge loan’’). CRLLC entered into the commitment letter in connection with ensuring that financing would be available for the Wynnewood Acquisition in the event that the offering of the Additional First Lien Notes was not closed by the date of closing of the Wynnewood Acquisition. Due to the closing of the issuance of the Additional First Lien Notes, the bridge loan was terminated. At the closing of the issuance of the Additional First Lien Notes and the Wynnewood Acquisition, a commitment fee was paid to the lenders who provided the commitment. Other third-party costs were incurred. All costs associated with the undrawn bridge loan were fully expensed. In conjunction with the issuance of the Additional First Lien Notes, CRLLC expanded the existing ABL credit facility (see ‘‘ABL Credit Facility’’ below for further discussion of the expansion and associated accounting treatment) and incurred a commitment fee and other third-party costs associated with the expansion. CRLLC received total net proceeds from the offering of approximately $202.8 million, net of an underwriting discount of $4.0 million, bridge loan commitment and other associated fees of $3.3 million, an ABL commitment fee of $2.6 million, an Additional First Lien Notes structuring fee of $0.2 million, and certain third-party fees of $0.8 million. The related original issue premium and other debt issuance costs related to the Additional First Lien Notes were amortized over the remaining term of the First Lien Notes. Fees and third-party costs totaling $3.9 million related to the undrawn bridge loan were expensed for the year ended December 31, 2011 and are included in selling, general and administrative expenses (exclusive of depreciation and amortization) on the Consolidated Statements of Operations. Fees and third-party costs associated with the ABL credit facility expansion are being amortized over the remaining term of the facility. The First Lien Notes were scheduled to mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. See further discussion below related to the tender and redemption of all the outstanding First Lien Notes in the fourth quarter of 2012. The Second Lien Notes were scheduled to mature on April 1, 2017, unless earlier redeemed or repurchased by the issuers. The indenture governing the Second Lien Notes was satisfied and discharged on January 23, 2013. See Note 22 (‘‘Subsequent Events’’). 153 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Senior Notes Tender Offer The completion of the initial public offering of the Nitrogen Fertilizer Partnership in April 2011 triggered a Fertilizer Business Event (as defined in the indentures governing the Notes). As a result, the issuers were required to offer to purchase a portion of the Old Notes from holders at a purchase price equal to 103.0% of the principal amount plus accrued and unpaid interest. A Fertilizer Business Event Offer was made on April 14, 2011 to purchase up to $100.0 million of the First Lien Notes and the Second Lien Notes in the second quarter of 2011. Approximately $2.7 million of the Old Notes were repurchased, including approximately $0.5 million of First Lien Notes and $2.2 million of Second Lien Notes. The change of control discussed in Note 3 required CVR to make an offer to repurchase all of the Issuers’ outstanding Old Notes; and on June 4, 2012, the Issuers offered to purchase all or any part of the Old Notes, at a cash purchase price of 101% of the aggregate principal amount of the Old Notes, plus accrued and unpaid interest, if any. The offer expired on July 5, 2012 with none of the outstanding Old Notes tendered. 2022 Senior Secured Notes On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the ‘‘2022 Notes’’). The 2022 Notes were issued at par. Refining LLC received approximately $492.5 million of cash proceeds, net of the underwriting fees, but before deducting other third-party fees and expenses associated with the offering. The 2022 Notes are secured by substantially the same assets that secured the outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. A portion of the net proceeds from the offering of the 2022 Notes approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to pay related fees and expenses. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. CRLLC used the remaining proceeds from the offering to fund a completed and settled redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount. Previously deferred financing charges and unamortized original issuance premium related to the First Lien Notes totaled approximately $8.1 million and $6.3 million, respectively. As a result of these transactions, a loss on extinguishment of debt of $33.4 million was recorded in the Consolidated Statement of Operations in the fourth quarter of 2012, which includes the total premiums paid of $31.6 million and write-of off previously deferred financing charges of $8.1 million, partially offset by the write-off of the unamortized original issuance premium of $6.3 million. The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and will be amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. 154 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Included in other current liabilities on the Consolidated Balance Sheet is accrued interest payable totaling approximately $12.2 million and $16.1 million for the years ended December 31, 2012 and 2011, respectively, related to the Old Notes and 2022 Notes. Of the balance at December 31, 2011, $3.7 million represents cash received from the Additional First Lien Notes offering for accrued interest for the period October 1, 2011 through December 15, 2011. At December 31, 2012, the estimated fair value of the Second Lien Notes and 2022 Notes was approximately $243.0 million and $497.5 million, respectively. These estimates of fair value are Level 2 as they were determined by quotations obtained from a broker-dealer who makes a market in these and similar securities. The 2022 Notes are guaranteed by the Refining Partnership, Refining LLC and its existing domestic subsidiaries. Prior to the satisfaction and discharge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, the Nitrogen Fertilizer Partnership and CRNF are not guarantors. Asset-Backed (ABL) Credit Facility On February 22, 2011, CRLLC entered into a $250.0 million asset-backed revolving credit agreement (‘‘ABL credit facility’’) with a group of lenders including Deutsche Bank Trust Company Americas as collateral and administrative agent. The ABL credit facility was scheduled to mature in August 2015 and replaced the $150.0 million first priority credit facility which was terminated. The ABL credit facility was used to finance ongoing working capital, capital expenditures, letters of credit issuance and general needs of the Company and includes among other things, a letter of credit sublimit equal to 90% of the total facility commitment and a feature which permits an increase in borrowings of up to $250.0 million (in the aggregate), subject to additional lender commitments. On December 15, 2011, CRLLC entered into an incremental commitment agreement to increase the borrowings under the ABL credit facility to $400.0 million in the aggregate in connection with the Additional First Lien Notes issuance as discussed above. Terms of the ABL credit facility did not change as a result of the additional availability. On December 20, 2012, the ABL credit facility was amended and restated as further discussed below. There were no borrowings outstanding under the ABL credit facility as of December 31, 2011. Borrowings under the facility bore interest based on a pricing grid determined by the previous quarter’s excess availability. The pricing for borrowings under the ABL credit facility could range from LIBOR plus a margin of 2.75% to LIBOR plus 3.0% or the prime rate plus 1.75% to prime rate plus 2.0% for Base Rate Loans. Availability under the ABL credit facility was determined by a borrowing base formula supported primarily by cash and cash equivalents, certain accounts receivable and inventory. In connection with the ABL credit facility, CRLLC incurred lender and other third-party costs of approximately $9.1 million for the year ended December 31, 2011. These costs were deferred and amortized to interest expense and other financing costs using a straight-line method over the term of the facility. In connection with termination of the first priority credit facility, a portion of the unamortized deferred financing costs associated with this facility, totaling approximately $1.9 million, was written off in the first quarter of 2011. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining approximately $0.8 million of unamortized deferred financing costs associated with the first priority credit facility were amortized over the term of the ABL credit facility. 155 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) In connection with the closing of the Nitrogen Fertilizer Partnership’s initial public offering in April 2011, the Nitrogen Fertilizer Partnership and CRNF were released as guarantors of the ABL credit facility. In connection with the change in control described in Note 3 above, CRLLC, Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent, the lenders and the other parties thereto, entered into a First Amendment to Credit Agreement effective as of May 7, 2012 (the ‘‘ABL First Amendment’’), pursuant to which the parties agreed to exclude Icahn’s acquisition of Shares from the definition of change of control as provided in the ABL credit facility. Absent the ABL First Amendment, the change in control of CVR described above would have triggered an event of default pursuant to the ABL credit facility. Amended and Restated Asset Backed (ABL) Credit Facility On December 20, 2012, CRLLC, CVR Refining, Refining LLC and each of the operating subsidiaries of Refining LLC (collectively, the ‘‘Credit Parties’’) entered into an amended and restated ABL credit agreement (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 replaced the ABL credit facility described above and is scheduled to mature on December 20, 2017. Under the amended and restated facility, the Refining Partnership assumed the Company’s position as borrower and the Company’s obligations under the facility upon the closing of the Refining Partnership’s IPO on January 23, 2013, as further discussed in Note 22 (‘‘Subsequent Events’’). The Amended and Restated ABL Credit Facility is a senior secured asset based revolving credit facility in 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 additional lender commitments and certain other conditions. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Credit Parties and their subsidiaries. The Amended and Restated ABL Credit Facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swingline loans and 90% of the total facility commitment for letters of credit. Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. The Refining Partnership will also be required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable 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 156 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 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 respective subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility. The Credit Parties were in compliance with the covenants of the Amended and Restated ABL Credit Facility as of December 31, 2012. In connection with the Amended and Restated ABL Credit Facility, CRLLC and its subsidiaries incurred lender and other third-party costs of approximately $2.1 million for the year ended December 31, 2012. These costs will be deferred and amortized to interest expense and other financing costs using a straight-line method over the term of the amended facility. In connection with amendment of the ABL credit facility, a portion of the unamortized deferred financing costs associated with the ABL Credit Facility, totaling approximately $4.1 million, were written off in the fourth quarter of 2012. This expense is reflected on the Consolidated Statement of Operations as a loss on extinguishment of debt for the year ended December 31, 2012. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining approximately $2.8 million of unamortized deferred financing costs associated with the ABL credit facility will continue to be amortized over the term of the Amended and Restated ABL Credit Facility. As of December 31, 2012, CRLLC and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $372.3 million and had letters of credit outstanding of approximately $27.7 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of December 31, 2012. Nitrogen Fertilizer Partnership Credit Facility On April 13, 2011, CRNF, as borrower, and the Nitrogen Fertilizer Partnership, as guarantor, entered into a new credit facility with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million, which was undrawn as of December 31, 2012, with an uncommitted incremental facility of up to $50.0 million. No amounts were outstanding under the revolving credit facility at December 31, 2012. There is no scheduled amortization of the credit facility, which matures in April 2016. The carrying value of the Nitrogen Fertilizer Partnership’s debt approximates fair value. The Nitrogen Fertilizer Partnership, upon the closing of the credit facility, made a special distribution of approximately $87.2 million to CRLLC, in order to, among other things, fund the offer to purchase CRLLC’s senior secured notes required upon consummation of the Nitrogen Fertilizer Partnership IPO. The credit facility is used to finance on-going working capital, capital expenditures, letters of credit issuances and general needs of CRNF. Borrowings under the credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the credit facility is the Eurodollar rate plus a margin of 3.50% or, for base rate loans, the prime rate plus 2.50%. Under its terms, the lenders under the credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Nitrogen Fertilizer Partnership. 157 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The credit facility requires 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 creation of liens on assets, the ability to dispose of assets, the ability to make restricted payments, investments and acquisitions, sale-leaseback transactions and affiliate transactions. The credit facility provides that the Nitrogen Fertilizer Partnership can make distributions to holders of its common units provided, among other things, it is in compliance with the leverage ratio and interest coverage ratio on a pro forma basis after giving effect to any distribution and there is no default or event of default under the credit facility. As of December 31, 2012, CRNF was in compliance with the covenants of the credit facility. In connection with the credit facility, the Nitrogen Fertilizer Partnership incurred lender and other third-party costs of approximately $4.8 million for the year ended December 31, 2011. The costs associated with the credit facility have been deferred and are being amortized over the term of the credit facility as interest expense using the effective-interest amortization method for the term loan facility and the straight-line method for the revolving credit facility. Deferred Financing Costs For the years ended December 31, 2012, 2011 and 2010, amortization of deferred financing costs reported as interest expense and other financing costs totaled approximately $5.0 million, $4.9 million and $3.7 million, respectively. Estimated amortization of deferred financing costs is as follows: Year Ending December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred Financing (in thousands) $ 3,687 3,687 3,687 2,995 2,047 4,215 $20,318 Capital Lease Obligations As a result of the Wynnewood Acquisition, the Company acquired certain lease assets and assumed related capital lease obligations related to the Magellan Pipeline Terminals, L.P. and Excel Pipeline LLC. See Note 4 (‘‘Wynnewood Acquisition’’) for further discussion. The underlying assets and related depreciation were 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 202 months remaining through September 2029. See Note 15 (‘‘Commitments and Contingencies’’) for further discussion. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 201 months remaining and will expire in September 2029. 158 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Future payments required under capital lease at December 31, 2012 are as follows: 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2018 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total future payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: amount representing interest Present value of future minimum payments . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capital Lease (in thousands) $ 6,269 6,311 6,355 6,411 6,444 76,756 108,546 56,287 52,259 1,091 Long-term portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 51,168 (13) Earnings Per Share The computations of the basic and diluted earnings per share for the year ended December 31, 2012, 2011 and 2010 are as follows: Net income attributable to CVR Energy stockholders . . . . . . Weighted-average number of shares of common stock For the Year Ended December 31, 2012 2011 2010 (in thousands, except share data) $ 378,605 $ 345,776 $ 14,290 outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86,822,913 86,493,735 86,340,342 Effect of dilutive securities: Non-vested restricted shares . . . . . . . . . . . . . . . . . . . . . . . Stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 567,166 2,191 1,268,471 4,367 448,837 — Weighted-average number of shares of common stock outstanding assuming dilution . . . . . . . . . . . . . . . . . . . . 87,392,270 87,766,573 86,789,179 Basic earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . . . $ $ 4.36 4.33 $ $ 4.00 3.94 $ $ 0.17 0.16 Outstanding stock options totaling 18,533 and 22,900 common shares were excluded from the diluted earnings per share calculation for the years ended December 31, 2011 and 2010, respectively, as they were antidilutive. No stock options were excluded from the diluted earnings per share calculation for the year ended December 31, 2012. (14) Benefit Plans As of December 31, 2012, CVR sponsored three defined-contribution 401(k) plans (the ‘‘Plans’’) for all employees. Participants in the Plans may elect to contribute up to 50% of their annual salaries and up to 100% of their annual income sharing. CVR matches up to 100% of the first 6% of the participant’s contribution for the nonunion plan, 100% of the first 6% of the participant’s contribution 159 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) for the CVR union plan, and 80% on the first 5% of the participant’s contributions plus a 3% employer contribution each pay period for the Wynnewood union plan. All Plans are administered by CVR and contributions for the union plans were determined in accordance with provisions of negotiated labor contracts. Participants in all Plans are immediately vested in their individual contributions. All Plans have a three year vesting schedule for CVR’s matching funds and contain a provision to count service with any predecessor organization. CVR’s contributions under the Plans were approximately $4.5 million, $2.3 million and $2.2 million for the years ended December 31, 2012, 2011 and 2010, respectively. The Wynnewood Union 401(k) Plan became effective with the Wynnewood Acquisition on December 16, 2011. Participants include all Wynnewood union employees. Wynnewood non-union employees are participants in the CVR 401(k) Plan. Beginning April 1, 2013, the Wynnewood Union 401(k) Plan will be merged into the CVR union plan, thereby decreasing the number of defined-contribution 401(k) plans from three to two. The CVR union plan retains its match of 100% of the first 6% of the participant’s contribution. There were no changes to the nonunion plan. (15) Commitments and Contingencies The minimum required payments for CVR’s operating lease agreements and unconditional purchase obligations are as follows: Year Ending December 31, Operating Leases Unconditional Purchase Obligations(1) (in thousands) 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,968 7,804 6,392 5,545 3,192 6,465 $ 123,388 110,011 99,095 92,053 90,770 930,749 $39,366 $1,446,066 (1) This amount includes approximately $1,007.8 million payable ratably over eighteen years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP (‘‘TransCanada’’). Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada’s Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011. CVR leases various equipment, including rail cars, and real properties under long-term operating leases expiring at various dates. For the years ended December 31, 2012, 2011 and 2010, lease expense totaled approximately $7.7 million, $5.1 million and $5.1 million, respectively. 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 will 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. See below for further discussion and related expense of material long-term commitments. 160 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) CRNF has an agreement with the City of Coffeyville (the ‘‘City’’) pursuant to which it must make a series of future payments for the supply, generation and transmission of electricity and City margin based upon agreed upon rates. This agreement has an expiration of July 1, 2019. Effective August 2008 and through July 2010, the City began charging a higher rate for electricity than what had been agreed to in the contract. CRNF filed a lawsuit to have the contract enforced as written and to recover other damages. CRNF paid the higher rates under protest and subject to the lawsuit in order to obtain the electricity. In August 2010, the lawsuit was settled and CRNF received a return of funds totaling approximately $4.8 million. This return of funds was recorded in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations during the third quarter of 2010. In connection with the settlement, the electrical services agreement was amended. CRRM has a Pipeline Construction, Operation and Transportation Commitment Agreement with Plains Pipeline, L.P. (‘‘Plains Pipeline’’) pursuant to which Plains Pipeline constructed a crude oil pipeline from Cushing, Oklahoma to Caney, Kansas. The term of the agreement expires on March 1, 2025. Pursuant to the agreement, CRRM transports approximately 80,000 barrels per day of its crude oil requirements for the Coffeyville refinery at a fixed charge per barrel for the first five years of the agreement and for the remaining fifteen years of the agreement, CRRM must transport all of its non-gathered crude oil up to the capacity of the Plains Pipeline. The rate is subject to a Federal Energy Regulatory Commission (‘‘FERC’’) tariff and is subject to change on an annual basis per the agreement. Lease expense associated with this agreement and included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2012, 2011 and 2010, totaled approximately $12.5 million, $9.8 million and $11.4 million, respectively. During 2005, CRRM entered into a Pipeage Contract with Mid-America Pipeline Company (‘‘MAPL’’) pursuant to which CRRM agreed to ship a minimum quantity of NGLs on an inbound pipeline operated by MAPL between Conway, Kansas and Coffeyville, Kansas. Pursuant to the contract, CRRM is obligated to ship 2.0 million barrels (‘‘Minimum Commitment’’) of NGLs per year at a fixed rate per barrel. All barrels above the Minimum Commitment are at a different fixed rate per barrel. The rates are subject to a tariff approved by the Kansas Corporation Commission (‘‘KCC’’) and are subject to change throughout the term of this contract as ordered by the KCC. In 2012, CRRM and MAPL entered into new one-year pipeage contracts in connection with settlement of a dispute, as discussed in further detail below in the Litigation section. Lease expense associated with MAPL and included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2012, 2011 and 2010, totaled approximately $3.5 million, $1.3 million and $2.4 million, respectively. During 2004, CRRM entered into a Transportation Services Agreement with CCPS Transportation, LLC (‘‘CCPS’’) pursuant to which CCPS reconfigured an existing pipeline (‘‘Spearhead Pipeline’’) to transport Canadian sourced crude oil to Cushing, Oklahoma. The agreement expires March 1, 2016. Pursuant to the agreement and pursuant to options for increased capacity which CRRM has exercised, CRRM is obligated to pay an incentive tariff, which is a fixed rate per barrel for a minimum of 10,000 barrels per day. Lease expense associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2012, 2011 and 2010, totaled approximately $6.1 million, $8.4 million and $16.6 million, respectively. During 2004, CRRM entered into a Terminalling Agreement with Plains Marketing, LP (‘‘Plains’’) whereby CRRM has the exclusive storage rights for working storage, blending, and terminalling services at several Plains tanks in Cushing, Oklahoma. During 2007, CRRM entered into an Amended and Restated Terminalling Agreement with Plains that replaced the 2004 agreement. Pursuant to the 161 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Amended and Restated Terminalling Agreement, CRRM is obligated to pay fees on a minimum throughput volume commitment of 29.2 million barrels per year. Fees are subject to change annually based on changes in the Consumer Price Index (‘‘CPI-U’’) and the Producer Price Index (‘‘PPI-NG’’). Expenses associated with this agreement, included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2012, 2011 and 2010, totaled approximately $2.6 million, $2.4 million and $2.5 million, respectively. The original term of the Amended and Restated Terminalling Agreement expires December 31, 2014, but is subject to annual automatic extensions of one year beginning two years and one day following the effective date of the agreement, and successively every year thereafter unless either party elects not to extend the agreement. Concurrently with the above-described Amended and Restated Terminalling Agreement, CRRM entered into a separate Terminalling Agreement with Plains whereby CRRM has obtained additional exclusive storage rights for working storage and terminalling services at several Plains tanks in Cushing, Oklahoma. CRRM is obligated to pay Plains fees based on the storage capacity of the tanks involved, and such fees are subject to change annually based on changes in the Producer Price Index (‘‘PPI-FG’’ and ‘‘PPI-NG’’). Expenses associated with this Terminalling Agreement totaled approximately $3.4 million, $3.3 million and $3.1 million for 2012, 2011 and 2010, respectively. Select tanks covered by this agreement have been designated as delivery points for crude oil. During 2005, CRNF entered into the Amended and Restated On-Site Product Supply Agreement with The BOC Group, Inc. (as predecessor in interest to Linde LLC). Pursuant to the agreement, which expires in 2020, CRNF is required to take as available and pay approximately $300,000 per month, which amount is subject to annual inflation adjustments, for the supply of oxygen and nitrogen to the fertilizer operation. Expenses associated with this agreement included in direct operating expenses (exclusive of depreciation and amortization) for the years ended December 31, 2012, 2011 and 2010, totaled approximately $4.3 million, $4.2 million and $4.7 million, respectively. During 2006, CRRM entered into a Lease Storage Agreement with Enterprise Crude Pipeline LLC (‘‘Enterprise’’) (as successor in interest to TEPPCO Crude Pipeline, L.P.) whereby CRRM leases tank capacity at Enterprise’s Cushing tank farm in Cushing, Oklahoma. In September 2006, CRRM exercised its option to increase the shell capacity leased at the facility subject to this agreement. Pursuant to the agreement, CRRM is obligated to pay a monthly per barrel fee regardless of the number of barrels of crude oil actually stored at the leased facilities. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2012, 2011 and 2010, totaled approximately $2.4 million, $1.8 million and $1.3 million, respectively. CRRM and Enterprise entered into a new five-year lease agreement for the above-described tank capacity effective March 1, 2011. On October 10, 2008, the Company, through its wholly-owned subsidiaries entered into ten year agreements with Magellan Pipeline Company LP (‘‘Magellan’’) that will allow for the transportation of an additional 20,000 barrels per day of refined fuels from the Company’s Coffeyville, Kansas refinery and the storage of refined fuels on the Magellan system. CRRM commenced usage of the capacity lease in December 2009 and the storage of refined fuels commenced in April 2010. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2012, 2011 and 2010, totaled $2.1 million, $0.7 million and $0.6 million, respectively. On December 15, 2011, the Company consummated the Wynnewood Acquisition, which resulted in the assumption of certain agreements. The Company assumed a throughput and deficiency agreement with Excel Pipeline LLC that expires in 2020. Under the agreement, the Company is obligated to pay a 162 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) tariff fee on the minimum daily volume of crude oil or else pay for any deficiencies. Expenses associated with the throughput and deficiency agreement totaled approximately $3.6 million for the year ended December 31, 2012. CVR Partners entered into a pet coke supply agreement with HollyFrontier Corporation which became effective on March 1, 2012. The initial term ends in December 2013 and the agreement is subject to renewal. Expenses related to the pet coke supply agreement totaled approximately $6.0 million for the year ended December 31, 2012, which was recorded in cost of product sold (exclusive of depreciation and amortization). Crude Oil Supply Agreement On August 31, 2012, CRRM, and Vitol Inc. (‘‘Vitol’’), entered into an Amended and Restated Crude Oil Supply Agreement (the ‘‘Vitol Agreement’’). The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended (the ‘‘Previous Supply Agreement’’). Under the 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 has an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the ‘‘Initial Term’’). Following the Initial Term, the Vitol Agreement will automatically renew for successive one-year terms (each such term, a ‘‘Renewal Term’’) unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of the Initial Term or any Renewal Term. Notwithstanding the foregoing, CRRM has an option to terminate the Vitol Agreement effective December 31, 2013 by providing written notice of termination to Vitol on or before May 1, 2013. 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 within the next year due to uncertainties inherent in litigation and settlement negotiations. 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 consolidated financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate. Samson Resources Company, Samson Lone Star, LLC and Samson Contour Energy E&P, LLC (together, ‘‘Samson’’) filed fifteen lawsuits in federal and state courts in Oklahoma and two lawsuits in state courts in New Mexico against CRRM and other defendants between March 2009 and July 2009. In addition, in May 2010, separate groups of plaintiffs (the ‘‘Anstine and Arrow cases’’) filed two lawsuits against CRRM and other defendants in state court in Oklahoma and Kansas. All of the lawsuits filed in state court were removed to federal court. All of the lawsuits (except for the New Mexico suits, which remained in federal court in New Mexico) were then transferred to the Bankruptcy Court for the United States District Court for the District of Delaware, where the SemGroup 163 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) bankruptcy resides. In March 2011, CRRM was dismissed without prejudice from the New Mexico suits. All of the lawsuits allege that Samson or other respective plaintiffs sold crude oil to a group of companies, which generally are known as SemCrude or SemGroup (collectively, ‘‘Sem’’), which later declared bankruptcy and that Sem has not paid such plaintiffs for all of the crude oil purchased from Sem. The Samson lawsuits further allege that Sem sold some of the crude oil purchased from Samson to J. Aron & Company (‘‘J. Aron’’) and that J. Aron sold some of this crude oil to CRRM. All of the lawsuits seek the same remedy, the imposition of a trust, an accounting and the return of crude oil or the proceeds therefrom. The amount of the plaintiffs’ alleged claims is unknown since the price and amount of crude oil sold by the plaintiffs and eventually received by CRRM through Sem and J. Aron, if any, is unknown. CRRM timely paid for all crude oil purchased from J. Aron. On January 26, 2011, CRRM and J. Aron entered into an agreement whereby J. Aron agreed to indemnify and defend CRRM from any damage, out-of-pocket expense or loss in connection with any crude oil involved in the lawsuits which CRRM purchased through J. Aron, and J. Aron agreed to reimburse CRRM’s prior attorney fees and out-of-pocket expenses in connection with the lawsuits. The indemnification agreement does not provide reimbursement for any damages that CRRM may be liable for in connection with any purchases it made directly from Sem. Samson and CRRM entered a stipulation of dismissal with respect to all of the Samson cases and the Samson cases were dismissed with prejudice on February 8, 2012. In February 2013, CRRM agreed to a settlement in the Anstine and Arrow cases. The settlement will not have a material adverse effect on the consolidated financial statements. On June 21, 2012, Goldman, Sachs & Co. (‘‘GS’’) filed suit against CVR in state court in New York, alleging that CVR failed to pay GS approximately $18.5 million in fees allegedly due to GS by CVR pursuant to an engagement letter dated March 21, 2012, which according to the allegations set forth in the complaint, provided that GS was engaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR’s stock, made by Carl C. Icahn and certain of his affiliates. CVR believes it has meritorious defenses and intends to vigorously defend against the suit. This amount has been fully accrued as of December 31, 2012. On August 10, 2012, Deutsche Bank (‘‘DB’’) filed suit against CVR in state court in New York, alleging that CVR failed to pay DB approximately $18.5 million in fees allegedly due to DB by CVR pursuant to an engagement letter dated March 23, 2012, which according to the allegations set forth in the complaint, provided that DB was engaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR’s stock made by Carl C. Icahn and certain of his affiliates. CVR believes it has meritorious defenses and intends to vigorously defend against the suit. This amount has been fully accrued as of December 31, 2012. On December 17, 2012, Gary Community Investment Company, F/K/A The Gary-Williams Company and GWEC Holding Company, Inc. (referred to herein collectively as ‘‘Gary-Williams’’) filed a lawsuit in the Supreme Court of New York, New York County (Gary Community Investment Co. v. CVR Energy, Inc., No. 654401/12) against CVR and CRLLC (referred to collectively for purposes of this paragraph as ‘‘CVR’’). The action arises out of claims relating to CVR’s purchase of the Wynnewood, Oklahoma refinery pursuant to the Purchase and Sale Agreement entered into by the parties on November 2, 2011 (the ‘‘Purchase Agreement’’). Specifically, CVR provided notice to Gary-Williams that it sought indemnification for various breaches of the Purchase Agreement and subsequently made a claim notice for payment of the entire escrow property pursuant to the Escrow Agreement by an among Gary-Williams, CRLLC, and the escrow agent, dated as of December 15, 2011. Gary-Williams, in its lawsuit, alleges that CVR breached the Purchase Agreement and the Escrow Agreement, and is seeking a declaratory judgment that CVR’s claims are without any legal basis, 164 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) damages in an unspecified amount, and release of the full amount of the escrow property to Gary-Williams. CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with the construction of the nitrogen fertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed CRNF’s nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment resulted in an increase in CRNF’s annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, $11.7 million for the year ended December 31, 2010, $11.4 million for the year ended December 31, 2011, and $11.3 million for the year ended December 31, 2012. CRNF did not agree with the county’s classification of its nitrogen fertilizer plant and protested the classification and resulting valuation for each of those years to the Kansas Court of Tax Appeals, or COTA. However, CRNF has fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2011, 2010, 2009 and 2008 and has estimated and accrued for property tax for the year ended December 31, 2012. The first payment in respect to CRNF’s 2012 property taxes was paid in December 2012 and the second payment will be made in May 2013. This property tax expense is reflected as a direct operating expense in the financial results. In February, 2011, CRNF tried the 2008 case to COTA and in January 2012, COTA issued its decision holding that CRNF’s fertilizer plant was almost entirely real property instead of almost entirely personal property. CRNF disagreed with the ruling and filed a petition for reconsideration with COTA (which was denied) and then filed an appeal to the Kansas Court of Appeals. CRNF also protested the valuation of the CRNF fertilizer plant for tax years 2009 through 2012, which cases remained pending before COTA. On February 25, 2013, Montgomery County and CRNF agreed to a settlement for tax years 2009 through 2012 which generally provides that the nitrogen fertilizer plant will be appraised at a total value of $35.0 million for tax years 2013 through 2016 which will lower CRNF’s property taxes by about $10.5 million per year based on current mill levy rates. In addition, the settlement provides that Montgomery County will not challenge or contest CRNF’s application for a ten year tax exemption pursuant to Kansas law for the UAN expansion and will support the approval of such application by COTA, the reviewing body for such exemption application. Finally, the settlement provides that CRNF will continue its appeal of the 2008 case and that Montgomery County will make a payment to CRNF for the 2008 tax year upon the final conclusion of the appeal, with the amount of the payment to depend on the appeal’s outcome. In addition, on February 25, 2013, CRRM also agreed to a settlement with Montgomery County that generally provides the Coffeyville refinery will be appraised at a total value of $160.0 million for tax years 2013 through 2016. This is a continuation of the settlement CRRM has had with Montgomery County for tax years 2007 through 2012. On July 25, 2011, Mid-America Pipeline Company, LLC (‘‘MAPL’’) filed an application with the Kansas Corporation Commission (‘‘KCC’’) for the purpose of establishing rates (‘‘New Rates’’) effective October 1, 2011 for pipeline transportation service on MAPL’s liquids pipelines running between Conway, Kansas and Coffeyville, Kansas (‘‘Inbound Line’’) and between Coffeyville, Kansas and El Dorado, Kansas (‘‘Outbound Line’’). CRRM ships refined fuels on the Outbound Line and CRRM ships natural gas liquids on the Inbound Line. On April 3, 2012, the parties entered into a Settlement Agreement which resolved the rate dispute both at the KCC and at the U.S. Federal Energy Regulatory Commission (‘‘FERC’’). Among other provisions, the Settlement Agreement provides for pipeage contracts to be entered into between the parties with rates (‘‘Settlement Rates’’) to be established for an initial one year period. The Settlement Rates consist of two components, a base rate and a pipeline integrity cost recovery rate along with an annual take or pay minimum transportation quantity. The 165 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Settlement Rate on the Inbound Line was effective April 1, 2012 and the Settlement Rate on the Outbound Line was effective June 1, 2012. Prior to the end of the initial one year term of the pipeage contracts, and prior to the end of each annual period thereafter until the tenth anniversary of each of the two pipeage contracts, MAPL will provide its estimate of pipeline integrity costs for the upcoming annual period and CRRM may either agree to pay a rate for such upcoming annual period which includes a recovery rate component sufficient to collect such pipeline integrity costs for such upcoming annual period subject to true-up to actual costs at the end of the annual period. FERC rates will be the same as the KCC rates. Flood, Crude Oil Discharge and Insurance Crude oil was discharged from the Company’s Coffeyville refinery on July 1, 2007, due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. In connection with the discharge, the Company received in May 2008, notices of claims from sixteen private claimants under the Oil Pollution Act (‘‘OPA’’) in an aggregate amount of approximately $4.4 million (plus punitive damages). In August 2008, those claimants filed suit against the Company in the United States District Court for the District of Kansas in Wichita (the ‘‘Angleton Case’’). In October 2009 and June 2010, companion cases to the Angleton Case were filed in the United States District Court for the District of Kansas in Wichita, seeking a total of approximately $3.2 million (plus punitive damages) for three additional plaintiffs as a result of the July 1, 2007 crude oil discharge. The Company has settled all of the claims with the plaintiffs from the Angleton Case and has settled all of the claims except for one of the plaintiffs from the companion cases. The settlements did not have a material adverse effect on the consolidated financial statements. The Company believes that the resolution of the remaining claim will not have a material adverse effect on the consolidated financial statements. As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (the ‘‘Consent Order’’) with the U.S. Environmental Protection Agency (the ‘‘EPA’’) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of crude oil from the Company’s Coffeyville refinery caused an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform specified remedial actions to respond to the discharge of crude oil from the Company’s refinery. The substantial majority of all required remedial actions were completed by January 31, 2009. The Company prepared and provided its final report to the EPA in January 2011 to satisfy the final requirement of the Consent Order. In April 2011, the EPA provided the Company with a notice of completion indicating that the Company has no continuing obligations under the Consent Order, while reserving its rights to recover oversight costs and penalties. On October 25, 2010, the Company received a letter from the United States Coast Guard on behalf of the EPA seeking approximately $1.8 million in oversight cost reimbursement. The Company responded by asserting defenses to the Coast Guard’s claim for oversight costs. On September 23, 2011, the United States Department of Justice (‘‘DOJ’’), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking recovery from CRRM related to alleged non-compliance with the Clean Air Act’s Risk Management Program (‘‘RMP’’), the Clean Water Act (‘‘CWA’’) and the OPA. (See ‘‘Environmental, Health and Safety (‘‘EHS’’) Matters’’ below.) CRRM has reached an agreement with the DOJ resolving its claims under CWA and OPA. The agreement is memorialized in a Consent Decree that was filed with the Court on February 12, 2013 (the ‘‘2013 Consent Decree’’). CRRM will pay a civil penalty in the amount of $0.6 million for CWA violations and reimburse the Coast Guard for oversight costs 166 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) under OPA in the amount of $1.7 million. The 2013 Consent Decree also requires CRRM to make upgrades to the Coffeyville refinery, including flood control measures, the installation of river modeling and monitoring procedures, the implementation of a wet weather plan and training employees on proper shutdown procedures during a flood. The parties also reached an agreement to settle DOJ’s RMP claims, but DOJ has re-opened the negotiations. Any liability to DOJ related to the RMP claims is not expected to be material. The Company is seeking insurance coverage for this release and for the ultimate costs for remediation and third-party property damage claims. On July 10, 2008, the Company filed a lawsuit in the United States District Court for the District of Kansas against certain of the Company’s environmental insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. Although the Court has now issued summary judgment opinions that eliminate the majority of the insurance defendants’ reservations and defenses, the Company cannot be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The Company has received $25.0 million of insurance proceeds under its primary environmental liability insurance policy which constitutes full payment to the Company of the primary pollution liability policy limit. The lawsuit with the insurance carriers under the environmental policies remains the only unsettled lawsuit with the insurance carriers related to these events. Environmental, Health, and Safety (‘‘EHS’’) Matters CRRM, Coffeyville Resources Crude Transportation, LLC (‘‘CRCT’’), Coffeyville Resources Terminal, LLC (‘‘CRT’’), Wynnewood Refining Company LLC (‘‘WRC’’), all of which are wholly-owned subsidiaries of the Refining Partnership and CRNF 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, CRCT, WRC and 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 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 OPA 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. 167 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and the now-closed Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). As of December 31, 2012 and 2011, environmental accruals of approximately $2.3 million and $1.9 million, respectively, were reflected in the Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders, for which approximately $0.7 million and $0.5 million, respectively, are included in other current liabilities. Accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at December 31, 2012 and 2011, respectively. The accruals include estimated closure and post-closure costs of approximately $0.8 million and $0.9 million for two landfills at December 31, 2012 and 2011, respectively. The estimated future payments for these required obligations are as follows: Year Ending December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amount (in thousands) $ 724 334 184 127 109 1,056 Undiscounted total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less amounts representing interest at 1.47% . . . . . . . . . . . . . . . . . . . . . . . . . . 2,534 210 Accrued environmental liabilities at December 31, 2012 . . . . . . . . . . . . . . . . $2,324 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. 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, 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. In 2007, the EPA promulgated the Mobile Source Air Toxic II (‘‘MSAT II’’) rule that requires the reduction of benzene in gasoline by 2011. CRRM and WRC are considered to be small refiners under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. However, the change in control resulting from the Icahn Enterprises acquisition in 2012 triggered the loss of small refiner status. Accordingly, the MSAT II projects have been accelerated by three months. Capital expenditures to comply with the rule are expected to be approximately $59.0 million for CRRM and $94.0 million for WRC. 168 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The petroleum business is subject to the Renewable Fuel Standard (‘‘RFS’’) which requires refiners to blend ‘‘renewable fuels’’ in with their transportation fuels or purchase renewable energy credits, known as renewable identification numbers (‘‘RINs’’) in lieu of blending. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. In 2012, about 9% of all fuel used was required to be ‘‘renewable fuel.’’ About 9.6% of all transportation fuel is required to be ‘‘renewable fuel’’ in 2013. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. motor fuel market, there may be a decrease in demand for petroleum products. The petroleum business currently purchases RINs for some fuel categories on the open market as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with RFS. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. The Wynnewood refinery is required to comply beginning in 2013. In the future, the petroleum business likely will be required to purchase additional RINs on the open market or waiver credits from the EPA to comply with RFS. The petroleum business cannot predict the future prices of RINs or waiver credits, but the costs to obtain the necessary number of RINs and waiver credits could likely be material. Additionally, the Coffeyville and Wynnewood refineries may be impacted by increased operating expenses and production costs to meet the mandated renewable fuel volumes to the extent that these increased costs cannot be passed on to the consumers. The EPA is expected to propose ‘‘Tier 3’’ gasoline sulfur standards in 2013. If the EPA were to propose a standard at the level currently being discussed in the pre-proposal phase by the EPA, CRRM will need to make capital expenditures and install controls in order to meet the anticipated new standard. It is not anticipated that the Wynnewood refinery would require additional controls or capital expenditures to meet the anticipated new standard. The Company does not believe that costs associated with the EPA’s proposed Tier 3 rule will be material. In March 2004, CRRM and CRT entered into a Consent Decree (the ‘‘2004 Consent Decree’’) with the EPA and the Kansas Department of Health and Environment (the ‘‘KDHE’’) to resolve air compliance concerns raised by the EPA and KDHE related to Farmland Industries Inc.’s prior ownership and operation of the Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. Under the 2004 Consent Decree, CRRM agreed to install controls to reduce emissions of sulfur dioxide, nitrogen oxides and particulate matter from its FCCU by January 1, 2011. In addition, pursuant to the 2004 Consent Decree, CRRM and CRT assumed clean-up obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities. In March 2012, CRRM entered into a ‘‘Second Consent Decree’’ with the EPA, which replaces the 2004 Consent Decree, as amended (other than certain financial assurance provisions associated with corrective action at the refinery and terminal under RCRA). The Second Consent Decree gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a ‘‘global settlement’’ under the EPA’s ‘‘National Petroleum Refining Initiative.’’ Under the National Petroleum Refining Initiative, the EPA identified industry-wide Non-compliance with four ‘‘marquee’’ issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees imposing civil penalties and requiring the installation of pollution control equipment and enhanced operating procedures. Under the Second Consent Decree, the Company was required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the 2004 Consent Decree, add controls to certain heaters 169 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) and boilers and enhance certain work practices relating to wastewater and fugitive emissions. The remaining costs of complying with the Second Consent Decree are expected to be approximately $41.0 million, of which approximately $39.0 million is expected to be capital expenditures. CRRM also agreed to complete a voluntary environmental project that will reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. The incremental capital expenditures associated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The Second Consent Decree was entered by the U.S. District Court for the District of Kansas on April 19, 2012. WRC’s refinery has not entered into a global settlement with the EPA and the Oklahoma Department of Environmental Quality (the ‘‘ODEQ’’) under the National Petroleum Refining Initiative, although it had discussions with the EPA and the ODEQ about doing so. Instead, WRC entered into a Consent Order with the ODEQ in August 2011 (the ‘‘Wynnewood Consent Order’’). The Wynnewood Consent Order addresses some, but not all, of the traditional marquee issues under the National Petroleum Refining Initiative and addresses certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing A substantial portion of the costs of complying with the Wynnewood Consent Order were expended during the last turnaround. The remaining costs are expected to be $2.0 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ order. The EPA has investigated CRRM’s operation for compliance with the RMP. On September 23, 2011, the DOJ, acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas (in addition to the matters described above, see ‘‘Flood, Crude Oil Discharge and Insurance’’) seeking recovery from CRRM related to alleged non-compliance with the RMP. The Company has reached an agreement with DOJ to settle the RMP claims, but the DOJ re-opened the negotiations. Any liability to DOJ related to the RMP claims is not expected to be material. The lawsuit is stayed while the parties attempt to finalize and file the consent decree. From time to time, the EPA has conducted inspections and issued information requests to CRNF with respect to the Company’s compliance with the RMP and the release reporting requirements under CERCLA and the EPCRA. These previous investigations have resulted in the issuance of preliminary findings regarding CRNF’s compliance status. In the fourth quarter of 2010, following CRNF’s reported release of ammonia from its cooling water system and the rupture of its UAN vessel (which released ammonia and other regulated substances), the EPA conducted its most recent inspection and issued an additional request for information to CRNF. The EPA has not made any formal claims against the Company and the Company has not accrued for any liability associated with the investigations or releases. WRC has entered into a series of Clean Water Act consent orders with ODEQ. The latest Consent Order (the ‘‘CWA Consent Order’’), which supersedes other consent orders, became effective in September 2011. The CWA Consent Order addresses alleged Non-compliance by WRC with its Oklahoma Pollutant Discharge Elimination System permit limits. The CWA Consent Order requires WRC to take corrective action steps, including undertaking studies to determine whether the Wynnewood refinery’s wastewater treatment plant capacity is sufficient. The Wynnewood refinery may need to install additional controls or make operational changes to satisfy the requirements of the CWA 170 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Consent Order. The cost of additional controls, if any, cannot be predicted at this time. However, based on our experience with wastewater treatment and controls, the Company does not anticipate that the costs of any required additional controls or operational changes would be material. Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the years ended December 31, 2012, 2011 and 2010, capital expenditures were approximately $28.4 million, $7.6 million and $13.7 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations. 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 above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations. Wynnewood Refinery Incident On September 28, 2012, the Wynnewood refinery experienced an explosion in a boiler unit that had been temporarily shut down as part of the turnaround process. Two employees were fatally injured. Damage at the refinery was limited to the boiler; process units and other areas of the facility were unaffected. Additionally, there has been no evidence of environmental impact. The refinery was shut down for turnaround maintenance at the time of the incident. The petroleum business completed an internal investigation of the incident and continues to cooperate with OSHA and Oklahoma Department of Labor (‘‘ODL’’) investigations. (16) Fair Value Measurements ASC Topic 820 — Fair Value Measurements and Disclosures (‘‘ASC 820’’) established a single authoritative definition of fair value when accounting rules require the use of fair value, set out a framework for measuring fair value and required additional disclosures about fair value measurements. ASC 820 clarifies that fair value is an exit price, representing the amount from the perspective of a market participant that holds the asset or owes the liability at the measurement date. ASC 820 discusses valuation techniques, such as the market approach (prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities or a group of assets and liabilities such as a business), the income approach (techniques to convert future amounts to a single current amount based on market expectations about those future amounts including present value techniques and option pricing), and the cost approach (amount that would be required currently to replace the service capacity of an asset which is often referred to as a replacement cost). 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) 171 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of December 31, 2012 and 2011: December 31, 2012 Level 1 Level 2 Level 3 Total (in thousands) Location and Description Cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current assets (marketable securities) . . . . . . . . . . . . . Other current assets (other derivative agreements) . . . . . . . . Other long-term assets (other derivative agreements) . . . . . . $ $133,897 38 — — — $ — $133,897 38 — — — 938 938 — — — Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $133,935 $ 938 $ — $134,873 Other current liabilities (other derivative agreements) . . . . . . Other current liabilities (interest rate swap) . . . . . . . . . . . . . Other long-term liabilities (other derivative agreements) . . . . Other long-term liabilities (interest rate swap) . . . . . . . . . . . — (67,747) — (861) — — — — (1,890) — — — (67,747) (861) — (1,890) Total Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $(70,498) $ — $ (70,498) December 31, 2011 Level 1 Level 2 Level 3 Total (in thousands) Location and Description Cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current assets (marketable securities) . . . . . . . . . . . . . . Other current assets (other derivative agreements) . . . . . . . . . Other long-term assets (other derivative agreements) . . . . . . . $187,327 25 — — 63,051 — 18,831 $ — $ — $187,327 25 — 63,051 — 18,831 — Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $187,352 $81,882 $ — $269,234 Other current liabilities (interest rate swap) . . . . . . . . . . . . . . Other long-term liabilities (interest rate swap) . . . . . . . . . . . . (905) — — — (1,483) — (905) (1,483) Total Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ (2,388) $ — $ (2,388) As of December 31, 2012 and 2011, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company’s cash equivalents, available-for-sale marketable securities and derivative instruments. Additionally, the fair value of the Company’s debt issuances is disclosed in Note 12 (‘‘Long-Term Debt’’). The Refining Partnership’s commodity derivative contracts are valued using broker quoted market prices of similar commodity contracts using Level 2 inputs. The Nitrogen Fertilizer Partnership has an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs. The fair value of these interest rate swap instruments are based on discounted cash flow models that incorporate the cash flows of the derivatives, as well as the current LIBOR rate and a forward LIBOR curve, along with other observable market inputs. The Company’s investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair market value using quoted market prices. The Company had no transfers of assets or liabilities between any of the above levels during the year ended December 31, 2012. 172 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) (17) Derivative Financial Instruments Gain (loss) on derivatives, net consisted of the following: Year Ended December 31, 2012 2011 2010 (in thousands) Realized gain (loss) on other derivative agreements . . . . . . . . . . . . . . . Unrealized gain (loss) on other derivative agreements . . . . . . . . . . . . . Realized gain (loss) on interest rate swap agreements . . . . . . . . . . . . . Unrealized gain (loss) on interest rate swap agreements . . . . . . . . . . . . $(137,565) $ (7,182) $ (148,027) — — 721 (2,196) — (2,860) 2,830 — 85,262 Total gain (loss) on derivatives, net . . . . . . . . . . . . . . . . . . . . . . . . . . . $(285,592) $78,080 $(1,505) CVR is 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 Company from time to time enters into various commodity derivative transactions. The Company, as further described below, entered into certain commodity derivate contracts and an interest rate swap as required by the long-term debt agreements. The commodity derivative contracts are for the purpose of managing price risk on crude oil and finished goods and the interest rate swap was for the purpose of managing interest rate risk until September 30, 2010. CVR has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR 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 Consolidated Statements of Operations. CVR 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 Consolidated Balance Sheets. The maintenance margin balance is included within other current assets within the Consolidated Balance Sheets. Dependent upon the position of the open commodity derivatives, the amounts are accounted for as an other current asset or an other current liability within the Consolidated Balance Sheets. From time to time, CVR may be required to deposit additional funds into this margin account. The fair value of the open commodity positions as of December 31, 2012 was a net loss of $14,000 included in other current liabilities. For the year ended December 31, 2012, the Company recognized a realized loss of $10.9 million and an unrealized loss of $0.8 million, which is recorded in loss on derivatives, net in the Consolidated Statement of Operations. Commodity Swap Beginning September 2011, the Company entered into several commodity swap contracts with effective periods beginning in January 2012. 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 Consolidated Balance Sheets with changes in fair value currently recognized in the 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 173 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) at each period end. At December 31, 2012 and 2011, the Company had open commodity hedging instruments consisting of 23.3 million barrels and 13.0 million barrels of crack spreads primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at December 31, 2012 was a net unrealized loss of $66.8 million, $67.7 million of which is included in current liabilities and $0.9 million is included in non-current assets. The fair value of the outstanding contracts at December 31, 2011 was a net unrealized gain of $80.4 million, $61.6 million of which is included in current assets and $18.8 million is included in long-term assets. For the years ended December 31, 2012 and 2011, the Company recognized a realized loss of $126.6 million and $0, respectively, and an unrealized loss of $147.3 million and an unrealized gain of $80.4 million, respectively, which are recorded in loss on derivatives, net in the Consolidated Statements of Operations. In addition, the Company assumed a commodity swap as part of its Wynnewood Acquisition that expired on December 31, 2011. This commodity swap was not designated as a hedge. Nitrogen Fertilizer Partnership Interest Rate Swap On June 30 and July 1, 2011, CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of the nitrogen fertilizer business’ $125.0 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements, which commenced on August 12, 2011 and expires on February 12, 2016, totals $62.5 million (split evenly between the two agreement dates). Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit agreement. At December 31, 2012, the effective rate was approximately 4.58%. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) (‘‘AOCI’’), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense on the Consolidated Statement of Operations. The realized loss on the interest rate swap re-classed from AOCI into interest expense was $1.0 million and $0.4 million for the years ended December 31, 2012 and 2011, respectively. For the years ended December 31, 2012 and 2011, the decrease in the fair value of the interest rate swap agreements of $0.4 million and $2.4 million, respectively, which was unrealized, was recognized in accumulated other comprehensive income. Interest Rate Swap — CRLLC Until June 30, 2010, CRLLC held derivative contracts known as interest rate swap agreements (the ‘‘Interest Rate Swap’’) that converted CRLLC’s floating-rate bank debt into 4.195% fixed-rate debt on a notional amount of $180.0 million from March 31, 2009 until March 31, 2010 and $110.0 million from March 31, 2010 until June 30, 2010. The Interest Rate Swap expired on June 30, 2010. Half of the Interest Rate Swap agreements were held with a related party (as described in Note 18, (‘‘Related Party Transactions’’), and the other half were held with a financial institution that was also a lender under CRLLC’s first priority credit facility until April 6, 2010. 174 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Under the Interest Rate Swap, CRLLC paid the fixed rate of 4.195% and received a floating rate based on three month LIBOR rates, with payments calculated on the notional amount. The notional amount did not represent the actual amount exchanged by the parties but instead represented the amount on which the contracts are based. The Interest Rate Swap was settled quarterly and marked to market at each reporting date with all unrealized gains and losses recognized on the Consolidated Statement of Operations. Transactions related to the Interest Rate Swap agreements were not allocated to the Petroleum or Nitrogen Fertilizer segments. (18) Related Party Transactions In May 2012, Carl C. Icahn and certain of his affiliates (collectively, ‘‘Icahn’’) announced that Icahn 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 December 31, 2012, Icahn owned approximately 82% of all common shares outstanding. See Note 3 (‘‘Change in Control’’) for additional discussion. Until February 2011, the Goldman Sachs Funds and Kelso Funds owned approximately 40% of CVR. On February 8, 2011, GS and Kelso completed a registered public offering, whereby GS sold into the public market its remaining ownership interest in CVR and Kelso substantially reduced its interest in the Company. On May 26, 2011, Kelso completed a registered public offering in which Kelso sold into the market its remaining ownership interest in CVR. As a result of these sales, the Goldman Sachs Funds and Kelso Funds are no longer stockholders of the Company. Lease Since March 2009, the Company, through the Nitrogen Fertilizer Partnership, has leased 200 railcars from American Railcar Leasing LLC, a company controlled by Mr. Carl Icahn, the Company’s majority stockholder. The agreement is scheduled to expire on March 31, 2014. For the year ended December 31, 2012, $1.1 million of rent expense was recorded related to this agreement and is included in cost of product sold (exclusive of depreciation and amortization) in the Consolidated Statements of Operations. Tax Allocation Agreement On May 19, 2012, CVR became a member of the consolidated federal tax group of American Entertainment Properties Corporation (‘‘AEPC’’), a wholly-owned subsidiary of Icahn Enterprises, 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 December 31, 2012, the Company has an overpayment of approximately $9.2 million for federal income taxes due to AEPC under the Tax Allocation Agreement, to be applied as a credit against the Company’s estimated tax to be paid during the first quarter of 2013. During the year ended December 31, 2012, the Company paid $150.7 million to AEPC under the Tax Allocation Agreement. 175 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Insight Portfolio Group (formerly Icahn Sourcing, LLC) Icahn Sourcing, LLC (‘‘Icahn Sourcing’’) is an entity formed and controlled by Mr. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property at negotiated rates. CVR Energy was a member of the buying group in 2012. Prior to December 31, 2012, the Company did not pay Icahn Sourcing any fees or other amounts with respect to the buying group arrangement. In December, 2012, Icahn Sourcing advised CVR Energy that effective January 1, 2013 it would restructure its ownership and change its name to Insight Portfolio Group LLC (‘‘Insight Portfolio Group’’). In connection with the restructuring, 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. The Company projects payments to Insight Portfolio Group will be approximately $0.1 million during 2013. Interest Rate Swap On June 30, 2005, the Company entered into three Interest Rate Swap agreements with J. Aron & Company. Approximately $(16,000) was recognized in gain (loss) on derivatives, net, related to these swap agreements for the year ended December 31, 2010. The Interest Rate Swap expired June 30, 2010. Financing and Other In connection with the Nitrogen Fertilizer Partnership IPO, an affiliate of GS received an underwriting fee of approximately $5.7 million for its role as a joint book-running manager. In April 2011, CRNF entered into a credit facility as discussed further in Note 12 (‘‘Long-Term Debt’’) whereby an affiliate of GS was paid fees and expenses of approximately $2.0 million. In March 2010, CRLLC amended its outstanding first priority credit facility. In connection with the amendment, CRLLC paid a subsidiary of GS fees and expenses of approximately $0.9 million for their services as lead bookrunner. In addition, on April 6, 2010, a subsidiary of GS received a fee of $2.0 million as a participating underwriter upon completion of the issuance of the Old Notes (as described in Note 12 ‘‘Long-Term Debt’’). For the years ended December 31, 2011 and 2010, the Company recognized approximately $0.5 million and $0.7 million, respectively, in expenses for the benefit of GS, Kelso and the president, chief executive officer and chairman of the Board of CVR, in connection with CVR’s Registration Rights Agreement. These amounts included registration and filing fees, printing fees, external accounting fees and external legal fees. (19) 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 ASC Topic 280 — Segment Reporting. All operations of the segments are located within the United States. 176 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 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 the Nitrogen Fertilizer Partnership 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. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in petroleum net sales were approximately $9.9 million, $11.4 million and $4.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales (purchases) described below under ‘‘Nitrogen Fertilizer’’ of approximately $(6.1) million, $13.2 million and $(1.6) million for the years ended December 31, 2012, 2011 and 2010, 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 $10.2 million, $10.7 million and $4.0 million for the years ended December 31, 2012, 2011 and 2010, respectively. Pursuant to the feedstock agreement, the Company’s segments have the right to transfer excess 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. For the years ended December 31, 2012, 2011 and 2010, the net sales generated from intercompany hydrogen sales were $6.3 million, $14.2 million and $0.1 million, respectively. For the year ended December 31, 2012, 2011 and 2010, the nitrogen fertilizer segment also recognized approximately $0.2 million, $1.0 million and $1.8 million, respectively, of cost of product sold related to the transfer of excess hydrogen. As these intercompany sales and cost of product sold are eliminated, there is no financial statement impact on the consolidated financial statements. 177 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Other Segment The Other Segment reflects intercompany eliminations, cash and cash equivalents, certain debt related activities, income tax activities and other corporate activities that are not allocated to the operating segments. Year Ended December 31, 2012 2011 2010 (in thousands) Net sales Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Fertilizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intersegment elimination . . . . . . . . . . . . . . . . . . . . . . . . . . . $8,281,539 302,309 — (16,521) $4,751,826 302,867 — (25,580) $3,903,826 180,468 — (4,526) Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $8,567,327 $5,029,113 $4,079,768 Cost of product sold (exclusive of depreciation and amortization) Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Fertilizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intersegment elimination . . . . . . . . . . . . . . . . . . . . . . . . . . . $6,667,311 46,072 — (16,471) $3,926,632 42,511 — (25,629) $3,538,017 34,328 — (4,227) Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $6,696,912 $3,943,514 $3,568,118 Direct operating expenses (exclusive of depreciation and amortization) Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Fertilizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 426,527 95,614 (66) $ 247,665 86,491 (104) $ 153,112 86,679 — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 522,075 $ 334,052 $ 239,791 Depreciation and amortization Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Fertilizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 107,643 20,723 1,639 $ $ 69,852 18,869 1,600 66,391 18,463 1,907 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 130,005 $ 90,321 $ 86,761 Operating income Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Fertilizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,012,521 115,758 (93,364) $ 465,710 136,198 (35,312) $ 104,564 20,356 (31,856) Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,034,915 $ 566,596 Capital expenditures Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen fertilizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 119,974 82,151 10,069 $ 68,612 19,144 3,468 $ $ 93,064 19,761 10,117 2,531 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 212,194 $ 91,224 $ 32,409 178 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Year Ended December 31, 2012 2011 2010 (in thousands) Total assets Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Fertilizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,258,515 622,954 729,426 $2,322,148 659,309 137,834 $1,049,361 452,165 238,658 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,610,895 $3,119,291 $1,740,184 Goodwill Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Fertilizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ 40,969 — 40,969 — — 40,969 — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 40,969 $ 40,969 $ 40,969 (20) Major Customers and Suppliers Sales to major customers were as follows: Petroleum Customer A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Customer B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Customer C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Fertilizer Customer D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Customer E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2012 2011 2010 10% 9% 8% 27% 10% 10% 20% 15% 12% 9% 36% 17% 12% 29% 14% 11% 10% 35% 12% 10% 22% The Petroleum Segment obtained crude oil from one supplier under a long-term supply agreement during 2012, 2011 and 2010. The crude oil purchased from this supplier is governed by a long-term contract. Purchases contracted as a percentage of the total cost of product sold (exclusive of depreciation and amortization) for each of the periods were as follows: Year Ended December 31, 2012 2011 2010 Petroleum Supplier A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45% 65% 64% The Nitrogen Fertilizer Segment maintains long-term contracts with one supplier. Purchases from this supplier as a percentage of direct operating expenses (exclusive of depreciation and amortization) were as follows: Nitrogen Fertilizer Supplier B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5% 5% 5% Year Ended December 31, 2012 2011 2010 179 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) (21) Selected Quarterly Financial Information (unaudited) Summarized quarterly financial data for December 31, 2012 and 2011. Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating costs and expenses: Cost of product sold (exclusive of Year Ended December 31, 2012 Quarter First Second Third Fourth $ 1,968,631 (in thousands except share data) $ 2,409,624 $ 2,308,318 $ 1,880,754 depreciation and amortization) . . . . . . . . . 1,635,155 1,874,210 1,702,452 1,485,095 Direct operating expenses (exclusive of depreciation and amortization) . . . . . . . . . Selling, general and administrative (exclusive of depreciation and amortization) . . . . . . . Depreciation and amortization . . . . . . . . . . 115,514 94,099 109,929 202,533 45,342 32,112 72,047 32,190 30,390 33,109 35,641 32,594 Total operating costs and expenses . . . . . . 1,828,123 2,072,546 1,875,880 1,755,863 Operating income . . . . . . . . . . . . . . . . . . 140,508 235,772 533,744 124,891 Other income (expense): Interest expense and other financing costs . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Realized loss on derivatives, net Unrealized gain (loss) on derivatives, net . . . Loss on extinguishment of debt . . . . . . . . . . Other income (expense), net . . . . . . . . . . . . Total other income (expense) . . . . . . . . . . Income (loss) before income tax expense . Income tax expense (benefit) . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . Less: Net income attributable to (19,253) 90 (19,086) (128,167) — 117 (166,299) (25,791) (9,746) (16,045) (18,974) 133 (8,069) 46,886 — 709 20,685 256,457 91,099 165,358 (18,962) 292 (53,271) (115,699) — (32) (187,672) 346,072 127,618 218,454 (18,246) 352 (57,139) 48,953 (37,540) 166 (63,454) 61,437 16,613 44,824 noncontrolling interest . . . . . . . . . . . . . 9,157 10,624 9,558 4,647 Net income (loss) attributable to CVR Energy stockholders . . . . . . . . . . . . . . . Net earnings (loss) per share Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted-average common shares outstanding Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ $ (25,202) $ 154,734 (0.29) $ (0.29) $ 1.78 1.75 $ $ $ 208,896 2.41 2.41 $ $ $ 40,177 0.46 0.46 86,808,150 86,808,150 86,821,224 88,454,006 86,831,050 86,831,050 86,831,050 86,831,050 180 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating costs and expenses: Cost of product sold (exclusive of Year Ended December 31, 2011 Quarter First Second Third Fourth $ 1,167,265 (in thousands except share data) $ 1,351,964 $ 1,447,716 $ 1,062,168 depreciation and amortization) . . . . . . . . . 936,822 1,123,375 1,026,040 857,277 Direct operating expenses (exclusive of depreciation and amortization) . . . . . . . . . Insurance recovery — business interruption . Selling, general and administrative (exclusive of depreciation and amortization) . . . . . . . Depreciation and amortization . . . . . . . . . . 68,434 (2,870) 33,262 22,011 66,207 — 18,171 22,043 74,615 (490) 17,584 22,025 124,796 — 28,973 24,242 Total operating costs and expenses . . . . . . 1,057,659 1,229,796 1,139,774 1,035,288 Operating income . . . . . . . . . . . . . . . . . . 109,606 217,920 212,190 26,880 Other income (expense): Interest expense and other financing costs . . Interest income (expense) . . . . . . . . . . . . . . Realized gain (loss) on derivatives, net . . . . . Unrealized gain (loss) on derivatives, net . . . Loss on extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income, net Total other income (expense) . . . . . . . . . . Income before income tax expense . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . Less: Net income attributable to (13,190) 274 (18,848) (3,258) (1,908) 231 (36,699) 72,907 27,119 45,788 (14,205) 211 484 6,448 (170) 246 (6,986) 210,934 76,738 134,196 (13,757) 93 66 (9,991) — 243 (23,346) 188,844 68,603 120,241 (14,657) (89) 11,116 92,063 — 124 88,557 115,437 37,103 78,334 noncontrolling interest . . . . . . . . . . . . . — 9,331 10,976 12,476 Net income attributable to CVR Energy stockholders . . . . . . . . . . . . . . . . . . . . Net earnings per share Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted-average common shares outstanding Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . (22) Subsequent Events Initial Public Offering of CVR Refining, LP $ $ $ 45,788 0.53 0.52 $ $ $ 124,865 1.44 1.42 $ $ $ 109,265 1.26 1.25 $ $ $ 65,858 0.76 0.75 86,413,781 87,783,857 86,422,881 87,789,351 86,549,846 87,743,600 86,852,800 87,746,843 On January 23, 2013, CVR Refining, LP (the ‘‘Refining Partnership’’) completed its initial public offering of its common units representing limited partner interests (the ‘‘Refining Partnership IPO’’). The Refining Partnership sold 24,000,000 common units at a price of $25.00 per unit, resulting in gross 181 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) proceeds of $600.0 million, before giving effect to underwriting discounts and other offering expenses. Of the common units issued, 4,000,000 units were purchased by an affiliate of Icahn Enterprises. Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per common unit resulting in gross proceeds of $90.0 million, before giving effect to underwriting discounts and other offering costs. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol ‘‘CVRR.’’ In connection with the Refining Partnership IPO, the Refining Partnership paid approximately $32.5 million in underwriting fees and incurred approximately $3.9 million of other offering costs. Upon consummation of the Refining Partnership IPO, CVR indirectly owned the Refining Partnership’s general partner and limited partnership interests in the form of common units. Following the Offering, the Refining Partnership has two types of partnership interests outstanding: • common units representing limited partner interests; and • a general partner interest, which is not entitled to any distributions, and which is held by the Refining Partnership’s general partner. The net proceeds from the Refining Partnership IPO of approximately $653.6 million, after deducting underwriting discounts and commissions and offering expenses, have been, or will be, utilized as follows: • approximately $253.0 million was used to repurchase the 10.875% senior secured notes due 2017 (including accrued interest); • approximately $160.0 million will be used to pre-fund certain maintenance and environmental capital expenditures through 2014; • approximately $54.0 million was used to fund the turnaround expenses at the Wynnewood refinery that were incurred during the fourth quarter of 2012; • approximately $85.1 million was distributed to CRLLC; and • the balance of the proceeds are being utilized by the Refining Partnership for general partnership purposes. Subsequent to the Refining Partnership IPO, CVR Energy indirectly owns approximately 81% of the Refining Partnership’s outstanding common units and 100% of the Partnership’s general partner, which holds a non-economic general partner interest. The Refining Partnership’s general partner, CVR Refining GP, LLC, manages the Refining Partnership’s activities subject to the terms and conditions specified in the Refining Partnership’s partnership agreement. The Refining Partnership’s general partner is owned by CVR Refining Holdings. The operations of its general partner, in its capacity as general partner are managed by its board of directors. Actions by its general partner that are made in its individual capacity are made by CVR Refining Holdings as the sole member of the Refining Partnership’s general partner and not by the board of directors of its general partner. The Refining Partnership’s general partner is elected by the Refining Partnership’s unitholders and will not be subject to re-election on a regular basis in the future. The officers of its general partner manage the day-to-day affairs of the business. 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 and 182 CVR Energy, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) will generally be distributed within 60 days of quarter end. 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. In connection with the Initial Public Offering, the Refining Partnership entered into a services agreement, pursuant to which the Refining Partnership and its general partner will obtain certain management and other services from CVR Energy. In addition, by virtue of the fact that the Refining Partnership is a controlled affiliate of CVR Energy, the Refining Partnership is bound by an omnibus agreement entered into by CVR Energy, CVR Partners and the general partner of CVR Partners, pursuant to which the Refining Partnership may not engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as CVR Energy and certain of its affiliates continue to own at least 50% of CVR Partners’ outstanding units. Second Lien Senior Secured Notes Repurchase On January 23, 2013, $253.0 million of the proceeds from the Refining Partnership’s IPO were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million in the first quarter of 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million. Dividend On January 24, 2013, the board of directors of the Company adopted a quarterly cash dividend policy. Subject to declaration by its board of directors, CVR Energy’s initial quarterly dividend is expected to be $0.75 per share, or $3.00 per share on an annualized basis, which the Company plans to begin paying in the second quarter of 2013. In addition, the board of directors of CVR Energy declared a special dividend of $5.50 per share, which was paid on February 19, 2013, to stockholders of record at the close of business on February 5, 2013. The total amount of the special dividend payment was approximately $477.6 million. Nitrogen Fertilizer Partnership Distribution On February 14, 2013, the Nitrogen Fertilizer Partnership paid out a cash distribution to the Nitrogen Fertilizer Partnership’s unitholders of record at the close of business on February 7, 2013 for the fourth quarter of 2012 in the amount of $0.192 per unit, or $14.0 million in aggregate. The Company received $9.8 million in respect of our common units. 183 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures. As of December 31, 2012, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of that evaluation our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’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. Management’s Report On Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (‘‘COSO’’). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the Company’s internal control over financial reporting was effective as of December 31, 2012. Our independent registered public accounting firm, that audited the consolidated financial statements included herein under Item 8, has issued a report on the effectiveness of our internal control over financial reporting. This report can be found under Item 8. 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 December 31, 2012 that has materially affected or is reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information None. 184 Item 10. Directors, Executive Officers and Corporate Governance PART III Information required by this Item regarding our directors, executive officers and corporate governance is included under the captions ‘‘Corporate Governance,’’ ‘‘Proposal 1 — Election of Directors,’’ ‘‘Section 16(a) Beneficial Ownership Reporting Compliance,’’ and ‘‘Stockholder Proposals’’ contained in our proxy statement for the annual meeting of our stockholders, which will be filed with the SEC, and this information is incorporated herein by reference. Item 11. Executive Compensation Information about executive and director compensation is included under the captions ‘‘Corporate Governance — Compensation Committee Interlocks and Insider Participation,’’ ‘‘Proposal 1 — Election of Directors,’’ ‘‘Director Compensation for 2012,’’ ‘‘Compensation Discussion and Analysis,’’ ‘‘Compensation Committee Report’’ and ‘‘Compensation of Executive Officers’’ contained in our proxy statement for the annual meeting of our stockholders, which will be filed with the SEC and this information is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Information about security ownership of certain beneficial owners and management is included under the captions ‘‘Compensation of Executive Officers — Equity Compensation Plan Information’’ and ‘‘Securities Ownership of Certain Beneficial Owners and Officers and Directors’’ contained in our proxy statement for the annual meeting of our stockholders, which will be filed with the SEC, and this information is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions, and Director Independence Information about related party transactions between CVR Energy and its directors, executive officers and 5% stockholders that occurred during the year ended December 31, 2012 is included under the captions ‘‘Certain Relationships and Related Party Transactions’’ and ‘‘Corporate Governance — Director Independence’’ contained in our proxy statement for the annual meeting of our stockholders, which will be filed with the SEC, and this information is incorporated herein by reference. Item 14. Principal Accounting Fees and Services Information about principal accounting fees and services is included under the captions ‘‘Proposal 2 — Ratification of Selection of Independent Registered Public Accounting Firm’’ and ‘‘Fees Paid to the Independent Registered Public Accounting Firm’’ contained in our proxy statement for the annual meeting of our stockholders, which will be filed with the SEC and this information is incorporated herein by reference. 185 Item 15. Exhibits, Financial Statement Schedules (a)(1) Financial Statements PART IV See ‘‘Index to Consolidated Financial Statements’’ Contained in Part II, Item 8 of this Report. (a)(2) Financial Statement Schedules All schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and therefore have been omitted. (a)(3) Exhibits Exhibit Number 2.1** 2.2** 3.1** 3.1.1** 3.2** 4.1** 4.2** 4.3** 4.4** Exhibit Title Stock Purchase and Sale Agreement by and among CVR Energy, Inc., The Gary-Williams Company, Inc., GWEC Holding Company, Inc., Gary-Williams Energy Corporation and Coffeyville Resources, LLC, dated November 2, 2011 (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on December 19, 2011). Transaction Agreement among CVR Energy, Inc., IEP Energy LLC and each of the other Offeror Parties (as defined therein) dated as of April 18, 2012 (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on April 23, 2012). Amended and Restated Certificate of Incorporation of CVR Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended September 30, 2007, filed on December 6, 2007). Certificate of Designations, Rights and Preferences setting forth the terms of the Series A Preferred Stock of CVR Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on January 17, 2012). Amended and Restated Bylaws of CVR Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on July 20, 2011). Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A, File No. 333-137588, filed on June 5, 2007). Indenture, dated as of October 23, 2012, among CVR Refining, LLC, Coffeyville Finance Inc., the Guarantors (as defined therein) and Wells Fargo Bank, National Association, as Trustee and Collateral Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on October 29, 2012). Forms of 6.500% Second Lien Senior Secured Notes due 2022 (included within the Indenture filed as Exhibit 4.2) Registration Rights Agreement, dated October 23, 2012, among CVR Refining, LLC, Coffeyville Finance Inc., the Subsidiary Guarantors, and Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc. as Representatives of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on October 29, 2012). 186 Exhibit Number 4.5** 10.1** 10.2** 10.3** 10.4** 10.5** Exhibit Title Registration Rights Agreement, dated as of January 23, 2013, by and among CVR Refining, LP, Icahn Enterprises Holdings L.P., CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). Amended and Restated ABL Credit Agreement, dated as of December 20, 2012, among Coffeyville Resources, LLC, CVR Refining, LP, CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC and certain of their affiliates, the lenders from time to time party thereto, Wells Fargo Bank, National Association, as collateral agent and administrative agent (incorporated by reference to Exhibit 1.1 to the Company’s Form 8-K filed on December 27, 2012). Amended and Restated ABL Pledge and Security Agreement, dated as of December 20, 2012, among CVR Refining, LP, CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC and certain of their affiliates, and Wells Fargo Bank, National Association, as collateral agent (incorporated by reference to Exhibit 1.2 to the Company’s Form 8-K filed on December 27, 2012). Amended and Restated First Lien Pledge and Security Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Credit Suisse, as collateral agent (incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-1/A, File No. 333-137588, filed on February 12, 2007). ABL Intercreditor Agreement, dated as of February 22, 2011, among Coffeyville Resources, LLC, Coffeyville Finance Inc., Deutsche Bank Trust Company Americas, as collateral agent for the ABL secured parties, Wells Fargo Bank, National Association, as collateral trustee for the secured parties in respect of the outstanding first lien obligations, and the outstanding second lien notes and certain subordinated liens, respectively, and the Guarantors (as defined therein) (incorporated by reference to Exhibit 1.3 to the Company’s Form 8-K filed on February 28, 2011). First Amended and Restated Collateral Trust and Intercreditor Agreement, dated as of April 6, 2010, among Coffeyville Resources, LLC, Coffeyville Finance Inc., the other grantors from time to time party thereto, Credit Suisse AG, Cayman Islands Branch, as administrative agent, Wells Fargo Bank, National Association, as indenture agent, J. Aron & Company, as hedging counterparty, each additional first lien representative and Wells Fargo Bank, National Association, as collateral trustee (incorporated by reference to Exhibit 10.33 to the Company’s Form 10-K for the year ended December 31, 2011, filed on February 29, 2012). 187 Exhibit Number 10.6** 10.7** 10.8** 10.9†** 10.10†** 10.10.1** 10.11†** 10.12†** Exhibit Title Omnibus Amendment Agreement and Consent under the Intercreditor Agreement, dated as of April 6, 2010, by and among Coffeyville Resources, LLC, Coffeyville Finance Inc., Coffeyville Pipeline, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., CL JV Holdings, LLC, and certain subsidiaries of the foregoing as Guarantors, the Requisite Lenders, Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, Collateral Agent and Revolving Issuing Bank, J. Aron & Company, as a hedge counterparty and Wells Fargo Bank, National Association, as Collateral Trustee (incorporated by reference to Exhibit 1.4 to the Company’s Form 8-K filed on April 12, 2010). First and Subordinated Lien Intercreditor Agreement, dated as of April 6, 2010, among Coffeyville Resources, LLC, Wells Fargo Bank, National Association, as collateral agent for the first lien claimholders, and Wells Fargo Bank, National Association, as collateral trustee for itself and the subordinated lien claimholders (incorporated by reference to Exhibit 10.34 to the Company’s Form 10-K for the year ended December 31, 2011, filed on February 29, 2012). Credit and Guaranty Agreement, dated as of April 13, 2011, among Coffeyville Resources Nitrogen Fertilizers, LLC, CVR Partners, LP, the lenders party thereto and Goldman Sachs Lending Partners LLC, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.8 to the Company’s Form 8-K filed on May 23, 2011). License Agreement For Use of the Texaco Gasification Process, Texaco Hydrogen Generation Process, and Texaco Gasification Power Systems, dated as of May 30, 1997 by and between GE Energy (USA), LLC (as successor in interest to Texaco Development Corporation) and Coffeyville Resources Nitrogen Fertilizers, LLC (as successor in interest to Farmland Industries, Inc.), as amended (incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1/A, File No. 333-137588, filed on April 18, 2007). Amended and Restated On-Site Product Supply Agreement dated as of June 1, 2005, between The BOC Group, Inc. (n/k/a Linde LLC) and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-1/A, File No. 333-137588, filed on April 18, 2007). First Amendment to Amended and Restated On-Site Product Supply Agreement, dated as of October 31, 2008, between Coffeyville Resources Nitrogen Fertilizers, LLC and Linde, Inc. (n/k/a Linde LLC) (incorporated by reference to Exhibit 10.3 to the Company’s Form 10-Q for the quarter ended September 30, 2008, filed on November 13, 2008). Amended and Restated Crude Oil Supply Agreement, dated August 31, 2012, by and between Vitol Inc. and Coffeyville Resources Refining & Marketing, LLC (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q for the quarter ended September 30, 2012, filed on November 6, 2012). Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC (incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-1/A, File No. 333-137588, filed on April 18, 2007). 188 Exhibit Number 10.13** 10.14**++ 10.15**++ 10.16**++ 10.17**++ 10.18**++ 10.19** 10.20** 10.21** 10.21.1** 10.21.2** Exhibit Title Amended and Restated Electric Services Agreement dated as of August 1, 2010, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 25, 2010). Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and John J. Lipinski (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011). Third Amended and Restated Employment Agreement, dated as of July 27, 2012, between CVR Energy, Inc. and Susan M. Ball (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended September 30, 2012, filed on November 6, 2012). Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Stanley A. Riemann (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011). Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Edmund S. Gross (incorporated by reference to Exhibit 10.4 to the Company’s Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011). Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Robert W. Haugen (incorporated by reference to Exhibit 10.5 to the Company’s Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011). Second Amended and Restated Agreement of Limited Partnership of CVR Partners, LP, dated April 13, 2011 (incorporated by reference to Exhibit 10.7 to the Company’s Form 8-K/A filed on May 23, 2011). Amended and Restated Contribution, Conveyance and Assumption Agreement, dated as of April 7, 2011, among Coffeyville Resources, LLC, CVR GP, LLC, Coffeyville Acquisition III LLC, CVR Special GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K/A filed on May 23, 2011). Environmental Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.7 to the Company’s Form 10-Q for the quarter ended September 30, 2007, filed on December 6, 2007). Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.17.1 to the Company’s Form 10-K for the year ended December 31, 2007, filed on March 28, 2008). Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended June 30, 2008, filed on August 14, 2008). 189 Exhibit Number 10.22** 10.23** 10.24** 10.25** 10.26** 10.27** 10.28** 10.29** 10.30** 10.31** 10.32** Exhibit Title Amended and Restated Feedstock and Shared Services Agreement, dated as of April 13, 2011, among Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.4 to the Company’s Form 8-K/A filed on May 23, 2011). Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-Q for the quarter ended September 30, 2007, filed on December 6, 2007). Second Amended and Restated Services Agreement, dated as of May 4, 2012, among CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q filed on August 2, 2012). Amended and Restated Omnibus Agreement, dated as of April 13, 2011, among CVR Energy, Inc., CVR GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K/A filed on May 23, 2011). Amended and Restated Registration Rights Agreement, dated as of April 13, 2011, among CVR Partners, LP and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.6 to the Company’s Form 8-K/A filed by on May 23, 2011). Coke Supply Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Company’s Form 10-Q for the quarter ended September 30, 2007, filed on December 6, 2007). Amended and Restated Cross-Easement Agreement, dated as of April 13, 2011, among Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K/A filed on May 23, 2011). GP Services Agreement, dated as of November 29, 2011, among CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.22 to the Form 10-K for the year ended December 31, 2011, filed by CVR Partners, LP on February 24, 2012 (Commission File No. 001-35120)). Trademark License Agreement, dated as of April 13, 2011, among CVR Energy, Inc. and CVR Partners, LP (incorporated by reference to Exhibit 10.9 to the Company’s Form 8-K/A filed on May 23, 2011). Lease and Operating Agreement, dated as of May 4, 2012, between Coffeyville Resources Terminal, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q filed on August 2, 2012). Form of Indemnification Agreement between CVR Energy, Inc. and each of its directors and officers (incorporated by reference to Exhibit 10.49 to the Company’s Form 10-K for the year ended December 31, 2008, filed on March 13, 2009). 10.33**++ Amended and Restated CVR Energy, Inc. 2007 Long Term Incentive Plan, dated as of December 18, 2009 (incorporated by reference to Exhibit 10.28 to the Company’s Form 10-K for the year ended December 31, 2009, filed on March 12, 2010). 10.33.1**++ Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.33.1 to the Company’s Registration Statement on Form S-1/A, File No. 333-137588, filed on June 5, 2007). 190 Exhibit Number Exhibit Title 10.33.2**++ Form of Director Stock Option Agreement (incorporated by reference to Exhibit 10.33.2 to the Company’s Registration Statement on Form S-1/A, File No. 333-137588, filed on June 5, 2007). 10.33.3**++ Form of Director Restricted Stock Agreement (incorporated by reference to Exhibit 10.28.3 to the Company’s Form 10-K for the year ended December 31, 2009, filed on March 12, 2010). 10.33.4**++ Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December 23, 2011). 10.33.5**++ Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 4, 2013). 10.34**++ CVR Partners, LP Long-Term Incentive Plan (adopted March 16, 2011) (incorporated by reference to Exhibit 10.1 to the Form S-8 filed by CVR Partners, LP on April 12, 2011 (Commission File No. 333-173444)). 10.34.1**++ Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.18.4 to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)). 10.34.2**++ Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.18.5 to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)). 10.35**++ 10.36**++ CVR Energy, Inc. Performance Incentive Plan (incorporated by reference to Exhibit 10.24 to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)). CVR Partners, LP Performance Incentive Plan (incorporated by reference to Exhibit 10.24 to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)) 10.37** 10.38** 10.39** 10.40**++ 10.41** Third Amended and Restated Limited Liability Company Agreement of CVR GP, LLC, dated April 13, 2011 (incorporated by reference to Exhibit 3.4 to the Form 10-K for the year ended December 31, 2011 filed by CVR Partners, LP on February 24, 2012 (Commission File No. 001-35120)). First Amended and Restated Agreement of Limited Partnership of CVR Refining, LP, dated as of January 23, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). Contribution Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form S-1/A filed by CVR Refining, LP on January 8, 2013 (Commission File No. 333-184200)). CVR Refining, LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnership’s Form 8-K filed on January 23, 2013 (Commission File No. 001-35781)). Services Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.2 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). 191 Exhibit Number 10.42** 10.43** 10.44** 21.1* 23.1* 31.1* 31.2* 32.1* 101* Exhibit Title Trademark License Agreement, dated as of January 23, 2013, by and among CVR Refining, LP and CVR Energy, Inc. (incorporated by reference to Exhibit 10.3 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). Senior Unsecured Revolving Credit Agreement, dated as of January 23, 2013, by and among CVR Refining, LLC and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). Reorganization Agreement, dated as of January 16, 2013, by and among CVR Refining, LP, CVR Refining GP, LLC, CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by CVR Refining, LP on January 23, 2013 (Commission File No. 001-35781)). List of Subsidiaries of CVR Energy, Inc. Consent of KPMG LLP. Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. Section 1350 Certification of Chief Executive Officer and Chief Financial Officer. The following financial information for CVR Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012, formatted in XBRL (‘‘Extensible Business Reporting Language’’) includes: (1) Consolidated Balance Sheets, (2) Consolidated Statements of Operations, (3) Consolidated Statements of Cash Flows, (4) Consolidated Statement of Changes in Equity, (5) the Notes to Consolidated Financial Statements, tagged in detail.*** * Filed herewith. ** Previously filed. *** Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and is otherwise not subject to liability under these sections. † Certain portions of this exhibit have been omitted and separately filed with the SEC pursuant to a request for confidential treatment which has been granted by the SEC. ++ Denotes management contract or compensatory plan or arrangement. PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Annual Report on Form 10-K. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of 192 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 or its business or operations on the date hereof. 193 Pursuant to the requirements of Section 13 or 15(d) 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. SIGNATURES CVR Energy, Inc. By: /s/ JOHN J. LIPINSKI Name: John J. Lipinski Title: Chief Executive Officer Date: March 14, 2013 Pursuant to the requirements of the Securities Exchange Act of 1934, this Report had been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated. Signature Title Date /s/ JOHN J. LIPINSKI John J. Lipinski /s/ SUSAN M. BALL Susan M. Ball Carl C. Icahn /s/ BOB G. ALEXANDER Bob G. Alexander /s/ SUNGHWAN CHO SungHwan Cho /s/ VINCENT J. INTRIERI Vincent J. Intrieri /s/ SAMUEL MERKSAMER Samuel Merksamer /s/ STEPHEN MONGILLO Stephen Mongillo /s/ DANIEL A. NINNIVAGGI Daniel A. Ninnivaggi /s/ JAMES M. STROCK James M. Strock Chief Executive Officer, President and Director (Principal Executive Officer) March 14, 2013 Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer) March 14, 2013 Chairman of the Board of Directors March 14, 2013 Director March 14, 2013 Director March 14, 2013 Director March 14, 2013 Director March 14, 2013 Director March 14, 2013 Director March 14, 2013 Director March 14, 2013 194 Corporate Information Executive Ofﬁcers John J. Lipinski President and Chief Executive Ofﬁcer Stanley A. Riemann Chief Operating Ofﬁcer Susan M. Ball Chief Financial Ofﬁcer and Treasurer Edmund S. Gross Senior Vice President, General Counsel and Secretary Robert W. Haugen Executive Vice President, Reﬁning Operations Wyatt E. Jernigan Executive Vice President, Crude Oil Acquisition and Petroleum Marketing Christopher G. Swanberg Vice President, Environmental, Health and Safety Directors Carl C. Icahn (Chairman) Bob G. Alexander SungHwan Cho Vincent J. Intrieri John J. Lipinski Samuel Merksamer Stephen Mongillo Daniel A. Ninivaggi James M. Strock m o c . n g i s e d n o s x o r c n g i s e D N O S X O R C Corporate Ofﬁces CVR Energy, Inc. 2277 Plaza Drive, Suite 500 Sugar Land, Texas 77479 Additional copies of CVR Energy’s annual report on Form 10-K, which is ﬁled with the Securities and Exchange Commission (SEC), are available upon request and may be obtained by writing to Investor Relations at the Corporate Ofﬁces. In addition, all company ﬁlings with the SEC, including the 10-K, may be accessed via the Internet at www.CVREnergy.com. Stock Exchange Listing CVR Energy, Inc.’s common stock is listed on the New York Stock Exchange under the ticker symbol “CVI.” Auditor KPMG LLP Houston, Texas Stock Transfer Agent And Registrar American Stock Transfer & Trust Company, LLC 6201 15th Avenue Brooklyn, N.Y. 11219 1-800-937-5449 www.amstock.com Correspondence or questions concerning share holdings, transfers, lost certiﬁcates, dividends, or address or registration changes should be directed to American Stock Transfer & Trust Company. Our selected ﬁnancial information, management’s discussion and analysis of ﬁnancial condition and results of operations, quantitative and qualitative disclosures about market risk, a description of our business, information relating to our industry segments, and information regarding the market price of and dividends on our common equity and related stockholder matters are included in our Form 10-K for the year ended Dec. 31, 2012, which is attached to this annual report. C V R E n e r g y , I n c . 2 0 1 2 A n n u a l R e p o r t 2277 Plaza Drive, Suite 500 Sugar Land, Texas 77479 www.CVREnergy.com

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