Suncoke Energy Partners L.P.
Annual Report 2012

Plain-text annual report

2012 Annual Report Fueling the Future Financial Highlights $ in millions, except per share data Total revenues Operating income Adjusted EBITDA(1) Net income (2) Net income per common share (diluted) (2) Cash and cash equivalents Total assets Long-term debt, including current portion Stockholders’ equity / net parent investment Capital expenditures Coke Operating Data Capacity utilization Domestic sales (in 000s of tons) Domestic coke production (in 000s of tons) International coke production (in 000s of tons) Coal Operating Data Total coal sales (in 000s of tons) Total production (in 000s of tons) 2012 2011 2010 $1,914 $1,539 $1,327 174 266 99 1.40 239 2,011 723 539 81 102% 4,345 4,342 1,209 1,500 1,476 68 139 61 0.87 128 1,942 726 526 238 100% 3,770 3,762 1,442 1,454 1,364 174 234 139 1.99 40 1,718 – 370 216 97% 3,638 3,594 1,636 1,277 1,104 (1) Adjusted EBITDA represents earnings before interest, taxes, depreciation, depletion and amortization, adjusted for sales discounts and the interest, taxes, depreciation, depletion and amortization attributable to equity earnings in our unconsolidated affiliates. (2) For the years presented, reflects net income attributable to SunCoke Energy, Inc. Cokemaking Facilities Highlights Facility Jewell Location Virginia Indiana Harbor Indiana Haverhill Phase 1 Phase 2 Granite City Middletown Vitória (3) Total Ohio Illinois Ohio Brazil Startup Year Number of Coke Ovens 1962 1998 2005 2008 2009 2011 2007 142 268 100 100 120 100 320 1,150 Capacity (in thousands of tons) 720 1,220 550 550 650 550 1,700 5,940 (3) Operated under licensing and operating agreements. Use of Waste Heat Partially used for thermal coal drying Heat for power generation Process steam Power generation Steam for power generation Power generation Steam for power generation Dear Fellow StockholDerS: We made substantial progress in 2012. Our coke fleet performed well, enabling us to meet or exceed our financial targets in spite of continued challenges in our coal business. We are building a strong foundation for growth. As we completed a full year of operations at a new cokemaking facility and drove continuous improvement, we laid promising groundwork for future growth in North America and overseas. We are working to fuel our future. We are building this company to deliver long-term value for you, our investors. There is work to do, but we see a bright future ahead. 1 SunCoke energy 2012 AnnuAl reportSenior Management Team Frederick A. Henderson, Chairman and Chief Executive Officer Michael J. Thomson, President and Chief Operating Officer Mark E. Newman, Senior Vice President and Chief Financial Officer P. Michael Hardesty, Senior Vice President, Sales and Commercial Operations Denise R. Cade, Senior Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer A year of executing on our commitments For SunCoke Energy, 2012 was a very good year. We deliv- On the global front, we announced the signing of a coke- making joint venture agreement with VISA Steel Limited, ered solid performance across our cokemaking operations and a leader in India’s specialty steel, coke and ferrochrome made real progress in laying the foundation for future growth. industries, that we expect to close in early 2013. VISA Steel is a well-run organization that operates a heat recovery coke In my letter to you last year, I said that 2012 would be a plant with steam generation in Odisha, India. This venture year of execution, and that we were on the right path to represents a beachhead for SunCoke in India, a market whose improve earnings, cash flow and returns. Thanks to strong demand for coke is expected to more than double by 2020. contributions from our new Middletown facility, progress at our Indiana Harbor plant and a dedication to operational Our coal business remains a work in progress. While we excellence across the organization, I am very pleased to improved safety and compliance, and upgraded our people say we achieved what we set out to do. and equipment, our continued high production costs negatively impacted the business. As you read this, we have I outlined a few key priorities for 2012: execute the startup accelerated our efforts to reduce costs and improve the of our new Middletown cokemaking facility; advance the productivity, safety, compliance and strategic flexibility of permitting process for a potential new U.S. cokemaking plant; our coal operations. move forward with our international expansion strategy in India; and improve performance in coal operations. Strong financial performance We improved our financial results across the board in 2012. The performance of Middletown and the rest of the fleet Revenues for 2012 were $1.9 billion, up 24 percent over enabled us to exceed our coke production target for 2012, $1.5 billion in 2011. On the strength of our cokemaking reaching 4.3 million tons. Also during the year we advanced business, operating income increased by 157 percent our engineering and design plans for a new U.S. cokemaking year-over-year to $173.7 million, and adjusted EBITDA facility and in early December submitted a permit application was $265.7 million, compared with $138.8 million in 2011. for a potential new site in Kentucky. Earnings per share rose accordingly to $1.40, a 61 percent year-over-year improvement. 2 SunCoke energy 2012 AnnuAl reportDriven by this performance and improvement in working percentage of coal sourced via our Revelation contract mining capital, we generated $120 million in free cash flow in 2012. arrangement as well as open market purchases; and investing We also saw our stock price improve 39 percent during to update key assets for enhanced productivity and yield. the year. MLP: Driving growth in North America In last year’s annual report, we said we would explore manufacturing system for achieving operational excellence that touches every aspect of how we do business. The structuring our domestic coke assets under a Master Limited SunCoke Way will continue to be a foundation for our results A major contributor to our results was the SunCoke Way, our Partnership (MLP) during 2012. In July, our Board approved in 2013 and beyond. the formation of the coke and steel industry’s first-ever MLP—SunCoke Energy Partners, L.P. (trading symbol SXCP). Thank you for your confidence The SunCoke Way cannot succeed without the engagement In January 2013, we completed the initial public offering and commitment of our people. I would like to thank our for 42 percent of SXCP, which owns a 65 percent interest employees for the central role they played in a successful in our Haverhill and Middletown cokemaking facilities. We 2012. I challenged them to “start fast” back in January 2012 are the general partner of the MLP, holding a two percent and they did just that, maintaining the pace and intensity ownership interest and incentive distribution rights, as well of their efforts throughout the year. Thanks also are due as a 56 percent interest in the partnership. to our exceptional Board of Directors, whose support was instrumental in our success in 2012. Finally, I want to thank our We believe SXCP will be value accretive to our existing shareholders for your support as we reinvent our future. assets and provide a cost of capital advantage to fund North American growth. There are still challenges ahead and we have a great deal Continuing our progress in 2013 During the coming year, we will continue to emphasize operational excellence to drive performance. We will largely complete the refurbishment of Indiana Harbor, which should of work to do. But we have generated strong momentum in our first full year as an independent public company, and I fully expect to maintain this pace in the year ahead. generate improved operating results going forward. In Sincerely, terms of our customer, we are confident we will be able to negotiate a contract extension with ArcelorMittal at Indiana Harbor during 2013. In India, we expect to close on our VISA SunCoke joint Chairman and Chief Executive Officer Frederick A. Henderson venture in early 2013. Domestically, we will actively pursue opportunities to leverage our MLP to grow through acquisition, and move forward with permitting efforts for our next U.S. coke plant, which may eventually become a part of our MLP. In our coal business, the focus will be on reducing costs and enhancing our strategic flexibility. This will include rationalizing underground mining operations; increasing the 3 SunCoke energy 2012 AnnuAl reportFueling the Future SunCoke 2012: A year DomeStic coke ProDuction earningS Per Share millions of tons 4.5 3.5 2.5 3.6 3.8 4.3 2010 2011 2012 $1.40 uP 61% 4.5 4.0 3.5 3.0 2.5 2.0 Free caSh Flow beSt-ever StartuP miDDletown coke ProDuction 2012 $120 million in 2012 4 SUNCOKE ENERGy 2012 ANNUAL REPORT 604020thousandsof tons4Q20111Q20122Q20123Q20124Q2012of accomplishment. total coal ProDuction aDjuSteD ebitDa millions of tons 2.0 1.5 1.0 0.5 1.4 1.5 1.1 2010 2011 2012 $266 million uP 91% 2.0 1.5 1.0 0.5 0.0 Public oFFering oF announceD viSa Steel joint venture Partners comPleteD in january 2013 India SUNCOKE ENERGy 2012 ANNUAL REPORT 5 Laying the foundation: A strong first year at Middletown Launching the VISA Steel joint venture Strong first-year performance at our Middletown plant was In 2012, we sharpened our focus on India as the best growth a major contributor to 2012 SunCoke results. Middletown opportunity for SunCoke outside North America. India has achieved 100 percent capacity ahead of schedule, and with an active merchant coke market and with a growing steel start-up costs behind us, we expect this state-of-the-art facility industry, demand for coke is projected to more than double to continue to contribute to SunCoke’s growth in the future. to approximately 62 million tons by 2020. The high cost of Progress at Indiana Harbor India align well with our heat recovery cokemaking expertise. electricity and significant demand for power generation in As we work to complete the refurbishment of Indiana Harbor, we see the plant’s contributions to SunCoke performance increasing over time. We’re beginning to see the results of improvement initiatives at the facility—for example, the new door and lintel design currently being installed is already resulting in improved coal charge. We expect the plant to reach its potential in 2014. The VISA SunCoke JV gives us entry into one of the world’s fastest growing steel markets. We see Middletown and steady improvement at Indiana Harbor as near- term growth drivers. Our joint venture with VISA Steel to form VISA SunCoke, announced in 2012, provides an excellent entry point into India. VISA Steel has a solid reputation in the marketplace and operates a well-maintained, Chinese-designed heat recovery plant with an annual capacity of 400,000 metric tons of high-quality coke. An added bonus is VISA’s stamp-charging 6 SUNCOKE ENERGy 2012 ANNUAL REPORT For future growth SUNCOKE ENERGy 2012 ANNUAL REPORT 7 u.S. anD canaDa coke DemanD u.S. anD canaDa coke aSSet age ProFile 18% SunCoke 5% DTE Energy 6% Other Merchant & Foundry 8% Imports 63% Integrated Steel Producers Total 2011 Coke Demand 19.5 million tons U.S. and Canada (excl. SXC) 37 SunCoke 9 30–40 Years 27% 40+ Years 24% Average Age Percent of U.S. and Canada Coke Production technology, which enables greater use of lower-cost coal This strategy is a potential win-win for our company and blends. VISA SunCoke will have no long-term debt upon customers, enabling us to grow capacity, sales and earnings closing, providing maximum flexibility to support growth while customers benefit from an assured supply of high- strategies in the country. quality coke at competitive prices. Our intention is to apply Growth opportunity: acquisition of operational improvements in by-product coke production North American coke batteries for profitable growth. the SunCoke Way and our cokemaking expertise to realize Another promising avenue for growth opened for SunCoke with the launch in early 2013 of SunCoke Energy Partners, L.P. We formed this MLP to highlight the value of SunCoke’s cokemaking assets and provide a cost of capital advantage to pursue new opportunities, including the potential acquisi- tion of viable existing coke batteries. We have identified approximately 4.1 million tons of annual coke capacity in We believe the MLP will provide a cost of capital advantage to fund domestic growth. North America that may meet our criteria. Permitting a new U.S. plant Acquisition of existing coke batteries represents a domestic growth avenue with significant potential. In the U.S. and Canada, the average age of the steel industry’s-owned coke batteries is 37 years. We believe about 4 million tons of the current North American annual capacity is in batteries that are approaching the end of their useful life and will need to be retired and replaced. We are moving forward with plans to permit a new facility to address that need. 8 SunCoke energy 2012 AnnuAl reportIn December 2012, we submitted a permit application for a prep plant efficiency and yield, and have implemented a site under consideration in Kentucky. Wherever we ultimately disciplined maintenance and operating cost management locate the plant, this will be a next-generation design that system. Longer term, we are evaluating whether to relocate integrates all SunCoke learnings to date, including newly the prep plant closer to coal operations to enhance the developed gas-sharing technology that will enable the facility strategic flexibility of the business. to achieve near-zero bypass venting. Not only will the new plant meet increasingly stringent EPA standards, it also will Fueling SunCoke’s future be engineered for better capital costs, and more operating We are building SunCoke on a solid foundation of opera- efficiency and flexibility. tional excellence and executing a clear, balanced growth strategy. Our U.S. coke production fleet is performing well. Optimizing our coal assets We see further improvement potential at Indiana Harbor. We In the current environment of depressed coal prices, we are have established a foothold in India. Our MLP positions us intensifying efforts within our coal business unit to reduce to grow through acquisitions, our plans for a new U.S. plant costs and enhance strategic flexibility. These efforts include are in motion, and we are moving aggressively to improve consolidating our best people and equipment into the most performance and strategic flexibility in our coal operations. productive mines, in turn idling a number of company-owned We are fueling SunCoke’s future, and that future is looking and contract mines. We are also increasing the amount of brighter than ever. coal we source from our Revelation contract mining arrange- ment and from open market purchases to help manage cash production costs. To improve productivity, we have invested to replace outdated mine equipment and enhance 9 SunCoke energy 2012 AnnuAl reportThe fire within: SunCoke has the people, organizational expertise and capabilities to execute its growth strategies. 10 SUNCOKE ENERGy 2012 ANNUAL REPORT People fuel our future. Industry-leading expertise Committed to our communities Strategies don’t drive performance. People do. From our The well-being of the communities near our facilities is experienced management to our operating and technical always a top priority at SunCoke. We do things the right experts, from customer relationship teams to business way, from compliance with environmental and workplace development specialists, we have built a team at SunCoke safety regulations to open and ongoing communications to execute our growth plans. We have industry-leading with community groups. Our five core values—excellence, competencies in operations, technology, coal science and innovation, commitment, integrity and stewardship—guide engineering, organized into multidisciplinary teams that us as a company and as individuals. Our community involve- include computational, process and technology experts— ment framework, “A Higher Degree of Giving,” aligns our talent and experience to fuel our future. efforts with those values and maximizes the positive impact we have in our communities and our world. The SunCoke Way Operational excellence was a key contributor to 2012 results, and is essential to future success. The SunCoke Way is a set of processes and a way of thinking that harnesses the passion of our people to drive excellence in our operations across the company. By focusing on continuous improvement in safety and environment, operational execution and overall produc- tivity, the SunCoke Way links the efforts and attitudes of our people directly to the financial performance of our company. The SunCoke Way is how we connect the passion of our people to the performance of our company. SUNCOKE ENERGy 2012 ANNUAL REPORT 11 Board of Directors Pictured left to right: Frederick A. Henderson Peter B. Hamilton John W. Rowe Karen B. Peetz James E. Sweetnam Alvin Bledsoe Robert J. Darnall 12 SUNCOKE ENERGy 2012 ANNUAL REPORT Frederick A. Henderson (1) Chairman and Chief Executive Officer, SunCoke Energy, Inc. Karen B. Peetz (2), (4) President, The Bank of New york Mellon Corporation Robert J. Darnall (1), (4) Lead Director Former Chairman, President and Chief Executive Officer, Inland Steel Industries, Inc. Alvin Bledsoe (2) Former Senior Executive, PricewaterhouseCoopers LLP John W. Rowe (3), (4) Former Chairman and Chief Executive Officer, Exelon Corporation James E. Sweetnam (2), (3) Former President and Chief Executive Officer, Dana Holding Corporation Peter B. Hamilton (3) Former Senior Vice President and Chief Financial Officer, Brunswick Corporation (1) Executive Committee (2) Audit Committee (3) Compensation Committee (4) Governance Committee 2012 10-K This page intentionally left blank. UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) È 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 001-35243 SUNCOKE ENERGY, INC. (Exact name of Registrant as specified in its charter) Delaware (State of or other jurisdiction of incorporation or organization) 90-0640593 (I.R.S. Employer Identification No.) 1011 Warrenville Road, Suite 600 Lisle, Illinois (Address of principal executive offices) 60532 (zip code) Registrant’s telephone number, including area code: (630) 824-1000 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 New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes ‘ No È Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes ‘ No È 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 È No ‘ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes È No ‘ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. È 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 È Non-accelerated filer ‘ (Do not check if a smaller reporting company) Accelerated filer Smaller reporting company ‘ Indicate by check mark whether the Registrant is a shell company, as defined in Rule 12b-2 of the Securities Exchange Act ‘ of 1934. Yes ‘ No È The aggregate market value of Common Stock (based upon the June 29, 2012, closing price of $14.65 on the New York Stock Exchange) held by non-affiliates was approximately $1,023,704,320. The number of shares of common stock outstanding as of February 15, 2013 was 70,055,748. Selective portions of the SunCoke Energy, Inc. definitive Proxy Statement, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2012, are incorporated by reference in Part III of this Form 10-K. SUNCOKE ENERGY, INC. TABLE OF CONTENTS PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 2. Item 3. Item 4. PART II Item 5. Item 6. Item 7. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Market for Registrant’s Common Equity, Related Stockholders 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 8. Item 9. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART III Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . Item 14. Principal Accountant Fees Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART IV 1 14 36 36 39 39 40 41 42 77 79 135 135 136 136 136 137 137 Item 15. Exhibits, Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138 Item 1. Business Overview PART I SunCoke Energy, Inc. (“SunCoke Energy”, “Company”, “we”, “our” and “us”) is the largest independent producer of high-quality coke in the Americas, as measured by tons of coke produced each year, and has more than 50 years of coke production experience. Coke is a principal raw material in the blast furnace steelmaking process. Coke is generally produced by heating metallurgical coal in a refractory oven, which releases certain volatile components from the coal, thus transforming the coal into coke. We have designed, developed and built, and own and operate five cokemaking facilities in the United States (“U.S.”) and designed and operate one cokemaking facility in Brazil under licensing and operating agreements on behalf of our customer. Our newest U.S. cokemaking facility in Middletown, Ohio commenced operations in October 2011, bringing our total U.S. cokemaking capacity from approximately 3.7 million tons of coke per year to approximately 4.2 million tons of coke per year. The cokemaking facility that we operate in Brazil has cokemaking capacity of approximately 1.7 million tons of coke per year. We also have a preferred stock investment in the project company that owns the Brazil facility. Our cokemaking ovens utilize efficient, modern heat recovery technology designed to combust the coal’s volatile components liberated during the cokemaking process and use the resulting heat to create steam or electricity for sale. This differs from by-product cokemaking which seeks to repurpose the coal’s liberated volatile components for other uses. We have constructed the only greenfield cokemaking facilities in the U. S. in the last 25 years and are the only North American coke producer that utilizes heat recovery technology in the cokemaking process. We believe that heat recovery technology has several advantages over the alternative by-product cokemaking process, including producing higher quality coke, using waste heat to generate steam or electricity for sale and reducing environmental impact. Our Granite City facility and the first phase of our Haverhill facility, or Haverhill 1, include steam generation facilities which use hot flue gas from the cokemaking process to produce steam. The steam is sold to third-parties pursuant to steam supply and purchase agreements. Our Middletown facility and the second phase of our Haverhill facility, or Haverhill 2, include cogeneration plants that use the hot flue gas created by the cokemaking process to generate electricity. The electricity is either sold into the regional power market or to AK Steel pursuant to energy sales agreements. We own and operate coal mining operations in Virginia and West Virginia that sold approximately 1.3 million tons of metallurgical coal (including internal sales to our cokemaking operations) and 0.2 million tons of thermal coal in 2012. Incorporated in Delaware in 2010 and headquartered in Lisle, Illinois, we became a publicly-traded company in 2011 and our stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “SXC.” As discussed below, our two-step separation (“Separation”) from Sunoco, Inc. (“Sunoco”) was completed in 2012. Our Separation from Sunoco On January 17, 2012 (the “Distribution Date”), we became an independent, publicly-traded company following our separation from Sunoco. Our separation from Sunoco occurred in two steps: • We were formed as a wholly-owned subsidiary of Sunoco. On July 18, 2011 (the “Separation Date”), Sunoco contributed the subsidiaries, assets and liabilities that were primarily related to its cokemaking and coal mining operations to us in exchange for shares of our common stock. As of such date, Sunoco owned 100 percent of our common stock. On July 26, 2011, we completed an initial public offering 1 (“IPO”) of 13,340,000 shares of our common stock, or 19.1 percent of our outstanding common stock. Following the IPO, Sunoco continued to own 56,660,000 shares of our common stock, or 80.9 percent of our outstanding common stock. • On the Distribution Date, Sunoco made a pro-rata, tax free distribution (the “Distribution”) of the remaining shares of our common stock that it owned in the form of a special stock dividend to Sunoco shareholders. Sunoco shareholders received 0.53046456 of a share of common stock for every share of Sunoco common stock held as of the close of business on January 5, 2012, the record date for the Distribution. After the Distribution, Sunoco ceased to own any shares of our common stock. Formation of a Master Limited Partnership On January 24, 2013, we completed the initial public offering of a master limited partnership (“the Partnership”) through the sale of 13,500,000 common units of limited partner interests in the Partnership in exchange for $233.1 million of net proceeds. Of these net proceeds, $67 million was retained by the Partnership for environmental remediation capital expenditures and $12.4 million for sales discounts related to tax credits owed to our customers. Upon the closing of the Partnership offering (“the Partnership offering”), we own the general partner of the Partnership, which consists of a 2 percent ownership interest and incentive distribution rights, and we currently own a 55.9 percent interest in the Partnership. The key assets of the Partnership are 65 percent of our interests in each of our Haverhill and Middletown cokemaking and heat recovery facilities. The operations of the Partnership will be consolidated in our results. We are also party to an omnibus agreement pursuant to which we will provide remarketing efforts to the Partnership upon the occurrence of certain potential adverse events under our coke sales agreements, indemnification of certain environmental costs and preferential rights for growth opportunities. In connection with the closing of the Partnership offering, we repaid $225.0 million of our Term Loan and entered into an amendment to our Credit Agreement. The Partnership issued $150.0 million of Senior Notes and entered into a $100.0 million revolving credit facility. For a more detailed discussion see “Liquidity and Capital Resources.” Business Segments We report our business results through four segments: • Jewell Coke consists of our cokemaking operations located in Vansant, Virginia. • Other Domestic Coke consists of our Indiana Harbor, Haverhill and Granite City cokemaking and heat recovery operations located in East Chicago, Indiana, Franklin Furnace, Ohio and Granite City, Illinois, respectively. Beginning in October 2011, we included the operating results of our Middletown operations located in Middletown, Ohio in the Other Domestic Coke segment. Prior to October 2011, costs associated with the start-up of our Middletown facility were included in the Corporate segment. • International Coke consists of our operations in Vitória, Brazil, where we operate a cokemaking facility for a Brazilian subsidiary of ArcelorMittal. • Coal Mining consists of our metallurgical and thermal coal mining activities conducted in Virginia and West Virginia. In January 2011, we acquired Harold Keene Coal Co., Inc. and its affiliated companies (the “HKCC Companies” or “HKCC”) whose results are included in this segment from the date of acquisition. For additional information regarding our business segments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 24 to our Combined and Consolidated Financial Statements. 2 Cokemaking Operations The following table sets forth information about our cokemaking facilities: Facility Owned and Operated: Jewell Indiana Harbor Haverhill Phase I Phase II Granite City Middletown(1) Total Operated: Vitória Total Location Customer Year of Start Up Contract Expiration Number of Coke Ovens Cokemaking Capacity(1) (thousands of tons) Use of Waste Heat Vansant, Virginia East Chicago, Indiana Franklin Furnace, Ohio Franklin Furnace, Ohio Granite City, Illinois Middletown, Ohio ArcelorMittal 1962 2020 ArcelorMittal 1998 2013 ArcelorMittal 2005 2020 AK Steel 2008 2022 U.S. Steel 2009 2025 AK Steel 2011 2032 Vitória, Brazil ArcelorMittal 2007 2023 142 268 100 100 120 100 830 320 1,150 720 1,220 550 550 650 550 4,240 1,700 5,940 Partially used for thermal coal drying Heat for power generation Process steam Power generation Steam for power generation Power generation Steam for power generation (1) Cokemaking capacity represents stated capacity for production of blast furnace coke. Middletown production and sales volumes are based on “run of oven” capacity, which include both blast furnace coke and small coke. Middletown capacity on a “run of oven” basis is 578 thousand tons per year. We are a technological leader in cokemaking. Our advanced heat recovery cokemaking process has numerous advantages over by-product cokemaking, including producing higher quality coke, using waste heat to generate derivative energy for resale and reducing environmental impact. The Clean Air Act Amendments of 1990 specifically directed the U.S. Environmental Protection Agency (“EPA”) to evaluate our heat recovery coke oven technology as a basis for establishing Maximum Achievable Control Technology (“MACT”), standards for new cokemaking facilities. In addition, each of the four cokemaking facilities that we have built since 1990 has either met or exceeded the applicable Best Available Control Technology (“BACT”), or Lowest Achievable Emission Rate (“LAER”) standards, as applicable, set forth by the EPA for cokemaking facilities. According to CRU, a leading publisher of industry market research, coke demand in the United States and Canada was an estimated 19.5 million tons in 2011. Approximately 90 percent of demand, or 17.5 million tons, was for blast furnace steelmaking operations and the remaining 10 percent was for foundry and other non- steelmaking operations. CRU expects annual blast furnace steelmaking coke demand in the United States and Canada to grow by 2 million tons, or 11 percent, by 2016 driven by a recovery in steel demand over the same time period. Our core business model is predicated on providing steelmakers an alternative to investing capital in their own captive coke production facilities. We direct our marketing efforts principally towards steelmaking customers that require coke for use in their blast furnaces. According to CRU, there is approximately 14.4 million tons of captive cokemaking capacity in the United States and Canada. The average age of capacity at these captive facilities is 36 years, with 24 percent of capacity coming from facilities over 40 years old. As these cokemaking facilities continue to age, they will require replacement, providing us with investment opportunities. In addition, we believe that we may have opportunities to acquire steelmakers’ captive facilities as well as merchant coke producers’ facilities. 3 All our coke sales are made pursuant to long-term take-or-pay agreements with ArcelorMittal, AK Steel and U.S. Steel, who are three of the largest blast furnace steelmakers in North America. These coke sales agreements have an average remaining term of approximately 10 years and contain pass-through provisions for costs we incur in the cokemaking process, including coal procurement costs, subject to meeting contractual coal-to-coke yields, operating and maintenance expenses, costs related to the transportation of coke to our customers, taxes (other than income taxes) and costs associated with changes in regulation. For the years ended December 31, 2012, 2011 and 2010, ArcelorMittal, our largest customer, accounted for approximately 54 percent, 64 percent and 68 percent of our sales and other operating revenue, respectively. The decreased percentage of sales to ArcelorMittal in 2012 reflects the commencement of our Middletown operations in October 2011 and the impact of our settlement in January 2011 with ArcelorMittal regarding the Jewell coke sales agreement described in “Item 3. Legal Proceedings.” For the years ended December 31, 2012, 2011 and 2010, AK Steel accounted for 28 percent, 14 percent and 13 percent, respectively and U.S. Steel accounted for 16 percent, 15 percent and 15 percent of our sales and other operating revenue, respectively. The take-or-pay provisions in our coke sales agreements require that our customers either take all of our coke production up to a specified tonnage maximum or pay the contract price for any such coke they elect not to accept. To date, our customers have always satisfied their obligations under these agreements. With the exception of our Jewell cokemaking facility, where we mine our own coal, all of our current coke sales agreements also provide for the pass-through of actual coal costs on a delivered basis, subject to meeting contractual coal-to-coke yields. The coal cost component of the coke price under the Jewell coke sales agreement reflects a market price for coal based upon third-party coal purchases under our Haverhill contract with ArcelorMittal. These features of our coke sales agreements reduce our exposure to coal price changes over the remaining terms of these agreements. Revenues from our Brazilian cokemaking facility are derived from licensing and operating fees based upon the level of production required by our customer and include the full pass-through of the operating costs of the facility. We also receive an annual preferred dividend on our preferred stock investment in the Brazilian project company that owns the facility. In general, the facility must achieve certain minimum production levels for us to receive the preferred dividend. Recently we have reduced production at our Brazilian cokemaking facility at the request of our customer. This decrease to production does not impact our ability to receive our preferred dividend. Coal Mining Operations Our underground metallurgical coal mining operations are located near our Jewell cokemaking facility. Coal mining production was 1.5 million tons in 2012. As of December 31, 2012, including the HKCC Companies and our contract surface mining agreement with Revelation Energy, LLC (“Revelation”), our mining operations consisted of 13 active underground mines, two active surface mines and one active highwall mine as well as three preparation plants and four load-out facilities in Russell and Buchanan Counties, Virginia and McDowell County, West Virginia. During the first quarter of 2013, two of our active surface mines were idled. Our coal mining operations have historically produced coal that possesses highly desirable coking properties: mid- volatility and low sulfur and ash content. Historically, substantially all of our mined coal has been used internally at our nearby Jewell cokemaking facility or at our other domestic cokemaking facilities. The acquisition of the HKCC Companies has the ability to produce between 250 thousand and 300 thousand tons of coal production annually, with the potential to expand production in the future. HKCC has approximately 20 million tons of proven and probable coal reserves located in Russell and Buchanan Counties in Virginia, contiguous to our existing metallurgical coal mining operations. The operations of our HKCC Companies produce high volatile A and high volatile B metallurgical coals, which can be blended with the mid-volatility coal produced by our existing coal mining operations, and high quality steam coal. In 2011, we engaged Marshall Miller & Associates, Inc., a leading mining engineering firm, to conduct a comprehensive study to determine our proven and probable reserves for our coal mines. This study determined 4 that we control proven and probable coal reserves of approximately 114 million tons as of December 31, 2011. In 2012, we mined over 1 million tons of coal from these proven and probable reserves and at December 31, 2012 control proven and probable coal reserves of approximately 113 million tons. Without the addition of more coal reserves, we expect that our current reserves will sustain production levels through 2062. The majority of our reserves consist of coal seams ranging in thickness from two feet to four and a half feet, with the mining height ranging from three and a half feet to six feet. As a result of these relatively “thin” seams, all of our underground mines are operated via the “room and pillar” method and employ continuous mining equipment. We control a significant portion of our coal reserves through private leases. Substantially all of the leases are “life of mine” agreements that extend our mining rights until all reserves have been recovered. These leases convey mining rights to us in exchange for royalties and/or fixed fee payments. All of the raw coal produced at our Jewell coal mines is trucked to the central preparation plant. The trucking distance to the preparation plant varies by mine but averages approximately 20 miles. The raw coal is then processed through the 800 ton-per-hour preparation plant before it is shipped to our customers via rail, or transported to our adjacent Jewell cokemaking facility via conveyor. The rail loadout facility can load approximately 5,000 tons of coal per day. Most steelmakers require the blending of multiple metallurgical coals, up to eight or more in some cases, to meet coke quality requirements and avoid overexpansion of the coal blend in their coke ovens. Coal expansion can exert pressure on by-product coke ovens causing wall cracking or catastrophic failures. However, our coal can be used as a single coal blend to make high quality coke. When heated, our coal contracts and therefore does not place pressure on coke battery walls. Our coal also possesses other favorable properties generally preferred by customers. Although sulfur content can vary by seam, the average sulfur content of our coal varies between 0.7 percent and 1.0 percent. The ash content in our coal averages between 5.0 percent and 9.5 percent, and the volatile content of our coal ranges between 22 percent and 25 percent. The metallurgical coal produced from our venture with Revelation, has similar quality characteristics. Most of the high volatile A and high volatile B metallurgical coals of the HKCC Companies can be blended with the mid-volatility coal produced by our existing coal mining operations, sold to other companies for blending purposes or marketed as a premium utility coal. Revenues from our Coal Mining operations are currently generated largely from sales of coal to our Jewell cokemaking facility for conversion into coke. Some coal is also sold to our other domestic cokemaking facilities. In 2012, 69 percent of the coal we sold was used at our Jewell cokemaking facility and 8 percent was used at our other domestic cokemaking facilities. In 2011, 72 percent of the coal we sold was used at our Jewell cokemaking facility and 6 percent was used at our other domestic cokemaking facilities. Coal sales to third parties have historically been limited, but have increased as a result of the HKCC acquisition and were 23 percent and 22 percent of coal sold in 2012 and 2011, respectively. Intersegment coal revenues for sales to our Jewell Coke and Other Domestic Coke segments are based on prices that third parties, or coke customers of our Other Domestic Coke segment, have agreed to pay for our coal and which approximate the market price for the applicable quality of metallurgical coal. Most of the coal sales to these third parties and facilities are under contracts with one year terms, and, as a result, coal revenues lag the market for spot coal prices. In June 2011, we entered into a series of coal transactions with Revelation. Under a contract mining agreement, Revelation will mine approximately 1.2 million tons of coal reserves at our Jewell coal mining operations of which 1.0 million tons is included in our current proven and probable reserve estimate as of December 31, 2012. Mining began in the first quarter of 2012, resulting in approximately 180 thousand tons of production, which was lower than expected as a result of permitting delays for a portion of the reserves. We expect the remaining tons to be mined between 2013 and 2015 and anticipate 75 percent of production to be mid- volatility metallurgical coal and 25 percent to be thermal coal. In conjunction with the Revelation agreement, we intended to build a train coal loading facility; however we have deferred the project and are providing load out services to Revelation from our existing facilities. We are evaluating alternatives to this load out facility in conjunction with the potential construction of a new coal preparation plant for our Jewell Coal Mining operations. 5 Coal market conditions deteriorated throughout 2012 and are expected to remain weak in 2013. We have and will continue to take several actions to reduce costs and increase productivity including idling certain high- cost mines; consolidating our labor force and equipment into more productive, lower cost mines; relocating mine sections in our largest mine and implementing deep cut mining plans as permits are received. In addition, we deferred our expansion plans for our Jewell underground mines (“expansion plan”), and substantially all the capital expenditures associated with the expansion plan. Coal mining production was 1.5 million tons in 2012 and we do not anticipate increasing production in 2013. In the fourth quarter of 2012, we negotiated coal sale contracts for 2013 and expect average sales prices in our coal mining segment to decrease approximately $45 to $50 per ton. As a result of these challenges, we expect Adjusted EBITDA for our coal mining segment to range from break-even to a loss of $15 million for 2013. Seasonality Our revenues are tied to long-term take-or-pay contracts, and as such, are not seasonal. However, our profitability is tied to coal-to-coke yields, which improve in drier weather. Accordingly, the coal-to coke yield component of our profitability tends to be more favorable in the third quarter. Raw Materials Metallurgical coal is the principal raw material for our cokemaking operations. Except for our Jewell cokemaking facility, where we internally supply substantially all of the metallurgical coal from our coal mining operations, most of the metallurgical coal used to produce coke at our domestic cokemaking facilities is purchased from third parties. We believe there is an ample supply of metallurgical coal available in the U.S. and worldwide, and we have been able to supply coal to our domestic cokemaking facilities without any significant disruption in coke production. Each ton of coke produced at our facilities requires approximately 1.4 tons of metallurgical coal. In 2012, we purchased 5.1 million tons of metallurgical coal compared to 4.8 million tons in 2011. The increase was due primarily to a full year of production at our Middletown facility. Additionally, our Coal Mining segment mined 1.5 million tons, of which 1.1 million tons were used by our Jewell Coke and Other Domestic Coke segments and 0.4 million tons were sold to third parties. Coal from third parties is generally purchased on an annual basis via one-year contracts with costs passed through to our customers in accordance with the applicable coke sales agreements. From time to time, shortfalls in deliveries by coal suppliers require us to procure supplemental coal volumes. As with typical annual purchases, the cost of these supplemental purchases is also passed through to our customers. Most coal procurement decisions are made through a coal committee structure with customer participation. The customer can generally exercise an overriding vote on most coal procurement decisions. While we generally pass coal costs through to our coke customers, all of our contracts include some form of coal-to-coke yield standard. To the extent that our actual yields are less than the standard in the contract, we are at risk for the cost of the excess coal used in the cokemaking process. Conversely, to the extent actual yields are higher than contractual standards we are able to realize higher margins. Transportation and Freight For inbound transportation of coal purchases, our facilities that access a single rail provider have long-term transportation agreements, and where necessary, coal-blending agreements that run concurrently with the associated coke sales agreement for the facility. At facilities with multiple transportation options, including rail and barge, we enter into short-term transportation contracts from year to year. For coke sales, the point of delivery varies by agreement and facility. The point of delivery for coke sales to subsidiaries of ArcelorMittal from our Jewell and Haverhill cokemaking facilities is generally designated by the customer and shipments are 6 made by railcar under long-term transportation agreements held by us. All delivery costs are passed through to the customers. Sales to AK Steel from our Haverhill cokemaking facility are made with the customer arranging for transportation. At our Middletown, Indiana Harbor and Granite City cokemaking facilities, coke is delivered primarily by a conveyor belt leading to the customer’s blast furnace. External transportation and freight costs are not material to our Coal Mining segment. Research and Development and Intellectual Property and Proprietary Rights Our research and development program seeks to develop promising new cokemaking technologies and improve our heat recovery processes. Over the years, this program has produced numerous patents related to our heat recovery coking design and operation, including patents for pollution control systems, oven pushing and charging mechanisms, oven flue gas control mechanisms and various others. For those cokemaking facilities where we do not own 100 percent of the entity owning the cokemaking facility (Indiana Harbor and Vitória, Brazil), we have licensing agreements in place for the entity’s use of our technology. At Indiana Harbor, we receive no payment for the licensing rights. At Vitória, we receive a licensing fee that is payable in conjunction with the operation of the facility. We have 16 patent applications (one of which has been opposed by the party challenging our existing Brazilian patents) awaiting examination. We expect the approval of certain of these patents will permit the Brazilian licensing agreement to continue through at least 2023. In the future, and especially in international markets, we may develop projects under similar structures where we do not own 100 percent of the facility but operate the facility and license our technology in exchange for fees. In conjunction with the formation of our Partnership, we are party to an omnibus agreement which grants the Partnership a royalty-free license to use the name “SunCoke” and related marks. Additionally, the omnibus agreement grants the Partnership a non-exclusive right to use all of our current and future cokemaking and related technology necessary to their operations. Competition Cokemaking The cokemaking business is highly competitive. Most of the world’s coke production capacity is owned by blast furnace steel companies utilizing by-product coke oven technology. The international merchant coke market is largely supplied by Chinese, Indian, Colombian and Ukrainian producers. Current production from our cokemaking business is largely committed under long-term contracts; therefore, competition mainly affects our ability to obtain new contracts supporting development of additional cokemaking capacity, both in the U. S. and internationally. The principal competitive factors affecting our cokemaking business include coke quality and price, technology, reliability of supply, proximity to market, access to metallurgical coals, and environmental performance. Competitors include by-product coke oven engineering and construction companies, as well as merchant coke producers. Specifically, Chinese and Indian companies have designed and built heat recovery facilities in China, India and Brazil for local steelmakers. Some of these design firms operate only on a local or regional basis while others, such as certain Chinese, German and Italian design companies, operate globally. There are also technologies being developed or in the process of commercialization that seek to produce carbonaceous substitutes for coke in the blast furnace or molten iron without a blast furnace (alternative ironmaking techniques such as direct reduced iron production, or DRI). We monitor the development of competing technologies, and it is unclear to us at this time whether these technologies will be successful in commercialization. 7 We believe we are well-positioned to compete with other coke producers given that our proven, industry- leading technology with many proprietary features allows us to construct cokemaking facilities that, when compared to other proven technologies, produce consistently higher quality coke and produce ratable quantities of heat that can be utilized as industrial grade steam or converted into electrical power. Coal Mining During the last several years, the U.S. coal industry has experienced increased consolidation. Many of our competitors in the domestic coal industry have significantly greater financial resources than we do. Intense competition among coal producers may impact our ability to retain or attract customers and adversely affect our future revenues and profitability. Domestic demand for, and the price of our coal, depends primarily upon metallurgical coal consumption patterns of the domestic steel industry. Metallurgical coal prices are also impacted by global supply and demand factors. The economic stability of the domestic steel industry has a significant effect on the demand for metallurgical coal and the level of competition among metallurgical coal producers. Instability in the domestic steel industry or a reduction in global demand, resulting in a decline in the metallurgical coal market, could materially and adversely affect our future revenues and profitability. The principal competitive factors affecting our coal business include coal quality and characteristics, price, reliability of supply and transportation cost. Employees As of December 31, 2012, we have approximately 1,214 employees in the United States. Approximately 312, or 26 percent, of our domestic employees, principally at our cokemaking operations, are currently represented by the United Steelworkers under various contracts. The labor agreement at our Haverhill facility was recently extended through October 31, 2015. As of December 31, 2012, we have approximately 249 employees at the cokemaking facility in Vitória, Brazil, all of whom are represented by a union under an agreement that expires on November 30, 2013. Legal and Regulatory Requirements The following discussion summarizes the principal legal and regulatory requirements that we believe may significantly affect us. Permitting and Bonding • Permitting Process for Coal Mining Operations. The U.S. coal mining permit application process is initiated by collecting baseline data to adequately characterize, assess and model the pre-mine environmental condition of the permit area, including geologic data, soil and rock structures, cultural resources, soils, surface and ground water hydrology, and coal that we intend to mine. We use all of this data to develop a mine and reclamation plan, which incorporates the provisions of the Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), state programs and complementary environmental programs that impact coal mining. The permit application includes the mine and reclamation plan, documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required by the Office of Surface Mining Reclamation and Enforcement’s (“OSM’s”) Applicant Violator System. Once a permit application is submitted to the regulatory agency, it goes through a completeness and technical review before a public notice and comment period. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine, and often take six months to two years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including through public hearings and intervention in the courts. 8 • • Bonding Requirements for Coal Mining Operations Permits. Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the payment and performance of certain long-term mine closure and reclamation obligations. The costs of these bonds or other forms of financial security have fluctuated in recent years and the market terms of surety bonds generally have become more unfavorable to mine operators. Surety providers are requiring greater amounts of collateral to secure a bond, which has required us to provide increasing quantities of cash to collateralize bonds or other forms of financial security to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by a decrease in the number of companies willing to issue surety bonds. As of December 31, 2012, we have posted an aggregate of approximately $36.2 million in surety bonds or other forms of financial security for reclamation purposes. Permitting Process for Cokemaking Facilities. The permitting process for our cokemaking facilities is administered by the individual states. However, the main requirements for obtaining environmental construction permits are found in the federal regulations. If all requirements are satisfied, a state or local agency produces an initial draft permit. Generally, the facility is allowed to review and comment on the initial draft. After accepting or rejecting the facility’s comments, the agency typically publishes a notice regarding the issuance of the draft permit in a local newspaper or on the internet and makes the permit and supporting documents available for public review and comment. Generally, a public hearing will be scheduled if the project is considered controversial. The EPA also has the opportunity to comment on the draft permit. The state or local agency responds to comments on the draft permit and may make revisions before a final construction permit is issued. A construction permit allows construction and commencement of operations of the facility and is generally valid for 18 months. Generally, construction must commence during this period, while some states allow this period to be extended in certain situations. • • • • • Air quality. Facilities that are major emitters of hazardous air pollutants must employ Maximum Available Control Technology (“MACT”) standards. Specific MACT standards apply to door leaks, charging, oven pressure, pushing and quenching. Certain MACT standards for new cokemaking facilities were developed using test data from our Jewell cokemaking facility located in Vansant, Virginia. Under applicable federal air quality regulations, permitting requirements differ, depending upon whether the cokemaking facility will be located in an “attainment” area—i.e., one that meets the national ambient air quality standards (“NAAQS”) for certain pollutants, or in a “non-attainment” area: In an attainment area, the facility must install air pollution control equipment or employ Best Available Control Technology (“BACT”). The facility must demonstrate, using air dispersion modeling, that the area will still meet NAAQS after the facility is constructed. An “additional impacts analysis” must be performed to evaluate the effect of the new facility on air, ground and water pollution. In a non-attainment area, the facility must install air pollution control equipment or employ procedures that meet Lowest Achievable Emission Rate (“LAER”) standards. LAER standards are the most stringent emission limitation achieved in practice by existing facilities. Unlike the BACT analysis, cost is generally not considered as part of a LAER analysis. Emissions of any pollutant in a non-attainment area must be offset by emission reductions obtained from existing sources located in the vicinity of the facility. Two new and more stringent NAAQS for ambient nitrogen dioxide and sulfur dioxide went into effect in 2010. In 2012, a new and more stringent NAAQS for fine particulate matter, or PM 2.5, went into effect. These new standards have two impacts on permitting: (1) demonstrating compliance using dispersion modeling from a new facility will be more difficult and (2) additional areas of the country will become non-attainment areas. New facilities in those non-attainment areas will have to obtain offsets and install air pollution control equipment or employ procedures that meet LAER standards. In September 2011, the EPA withdrew reconsideration of a new, lower NAAQS for ground level ozone promulgated in March 2008. Based on this decision, under the Clean Air Act, the EPA will be required to review and potentially issue a new NAAQS for ground level ozone in 2013. Designation of new non- attainment areas for the revised ozone NAAQS may result in additional federal and state regulatory 9 • • actions that could impact our operations and the operations of our customers and increase the cost of additions to property, plant and equipment. The EPA finalized a new rule in 2010 requiring a new facility that is a major source of greenhouse gases (primarily carbon dioxide from our facilities) (“GHGs”) to install equipment or employ BACT procedures. Currently, there is little information on what may be acceptable as BACT to control GHGs, but the database and additional guidance may be enhanced in the future. Several states have additional requirements and standards other than those in the federal statutes and regulations. Many states have lists of “air toxics” with emission limitations determined by dispersion modeling. States also often have specific regulations that deal with visible emissions, odors and nuisance. In some cases, the state delegates some or all of these functions to local agencies. • Wastewater and Stormwater. Our heat recovery cokemaking technology does not produce process wastewater as is typically associated with by-product cokemaking. Our cokemaking facilities, in some cases, have wastewater discharge and stormwater permits. • Waste. The primary solid waste product from our heat recovery cokemaking technology is calcium sulfate from the flue gas desulfurization operation, which is generally taken to a solid waste landfill. The material from periodic cleaning of heat recovery steam generators is disposed of as hazardous waste. On the whole, our heat recovery cokemaking process does not generate substantial quantities of hazardous waste. • U.S. Endangered Species Act. The U.S. Endangered Species Act and certain counterpart state legislations are intended to protect species whose populations allow for categorization as either endangered or threatened. With respect to permitting additional cokemaking facilities, protection of endangered or threatened species may have the effect of prohibiting, limiting the extent of or placing permitting conditions on soil removal, road building and other activities in areas containing the associated species. Based on the species that have been identified on our properties and the current application of these laws and regulations, we do not believe that they are likely to have a material adverse effect on our operations. Regulation of Operations • • Clean Air Act. The Clean Air Act and similar state laws and regulations affect our cokemaking operations, primarily through permitting and/or emissions control requirements relating to particulate matter (“PM”) and sulfur dioxide (“SO2”) control. The Clean Air Act imposes stringent limits on air emissions with a federally mandated operating permit program and civil and criminal enforcement sanctions. The Clean Air Act air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to: the Acid Rain Program; NAAQS implementation for SO2, PM and nitrogen oxides (“NOx”); GHG rules; the Clean Air Interstate Rule; MACT emissions limits for hazardous air pollutants; the Regional Haze Program; New Source Performance Standards (“NSPS”); and New Source Review. The Clean Air Act requires, among other things, the regulation of hazardous air pollutants through the development and promulgation of various industry-specific MACT standards. Our cokemaking facilities are subject to two categories of MACT standards. The first category applies to pushing and quenching. The EPA is required to make a risk-based determination for pushing and quenching emissions and determine whether additional emissions reductions are necessary for these processes. The EPA was supposed to do so by 2011, but the EPA has yet to publish or propose any residual risk standards from these operations; therefore, the impact cannot be estimated at this time. The second category of MACT standards applicable to our cokemaking facilities applies to emissions from charging and coke oven doors. Clean Water Act of 1972. The Clean Water Act (“CWA”) may affect our operations by requiring water quality standards generally and through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. Additionally, through the CWA Section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. 10 • • • Resource Conservation and Recovery Act. We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements. Comprehensive Environmental Response, Compensation, and Liability Act. Under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as Superfund, and similar state laws, responsibility for the entire cost of clean-up of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. In the course of our operations we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We also may be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. Under CERCLA, we may be responsible for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act. Climate Change Legislation and Regulations. Our facilities are presently subject to the GHG reporting rule, which obligates us to report annual emissions of GHGs. EPA has issued a notice of finding and determination that emissions of carbon dioxide and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the Clean Air Act. We may also be subject to EPA’s “Tailoring Rule,” where certain modifications to our facilities could subject us to the additional permitting and other obligations under the New Source Review/Prevention of Significant Deterioration (NSR/PSD) and Title V programs of the Clean Air Act based on a facility’s GHG emissions. Numerous other proposals for federal and state legislation have been made relating to GHG emissions (including carbon dioxide). The impact of GHG-related legislation and regulations on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover the costs related to compliance with regulatory requirements imposed on us from our customers due to limitations in our agreements. The imposition of a carbon tax or similar regulation could materially and adversely affect our revenues. • Mine Improvement and New Emergency Response Act of 2006. The Mine Improvement and New Emergency Response Act of 2006 (the “Miner Act”), has increased significantly the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There also has been a dramatic increase in the dollar penalties assessed for citations issued. • Use of Explosives. Our limited surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to strict regulatory requirements established by four different federal regulatory agencies. Reclamation and Remediation • Surface Mining Control and Reclamation Act of 1977. The SMCRA established comprehensive operational, environmental, reclamation and closure standards for all aspects of U.S. surface mining as well as many aspects of deep mining. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority, and states that operate federally approved state 11 programs may impose standards that are more stringent than the requirements of SMCRA. Permitting under SMCRA generally has become more difficult in recent years, which adversely affects the cost and availability of coal. The Abandoned Mine Land Fund, which is part of SMCRA, assesses a fee on all coal produced in the U.S. From October 1, 2007 through September 30, 2012, the fee is $0.315 per ton of surface-mined coal and $0.135 per ton of underground mined coal. From October 1, 2012 through September 30, 2021, the fee has been reduced to $0.28 per ton of surface-mined coal and $0.12 per ton of underground mined coal. Our reclamation obligations under applicable environmental laws could be substantial. Under GAAP, we are required to account for the costs related to the closure of mines and the reclamation of the land upon exhaustion of coal reserves. The fair value of an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long- lived asset. At December 31, 2012, we had accrued $6.8 million related to estimated mine reclamation costs. The amounts recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted interest rates. Our future operating results would be adversely affected if these accruals were determined to be insufficient. These obligations are unfunded. Further, although specific criteria varies from state to state as to what constitutes an “owner” or “controller” relationship, under SMCRA the responsibility for reclamation or remediation, unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators can be imputed to other companies which are deemed, according to the regulations, to have “owned” or “controlled” the contract mine operator. Sanctions are quite severe and can include being denied new permits, permit amendments, permit revisions and revocation or suspension of permits issued since the violation or penalty or fee due date. • Comprehensive Environmental Response, Compensation, and Liability Act. Under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as Superfund, and similar state laws, responsibility for the entire cost of clean-up of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. In the course of our operations we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We also may be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. Under CERCLA, we may be responsible for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act. Other Regulatory Requirements • Black Lung Benefits Revenue Act of 1977 and Black Lung Benefits Reform Act of 1977, as amended in 1981. Under these laws, each U.S. coal mine operator must pay federal black lung benefits and medical expenses to claimants who are current and former employees and last worked for the operator after July 1, 1973. Coal mine operators also must make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on U.S. coal production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4 percent of the gross sales price. The Patient Protection and Affordable Care Act (“PPACA”), which was implemented in 2010, amended previous legislation and provides for the automatic extension of awarded lifetime benefits to surviving spouses and changes the legal criteria used to assess and award claims. Our obligation related to black lung benefits is estimated based on various assumptions, including actuarial estimates, discount rates, changes in health care costs and the impact of PPACA. 12 Environmental Matters and Compliance Our failure to comply with the aforementioned requirements may result in the assessment of administrative, civil and criminal penalties, the imposition of clean-up and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. Please see Note 17 entitled “Commitments and Contingent Liabilities” to our Combined and Consolidated Financial Statements within this Annual Report on Form 10-K for a discussion of the Notices of Violation (“NOVs”) issued by the EPA and state regulators for our Haverhill, Granite City, Middletown and Indiana Harbor cokemaking facilities. Many other legal and administrative proceedings are pending or may be brought against us arising out of our current and past operations, including matters related to commercial and tax disputes, product liability, antitrust, employment claims, natural resource damage claims, premises-liability claims, allegations of exposures of third parties to toxic substances and general environmental claims. Although the ultimate outcome of these proceedings cannot be ascertained at this time, it is reasonably possible that some of them could be resolved unfavorably to us. Our management believes that any liabilities that may arise from such matters would not be material in relation to our business or our combined and consolidated financial position, results of operations or cash flows at December 31, 2012. Available Information We make available free of charge on our website, www.suncoke.com, all materials that we file electronically with the Securities and Exchange Commission (“SEC”), including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and any amendments to such reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC. Executive Officers of the Registrant Our executive officers and their ages as of February 22, 2013 were as follows: Name Age Position Frederick A. Henderson . . . . . . . . Michael J. Thomson . . . . . . . . . . . Denise R. Cade . . . . . . . . . . . . . . . Mark E. Newman . . . . . . . . . . . . . Fay West . . . . . . . . . . . . . . . . . . . . 54 Chairman and Chief Executive Officer President and Chief Operating Officer 54 Senior Vice President, General Counsel, Corporate Secretary and 50 Chief Compliance Officer Senior Vice President and Chief Financial Officer 49 43 Vice President and Controller Frederick A. Henderson. Mr. Henderson was elected as our Chairman and Chief Executive Officer in December 2010. He also served as a Senior Vice President of Sunoco (a petroleum refiner and chemicals manufacturer with interests in logistics) from September 2010 until our initial public offering in July 2011. In addition, Mr. Henderson was appointed Chairman and Chief Executive Officer of SunCoke Energy Partners GP LLC, the general partner of SunCoke Energy Partners, L.P., in July 2012. From February 2010 until September 2010, he was a consultant for General Motors LLC, and from March 2010 until August 2010, he was a consultant for AlixPartners LLC (a business consulting firm). He was President and Chief Executive Officer of General Motors (a global automotive company) from April 2009 until December 2009. He was President and Chief Operating Officer of General Motors from March 2008 until March 2009. He was Vice Chairman and Chief Financial Officer of General Motors from January 2006 until February 2008. Mr. Henderson is a director of Compuware Corp. (a technology performance company), where he serves as chair of its Audit Committee. Mr. Henderson is also a trustee of the Alfred P. Sloan Foundation. Michael J. Thomson. Mr. Thomson was appointed President and Chief Operating Officer, SunCoke Energy, Inc., in December 2010. In addition, Mr. Thomson was appointed President and Chief Operating Officer and 13 named to the Board of Directors of SunCoke Energy Partners GP LLC, the general partner of SunCoke Energy Partners, L.P., in July 2012. From May 2008 until December 2010, he served as President, SunCoke Technology and Development LLC. He was Vice President and Executive Vice President, SunCoke Technology and Development LLC from March 2007 to May 2008 and held the additional position of Chief Operating Officer of SunCoke Technology and Development LLC from January 2008 to May 2008. He also served as a Senior Vice President of Sunoco from May 2008 until the IPO. He was President of PSEG Fossil LLC, a subsidiary of Public Service Enterprise Group Incorporated (a diversified energy group), from August 2003 to February 2007. Denise R. Cade. Ms. Cade was appointed Senior Vice President and General Counsel of SunCoke Energy, Inc. in March 2011 and was elected its Corporate Secretary in June 2011 and Chief Compliance Officer in July 2011. In addition, Ms. Cade was named Senior Vice President, General Counsel and Corporate Secretary and appointed to the Board of Directors of SunCoke Energy Partners GP LLC, the general partner of SunCoke Energy Partners, L.P., in July 2012. Prior to joining SunCoke Energy, Inc., Ms. Cade was with PPG Industries, Inc. (“PPG”) (a coatings and specialty products company) from March 2005 to March 2011. At PPG, she served as Assistant General Counsel and Corporate Secretary from July 2009 until March 2011, as Corporate Counsel, Securities and Finance, from September 2007 until July 2009, and as Chief Mergers and Acquisition Counsel and General Counsel of the glass and fiber glass division from March 2005 until September 2007. Ms. Cade began her legal career in private practice in 1990, specializing in corporate and securities law matters and corporate transactions. She was a partner at Shaw Pittman LLP in Washington, D.C. before her move to PPG. Mark E. Newman. Mr. Newman was appointed Senior Vice President and Chief Financial Officer of SunCoke Energy, Inc. in March 2011. In addition, Mr. Newman was appointed Senior Vice President and Chief Financial Officer and appointed to the Board of Directors of SunCoke Energy Partners GP LLC, the general partner of SunCoke Energy Partners, L.P., in July 2012. From May 2008 until February 2011, Mr. Newman was Vice President, Remarketing, Ally Financial, Inc. (an automotive financial services company) and managing director of SmartAuction (Ally Financial, Inc.’s online used vehicle auction). Mr. Newman was GM North America Vice President and Chief Financial Officer and Vice Chairman, GMAC Bank, of GMAC Financial Services LLC (an automotive financial services company) from January 2007 until April 2008. He was GM North America Vice President and CFO of General Motors Corporation (a global automotive company) from February 2006 until December 2006 and was Assistant Treasurer and General Director of General Motors Corporation from August 2002 until January 2006. Mr. Newman was Vice President and CFO of Shanghai General Motors Ltd. from November 1999 until July 2002. Fay West. Ms. West was appointed Vice President and Controller of SunCoke Energy, Inc. in February 2011. In addition, Ms. West was appointed Vice President and Controller of SunCoke Energy Partners GP LLC, the general partner of SunCoke Energy Partners, L.P., in July 2012. Prior to joining SunCoke Energy, Inc., she was Assistant Controller at United Continental Holdings, Inc. (an airline holding company) from April 2010 to January 2011. She was Vice President, Accounting and Financial Reporting for PepsiAmericas, Inc. (a manufacturer and distributor of beverage products) from December 2006 through March 2010 and Director of Financial Reporting from December 2005 to December 2006. Ms. West worked at GATX Corporation from 1998 to 2005 in various accounting roles, including Vice President and Controller of GATX Rail Company from 2001 to 2005 and Assistant Controller of GATX Corporation from 2000 to 2001. Item 1A. Risk Factors In addition to the other information included in this Annual Report on Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. These risk factors represent what we believe to be the known material risk factors with respect to us and our business. Our business, operating results, cash flows and financial condition are subject to these risks and uncertainties, any of which could cause actual results to vary materially from recent results or from anticipated future results. 14 Risks Inherent in Our Business and Industry We are subject to extensive laws and regulations, which may increase our cost of doing business and have an adverse effect on our cash flows, financial position or results of operations. Our operations are subject to increasingly strict regulation by federal, state and local authorities with respect to protection of the environment and health and safety matters, including those legal requirements pursuant to the Clean Air Act and other laws that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, the protection of groundwater quality and availability, plant and wildlife protection, reclamation and restoration of properties after mining or drilling is completed, the installation of various safety equipment in our facilities, control of surface subsidence from underground mining protection of employee health and safety. Complying with these requirements, including the terms of our permits, can be costly and time-consuming, and may delay commencement or continuation of exploration or production operations. Failure to comply with these regulations or permits may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could limit or materially increase the cost of our operations. For instance, as more fully discussed herein, our Haverhill, Granite City and Indiana Harbor cokemaking facilities have been issued Notices of Violation for alleged violations of air emission limits. The resolution of Notices of Violation at our Haverhill and Granite City cokemaking facilities will cause us to undertake capital projects and will require payment of a penalty. We may not have been, or may not be, at all times, in complete compliance with all of these requirements, and we may incur material costs or liabilities in connection with these requirements, or in connection with remediation at sites we own, or third-party sites where it has been alleged that we have liability, in excess of the amounts we have accrued. In addition, these requirements are complex, change frequently and have become more stringent over time. These requirements may change in the future in a manner that could have a material adverse effect on our business. For a description of certain environmental laws and matters applicable to us, see “Item 1. Business— Legal and Regulatory Requirements.” In addition, our facilities are currently subject to GHG regulations, including the obligation to report annual GHG emissions for the preceding year. Any modifications to our facilities could be subject to the EPA’s Tailoring Rule, which could place additional permitting and other implementation requirements on GHG emissions. The U.S. Congress has considered “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs and require most sources of GHGs to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of GHGs. Additional climate change regulation could result in increased costs to operate or maintain our facilities, increased capital expenditures to install new emission controls on our facilities, increased costs to administer and manage any potential GHG emissions regulations or carbon trading or tax programs, and reduce demand for our coke. Any such federal or state regulations requiring us, or our customers, to employ expensive technology to capture and sequester carbon dioxide could likewise adversely affect our future revenues, or profitability. The PPACA, which was implemented in 2010, amended previous legislation related to coal workers’ black lung obligations. PPACA provides for the automatic extension of awarded lifetime benefits to surviving spouses and changes the legal criteria used to assess and award claims. Our obligation related to black lung benefits is estimated based on various assumptions, including actuarial estimates, discount rates, and changes in health care costs. Equipment upgrades, equipment failures and deterioration of assets may lead to production curtailments, shutdowns or additional expenditures. Our cokemaking and coal mining operations depend upon critical pieces of equipment that occasionally may be out of service for scheduled upgrades or maintenance or as a result of unanticipated failures. Our facilities are subject to equipment failures and the risk of catastrophic loss due to unanticipated events such as fires, accidents 15 or violent weather conditions. As a result, we may experience interruptions in our processing and production capabilities, which could have a material adverse effect on our results of operations and financial condition. In addition, assets critical to the operations of our cokemaking and coal mining operations, including our cokemaking facilities and equipment and our coal mines, may deteriorate or become depleted materially sooner than we currently estimate. Such deterioration of assets may result in additional maintenance spending or additional capital expenditures. If these assets do not generate the amount of future cash flows that we expect, and we are not able to procure replacement assets in an economically feasible manner, our future results of operations may be materially and adversely affected. We are also required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. If we are required to incur impairment charges in the future, our results of operations in the period taken could be materially and adversely affected. We may be unable to obtain, maintain or renew permits or leases necessary for our operations, which could materially reduce our production, cash flow or profitability. Our cokemaking facilities and coal mining operations require us to obtain a number of permits that impose strict regulations on various environmental and operational matters in connection with cokemaking and coal mining. These include permits used by various federal, state and local agencies and regulatory bodies. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by our regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing operations or the development of future cokemaking facilities or coal mines. The public, including non-governmental organizations, environmental groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements prepared in connection with applicable regulatory processes, and otherwise engage in the permitting process, including bringing citizen’s lawsuits to challenge the issuance of permits, the validity of environmental impact statements or performance of cokemaking or coal mining activities. If any permits or leases are not issued or renewed in a timely fashion or at all, or if permits issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our cokemaking or coal mining operations, our cash flows or profitability could be materially and adversely affected. Our businesses are subject to inherent risks, some for which we maintain third-party insurance and some for which we self-insure. We may incur losses and be subject to liability claims that could have a material adverse effect on our financial condition, results of operations or cash flows. We maintain insurance policies that provide limited coverage for some, but not all, of the potential risks and liabilities associated with our businesses. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. In addition, certain environmental and pollution risks generally are not fully insurable. Even where insurance coverage applies, insurers may contest their obligations to make payments. Our financial condition, results of operations and cash flows could be materially and adversely affected by losses and liabilities from un-insured or under-insured events, as well as by delays in the payment of insurance proceeds, or the failure by insurers to make payments. We also may incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. We must compensate employees for work-related injuries. If we do not make 16 adequate provision for our workers’ compensation liabilities, it could harm our future operating results. If we are pursued for these sanctions, costs and liabilities, our operations and our profitability could be adversely affected. Our operating results have been and may continue to be affected by fluctuations in our costs of production, and, if we cannot pass increases in our costs of production to our customers, our financial condition, results of operations and cash flows may be negatively affected. Over the course of the last two to three years, many of the components of our cost of produced coke and coal revenues, including cost of supplies, equipment and labor, have experienced significant price inflation, and such price inflation may continue in the future. Our coal mining operations, for example, require a reliable supply of mining and industrial equipment, replacement parts, fuel and steel-related products, including roof control and lubricants. The supplier base providing such mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, resulting in a situation where purchases of certain underground mining equipment are concentrated in single suppliers. The price of such components is also highly volatile. Our profit margins may be reduced and our financial condition, results of operations and cash flows may be adversely affected if the costs of production increase significantly and we cannot pass such increases in our costs of production to our customers. If we fail to maintain satisfactory labor relations, we may be adversely affected. Union represented labor creates an increased risk of work stoppages and higher labor costs. We rely, at one or more of our facilities, on unionized labor, and there is always the possibility that the employing entity will be unable to reach agreement on terms and conditions of employment or renewal of a collective bargaining agreement. Any labor disputes, work stoppages, or increased labor costs could adversely affect operations, the stability of production and reduce our future revenues, or profitability. It is also possible that, in the future, additional employee groups may choose to be represented by a labor union. We have obligations for long-term employee plan benefits that may involve expenses that are greater than we have assumed. We are required to provide various long-term employee benefits to retired employees and current employees who will retire in the future. At December 31, 2012, these obligations included: • • pension benefits of $37.5 million; and postretirement medical and life insurance of $43.7 million. We have estimated certain of these unfunded obligations based on actuarial assumptions described in the notes to our financial statements. However, if our assumptions are inaccurate, we could be required to expend materially greater amounts than anticipated. Approximately 93 percent of the pension benefits were funded on an accounting basis at December 31, 2012, while the post-retirement medical and life insurance obligations are unfunded. If we are required to expend materially greater amounts than anticipated, it could have a material and adverse effect on our financial condition, results of operations and cash flows. We currently are, and likely will be, subject to litigation, the disposition of which could have a material adverse effect on our cash flows, financial position or results of operations. The nature of our operations exposes us to possible litigation claims in the future, including disputes relating to our operations and commercial and contractual arrangements. Although we make every effort to avoid litigation, these matters are not totally within our control. We will contest these matters vigorously and have made insurance claims where appropriate, but because of the uncertain nature of litigation and coverage decisions, we cannot predict the outcome of these matters. Litigation is very costly, and the costs associated with prosecuting and defending litigation matters could have a material adverse effect on our financial condition and 17 profitability. In addition, our profitability or cash flow in a particular period could be affected by an adverse ruling in any litigation currently pending in the courts or by litigation that may be filed against us in the future. We are also subject to significant environmental and other government regulation, which sometimes results in various administrative proceedings. Our substantial indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the senior notes and the credit facilities. We have a significant amount of indebtedness. As of December 31, 2012, our total debt was approximately $723.4 million, excluding $150.0 million of substantially unused commitments under the credit facilities. Additionally, the credit agreement provides for up to $75.0 million in uncommitted incremental facilities that are available subject to the satisfaction of certain conditions, $30.0 million of which was outstanding as of December 31, 2012. Subject to the limits contained in the credit agreement that governs the credit facilities (which term includes our new revolving, term loan and incremental facilities), the Indenture that governs the notes and our other debt instruments, we may be able to incur substantial additional debt from time to time to finance working capital, capital expenditures, investments or acquisitions, or for other purposes. If we do so, the risks related to our high level of debt could intensify. Specifically, our high level of debt could have important consequences, including: • • • • • • • • making it more difficult for us to satisfy our obligations with respect to the notes and our other debt; limiting our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions or other general corporate requirements; requiring a substantial portion of our cash flows to be dedicated to debt service payments instead of other purposes, thereby reducing the amount of cash flows available for working capital, capital expenditures, acquisitions and other general corporate purposes; increasing our vulnerability to general adverse economic and industry conditions; exposing us to the risk of increased interest rates as certain of our borrowings, including borrowings under the credit facilities, are at variable rates of interest; limiting our flexibility in planning for and reacting to changes in the industry in which we compete; placing us at a competitive disadvantage to other, less leveraged competitors; and increasing our cost of borrowing. In addition, the indenture that governs the notes and the credit agreement governing our credit facilities contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interest. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all our debt. Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. Borrowings under the credit facilities are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness will increase even though the amount borrowed remained the same, and our net income and cash flows, including cash available for servicing our indebtedness, will correspondingly decrease. We have entered into and may in the future enter into additional interest rate swaps that involve the exchange of floating for fixed rate interest payments in order to reduce interest rate volatility. However, we may decide not to maintain interest rate swaps with respect to all of our variable rate indebtedness, and any swaps we enter into may not fully mitigate our interest rate risk. 18 Unfavorable economic conditions resulting from the ongoing U.S. and worldwide financial and credit crisis, and potential further deteriorating conditions in the U. S. and globally, may cause a reduction in the demand for our products, which could adversely affect our cash flows, financial position or results of operations. Continued volatility and disruption in worldwide capital and credit markets and potential further deteriorating conditions in the United States and globally could cause reduced demand for our products. Additionally, unfavorable economic conditions, including the reduced availability of credit, may cause a reduction in the demand for steel products, which, in turn, could adversely affect demand for our products. Such conditions could have an adverse effect on our cash flows, financial position or results of operations. Risks Related to Our Cokemaking Business We are exposed to the credit risk, and certain other risks, of our major customers, and any material nonpayment or nonperformance by our major customers, or the failure of our customers to continue to purchase coke from us at similar prices under similar arrangements, may have a material adverse effect on our cash flows, financial position or results of operations. We are subject to the credit risk of our major customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration of their creditworthiness, any resulting increase in nonpayment or nonperformance by them could have a material adverse effect on our cash flows, financial position or results of operations. We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, whose operations are concentrated in a single industry, the steel industry. We sell coke to these customers pursuant to long-term take-or-pay agreements that require that our customers either purchase all of our coke production or a specified tonnage maximum greater than our stated capacity, as applicable, or pay the contract price for any such coke they elect not to accept. Our customers experience significant fluctuations in demand for steel products because of economic conditions, consumer demand, raw material and energy costs and decisions by the U.S. federal and state governments to fund or not fund infrastructure projects, such as highways, bridges, schools, energy plants, railroads and transportation facilities. During periods of weak demand for steel, our customers may experience significant reductions in their operations, or substantial declines in the prices of the steel they sell. These and other factors may lead some customers to seek renegotiation or cancellation of their existing long- term coke purchase commitments to us, which could have a material adverse effect on our cash flows, financial position or results of operations. If a substantial portion of our agreements to supply coke and electricity are modified or terminated, our results of operations may be adversely affected if we are not able to replace such agreements, or if we are not able to enter into new agreements at the same level of profitability. We sell substantially all of our coke and electricity under long-term agreements. If a substantial portion of these agreements are modified or terminated or if force majeure is exercised, our results of operations may be adversely affected if we are not able to replace such agreements, or if we are not able to enter into new agreements at the same level of profitability. The profitability of our long-term coke and energy sales agreements depends on a variety of factors that vary from agreement to agreement and fluctuate during the agreement term. We may not be able to obtain long-term agreements at favorable prices, compared either to market conditions or to our cost structure. Price changes provided in long-term supply agreements may not reflect actual increases in production costs. As a result, such cost increases may reduce profit margins on our long-term coke and energy sales agreements. In addition, contractual provisions for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term price volatility. From time to time, we discuss the extension of existing agreements and enter into new long-term agreements for the supply of coke and energy to our customers, but these negotiations may not be successful and 19 these customers may not continue to purchase coke or electricity from us under long-term agreements. If any one or more of these customers were to significantly reduce their purchases of coke or electricity from us, or if we were unable to sell coke or electricity to them on terms as favorable to us as the terms under our current agreements, our cash flows, financial position or results of operations may be materially and adversely affected. Further, because of certain technological design constraints, we do not have the ability to shut down our cokemaking operations if we do not have adequate customer demand. If a customer refuses to take or pay for our coke, we must continuously operate our coke ovens even though we may not be able to sell our coke immediately and may incur significant additional costs for natural gas to maintain the temperature inside our coke oven batteries, which may have a material and adverse effect on our cash flows, financial position or results of operations. The financial performance of our cokemaking business is substantially dependent upon three customers in the steel industry, and any failure by them to perform under their contracts with us could adversely affect our financial condition, results of operations and cash flows. Substantially all of our domestic coke sales are currently made under long-term contracts with ArcelorMittal, U.S. Steel and AK Steel. For the year ended December 31, 2012, ArcelorMittal, AK Steel and U.S. Steel accounted for approximately 54 percent, 28 percent and 16 percent of our sales and other operating revenue, respectively. We expect these three customers to continue to account for a significant portion of our revenues for the foreseeable future. If any one or more of these customers were to significantly reduce its purchases of coke from us, or default on their agreements with us, or fail to renew or terminate its agreements with us, or if we were unable to sell coke to any one or more of these customers on terms as favorable to us as the terms under our current agreements, our cash flows, financial position and results of operations could be materially and adversely affected. The coke sales agreement and the energy sales agreement with AK Steel at our Haverhill facility are subject to early termination under certain circumstances and any such termination could have a material adverse effect on our results of operations and therefore our ability to distribute cash to unitholders. The coke sales agreement and the energy sales agreement with AK Steel at Haverhill 2, or the Haverhill AK Steel Contracts, are subject to early termination by AK Steel under certain circumstances and any such termination could have a material adverse effect on our business. For the year ended December 31, 2012, the Haverhill AK Steel Contracts accounted for approximately $222.0 million, or 12 percent, of our total revenues. The Haverhill coke sales agreement with AK Steel expires on January 1, 2022, with two automatic, successive five-year renewal periods. The Haverhill energy sales agreement with AK Steel runs concurrently with the term of the coke sales agreement, including any renewals, and automatically terminates upon the termination of the related coke sales agreement. The coke sales agreement may be terminated by AK Steel at any time on or after January 1, 2014 upon two years prior written notice if AK Steel (i) permanently shuts down iron production operations at its steel plant works in Ashland, Kentucky, or the Ashland Plant; and (ii) has not acquired or begun construction of a new blast furnace in the United States to replace, in whole or in part, the Ashland Plant’s iron production capacity. If such termination occurs at any time prior to January 1, 2018, AK Steel will be required to pay a significant termination fee. If AK Steel were to terminate the Haverhill AK Steel Contracts, we may be unable to enter into similar long-term contracts with replacement customers for all or any portion of the coke previously purchased by AK Steel. Similarly, we may be forced to sell some or all of the previously contracted coke in the spot market, which could be at prices lower than we have currently contracted for and could subject us to significant price volatility. If AK Steel elects to terminate the Haverhill AK Steel Contracts, our cash flows, financial position and results of operations could be materially and adversely affected. 20 We may not be able to successfully implement our international growth strategy and develop, design, construct, start up and operate new, or make investments in existing, cokemaking facilities outside of North America. A central element of our growth strategy involves the international expansion of our business. We expanded our cokemaking business internationally in 2007 through our development and operation of our customer’s cokemaking facility in Vitória, Brazil. We are currently exploring opportunities with steel companies for developing new cokemaking facilities in foreign countries, which could be either wholly owned or developed through other business structures. We also are exploring opportunities with respect to making investments in entities that own and operate, or forming a joint venture or similar arrangement with respect to assets comprising, existing cokemaking facilities in foreign countries, principally in India. For example, on November 20, 2012, we announced that we had entered into agreements to form a cokemaking joint venture with VISA Steel Limited (“VISA Steel”) in India. The transaction is expected to close in the first quarter of 2013, subject to customary conditions. When the VISA SunCoke joint venture transaction is closed, and in the event we make additional investments in entities that own and operate existing cokemaking facilities, or form joint ventures or other similar arrangements with respect to assets comprising an existing cokemaking facility, we will and would share ownership and management with one or more parties who may not have the same goals, strategies, priorities, or resources as we do. Such arrangements are intended to be operated for the equal benefit of all co-owners, rather than for our exclusive benefit. Making an investment in an entity that owns and operates an existing cokemaking facility or operating a business as a joint venture will require additional organizational formalities as well as time-consuming procedures for sharing information and making decisions. We will be required to pay close attention to our relationship with our co- owners as well as with the existing entity or joint venture, and if a co-owner changes, our relationship may be materially adversely affected. The benefits from a successful investment in an existing entity or joint venture will be shared among the co-owners, so that we will not receive all the benefits from a successful investment. Our ability to expand internationally by entering into additional arrangements in non-U.S. markets and to successfully implement our international growth strategy is subject to a variety of risks, including, but not limited to: • • • • • • • • • certain acquisition and investment opportunities may not result in the consummation of a transaction; we may not be able to obtain acceptable terms for any required financing for any such acquisition or investment that arises; incorrect assumptions regarding the future results of investments or expected cost reductions or other synergies expected to be realized as a result of our investments; failing to successfully and timely integrate the operations or management of any investments in non- U.S. markets and the risk of diverting management’s attention from existing operations or other priorities; the possibility of negative developments in the demand for steel in non-U.S. markets; the difficulty or costs associated with complying with industry guidelines or laws or regulations of non- U.S. markets; the possibility that language and other cultural differences may inhibit our development and operations efforts and create internal communication problems among our U.S. and non-U.S. teams, increasing the difficulty of managing multiple, remote locations performing various development and quality assurance projects; compliance with non-U.S. laws that may be unfamiliar to our management and employees; currency risk due to the fact that our revenues and expenses for our international operations may be denominated in different currencies; and 21 • economic or political instability or legal restrictions could affect our ability to efficiently invest and repatriate our capital from the local country. If we are not able to successfully execute our plans for international development and expansion of our cokemaking operations, as a result of unfavorable market conditions in the steel industry or otherwise, our future revenues and profitability could be materially and adversely affected. The failure to consummate or integrate business relationships or other transactions with respect to existing cokemaking facilities in the United States and Canada in a timely and cost-effective manner, and operational challenges associated with operating any such cokemaking facility, could have an adverse effect on our financial condition and results of operations. We are exploring opportunities to enter into business relationships or other transactions with respect to existing cokemaking facilities in order to opportunistically capture market share in the United States and Canada. We believe that such opportunities may arise from time to time, and any such transaction could be significant. Any transaction could involve the payment by us of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. Certain opportunities may not result in the consummation of a transaction. In addition, we may not be able to obtain acceptable terms for the required financing for any such transaction that arises. Our future business relationships or other transactions with respect to existing cokemaking facilities could present a number of risks, including the risk of incorrect assumptions regarding the future results of such operations or assets or expected cost reductions or other synergies expected to be realized as a result of entering into a transaction with respect to such operations or assets, the risk of failing to successfully and timely integrate the operations or management of any such operations or assets and the risk of diverting management’s attention from existing operations or other priorities. If we fail to consummate and integrate any transaction in a timely and cost-effective manner, our financial condition and results of operations could be adversely affected. In addition, existing cokemaking facilities in the United States and Canada typically utilize by-product cokemaking. By-product cokemaking seeks to recover the coal’s volatile components liberated during the cokemaking process and re-purpose these components into by-products for other uses. Our cokemaking ovens utilize heat recovery technology, which is fundamentally different from the by-product method. If we are not able to successfully operate any by-product cokemaking facility that we may enter into a business relationship or other transaction with, as a result of challenges associated with operating a facility utilizing a different technology or otherwise, our future revenues and profitability could be materially and adversely affected. Excess capacity in the global steel industry, including in China, may weaken demand for steel produced by our U.S. steel industry customers, which, in turn, may reduce demand for our coke. In some countries, such as China, steelmaking capacity exceeds demand for steel products. Rather than reducing employment by matching production capacity to consumption, steel manufacturers in these countries (often with local government assistance or subsidies in various forms) may export steel at prices that are significantly below their home market prices and that may not reflect their costs of production or capital. The availability of this steel at such prices may negatively affect our steelmaking customers, who may not be able to increase and may have to decrease, the prices that they charge for steel as the supply of steel increases. Our customers may also reduce their steel output in response to this increased supply, which would correspondingly reduce their demand for coke and make it more likely that they may seek to renegotiate their contracts with us or fail to pay for the coke they are required to take under our contracts. As a result, the profitability and financial position of our steelmaking customers may be adversely affected, which in turn, could adversely affect the certainty of our long-term relationships with those customers and our own results of operations. 22 Increased exports of coke from China related to reduced export duties and export quotas may weaken our customers’ demand for coke capacity. An appeals panel of the World Trade Organization (the “WTO”) ruled in early 2012 that China’s export duties and export quotas on certain raw materials, including coke, violated global trade rules. The WTO’s dispute-settlement body recently adopted the appeals panel report. Consequently, China has eliminated the export tariff effective January 1, 2013 which may reduce prices for Chinese coke in the international market and result in increased exports of coke from China. Increased exports of coke from China could reduce our customers’ demand for coke capacity, which would limit our ability to construct a potential new plant in the United States or Canada and to enter into new, or renew existing, commercial arrangements with our customers and materially and adversely affect our future revenues and profitability. We face increasing competition both from alternative steelmaking and cokemaking technologies that have the potential to reduce or completely eliminate the use of coke, which may reduce the demand for the coke we produce and which could have an adverse effect on our results of operations. Historically, coke has been used as a main input in the production of steel in blast furnaces. However, some blast furnace operators have reduced the amount of coke per ton of hot metal through alternative injectants, such as natural gas and pulverized coal injectant, and the use of these coke substitutes could increase in the future, particularly in light of current low natural gas prices. Many steelmakers also are exploring alternatives to blast furnace technology that require less or no use of coke. For example, electric arc furnace technology is a commercially proven process widely used in the United States. As these alternative processes for production of steel become more widespread, the demand for coke, including the coke we produce, may be significantly reduced, and this reduction could have a material and adverse effect on our financial position, results of operations and cash flows. We also face competition from alternative cokemaking technologies, including both by-product and heat recovery technologies. As these technologies improve and as new technologies are developed, we anticipate that competition in the cokemaking industry will intensify. Such increased competition may adversely affect our future revenues and profitability. Certain provisions in our long-term coke agreements may result in economic penalties to us, or may result in termination of our coke sales agreements for failure to meet minimum volume requirements or other required specifications, and certain provisions in these agreements and our energy sales agreements may permit our customers to suspend performance. All of our coke sales agreements and our steam supply and purchase agreements contain provisions requiring us to supply minimum volumes of our products to our customers. To the extent we do not meet these minimum volumes, we are generally required under the terms of our coke sales agreements to procure replacement supply to our customers at the applicable contract price or potentially be subject to cover damages for any shortfall. If future shortfalls occur, we will work with our customer to identify possible other supply sources while we implement operating improvements at the facility, but we may not be successful in identifying alternative supplies and may be subject to paying the contract price for any shortfall or to cover damages, either of which could adversely affect our future revenues and profitability. Our coke sales agreements also contain provisions requiring us to deliver coke that meets certain quality thresholds. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of our agreements. Our coke and energy sales agreements contain force majeure provisions allowing temporary suspension of performance by our customers for the duration of specified events beyond the control of our customers. Declaration of force majeure, coupled with a lengthy suspension of performance under one or more coke or energy sales agreements, may seriously and adversely affect our cash flows, financial position and results of operations. 23 To the extent we do not meet coal-to-coke yield standards in our coke sales agreements, we are responsible for the cost of the excess coal used in the cokemaking process, which could adversely impact our results of operations and profitability. Our ability to pass through our coal costs to our customers under our coke sales agreements is generally subject to our ability to meet some form of coal-to-coke yield standard. To the extent that we do not meet the yield standard in the contract, we are responsible for the cost of the excess coal used in the cokemaking process. We may not be able to meet the yield standards at all times, and as a result we may suffer lower margins on our coke sales and our results of operations and profitability could be adversely affected. Failure to maintain effective quality control systems at our cokemaking facilities could have a material adverse effect on our results of operations. The quality of our coke is critical to the success of our business. For instance, our coke sales agreements contain provisions requiring us to deliver coke that meets certain quality thresholds. If our coke fails to meet such specifications, we could be subject to significant contractual damages or contract terminations, and our sales could be negatively affected. The quality of our coke depends significantly on the effectiveness of our quality control systems, which, in turn, depends on a number of factors, including the design of our quality control systems, our quality-training program and our ability to ensure that our employees adhere to our quality control policies and guidelines. Any significant failure or deterioration of our quality control systems could have a material adverse effect on our results of operations. Disruptions to our supply of coal and coal blending services may reduce the amount of coke we produce and deliver and, if we are not able to cover the shortfall in coal supply or obtain replacement blending services from other providers, our results of operations and profitability could be adversely affected. Most of the metallurgical coal used to produce coke at our cokemaking facilities, other than our Jewell facility, is purchased from third parties under one- to two-year contracts. We cannot assure that there will continue to be an ample supply of metallurgical coal available or that we will be able to supply these facilities without any significant disruption in coke production, as economic, environmental, and other conditions outside of our control may reduce our ability to source sufficient amounts of coal for our forecasted operational needs. The failure of our coal suppliers to meet their supply commitments could materially and adversely impact our results of operations if we are not able to make up the shortfalls resulting from such supply failures through purchases of coal from other sources. Other than at our Jewell cokemaking facility, we rely on third parties to blend coals that we have purchased into coal blends that we use to produce coke. We have entered into long-term agreements with coal blending service providers that are co-terminous with our coke sales agreements. Generally, we store an inventory of blended coal at or near our cokemaking facilities to cover approximately 15 to 30 days of coke production. There are limited alternative providers of coal blending services and disruptions from our current service providers could materially and adversely impact our results of operations. In addition, if our rail transportation agreements are terminated, we may have to pay higher rates to access rail lines or make alternative transportation arrangements. Limitations on the availability and reliability of transportation, and increases in transportation costs, particularly rail systems, could materially and adversely affect our ability to obtain a supply of coal and deliver coke to our customers. Our ability to obtain coal depends primarily on third-party rail systems and to a lesser extent river barges. If we are unable to obtain rail or other transportation services, or are unable to do so on a cost-effective basis, our results of operations could be adversely affected. Alternative transportation and delivery systems are generally inadequate and not suitable to handle the quantity of our shipments or to ensure timely delivery. The loss of 24 access to rail capacity could create temporary disruption until the access is restored, significantly impairing our ability to receive coal and resulting in materially decreased revenues. Our ability to open new cokemaking facilities may also be affected by the availability and cost of rail or other transportation systems available for servicing these facilities. Our coke production obligations at our Jewell cokemaking facility and one half of our Haverhill cokemaking facility require us to deliver coke to certain customers via railcar. We have entered into long-term rail transportation agreements to meet these obligations. Disruption of these transportation services because of weather-related problems, mechanical difficulties, train derailments, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, fuel costs, transportation delays, accidents, terrorism, domestic catastrophe or other events could temporarily, or over the long-term impair, our ability to produce coke, and therefore, could materially and adversely affect our business and results of operations. Income from operation of the Vitória, Brazil cokemaking facility may be affected by global and regional economic and political factors and the policies and actions of the Brazilian government. The Vitória cokemaking facility is owned by a project company controlled by a Brazilian affiliate of ArcelorMittal. We earn income from the Vitória, Brazil operations through licensing and operating fees earned at the Brazilian cokemaking facility payable to us under long-term agreements with the project company and an annual preferred dividend from the project company guaranteed by the Brazilian affiliate of ArcelorMittal. These revenues depend on continuing operations and, in some cases, certain minimum production levels being achieved at the Vitória cokemaking facility. In the past, the Brazilian economy was characterized by frequent and occasionally extensive intervention by the Brazilian government and unstable economic cycles. The Brazilian government has changed in the past, and may change monetary, taxation, credit, tariff and other policies to influence Brazil’s economy in the future. If the operations at Vitória cokemaking facility are interrupted or if certain minimum production levels are not achieved, we will not be able to earn the same licensing and operating fees as we are currently earning, which could have an adverse effect on our financial position, results of operations and cash flows. The Brazilian licensing agreement for certain of our Brazilian patents used at the Vitória cokemaking facility may terminate if we are not able to maintain or supplement the patents subject to the licensing agreement, which may have an adverse effect on our future revenues and profitability. We currently collect certain fees in connection with the licensing of certain of our Brazilian patents at the Vitória cokemaking facility pursuant to a Brazilian licensing agreement with a term that runs through 2023. The validity of these patents is being challenged in Brazil, and the patents will otherwise expire by May 2014. We have sixteen patent applications (one of which has been opposed by the party challenging our existing Brazilian patents) awaiting examination that, if approved, we expect will permit the Brazilian licensing agreement to continue through at least 2023. If the challenge to our existing Brazilian patents is successful, or if such Brazilian patents expire prior to a new Brazilian patent becoming subject to the Brazilian licensing agreement, and we no longer have any technology licensed under any applicable licensing agreement, we will no longer receive any licensing fees. The loss of these licensing fees would adversely affect our results of operations. We recorded licensing fees of $4.4 million, $5.2 million and $5.9 million in 2012, 2011 and 2010, respectively. Labor disputes with the unionized portion of our workforce could affect us adversely. As of December 31, 2012, we have approximately 1,214 employees in the United States. Approximately 312, or 26 percent, of our domestic employees, principally at our cokemaking operations, are currently represented by the United Steelworkers under various contracts. The labor agreement at our Haverhill facility was recently extended through October 31, 2015. As of December 31, 2012, we have approximately 249 employees at the cokemaking facility in Vitória, Brazil, all of whom are represented by a union under an agreement that expires on November 30, 2013. When these agreements expire or terminate, we may not be able 25 to negotiate the agreements on the same or more favorable terms as the current agreements, or at all, and without production interruptions, including labor stoppages. If we are unable to negotiate a new collective bargaining agreement before the expiration date, our operations and our profitability could be adversely affected. A prolonged labor dispute, which could include a work stoppage, could adversely affect our ability to satisfy our customers’ orders and, as a result, adversely affect our production and profitability. Risks Related to Our Coal Mining Business Coal prices are volatile, and a substantial or extended decline in prices could adversely affect our profitability and the value of our coal reserves. Our profitability and the value of our coal reserves depend upon the prices we receive for our coal. The contract prices we may receive for coal in the future depend upon factors beyond our control, including: • • • • • • • • the domestic and foreign demand and supply for metallurgical coal; the quantity and quality of coal available from domestic and foreign competitors; the demand for steel, which may lead to price fluctuations in the re-pricing of our metallurgical coal contracts; competition within our industry; adverse weather, climatic or other natural conditions, including natural disasters; domestic and foreign economic conditions, including economic slowdowns; legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions; and the proximity, capacity and cost of transportation facilities. A substantial or extended decline in the prices we receive for our future coal sales could adversely affect our profitability and the value of our coal reserves. Extensive governmental regulations pertaining to employee health and safety and mandated benefits for retired coal miners impose significant costs on our mining operations, which could materially and adversely affect our results of operations. The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as employee health and safety and mandated benefits for retired coal miners. Compliance with these requirements imposes significant costs on us and can result in reduced productivity. Moreover, the possibility exists that new health and safety legislation and/or regulations and orders may be adopted that may materially and adversely affect our mining operations. We must compensate employees for work-related injuries. If we do not make adequate provisions for our workers’ compensation liabilities, it could harm our future operating results. In addition, the erosion through tort liability of the protections we are currently provided by workers’ compensation laws could increase our liability for work-related injuries and materially and adversely affect our operating results. Under federal law, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and contribute to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry before January 1, 1970. The trust fund is funded by an excise tax on coal production. If this tax increases, or if we could no longer pass it on to the purchasers of our coal under our coal sales agreements, our operating costs could be increased and our results could be materially and adversely harmed. At December 31, 2012, our liabilities for coal workers’ black lung benefits totaled 26 $34.8 million, which included the estimated impact of PPACA. If new laws or regulations increase the number and award size of claims, it could materially and adversely harm our business. See “Item 1. Business—Legal and Regulatory Requirements—Other Regulatory Requirements.” Federal or state regulatory agencies have the authority to order our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers’ demands. Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed. If this occurred, we may be required to incur capital expenditures to re-open the mine and may incur fines. In the event that these agencies order the closing of our mines, our coal sales contracts generally permit us to issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, to fulfill these obligations, incur capital expenditures to re-open the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or termination of customers’ contracts. Our coal operations also provide substantially all of the coal used at our Jewell cokemaking facility. The inability to deliver the required coal to this facility could significantly impact operations at the facility. Any of these actions could have a material adverse effect on our business and results of operations. Extensive environmental regulations impose significant costs on our mining operations, and future regulations could materially increase those costs, impose new or increased liabilities, limit our ability to produce and sell coal, or require us to change our operations significantly, any one or more of which could materially and adversely affect our financial position and/or results of operations. Our coal mining operations are subject to increasingly strict regulation by federal, state and local authorities with respect to environmental matters such as: • • • • • • • • • • • • • limitations on land use; mine permitting and licensing requirements; reclamation and restoration of mining properties after mining is completed; management of materials generated by mining operations; the storage, treatment and disposal of wastes; remediation of contaminated soil and groundwater, including with respect to past or legacy mining operations; air quality standards; water pollution; protection of human health, plant-life and wildlife, including endangered or threatened species; protection of wetlands; the discharge of materials into the environment; the effects of mining on surface water and groundwater quality and availability; and the management of electrical equipment containing polychlorinated biphenyls. The costs, liabilities and requirements associated with the laws and regulations related to these and other environmental matters can be costly and time-consuming, and could delay commencement or continuation of expansion or production operations. We may not have been, or may not be, at all times in compliance with the 27 applicable laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may incur material costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for sanctions, costs and liabilities in respect of these matters, our mining operations and, as a result, our profitability could be materially and adversely affected. New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment that would further regulate and tax the coal industry, also may require us to change operations significantly, or incur increased costs. Such changes could have a material adverse effect on our financial condition and results of operations. See “Item 1. Business—Legal and Regulatory Requirements” for further information about the various governmental regulations affecting us. Our coal mining operations are subject to operating risks, some of which are beyond our control, that could result in a material increase in our operating expenses and a decrease in our production levels. Factors beyond our control could disrupt our coal mining operations, adversely affect production and shipments and increase our operating costs, all of which could have a material adverse effect on our results of operations. Such factors could include: • • • • • • • • poor mining conditions resulting from geological, hydrologic or other conditions that may cause damage to nearby infrastructure or mine personnel; variations in the thickness and quality of coal seams, and variations in the amounts of rock and other natural materials overlying the coal being mined; a major incident at a mine site that causes all or part of the operations of the mine to cease for some period of time; mining, processing and plant equipment failures and unexpected maintenance problems; adverse weather and natural disasters, such as heavy rains or snow, flooding and other natural events affecting operations, transportation or customers; unexpected or accidental surface subsidence from underground mining; accidental mine water discharges, fires, explosions or similar mining accidents; and competition and/or conflicts with other natural resource extraction activities and production within our operating areas, such as coalbed methane extraction. If any of these conditions or events occur, our coal mining operations may be disrupted, we could experience a delay or halt of production or shipments, operating costs could increase significantly, and we could incur substantial losses. In particular, our Jewell cokemaking facility currently obtains essentially all of its metallurgical coal requirements from our existing coal mining operations. Disruptions in our coal mining operations, resulting in decreased production of metallurgical coal, could seriously and adversely affect production at our Jewell cokemaking facility. If transportation for our coal becomes unavailable or uneconomical for our customers, it may impair our ability to sell coal, and our results of operations may be adversely affected. Transportation costs represent a significant portion of the total cost of coal and the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs and the lack of sufficient rail and port capacity could lead to reduced coal sales. For example, all of our coal mining operations are 28 substantially dependent on, and only have access to, a single rail provider. A substantial amount of the metallurgical coal produced from our coal mining operations is used in our adjacent Jewell cokemaking facility. However, future disruption of transportation services (due to weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, underperformance of port and rail infrastructure, congestion and balancing systems used to manage vessel queuing and demurrage, transportation delays or other reasons) may temporarily impair our ability to supply coal to other customers and adversely affect our results of operations. We face numerous uncertainties in estimating economically recoverable coal reserves, and inaccuracies in estimates may result in lower than expected revenues, higher than expected costs and decreased profitability. Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. We base our estimates of reserves on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. We update our estimates of the quantity and quality of proven and probable coal reserves as needed to reflect production of coal from the reserves, updated geological models and mining recovery data, tonnage contained in newly acquired lease areas and estimated costs of production and sales prices. There are numerous factors and assumptions that affect economically recoverable reserve estimates, including: • • • • • • • quality of the coal; historical production from the area compared with production from other producing areas; geological and mining conditions, which may not be fully identified by available exploration data and/ or may differ from our experiences in areas where we currently mine; the percentage of coal ultimately recoverable; the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies; assumptions concerning the timing for the development of the reserves; and assumptions concerning equipment and productivity, future coal prices, operating costs, including costs for critical supplies such as fuel and tires, capital expenditures and development and reclamation costs. Each of these factors may vary considerably. As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the foregoing factors and assumptions. Therefore, our estimates may not accurately reflect our actual reserves. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and these variances may be material. We engaged Marshall Miller & Associates, Inc., a leading mining engineering firm, to conduct a new and comprehensive study to determine our proven and probable reserves for our coal mines. This study determined that we control proven and probable coal reserves of approximately 114 million tons as of December 31, 2011, which was an increase of 8 million tons from December 31, 2010. In 2012 we mined over 1 million tons of coal from our proven and probable reserves and control proven and probable coal reserves of approximately 113 million tons at December 31, 2012. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs. 29 Our inability to develop coal reserves in an economically feasible manner could materially and adversely affect our business. Our future success depends upon our ability to continue developing economically recoverable coal reserves. If we fail to develop additional coal reserves, our existing reserves eventually will be depleted. We may not be able to obtain replacement reserves when we require them. Replacement reserves may not be available or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. Our ability to develop coal reserves in the future also may be limited by the availability of cash we generate from our operations or available financing, restrictions under our existing or future financing arrangements, the lack of suitable opportunities or the inability to acquire coal properties or leases on commercially reasonable terms. If we are unable to develop replacement reserves, our future production may decrease significantly and this may have a material and adverse impact on our cash flows, financial position and results of operations. Mining in Central Appalachia is more complex and involves more regulatory constraints than mining in other areas of the United States, which could affect our mining operations and cost structures in these areas. Our coal mines are located in Virginia and West Virginia, in what is known as the Central Appalachian region. The geological characteristics of Central Appalachian coal reserves, such as coal seam thickness, make them complex and costly to mine. As compared to mines in other regions, permitting, licensing and other environmental and regulatory requirements are more costly and time consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of coal produced at our mines in Central Appalachia. A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs. We conduct a significant part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. In some cases, the seller or lessor warrants property title. In other cases, separate title confirmation may not be required for leasing reserves where mining has occurred previously. Our right to mine some of our reserves may be adversely affected if defects in title or boundaries exist, or if our leasehold interests are subject to superior property rights of third parties. In order to conduct our mining operations on properties where such defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate. In addition, we may not be able to successfully negotiate new leases for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. Disruptions in the quantities of coal produced by our contract mine operators could impair our ability to fill customer orders or increase our operating costs. We use independent contractors to mine coal at certain of our mining operations. Some of our contract miners may experience adverse geologic mining conditions, operational difficulties, escalated costs, financial difficulties or other factors beyond our control that could affect the availability, pricing and quality of coal produced for us. In addition, market volatility and price increases for coal or freight could result in non- performance by third-party suppliers under existing contracts with us, in order to take advantage of the higher prices in the current market. Disruptions in the quantities of coal produced by independent contractors for us could impair our ability to supply our cokemaking facilities and to fill our customer orders. Our profitability or exposure to loss on transactions or relationships such as these depends upon the reliability of the supply or the ability to substitute, when economical, third-party coal sources, with internal production or coal purchased in the 30 market and other factors. Non-performance by contract miners may adversely affect our ability to fulfill deliveries under our coal supply agreements. If we are unable to fill a customer order, or if we are required to purchase coal from other sources in order to satisfy a customer order, we could lose existing customers and our operating costs could increase. We require a skilled workforce to run our coal mining business. If we or our contractors cannot hire qualified people to meet replacement or expansion needs, our labor costs may increase and we may not be able to achieve planned results. Efficient coal mining using modern techniques and equipment requires skilled workers in multiple disciplines, including experienced foremen, electricians, equipment operators, engineers and welders, among others. Our future success depends greatly on our continued ability to attract and retain highly skilled and qualified personnel. We have an aging workforce, and an extended effort to recruit new employees to replace those who retire or a sustained shortage of skilled labor in the areas in which we operate could make it difficult to meet our staffing needs or result in higher labor rates. We also may be forced to hire novice miners, who are required to be accompanied by experienced workers as a safety precaution. These measures could adversely affect our productivity and operating costs. A lack of qualified people also may affect companies that we use to perform certain specialized work. If we or our contractors cannot find enough qualified workers, it may delay completion of projects and increase our costs. We have reclamation and mine closure obligations. If the assumptions underlying our accruals are inaccurate, we may be required to expend significantly greater amounts than anticipated. The Surface Mining Control and Reclamation Act established operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. We accrue for the costs of current mine disturbance and of final mine closure, including the cost of treating mine water discharge where necessary. The amounts recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. Furthermore, our reclamation and mine-closing liabilities are unfunded. If these accruals are insufficient, or our cash requirements in a particular year are greater than currently anticipated, our future operating results and cash flows could be adversely affected. Our failure to obtain or renew surety bonds on acceptable terms could materially and adversely affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal. Our reclamation and mine-closing liabilities are unfunded. Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. These bonds are typically renewable annually. Surety bond issuers and holders may not continue to renew the bonds or may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. We are also subject to increases in the amount of surety bonds required by federal and state laws as these laws, or interpretations of these laws, change. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, our failure to maintain (or inability to acquire) these bonds would have a material and adverse impact on us. That failure could result from a variety of factors, including the following: lack of availability, higher expense or unfavorable market terms of new bonds; restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of future indebtedness; our inability to meet certain financial tests with respect to a portion of the post-mining reclamation bonds; and the exercise by third-party surety bond issuers of their right to refuse to renew or issue new bonds. 31 Risks Related to Ownership of Our Common Stock Your percentage ownership in us may be diluted by future issuances of capital stock or securities or instruments that are convertible into our capital stock, which could reduce your influence over matters on which stockholders vote. Our Board of Directors has the authority, without action or vote of our stockholders, to issue all or any part of our authorized but unissued shares of common stock, including shares issuable upon the exercise of options, shares that may be issued to satisfy our obligations under our incentive plans, shares of our authorized but unissued preferred stock and securities and instruments that are convertible into our common stock. Issuances of common stock or voting preferred stock would reduce your influence over matters on which our stockholders vote and, in the case of issuances of preferred stock, likely would result in your interest in us being subject to the prior rights of holders of that preferred stock. We have no plans to pay dividends on our common stock, so you may not receive funds without selling your common stock. We do not anticipate paying any dividends on our common stock in the foreseeable future. Any declaration and payment of future dividends to holders of our common stock are limited by restrictive covenants contained in our debt agreements, and will be at the sole discretion of our Board of Directors and will depend on many factors, including our financial condition, earnings, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board of Directors deems relevant. Further, we may not have sufficient surplus under Delaware law to be able to pay any dividends in the future. The absence of sufficient surplus may result from extraordinary cash expenses, actual expenses exceeding contemplated costs, funding of capital expenditures or increases in reserves. Provisions of our amended and restated articles of incorporation, our amended and restated by-laws and the Delaware General Corporation Law (the “DGCL”) could discourage potential acquisition proposals and could deter or prevent a change in control. Our amended and restated articles of incorporation and amended and restated by-laws contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with our Board of Directors rather than to attempt a hostile takeover. These provisions include: • • • • • • a Board of Directors that is divided into three classes with staggered terms; action by written consent of stockholders may only be taken unanimously by holders of all our shares of common stock; rules regarding how our stockholders may present proposals or nominate directors for election at stockholder meetings; the right of our Board of Directors to issue preferred stock without stockholder approval; limitations on the right of stockholders to remove directors; and limitations on our ability to be acquired. The DGCL also imposes some restrictions on mergers and other business combinations between us and any holder of 15 percent or more of our outstanding common stock. We believe that these provisions protect our stockholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our Board of Directors and by providing our Board of Directors 32 with more time to assess any acquisition proposal. These provisions are not intended to make us immune from takeovers. However, these provisions apply even if the offer may be considered beneficial by some stockholders and could delay or prevent an acquisition that our Board of Directors determines is in our best interests and that of our stockholders. Any or all of the foregoing provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock. Risks Related to Our Separation from Sunoco We have a limited operating history as a separate public company, and our historical financial information is not necessarily representative of the results that we would have achieved as a separate, publicly-traded company and may not be a reliable indicator of our future results. Our historical financial information for the periods ended prior to the Separation included in this Annual Report on Form 10-K is derived from the consolidated financial statements and accounting records of Sunoco. Accordingly, the historical financial information included here do not necessarily reflect the results of operations, financial position and cash flows that we would have achieved as a separate, publicly-traded company during the periods presented or those that we will achieve in the future primarily as a result of the following factors: • • • • Prior to the Separation, our business was operated by Sunoco as part of its broader corporate organization, rather than as an independent company. Sunoco or one of its affiliates performed various corporate functions for us, including, but not limited to, legal services, treasury, accounting, auditing, risk management, information technology, human resources, corporate affairs, tax administration, certain governance functions (including internal audit and compliance with the Sarbanes-Oxley Act of 2002) and external reporting. Our historical financial results reflect allocations of corporate expenses from Sunoco for these and similar functions. These allocations are likely less than the comparable expenses we believe we would have incurred had we operated as a separate public company. Previously, our business was integrated with the other businesses of Sunoco. Historically, we have shared economies of scale in costs, employees, vendor relationships and customer relationships. While we entered into transition agreements with Sunoco in connection with the Separation that govern certain commercial and other relationships between us, those transitional arrangements may not fully capture the benefits our businesses have enjoyed as a result of being integrated with the other businesses of Sunoco. The loss of these benefits could have an adverse effect on our cash flows, financial position and results of operations. Generally, prior to the Separation, our working capital requirements and capital for our general corporate purposes, including acquisitions, research and development and capital expenditures, were satisfied as part of the enterprise-wide cash management policies of Sunoco. In connection with the Separation and the IPO, we obtained financing in the form of our credit facilities and notes. In the future, we may need to obtain additional financing from banks, through public offerings or private placements of debt or equity securities, strategic relationships or other arrangements. The cost of capital for our business may be higher than Sunoco’s cost of capital prior to the Separation. Other significant changes may occur in our cost structure, management, financing and business operations as a result of operating as a public company separate from Sunoco. The adjustments and allocations we have made in preparing our historical Combined and Consolidated Financial Statements may not appropriately reflect our operations during those periods as if we had in fact operated as a stand-alone entity, or what the actual effect of our Separation from Sunoco will be. 33 If there is a determination that the Distribution is taxable for U.S. federal income tax purposes because the facts, assumptions, representations or undertakings underlying the Internal Revenue Service, (“IRS”), private letter ruling or tax opinion are incorrect or for any other reason, then Sunoco and its shareholders could incur significant U.S. federal income tax liabilities and we could incur significant liabilities. Sunoco has received a private letter ruling from the IRS, substantially to the effect that, among other things, the contribution and the distribution qualify as a transaction that is tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Internal Revenue Code. In addition, Sunoco has received an opinion of Wachtell, Lipton, Rosen & Katz, counsel to Sunoco, to the effect that the contribution and the distribution will qualify as a transaction that is described in Sections 355 and 368(a)(1)(D) of the Internal Revenue Code. The ruling and the opinion rely on certain facts, assumptions, representations and undertakings from Sunoco and us regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, assumptions, representations or undertakings are incorrect or not otherwise satisfied, Sunoco and its shareholders may not be able to rely on the ruling or the opinion of tax counsel and could be subject to significant tax liabilities. Notwithstanding the private letter ruling and opinion of tax counsel, the IRS could determine on audit that the Separation is taxable if it determines that any of these facts, assumptions, representations or undertakings are not correct or have been violated or if it disagrees with the conclusions in the opinion that are not covered by the private letter ruling, or for other reasons, including as a result of certain significant changes in the stock ownership of Sunoco or us after the Separation. If the Separation is determined to be taxable for U.S. federal income tax purposes, Sunoco and its shareholders could incur significant U.S. federal income tax liabilities and we could incur significant liabilities. See Note 8 to the Combined and Consolidated Financial Statements for a description of the sharing of such liabilities between Sunoco and us. To preserve the tax-free treatment to Sunoco of the contribution and the Distribution, we may not be able to engage in certain transactions. To preserve the tax-free treatment to Sunoco of the contribution and the Distribution, under the tax sharing agreement we are restricted from taking any action that prevents the Distribution and related transactions from being tax-free for U.S. federal income tax purposes. These restrictions may limit our ability to pursue certain strategic transactions or engage in other transactions, including use of our common stock to make acquisitions and equity capital market transactions, that might increase the value of our business. See Note 8 to the Combined and Consolidated Financial Statements for more information. Risks Related to Our Master Limited Partnership We own a significant equity interest in SunCoke Energy Partners, L.P. (the “Partnership”), a publicly traded master limited partnership. We own the general partner of the Partnership, which consists of a 2 percent ownership interest and incentive distribution rights, and we currently own a 55.9 percent interest in the Partnership. The Partnership holds a 65 percent interest in each of two entities that own our Haverhill and Middletown cokemaking facilities and related assets. The Haverhill and Middletown facilities have a combined 300 cokemaking ovens with an aggregate capacity of approximately 1.7 million tons per year and an average age of four years. The Partnership currently operates at full capacity and expects to sell an aggregate of approximately 1.7 million tons of coke per year to two primary customers: AK Steel and ArcelorMittal. All of the Partnership’s coke sales are made pursuant to long-term take-or-pay agreements. Our financial statements include the consolidated results of the Partnership. The Partnership is subject to operating and regulatory risks which are substantially similar to our own. The occurrence of any of these risks could directly or indirectly affect the Partnership’s, as well as our, financial condition, results of operations and cash flows as the Partnership is a consolidated subsidiary. For additional information about the Partnership, see “Cokemaking Operations” and “Formation of a Master Limited Partnership” in Business and Management’s Discussion and Analysis of Financial Condition and Operating Results (Items 1 and 7). 34 We are party to an omnibus agreement with the Partnership that exposes us to various risks and uncertainties. In connection with the initial public offering of the Partnership, we entered into an omnibus agreement with the Partnership. Pursuant to this agreement, we have agreed to grant the Partnership preferential rights to pursue certain growth opportunities we identify in the United States and Canada and a right of first offer to acquire certain of our cokemaking assets located in the United States and Canada for so long as we control the Partnership’s general partner. In addition, pursuant to this agreement, we have agreed, for a period of five years from the closing of the initial public offering, to make the Partnership whole, in certain circumstances, to the extent of a customer’s failure to satisfy its obligations or to the extent a customer’s obligations are reduced. This includes an obligation during this five year period to indemnify the Partnership in the event that AK Steel fails to fulfill its obligations to purchase or pay for coke under the Haverhill coke sales agreement, subject to certain conditions. Additionally, pursuant to this agreement, we have agreed to indemnify the Partnership for certain environmental remediation costs arising prior to the closing of the initial public offering. The agreement further provides that we will fully indemnify the Partnership with respect to any tax liability arising prior to or in connection with the closing of the initial public offering and that we will cure or fully indemnify the Partnership for losses resulting from certain title defects at the properties owned by the Partnership or its subsidiaries. Our obligations and the extent of our exposures that may arise under the omnibus agreement are subject to various contingencies and cannot be estimated with certainty at this time. The tax treatment of the Partnership depends on its status as a partnership for federal income tax purposes, as well as not being subject to a material amount of entity level taxation by individual states. If the Internal Revenue Service (“IRS”) treats the Partnership as a corporation or it becomes subject to a material amount of entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to its unitholders, including SunCoke Energy. The anticipated after-tax economic benefit of SunCoke Energy’s investment in the common units of the Partnership depends largely on the Partnership being treated as a partnership for federal income tax purposes. The Partnership has not requested, and does not plan to request, a ruling from the IRS on this matter. The IRS may adopt positions that differ from the ones the Partnership has taken. A successful IRS contest of the federal income tax positions the Partnership takes may impact adversely the market for its common units, and the costs of any IRS contest will reduce the Partnership’s cash available for distribution to unitholders, including SunCoke Energy. If the Partnership was treated as a corporation for federal income tax purposes, it would pay federal income tax at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to unitholders, including SunCoke Energy, generally would be taxed again as corporate distributions. Treatment of the Partnership as a corporation would result in a material reduction in its anticipated cash flow and after-tax return to unitholders, including SunCoke Energy. Current law may change so as to cause the Partnership to be treated as a corporation for federal income tax purposes or to otherwise subject it to a material level of entity level taxation. States are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. If any of these states were to impose a tax on the Partnership, the cash available for distribution to unitholders, including Suncoke Energy, would be reduced. The tax treatment of publicly traded partnerships or an investment in the Partnership’s common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis. The present federal income tax treatment of publicly traded partnerships, including the Partnership, or an investment in its common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for the Partnership to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause us to change our 35 business activities, or affect the tax consequences of an investment in its common units. For example, members of Congress have been considering substantive changes to the definition of qualifying income and the treatment of certain types of income earned from partnerships. While these specific proposals would not appear to affect the treatment of the Partnership as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of SunCoke Energy’s investment in the Partnership’s common units. Item 1B. Unresolved Staff Comments None. Item 2. Properties Properties We own the following real property: • • • • • Approximately 66 acres in Vansant (Buchanan County), Virginia, on which the Jewell cokemaking facility is located, along with an additional approximately 2,550 acres including the offices, warehouse and support buildings for our Jewell coal and coke affiliates located in Buchanan County, Virginia, as well as other general property holdings and unoccupied land in Buchanan County, Virginia and McDowell County, West Virginia. In addition, we own certain mineral rights on approximately 1,650 acres of property in Buchanan, Dickenson and Wise Counties, Virginia. Approximately 250 acres in Russell County, Virginia owned by the HKCC Companies, which include a warehousing facility, two coal preparation plants and certain coal loadout facilities as well as unoccupied land. Approximately 400 acres in Franklin Furnace (Scioto County), Ohio, on which the Haverhill cokemaking facility (both the first and second phases) is located. Approximately 41 acres in Granite City (Madison County), Illinois, adjacent to the U.S. Steel Granite City Works facility, on which the Granite City cokemaking facility is located. Upon the earlier of ceasing production at the facility or the end of 2044, U.S. Steel has the right to repurchase the property, including the facility, at the fair market value of the land. Alternatively, U.S. Steel may require us to demolish and remove the facility and remediate the site to original condition upon exercise of its option to repurchase the land. Approximately 250 acres in Middletown (Butler County), Ohio near AK Steel’s Middletown Works facility, on which the Middletown cokemaking facility is located. We lease the following real property: • • • • Approximately 88 acres of land located in East Chicago (Lake County), Indiana, on which the Indiana Harbor cokemaking facility is located and, through a sublease, the coal handling and blending facilities that service the Indiana Harbor cokemaking facility. The leased property is inside ArcelorMittal’s Indiana Harbor Works facility and is part of an enterprise zone. Approximately 22 acres of land located in Buchanan County, Virginia, on which one of our coal preparation plants is located. Our former corporate headquarters located in Knoxville, Tennessee, under a ten year lease which commenced in 2007. Beginning in the second quarter of 2011, concurrent with our move to Lisle, Illinois, this space was subleased to another tenant for the remainder of the lease term, although we remain directly liable to the landlord under the original lease. Our corporate headquarters is located in leased office space in Lisle, Illinois under an 11-year lease that commenced in 2011. 36 In addition, through our Jewell coal affiliates and the HKCC Companies, we lease small parcels of land, mineral rights and coal mining rights for approximately 127 thousand acres of land in Buchanan and Russell Counties, Virginia and McDowell County, West Virginia. Substantially all of the leases are “life of mine” agreements that extend our mining rights until all reserves have been recovered. These leases convey mining rights to us in exchange for payment of certain royalties and/or fixed fees. We use internal land managers and attorneys to perform title reviews on properties prior to obtaining coal leases. Set forth below is a map depicting the properties and facilities of our coal mining operations. 37 The table below sets forth the proven and probable metallurgical coal reserves at our Jewell coal mining operations as of December 31, 2012: Total Demonstrated Reserves (millions of tons)(1)(2) Reserves Tons by Assignment Tons by Mining Type Tons by Permit Status Tons by Property Control Not Seam Total Proven Probable Assigned Unassigned Surface Deep Permitted Permitted Owned Leased 0.16 Hagy . . . . . . . . . . . . . . . 0.50 0.34 0.16 Middle Splashdam . . . . 1.58 1.42 0.11 Upper Banner . . . . . . . . 0.52 0.41 Kennedy . . . . . . . . . . . . 2.88 2.40 0.48 Red Ash . . . . . . . . . . . . 26.91 16.77 10.14 3.01 Jawbone Rider . . . . . . . 7.29 4.28 Jawbone (JB30) . . . . . . 41.28 24.67 16.61 3.26 Tiller . . . . . . . . . . . . . . . 12.04 8.78 0.13 0.27 0.00 0.14 3.23 0.00 8.87 7.09 Grand Total . . . . . . . . 93.00 59.07 33.93 19.73 0.37 1.31 0.52 2.74 23.68 7.29 32.41 4.95 73.27 0.50 0.00 1.58 0.00 0.52 0.00 0.00 2.88 0.00 26.91 7.29 0.00 0.34 40.94 0.04 12.00 0.13 0.27 0.00 0.29 7.64 0.00 7.22 7.61 0.38 92.62 23.16 0.37 1.31 0.52 2.59 19.27 7.29 34.06 4.43 69.84 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.50 1.58 0.52 2.88 26.91 7.29 41.28 12.04 93.00 (1) All tons are recoverable, reserve tons utilizing appropriate mine recovery, wash recovery at 1.50 float, preparation plant efficiency, and moisture factors. (2) Amounts may not add to totals due to rounding. The table below sets forth a summary of the proven and probable metallurgical coal reserves of the HKCC Companies as of December 31, 2012: Total Demonstrated Reserves (millions of tons)(1)(2) Reserves Tons by Assignment Tons by Mining Type Tons by Permit Status Tons by Property Control Seam Total Proven Probable Assigned Unassigned Surface Deep Permitted Permitted Owned Leased Lower Banner . . . . . . . . 2.82 1.93 Kennedy . . . . . . . . . . . . 3.27 2.84 Red Ash . . . . . . . . . . . . 4.98 4.52 Jawbone Rider . . . . . . . 7.60 6.76 Jawbone (JB20-30 & JB 10-30) . . . . . . . . . 1.44 1.43 Grand Total . . . . . . . . 20.11 17.48 0.89 0.43 0.46 0.84 0.01 2.63 2.82 3.27 4.98 7.60 1.44 20.11 0.00 0.00 0.00 0.00 0.00 0.00 1.49 0.19 0.00 0.00 1.33 3.08 4.98 7.60 0.00 1.44 1.68 18.43 0.00 0.57 0.00 0.00 0.00 0.57 2.82 2.70 4.98 7.60 1.44 19.54 0.03 0.04 0.00 0.00 0.00 0.07 2.79 3.23 4.98 7.60 1.44 20.04 Not (1) All tons are recoverable, reserve tons utilizing appropriate mine recovery, wash recovery at 1.50 float, and moisture factors. (2) Amounts may not add to totals due to rounding. The table below sets forth the historical amount of coal produced at our coal mining operations: Company Operated Mines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contractor Operated Mines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 878 842 867 609(1) 522(1) 226 823 311 879 300 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,476 1,364 1,104 1,134 1,179 Years Ended December 31, 2012 2011 2010 2009 2008 (1) These amounts include coal production of the HKCC Companies, which we acquired in January 2011. 38 Item 3. Legal Proceedings Beginning in July 2009, ArcelorMittal initiated legal proceedings challenging the prices we charged ArcelorMittal under the Jewell coke sales agreement. In January 2011, we participated in a mediation ordered by the U.S. District Court for the Northern District of Ohio (Eastern Division) with ArcelorMittal that resulted in a commercial resolution of the litigation. We entered into a settlement agreement with ArcelorMittal to resolve the lawsuit concerning coke pricing for the Jewell facility. The parties agreed to amend the Jewell and Haverhill coke sales agreements effective January 1, 2011 to eliminate the fixed coal cost adjustment factor in the Jewell agreement and increase the operating cost and fixed fee components of the coke price under both agreements. The parties also agreed that the take-or-pay provisions of these coke sales agreements would remain in effect through the end of the terms of these agreements in December 2020. Prior to the settlement, these take-or-pay provisions were scheduled to change in the second half of 2012 into annually adjusted provisions that would have only required ArcelorMittal to purchase coke from us for its projected requirements above certain fixed thresholds. If the amendments to the Jewell and Haverhill coke supply agreements had been in place during 2010, our pretax earnings would have been reduced by approximately $51 million. On August 3, 2010, ArcelorMittal (through its main United States subsidiary) gave the partnership that owns the Indiana Harbor cokemaking facility (“Indiana Harbor Partnership”), in which we are the general partner and currently own an 85 percent interest, written notice that it intended to arbitrate certain outstanding issues under the Indiana Harbor coke sales agreement. ArcelorMittal claimed that it has been subject to substantial overcharges and losses as a result of: (1) alleged improper force majeure notifications issued by the Indiana Harbor Partnership in 2010, (2) the alleged overstatement of the coal cost component of the coke price, (3) the Indiana Harbor Partnership allegedly failing to provide the ongoing anticipated capital needs of the Indiana Harbor cokemaking facility, and (4) the alleged inadequacy of the Indiana Harbor Partnership’s procedures to control coal inventory loss. We entered into a settlement agreement with ArcelorMittal to resolve the Indiana Harbor arbitration claims. The settlement was effective January 1, 2011 and will not significantly impact our future income. The EPA has issued NOVs to us for our Haverhill, Granite City, Middletown and Indiana Harbor cokemaking facilities described in Note 17 to our Combined and Consolidated Financial Statements. Many other legal and administrative proceedings are pending or may be brought against us arising out of our current and past operations, including matters related to commercial and tax disputes, product liability, antitrust, employment claims, natural resource damage claims, premises-liability claims, allegations of exposures of third parties to toxic substances and general environmental claims. Although the ultimate outcome of these proceedings cannot be ascertained at this time, it is reasonably possible that some of them could be resolved unfavorably to us. Our management believes that any liabilities that may arise from such matters would not be material in relation to our business or our consolidated financial position, results of operations or cash flows at December 31, 2012. Item 4. Mine Safety Disclosures The information concerning mine safety violations and other regulatory matters that we are required to report in accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95.1 to this Annual Report on Form 10-K. 39 Item 5. Market for Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of PART II Equity Securities Market Information Shares of our common stock, which is traded under the stock trading symbol “SXC”, have been trading since July 21, 2011, when our stock was listed on the New York Stock Exchange. As a result, the table below provides data beginning with the third quarter of 2011. Quarterly price ranges of our common stock are based on the high and low prices from intraday trades. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . First Quarter Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $16.00 15.37 17.59 17.24 $11.01 13.10 14.04 14.26 18.00 13.11 10.78 9.20 2012 2011 High Low High Low Holders As of February 15, 2013, we had a total of 70,055,748 issued and outstanding shares of our common stock and had 16,099 holders of record of our common stock. Dividends Since our formation, we have not paid any dividends on our common stock. We have no current plans to pay any dividends on our common stock. Our payment of dividends in the future, if any, will be determined by our Board of Directors and will depend on business conditions, our financial condition, earnings, liquidity and capital requirements, covenants in our debt agreements and other factors. Share Repurchase Program On February 16, 2012, our Board of Directors authorized a program to repurchase an aggregate amount of up to 3,500,000 shares of our common stock through the end of 2015 from time to time in the open market, through privately negotiated transactions, block transactions or otherwise in order to counter the dilutive impact of exercised stock options and the vesting of restricted stock grants. The Company did not make any repurchases of common stock during the fourth quarter of 2012. Period Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1) October 1 – 31, 2012 . . . . . . . . . . . . . . . . . . . November 1 – 30, 2012 . . . . . . . . . . . . . . . . . December 1 – 31, 2012 . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — (In millions, except per share amounts) $— $— $— — — — Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs(1) 2.9 2.9 2.9 (1) On February 29, 2012, we reported that our Board of Directors authorized the repurchase of up to 3.5 million shares of the Company’s common stock in order to counter the dilutive impact of exercised stock options and the vesting of restricted stock grants. Such authorization expires on December 31, 2015. 40 Item 6. Selected Financial Data The following table presents summary combined and consolidated operating results and other information of SunCoke Energy and should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Combined and Consolidated Financial Statements and accompanying notes included elsewhere in this Annual Report on Form 10-K. The historical Combined Financial Statements for periods prior to the Separation Date include the accounts of all operations that comprised the cokemaking and coal mining operations of Sunoco, after elimination of all intercompany balances and transactions within the combined group of companies. The historical Combined Financial Statements also include allocations of certain Sunoco corporate expenses. Our management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses were reasonable. However, such expenses should not be considered indicative of the actual level of expense that we would have incurred if we had operated as an independent, publicly-traded company during the periods prior to the IPO or of the costs expected to be incurred in future periods. See Note 6 to our Combined and Consolidated Financial Statements for further information regarding allocated expenses. The weighted average number of common shares outstanding used in the computation of earnings attributable to SunCoke Energy, Inc. / net parent investment per common share for periods prior to 2012 includes 70.0 million shares of common stock owned by Sunoco on the Separation Date as a result of its contribution of the assets of its cokemaking and coal mining operations to us and related capitalization. Operating Results: Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income attributable to SunCoke Energy, Inc. / net Years Ended December 31, 2012 2011 2010 2009 2008 (Dollars in millions, except per share amounts) $1,914.1 $ 173.7 $ 102.5 $1,538.9 67.5 $ 58.9 $ $1,326.5 $ 174.2 $ 146.3 $1,145.0 $ 211.6 $ 211.2 $ 840.3 $ 150.7 $ 132.9 parent investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 98.8 $ 60.6 $ 139.2 $ 189.6 $ 113.9 Earnings attributable to SunCoke Energy, Inc. / net parent investment per common share: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 1.41 1.40 $ $ 0.87 0.87 $ $ 1.99 1.99 $ $ 2.71 2.71 $ $ 1.63 1.63 Other Information: Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt, including current portion (due to $ 239.2 $2,011.0 $ 127.5 $1,941.8 $ 40.1 $1,718.4 $ 2.7 $1,546.7 $ 23.0 $1,312.9 unrelated parties) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 723.4 $ 726.4 $ — $ — $ — SunCoke Energy, Inc. stockholders’ equity / net parent investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 539.1 $ 525.5 $ 369.5 $ 742.0 $ 552.4 41 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations This Annual Report on Form 10-K contains certain forward-looking statements of expected future developments, as defined in the Private Securities Litigation Reform Act of 1995. This discussion contains forward-looking statements about our business, operations and industry that involve risks and uncertainties, such as statements regarding our plans, objectives, expectations and intentions. Our future results and financial condition may differ materially from those we currently anticipate as a result of the factors we describe under “Cautionary Statement Concerning Forward-Looking Statements” and “Risk Factors.” Unless the context otherwise requires, references in this report to “the Company,” “we,” “our,” “us,” or like terms, when used in describing periods prior to July 18, 2011, refer to the cokemaking and coal mining operations of Sunoco prior to their transfer to the Company in connection with the Separation. References when used in describing periods after July 18, 2011, refer to SunCoke Energy, Inc. and its subsidiaries. This “Management’s Discussion and Analysis of Financial Condition and Results of Operations” is based on financial data derived from the financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and certain other financial data that is prepared using non-GAAP measures. For a reconciliation of these non-GAAP measures to the most comparable GAAP components, see “Non- GAAP Financial Measures” at the end of this Item. Overview SunCoke Energy, Inc. (“SunCoke Energy”, “Company”, “we”, “our” and “us”) is the largest independent producer of high-quality coke in the Americas, as measured by tons of coke produced each year, and has more than 50 years of coke production experience. Coke is a principal raw material in the blast furnace steelmaking process. Coke is generally produced by heating metallurgical coal in a refractory oven, which releases certain volatile components from the coal, thus transforming the coal into coke. We have designed, developed and built, and own and operate five cokemaking facilities in the United States (“U.S.”) and designed and operate one cokemaking facility in Brazil under licensing and operating agreements on behalf of our customer. Our newest U.S. cokemaking facility in Middletown, Ohio commenced operations in October 2011 bringing our total U.S. cokemaking capacity from approximately 3.7 million tons of coke per year to approximately 4.2 million tons of coke per year. The cokemaking facility that we operate in Brazil has cokemaking capacity of approximately 1.7 million tons of coke per year. We have a preferred stock investment in the project company that owns the Brazil facility. Our cokemaking ovens utilize efficient, modern heat recovery technology designed to combust the coal’s volatile components liberated during the cokemaking process and use the resulting heat to create steam or electricity for sale. This differs from by-product cokemaking which seeks to repurpose the coal’s liberated volatile components for other uses. We have also constructed the only greenfield cokemaking facilities in the United States in the last 25 years and are the only North American coke producer that utilizes heat recovery technology in the cokemaking process. We believe that heat recovery technology has several advantages over the alternative by-product cokemaking process, including producing higher quality coke, using waste heat to generate steam or electricity for sale and reducing environmental impact. Our Granite City facility and the first phase of our Haverhill facility, or Haverhill 1, include steam generation facilities which use hot flue gas from the cokemaking process to produce steam. The steam is sold to third-parties pursuant to steam supply and purchase agreements. Our Middletown facility and the second phase of our Haverhill facility, or Haverhill 2, include cogeneration plants that use the hot flue gas created by the cokemaking process to generate electricity. The electricity is either sold into the regional power market or to AK Steel pursuant to energy sales agreements. We own and operate coal mining operations in Virginia and West Virginia that sold approximately 1.3 million tons of metallurgical coal (including internal sales to our cokemaking operations) and 0.2 million tons of thermal coal in 2012. 42 Incorporated in Delaware in 2010 and headquartered in Lisle, Illinois, we became a publicly-traded company in 2011 and our stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “SXC.” As discussed below, our two-step separation (“Separation”) from Sunoco, Inc. (“Sunoco”) was completed in 2012. Our Separation from Sunoco On January 17, 2012 (the “Distribution Date”), we became an independent, publicly-traded company following our separation from Sunoco. Our separation from Sunoco occurred in two steps: • We were formed as a wholly-owned subsidiary of Sunoco. On July 18, 2011 (the “Separation Date”), Sunoco contributed the subsidiaries, assets and liabilities that were primarily related to its cokemaking and coal mining operations to us in exchange for shares of our common stock. As of such date, Sunoco owned 100 percent of our common stock. On July 26, 2011, we completed an initial public offering (“IPO”) of 13,340,000 shares of our common stock, or 19.1 percent of our outstanding common stock. Following the IPO, Sunoco continued to own 56,660,000 shares of our common stock, or 80.9 percent of our outstanding common stock. • On the Distribution Date, Sunoco made a pro-rata, tax free distribution (the “Distribution”) of the remaining shares of our common stock that it owned in the form of a special stock dividend to Sunoco shareholders. Sunoco shareholders received 0.53046456 of a share of common stock for every share of Sunoco common stock held as of the close of business on January 5, 2012, the record date for the Distribution. After the Distribution, Sunoco ceased to own any shares of our common stock. Formation of a Master Limited Partnership On January 24, 2013, we completed the initial public offering of a master limited partnership (“the Partnership”) through the sale of 13,500,000 common units of limited partner interests in the Partnership in exchange for $233.1 million of net proceeds. Of these net proceeds, $67 million was retained by the Partnership for environmental remediation capital expenditures and $12.4 million for sales discounts related to tax credits owed to our customers. Upon the closing of the Partnership offering (“the Partnership offering”), we own the general partner of the Partnership, which consists of a 2 percent ownership interest and incentive distribution rights, and we currently own a 55.9 percent interest in the Partnership. The key assets of the Partnership are 65 percent of our interests in each of our Haverhill and Middletown cokemaking and heat recovery facilities. The operations of the Partnership will be consolidated in our results. We are also party to an omnibus agreement pursuant to which we will provide remarketing efforts to the Partnership upon the occurrence of certain potential adverse events under our coke sales agreements, indemnification of certain environmental costs and preferential rights for growth opportunities. In connection with the closing of the Partnership offering, we repaid $225.0 million of our Term Loan and entered into an amendment to our Credit Agreement. The Partnership issued $150.0 million of Senior Notes and entered into a $100.0 million revolving credit facility. For a more detailed discussion see “Liquidity and Capital Resources.” 2012 Key Financial Results • Total revenues in 2012 increased 24 percent to $1,914.1 million primarily due to the addition of our Middletown operations which contributed $260.3 million to the increase. The remaining increase was primarily driven by higher sales in our Jewell Coke and Other Domestic Coke segments due to the pass- through of higher coal prices and transportation costs. Higher sales in our Coal Mining segment, which reflect higher coal prices and increased volumes, also contributed to the increase. • Net income attributable to stockholders was $98.8 million in 2012 compared to $60.6 million in 2011. The increase was due to the contribution of our Middletown facility and the strong performance of our cokemaking operations, offset by an increase in our interest cost as a stand-alone financial structure and decreased performance from our Coal Mining segment. 43 • Adjusted EBITDA was $265.7 million in 2012 compared to $138.8 million in 2011 due primarily to the same factors driving the increase in net income discussed above. • Cash generated from operating activities was $206.1 million in 2012 compared to $101.3 million in 2011. The increase is due primarily to a full year of production at Middletown in 2012 as compared to the 2011 period. Additionally, changes in working capital, including a decline in inventory in 2012, further contributed to the increase. Our Focus in 2012 In 2012, we executed on our commitments and made progress in laying the foundation for future growth. We delivered solid performance across our cokemaking operations including the start-up of our Middletown facility. We also took actions in our coal operations to address challenges caused by weak demand and a low price environment. In 2012, we generated cash from operating activities of $206.1 million and achieved Adjusted EBITDA of $265.7 million. Further, we have positioned our business for future growth with the signing of an agreement to form a cokemaking joint venture in India with VISA Steel Limited, filing a permit application to potentially build a new U.S. cokemaking facility and pursuing our plans for an initial public offering of a master limited partnership. Our 2012 strategies and accomplishments were as follows: • Execute the startup of our Middletown cokemaking operations and achieve full production. • Achieve targeted domestic coke production volume of 4.0 to 4.2 million tons through continued focus on operational excellence, including safety and environmental stewardship, at all facilities. • Continue permitting work for a potential new U.S. plant in anticipation of a market recovery. • Continue pursuing and exploring opportunities to profitably expand our cokemaking presence in global markets with a focus on India. • • Improve efficiency of mining operations and implement cost reduction plans to navigate the difficult industry environment. Pursue an initial public offering of a master limited partnership for a portion of our cokemaking business. Execute the ramp up of our Middletown cokemaking operations and achieve full production. We successfully executed the start-up of our Middletown, Ohio cokemaking facility and reached full production in the first quarter of 2012, ahead of schedule. The facility consists of 100 ovens which have a cokemaking capacity of 550 thousand tons of coke per year and a cogeneration facility which generates, on average, approximately 45 megawatts of electricity per hour. In 2012, the Middletown facility produced 602 thousand tons of coke, which is in excess of 100 percent capacity utilization, and contributed $289.0 million and $59.9 million to revenues and Adjusted EBITDA, respectively. Achieve targeted domestic coke production volume of 4.0 to 4.2 million tons through continued focus on operational excellence, including safety and environmental stewardship, at all facilities. During 2012, we produced 4.3 million tons of coke, exceeding both 100 percent capacity utilization and our domestic coke production target of 4.0 to 4.2 million tons. In addition, the coal-to-coke yield performance improved at all our domestic cokemaking facilities, contributing positively to 2012 results. Operating our cokemaking facilities reliably and at low cost, while producing consistently high quality coke, is critical to maintaining the satisfaction of existing customers and our ability to grow with new and existing customers. We have continued to achieve reliable and cost-efficient operation of our facilities through the SunCoke Way, a standardized processes, procedures and management system incorporating best practices. We believe the SunCoke Way provides the foundation to achieve operational excellence at our facilities and is essential to our future growth. Our expertise at developing, constructing and operating our facilities will enable us to continue growing with current and new customers, as they construct new blast furnaces and their existing cokemaking facilities require replacement. 44 We are also committed to maintaining a safe work environment and ensuring strict compliance with applicable laws and regulations at our cokemaking and coal mining operations. To support these objectives, we have implemented the core components of a structured safety and environmental process and will continue to build upon this and other processes to create a robust framework for managing and monitoring safety and environmental performance. For example, our coal mining operations’ safety performance was in the first quartile of U.S. coal mining companies in 2012. We also seek to foster good relationships with regulators, policymakers, state and local officials and the communities in which we operate. Continue permitting work for a potential new U.S. plant in anticipation of market recovery. We are currently discussing opportunities for developing new heat recovery cokemaking facilities with domestic steel companies. Such cokemaking facilities could be either wholly-owned or developed through other business structures. As applicable, our steel making customers would be expected to purchase coke production under long-term, take or pay contracts. We expect such future facilities would also generate steam, or electrical power, which could either be sold to the steel customer or into the local power market. During 2012, we focused on the design, engineering and planning work required for a potential new cokemaking facility with 120 ovens and approximately 660 thousand tons of capacity. This potential new facility may serve multiple customers while also reserving a portion of its capacity for opportunistic spot market coke sales. We submitted a permit application in Kentucky for this potential facility in December 2012 and will seek customer commitments once the permit has been received while continuing to assess alternative sites in other states. We anticipate receiving our permit in late 2013 or early 2014. Our ability to construct a new facility and to enter into new commercial arrangements is dependent upon market conditions in the steel industry. The Partnership has preferential rights to purchase our interest in this potential facility upon the completion of construction at a price sufficient to provide us with a return on our invested capital equal to our weighted average cost of capital plus 6 percent. Continue pursuing and exploring opportunities to profitably expand our cokemaking presence in global markets, with a focus on India. During 2012, we actively researched a number of coke business opportunities in India. As part of this effort, we announced our plan to form a cokemaking joint venture with VISA Steel Limited in India called VISA SunCoke Limited. VISA SunCoke Limited will be comprised of VISA Steel’s 400 thousand metric ton heat recovery cokemaking facility, and the facility’s associated steam generation units. Upon closing, we will acquire a 49 percent interest in the joint venture, with VISA Steel holding the remaining 51 percent. We believe this joint venture enables us to better pursue future opportunities to grow in India and other emerging markets. We plan to close the transaction in the first quarter of 2013 by making an investment of approximately $67 million, subject to customary closing conditions. Improve efficiency of coal operations and implement cost reduction plans. When we began 2012, our initial strategy was to expand production at our Jewell underground coal mining operations. However, coal market conditions deteriorated throughout 2012 and are expected to remain weak in 2013. As we progressed through 2012, our strategy shifted and we implemented plans to reduce costs and increase productivity in our coal operations. These plans included idling certain high-cost mines; consolidating our labor force and equipment into more productive, lower cost mines; relocating mine sections in our largest mine and implementing deep cut mining plans as permits are received. Simultaneously, we deferred our expansion plans for our Jewell underground mines and substantially all the capital expenditures associated with the expansion plan. Jewell coal mining production was 1.1 million tons in 2012 and we do not anticipate increasing production in 2013. In June 2011, we entered into a series of coal transactions with Revelation Energy, LLC (“Revelation”). Under a contract mining agreement, Revelation will mine approximately 1.2 million tons of coal reserves at our Jewell coal mining operations of which 1.0 million tons is included in our current proven and probable reserve 45 estimate as of December 31, 2012. Mining began in the first quarter of 2012, resulting in approximately 180 thousand tons of production which was lower than expected as a result of permitting delays for a portion of the reserves. We expect the remaining tons to be mined between 2013 and 2015 and anticipate 75 percent of production to be mid-volatility metallurgical coal and 25 percent to be thermal coal. In conjunction with the Revelation agreement, we intended to build a train coal loading facility; however we have deferred the project and are providing load out services to Revelation from our existing facilities. We are evaluating alternatives to this load out facility in conjunction with the potential construction of a new coal preparation plant for our Jewell Coal Mining operations. Pursue an initial public offering of a master limited partnership. On July 19, 2012, our Board of Directors approved the formation of a master limited partnership (the “Partnership”) and the filing of a registration statement to affect the initial public offering of common units representing limited partner interests in the Partnership. On January 24, 2013, we completed the initial public offering of a master limited partnership through the sale of 13,500,000 common units of limited partner interests in the Partnership in exchange for $233.1 million of net proceeds. Of these net proceeds, $67 million was retained by the Partnership for environmental remediation capital expenditures and $12.4 million to pay sales discounts related to tax credits owed to our customers. The Partnership will benefit from favorable partnership tax treatment and is expected to result in a lower cost of capital which could provide us with a potential advantage to grow the business. For a more detailed discussion of the Partnership, see “Formation of a Master Limited Partnership.” Our Focus and Outlook for 2013 In 2013, our primary focus will be to: • Sustain momentum established at our cokemaking facilities. • Execute initiatives at Indiana Harbor and certain of our other domestic cokemaking facilities. • Pursue domestic and international opportunities to grow the coke business. • Optimize coal assets to enhance long-term strategic flexibility. Taking into account the effects of the IPO of our master limited partnership, we expect 2013 net income attributable to Suncoke Energy, Inc. to be in the range of $43 million to $60 million, diluted earnings per share attributable to SunCoke Energy, Inc. stockholders to be in the range of $0.30 to $0.55 and total Adjusted EBITDA to be in the range of $205 million to $230 million. This compares to 2012 net income of $98.8 million, diluted earnings per share attributable to SunCoke Energy, Inc. stockholders of $1.40 and total Adjusted EBITDA of $265.7 million. We expect cash from operations in 2013 of approximately $140 million. Our capital expenditures for 2013 are expected to be approximately $133 million, consisting of $58 million of on-going capital expenditures, $60 million for the refurbishment of the Indiana Harbor facility and $15 million in environmental remediation capital. Sustain momentum at our cokemaking facilities. Given our strong cokemaking operations in 2012 and the growth initiatives we are pursuing, we expect our cokemaking business to maintain its positive momentum over the long term. In 2013 we expect to produce in excess of 4.3 million tons of coke, again exceeding 100 percent capacity utilization. Under the take-or-pay provisions of our contracts, the cost of coal used to make coke for our customers is passed through to them subject to certain yield standards. If we exceed those standards, we recognize the benefit of using less coal to produce the same amount of coke but still get to bill our customer based on the contracted coal-to-coke yield standard. As coal prices decline, coal-to-coke yield benefits also decline as the coal prices passed through to customers is less and therefore the benefit of exceeding the contracted yield standard is less. Due to lower 46 expected coal prices in 2013, we expect less benefit from better coal-to-coke yields, although this will be partially offset by sustained strong domestic cokemaking performance, meaningful improvement at our Indiana Harbor facility and the absence of start-up costs and higher operating expense recovery at our Middletown facility. Despite this reduced benefit we expect Adjusted EBITDA per ton from our cokemaking operations of between $55 and $60 in 2013, consistent with 2012 levels. Execute initiatives at Indiana Harbor and certain of our other domestic cokemaking facilities. The initial term of our coke sales agreement at Indiana Harbor ends on September 30, 2013. In preparation for negotiation of a new long-term contract, we conducted an engineering study to identify major maintenance projects necessary to preserve the production capacity of the facility. In accordance with the findings of the study, we originally estimated that we would spend approximately $50 million. Based on discussions with our customer regarding their requirements for the potential contract renewal term, we now estimate that we could spend as much as $85 million. We spent $14 million related to this project in 2012 and anticipate spending $60 million in 2013. While we believe there is a reasonable likelihood that we will reach agreement with our customer for a new long-term contract, such an agreement may not be reached. We expect to earn a reasonable return on our investment, and consequently the actual level of capital expenditures may depend upon the terms of an eventual agreement with our customer and DTE Energy Company, the third party investor owning a 15 percent interest in the partnership (the “Indiana Harbor Partnership”) that owns the Indiana Harbor cokemaking facility. In addition, we believe the project scope will address items that may be required in connection with the settlement of the NOVs at our Indiana Harbor facility. See the section entitled “Business— Legal and Regulatory Requirements—Environmental Matters and Compliance.” Our customer also has a contractual relationship to purchase steam and electricity from Cokenergy, Inc. (“Cokenergy”), an independent power producer that owns and operates an energy facility, including heat recovery equipment, a flue gas desulfurization system and a power generation plant, that processes hot flue gas from the Indiana Harbor Partnership’s facility to produce steam and electricity and to reduce the sulfur and particulate content of such flue gas. The Indiana Harbor Partnership also has an agreement with Cokenergy under which the Indiana Harbor facility supplies flue gas to Cokenergy and Cokenergy processes such flue gas. The agreement between the Indiana Harbor Partnership and Cokenergy ends on September 30, 2013. In the first six months of the final year of the agreement between the Indiana Harbor Partnership and Cokenergy, the parties are obligated to negotiate in good faith for an extension to the term of the agreement. In the event that the parties cannot reach agreement on an extension of the term of the agreement, and subject to the rights of our customer to purchase the energy facility from Cokenergy, the Indiana Harbor Partnership may purchase certain assets, specifically the flue gas desulfurization system and heat recovery equipment, necessary for the continued operation of the Indiana Harbor cokemaking facility from Cokenergy at fair market value upon written notice to Cokenergy not later than six months prior to the expiration of the agreement. To the extent the Indiana Harbor Partnership does not exercise such right, Cokenergy, at its option, may either abandon or remove all or any of the heat recovery equipment of the energy facility. We have undertaken capital projects to improve the reliability of the energy recovery systems and enhance environmental performance at our Haverhill and Granite City cokemaking facilities. As a result of discussions with the EPA, we spent approximately $5 million related to these projects in 2012 and expect to spend approximately $15 million in 2013 and an additional $80 million in the 2014 to 2016 timeframe, $67 million of which is to be funded with a portion of the proceeds from the Partnership offering. The final cost of the projects will be dependent upon the ultimate outcome of discussions with regulators. We are currently engaged in penalty negotiations with regulators and estimate our probable loss to be approximately $2.2 million. For more information, see the section entitled “Business—Legal and Regulatory Requirements—Environmental Matters and Compliance.” 47 Pursue domestic and international opportunities to grow the coke business. In 2013, we expect to continue to explore ways to grow our coke business both domestically and abroad. We expect to obtain a permit for our next potential U.S. facility in Kentucky in late 2013 or early 2014 and are working to identify and pursue strategic acquisition opportunities for the Partnership in the U.S. and Canada. We plan to close the VISA SunCoke joint venture in the first quarter of 2013 and are continuing to work to identify potential follow-on international opportunities, focusing initially on India. We believe that the efficiencies we have developed from our experience as the leading independent U.S. coke producer and our proven ability to provide a reliable supply of coke make us well suited to purchase or operate facilities, including by-product cokemaking facilities, currently operated by steelmakers or others that would prefer to utilize the capital committed to such equipment for other purposes. According to CRU, in 2011, there was approximately 16 million tons of cokemaking capacity in the U. S. and Canada unaffiliated with us, of which 89 percent was owned by steel producers and 11 percent was owned by merchant providers. We may acquire, make investments in or enter into commercial arrangements with respect to existing cokemaking facilities in order to opportunistically capture market share in the United States and Canada. Optimize coal assets to enhance long-term strategic flexibility. During 2013, we will continue to reposition our mining operations to address near-term market weakness and enhance long-term strategic flexibility. In the first quarter of 2013, we continued with our plan to reduce costs and increase productivity and implemented a reduction in force. This reduction in force resulted in the termination of 52 employees eligible to receive certain payments resulting in expected restructuring charges of $0.7 million during 2013. In addition, we have and will continue to take several actions to reduce costs and increase productivity as previously discussed. Coal mining production was 1.5 million tons in 2012 and we do not anticipate increasing production in 2013. In the fourth quarter of 2012, we negotiated coal sale contracts for 2013 and expect average sales prices in our Coal Mining segment to decrease by approximately $45 to $50 per ton. As a result of these factors, we expect Adjusted EBITDA for our coal mining segment to be in the range of break-even to a loss of $15 million for 2013. Items Impacting Comparability • Middletown Project Execution. We successfully executed the start-up of our Middletown, Ohio cokemaking facility in October 2011 and reached full production in the first quarter of 2012, ahead of schedule. Total costs of the project were approximately $410 million. For the year ended December 31, 2012, the Middletown cokemaking facility produced 602 thousand tons of coke and contributed $289.0 million and $59.9 million to revenues and Adjusted EBITDA, respectively. For the year ended December 31, 2011, the Middletown cokemaking facility produced 68 thousand tons of coke and contributed $28.7 million and ($0.3) million to revenues and Adjusted EBITDA, respectively. Unreimbursed costs and start-up costs of $10.0 million, of which $4.0 million related to start-up activities in the first quarter of 2012, are included in the results of operations for the year ended December 31, 2012. Beginning in 2013, we expect an increase in the recovery of operating costs at Middletown as the operating fee transitions from a fixed amount per ton to a budgeted amount per ton based on the full recovery of expected operating maintenance costs. • Indiana Harbor. On September 30, 2011, we acquired the 19 percent interest held by an affiliate of GE Capital in the Partnership that owns the Indiana Harbor facility for $34.0 million. As a result of this transaction, we now hold an 85 percent interest in the Partnership. The remaining 15 percent interest in the Partnership is owned by an affiliate of DTE Energy Company. The change in ownership percentage contributed $4.7 million and $0.6 million to Net Income attributable to SunCoke Energy, Inc. for the years ended December 31, 2012 and 2011, respectively. In the fourth quarter of 2011, we clarified the interpretation of certain contract and billing items with our customer. As a result, coal spilled during the coke oven charging process (“pad coal”) may not be subsequently reused for making coke for this customer, unless it is included in the coal blend at zero 48 • • • • cost. The Company recorded expense of approximately $7.0 million for the year ended December 31, 2011 related to these contract and billing issues. The Company reached an agreement to settle its contract and billing issues with ArcelorMittal during the fourth quarter of 2012 and reversed $4.2 million of the $7.0 million charge recorded in 2011. For the year ended December 31, 2012, the Company recorded approximately $3.3 million in lower of cost or market adjustments on existing pad coal inventory, and is currently remarketing this pad coal to other customers. Corporate Separation Transactions. Prior to the Distribution Date, our operating expenses included allocations of certain general and administrative costs of Sunoco for services provided to us by Sunoco. During 2011, we replaced most services provided by Sunoco and developed the internal functions, such as financial reporting, tax, regulatory compliance, legal, corporate governance, treasury, internal audit and investor relations, necessary to fulfill our responsibilities as a stand-alone public company. Allocations from Sunoco were $0.6 million and $14.9 million for the years ended December 31, 2012 and 2011, respectively. Additionally, we incurred $7.2 million in nonrecurring operating expense related to headquarter relocation costs and costs associated with hiring key senior management personnel during the year ended December 31, 2011. Loss on Firm Purchase Commitments. During 2011, we estimated that Indiana Harbor would fall short of its 2011 annual minimum coke production requirements by approximately 122 thousand tons. Accordingly, we entered into contracts to procure approximately 133 thousand tons of coke from third parties. However, the coke prices in the purchase agreements exceeded the sales price in our contract with ArcelorMittal. This pricing difference resulted in an estimated loss on firm purchase commitments of $18.5 million ($12.2 million attributable to net parent investment and $6.3 million attributable to noncontrolling interest), all of which was recorded during the first quarter of 2011. In the remainder of 2011, the Company recorded lower of cost or market adjustments of $1.9 million ($1.4 million attributable to SunCoke Energy, Inc./net parent investment and $0.5 million attributable to noncontrolling interests) on this purchased coke. In the second quarter of 2011, the Company sold 38 thousand tons of this coke to ArcelorMittal. Operational improvements at Indiana Harbor subsequent to the first quarter of 2011 increased coke production for the balance of 2011, and Indiana Harbor was able to meet its 2011 contractual requirements with ArcelorMittal. In the third quarter of 2011, the Company entered into an agreement to sell approximately 95 thousand tons of this purchased coke to a customer on a consignment basis that will expire, as amended, on the earlier of April 30, 2013 or full consumption of, and payment for, the coke. The customer did not consume any coke in fiscal 2011. The customer consumed approximately 73 thousand tons of consigned coke during 2012 and the remaining 22 thousand tons during January 2013. Black Lung Obligations. The Patient Protection and Affordable Care Act (“PPACA”), which was implemented in 2010, amended previous legislation related to coal workers’ black lung obligations. PPACA provides for the automatic extension of awarded lifetime benefits to surviving spouses and changes the legal criteria used to assess and award claims. Our obligation related to black lung benefits is estimated based on various assumptions, including actuarial estimates, discount rates, and changes in health care costs. The impact of PPACA in 2011 as well as, changes in discount rates and other assumptions, increased our black lung benefit obligation by approximately $1.8 million and $6.0 million during 2012 and 2011, respectively. Resolution of Contract Disputes with ArcelorMittal. Beginning in July 2009, ArcelorMittal initiated legal proceedings challenging the prices charged to ArcelorMittal under the Jewell coke sales agreement. In January 2011, we participated in court ordered mediation with ArcelorMittal which resulted in a commercial resolution of the litigation. The parties agreed to amend the Jewell and Haverhill coke sales agreements effective January 1, 2011 to eliminate the fixed coal cost adjustment factor in the Jewell agreement and increase the operating cost and fixed fee components of the coke price under both agreements. The parties also agreed that the take-or-pay provisions of these coke sales agreements would remain in effect through the end of the terms of these agreements in December 2020. 49 Prior to the settlement, these take-or-pay provisions were scheduled to change in the second half of 2012 into annually adjusted provisions that would have only required ArcelorMittal to purchase coke from us for its projected requirements above certain fixed thresholds. This extension provides us a guaranteed outlet for coke production through 2020. We also expect that the settlement will significantly reduce the concentration of our profitability in the Jewell coke sales agreement. For example, with our Middletown facility in full production, none of our coke sales agreements constitute more than approximately 20 percent of our overall operating income excluding corporate overhead costs, whereas the Jewell coke sales agreement accounted for nearly 80 percent of such income in 2010. If the amendments to the coke supply agreements had been in place during 2010, the pretax earnings of the Jewell Coke segment would have been reduced by approximately $69 million and the pretax earnings of our Haverhill facility included in the Other Domestic Coke segment would have been increased by approximately $18 million. We also entered into a settlement agreement with ArcelorMittal to resolve the Indiana Harbor arbitration claims. This settlement was effective January 2011 and will not significantly impact our future income. Acquisition of HKCC Companies. In January 2011, we acquired the HKCC Companies and its affiliated companies for approximately $52 million, consisting of net cash payment of $38 million and contingent consideration of $14 million. HKCC has 20 million tons of proven and probable coals reserves located in Russell and Buchanan Counties in Virginia, contiguous to our existing metallurgical coal mining operations. While lower production levels are anticipated in the short-term due to unfavorable coal market conditions, this acquisition has the ability to produce between 250 thousand and 300 thousand tons of coal production annually, with the potential to expand production in the future. HKCC contributed revenues and gross margin of $8.1 million and ($2.1) million, respectively, for the year ended December 31, 2012 and contributed $19.4 million and $2.7 million to revenues and gross margin, respectively, for the year ended December 31, 2011. Financing Activities. Prior to the IPO, our primary source of liquidity was cash from operations and borrowings from Sunoco. Our funding from Sunoco was through floating-rate borrowings from Sunoco, Inc. (R&M), a wholly-owned subsidiary of Sunoco. The agreements between Sunoco and the Company related to these borrowings terminated concurrent with the IPO and all outstanding advances were settled. Prior to the Separation Date, we also earned interest income on $289.0 million in notes receivable from The Claymont Investment Company (“Claymont”), a then wholly-owned subsidiary of Sunoco. In connection with the Separation, Sunoco contributed Claymont to SunCoke Energy. As a result, we no longer earn interest income for these notes, as the balances and related interest are eliminated in our consolidated results. For periods prior to the Separation Date, interest income exceeded interest expense. Between July 26, 2011 through December 31, 2012, SunCoke Energy issued $730.0 million in debt. For periods subsequent to the Separation Date, interest expense exceeded interest income. For more information, see the section entitled “Liquidity and Capital Resources.” • • 50 Results of Operations The following table sets forth amounts from the Combined and Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010: Years Ended December 31, 2012 2011 2010 (Dollars in millions) Revenues Sales and other operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income, net $1,902.0 12.1 $1,527.6 11.3 $1,316.5 10.0 Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,914.1 1,538.9 1,326.5 Costs and Operating Expenses Cost of products sold and operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on firm purchase commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,577.6 — 82.0 80.8 1,305.8 18.5 88.7 58.4 1,036.9 — 67.2 48.2 Total costs and operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,740.4 1,471.4 1,152.3 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173.7 Interest income—affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost—affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capitalized interest Total financing (expense) income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income before income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Net income (loss) attributable to noncontrolling interests . . . . . . . . . . . . . . Net income attributable to SunCoke Energy, Inc. / net parent — 0.4 — (48.2) — (47.8) 125.9 23.4 102.5 3.7 67.5 12.5 0.4 (3.5) (20.6) 9.8 (1.4) 66.1 7.2 58.9 (1.7) 174.2 23.7 — (5.4) — 0.7 19.0 193.2 46.9 146.3 7.1 investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 98.8 $ 60.6 $ 139.2 Year Ended December 31, 2012 compared to Year Ended December 31, 2011 Revenues. Our total revenues, net of sales discounts, were $1,914.1 million for the year ended December 31, 2012 compared to $1,538.9 million for the corresponding period of 2011. Our Middletown facility contributed $260.3 million to the increase in revenues. The remaining increase was primarily driven by higher sales in our Jewell Coke and Other Domestic Coke segments due to the pass-through of higher coal prices and transportation costs. Also contributing to the revenue increase was higher sales in our Coal Mining segment, due primarily to higher coal prices and increased volumes. Sales price discounts provided to our customers in connection with sharing of nonconventional fuel tax credits were $11.2 million and $12.9 million for 2012 and 2011, respectively. Costs and Operating Expenses. Total operating expenses were $1,740.4 million for the year ended December 31, 2012 compared to $1,471.4 million for the corresponding period of 2011. Our Middletown facility contributed $212.3 million to the increase in operating expenses. The remaining increase in cost of products sold and operating expenses was driven by increased coal and coke volumes and higher coal mining costs. Selling, general and administrative expenses (“SG&A”) decreased slightly in 2012 due to favorable comparison to the prior year, which included start-up costs related to our Middletown operations and restructuring charges related to the relocation of our corporate headquarters, offset partially by higher legal costs, increased headcount and higher share-based compensation expense. Depreciation, depletion and amortization expense increased due to the 51 addition of our Middletown cokemaking facility, higher depreciation at our Coal Mining segment due to prior year capital expenditures and accelerated depreciation taken on certain assets due to a change in their estimated useful lives. Financing Expense, Net. Net financing expense was $47.8 million for the year ended December 31, 2012 compared to $1.4 million for the year ended December 31, 2011. Comparability between periods is impacted by the financing activities discussed above. Income Taxes. Income tax expense increased $16.2 million to $23.4 million for the year ended December 31, 2012 compared to $7.2 million for the corresponding period of 2011. Our effective tax rate was 18.6 percent and 10.9 percent in 2012 and 2011, respectively. Our effective tax rate, after deducting income attributable to noncontrolling interests, and excluding tax credits and the effects of state statutory tax rate changes, was 34.8 percent for 2012 compared to 38.3 percent for 2011. Our effective tax rate, excluding the items referenced above, was lower for the year ended December 31, 2012 as compared to the year ended December 31, 2011 largely due to the minimized impact of permanent book to tax differences given the increase in pre-tax income. Additionally, the loss of the 2010 manufacturer’s deduction for federal income tax purposes in 2011 further contributed to the decrease. We were not able to utilize this tax benefit in 2011 because we had a federal net operating loss for tax purposes. Nonconventional fuel tax credits decreased $3.8 million to $16.0 million for 2012 from $19.8 million in 2011 due to the expiration of the Haverhill nonconventional fuel tax credits on June 30, 2012. In 2012, we recorded a net tax credit benefit of $1.2 million in addition to a $1.9 million state tax benefit related to a state tax rate change. Year Ended December 31, 2011 compared to Year Ended December 31, 2010 Revenues. Our total revenues, net of sales discounts, were $1,538.9 million for the year ended December 31, 2011 compared to $1,326.5 million for the corresponding period of 2010. The increase was primarily driven by higher sales in our Other Domestic Coke segment due to the pass-through of higher coal prices and an increase in fees. Higher sales in our Coal Mining segment, due to higher coal prices and the contribution from HKCC Companies, also contributed to the increase in revenues. Sales price discounts provided to our customers in connection with sharing of nonconventional fuels tax credits were $12.9 million and $12.0 million for the year ended December 31, 2011 and 2010, respectively. Costs and Operating Expenses. Total operating expenses were $1,471.4 million for the year ended December 31, 2011 compared to $1,152.3 million for the corresponding period of 2010. The increase in cost of products sold and operating expenses was driven by higher purchased coal costs, increased coal and coke volumes and higher coal mining costs. SG&A expense increased $21.5 million in 2011 due to higher corporate expenses associated with public company readiness, increased headcount and relocation costs and higher pre-start up Middletown costs. SG&A expenses in 2010 included legal fees and settlement charges related to the resolution of the Jewell Coke contract amendments and a settlement agreement with ArcelorMittal that resolved Indiana Harbor arbitration claims. Depreciation, depletion and amortization expense increased due to the addition of the Middletown cokemaking facility, the acquisition of HKCC and higher depreciation at our Granite City facility due to prior year capital expenditures. Financing (Expense) Income, Net. Net financing expense was $1.4 million for the year ended December 31, 2011 compared to $19.0 million in net financing income for the year ended December 31, 2010. The 2011 period reflects $20.6 million of interest expense associated with the issuance of debt and a $10.8 million decrease in interest income from Claymont, a former Sunoco subsidiary, offset by a $9.1 million increase in capitalized interest related to capital projects. Beginning in the third quarter of 2011, the Company used its external interest rate as a basis for capitalizing interest, which was higher than historical rates. Income Taxes. Income tax expense decreased $39.7 million to $7.2 million for the year ended December 31, 2011 compared to $46.9 million for the corresponding period of 2010. Our effective tax rate was 10.9 percent and 24.3 percent, respectively. Our effective tax rate, after deducting income attributable to noncontrolling 52 interests, and excluding tax credits and the effects of the Indiana and Illinois statutory rate changes recorded during the second and third quarters of 2011, was 38.3 percent for the year ended December 31, 2011 compared to 35.4 percent for the corresponding period of 2010. Our effective tax rate, excluding the items referenced above, was higher for the year ended December 31, 2011 compared to December 31, 2010 largely due to the loss of the 2010 manufacturer’s deduction for federal income tax purposes. We were not able to utilize this tax benefit in 2011 because we had a federal net operating loss for tax purposes. Nonconventional fuel tax credits increased $0.8 million to $19.8 million for the 2011 period from $19.0 million in the same period of 2010 driven by increased production from the Granite City and Haverhill cokemaking facilities. Results of Reportable Business Segments We report our business results through four segments: • • • • Jewell Coke consists of our cokemaking operations located in Vansant, Virginia; Other Domestic Coke consists of our Indiana Harbor, Haverhill and Granite City cokemaking and heat recovery operations located in East Chicago, Indiana, Franklin Furnace, Ohio and Granite City, Illinois, respectively. Beginning in the fourth quarter of 2011, our Other Domestic Coke segment included our Middletown, Ohio facility; International Coke consists of our operations in Vitória, Brazil, where we operate a cokemaking facility for a Brazilian subsidiary of ArcelorMittal; and Coal Mining consists of our metallurgical coal mining activities conducted in Virginia and West Virginia. In addition, we have included the results of the HKCC Companies that we acquired in January 2011 in this segment from the date of acquisition. Our coke sales agreements in our Jewell Coke and Other Domestic Coke segments contain highly similar contract provisions. Specifically, each agreement includes: • • Take-or-Pay Provisions. Substantially all of our current coke sales are under take-or-pay contracts that require us to produce the contracted volumes of coke and require the customer to purchase such volumes of coke up to a specified tonnage maximum or pay the contract price for any tonnage they elect not to take. As a result, our ability to produce the contracted coke volume and performance by our customers are key determinants of our profitability. We do not have any significant spot coke sales; accordingly, spot prices for coke do not generally affect our revenues. Coal Cost Component with Pass-Through Provisions. The largest cost component of our coke is the cost of purchased coal, including any transportation or handling costs. Under the contracts at our cokemaking facilities in the Other Domestic Coke segment, coal costs are a pass-through component of the coke price, provided that we realize certain targeted coal-to-coke yields. When targeted coal-to- coke yields are achieved, the price of coal is not a significant determining factor in the profitability of these facilities, although it does affect our revenue and cost of sales for these facilities in approximately equal amounts. However, to the extent that the actual coal-to-coke yields are less than the contractual standard, we are responsible for the cost of the excess coal used in the cokemaking process. Conversely, to the extent our actual coal-to-coke yields are higher than the contractual standard, we realize gains. As coal prices decline, the benefits associated with favorable coal-to-coke yields also decline. Under the Jewell coke sales agreement, prior to January 1, 2011, the component of the coke price attributable to coal was equal to the delivered cost of coal applicable to our sales to ArcelorMittal from our Haverhill facility increased by the application of a fixed adjustment factor. As a result of this pricing formula, as coal prices increased, the profitability of our Jewell facility increased, and as coal prices decreased, the profitability of our Jewell cokemaking facility decreased. The coal supply for our Haverhill cokemaking facility has generally been purchased under contracts with terms of one- to two- 53 years. Accordingly, these coal costs were most impacted by market prices at the time these agreements were entered into and were generally not responsive to changes in coal prices during the year. The impact of coal prices on Jewell Coke profitability has therefore lagged the market for spot coal prices. Beginning January 1, 2011, as a result of the settlement agreement with ArcelorMittal discussed above, the coal component of the price of coke under the Jewell coke sales agreement was amended. The coal component of the Jewell coke price will now be fixed annually for each calendar year based on the weighted-average contract price of third-party coal purchases at our Haverhill facility applicable to ArcelorMittal coke sales. To the extent that contracts for third-party coal purchases at our Haverhill facility convert to pricing mechanisms of less than a year, the Jewell coke price will be adjusted accordingly during that year. The fixed adjustment factor has been eliminated, and as a result, coal prices will no longer significantly affect the financial results of the Jewell Coke segment. Beginning in the first quarter of 2012, the intersegment coal price charged to the Jewell Coke segment is reflective of the contract price Jewell Coke charges its customers. Prior year periods have been adjusted to reflect this change. Operating Cost Component with Pass-Through or Inflation Adjustment Provisions. Our coke prices include an operating cost component. Operating costs under three of our coke sales agreements are passed through to the respective customers subject to an annually negotiated budget in some cases subject to a cap annually adjusted for inflation, and we share any difference in costs from the budgeted amounts with our customers. Under our other two coke sales agreements, the operating cost component for our coke sales are fixed subject to an annual adjustment based on an inflation index. Accordingly, actual operating costs can have a significant impact on the profitability of all our domestic cokemaking facilities. At Middletown, our actual coal-to-coke yields were lower than the contractual standard in 2011 due to the start-up of operations, which lowered operating income by $1.0 million. Coal-to-coke yields at Middletown were near break-even in 2012 due to improved performance in the second half of the year. Fixed Fee Component. Our coke prices also include a per ton fixed fee component for each ton of coke sold to the customer and is determined at the time the coke sales agreement is signed and is effective for the term of each sales agreement. Tax Component. Our coke sales agreements also contain provisions that generally permit the pass- through of all applicable taxes (other than income taxes) related to the production of coke at our facilities. Coke Transportation Cost Component. Where we deliver coke to our customers via rail, our coke sales agreements also contain provisions that permit the pass-through of all applicable transportation costs related to the transportation of coke to our customers. • • • • Our domestic coke facilities have also realized, and some continue to realize, certain federal income tax credits. Specifically, energy policy legislation enacted in August 2005 created nonconventional fuel tax credits for U.S. federal income tax purposes pertaining to a portion of the coke production at our Jewell cokemaking facility, all of the production at our Haverhill and Granite City cokemaking facilities and all future domestic cokemaking facilities placed into service by January 1, 2010. The credits cover a four-year period, effective the later of January 1, 2006 or the date any new facility is placed into service prior to January 1, 2010. The credits attributable to production from the second phase of our Haverhill expired in June of 2012 and those attributable to production at our Granite City facility will expire in September of 2013. In 2012, 2011 and 2010, the value of these credits was approximately $15.35, $15.02 and $14.67 per ton of coke produced at facilities eligible to receive credits, respectively. We have shared a portion of the tax credits with AK Steel for sales from the second phase of our Haverhill facility and continue to share a portion of the tax credits with U.S. Steel for sales from our Granite City facility, through discounts to the sales price of coke. We received federal income tax credits for coke production from the second phase of our Haverhill facility through June 30, 2012 and are currently receiving federal income tax credits for coke production from our Granite City cokemaking facility. To the extent Sunoco ultimately utilizes federal income tax credits for coke 54 production for which it qualified prior to the Distribution, we expect to share a portion of the value of such credits with our customers, but we will not receive the benefits of such credits on our consolidated federal income tax return (pursuant to the tax sharing agreement we entered into in connection with our separation from Sunoco). Sales price discounts provided to our customers in connection with sharing of nonconventional fuels tax credits, which are reflected in the operating results of the Other Domestic Coke segment, totaled $11.2 million, $12.9 million and $12.0 million in the 2012, 2011 and 2010 periods, respectively. Following the Distribution, we will share a portion of the tax credits when we utilize the benefits of such credits on our consolidated federal income tax return. As a result of these discounts, our pretax results for these facilities reflect the impact of these sales discounts, while the actual tax benefits are reflected as a reduction of income tax expense. Accordingly, when the tax credits expire, the results of our Other Domestic Coke segment will increase, but this increase will be more than offset by the increase in our income tax expense. Revenues from our International Coke segment are derived from licensing and operating fees based upon the level of production from a Brazilian subsidiary of ArcelorMittal. Our revenues also include the full pass- through of the operating costs of the facility. We also receive an annual preferred dividend on our preferred stock investment in the Brazilian project company that owns the facility. In general, the facility must achieve certain minimum production levels for us to receive the preferred dividend. Recently we have reduced production at our Brazilian cokemaking facility at the request of our customer. These decreases to production do not impact the receipt of our preferred dividend. Revenues from our Coal Mining segment are generated largely from sales of coal to the Jewell cokemaking facility for conversion into coke. Some coal is also sold to our other domestic cokemaking facilities. Coal sales to third parties have historically been limited, but they have increased as a result of the HKCC acquisition and our contract mining arrangement with Revelation. Intersegment coal revenues for sales to the Jewell Coke and Other Domestic Coke segments are based on prices that third parties or coke customers of the Other Domestic Coke segment have agreed to pay for our coal and which approximate the market price for this quality of metallurgical coal. Most of the coal sales to these third parties and facilities are under contracts with one- to two-year terms, and as a result coal revenues lag the market for spot coal prices. Accordingly, the revenues from the Coal Mining segment are most affected by the timing of the execution of coal sales agreements with third parties or the customers of our Other Domestic Coke segment. Coal production costs are the other critical factor in the financial results of the Coal Mining segment. Overhead expenses that can be identified with a segment have been included as deductions in determining operating results of our business segments, and the remaining expenses have been included in Corporate and Other. Management believes Adjusted EBITDA is an important measure of operating performance and is used as the primary basis for the Chief Operating Decision Maker (CODM) to evaluate the performance of each of our reportable segments. Adjusted EBITDA should not be considered a substitute for the reported results prepared in accordance with US GAAP. See “Non-GAAP Financial Measures” at the end of this Item. 55 The following tables set forth the sales and other operating revenues and Adjusted EBITDA of our segments and other financial and operating data for the years ended December 31, 2012, 2011 and 2010: Segment Operating Data Years Ended December 31, 2012 2011 2010 (Dollars in millions) Sales and other operating revenues: Jewell Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jewell Coke intersegment sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Domestic Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coal Mining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coal Mining intersegment sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Elimination of intersegment sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 286.4 — 1,530.4 36.9 48.3 203.4 (203.4) $ 257.6 — 1,187.5 38.0 44.5 183.6 (183.6) $ 298.0 5.8 979.5 38.4 0.6 159.9 (165.7) Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,902.0 $1,527.6 $1,316.5 Adjusted EBITDA(1): Jewell Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Domestic Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coal Mining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corporate and Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 50.5 198.9 11.9 33.4 (29.0) 46.1 87.7 13.7 35.5 (44.2) $ 123.9 85.6 15.0 24.0 (14.1) Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 265.7 $ 138.8 $ 234.4 Coke Operating Data: Capacity Utilization (percent) Jewell Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Domestic Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coke production volumes (thousands of tons): Jewell Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Domestic Coke(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International Coke production—operated facility (thousands of tons) . . . . . . . . . Coke sales volumes (thousands of tons): . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jewell Coke(3) Other Domestic Coke(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 103 102 699 3,643 4,342 1,209 710 3,635 4,345 98 100 100 707 3,055 3,762 1,442 702 3,068 3,770 99 97 97 715 2,879 3,594 1,636 721 2,917 3,638 Domestic Coke Adjusted EBITDA per ton(5) Coal Operating Data(6): Coal sales volumes (thousands of tons): $ 57.40 $ 35.49 $ 57.59 Internal use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,149 351 1,500 1,128 326 1,454 1,275 2 1,277 Coal production (thousands of tons) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchased coal (thousands of tons) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coal sales price per ton (excludes transportation costs)(7) . . . . . . . . . . . . . . . . . . Coal cash production cost per ton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchased coal cost per ton(8) Total coal production cost per ton(9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,476 42 $ 167.23 $ 144.90 $ 93.77 $ 152.75 1,364 117 $ 156.52 $ 132.27 $ 103.11 $ 137.23 1,104 149 $ 125.39 $ 105.92 $ 87.74 $ 108.67 56 (1) See definition of Adjusted EBITDA and reconciliation to GAAP below. (2) Includes Middletown production volumes of 602 thousand tons and 68 thousand tons for 2012 and 2011, respectively. (3) Excludes 17 thousand tons of internal coke sales to our Indiana Harbor cokemaking operations during 2010. (4) Excludes 73 thousand tons of consigned coke sales for 2012. Includes Middletown sales volumes of 597 thousand tons and 68 thousand tons for 2012 and 2011, respectively. (5) Reflects Jewell Coke plus Other Domestic Coke Adjusted EBITDA divided by U.S. coke sales volume. Includes production from Company and contract-operated mines, inclusive of our Revelation contract- (6) mining arrangement. Includes sales to affiliates, including sales to Jewell Coke established via a transfer pricing agreement. The transfer price per ton to Jewell Coke was $179.30, $165.00 and $130.28 for 2012, 2011 and 2010, respectively. (7) (8) Costs of purchased raw coal divided by purchased coal volume. (9) Cost of mining and preparation costs, purchased raw coal costs, and depreciation, depletion and amortization divided by coal sales volume. Depreciation, depletion and amortization per ton were $11.76, $8.89 and $6.04 for 2012, 2011 and 2010, respectively. Analysis of Segment Results Year Ended December 31, 2012 compared to Year Ended December 31, 2011 Jewell Coke Sales and Other Operating Revenue Sales and other operating revenue increased $28.8 million, or 11.2 percent, to $286.4 million in 2012 compared to $257.6 million in 2011. The pass-through of higher coal costs and higher volumes contributed $20.2 million and $2.9 million, respectively, to the increase in segment sales and other operating revenues in 2012. The remaining $5.7 million increase was primarily driven by higher pass-through of transportation costs and increased operating expense recovery. Adjusted EBITDA Beginning in the first quarter of 2012, the intersegment coal price charged to the Jewell Coke segment is reflective of the contract price Jewell Coke charges its customers. Prior year periods have been adjusted to reflect this change. Adjusted EBITDA from our Jewell Coke segment increased $4.4 million, or 9.5 percent, to $50.5 million for 2012 compared to $46.1 million for 2011. More favorable coal-to-coke yields increased Adjusted EBITDA by $3.0 million for 2012. The remaining $1.4 million increase relates primarily to a lower allocation of corporate costs for 2012 as compared to 2011. Depreciation expense, which is not included in segment profitability, increased $0.5 million, from $4.9 million in 2011 to $5.4 million in 2012. Other Domestic Coke Sales and Other Operating Revenue Sales and other operating revenue increased $342.9 million, or 28.9 percent, to $1,530.4 million in 2012 compared to $1,187.5 million in 2011. Our Middletown facility commenced operations in the fourth quarter of 2011 and contributed $260.3 million to the increase in sales for 2012. Excluding Middletown, the increase was mainly attributable to higher pricing driven by the pass-through of higher coal costs, which contributed $47.9 million of the increase. Approximately $18.9 million of the increase was related to higher fees for the reimbursement of operating and transportation costs. Coke sales volumes, excluding Middletown, also increased 57 38 thousand tons, or 1 percent, in 2012 compared to 2011, which contributed $14.2 million of the increase. Capacity utilization in 2012 was 103 percent, an increase from 100 percent in 2011, which favorably impacted volume and sales at each of our facilities. Decreased sales discounts due to the expiration of federal income tax credits at our Haverhill facility in June 2012 increased revenues approximately $1.7 million in 2012. Revenues in 2012 also benefited approximately $4.2 million from the settlement of a billing dispute with ArcelorMittal during the fourth quarter of 2012. These increases were partially offset by a decrease in energy pricing, which lowered sales and other operating revenue by $4.3 million for 2012. Adjusted EBITDA Other Domestic Coke Adjusted EBITDA increased $111.2 million, or over 126.8 percent, to $198.9 million for 2012 compared to $87.7 million in 2011. The contribution of our Middletown facility increased Adjusted EBITDA by $60.2 million for 2012. The Middletown results included approximately $10.0 million of unreimbursed costs, $4.0 million of which is associated with start-up activities in the first quarter of 2012. Excluding Middletown, Adjusted EBITDA increased $51.0 million. Increased coal cost recovery of $35.1 million and increased operating cost recovery of $8.1 million, which was primarily driven by improved performance at our Indiana Harbor and Granite City facilities, contributed primarily to the increase. Increased volumes contributed an additional $4.2 million to the increase in Adjusted EBITDA and the settlement of a billing dispute with ArcelorMittal during the fourth quarter of 2012 also contributed an additional $11.2 million when compared to the prior period. These increases were partially offset by decreases of $7.6 million primarily related to decreased energy sales due primarily to lower pricing and an increase in selling, general and administrative expenses due primarily to an increase in legal costs. Depreciation expense, which is not included in segment profitability, increased $16.6 million, to $55.3 million in 2012, from $38.7 million in 2011, primarily due to the impact of Middletown operations and accelerated depreciation taken on certain assets due to a change in their estimated useful lives. International Coke Sales and Other Operating Revenue Sales and other operating revenue decreased $1.1 million, or 2.9 percent, to $36.9 million in 2012 compared to $38.0 million in 2011 due to a decrease in volumes of 233 thousand tons, or 16.2 percent, partially offset by higher pass-through of operating costs. The decrease in volumes was due to a request from our customer and does not impact our ability to receive our preferred dividend. Adjusted EBITDA Adjusted EBITDA in the International Coke segment decreased $1.8 million, or 13.1 percent, to $11.9 million in 2012 compared to $13.7 million in 2011. The decrease is due primarily to higher legal costs, decreased volumes, an unfavorable comparison to prior year due to an operating expense reimbursement in 2011. This was partially offset by increased operating expense recovery. Depreciation expense, which is not included in segment profitability, was insignificant in both 2012 and 2011. Coal Mining Sales and Other Operating Revenue Total sales and other operating revenue, including intersegment sales, increased by $23.6 million, or 10.3 percent, to $251.7 million in 2012 compared to $228.1 million in 2011. The increase in sales and other operating revenue is due to an increase in coal sales price per ton of $10.71, or 6.8 percent, to $167.23 in 2012, from $156.52 in 2011. Additionally, volume increased 46 thousand tons, or 3.2 percent, for 2012. 58 Third party sales in 2012 increased $3.8 million, or 8.5 percent, to $48.3 million in 2012 from $44.5 million in 2011 due primarily to an increase in volume of 25 thousand tons, or 7.7 percent. Pricing for third party sales was essentially flat in 2012 as compared to 2011. Sales and other operating revenue is historically generated largely from sales of coal to the Jewell cokemaking facility and our other domestic cokemaking facilities. Beginning in the first quarter of 2012, intersegment coal revenues for sales to Jewell Coke are reflective of the contract price Jewell Coke charges its customer. Prior year periods have been adjusted to reflect this change. Intersegment sales increased $19.8 million, or 10.8 percent, to $203.4 million in 2012 compared to $183.6 million in 2011 due mainly to an increase in price to $176.98 per ton in 2012 from $162.69 per ton in 2011. Internal sales volumes increased 21 thousand tons, or 1.9 percent, in 2012 as compared to 2011, contributing marginally to the increase. Adjusted EBITDA Adjusted EBITDA decreased $2.1 million, or 5.9 percent, to $33.4 million in 2012 from $35.5 million in 2011. The decrease in Adjusted EBITDA was driven primarily by higher average coal cash production costs per ton caused by increased reject rates early in the year, increased labor costs due to higher wage rates and the implementation of a new bonus program and higher royalty and trucking payments. The remainder of the decrease was primarily related to lower sales of hi-volatile and thermal coal, despite increased overall volumes and selling prices. Coal cash production costs per ton increased over the prior year due to a change in the mix of coal produced, with hi-volatile and thermal coals representing a smaller portion of production in the current year. Because mid-volatile coal is generally more costly to mine as compared to hi-volatile and thermal coal production, our shift toward mid-volatile production in response to weaker hi-volatile and thermal market conditions increased the average cash production cost per ton in the current year. These decreases to Adjusted EBITDA were partially offset by an increase in the favorable fair value adjustment related to our HKCC contingent consideration arrangement of $2.3 million, from $1.9 million in 2011 to $4.2 million in 2012. The combined impact of these factors resulted in coal production costs increasing to $152.75 per ton in 2012 from $137.23 per ton in 2011 and coal cash production costs increasing to $144.90 per ton in 2012 from $132.27 per ton in 2011. Depreciation expense, which is not included in segment profitability, increased $4.7 million, from $12.9 million in 2011 to $17.6 million in 2012 due primarily to capital expenditures for mining equipment in the prior year. Corporate and Other Corporate expenses decreased $15.2 million, or 34.4 percent, to $29.0 million in 2012 compared to $44.2 million in 2011. The decrease in corporate expenses was driven by lower relocation costs of $7.4 million, increased allocations of corporate costs of $7.2 million, decreased consulting and outside service cost of $7.2 million and favorable comparison to the prior year period which included approximately $3.6 million of start-up costs related to our Middletown operations. These decreases were partially offset by increased costs of $10.2 million primarily related to share-based compensation expense and increased incentive compensation expense in 2012. Depreciation expense, which is not included in segment profitability, increased $0.5 million, from $1.7 million in 2011 to $2.2 million in 2012. The increase in depreciation is primarily due to increased capital expenditures in the current period, partially offset by accelerated depreciation and asset write-offs resulting from our corporate headquarters relocation in the prior year. 59 Year Ended December 31, 2011 compared to Year Ended December 31, 2010 Jewell Coke Sales and Other Operating Revenue Sales and other operating revenue decreased $40.4 million, or 13.5 percent, to $257.6 million in 2011 compared to $298.0 million in 2010. Comparability between periods was impacted by the ArcelorMittal contract amendments. As a result of the amendments, the absence of the fixed adjustment factor decreased sales revenue by $96.8 million while higher operating cost and fixed fee components from the amendments increased sales revenues by $28.0 million over the prior year period. The combination of these factors resulted in a net decrease of $68.8 million over the prior year period. Sales revenue further decreased $10.3 million due to decreased external sales in 2011 compared to the prior year period. These factors were partially offset by higher average coal and transportation costs and an increase in tons sold to ArcelorMittal, which increased sales revenue by $32.6 million, $3.4 million and 2.8 million, respectively. Adjusted EBITDA Adjusted EBITDA from our Jewell Coke segment decreased $77.8 million, or 62.8 percent, to $46.1 million in 2011 compared to $123.9 million in 2010. Comparability between periods is impacted by the ArcelorMittal contract amendments, which decreased segment earnings by $68.8 million. Beginning in the first quarter of 2012, the intersegment coal price charged to the Jewell Coke segment is reflective of the contract price Jewell Coke charges its customers. Prior year periods have been adjusted to reflect this change. Internal coal transfer pricing increased from $130.28 per ton in 2010 to $165.00 per ton in 2011, subsequent to the transfer price adjustment referenced above, and negatively impacted Jewell Coke segment earnings by $36.1 million, with a corresponding increase in the earnings of the Coal Mining segment. Other items, including the absence of attractively priced spot coke sales that occurred in the prior year, the consolidated elimination of intersegment coke sales in the prior period and higher operating expenses in the current period further reduced segment earnings by an aggregate of $11.6 million. Excluding the impact of these spot coke sales and intersegment coke sales, the impact of volume changes on Adjusted EBITDA was flat. The impact to earnings due to these higher coal costs and other items was partially offset by $38.7 million of higher revenues, primarily due to the pass-through of higher coal prices. Depreciation expense, which is not included in segment profitability, increased $0.5 million, from $4.4 million in 2010 to $4.9 million in 2011. Other Domestic Coke Sales and Other Operating Revenue Sales and other operating revenue increased $208.0 million, or 21.2 percent, to $1,187.5 million in 2011 compared to $979.5 million in 2010. The start-up of Middletown operations in the fourth quarter of 2011 contributed $28.6 million to the increase in sales. Excluding Middletown, the increase was mainly attributable to higher pricing driven by the pass-through of higher coal costs, which contributed $115.9 million of the increase. Higher fixed fee revenue and fees for the reimbursement of operating costs contributed $34.9 million to sales revenue. Coke sales volumes also increased 83 thousand tons, or 3 percent, in 2011 compared to 2010, which contributed $27.8 million of the increase. Capacity utilization in 2011 was 100 percent and increased from 97 percent in 2010. Increased capacity utilization at Indiana Harbor and Granite City favorably impacted volume and sales, including energy sales. Sales decreased by $7.0 million in 2011 due to a resolution of certain contract and billing issues with our customer at Indiana Harbor. 60 Adjusted EBITDA Other Domestic Coke Adjusted EBITDA increased $2.1 million, or 2.5 percent, to $87.7 million for 2011 compared to $85.6 million in 2010. The start-up of Middletown operations in the fourth quarter of 2011 decreased Adjusted EBITDA by $0.4 million. Excluding Middletown, increases in Adjusted EBITDA attributable to contract changes and steam sales were partially offset by decreased recovery of coal and operating costs primarily due to Indiana Harbor results in the first quarter of 2011. Sales discounts also increased $0.9 million, which are excluded from Adjusted EBITDA. Haverhill contract changes increased operating cost reimbursement and fixed fee revenue by $17.5 million in 2011. Higher steam and power sales increased segment earnings by $6.8 million. These increases were partially offset by lower results at Indiana Harbor. During the first three months of 2011, we estimated that Indiana Harbor would fall short of its 2011 annual minimum coke production requirements by approximately 122 thousand tons. We entered into contracts to procure the coke from third parties to meet the projected volume shortfall. However, the coke prices in the purchase agreements exceeded the sales price in our contract with ArcelorMittal. This pricing difference resulted in an estimated loss on firm purchase commitments of $18.5 million ($12.2 million attributable to net parent investment and $6.3 million attributable to noncontrolling interest), all of which was recorded during the first three months of 2011. During the balance of the year, we recorded lower of cost or market adjustments totaling $1.9 million ($1.4 million attributable to SunCoke Energy stockholders’ equity and $0.5 million attributable to noncontrolling interests) on the purchased coke. Operational improvements at Indiana Harbor resulting from maintenance and repairs at this facility increased volume during the second, third and fourth quarters such that coke production at Indiana Harbor was sufficient to meet contractual requirements with ArcelorMittal. Additionally, higher maintenance and repair costs to address oven reliability issues of approximately $6.4 million, which was not recoverable from our customer, lowered recovery of operating costs in 2011. Finally, the resolution of certain contract and billing issues with our customer at Indiana Harbor decreased Adjusted EBITDA by $7.0 million in 2011. Selling, general and administrative expenses decreased by approximately $9.1 million, which was driven primarily by settlement and legal cost incurred at Indiana Harbor in 2010, which was slightly offset by a change in the corporate allocation methodology for Granite City. Depreciation expense, which is not included in segment profitability, increased $3.7 million, from $35.0 million in 2010 to $38.7 million in 2011. International Coke Sales and Other Operating Revenue Sales and other operating revenue decreased $0.4 million, or 1 percent, to $38.0 million in 2011 compared to $38.4 million in 2010. Sales and other operating revenue decreased due to lower operating and license fees driven by a 12 percent decrease in coke production, partially offset by a higher pass-through of operating costs. Adjusted EBITDA Adjusted EBITDA in the International Coke segment decreased $1.3 million, or 9 percent, to $13.7 million in 2011 compared to $15.0 million in 2010. The decrease is due primarily to lower licensing and operating fees and higher selling, general and administrative expenses in 2011 partially offset by the absence of currency transaction losses recognized in 2010. Depreciation expense, which is not included in segment profitability, was insignificant in both 2011 and 2010. 61 Coal Mining Sales and Other Operating Revenue Total sales and other operating revenue increased by $67.6 million, or 42.1 percent, to $228.1 million in 2011 compared to $160.5 million in 2010 due to an increase in coal sales price per ton of $31.13 from $125.39 in 2010 to $156.52 in 2011 and an increase in volume of 177 thousand tons. Beginning in the first quarter of 2012, the intersegment coal price charged to the Jewell Coke segment is reflective of the contract price Jewell Coke charges its customers. Prior year periods have been adjusted to reflect this change. Sales and other operating revenue is historically generated largely from sales of coal to the Jewell cokemaking facility and our other domestic cokemaking facilities. Intersegment sales increased $23.7 million, or 14.8 percent, to $183.6 million in 2011 compared to $159.9 million in 2010 due mainly to an increase in transfer price from $130.28 per ton in 2010 to $165.00 per ton in 2011. The increase in price was partially offset by an 11.5 percent decrease in internal sales volume as sales to facilities in our Other Domestic Coke segment decreased. Third party sales in 2011 increased $43.9 million from $0.6 million in 2010 to $44.5 million in 2011. Third party sales during 2010 were insignificant. Existing operations sold 150 thousand external tons in 2011 and contributed $24.7 million to the increase. The acquisition of HKCC contributed 176 thousand tons, or $19.2 million in third party sales, during 2011. Adjusted EBITDA Adjusted EBITDA increased $11.5 million to $35.5 million in 2011 from $24.0 million in 2010. Beginning in the first quarter of 2012, the intersegment coal price charged to the Jewell Coke segment is reflective of the contract price Jewell Coke charges its customers. Prior year periods have been adjusted to reflect this change. The increase in Adjusted EBITDA was driven by higher sales offset by higher operating costs of $72.2 million. Our existing mining operations contributed $55.6 million of the increase in operating costs. This increase was driven by increasing reject rates due to variations in the thickness and quality of coal seams, lower productivity due to labor shortages for experienced miners and regulatory compliance requirements, incremental costs associated with training, higher wage rates and implementation of a new bonus program to retain skilled mine employees, and higher royalty payments. HKCC further contributed $16.7 million in operating costs, which also included a $1.9 million favorable fair value adjustment related to the HKCC contingent consideration arrangement that requires the Company to pay the former owners of HKCC $2.00 per ton of coal for each ton produced from the real property or leased property acquired by HKCC if production levels exceed 150 thousand tons in a calendar year for a period of 20 years or until full exhaustion, whichever comes sooner. This fair value adjustment decreased coal production costs by $1.32 per ton. Lower volumes of purchased coal improved Adjusted EBITDA by $1.0 million. Increased selling, general and administrative expenses of $1.0 million related to the acquisition of HKCC and capital expenditures further decreased Adjusted EBITDA for 2011 compared to 2010. Finally, coal cash production costs absorbed in inventory increased $5.8 million for 2011 compared to 2010. The combined impact of these factors resulted in coal production costs increasing from $108.67 per ton in 2010 to $137.23 per ton in 2011 and coal cash production costs increasing from $105.92 per ton in 2010 to $132.27 per ton in 2011. Depreciation expense, which is not included in segment profitability, increased $5.2 million, from $7.7 million in 2010 to $12.9 million in 2011 due primarily to the acquisition of HKCC. 62 Corporate and Other Corporate expenses increased $30.1 million to $44.2 million in 2011 compared to $14.1 million in 2010. The increase in corporate expenses was driven by $14.9 million in additional headcount and fees required to operate as a public company, $3.6 million in additional headcount and costs related to the planned start-up of the Middletown operations, $7.2 million in headquarters relocation costs and $2.6 million in costs related to Black Lung obligations. Depreciation expense, which is not included in segment profitability, increased $0.7 million, from $1.0 million in 2010 to $1.7 million in 2011 due primarily to accelerated depreciation and asset write-offs as a result of our corporate headquarters relocation. Liquidity and Capital Resources Prior to the Separation Date, our primary source of liquidity was cash from operations and borrowings from Sunoco. Our funding from Sunoco had been through floating-rate borrowings from Sunoco, Inc. (R&M), a wholly- owned subsidiary of Sunoco. The agreements between Sunoco and the Company related to these borrowings terminated concurrent with the IPO and all outstanding advances were settled pursuant to the Separation and Distribution Agreement described in Note 3 to the Combined and Consolidated Financial Statements. Concurrently with the IPO, SunCoke Energy also entered into the Credit Agreement dated as of July 26, 2011 that provides for a seven-year term loan in a principal amount of $300 million (the “Term Loan”), repayable in equal quarterly installments at a rate of 1.00 percent of the original principal amount per year, with the balance payable on the final maturity date. Additionally, the Credit Agreement provides for up to $75.0 million in uncommitted incremental facilities (the “Incremental Facilities”) that are available subject to the satisfaction of certain conditions. On December 15, 2011, we borrowed an additional $30.0 million Term Loan as part of the Incremental Facilities. As of December 31, 2012, there was $45.0 million of capacity under the Incremental Facilities. We have $325.1 million outstanding under the Term Loan as of December 31, 2012. The Credit Agreement also provided for a five-year $150 million revolving facility (the “Revolving Facility”). The proceeds of any loans made under the Revolving Facility could be used to finance capital expenditures, acquisitions, working capital needs and for other general corporate purposes. In the fourth quarter of 2011, we utilized the Revolving Facility to fund the completion and start-up of our Middletown facility. We did not have any outstanding borrowings under the Revolving Facility as of December 31, 2012. Concurrently with the IPO, SunCoke Energy issued $400 million aggregate principal amount of senior notes (the “Notes”) that bear interest at a rate of 7.625 percent per annum and will mature in 2019 with all principal paid at maturity. During the year ended December 31, 2011, net proceeds from the issuance of the Notes and Term Loan were $708.8 million, which reflected a discount reduction of $2.1 million and debt issuance costs and fees of $19.1 million. The net proceeds were used to repay certain intercompany indebtedness to Sunoco of $575.0 million and for general corporate purposes. Following the Separation Date, our primary sources of liquidity are cash on hand, cash from operations and borrowings under the debt financing arrangements described above. In connection with the closing of the Partnership offering, we repaid $225.0 million of our Term Loan, and entered into an amendment to our Credit Agreement. The Partnership issued $150.0 million of Senior Notes (“Partnership Notes”) and entered into a $100.0 million revolving credit facility. Management believes our operating cash flows and the Revolving Facilities and the Incremental Facilities should provide sufficient funds to fund our planned operations, including capital expenditures and stock repurchases. 63 The following table sets forth a summary of the net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2012, 2011 and 2010: Years Ended December 31, Net cash provided by operating activities . . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . . . . . . . . . . . . . . Net cash (used in) provided by financing activities . . . . . . . 2010 2012 2011 (Dollars in millions) $ 101.3 (275.7) 261.8 $206.1 (84.1) (10.3) $ 296.6 (213.9) (45.3) Net increase in cash and cash equivalents . . . . . . . . . . . . . . . $111.7 $ 87.4 $ 37.4 Cash Provided by Operating Activities Net cash provided by operating activities increased by $104.8 million to $206.1 million for the year ended December 31, 2012 as compared to 2011. The increase was primarily attributable to the contribution to earnings of our Middletown operations of approximately $29.4 million and decreases in working capital in 2012 versus 2011. The decrease in working capital was primarily due to a $32.8 million decrease in coal inventory held in the Other Domestic Coke segment, as well as a $28.1 million decrease in consigned coke inventory. Coal inventory levels were higher in 2011 due to increased purchases in the third quarter in response to force majeure events experienced by multiple coal suppliers in the first half of 2011. This decrease in inventory was partially offset by decreases in accounts payable due primarily to lower inventory purchases. Net cash provided by operating activities decreased by $195.3 million to $101.3 million for the year ended December 31, 2011. The decrease was primarily attributable to increases in working capital in 2011 largely due to an increase in coal inventory, an increase in coke inventory to meet the projected shortfall at Indiana Harbor and higher receivables, offset partly by higher accounts payable related to inventory purchases. The increase in coal inventory was due in part to the start-up of Middletown operations, which contributed $20.9 million to the increase. The remaining increase was in the Other Domestic Coke segment and was primarily due to an increase in coal inventory volume that resulted from additional purchases made in the third quarter in response to tightness in coal supply due to force majeure events experienced by coal suppliers in the first and second quarters of 2011. Lower net income also contributed to the decrease in cash flow from operations. The year ended December 31, 2010 included a reduction in working capital largely attributable to lower receivables balances from a customer that deferred payment at December 31, 2009. Cash Used in Investing Activities Cash used in investing activities decreased $191.6 million to $84.1 million for the year ended December 31, 2012. The prior year period included capital expenditures of $169.4 million related to the construction of our Middletown facility and $37.6 million net cash used for the acquisition of the HKCC Companies. The current year period includes $4.8 million of environmental remediation capital expenditures as well as $13.7 million of expansion capital expenditures at Indiana Harbor. In addition, a $3.5 million payment to complete the HKCC acquisition was made in 2012. Cash used in investing activities increased $61.8 million to $275.7 million for the year ended December 31, 2011. The increase was due to higher capital expenditures primarily associated with the construction of the Middletown facility and the acquisition of the HKCC Companies. For a more detailed discussion of our capital expenditures, see “Capital Requirements and Expenditures” below. 64 Cash (Used in) Provided by Financing Activities For the year ended December 31, 2012 net cash used in financing activities was $10.3 million compared to net cash provided by financing activities of $261.8 million for the year ended December 31, 2011. The 2011 period included the issuance of the Notes, Term Loan and Incremental Facilities described above offset by repayments to the Sunoco affiliate and the Company’s acquisition of an additional 19 percent ownership interest in the Indiana Harbor Partnership for $34.0 million. During 2012, we repurchased 603,528 shares for $9.4 million and repaid debt of $3.3 million, which were partly offset by proceeds from stock option exercises of $4.7 million. Net cash provided by financing activities of $261.8 million increased by $307.1 million for the year ended December 31, 2011 compared to the corresponding period in 2010. The increase was primarily a result of the issuance of the Notes, Term Loan and Incremental Facilities described above offset by repayments to the Sunoco affiliate and the Company’s acquisition of an additional 19 percent ownership interest in the Partnership that owns the Indiana Harbor cokemaking facility for $34.0 million. Capital Requirements, Expenditures and Investments Capital Requirements and Expenditures Our cokemaking and coal mining operations are capital intensive, requiring significant investment to upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted, and are expected to consist, primarily of: • • • ongoing capital expenditures required to maintain equipment reliability, the integrity and safety of our coke ovens, steam generators and coal mines and to comply with environmental regulations; environmental remediation capital expenditures required to implement design changes to ensure that our existing facilities operate in accordance with existing environmental permits; and expansion capital expenditures to acquire and/or construct complementary assets to grow our business and to expand existing facilities, such as projects that increase coal production from existing mines and increase coke production from existing facilities, as well as capital expenditures made to enable the renewal of a coke sales agreement and on which we expect to earn a reasonable return. The following table summarizes ongoing, environmental remediation and expansion capital expenditures: Years Ended December 31, 2012 2011 2010 Ongoing capital Environmental remediation capital Expansion capital(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Indiana Harbor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Middletown . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coal Mining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Dollars in millions) $ 57.3 — $ 45.9 — $61.2 4.8 13.7 — 0.9 0.9 — 169.4 11.4 180.8 — 169.7 — 169.7 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $80.6 $238.1 $215.6 (1) Excludes the acquisition of the HKCC Companies. Our capital expenditures for 2013 are expected to be approximately $133 million, of which ongoing capital expenditures are anticipated to be approximately $58 million. Ongoing capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and/or to extend their useful lives. Ongoing capital expenditures also include new 65 equipment that improves the efficiency, reliability or effectiveness of existing assets. Ongoing capital expenditures do not include normal repairs and maintenance expenses, which are expensed as incurred. In 2013, we anticipate spending $60 million for the refurbishment of the Indiana Harbor facility and $15 million in environmental remediation capital to enhance the environmental performance at our Haverhill and Granite City cokemaking operations. Our business is capital intensive, requiring capital to fund the construction or acquisition of assets and to maintain such assets. The level of future capital expenditures will depend on various factors, including market conditions and customer requirements, and may differ from current or anticipated levels. Material changes in capital expenditures levels may impact financial results, including but not limited to the amount of depreciation, interest expense and repair and maintenance expense. Investments In December 2012, we announced our plan to form a cokemaking joint venture with VISA Steel Limited in India. The joint venture will be named VISA SunCoke Limited and will be comprised of VISA Steel’s heat recovery coke plant, which produces 400 thousand metric tons of coke per year, and the plant’s associated steam generation units. We will acquire a 49 percent interest in the joint venture, while VISA Steel will hold the remaining 51 percent. We expect this transaction to close in early 2013 and expect to invest approximately $67 million in this joint venture. Contractual Obligations The following table summarizes our significant contractual obligations as of December 31, 2012: Payment Due Dates Total 2013 2014-2015 2016-2017 Thereafter (Dollars in millions) Total Debt: Principal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating leases(1) Purchase obligations: $ 725.1 278.4 17.3 $ 3.3 44.5 3.6 $ Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Transportation and coal handling(2) . . . . . . . . . . . . . . . Obligations supporting financing arrangements(3) . . . . Other(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 656.2 363.0 3.5 20.0 656.2 47.4 3.5 3.4 6.6 88.6 6.8 — 48.6 — 3.6 $ 6.6 87.2 3.2 — 51.4 — 3.1 $708.6 58.1 3.7 — 215.6 — 9.9 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,063.5 $761.9 $154.2 $151.5 $995.9 (1) Our operating leases include leases for office space, land, locomotives, office equipment and other property and equipment. Operating leases include all operating leases that have initial noncancelable terms in excess of one year. (2) Transportation and coal handling services consist primarily of railroad and terminal services attributable to delivery and handling of coal purchases and coke sales. Long-term commitments generally relate to locations for which limited transportation options exist and match the length of the related coke sales agreement. (3) Represents fixed and determinable obligations to secure coal handling services at the Indiana Harbor cokemaking facility. (4) Primarily represents open purchase orders for materials and supplies. A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Our principal purchase obligations in the 66 ordinary course of business consist of coal and transportation and distribution services, including railroad services. We also have contractual obligations supporting financing arrangements of third parties, contracts to acquire or construct properties, plants and equipment, and other contractual obligations, primarily related to services and materials. Most of our coal purchase obligations are based on fixed prices. These purchase obligations generally include fixed or minimum volume requirements. Transportation and distribution obligations also typically include required minimum volume commitments. The purchase obligation amounts in the table above are based on the minimum quantities or services to be purchased at estimated prices to be paid based on current market conditions. Accordingly, the actual amounts may vary significantly from the estimates included in the table. Off-Balance Sheet Arrangements Other than the arrangements described in Note 17 to the Combined and Consolidated Financial Statements, the Company has not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities. Impact of Inflation Although the impact of inflation has slowed in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace properties, plants, and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and existing agreements, we have generally passed along increased costs to our customers in the form of higher fees and we expect to continue this practice. Critical Accounting Policies A summary of our significant accounting policies is included in Note 2 to the Combined and Consolidated Financial Statements. Our management believes that the application of these policies on a consistent basis enables us to provide the users of the financial statements with useful and reliable information about our operating results and financial condition. The preparation of our Combined and Consolidated Financial Statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Significant items that are subject to such estimates and assumptions consist of: (1) properties, plants and equipment; (2) retirement benefit liabilities; (3) black lung benefit obligations; and (4) deferred income taxes. Although our management bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, actual results may differ to some extent from the estimates on which our Combined and Consolidated Financial Statements have been prepared at any point in time. Despite these inherent limitations, our management believes the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Combined and Consolidated Financial Statements provide a meaningful and fair perspective of our financial condition. Properties, Plants and Equipment The cost of plants and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives of assets which are depreciated on a straight-line basis are based on historical experience and are adjusted when changes in the expected physical life of the asset, its planned use, technological advances, or other factors show that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The lease and mineral rights are capitalized and amortized to operations as depletion expense using the units-of-production method. Normal repairs and maintenance costs are expensed as incurred. Amounts incurred that extend an asset’s useful life, increase its productivity or add production capacity are capitalized. Direct costs, such as outside labor, materials, internal payroll and benefit costs, incurred during the construction of a new facility are capitalized; indirect costs are not capitalized. Repairs and maintenance costs were $100.1 million, $93.7 million and $65.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. 67 Long-lived assets, other than those held for sale, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Such events and circumstances include, among other factors: operating losses; unused capacity; market value declines; changes in the expected physical life of an asset; technological developments resulting in obsolescence; changes in demand for our products or in end-use goods manufactured by others utilizing our products as raw materials; changes in our business plans or those of our major customers, suppliers or other business partners; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of capital, operating or environmental remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are described under “Cautionary Statement Concerning Forward-Looking Statements.” A long-lived asset that is not held for sale is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. Such estimated future cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions. The impairment recognized is the amount by which the carrying amount exceeds the fair market value of the impaired asset. It is also difficult to precisely estimate fair market value because quoted market prices for our long-lived assets may not be readily available. Therefore, fair market value is generally based on the present values of estimated future cash flows using discount rates commensurate with the risks associated with the assets being reviewed for impairment. We have had no significant asset impairments during the years ended December 31, 2012, 2011 and 2010. Retirement Benefit Liabilities Pension Benefit Liabilities. We have obligations totaling $37.5 million in connection with a funded noncontributory defined benefit pension plan. During 2012 we contributed $4.6 million to this plan. Effective January 1, 2011, benefits under this plan were frozen for all eligible participants. In addition, we have obligations totaling $43.7 million in connection with postretirement welfare benefit plans that provide health care benefits for substantially all of our current retirees. Medical benefits under these plans were also phased out or eliminated for most non-mining employees with less than 10 years of service on January 1, 2011. Our future contributions for these plans will also be subject to an annual cap for all those who are still eligible for these benefits. The postretirement welfare benefit plans are unfunded and have historically been paid by us subject to deductibles and coinsurance that have been the responsibility of retirees. The principal assumptions that impact the determination of both expense and benefit obligations for our pension plan is the discount rate and the long-term expected rate of return on plan assets. The discount rate and the health care cost trend rate are the principal assumptions that impact the determination of expense and benefit obligations for our postretirement health care benefit plans. However, the impact of the health care trend rate has been greatly mitigated by the cap on our contributions. We determine the discount rates for our pension and other postretirement welfare benefit obligations on the measurement date by reference to annualized rates earned on high quality fixed income investments and yield-to- maturity analysis specific to each plans’ estimated future benefit payments. The present values of our future pension and other postretirement welfare obligations were determined using discount rates of 3.65 and 3.30 percent, respectively, at December 31, 2012 and 4.25 and 3.90 percent, respectively, at December 31, 2011. Our expense under these plans is generally determined using the discount rate as of the beginning of the year, or using a weighted-average rate when curtailments, settlements and/or other events require a plan remeasurement. The weighted-average discount rate for the pension plan was 4.25, 5.00 and 5.60 percent for 2012, 2011 and 2010, respectively. The weighted-average discount rate for postretirement welfare plans was 3.90, 4.60 and 5.30 percent for 2012, 2011 and 2010, respectively. The long-term expected rate of return on plan assets was assumed to be 6.25 percent for 2012 and 8.25 percent for each of 2011 and 2010. During the second quarter of 2012, the pension plan’s investment strategy and target asset allocation for non-cash investments were modified to implement an allocation of 66 68 percent to equity securities and 34 percent to investment grade fixed income securities. The objective of this strategy is to maximize the long-term return on plan assets at a prudent level of risk in order to ensure adequate funding for the Company’s pension benefit obligations. Prior to this change, the plan’s investment strategy for 2012 reflected a 100 percent allocation to investment grade fixed income securities with a weighted average duration approximately equal to the plan’s benefit obligation. Following this change in asset allocation, the plan’s expected return on assets increased from 4.25 percent to 6.25 percent and resulted in a reduction of defined benefit plan expense of $0.6 million for fiscal 2012. A long-term expected rate of return of 7.25 percent on plan assets is anticipated to be used to determine our pension expense for 2013. The expected rate of return on plan assets is estimated utilizing a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. The long-term expected rate of return for 2013 reflects the 20 year compound average of simulated expected returns of the portfolio described above based on market conditions as of the beginning of 2013 and reflects blended reversion to long-term normative assumptions. In determining pension expense, we apply the expected rate of return to the fair market value of plan assets at the beginning of the year. The expected rate of return on plan assets is designed to be a long-term assumption. It generally will differ from the actual annual return, which is subject to considerable year-to-year variability. In 2011 and 2010, our pension plan assets were invested in a trust with the assets of other pension plans of Sunoco. Per the Separation and Distribution Agreement, these assets were separated from the Sunoco trust in January 2012 and were transferred to a newly formed trust established for our pension plan. For 2012, the pension plan assets generated a positive return of 6.8 percent compared to a return of 6.7 percent for 2011 and a return of 16.0 percent in 2010. For the 15-year period ended December 31, 2012, the compounded annual investment return on our pension plan assets was a positive return of 6.4 percent. While the 15-year period return is below our long-term expected rate of return for fiscal 2013, we believe that this is largely a result of the negative return during 2008, which was one of the worst asset return periods in history as a result of the financial crisis in the second half of that year. As permitted by existing accounting rules, we do not currently recognize in pension expense the difference between the expected and actual return on assets. Rather, the difference along with other actuarial gains or losses resulting from changes in actuarial assumptions used in accounting for the plans (primarily the discount rate) and differences between actuarial assumptions and actual experience are fully recognized in the Consolidated Balance Sheets. If such actuarial gains and losses on a cumulative basis exceed 10 percent of the projected benefit obligation (or the fair market value of plan assets, if larger), the excess is amortized into net income as a component of pension or postretirement welfare benefits expense generally over the average remaining service period of plan participants still employed with us, which currently is approximately 13 years for the pension plans and approximately 9 years for the postretirement welfare benefit plans. At December 31, 2012, the accumulated net actuarial loss (gain) for defined benefit and postretirement welfare benefit plans was $16.7 million and $16.5 million, respectively. Other Post-Employment Benefit Liabilities. We also have unrecognized prior service benefits attributable to our postretirement benefit plans of approximately $22.2 million at December 31, 2012, which is primarily attributable to the phase down or elimination of retiree medical benefits described above. Most of the benefit of this liability reduction will be amortized into income through 2016. The initial health care cost trend assumptions used to compute the accumulated postretirement welfare benefit obligation were increases of 8.50 percent, 9.00 percent and 7.75 percent at December 31, 2012, 2011 and 2010, respectively. These trend rates were assumed to decline gradually to 5.00 percent in 2020 as of December 31, 2012 and December 31, 2011 and to 5.00 percent in 2017 as of December 31, 2010; the trend assumption remains at that level thereafter. 69 Set forth below are the estimated increases in pension and postretirement welfare benefits expense and benefit obligations that would occur in 2013 from a change in the indicated assumptions: Change in Rate Expense(2) Benefit Obligations(1)(2) (Dollars in millions) Pension benefits: Decrease in the discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Decrease in the long-term expected rate of return on plan 0.25% $— assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.25% $ 0.1 Postretirement welfare benefits: Decrease in the discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Increase in the annual health care cost trend rates . . . . . . . . . . . . . 0.25% 1.00% $— $— $ 1.1 $ 0.9 $ 1.0 $— (1) Represents both the increase in accumulated benefit obligation and the projected benefit obligation for our defined benefit pension plan and the accumulated postretirement benefit welfare obligations for our postretirement welfare benefit plans. (2) Certain expense and benefit obligation changes are less than $0.1 million and are not reflected in the table. Black Lung Benefit Liabilities We have obligations related to coal workers’ pneumoconiosis, or black lung, benefits to certain of our employees and former employees (and their dependents). Such benefits are provided for under Title IV of the Federal Coal Mine Health and Safety Act of 1969 and subsequent amendments, as well as for black lung benefits provided in the states of Virginia, Kentucky and West Virginia pursuant to workers’ compensation legislation. The Patient Protection and Affordable Care Act (“PPACA”), which was implemented in 2010, amended previous legislation related to coal workers’ black lung obligations. PPACA provides for the automatic extension of awarded lifetime benefits to surviving spouses and changes the legal criteria used to assess and award claims. We act as a self-insurer for both state and federal black lung benefits and adjust our liability each year based upon actuarial calculations of our expected future payments for these benefits. Charges against income for black lung benefits amounted to $3.3 million, $8.7 million and $4.8 million during the years ended December 31, 2012, 2011 and 2010, respectively. Our independent actuaries annually calculate the actuarial present value of the estimated black lung liability based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and discount rates. The discount rate is determined based on a portfolio of high-quality corporate bonds with maturities that are consistent with the estimated duration of our black lung obligations. For the years ended December 31, 2012, 2011 and 2010, the discount rate used to calculate the period end liability was 3.80, 4.50 and 5.00 percent respectively. A 0.25 percent decrease in the discount rate would have increased 2012 coal workers’ black lung expense by $1.2 million. The estimated liability recognized in our financial statements at December 31, 2012 and 2011 was $34.8 million and $33.5 million, respectively. Changes in actuarial assumptions, including the discount rate and mortality assumptions, increased our black lung obligation by approximately $1.8 million at December 31, 2012. For the year ended December 31, 2012, we paid black lung benefits of approximately $2.1 million. Our obligations with respect to these liabilities are unfunded at December 31, 2012. Deferred Income Taxes Prior to the Distribution Date, SunCoke Energy and certain subsidiaries of Sunoco were included in the consolidated federal and certain consolidated, combined or unitary state income tax returns filed by Sunoco. However, SunCoke Energy’s provision for income taxes and the deferred income tax amounts reflected in the Combined and Consolidated Financial Statements have been determined on a theoretical separate-return basis. 70 Prior to the Separation Date, any current federal and state income tax amounts were settled with Sunoco under a previous tax sharing arrangement. Under this previous tax sharing arrangement, net operating losses and tax credit carryforwards generated on a theoretical separate-return basis could be used to offset future taxable income determined on a similar basis. Such benefits were reflected in the Company’s deferred tax assets, notwithstanding the fact that such net operating losses and tax credits may actually have been realized on Sunoco’s consolidated income tax returns, or may be realized in future Sunoco consolidated income tax returns (for periods through the Distribution Date). Our Consolidated Balance Sheets as of December 31, 2011 included deferred income taxes assets (net of valuation allowances) attributable to tax credits and net operating loss carryforwards, determined on a theoretical separate-return basis, totaling $72.2 million. On the Separation Date, SunCoke Energy and Sunoco entered into a new tax sharing agreement that governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and other matters regarding taxes. Under the tax sharing agreement, certain deferred tax assets attributable to net operating losses and credit carry forwards, which had been reflected in SunCoke Energy’s balance sheets prior to the Separation Date on a standalone theoretical basis, are no longer realizable by SunCoke Energy. Accordingly, after the Separation Date, current and deferred tax benefits totaling $229.2 million were eliminated from the Consolidated Balance Sheets with a corresponding reduction in SunCoke Energy’s equity accounts, $85.8 million and $143.4 million of which were eliminated in the year ended December 31, 2012 and 2011, respectively. As of December 31, 2012, SunCoke Energy estimates that all tax benefits have been settled under the provisions of the tax sharing agreement. SunCoke Energy will continue to monitor the full utilization of all tax attributes when the respective tax returns are filed and will, consistent with the terms of the tax sharing agreement, record additional adjustments when necessary. Any additional adjustments will be recorded through income. We are currently receiving federal income tax credits for coke production from our Granite City cokemaking facility and received credits from the second phase of our Haverhill cokemaking facility through June 30, 2012. These tax credits are earned for each ton of coke produced and sold and expire four years after the initial coke production at the facility. The tax credit eligibility for coke production from the second phase of the Haverhill facility expired in June 2012 and the tax credit eligibility for coke production from the Granite City facility will expire in September 2013. In 2012, 2011 and 2010, the value of the credits was approximately $15.35 per ton, $15.02 per ton and $14.67 per ton of coke produced at facilities eligible to receive credits, respectively. We share with our customers a portion of the value of these credits, when utilized, through sales discounts to their respective coke prices. Sales discounts provided to our customers were $11.2 million, $12.9 million and $12.0 million in 2012, 2011 and 2010, respectively. To the extent Sunoco ultimately utilizes federal income tax credits for coke production for which it qualified prior to the Distribution, we expect to share a portion of the value of such credits with our customers but, pursuant to the tax sharing agreement we entered into in connection with our separation from Sunoco, we will not receive the benefits of such credits on our consolidated federal income tax return. At December 31, 2012, we had $36.2 million accrued related to sales discounts that had not yet been shared with our customers. See Note 8 to our Combined and Consolidated Financial Statements for additional information. Arrangements Between Sunoco and SunCoke Energy, Inc. In connection with the IPO, SunCoke Energy and Sunoco entered into certain agreements that effected the separation of SunCoke Energy’s business from Sunoco, provided a framework for its relationship with Sunoco after the separation and provided for the allocation between SunCoke Energy and Sunoco of Sunoco’s assets, employees, liabilities and obligations attributable to periods prior to, at and after SunCoke Energy’s separation from Sunoco. 71 Separation and Distribution Agreement. On the Separation Date, SunCoke Energy and Sunoco entered into the separation and distribution agreement, which set forth the agreements between SunCoke Energy and Sunoco regarding the principal corporate transactions required to effect SunCoke Energy’s separation from Sunoco, the IPO and the distribution, if any, of SunCoke Energy’s shares to Sunoco’s shareholders, and other agreements governing the relationship between Sunoco and SunCoke Energy. The separation and distribution agreement identified assets to be transferred, liabilities to be assumed and contracts to be assigned to each of SunCoke Energy and Sunoco as part of the separation of Sunoco into two companies. Except as expressly provided, all assets were transferred on an “as is,” “where is” basis. In general, each party to the separation and distribution agreement assumed liability for all pending, threatened and unasserted legal matters related to its own business or its assumed or retained liabilities and will indemnify the other party for any liability to the extent arising out of or resulting from such assumed or retained legal matters. In addition, the separation and distribution agreement provides for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of SunCoke Energy’s business with SunCoke Energy and financial responsibility for the obligations and liabilities of Sunoco’s business with Sunoco. The separation and distribution agreement allocates responsibility with respect to certain employee related matters, particularly with respect to Sunoco employee benefit plans in which any SunCoke Energy employees participate or SunCoke Energy employee benefit plans which hold assets in joint trusts with Sunoco. In addition, the separation and distribution agreement provides for certain adjustments with respect to Sunoco equity compensation awards that occurred when Sunoco completed the distribution. Tax Sharing Agreement. On the Separation Date, SunCoke Energy and Sunoco entered into a tax sharing agreement that governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and other matters regarding taxes. For a detailed discussion of the tax sharing agreement, see Note 8 to our Combined and Consolidated Financial Statements. Transition Services Agreement. On the Separation Date, SunCoke Energy and Sunoco entered into a transition services agreement in connection with the separation. Pursuant to the transition services agreement, Sunoco provides certain support services to SunCoke Energy, including, among others, information technology, treasury, risk management and insurance, tax, internal audit and various other corporate services, in each case consistent with the services provided by Sunoco to SunCoke Energy before the separation. The charges for the transition services generally are intended to allow Sunoco to fully recover the costs directly associated with providing the services, plus all out-of-pocket costs and expenses, generally without profit. The services provided under the transition services agreement will terminate at various times specified in the agreement (generally terminating upon completion of the Distribution on January 17, 2012). As of December 31, 2012, most services provided under this agreement have terminated, with the exception of certain information technology services and other de minimis support. SunCoke Energy may terminate certain or the remaining specified services by giving prior written notice to Sunoco of such services and paying any applicable termination charge. Guaranty, Keep Well, and Indemnification Agreement. On the Separation Date, SunCoke Energy and Sunoco entered into a guaranty, keep well, and indemnification agreement. Under this agreement, SunCoke Energy: (1) guarantees the performance of certain obligations of its subsidiaries, prior to the date that Sunoco or its affiliates may become obligated to pay or perform such obligations, including the repayment of a loan from Indiana Harbor Coke Company L.P.; (2) indemnifies, defends, and holds Sunoco and its affiliates harmless against all liabilities relating to these obligations; and (3) restricts the assets, debts, liabilities and business activities of one of its wholly-owned subsidiaries, so long as certain obligations of such subsidiary remain unpaid or unperformed. In addition, SunCoke Energy releases Sunoco from its guaranty of payment of a promissory note owed by one of its subsidiaries to another of its subsidiaries. 72 Recent Accounting Standards There are no recently issued accounting standards which are not yet effective that we believe would materially impact our financial statements. Non-GAAP Financial Measures In addition to the GAAP results provided in the Annual Report on Form 10-K, we have provided a non- GAAP financial measure, Adjusted EBITDA. Reconciliation from GAAP to the non-GAAP measurement is presented below. Our management, as well as certain investors, uses this non-GAAP measure to analyze our current and expected future financial performance. This measure is not in accordance with, or a substitute for, GAAP and may be different from, or inconsistent with, non-GAAP financial measures used by other companies. Adjusted EBITDA. Adjusted EBITDA represents earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) adjusted for sales discounts and the interest, taxes, depreciation, depletion and amortization attributable to equity earnings in our unconsolidated affiliates. EBITDA reflects sales discounts included as a reduction in sales and other operating revenue. The sales discounts represent the sharing with customers of a portion of nonconventional fuels tax credits, which reduce our income tax expense. However, we believe our Adjusted EBITDA would be inappropriately penalized if these discounts were treated as a reduction of EBITDA since they represent sharing of a tax benefit that is not included in EBITDA. Accordingly, in computing Adjusted EBITDA, we have added back these sales discounts. Our Adjusted EBITDA also includes EBITDA attributable to our unconsolidated affiliates. EBITDA and Adjusted EBITDA do not represent and should not be considered alternatives to net income or operating income under GAAP and may not be comparable to other similarly titled measures in other businesses. Management believes Adjusted EBITDA is an important measure of the operating performance of the Company’s net assets. Adjusted EBITDA does not represent and should not be considered as an alternative to net income as determined by GAAP, and calculations thereof may not be comparable to those reported by other companies. We believe Adjusted EBITDA is an important measure of operating performance and provides useful information to investors because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures and because it eliminates items that have less bearing on our operating performance. Adjusted EBITDA is a measure of operating performance that is not defined by GAAP and should not be considered a substitute for net income as determined in accordance with GAAP. Set forth below is additional detail as to how we use Adjusted EBITDA as a measure of operating performance, as well as a discussion of the limitations of Adjusted EBITDA as an analytical tool. Operating Performance. Our management uses Adjusted EBITDA in a number of ways to assess our combined financial and operating performance, and we believe this measure is helpful to management in identifying trends in our performance. Adjusted EBITDA helps management identify controllable expenses and make decisions designed to help us meet our current financial goals and optimize our financial performance while neutralizing the impact of capital structure on financial results. Accordingly, we believe this metric measures our financial performance based on operational factors that management can impact in the short-term, namely our cost structure and expenses. Limitations. Other companies may calculate Adjusted EBITDA differently then we do, limiting its usefulness as a comparative measure. Adjusted EBITDA also has limitations as an analytical tool and should not be considered in isolation or as a substitute for an analysis of our results as reported under GAAP. Some of these limitations include that Adjusted EBITDA: • • does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments; does not reflect changes in, or cash requirement for, working capital needs; 73 • • • • does not reflect our interest expense, or the cash requirements necessary to service interest on or principal payments of our debt; does not reflect certain other non-cash income and expenses; excludes income taxes that may represent a reduction in available cash; and includes net income (loss) attributable to noncontrolling interests. We explain Adjusted EBITDA and reconcile this non-GAAP financial measure to our net income, which is its most directly comparable financial measure calculated and presented in accordance with GAAP. Below is a reconciliation of Adjusted EBITDA to its closest GAAP measure: Years Ended December 31, 2012 2011 2010 Adjusted EBITDA attributable to SunCoke Energy, Inc . . . . . Subtract: Adjusted EBITDA attributable to noncontrolling (Dollars in millions) $142.8 $230.1 $262.7 interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3.0) 4.0 (4.3) Total Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $265.7 $138.8 $234.4 Subtract: Depreciation, depletion and amortization . . . . . . . . . . . . Financing expense (income), net . . . . . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales discount provided to customers due to sharing of nonconventional fuels tax credits . . . . . . . . . . . . . . . . . 80.8 47.8 23.4 11.2 58.4 1.4 7.2 12.9 48.2 (19.0) 46.9 12.0 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $102.5 $ 58.9 $146.3 Below is a reconciliation of 2013 Estimated Adjusted EBITDA to its closest GAAP measure: Adjusted EBITDA attributable to SunCoke Energy, Inc . . . Subtract: Adjusted EBITDA attributable to noncontrolling interests(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subtract: Depreciation, depletion and amortization . . . . . . . . . . . Financing expense, net . . . . . . . . . . . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales discount provided to customers due to sharing of nonconventional fuels tax credits . . . . . . . . . . . . . . . Adjustments to unconsolidated affiliate earnings(2) . . . . 2013 Low High (Dollars in millions) $190 $165 (40) 205 97 55 3 7 — (40) 230 95 55 10 7 3 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 43 $ 60 (1) Reflects non-controlling interest in Indiana Harbor and the portion of the Partnership owned by public unitholders (2) Reflects estimated pro-rata 2013 income related to planned VISA SunCoke JV 74 CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS We have made forward-looking statements in this Annual Report on Form 10-K, including, among others, in the sections entitled “Business,” “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Such forward-looking statements are based on management’s beliefs and assumptions and on information currently available. Forward-looking statements include the information concerning our possible or assumed future results of operations, business strategies, financing plans, competitive position, potential growth opportunities, potential operating performance improvements, benefits resulting from our separation from Sunoco, the effects of competition and the effects of future legislation or regulations. Forward-looking statements include all statements that are not historical facts and may be identified by the use of forward-looking terminology such as the words “believe,” “expect,” “plan,” “intend,” “anticipate,” “estimate,” “predict,” “potential,” “continue,” “may,” “will,” “should” or the negative of these terms or similar expressions. In particular, statements in this Annual Report on Form 10-K concerning future dividend declarations are subject to approval by our Board of Directors and will be based upon circumstances then existing. Forward-looking statements involve risks, uncertainties and assumptions. Actual results may differ materially from those expressed in these forward-looking statements. You should not put undue reliance on any forward-looking statements. We do not have any intention or obligation to update any forward-looking statement (or its associated cautionary language), whether as a result of new information or future events, after the date of this Annual Report on Form 10-K, except as required by applicable law. The risk factors discussed in “Risk Factors” could cause our results to differ materially from those expressed in forward-looking statements. There may also be other risks that we are unable to predict at this time. Such risks and uncertainties include, without limitation: • • • • • • • • • • • • changes in levels of production, production capacity, pricing and/or margins for metallurgical coal and coke; variation in availability, quality and supply of metallurgical coal used in the cokemaking process, including as a result of non-performance by our suppliers; changes in the marketplace that may affect supply and demand for our metallurgical coal and/or coke products, including increased exports of coke from China related to reduced export duties and export quotas and increasing competition from alternative steelmaking and cokemaking technologies that have the potential to reduce or eliminate the use of metallurgical coke; our dependence on, and relationships with, and other conditions affecting, our customers; severe financial hardship or bankruptcy of one of more of our major customers, or the occurrence of a customer default and other events affecting our ability to collect payments from our customers; our significant equity interest in the Partnership; volatility and cyclical downturns in the carbon steel industry and other industries in which our customers operate; our ability to enter into new, or renew existing, long-term agreements upon favorable terms for the supply of metallurgical coke to domestic and/or foreign steel producers; our ability to successfully implement our international growth strategy; our ability to realize expected benefits from investments and acquisitions, including our investment in the Indian joint venture; the possibility that our investment in the Indian joint venture does not close for any reason; age of, and changes in the reliability, efficiency and capacity of the various equipment and operating facilities used in our coal mining and/or cokemaking operations, and in the operations of our major customers, business partners and/or suppliers; 75 • • • • • • • • • • • • • • • • • • • • • • • • • • • • changes in the expected operating levels of our assets; our ability to meet minimum volume requirements, coal-to-coke yield standards and coke quality requirements in our coke sales agreements; changes in the level of capital expenditures or operating expenses, including any changes in the level of environmental capital, operating or remediation expenditures; our ability to service our outstanding indebtedness; our ability to comply with the restrictions imposed by our financing arrangements; nonperformance or force majeure by, or disputes with or changes in contract terms with, major customers, suppliers, dealers, distributors or other business partners; availability of skilled employees for our coal mining and/or cokemaking operations, and other workplace factors; effects of railroad, barge, truck and other transportation performance and costs, including any transportation disruptions; effects of adverse events relating to the operation of our facilities and to the transportation and storage of hazardous materials (including equipment malfunction, explosions, fires, spills, and the effects of severe weather conditions); our ability to enter into joint ventures and other similar arrangements under favorable terms; changes in the availability and cost of equity and debt financing; impact on our liquidity and ability to raise capital as a result of changes in the credit ratings assigned to our indebtedness; changes in credit terms required by our suppliers; risks related to labor relations and workplace safety; changes in, or new, statutes, regulations, governmental policies and taxes, or their interpretations, including those relating to the environment and global warming; the existence of hazardous substances or other environmental contamination on property owned or used by us; the availability of future permits authorizing the disposition of certain mining waste; claims of our noncompliance with any statutory and regulatory requirements; changes in the status of, or initiation of new litigation, arbitration, or other proceedings to which we are a party or liability resulting from such litigation, arbitration, or other proceedings; historical combined and consolidated financial data may not be reliable indicator of future results; effects resulting from our separation from Sunoco, Inc.; incremental costs as a stand-alone public company; our substantial indebtedness; certain covenants in our debt documents; our ability to secure new coal supply agreements or to renew existing coal supply agreements; our ability to acquire or develop coal reserves in an economically feasible manner; defects in title or the loss of one or more mineral leasehold interests; disruptions in the quantities of coal produced by our contract mine operators; 76 • • • • • • • our ability to obtain and renew mining permits, and the availability and cost of surety bonds needed in our coal mining operations; changes in product specifications for either the coal or coke that we produce; changes in insurance markets impacting costs and the level and types of coverage available, and the financial ability of our insurers to meet their obligations; changes in accounting rules and/or tax laws or their interpretations, including the method of accounting for inventories, leases and/or pensions; changes in financial markets impacting pension expense and funding requirements; the accuracy of our estimates of reclamation and other mine closure obligations; and effects of geologic conditions, weather, natural disasters. The factors identified above are believed to be important factors, but not necessarily all of the important factors, that could cause actual results to differ materially from those expressed in any forward-looking statement made by us. Other factors not discussed herein could also have material adverse effects on us. All forward- looking statements included in this Annual Report on Form 10-K are expressly qualified in their entirety by the foregoing cautionary statements. Item 7A. Quantitative and Qualitative Disclosures About Market Risk Our primary areas of market risk include changes in: (1) the price of coal, which is the key raw material for our cokemaking business and a product of our coal mining business; (2) interest rates; and (3) foreign currency exchange rates. In our Coal Mining segment, we expect to sell approximately 1.7 million tons of coal in 2013 (including transfers to our cokemaking operations). Although we have historically had limited third-party sales from our coal mining operations, we generally sell coal pursuant to contracts with terms similar to the terms of the contracts pursuant to which we buy coal from third parties, including pricing. For 2013, approximately 88 percent of our projected sales are committed at established selling prices. Accordingly, increases and decreases in the market price of metallurgical coal can significantly impact our Coal Mining Segment results. For our Other Domestic Coke segment, the largest component of the price of our coke is coal cost. However, under the coke sales agreements at all of our Other Domestic Coke cokemaking facilities, coal costs are a pass-through component of the coke price, provided that we are able to realize certain targeted coal-to-coke yields. As such, when targeted coal-to-coke yields are achieved, the price of coal is not a significant determining factor in the profitability of these facilities. Beginning January 1, 2011, as a result of a settlement agreement with ArcelorMittal, the coal component of the price of coke under the Jewell coke sales agreement was amended. The coal component of the Jewell coke price will now be fixed annually for each calendar year based on the weighted-average contract price of third- party coal purchases at our Haverhill facility applicable to ArcelorMittal coke sales. To the extent that contracts for third-party coal purchases at our Haverhill facility convert to pricing mechanisms of less than a year, then the Jewell coke price will be adjusted accordingly during that year. The fixed adjustment factor has been eliminated, and as a result, coal prices will no longer significantly affect the financial results of the Jewell Coke segment. The provisions of our coke sales agreements require us to meet minimum production levels and generally require us to secure replacement coke supplies at the prevailing contract price if we do not meet contractual minimum volumes. Because market prices for coke are generally highly correlated to market prices for metallurgical coal, to the extent any of our facilities are unable to produce their contractual minimum volumes we are subject to market risk related to the procurement of replacement supplies. 77 We do not use derivatives to hedge any of our coal purchases or sales. Although we have not previously done so, we may enter into derivative financial instruments from time to time in the future to economically manage our exposure related to these market risks. Prior to January 24, 2013, we were exposed to changes in interest rates as a result of our borrowing activities and our cash balances. Concurrently with the IPO, SunCoke Energy entered into the Credit Agreement which provides for a seven-year term loan in a principal amount of $300.0 million. The Credit Agreement also provides for up to $75.0 million of Incremental Facilities (“Incremental Facilities”) that are available subject to the satisfaction of certain conditions. Borrowings under the Term Loan and Incremental Facilities bear interest, at our option, at either (i) base rate plus an applicable margin or (ii) the greater of 1.00 percent or the London Interbank Offered Rate (“LIBOR”) plus an applicable margin. Borrowings under the Revolving Facility bear interest at either (i) base rate plus an applicable margin or (ii) at LIBOR plus an applicable margin. Additionally, the Company issued $400 million aggregate principal amount of fixed rate senior notes. After the impact of the related interest rate derivative instruments (described in Note 23 to our Combined and Consolidated Financial Statements), approximately 27.6 percent of our debt portfolio represented variable rate obligations. For the Term Loan, our variable rate exposure relates to changes in LIBOR, only when LIBOR is greater than 1.00 percent. During 2011, LIBOR was below the 1.00 percent floor that was established in the Credit Agreement. Therefore, the Company’s interest rate on Term Loan borrowings was fixed and as such the Company was not subject to changes in interest rates for Term Loan borrowings. For the Revolving Facility, the daily average outstanding balance was $0.4 million during the year ended December 31, 2012. Assuming a 50 basis point change in LIBOR, interest expense on the Term Loan and the Revolving Facility would not have changed by a significant amount for the full year 2012. As of December 31, 2012, there were no outstanding borrowings under the Revolving Facility. On January 24, 2013, in connection with the closing of the Partnership offering, we repaid $225.0 million of our Term Loan and entered into an amendment to our Credit Agreement. The amendment to our Credit Agreement, among other things, amended certain provisions to reflect the Partnership offering and extended the term of the Credit Agreement to January 2018. Please see Note 27 entitled “Subsequent Events” to our Combined and Consolidated Financial Statements within this Annual Report on Form 10-K for additional information regarding the amendment to our Credit Agreement. The Company utilizes interest rate swaps to manage the risk associated with changing interest rates and subsequent to the transactions described above is no longer exposed to changes in interest rates on its outstanding borrowings. At December 31, 2012, we had cash and cash equivalents of $239.2 million, which accrues interest at various rates. Assuming a 50 basis point change in the rate of interest associated with our cash and cash equivalents, interest income would not have changed by a significant amount for the year ended 2012. 78 Item 8. Financial Statements and Supplementary Data INDEX TO FINANCIAL STATEMENTS Page Reports of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 Combined and Consolidated Statements of Income for the Years Ended December 31, 2012, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 Combined and Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Balance Sheets at December 31, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Combined and Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Combined and Consolidated Statements of Equity for the Years Ended December 31, 2012, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Combined and Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 84 85 86 88 79 Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders SunCoke Energy, Inc. We have audited the accompanying consolidated balance sheets of SunCoke Energy, Inc. as of December 31, 2012 and 2011, and the related combined and consolidated statements of income, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of SunCoke Energy, Inc. at December 31, 2012 and 2011 and the combined and consolidated results of its operations and its cash flows for each of the three years in the 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), SunCoke Energy, Inc.’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 and our report dated February 22, 2013 expressed an unqualified opinion thereon. /s/ Ernst & Young LLP Chicago, Illinois February 22, 2013 80 Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders SunCoke Energy, Inc. We have audited SunCoke Energy, Inc.’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 (the COSO criteria). SunCoke Energy, Inc.’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. 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, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 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, SunCoke Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of SunCoke Energy, Inc. as of December 31, 2012 and 2011 and the related combined and consolidated statements of income, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2012 and our report dated February 22, 2013 expressed an unqualified opinion thereon. /s/ Ernst & Young LLP Chicago, Illinois February 22, 2013 81 SunCoke Energy, Inc. Combined and Consolidated Statements of Income Years Ended December 31, 2012 2011 2010 (Dollars and shares in millions, except per share amounts) Revenues Sales and other operating revenue . . . . . . . . . . . . . . . . . . . . . . Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Costs and operating expenses Cost of products sold and operating expenses . . . . . . . . . . . . . Loss on firm purchase commitments . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expenses . . . . . . . . . . . . . . Depreciation, depletion, and amortization . . . . . . . . . . . . . . . . Total costs and operating expenses . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest income—affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost—affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total financing (expense) income, net . . . . . . . . . . . . . . . . . . . Income before income tax expense . . . . . . . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Net income (loss) attributable to noncontrolling $1,902.0 12.1 1,914.1 1,577.6 — 82.0 80.8 1,740.4 173.7 — 0.4 — (48.2) — (47.8) 125.9 23.4 102.5 interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7 Net income attributable to SunCoke Energy, Inc. / net $1,527.6 11.3 1,538.9 1,305.8 18.5 88.7 58.4 1,471.4 67.5 12.5 0.4 (3.5) (20.6) 9.8 (1.4) 66.1 7.2 58.9 (1.7) $1,316.5 10.0 1,326.5 1,036.9 — 67.2 48.2 1,152.3 174.2 23.7 — (5.4) — 0.7 19.0 193.2 46.9 146.3 7.1 parent investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 98.8 $ 60.6 $ 139.2 Earnings attributable to SunCoke Energy, Inc. / net parent investment per common share: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ Weighted average number of common shares outstanding: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.41 1.40 70.0 70.3 $ $ 0.87 0.87 70.0 70.0 $ $ 1.99 1.99 70.0 70.0 (See Accompanying Notes) 82 SunCoke Energy, Inc. Combined and Consolidated Statements of Comprehensive Income Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other comprehensive (loss) income: Reclassifications of prior service benefit and actuarial loss amortization to Years Ended December 31, 2012 2011 2010 $102.5 $58.9 $146.3 earnings (net of related tax benefit of $1.2, $1.2 and $1.0, respectively) . . . . . . (1.9) (2.2) (1.7) Retirement benefit plans funded status adjustment (net of related tax (expense) benefit of ($0.8), $4.3, and ($14.8), respectively) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Currency translation adjustment 1.6 (1.1) Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Comprehensive income (loss) attributable to noncontrolling interests . . . . . . . . . 101.1 3.7 (6.3) (1.4) 49.0 (1.7) 24.1 0.4 169.1 7.1 Comprehensive income attributable to SunCoke Energy, Inc. / net parent investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 97.4 $50.7 $162.0 (See Accompanying Notes) 83 SunCoke Energy, Inc. Consolidated Balance Sheets Assets Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investment in Brazilian cokemaking operations . . . . . . . . . . . . . . . . . . . . . . . . . . Properties, plants and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lease and mineral rights, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred charges and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities and Equity Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current portion of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrual for black lung benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Retirement benefit liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity Preferred stock, $0.01 par value. Authorized 50,000,000 shares; no issued and December 31, 2012 2011 (Dollars in millions, except per share amounts) $ 239.2 70.0 160.1 2.6 471.9 41.0 1,396.6 52.5 9.4 39.6 $2,011.0 132.9 3.3 91.2 15.7 3.9 247.0 720.1 34.8 42.5 361.5 13.5 16.7 $ 127.5 66.2 219.7 0.6 414.0 41.0 1,391.8 53.2 9.4 32.4 $1,941.8 181.9 3.3 80.4 15.9 — 281.5 723.1 33.5 50.6 261.1 12.5 19.6 1,436.1 1,381.9 outstanding shares at December 31, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . — Common stock, $0.01 par value. Authorized 300,000,000 shares; issued and outstanding 69,988,728 shares and 70,012,702 shares at December 31, 2012 and December 31, 2011, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Treasury stock, 603,528 shares at December 31, 2012 and no shares at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total SunCoke Energy, Inc. stockholders’ equity / net parent investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Noncontrolling interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.7 (9.4) 436.9 (7.9) 118.8 539.1 35.8 574.9 — 0.7 — 511.3 (6.5) 20.0 525.5 34.4 559.9 Total liabilities and equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,011.0 $1,941.8 (See Accompanying Notes) 84 SunCoke Energy, Inc. Combined and Consolidated Statements of Cash Flows Cash Flows from Operating Activities: Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustments to reconcile net income to net cash provided by operating activities: Loss on firm purchase commitment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stock compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payments (in excess of) less than expense for retirement plans . . . . . . . . . . . . . Changes in working capital pertaining to operating activities: Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years Ended December 31, 2012 2011 2010 (Dollars in millions) $102.5 $ 58.9 $ 146.3 — 80.8 6.7 34.3 (6.6) (3.8) 56.1 (49.0) 15.2 (0.2) (17.4) (12.5) 18.5 58.4 — 24.0 5.8 (18.3) (110.1) 57.0 15.7 15.9 (21.3) (3.2) — 48.2 — 15.4 (6.0) 34.7 — 31.4 25.5 — (0.8) 1.9 Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 206.1 101.3 296.6 Cash Flows from Investing Activities: Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition of business, net of cash received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (80.6) (3.5) — (238.1) (37.6) — (215.6) — 1.7 Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (84.1) (275.7) (213.9) Cash Flows from Financing Activities: Proceeds from issuance of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repayment of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from exercise of stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repurchase of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchase of noncontrolling interest in Indiana Harbor facility . . . . . . . . . . . . . . . . . . Net decrease in advances from affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repayments of notes payable assumed in acquisition . . . . . . . . . . . . . . . . . . . . . . . . . Contribution from parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Increase in payable to affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash distributions to noncontrolling interests in cokemaking operations . . . . . . . . . . — — (3.3) 4.7 (9.4) — — — — — (2.3) 727.9 (19.1) (1.6) — — (34.0) (412.8) (2.3) — 5.3 (1.6) Net cash (used in) provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . (10.3) 261.8 Net increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111.7 127.5 87.4 40.1 — — — — — — (56.2) — 1.0 30.8 (20.9) (45.3) 37.4 2.7 Cash and cash equivalents at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $239.2 $ 127.5 $ 40.1 (See Accompanying Notes) 85 At December 31, 2010 . . . . . — $ — $ — $ — $ — $ — $ 369.5 $ 369.5 $ 59.8 $ 429.3 SunCoke Energy, Inc. Combined and Consolidated Statements of Equity Common Stock Treasury Stock Shares Amount Shares Amount Additional Paid-In Capital Accumulated Other Comprehensive Loss Retained Earnings Net Parent Investment Total SunCoke Energy, Inc. or Parent Equity Noncontrolling Interests Total Equity At December 31, 2009 . . . . . — $ — — $ — $ — (Dollars in millions) $ — $ — $ 742.0 $ 742.0 $ 73.6 $ 815.6 — — — — — Net income (loss) from January 1, 2009 to December 31, 2010 . . . . . . Reclassifications of prior service benefit and actuarial loss amortization to earnings (net of related tax benefit of $1.0 million) Retirement benefit plans . . . funded status adj. (net of related tax expense of $14.8 million) . . . . . . . . . . Currency translation adjustment . . . . . . . . . . . . . Capital contribution from Sunoco, Inc. . . . . . . . . . . . . Noncash distribution to affiliates. . . . . . . . . . . . . . . Cash distributions to noncontrolling interests . . . Net income (loss) from January 1, 2011 to July 18, 2011 . . . . . . . . . . . . . . . . . . Net income from July 19, 2011 to December 31, 2011 . . . . . . . . . . . . . . . . . . Reclassifications of prior service benefit and actuarial loss amortization to earnings (net of related tax benefit of $1.2 million) Retirement benefit plans . . . funded status adj. (net of related tax benefit of $4.3 million) . . . . . . . . . . . . . . . Currency translation adjustment . . . . . . . . . . . . . Capital contribution from Sunoco, Inc. in connection with contribution of business . . . . . . . . . . . . . . . Noncash distribution to — — — — — — — — 139.2 139.2 7.1 146.3 — — — — — — (1.7) (1.7) 24.1 0.4 1.0 24.1 0.4 1.0 (535.5) (535.5) — — — — — (1.7) 24.1 0.4 1.0 (535.5) — — (20.9) (20.9) — — — — — — — — — — — — (45.3) — — (1.1) (6.3) (2.0) — — 562.5 2.9 2.1 (0.2) (7.8) — — — — — — 40.6 20.0 — 40.6 20.0 (5.0) 35.6 3.3 23.3 — — — — — — — — — — (1.1) (2.2) — 0.6 (6.3) (1.4) 156.5 156.5 — (45.3) (566.1) — — — — — 2.1 (0.2) (7.8) — — — — — — — — (2.2) (6.3) (1.4) 156.5 (45.3) — 2.1 (1.4) (1.6) (22.3) — (30.1) — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — Sunoco under Tax Sharing Agreement . . . . . . . . . . . . . Issuance of common stock in exchange for cokemaking and coal mining operations of Sunoco, Inc . . . . . . . . . . 70,000,000 — — — 0.7 — Share-based compensation expense . . . . . . . . . . . . . . . Cash distributions to noncontrolling interests . . . Purchase of noncontrolling interests (net of related tax benefit of $4.1 million) . . . Shares issued to directors . . . — — — — — — 12,702 — — — — — At December 31, 2011 . . . . . 70,012,702 $ 0.7 — $ — $511.3 $ (6.5) $20.0 $ — $ 525.5 $ 34.4 $ 559.9 86 SunCoke Energy, Inc. Combined and Consolidated Statements of Equity Treasury Stock Common Stock Shares Amount Shares Amount Additional Paid-In Capital Accumulated Other Comprehensive Loss Retained Earnings Net Parent Investment Total SunCoke Energy, Inc. or Parent Equity Noncontrolling Interests Total Equity At December 31, 2011 . . . . 70,012,702 $ 0.7 — $— $511.3 (Dollars in millions) $ 20.0 $(6.5) — — — — — — 98.8 $— — $525.5 98.8 $34.4 3.7 $559.9 102.5 Net income . . . . . . . . . . . . . . Reclassifications of prior service benefit and actuarial loss amortization to earnings (net of related tax benefit of $1.2 million) . . . . . . . . . . . Retirement benefit plans funded status adjustment (net of related tax expense of $0.8 million) . . . . . . . . Currency translation adjustment . . . . . . . . . . . . Noncash distribution to Sunoco under Tax Sharing Agreement . . . . . . . . . . . . Share-based compensation expense . . . . . . . . . . . . . . . Cash distributions to noncontrolling interests . . Stock options exercised and RSUs vesting . . . . . . . . . . Shares repurchased . . . . . . . . Shares issued to directors . . . — — — — — — — — — — — — — — — — — — — 566,204 — (603,528) — 603,528 — 13,350 — — — — — — — — (9.4) — — — — (85.8) 6.5 — 4.7 — 0.2 (1.9) 1.6 (1.1) — — — — — — — — — — — — — — — — — — — — — — — — (1.9) 1.6 (1.1) (85.8) 6.5 — 4.7 (9.4) 0.2 — — — — — (2.3) — — — (1.9) 1.6 (1.1) (85.8) 6.5 (2.3) 4.7 (9.4) 0.2 At December 31, 2012 . . . . 69,988,728 $ 0.7 603,528 $(9.4) $436.9 $(7.9) $118.8 $— $539.1 $35.8 $574.9 (See Accompanying Notes) 87 SunCoke Energy, Inc. Notes to Combined and Consolidated Financial Statements 1. General Description of Business and Basis of Presentation SunCoke Energy, Inc. (“SunCoke Energy”, “Company”, “we”, “our” and “us”) is the largest independent producer of high-quality coke in the Americas, as measured by tons of coke produced each year, and has more than 50 years of coke production experience. Coke is a principal raw material in the blast furnace steelmaking process. Coke is generally produced by heating metallurgical coal in a refractory oven, which releases certain volatile components from the coal, thus transforming the coal into coke. We have designed, developed and built, and own and operate five cokemaking facilities in the United States (“U.S.”) and designed and operate one cokemaking facility in Brazil under licensing and operating agreements on behalf of our customer. Our newest U.S. cokemaking facility in Middletown, Ohio commenced operations in October 2011, bringing total U.S. cokemaking capacity from approximately 3.7 million tons of coke per year to approximately 4.2 million tons of coke per year. The cokemaking facility that we operate in Brazil has cokemaking capacity of approximately 1.7 million tons of coke per year. We have a preferred stock investment in the project company that owns the Brazil facility. Our cokemaking ovens utilize efficient, modern heat recovery technology designed to combust the coal’s volatile components liberated during the cokemaking process and use the resulting heat to create steam or electricity for sale. This differs from by-product cokemaking which seeks to repurpose the coal’s liberated volatile components for other uses. We have constructed the only greenfield cokemaking facilities in the United States in the last 25 years and are the only North American coke producer that utilizes heat recovery technology in the cokemaking process. Heat recovery technology uses waste heat to generate steam or electricity. Our Granite City facility and the first phase of our Haverhill facility, or Haverhill 1, include steam generation facilities which use hot flue gas from the cokemaking process to produce steam. The steam is sold to a third-party pursuant to a steam supply and purchase agreements. Our Middletown facility and the second phase of our Haverhill facility, or Haverhill 2, include cogeneration plants that use the hot flue gas created by the cokemaking process to generate electricity. The electricity is either sold into the regional power market or to AK Steel pursuant to energy sales agreements. We have coal mining operations in Virginia and West Virginia with more than 113 million tons of proven and probable reserves. In 2012, we sold approximately 1.3 million tons of metallurgical coal (including internal sales to our cokemaking operations) and 0.2 million tons of thermal coal. On January 17, 2012 (the “Distribution Date”), we became an independent, publicly-traded company following our separation from Sunoco, Inc. (“Sunoco”). Our separation from Sunoco occurred in two steps: • We were formed as a wholly-owned subsidiary of Sunoco. On July 18, 2011 (the “Separation Date”), Sunoco contributed the subsidiaries, assets and liabilities that were primarily related to its cokemaking and coal mining operations to us in exchange for shares of our common stock. As of such date, Sunoco owned 100 percent of our common stock. On July 26, 2011, we completed an initial public offering (“IPO”) of 13,340,000 shares of our common stock, or 19.1 percent of our outstanding common stock. Following the IPO, Sunoco continued to own 56,660,000 shares of our common stock, or 80.9 percent of our outstanding common stock. • On the Distribution Date, Sunoco made a pro-rata, tax free distribution (the “Distribution”) of the remaining shares of our common stock that it owned in the form of a special stock dividend to Sunoco shareholders. Sunoco shareholders received 0.53046456 of a share of common stock for every share of Sunoco common stock held as of the close of business on January 5, 2012, the record date for the Distribution. After the Distribution, Sunoco ceased to own any shares of our common stock. 88 Concurrent with the reorganization just prior to the IPO, substantially all related party balances were settled in connection with the issuance of common stock to Sunoco, with the exception of $575 million, which was repaid on July 26, 2011 in cash with a portion of the proceeds from SunCoke Energy’s debt issuance. The historical Combined Financial Statements for periods prior to the Separation Date include the accounts of all operations that comprised the cokemaking and coal mining operations of Sunoco, after elimination of all intercompany balances and transactions within the combined group of companies. The historical Combined Financial Statements also include allocations of certain Sunoco corporate expenses. SunCoke Energy management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. However, such expenses may not be indicative of the actual level of expense that would have been incurred by SunCoke Energy if it had operated as an independent, publicly-traded company during the periods prior to the IPO or of the costs expected to be incurred in the future. See Note 6 for further information regarding allocated expenses. The Consolidated Financial Statements for the period after the Separation Date pertain to the operations of SunCoke Energy. A variable interest entity (“VIE”) is a legal entity in which equity investors do not have sufficient equity at risk for the legal entity to finance its activities without additional subordinated financial support or, as a group, the holders of the equity investment at risk lack any one of the following three characteristics: (1) the power, through voting rights or similar rights, to direct the activities of a legal entity that most significantly impact the entity’s economic performance; (2) the obligation to absorb the expected losses of the legal entity; or (3) the right to receive the expected residual returns of the legal entity. A company with a variable interest or interests in a VIE is required to consolidate that VIE if it has a controlling financial interest, which will have both of the following characteristics: (1) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance; and (2) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The Company entered into an agreement in March 1997 with Lakeshore Coal Handling Corporation (“Lakeshore”), which provides coal handling services at the Indiana Harbor cokemaking facility. Under accounting principles generally accepted in the United States (GAAP), it is possible that Lakeshore would be a VIE and that the Company should be considered Lakeshore’s primary beneficiary. However, Lakeshore has declined to provide the Company with the financial information to make this determination. Accordingly, the Company does not include Lakeshore’s accounts in its Combined and Consolidated Financial Statements as permitted by a transition provision of the VIE accounting guidance. In addition, the Company has no obligations to Lakeshore under the agreement other than the amounts payable for the coal handling services (Note 17). The Company will continue to make efforts to obtain this information. 2. Summary of Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the Combined and Consolidated Financial Statements and accompanying notes. Actual amounts could differ from these estimates. Reclassifications Certain amounts in the prior period Combined and Consolidated Financial Statements have been reclassified to conform to the current year presentation. Currency Translation The functional currency of the Company’s Brazilian operations is the Brazilian real. The Company’s Brazilian operations translate their assets and liabilities into U.S. dollars at the current exchange rates in effect at 89 the end of the fiscal period. The gains or losses that result from this process are shown as cumulative translation adjustments within accumulated other comprehensive loss in the Consolidated Balance Sheets. The revenue and expense accounts of foreign subsidiaries are translated into U.S. dollars at the average exchange rates that prevailed during the period. Some transactions of the Company’s Brazilian operations are conducted in currencies different from their functional currency. Gains and losses from these foreign currency transactions are included in income as they occur and were not material to the results of operations during the years ended December 31, 2012, 2011 and 2010. Revenue Recognition The Company sells metallurgical coal and coke as well as steam and electricity to third-party customers. The Company also receives fees for operating the cokemaking plant in Brazil and for the licensing of its proprietary technology for use at this facility as well as reimbursement of substantially all of its operating costs. Revenues related to the sale of products are recognized when title passes, while service revenues are recognized when services are provided. Licensing fees, which are determined on a per ton basis, are recognized when coke is produced in accordance with the contract terms. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. Revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured. As discussed in Note 7, substantially all of the coke produced by the Company is sold pursuant to long-term contracts with its customers. The Company evaluates each of its contracts to determine whether the arrangement contains a lease under the applicable accounting standards. If the specific facts and circumstances indicate that it is remote that parties other than the contracted customer will take more than a minor amount of the coke that will be produced by the property, plant and equipment during the term of the coke supply agreement, and the price that the customer is paying for the coke is neither contractually fixed per unit nor equal to the current market price per unit at the time of delivery, then the long-term contract is deemed to contain a lease. The lease component of the price of coke represents the rental payment for the use of the property, plant and equipment, and all such payments are accounted for as contingent rentals as they are only earned by the Company when the coke is delivered and title passes to the customer. The total amount of revenue recognized by the Company for these contingent rentals represents less than 10 percent of combined sales and other operating revenues for each of the years ended December 31, 2012, 2011 and 2010. Cash Equivalents The Company considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of time deposits and money market investments. Inventories Inventories are valued at the lower of cost or market. Cost is determined using the first-in, first-out method, except for the cost of coal inventory in our Coal Mining segment and the Company’s materials and supplies inventory, which are determined using the average-cost method. The Company utilizes the selling prices under its long-term coke supply contracts (Note 7) to record lower of cost or market inventory adjustments. Properties, Plants and Equipment Plants and equipment are depreciated on a straight-line basis over their estimated useful lives. Coke and energy plant, machinery and equipment are depreciated over 25 to 30 years. All depreciation, depletion and 90 amortization is excluded from cost of products sold and operating expenses and presented separately in the Combined and Consolidated Statements of Income. Gains and losses on the disposal or retirement of fixed assets are reflected in earnings when the assets are sold or retired. Amounts incurred that extend an asset’s useful life, increase its productivity or add production capacity are capitalized. Direct costs, such as outside labor, materials, internal payroll and benefits costs, incurred during the construction of a new facility are capitalized; indirect costs are not capitalized. Normal repairs and maintenance costs are expensed as incurred. The Company’s coal mining operations lease small parcels of land, mineral rights and coal mining rights. Substantially all of the leases are “life of mine” agreements that extend the Company’s mining rights until all reserves have been recovered. These leases convey mining rights to the Company in exchange for payment of certain royalties and/or fixed fees. The lease and mineral rights are capitalized and amortized as depletion expense using the units-of-production method. Only proven and probable coal reserves are included in the depletion base. Impairment of Long-Lived Assets Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. An asset, or group of assets, is considered to be impaired when the undiscounted estimated net cash flows expected to be generated by the asset, or group of assets, are less than its carrying amount. The impairment recognized is the amount by which the carrying amount exceeds the fair market value of the impaired asset, or group of assets. Goodwill and Intangibles Goodwill, which represents the excess of the purchase price over the fair value of net assets acquired, is tested for impairment at least annually. There was no impairment of goodwill or intangibles during the periods presented. Intangible assets with finite useful lives are amortized over their useful lives in a manner that reflects the pattern in which the economic benefit of the intangible asset is consumed. Investment in Brazilian Cokemaking Operations SunCoke Energy’s investment in preferred shares of the company that owns the cokemaking facility in Vitória, Brazil, that SunCoke Energy operates under licensing and operating agreements, is accounted for at cost. Income received by SunCoke Energy from this investment, which is in the form of a dividend, is contingent upon achieving certain minimum production levels at the facility and payment is guaranteed by the parent company of the plant’s owner, which is a lessee of the facility. Accordingly, the Company recognizes income from this investment when certain required production levels have been met and the amount is deemed collectible, typically in the fourth quarter. Derivative Financial Instruments The Company utilizes derivative financial instruments to hedge against the risk of adverse movements in interest rates and foreign currency fluctuations. Our corporate policy prohibits the use of derivative instruments for trading or speculative purposes, and we have procedures in place to monitor and control their use. See Note 23 to the Combined and Consolidated Financial Statements. Cash received or paid upon settlement of derivative financial instruments are classified in the same category as the cash flows from items being hedged in the Combined and Consolidated Statements of Cash Flows. Income Taxes Prior to the Distribution Date, SunCoke Energy and certain subsidiaries of Sunoco were included in the consolidated federal and certain consolidated, combined or unitary state income tax returns filed by Sunoco. 91 However, SunCoke Energy’s provision for income taxes and the deferred income tax amounts reflected in the Combined and Consolidated Financial Statements have been determined on a theoretical separate-return basis. Prior to the Separation Date, any current federal and state income tax amounts were settled with Sunoco under a previous tax sharing arrangement. Under this previous tax sharing arrangement, net operating losses and tax credit carryforwards generated on a theoretical separate-return basis could be used to offset future taxable income determined on a similar basis. Such benefits were reflected in the Company’s deferred tax assets, notwithstanding the fact that such net operating losses and tax credits may actually have been realized on Sunoco’s consolidated income tax returns, or may be realized in future Sunoco consolidated income tax returns (for periods through the Distribution Date). On the Separation Date, SunCoke Energy and Sunoco entered into a new tax sharing agreement that governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and other matters regarding taxes. Under the tax sharing agreement, certain deferred tax assets attributable to net operating losses and credit carry forwards, which had been reflected in SunCoke Energy’s balance sheets prior to the Separation Date on a standalone theoretical basis, are no longer realizable by SunCoke Energy and as such were eliminated from the Consolidated Balance Sheets with a corresponding reduction in SunCoke Energy’s equity accounts. We did not retain any of the federal income tax credits or net operating loss carryforwards that the Company had recognized as deferred income tax assets that were generated prior to the Distribution Date. However, the Company retained certain state tax credits and net operating loss carryforwards, which have been recognized as deferred tax assets on our Consolidated Balance Sheet and that may be used to reduce the Company’s future income tax liabilities. The Company recognizes uncertain tax positions in its financial statements when minimum recognition threshold and measurement attributes are met in accordance with current accounting guidance. Unrecognized tax benefits and accruals for interest and penalties are included in other deferred credits and liabilities in the Consolidated Balance Sheets. The Company recognizes interest related to unrecognized tax benefits in interest cost and penalties in income tax expense in the Combined and Consolidated Statements of Income. Deferred tax asset and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those differences are projected to be recovered or settled. Retirement Benefit Liabilities The funded status of defined benefit and postretirement benefit plans is fully recognized on the Consolidated Balance Sheets. It is determined by the difference between the fair value of plan assets and the benefit obligation, with the benefit obligation represented by the projected benefit obligation for defined benefit plans and the accumulated postretirement benefit obligation for postretirement benefit plans. Actuarial gains (losses) and prior service (benefits) costs which have not yet been recognized in net income are recognized as a credit (charge) to accumulated other comprehensive loss. The credit (charge) to accumulated other comprehensive loss, which is reflected net of related tax effects, is subsequently recognized in net income when amortized as a component of defined benefit plans and postretirement benefit plans expense. In addition, the credit (charge) may also be recognized in net income as a result of a plan curtailment or settlement. Asset Retirement Obligations The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and depreciated over its remaining estimated useful life. The Company’s asset retirement obligations primarily relate to costs associated with restoring land to its original state. 92 Shipping and Handling Costs Shipping and handling costs are included in cost of products sold and operating expenses. Stock-based Compensation We measure the cost of employee services in exchange for an award of equity instruments based on the grant-date fair value of the award. The total cost is reduced by estimated forfeitures over the awards’ vesting period and the cost is recognized over the requisite service period. Forfeiture estimates are reviewed on an annual basis. Fair Value Measurements The Company determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, the Company utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy included in current accounting guidance. The Company generally applies the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety. Recently Issued Pronouncements There are no recently issued accounting standards which are not yet effective that we believe would materially impact our Combined and Consolidated Financial Statements. Labor Concentrations As of December 31, 2012, we have approximately 1,214 employees in the United States. Approximately 312, or 26 percent, of our domestic employees, principally at our cokemaking operations, are currently represented by the United Steelworkers under various contracts. The labor agreement at our Haverhill facility was recently extended through October 31, 2015. As of December 31, 2012, we have approximately 249 employees at the cokemaking facility in Vitória, Brazil, all of whom are represented by a union under an agreement that expires on November 30, 2013. 3. Arrangements Between Sunoco and SunCoke Energy, Inc. In connection with the IPO, SunCoke Energy and Sunoco entered into certain agreements that effected the separation of SunCoke Energy’s business from Sunoco (the “Separation”), provided a framework for its relationship with Sunoco after the separation and provided for the allocation between SunCoke Energy and Sunoco of Sunoco’s assets, employees, liabilities and obligations attributable to periods prior to, at and after SunCoke Energy’s Separation from Sunoco. Separation and Distribution Agreement. On the Separation Date, SunCoke Energy and Sunoco entered into the separation and distribution agreement, which set forth the agreements between SunCoke Energy and Sunoco regarding the principal corporate transactions required to effect SunCoke Energy’s separation from Sunoco, the IPO and the Distribution, if any, of SunCoke Energy’s shares to Sunoco’s shareholders, and other agreements governing the relationship between Sunoco and SunCoke Energy. The separation and distribution agreement identified assets to be transferred, liabilities to be assumed and contracts to be assigned to each of SunCoke Energy and Sunoco as part of the separation of Sunoco into two companies. Except as expressly provided, all assets were transferred on an “as is,” “where is” basis. In general, each party to the separation and distribution agreement assumed liability for all pending, threatened and 93 unasserted legal matters related to its own business or its assumed or retained liabilities and will indemnify the other party for any liability to the extent arising out of or resulting from such assumed or retained legal matters. In addition, the separation and distribution agreement provides for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of SunCoke Energy’s business with SunCoke Energy and financial responsibility for the obligations and liabilities of Sunoco’s business with Sunoco. The separation and distribution agreement allocates responsibility with respect to certain employee related matters, particularly with respect to Sunoco employee benefit plans in which any SunCoke Energy employees participate or SunCoke Energy employee benefit plans which hold assets in joint trusts with Sunoco. In addition, the separation and distribution agreement provided for certain adjustments with respect to Sunoco equity compensation awards that occurred when Sunoco completed the Distribution. Tax Sharing Agreement. On the Separation Date, SunCoke Energy and Sunoco entered into a tax sharing agreement that governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and other matters regarding taxes. For a detailed discussion of the tax sharing agreement, see Note 8. Transition Services Agreement. On the Separation Date, SunCoke Energy and Sunoco entered into a transition services agreement in connection with the separation. Pursuant to the transition services agreement, Sunoco provides certain support services to SunCoke Energy, including, among others, information technology, treasury, risk management and insurance, tax, internal audit and various other corporate services, in each case consistent with the services provided by Sunoco to SunCoke Energy before the Separation. The charges for the transition services generally are intended to allow Sunoco to fully recover the costs directly associated with providing the services, plus all out-of-pocket costs and expenses, generally without profit. The services provided under the transition services agreement terminate at various times specified in the agreement (generally terminating upon completion of the Distribution on January 17, 2012). As of December 31, 2012, most services provided by Sunoco under this agreement have terminated, with the exception of certain information technology services and other de minimis support. SunCoke Energy may terminate certain of the remaining specified services by giving prior written notice to Sunoco of such services and paying any applicable termination charge. Guaranty, Keep Well, and Indemnification Agreement. On the Separation Date, SunCoke Energy and Sunoco entered into a guaranty, keep well, and indemnification agreement. Under this agreement, SunCoke Energy: (1) guarantees the performance of certain obligations of its subsidiaries, prior to the date that Sunoco or its affiliates may become obligated to pay or perform such obligations, including the repayment of a loan from Indiana Harbor Coke Company L.P.; (2) indemnifies, defends, and holds Sunoco and its affiliates harmless against all liabilities relating to these obligations; and (3) restricts the assets, debts, liabilities and business activities of one of its wholly-owned subsidiaries, so long as certain obligations of such subsidiary remain unpaid or unperformed. In addition, SunCoke Energy releases Sunoco from its guaranty of payment of a promissory note owed by one of its subsidiaries to another of its subsidiaries. 4. Acquisition Harold Keene Coal Company, Inc. On January 14, 2011, the Company acquired 100 percent of the outstanding common shares of HKCC for approximately $52.0 million, including working capital and contingent consideration. The results of HKCC have been included in the Consolidated Financial Statements since that date and are included in the Coal Mining segment. HKCC engages in the business of coal mining and owns, leases, and operates mines in Russell County, Virginia. The operations of the HKCC Companies produce high volatile A and high volatile B metallurgical coals, which complement the coal produced by the Company’s existing coal mining operations, and high quality thermal coal. These operations have the ability to produce between 250 thousand and 300 thousand tons of coal production annually, with the potential to expand production in the future. HKCC has approximately 20 million tons of proven and probable coal reserves located in Russell and Buchanan Counties in Virginia, contiguous to 94 the Company’s existing metallurgical coal mining operations. The acquisition is part of the Company’s strategy to expand its domestic coal production and pursue selective reserve acquisitions. The goodwill of $6.0 million arising from the acquisition consists largely of synergies and cost reductions. The aggregate noncontingent portion of the purchase price was $41.1 million, of which $37.6 million was paid in cash, net of cash received of $0.8 million. The remaining amount relates to a purchase price holdback of $3.5 million that was paid in July 2012. The purchase price includes a contingent consideration arrangement that requires the Company to pay the former owners of HKCC $2.00 per ton of coal for each ton produced from the real property or leased property if production levels exceed 150 thousand tons in a calendar year for a period of 20 years or until full exhaustion, whichever comes sooner. The potential undiscounted amount of all future payments that could be required to be paid under the contingent consideration arrangement is between $0 and $42 million. The fair value of the contingent consideration at the acquisition date was $10.9 million, and was based on significant inputs that are not observable in the market, or Level 3 inputs. Key assumptions included (a) a risk-adjusted discount rate range of 0.895 percent to 6.027 percent, which reflects the credit spread adjustment for each period, and (b) probability adjusted production levels of HKCC operations between 300 thousand and 475 thousand tons per year. The fair value of the contingent consideration at December 31, 2012, was $4.8 million. The estimated fair value is based on significant inputs that are not observable in the market, or Level 3 within the valuation hierarchy. Key assumptions at December 31, 2012 include (a) a risk-adjusted discount rate range of 1.915 percent to 8.066 percent, which reflects a credit spread adjustment for each period, and (b) production levels of HKCC operations between 91 thousand and 318 thousand tons per year. The fair value adjustments to contingent consideration decreased cost of products sold by $4.2 million and $1.9 million for 2012 and 2011, respectively. The following table summarizes the consideration paid for HKCC and the fair value of the assets acquired and liabilities assumed at the acquisition date (dollars in millions): Consideration: Cash, net of cash received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Working capital adjustment and purchase price hold back . . . . . . . . . . . . . . . . Contingent consideration arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 37.6 3.5 10.9 Fair value of total consideration transferred . . . . . . . . . . . . . . . . . . . . . . . . $ 52.0 Recognized amounts of identifiable assets acquired and liabilities assumed: Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mineral rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred tax liabilities, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total identifiable net assets assumed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7.3 15.5 48.1 2.4 (1.5) (22.7) (2.3) (0.8) 46.0 6.0 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 52.0 The fair value of the acquired mineral rights of $47.3 million net of asset retirement obligations of $0.8 million was determined by applying the income approach, and is based on significant inputs that are not observable in the market, or Level 3 inputs. The acquired mineral rights will be depleted as they are extracted, which is estimated to be over a period of 31 years. Immediately upon acquisition, $2.3 million of notes payable were repaid. 95 The acquisition of HKCC contributed revenues and gross margin of $8.1 million and ($2.1) million, respectively in 2012 and contributed revenues and gross margin of $19.4 million and $2.7 million, respectively, in 2011. The acquisition of HKCC is not material to the Company’s combined and consolidated results of operations. Therefore, pro forma information has not been presented. 5. Noncontrolling Interests On February 19, 1998, the Company transferred an interest in its Indiana Harbor cokemaking operations to a third-party investor for $200.0 million in cash. On July 30, 2002, the Company transferred an additional interest in Indiana Harbor for $200.0 million and sold a portion of its interest in Indiana Harbor for $15.0 million in cash to another third-party investor. The Company did not recognize any gain at the dates of these transactions because the third-party investors were entitled to a preferential return on their investments. The returns of the investors were equal to 98 percent of the cash flows and tax benefits from such cokemaking operations during the preferential return period, which continued until the fourth quarter of 2007 (at which time both investors had recovered their investment and achieved a cumulative annual after-tax return of approximately 10 percent). During the third quarter of 2011, the Company purchased an additional 19 percent ownership interest in the partnership that owns the Indiana Harbor cokemaking facility for $34.0 million, which decreased equity attributable to SunCoke Energy by $7.8 million, net of $4.1 million in deferred taxes, for the year end December 31, 2011. As a result of this transaction, the Company now holds an 85 percent interest in the partnership. The remaining interest in the partnership is owned by an affiliate of DTE Energy Company. DTE Energy is entitled to a noncontrolling interest amounting to 15 percent of the partnership’s net income through 2037, at which time the noncontrolling interest percentage declines to 5 percent. The Company accounted for the increase in ownership as an equity transaction, which resulted in a $22.3 million decrease in noncontrolling interest and a $7.8 million decrease in additional paid-in capital, net of income taxes in 2011. Direct costs of $0.2 million related to the increase in ownership were also accounted for as part of the equity transaction in 2011. 6. Related Party Transactions The related party transactions with Sunoco and its affiliates are described below. Advances from/to Affiliate Prior to the Separation Date, Sunoco, Inc. (R&M), a wholly-owned subsidiary of Sunoco, served as a lender and borrower of funds and a clearinghouse for the settlement of receivables and payables for the Company and Sunoco and its affiliates. Amounts due Sunoco, Inc. (R&M) for the settlement of payables included advances to fund capital expenditures. Interest on such payables was based on short-term money market rates. The weighted- average annual interest rate used to determine interest expense was 2.4 percent and 1.6 percent for 2011 and 2010, respectively, and $3.5 million and $5.4 million of expense is included in interest cost—affiliate on the Combined and Consolidated Statements of Income for 2011 and 2010, respectively. As described in Note 1, on July 26, 2011, proceeds from debt issuances were used to repay $575 million of the advances from affiliate, and the remaining balance was treated as a contribution from Sunoco and capitalized to net parent investment. Indiana Harbor had a $30.0 million revolving credit agreement with Sunoco, Inc. (R&M) (the “Indiana Harbor Revolver”), which was terminated in conjunction with the Separation. The interest rates for advances under the Indiana Harbor Revolver were based on the one-month London Inter-Bank Offered Rate, as quoted by Bloomberg, L.P., plus 1 percent (1.26 percent at December 31, 2010). The expense associated with the revolving credit agreement is included in interest cost—affiliate on the Combined and Consolidated Statements of Income. Interest income on advances to affiliate generated by the investment of idle funds under the clearinghouse activities described above is included in interest income—affiliate in the Combined and Consolidated Statements of Income and totaled $0.5 million and $1.5 million in 2011 and 2010, respectively. Interest paid to affiliates 96 under the above borrowing arrangements is classified as interest cost—affiliate in the Combined and Consolidated Statements of Income and totaled $3.6 million and $5.4 million in 2011 and 2010, respectively. Receivable/Payable from/to Affiliate During 2002, in connection with an investment in the partnership by a third-party investor, Indiana Harbor loaned $200.0 million of excess cash to The Claymont Investment Company (“Claymont”), a then wholly-owned subsidiary of Sunoco. The loan was evidenced by a note with an interest rate of 7.44 percent per annum. Interest income related to the note, which was paid quarterly, is included in interest income—affiliate in the Combined and Consolidated Statements of Income and amounted to $8.0 million and $14.9 million in 2011 and 2010, respectively. During 2000, in connection with an investment in the partnership by a third-party investor, Jewell loaned $89.0 million of excess cash to Claymont. The loan was evidenced by a note with an interest rate of 8.24 percent per annum. Interest income related to the note, which was paid annually, is included in interest income—affiliate in the Combined and Consolidated Statements of Income and amounted to $4.0 million and $7.3 million in 2011 and 2010, respectively. In connection with the Separation, Sunoco contributed Claymont to SunCoke Energy primarily to transfer certain intercompany receivables from and intercompany payables to SunCoke Energy, including the notes payable to Indiana Harbor and Jewell. Accordingly, these notes receivable are now receivables and payables of SunCoke Energy’s subsidiaries and the balances and related interest income are now eliminated in consolidation. The Company had a non-interest bearing payable to affiliate totaling $55.8 million at December 31, 2010. This intercompany balance represented the difference between the taxes allocated to the Company by Sunoco under a tax-sharing arrangement and the taxes recognized by the Company on a separate-return basis as reflected in the combined financial statements. In connection with the Separation, the payable to affiliate at the Separation Date was capitalized to net parent investment as discussed in the Net Parent Investment/SunCoke Energy, Inc. Stockholders’ Equity section below. Sales to Affiliate The flue gas produced during the Haverhill cokemaking process is being utilized to generate low-pressure steam, which is sold to the adjacent chemical manufacturing complex formerly owned and operated by Sunoco’s chemicals business. In 2011, Sunoco sold this facility to Goradia Capital LLC (“Goradia”). Under this agreement, Goradia has assumed Sunoco’s obligations under the agreement. Steam sales to Sunoco’s chemicals business totaled $7.7 million and $9.6 million in 2011 and 2010, respectively. Allocated Expenses Prior to the Separation, amounts were allocated from subsidiaries of Sunoco for employee benefit costs of certain executives of the Company as well as for the cost associated with the participation of such executives in Sunoco’s principal management incentive plans. The employee benefit costs were allocated as a percentage of the executives’ actual pay, while the incentive plan costs represented the actual costs associated to the executives. Indirect corporate overhead attributable to the operations of the Company was also allocated from Sunoco. These overhead expenses incurred by Sunoco include costs of centralized corporate functions such as legal, accounting, tax, treasury, engineering, information technology, insurance and other corporate services. The allocation methods for these costs include estimates of the costs and level of support attributable to SunCoke Energy for legal, accounting, tax, treasury and engineering, usage and headcount for information technology and prior years’ claims information and historical cost of insured assets for insurance. 97 Concurrent with the Separation, SunCoke Energy entered into a transition services agreement with Sunoco. Under this agreement, Sunoco provides certain services, the use of facilities and other assistance on a transitional basis to SunCoke Energy for fees which approximate Sunoco’s cost of providing these services (Note 3). The above allocations and transition services fee are included in cost of products sold and operating expenses and selling, general and administrative expenses in the Combined and Consolidated Statements of Income and totaled $0.6 million, $7.0 million, and $7.1 million in 2012, 2011 and 2010, respectively. Note that since the Distribution, transactions with Sunoco are not considered related party transactions. Net Parent Investment/SunCoke Energy, Inc. Stockholders’ Equity Prior to the contribution of the cokemaking and coal mining operations to SunCoke Energy, the net parent investment represented Sunoco’s equity investment in the Company and reflected capital contributions and returns of capital, net income attributable to Sunoco’s ownership and accumulated other comprehensive loss, which was all attributable to Sunoco’s ownership. In connection with the Separation, Sunoco made a capital contribution to SunCoke Energy under the terms of the separation and distribution agreement which eliminated certain assets and obligations of SunCoke Energy previously reflected in its combined balance sheet. The following summarizes the impact on SunCoke Energy’s Consolidated Balance Sheet at the Separation Date: Increase (decrease) in capital contribution (dollars in millions): Interest receivable from affiliate . . . . . . . . . . . . . . . . . . . . . . . . Notes receivable from affiliate . . . . . . . . . . . . . . . . . . . . . . . . . Advances from affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payable to affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes (Note 8) . . . . . . . . . . . . . . . . . . . . . . . . $ (4.8) (289.0) 487.3 61.1 (98.1) Net capital contribution from Sunoco . . . . . . . . . . . . . . . . . . . . $ 156.5 In connection with the contribution of assets for shares of SunCoke Energy common stock, the appropriate components of the total net parent investment were capitalized to stockholders’ equity. Upon and subsequent to the Separation, SunCoke Energy made noncash distributions of $229.2 million related to the settlement of tax attributes under the tax sharing agreement with Sunoco. A corresponding reduction was made to SunCoke Energy’s equity account. See Note 8 for additional information. During 2010, certain entities which are part of the Company made noncash distributions comprised of $535.5 million of amounts receivable from Sunoco, Inc. (R&M) as a distribution of prior years’ earnings of such subsidiaries to Sunoco. The receivables, which had been offset against amounts due to Sunoco, Inc. (R&M) in the combined balance sheet, were established by prior cash deposits to Sunoco, Inc. (R&M) resulting primarily from the subsidiaries’ earnings. This transaction was treated as a noncash increase in advances from affiliate and a decrease in net parent investment. Accordingly, it is not reflected in the Combined Statement of Cash Flows for the year ended December 31, 2010. Guarantees and Indemnifications For a discussion of certain guarantees that Sunoco, Inc. is providing to the current and former third-party investors of the Indiana Harbor cokemaking operations and the former third-party investors of the Jewell cokemaking facility on behalf of the Company, see Note 17. 98 7. Customer Concentrations In 2012, the Company sold approximately 4.4 million tons of coke to its three primary customers in the United States: ArcelorMittal, AK Steel and U.S. Steel. Substantially all of the production from the Jewell and Indiana Harbor facilities and approximately one-half of the production from the Haverhill facility is sold pursuant to long-term contracts with affiliates of ArcelorMittal. The remaining balance of coke sales at the Haverhill facility are sold to AK Steel under long-term contracts. All coke sales from the Granite City cokemaking facility are made pursuant to a long-term contract with U.S. Steel. All coke sales from the Middletown cokemaking facility, which commenced operations in the fourth quarter of 2011, are made pursuant to a long-term contract with AK Steel. In addition, the licensing and operating fees, as well as preferred dividends pertaining to the Brazilian cokemaking operations, are payable to the Company under long-term contracts with a Brazilian subsidiary of ArcelorMittal. The Company generally does not require any collateral with respect to its receivables. At December 31, 2012, the Company’s receivables balance was primarily due from ArcelorMittal, AK Steel and U.S. Steel. As a result, the Company experiences concentrations of credit risk in its receivables with these three customers; these concentrations of credit risk may be affected by changes in economic or other conditions affecting the steel industry. At December 31, 2012, receivables due from ArcelorMittal, AK Steel and U.S. Steel were $26.1 million, $18.5 million and $10.4 million, respectively. Also included in receivables at December 31, 2012 is a $9.4 million preferred dividend from ArcelorMittal Brasil. This preferred dividend is recorded in other income, net on the Combined and Consolidated Statements of Income. Coke sales to ArcelorMittal and licensing and operating fees from ArcelorMittal Brasil, in total, accounted for $1,018.9 million, $989.1 million and $899.8 million, or 54 percent, 64 percent and 68 percent, for the years ended December 31, 2012, 2011 and 2010, respectively, of the Company’s sales and other operating revenue and are recorded in the Jewell Coke, Other Domestic Coke and International segments. Additionally, preferred dividends from ArcelorMittal Brasil of $9.4 million, $9.3 million and $8.7 million, are recorded in Other income, net on the Combined and Consolidated Statements of Income. Coke and power sales to AK Steel, in total, accounted for $539.4 million, $215.2 million and $176.1 million, or 28 percent, 14 percent and 13 percent, for the years ended December 31, 2012, 2011 and 2010, respectively, of the Company’s sales and other operating revenue and are recorded in the Other Domestic Coke segment. Coke and power sales to U.S. Steel, in total, accounted for $310.6 million, $231.4 million and $197.3 million or 16 percent, 15 percent and 15 percent, for the years ended December 31, 2012, 2011 and 2010, respectively, of the Company’s sales and other operating revenue and are recorded in the Other Domestic Coke segment. 8. Income Taxes Prior to the Distribution Date, SunCoke Energy and certain subsidiaries of Sunoco were included in the consolidated federal and certain consolidated, combined or unitary state income tax returns filed by Sunoco. However, SunCoke Energy’s provision for income taxes and the deferred income tax amounts reflected in the Combined and Consolidated Financial Statements have been determined on a theoretical separate-return basis. Prior to the Separation Date, any current federal and state income tax amounts were settled with Sunoco under a previous tax sharing arrangement. Under this previous tax sharing arrangement, net operating losses and tax credit carryforwards generated on a theoretical separate-return basis could be used to offset future taxable income determined on a similar basis. Such benefits were reflected in the Company’s deferred tax assets, notwithstanding the fact that such net operating losses and tax credits may actually have been realized on Sunoco’s consolidated income tax returns, or may be realized in future consolidated income tax returns covering the period through the Distribution Date. 99 On the Separation Date, SunCoke Energy and Sunoco entered into a new tax sharing agreement that governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and other matters regarding taxes. In general, under the tax sharing agreement: • With respect to any periods ending at or prior to the Distribution, SunCoke Energy is responsible for any U.S. federal income taxes and any U.S. state or local income taxes reportable on a consolidated, combined or unitary return, in each case, as would be applicable to SunCoke Energy as if it filed tax returns on a standalone basis. With respect to any periods beginning after the Distribution, SunCoke Energy will be responsible for any U.S. federal, state or local income taxes of it or any of its subsidiaries. • • Sunoco is responsible for any income taxes reportable on returns that include only Sunoco and its subsidiaries (excluding SunCoke Energy and its subsidiaries), and SunCoke Energy is responsible for any income taxes filed on returns that include only it and its subsidiaries. Sunoco is responsible for any non-income taxes reportable on returns that include only Sunoco and its subsidiaries (excluding SunCoke Energy and its subsidiaries), and SunCoke Energy is responsible for any non-income taxes filed on returns that include only it and its subsidiaries. SunCoke Energy is generally not entitled to receive payment from Sunoco in respect of any of SunCoke Energy’s tax attributes or tax benefits or any reduction of taxes of Sunoco. Moreover, Sunoco is generally entitled to refunds of income taxes with respect to periods ending at or prior to the Distribution. If SunCoke Energy realizes any refund, credit or other reduction in otherwise required tax payments in any period beginning after the Distribution Date as a result of an audit adjustment resulting in taxes for which Sunoco would otherwise be responsible, then, subject to certain exceptions, SunCoke Energy must pay Sunoco the amount of any such taxes for which Sunoco would otherwise be responsible. Further, if any taxes result to Sunoco as a result of a reduction in SunCoke Energy’s tax attributes for a period ending at or prior to the Distribution Date pursuant to an audit adjustment (relative to the amount of such tax attribute reflected on Sunoco’s tax return as originally filed), then, subject to certain exceptions, SunCoke Energy is generally responsible to pay Sunoco the amount of any such taxes. SunCoke Energy has also agreed to certain restrictions that are intended to preserve the tax-free status of the contribution and the Distribution. These covenants include restrictions on SunCoke Energy’s issuance or sale of stock or other securities (including securities convertible into our stock but excluding certain compensatory arrangements), and sales of assets outside the ordinary course of business and entering into any other corporate transaction which would cause SunCoke Energy to undergo a 50 percent or greater change in its stock ownership. SunCoke Energy has generally agreed to indemnify Sunoco and its affiliates against any and all tax-related liabilities incurred by them relating to the contribution or the Distribution to the extent caused by an acquisition of SunCoke Energy’s stock or assets, or other of its actions. This indemnification applies even if Sunoco has permitted SunCoke Energy to take an action that would otherwise have been prohibited under the tax-related covenants as described above. Under the tax sharing agreement, it was determined that certain deferred tax assets attributable to net operating losses and credit carry forwards, which had been reflected in SunCoke Energy’s balance sheets prior to the Separation Date on a theoretical separate-return basis, are not realizable by SunCoke Energy. Accordingly, current and deferred tax benefits totaling $229.2 million were eliminated from the Consolidated Balance Sheets with a corresponding reduction to SunCoke Energy’s equity accounts, $85.8 million and $143.4 million of which were eliminated in the year ended December 31, 2012 and 2011, respectively. 100 The following table sets forth the income tax benefits which were eliminated from SunCoke Energy’s income tax balances (dollars in millions): Nonconventional fuel credit carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gasification investment tax credit carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Federal net operating loss carryback . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Federal, state and foreign net operating losses and tax credit carryforwards . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years Ended December 31, 2012 2011 (Dollars in millions) $39.9 — — 45.9 — $ 54.2 40.7 26.9 22.0 (0.4) $85.8 $143.4 SunCoke Energy’s tax provision was determined on a theoretical separate-return basis through the Distribution Date. To the extent any tax assets or liabilities computed on that basis differ from amounts actually payable or realizable under the provisions of the tax sharing agreement, adjustments to the tax assets and liabilities will be reflected as an income tax expense or benefit with a corresponding payable due to Sunoco, if necessary, when such amounts have been effectively settled under the terms of the tax sharing agreement. As of December 31, 2012, SunCoke Energy estimates that all tax benefits have been settled under the provisions of the tax sharing agreement. SunCoke Energy will continue to monitor the full utilization of all tax attributes when the respective tax returns are filed and will, consistent with the terms of the tax sharing agreement, record additional adjustments when necessary. The components of income before income tax expense are as follows: Years Ended December 31, 2012 2011 2010 Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . The components of income tax expense are as follows: (Dollars in millions) $59.8 6.3 $187.0 6.2 $118.1 7.8 $125.9 $66.1 $193.2 Years Ended December 31, 2012 2011 2010 (Dollars in millions) Income taxes currently payable (receivable): U.S. federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(15.7) 2.1 2.7 $(16.8) (3.2) 3.2 $23.7 5.2 2.6 Deferred tax (benefit): U.S. federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (10.9) (16.8) 31.5 36.9 (2.6) 34.3 20.0 4.0 24.0 14.8 0.6 15.4 $ 23.4 $ 7.2 $46.9 101 The reconciliation of the income tax expense at the U.S. statutory rate to the income tax expense is as follows: Years Ended December 31, 2012 2011 2010 Income tax expense at 35 percent U.S. statutory rate . . . . . . . . . . . . . . . . Increase (reduction) in income taxes resulting from: Income attributable to noncontrolling interests(1) . . . . . . . . . . . . . . . Nonconventional fuel credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State and other income taxes, net of federal income tax effects . . . . Percentage depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Return-to-provision adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change in valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Domestic production activity deduction . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Dollars in millions) $ 23.1 $ 67.6 $ 44.1 (1.3) (16.0) (0.3) (1.3) (1.7) — (0.8) 0.7 0.6 (19.8) (0.8) (0.2) (1.2) 1.3 4.2 — (2.5) (19.0) 3.8 — — — (2.8) (0.2) $ 23.4 $ 7.2 $ 46.9 (1) No income tax expense is reflected in the Combined and Consolidated Statements of Income for partnership income attributable to noncontrolling interests. The tax effects of temporary differences that comprise the net deferred income tax liability are as follows: Deferred tax assets: Retirement benefit liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Black lung benefit liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nonconventional fuel credit carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . Federal net operating loss and tax credit carryforward . . . . . . . . . . . . . . . . . State tax credit carryforward, net of federal income tax effects . . . . . . . . . . State net operating loss carryforward, net of federal income tax effects . . . . Other liabilities not yet deductible . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred tax asset, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred tax liabilities: Properties, plants and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investment in partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2012 2011 (Dollars in millions) $ 18.2 13.4 8.4 — 7.5 2.0 12.3 6.2 68.0 (1.3) 66.7 (326.7) (98.9) (425.6) $ 22.3 12.5 38.8 25.6 6.5 2.6 11.3 2.9 122.5 (1.3) 121.2 (284.3) (97.4) (381.7) Net deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(358.9) $(260.5) The net deferred income tax liability is classified in the consolidated balance sheets as follows: December 31, 2012 2011 Current asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Noncurrent liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Dollars in millions) 0.6 $ (261.1) 2.6 (361.5) $ $(358.9) $(260.5) 102 Cash payments, including settlements for income taxes as required under the tax sharing arrangement with Sunoco, amounted to $6.3 million, $7.3 million and $32.4 million for the years ended December 31, 2012, 2011 and 2010, respectively. Sunoco’s consolidated federal income tax returns, which include SunCoke Energy, have been examined by the Internal Revenue Service (“IRS”) for all years through 2008. The 2007 and 2008 tax years remain open due to the carryback of net operating losses. State and foreign income tax returns are generally subject to examination for a period of three to five years after the filing of the respective returns. The state impact of any amended federal returns remains subject to examination by various states for a period of up to one year after formal notification of such amendments to the states. There are no outstanding controversies applicable to SunCoke Energy which would require recognition of a liability for unrecognized tax benefits at December 31, 2012, and the Company has recorded no liabilities for unrecognized tax benefits, interest or penalties during the years ended December 31, 2012, 2011 and 2010. The Company does not expect that any unrecognized tax benefits pertaining to income tax matters will be required in the next twelve months. 9. Inventories The Company’s inventory consists of metallurgical coal, which is the principal raw material for the Company’s cokemaking operations, coke, which is the finished good sold by the Company to its customers, and materials, supplies and other. These components of inventories were as follows: Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Materials, supplies and other . . . . . . . . . . . . . . . . . . . . . . . . . . . Consigned coke inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2012 2011 (Dollars in millions) $138.8 $108.0 15.1 11.8 29.4 32.0 36.4 8.3 $160.1 $219.7 During 2011, the Company estimated that Indiana Harbor would fall short of its 2011 annual minimum coke production requirements by approximately 122 thousand tons. Accordingly, we entered into contracts to procure approximately 133 thousand tons of coke from third parties. However, the coke prices in the purchase agreements exceeded the sales price in the Company’s contract with ArcelorMittal. This resulted in an estimated loss on firm purchase commitments of $18.5 million ($12.2 million attributable to net parent investment and $6.3 million attributable to noncontrolling interests). The Company recorded lower of cost or market adjustments of $1.9 million ($1.4 million attributable to SunCoke Energy, Inc./net parent investment and $0.5 million attributable to noncontrolling interests) on this purchased coke during 2011. In the second quarter of 2011, the Company sold 38 thousand tons of this coke to ArcelorMittal. Operational improvements at Indiana Harbor subsequent to the first quarter of 2011 increased coke production for the balance of 2011 and Indiana Harbor was able to meet its 2011 contractual requirements with ArcelorMittal. In the third quarter of 2011, the Company entered into an agreement to sell approximately 95 thousand tons of the purchased coke to a customer on a consignment basis that will expire, as amended, on the earlier of April 30, 2013 or full consumption of, and payment for, the coke. The customer did not consume any coke in fiscal 2011. In 2012, the customer consumed 73 thousand tons of consigned coke. 103 10. Properties, Plants and Equipment, Net The components of net properties, plants and equipment were as follows: December 31(1), 2012 2011 (Dollars in millions) Coke and energy plant, machinery and equipment . . . . . . . Mining plant, machinery and equipment . . . . . . . . . . . . . . Land and land improvements . . . . . . . . . . . . . . . . . . . . . . . Construction-in-progress . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,497.3 191.2 77.4 38.4 49.1 $1,488.9 164.3 60.8 26.0 34.5 Gross investment, at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . 1,853.4 (456.8) 1,774.5 (382.7) Total properties, plants and equipment, net . . . . . . . . $1,396.6 $1,391.8 (1) Includes assets, consisting mainly of coke and energy plant, machinery and equipment, with a gross investment totaling $1,049.7 million and $966.0 million and accumulated depreciation of $181.7 million and $140.3 million at December 31, 2012 and December 31, 2011, respectively, which are subject to long- term contracts to sell coke and are deemed to contain operating leases. 11. Asset Retirement Obligations The Company’s asset retirement obligations arise primarily from the Federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The Company also has asset retirement obligations related to certain contractual obligations, including the retirement and removal of long-lived assets from certain properties. We do not have any unrecorded asset retirement obligations. The following table provides a reconciliation of changes in the asset retirement obligation during each period (in millions): Balance at January 1, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion expense(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions in estimated cash flows . . . . . . . . . . . . . . . . . . . . . . . . $11.0 0.8 (0.2) 0.8 0.1 Balance at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . $12.5 Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion expense(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions in estimated cash flows . . . . . . . . . . . . . . . . . . . . . . . . 0.7 — 0.8 (0.5) Balance at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . $13.5 (1) Included in cost of products sold and operating expenses. 12. Goodwill The Company has goodwill of $9.4 million as of December 31, 2012 and 2011. During 2011, the Company recorded goodwill of $6.0 million in connection with its acquisition of HKCC, which was allocated to the Coal Mining segment (Note 4). 104 13. Retirement Benefits Plans Defined Benefit Pension Plan and Postretirement Health Care and Life Insurance Plans The Company has a noncontributory defined benefit pension plan (“defined benefit plan”), which provides retirement benefits for certain of its employees. The Company also has plans which provide health care and life insurance benefits for many of its retirees (“postretirement benefit plans”). The postretirement benefit plans are unfunded and the costs are borne by the Company. Effective January 1, 2011, pension benefits under the Company’s defined benefit plan were frozen for all participants in this plan. The Company also amended its postretirement benefit plans during the first quarter of 2010. Postretirement medical benefits for its future retirees were phased out or eliminated, effective January 1, 2011, for non-mining employees with less than ten years of service, all new employees and employer costs for all those still eligible for such benefits were capped. As a result of these changes to its postretirement benefit plans, the Company’s postretirement benefit liability declined $36.7 million during 2010. Most of the benefit of this liability reduction is being amortized into income through 2016. At December 31, 2011, the Company’s pension plan assets were invested in a trust with the assets of other pension plans of Sunoco. These plan assets were separated from the Sunoco trust in January 2012 and were transferred to a newly formed trust established for the Company’s plan. Defined benefit plan expense (benefit) consisted of the following components: Years Ended December 31, 2012 2011 2010 Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost on benefit obligations . . . . . . . . . . . . . . . . . . . . . . . . . Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of: (Dollars in millions) $— $— 1.5 (1.8) 1.5 (2.4) $ 0.5 1.6 (2.2) Actuarial losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.9 0.5 0.6 $ 0.6 $(0.4) $ 0.5 Postretirement benefit plans (benefit) expense consisted of the following components: Years Ended December 31, 2012 2011 2010 Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost on benefit obligations . . . . . . . . . . . . . . . . . . . . . . . . Amortization of: Actuarial losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prior service benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Curtailment gain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Dollars in millions) $ 0.3 2.1 $ 0.7 3.1 $ 0.3 1.8 1.6 (5.6) (1.9) — 1.2 (5.6) (2.0) — 2.1 (4.8) 1.1 (0.7) $(1.9) $(2.0) $ 0.4 Amortization of actuarial losses for 2013 is estimated at $1.0 million for the defined benefit plan. Amortization of actuarial losses and prior service benefit for 2013 is estimated to be $1.4 and $(5.7) million, respectively, for postretirement benefit plans. 105 Defined benefit plan and postretirement benefit plans expense (benefit) is determined using actuarial assumptions as of the beginning of the year or using weighted-average assumptions when curtailments, settlements, and/or other events require a plan remeasurement. The following assumptions were used to determine defined benefit plan and postretirement benefit plans expense (benefit): Defined Benefit Plan Postretirement Benefit Plans 2012 2011 2010 2012 2011 2010 Discount Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term expected rate of return on plan assets . . . . . . . . . . 4.25% 5.00% 5.60% 3.90% 4.60% 5.30% 6.25% 8.25% 8.25% — — — For the years ended December 31, 2012, 2011 and 2010, the long-term expected rate of return on plan assets was estimated based on a variety of factors, including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. The following amounts were recognized as components of other comprehensive (loss) income for the years ended December 31, 2012, 2011 and 2010: Defined Benefit Plan Postretirement Benefit Plans 2012 2011 2010 2012 2011 2010 (Dollars in millions) Reclassifications to earnings of: Actuarial loss amortization . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.9 Prior service benefit amortization . . . . . . . . . . . . . . . . . . . . — $ 0.5 — $ 0.6 — $ 1.6 (5.6) $ 1.2 (5.6) $ 1.9 (5.3) Retirement benefit plan funded status adjustments: Actuarial gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prior service benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (1.9) (6.0) — 0.2 — 0.4 3.9 (3.9) — 7.4 31.3 $(1.0) $(5.5) $ 0.8 $ 0.3 $(8.3) $35.3 The following tables set forth the components of the changes in benefit obligations and fair value of plan assets during 2012 and 2011, as well as the funded status at December 31, 2012 and 2011: Defined Benefit Plan Postretirement Benefit Plans 2012 2011 2012 2011 Benefit obligations at beginning of year(1) . . . . . . . . . . . . . . . . . . Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Actuarial losses (gains) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Plan amendments(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $35.8 — 1.5 2.1 — (1.9) (Dollars in millions) $ 49.7 $30.9 0.3 — 1.8 1.5 (0.7) 5.4 (3.9) — (3.5) (2.0) $ 46.8 0.3 2.1 3.9 — (3.4) Benefit obligations at end of year(1) . . . . . . . . . . . . . . . . . . . . . . . $37.5 $35.8 $ 43.7 $ 49.7 Fair value of plan assets at beginning of year . . . . . . . . . . . . . . . Actual income on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . Employer contribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Benefits paid from plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . $30.1 2.1 4.6 (1.9) $30.4 1.7 — (2.0) Fair value of plan assets at end of year . . . . . . . . . . . . . . . . . . . . . $34.9 $30.1 Funded status at end of year(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (2.6) $ (5.7) $(43.7) $(49.7) 106 (1) Represents both the accumulated benefit obligation and the projected benefit obligation for the defined benefit plan and the accumulated postretirement benefit obligations (“APBO”) for the postretirement benefit plans. (2) Represents retirement benefit liabilities (including current portion) in the consolidated balance sheets. The current portion of retirement liabilities, which totaled $3.8 and $4.8 million at December 31, 2012 and 2011, respectively, is classified in accrued liabilities in the consolidated balance sheets. (3) The Company has amended its postretirement benefit plan, effective January 1, 2013, to provide post-65 retiree health benefits via Health Reimbursement Arrangement employer contributions. The Company contributed $4.6 million to its defined benefit plan during 2012 and does not anticipate making an additional contribution during 2013. The following table sets forth the cumulative amounts not yet recognized in net income at December 31, 2012 and 2011: Defined Benefit Plan Postretirement Benefit Plans 2012 2011 2012 2011 (Dollars in millions) Cumulative amounts not yet recognized in net income: Actuarial losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $16.7 Prior service benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — $15.6 — $ 16.5 $ 18.7 (24.0) (22.2) Accumulated other comprehensive loss (income) (before related tax benefit) . . $16.7 $15.6 $ (5.7) $ (5.3) The following table sets forth the plan assets in the funded defined benefit plan measured at fair value, by input level, at December 31, 2012 and 2011: Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total 2012 2011 2012 2011 2012 2011 2012 2011 (Dollars in millions) Fixed income securities: Government and Federal-sponsored agency obligations . . . . . . . . . . . . . . . . $ — $— $— $ 2.1 Corporate and other debt . . . . . . . . . . . . . — — — $— $— $ — $ 2.1 9.5 — — 9.5 — Mutual and collective trust funds: Equity securities: Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International Fixed income securities: Government and Federal-sponsored agency obligations . . . . . . . . . . . . Corporate and other debt instruments . . . . . . . . . . . . . . . . . 12.6 — 8.2 — — — 6.8 — 4.7 — — — 12.6 8.2 6.8 4.7 2.7 — — — — — 2.7 — Private equity investments . . . . . . . . . . . . . . . — 1.0 Cash and cash equivalents(1) . . . . . . . . . . . . . . 10.4 — — — — 1.3 — 2.7 — — — — — — 10.4 3.0 — 1.0 — 2.7 3.0 1.3 $34.9 $ 1.3 $— $25.8 $— $ 3.0 $34.9 $30.1 (1) Substantially all of these funds are held in connection with fixed income investment strategies. 107 The following table sets forth the change in fair value for plan assets measured using significant unobservable inputs (level 3): Balance at the beginning of the year . . . . . . . . . . . . . . . . . Actual gain on plan assets: Assets held at end of year . . . . . . . . . . . . . . . . . . . . . . . Assets sold during the year . . . . . . . . . . . . . . . . . . . . . . Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Return on capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 2011 (Dollars in millions) $ 2.3 $ 3.0 — — — — (3.0) 0.7 — 0.4 (0.4) — Balance at the end of the year . . . . . . . . . . . . . . . . . . . . . . . $— $ 3.0 Investments in equity and fixed income securities that are publicly traded are valued at the closing market prices on the last business day of the year. Other equity and fixed income securities are generally valued using other observable inputs to estimate fair value on the last business day of the year. Investments in mutual funds and collective trust funds are primarily based on the closing market price of the assets held in the funds on the last business day of the year. At the beginning of 2012, the target asset allocation and strategy was a 100 percent allocation to a portfolio of investment grade fixed income securities with a weighted average duration approximately equal to the duration of the pension plan’s benefit obligation. During the second quarter of 2012, the pension plan’s investment strategy and target asset allocation for non-cash investments was modified to implement an allocation of 66 percent to equity securities and 34 percent to investment grade fixed income securities. The objective of this strategy is to maximize the long-term return on plan assets at a prudent level of risk in order to ensure adequate funding for the Company’s pension benefit obligations. Following this change in asset allocation, the plan’s expected return on assets for fiscal 2012 increased from 4.25 percent to 6.25 percent. This change resulted in a reduction of defined benefit plan expense of $0.6 million for fiscal 2012. The asset allocations attributable to the defined benefit plan at December 31, 2012 and 2011 and the target allocation of plan assets for 2013, by asset category, are as follows (in percentages): December 31, 2013 Target 2012 2011 Asset category: Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fixed income securities(1) Private equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66% 34% — % 100% 60% 40% — % 38% 52% 10% 100% 100% (1) Includes cash and cash equivalents which are held to manage duration in connection with fixed income investment strategies. 108 The expected benefit payments through 2022 for the defined benefit plan and postretirement benefit plans are as follows: Defined Benefit Plan Postretirement Benefit Plans (Dollars in millions) Year ending December 31: 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2018 through 2022 . . . . . . . . . . . . . . . . . . . . . . $ 2.2 $ 2.2 $ 2.2 $ 2.3 $ 2.3 $11.1 $ 3.9 $ 3.8 $ 3.8 $ 3.6 $ 3.5 $15.2 The measurement date for the Company’s defined benefit plan and postretirement benefit plans is December 31. The following discount rates were used at December 31, 2012 and 2011 to determine benefit obligations for the plans (in percentages): Defined Benefit Plan Postretirement Benefit Plans 2012 2011 2012 2011 Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.65% 4.25% 3.30% 3.90% The health care cost trend assumption used at December 31, 2012 to compute the APBO for the postretirement benefit plans was an increase of 8.50 percent (9.00 percent at December 31, 2011), which is assumed to decline gradually to 5.00 percent in 2020 and to remain at that level thereafter. A one-percentage point change each year in assumed health care cost trend rates would have an impact of less than $0.1 million on the total of service and interest cost components of postretirement benefits expense and APBO as of December 31, 2012 and 2011. Defined Contribution Plans The Company has defined contribution plans which provide retirement benefits for certain of its employees. The Company’s contributions, which are principally based on the Company’s pretax income and the aggregate compensation levels of participating employees and are charged against income as incurred, amounted to $5.9 million, $4.4 million and $1.8 million in 2012, 2011 and 2010, respectively. 14. Accrued Liabilities Accrued liabilities consist of following: Accrued sales discounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2012 2011 (Dollars in millions) $24.9 $36.2 18.1 21.5 10.5 10.9 26.9 22.6 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $91.2 $80.4 109 15. Debt Total debt, including the current portion of long-term debt, consisted of the following: Term loans, bearing interest at variable rates, due 2018, net of original issue discount of $1.7 million and $2.0 million at December 31, 2012 and December 31, 2011, respectively(1) . . . . 7.625 percent senior notes, due 2019 (“Notes”) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: current portion of long-term debt December 31, 2012 2011 (Dollars in millions) $323.4 400.0 $723.4 3.3 $326.4 400.0 $726.4 3.3 Total long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $720.1 $723.1 (1) Borrowed under the Company’s Credit Agreement dated as of July 26, 2011 (“Credit Agreement”). Credit Facilities On July 26, 2011, SunCoke Energy entered into a Credit Agreement which provides for a seven-year term loan in a principal amount of $300.0 million (the “Term Loan”), repayable in equal quarterly installments at a rate of 1.00 percent of the original principal amount per year, with the balance payable on the final maturity date. Additionally, the Credit Agreement provided for up to $75.0 million of Incremental Facilities (“Incremental Facilities”) that are available subject to the satisfaction of certain conditions. On December 15, 2011, SunCoke Energy borrowed an additional $30.0 million Term Loan as part of the Incremental Facilities. As of December 31, 2012 there was $45.0 million of capacity remaining under the Incremental Facilities. SunCoke Energy has $325.1 million outstanding under the Term Loan and Incremental Facilities as of December 31, 2012. The proceeds from the Term Loan and Incremental Facilities were used to repay certain intercompany indebtedness to Sunoco, to pay related fees and expenses and for general corporate purposes. The Credit Agreement also provides for a five-year $150 million revolving facility (the “Revolving Facility”). The proceeds of any loans made under the Revolving Facility can be used to finance capital expenditures, acquisitions, working capital needs and for other general corporate purposes. SunCoke Energy does not have any outstanding borrowings under the Revolving Facility as of December 31, 2012. Borrowings under the Term Loan bear interest, at SunCoke Energy’s option, at either (i) base rate plus an applicable margin or (ii) the greater of 1.00 percent or LIBOR plus an applicable margin. The applicable margin on the Term Loan is (i) in the case of base rate loans, 2.00 percent per annum and (ii) in the case of LIBOR loans, 3.00 percent per annum. Borrowings under the Revolving Facility bear interest, at SunCoke Energy’s option, at either (i) base rate plus an applicable margin or (ii) LIBOR plus an applicable margin. The applicable margin on loans made under the Revolving Facility is determined by reference to a consolidated leverage ratio based pricing grid. The weighted-average interest rate for borrowings outstanding under the Credit Agreement during 2012 was 4.07 percent. The Credit Agreement contains certain covenants, restrictions and events of default including, but not limited to, maintaining a maximum consolidated leverage ratio and a minimum consolidated interest coverage ratio and limitations on the ability of the Company and certain of the Company’s subsidiaries to (i) incur indebtedness, (ii) pay dividends or make other distributions, (iii) prepay, redeem or repurchase certain debt, (iv) make loans and investments, (v) sell assets, (vi) incur liens, (vii) enter into transactions with affiliates and (viii) consolidate or merge. In addition, under certain circumstances, the Term Loan is subject to mandatory principal prepayments. 110 The obligations under the Credit Agreement are guaranteed by certain of the Company’s subsidiaries and secured by liens on substantially all of the Company’s and the guarantors’ assets pursuant to a Guarantee and Collateral Agreement, dated as of July 26, 2011, among the Company, the subsidiaries of the Company party thereto and JPMorgan Chase Bank, N.A, as administrative agent. Senior Notes On July 26, 2011, SunCoke Energy issued $400 million aggregate principal of senior notes (the “Notes”) in a private placement. The Notes bear interest at a rate of 7.625 percent per annum and will mature in 2019 with all principal paid at maturity. Interest on the Notes is payable semi-annually in cash in arrears on August 1 and February 1 of each year, commencing on February 1, 2012. The proceeds from the Notes were used to repay certain intercompany indebtedness to Sunoco, to pay related fees and expenses and for general corporate purposes. The Notes were offered in the United States to qualified institutional buyers in reliance on Rule 144A under the Securities Act, and outside the United States to non-U.S. persons in reliance on Regulation S under the Securities Act. On January 25, 2012, we completed an exchange offer for the Notes for an equal principal amount of the Notes whose sale is registered under the Securities Act. The Notes are the Company’s senior unsecured obligations and are guaranteed on a senior unsecured basis by each of the Company’s existing and future subsidiaries that guarantees the Company’s credit facilities (collectively, the “Notes Guarantors”). The Notes rank equally in right of payment to all of the Company’s existing and future unsecured unsubordinated debt and senior in right of payment to all of the Company’s existing and future debt that is by its terms expressly subordinated in right of payment to the Notes. The Notes are subordinated to indebtedness under the Credit Agreement as well as any future secured debt to the extent of the value of the assets securing such debt. The Company may redeem some or all of the Notes prior to August 1, 2014 by paying a “make-whole” premium. The Company also may redeem some or all of the Notes on or after August 1, 2014 at specified redemption prices. In addition, prior to August 1, 2014, the Company may redeem up to 35 percent of the Notes using the proceeds of certain equity offerings. The Company is obligated to offer to purchase the Notes at a price of (a) 101 percent of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase, upon the occurrence of certain change of control events and (b) 100 percent of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase, with the proceeds from certain asset dispositions. These restrictions and prohibitions are subject to certain qualifications and exceptions set forth in the Indenture, including without limitation, reinvestment rights with respect to the proceeds of asset dispositions. The Indenture contains covenants that, among other things, limit the Company’s ability and the ability of certain of the Company’s subsidiaries to (i) incur indebtedness, (ii) pay dividends or make other distributions, (iii) prepay, redeem or repurchase certain debt, (iv) make loans and investments, (v) sell assets, (vi) incur liens, (vii) enter into transactions with affiliates and (viii) consolidate or merge. These covenants are subject to a number of exceptions and qualifications set forth in the Indenture. Upon issuance, the Company recorded the Notes and the Term Loan on the consolidated balance sheet of $727.9 million, which is net of a debt discount of $2.1 million. In addition, the Company recorded $19.1 million of deferred financing fees related to the issuance of the Notes and Credit Facilities. Debt maturities for each of the next five years is $3.3 million. Interest Rate Swaps On August 15, 2011, the Company entered into interest rate swap agreements with an aggregate notional amount of $125.0 million. See Note 23 for further information on the interest rate swaps. 111 16. Black Lung Benefit Obligations The Company is responsible for making pneumoconiosis (“black lung”) benefit payments to certain of its employees and former employees and their dependents. Such payments are for claims under Title IV of the Federal Coal Mine Health and Safety Act of 1969 and subsequent amendments, as well as for black lung benefits provided in the states of Virginia, Kentucky and West Virginia pursuant to workers’ compensation legislation. The Company acts as a self-insurer for both state and federal black lung benefits and adjusts the Company’s accrual each year based upon actuarial calculations of the Company’s expected future payments for these benefits. For the years ended December 31, 2012, 2011 and 2010, the discount rate used to calculate the period end liability was 3.80, 4.50 and 5.00 percent, respectively. The estimated liability was $34.8 million and $33.5 million at December 31, 2012 and 2011, respectively. Charges against income for black lung benefits amounted to $3.3 million, $8.7 million and $4.8 million during 2012, 2011 and 2010, respectively. The Patient Protection and Affordable Care Act (“PPACA”), which was implemented in 2010, amended previous legislation related to coal workers’ black lung obligations. PPACA provides for the automatic extension of awarded lifetime benefits to surviving spouses and changes the legal criteria used to assess and award claims. Our obligation related to black lung benefits is estimated based on various assumptions, including actuarial estimates, discount rates, and changes in health care costs. The impact of PPACA in 2011, changes in discount rates and other assumptions, increased our black lung benefit obligation by approximately $1.8 million and $6.0 million during 2012 and 2011, respectively. 17. Commitments and Contingent Liabilities The Company, as lessee, has noncancelable operating leases for land, office space, equipment and railcars. Total rental expense, net of sublease income, was $4.8 million, $5.8 million and $4.6 million in 2012, 2011 and 2010, respectively. Sublease income is generated from our former corporate headquarters located in Knoxville, Tennessee. Beginning in the second quarter of 2011, concurrent with our move to Lisle, Illinois, this space was subleased to another tenant for the remainder of the lease term, although we remain directly liable to the landlord under the original lease. The aggregate amount of future minimum annual rentals applicable to noncancelable operating leases and related subleases is as follows: Minimum Rental Payments Sublease Income Net Lease Expense (Dollars in millions) Year ending December 31: 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2018-Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3.6 3.6 3.2 2.2 1.0 3.7 $17.3 $ 0.6 0.7 0.7 0.7 0.3 — $ 3.0 $ 3.0 2.9 2.5 1.5 0.7 3.7 $14.3 As discussed in Note 1, the Company has an agreement with Lakeshore which provides coal handling services. The fixed and determinable amounts of the Company’s obligation under this agreement are as follows (dollars in millions): Year ending December 31: 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Amount representing interest $ 2.3 (0.1) Total at present value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2.2 112 Payments under this agreement, including variable components, totaled $14.1, $11.2 and $10.0 million in 2012, 2011 and 2010, respectively. The Company is subject to indemnity agreements with current and former third-party investors of Indiana Harbor and Jewell related to certain tax benefits that they earned as limited partners. Based on the partnership’s statute of limitations, as well as published filings of the limited partners, the Company believes that tax audits for years 2006 and 2007, relating to tax credits of approximately $51 million, may be still open for the limited partners and subject to examination. As of December 31, 2012, the Company has not been notified by the limited partners that any items subject to the indemnification are under examination and further believes that the potential for any claims under the indemnity agreements are remote. Sunoco also guarantees SunCoke Energy’s performance under the indemnification to the current third party investor of Indiana Harbor and the former investor at Jewell. On September 30, 2011, concurrent with SunCoke Energy’s purchase of the 19 percent ownership interest from one of the Indiana Harbor limited partners, Sunoco was released of its guarantee to the former Indiana Harbor partner of SunCoke Energy’s performance under this indemnification. SunCoke Energy has assumed this guarantee. The EPA has issued Notices of Violations (“NOVs”) for our Haverhill and Granite City cokemaking facilities which stem from alleged violations of our air emission operating permits for these facilities. We are currently working in a cooperative manner with the EPA, Ohio Environmental Protection Agency and the Illinois Environmental Protection Agency to address the allegations. Settlement may require payment of a penalty for alleged past violations as well as undertaking capital projects to improve reliability of the energy recovery systems and enhance environmental performance at the Haverhill and Granite City facilities. As a result of discussions with the EPA, we spent approximately $5 million related to these projects in 2012 and expect to spend approximately $15 million in 2013 and an additional $80 million in the 2014 to 2016 timeframe. We are currently engaged in penalty negotiations with regulators and estimate our probable loss to be approximately $2.2 million. The Company has received two NOVs from the EPA related to our Indiana Harbor cokemaking facility. After initial discussions with the EPA and the Indiana Department of Environmental Management (“IDEM”), resolution of the NOVs was postponed by mutual agreement because of ongoing discussions regarding the NOVs at the Haverhill and Granite City cokemaking facilities. In January 2012, the Company began working in a cooperative manner to address the allegations with the EPA, the IDEM and Cokenergy, Inc., an independent power producer that owns and operates an energy facility, including heat recovery equipment, a flue gas desulfurization system and a power generation plant, that processes hot flue gas from our Indiana Harbor facility to produce steam and electricity and to reduce the sulfur and particulate content of such flue gas. Settlement may require payment of a penalty for alleged past violations as well as undertaking capital projects to enhance reliability and environmental performance. In addition, we conducted an engineering study to identify major maintenance projects necessary to preserve the production capacity of the facility. In accordance with the findings of the study, we originally estimated that we would spend approximately $50 million. Based on discussions with our customer regarding their requirements for the potential contract renewal term, we now estimate that we could spend as much as $85 million. We spent $14 million related to this project in 2012 and anticipate spending $60 million in 2013. While we believe there is a reasonable likelihood that we will reach agreement with our customer for a new long-term contract, such an agreement may not be reached. We expect to earn a reasonable return on our investment, and consequently the actual level of capital expenditures may depend upon the terms of an eventual agreement with our customer and DTE Energy Company, the third party investor owning a 15 percent interest in the partnership (the “Indiana Harbor Partnership”) that owns the Indiana Harbor cokemaking facility. In addition, we believe the project scope will address items that may be required in connection with the settlement of the NOVs at our Indiana Harbor facility. At this time, the Company cannot yet assess any future injunctive relief or potential monetary penalty and any potential future citations. The Company is unable to estimate a range of probable or reasonably possible loss. On February 9, 2010, the Ohio Department of Environmental Protection (“ODEP”) issued a New Source Review permit-to-install (“NSR PTI”) for the Middletown cokemaking facility. During the 30-day statutory 113 appeal period ending March 11, 2010, four parties, including the City of Monroe, Ohio, Robert D. Snook, a pro se litigant, the National Resources Defense Council, and individuals affiliated with the SunCoke Watch opposition group, filed appeals at the Ohio Environmental Review Appeals Commission (“ERAC”), challenging ODEP’s issuance of the NSR PTI. In May 2012, we entered into a settlement agreement with the parties. The settlement agreement was approved by the ERAC in July 2012. The terms of the settlement were not material to the financial position, results of operations or cash flows of the Company at December 31, 2012. The Southwest Ohio Air Quality Agency (SWOAQA) also issued an NOV to our Middletown facility on November 19, 2012. We responded to the NOV by providing a carbon injection plan requested by SWOAQA. At present, the Company cannot assess whether there will be a monetary penalty or any future citations, but we do not expect such a penalty or citations to be material to the financial position, results of operations or cash flows of the Company at December 31, 2012. Other legal and administrative proceedings are pending or may be brought against the Company arising out of its current and past operations, including matters related to commercial and tax disputes, product liability, antitrust, employment claims, premises-liability claims, allegations of exposures of third parties to toxic substances and general environmental claims. Although the ultimate outcome of these claims cannot be ascertained at this time, it is reasonably possible that some portion of these claims could be resolved unfavorably to the Company. Management of the Company believes that any liability which may arise from such matters would not be material in relation to the financial position, results of operations or cash flows of the Company at December 31, 2012. 18. Restructuring In 2010, in connection with the Separation, the Company announced the relocation of its corporate headquarters from Knoxville, Tennessee to Lisle, Illinois, which was completed during the second quarter of 2011 and resulted in a termination of employees eligible for severance benefits upon such termination. The Company recorded restructuring charges of $0.6 million, $8.0 million and $0.4 million in 2012, 2011 and 2010, respectively. These charges consist of employee-related costs, primarily related to relocation, and lease terminations and asset write-offs. The following table presents aggregate restructuring charges related to the relocation: Employee- Related Costs Asset Write-offs Lease Terminations Year ended December 31, 2010 . . . . . . . . . . . . . . . . . Year ended December 31, 2011 . . . . . . . . . . . . . . . . . Year ended December 31, 2012 . . . . . . . . . . . . . . . . . Charges recorded through December 31, 2012 . . . . . . $0.1 5.4 0.5 $6.0 (Dollars in millions) $ 0.3 0.6 — $— 2.0 0.1 $ 0.9 $ 2.1 Total $0.4 8.0 0.6 $9.0 As of December 31, 2012, we do not believe any additional costs related to this restructuring would be material to our financial position in future periods. Employee-related costs and lease terminations are included in selling, general and administrative expenses. Asset write-offs are included in depreciation expense. 114 The following table presents accrued restructuring and related activity as of and for the years ended December 31, 2012 and 2011 related to the relocation: Employee- Related Costs Lease Terminations (Dollars in millions) Balance at December 31, 2010 . . . . . . . . . . . . . . . . . . . . Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at December 31, 2011 . . . . . . . . . . . . . . . . . . . . Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.1 5.4 (4.7) $ 0.8 0.5 (0.7) $— 2.0 (0.3) $ 1.7 0.1 (0.4) Total $ 0.1 7.4 (5.0) $ 2.5 0.6 (1.1) Balance at December 31, 2012 . . . . . . . . . . . . . . . . $ 0.6 $ 1.4 $ 2.0 19. Accumulated Other Comprehensive Loss The following table sets forth the components of accumulated other comprehensive loss (net of related income taxes) at December 31, 2012 and 2011, respectively: Retirement benefits plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign currency translation adjustment December 31, 2012 2011 (Dollars in millions) $(6.3) $(6.6) (0.2) (1.3) $(7.9) $(6.5) 20. Share-Based Compensation Effective July 13, 2011, SunCoke Energy’s Board of Directors approved the SunCoke Energy, Inc. Long- Term Performance Enhancement Plan (“SunCoke LTPEP”). The SunCoke LTPEP provides for the grant of equity-based rewards including stock options and share units, or restricted stock, to the Company’s directors, officers, and other employees, advisors, and consultants who are selected by the plan committee for participation in the SunCoke LTPEP. The plan authorizes the issuance of (i) 1,600,000 shares of SunCoke Energy common stock issuable upon the adjustment of Sunoco equity awards in connection with the Distribution and (ii) up to 6,000,000 shares of SunCoke Energy common stock pursuant to new awards under the SunCoke LTPEP. The Company measures the cost of employee services in exchange for an award of equity instruments based on the grant-date fair value of the award. The total cost is reduced for estimated forfeitures over the awards’ vesting period and the cost is recognized over the requisite service period. Forfeiture estimates are reviewed on an annual basis at a minimum, or as deemed necessary based on actual forfeitures. Compensation expense is recorded ratably over the service period. Stock Options During the year ended December 31, 2011, the Company granted stock options to certain employees to acquire 1,533,312 shares of common stock. The stock options have a ten-year term and a $17.25 per share weighted average exercise price, which was equal to the average of the high and low prices of SunCoke Energy common stock on the dates of grant. A total of 1,348,608 stock options will vest in three equal annual installments on the first, second and third anniversaries of the dates of grant (in each case subject to continued employment through the applicable vesting date). The Company issued 184,704 stock options that will vest in three equal annual installments beginning September 1, 2013. All awards vest immediately upon a change in control as defined by the SunCoke LTPEP. 115 During the year ended December 31, 2012, the Company granted stock options to certain employees to acquire 486,182 shares of common stock. The stock options have a ten-year term and a $14.29 per share weighted average exercise price, which was equal to the average of the high and low prices of SunCoke Energy common stock on the dates of grant. The stock options become exercisable in three equal annual installments beginning one year from the date of grant. All awards vest immediately upon a change in control as defined by the SunCoke LTPEP. The Company calculates the value of each employee stock option, estimated on the date of grant, using the Black-Scholes option pricing model. The weighted-average fair value of employee stock options granted during the years ended December 31, 2012 and 2011 was $5.70 and $6.93, respectively, using the following weighted- average assumptions: Risk Free Interest Rate . . . . . . . . . . . . . . . . . . . . . . . . . . Expected Term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dividend Yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted-Average Exercise Price . . . . . . . . . . . . . . . . . Years Ended December 31, 2012 2011 0.82% 1.54% 5 years 5 years 45% — % 44% — % $ 14.29 $ 17.25 The Company uses the average implied volatility of the Dow Jones U.S. Steel index coupled with the implied volatility of the S&P 600. Since the Company does not have a direct peer group and only has a limited trading history it believes this approach provides a reasonable implied volatility. The risk-free interest rate assumption is based on the U.S. Treasury yield curve at the date of grant for periods which approximates the expected life of the option. The dividend yield assumption is based on the Company’s future expectation of dividend payouts. The expected life of employee options represents the average contractual term adjusted by the average vesting period of each option tranche. The Company estimated a zero forfeiture rate in calculating fair value. This estimated forfeiture rate may be revised in subsequent periods if the actual forfeiture rate differs significantly. The following table summarizes information with respect to common stock option awards discussed above: Outstanding at December 31, 2011 . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Outstanding at December 31, 2012 . . . . . . . . . . Exercisable at December 31, 2012 . . . . . . . . . . Expected to vest at December 31, 2012 . . . . . . Number of Options 1,454,019 486,182 — (57,337) 1,882,864 404,317 1,882,864 Weighted Average Exercise Price Aggregate Intrinsic Value $17.25 $14.29 $17.20 $16.49 $17.25 $16.49 $ 0.6 $— $ 0.6 Intrinsic value for stock options is defined as the difference between the current market value of our common stock and the exercise price of the stock options. The Company recognized $3.8 million, $2.3 million net of tax, and $1.4 million, $0.9 million net of tax, in compensation expense during the year ended December 31, 2012 and 2011, respectively, related to the above stock options. As of December 31, 2012, there was $7.2 million of total unrecognized compensation cost related to nonvested stock options. This compensation cost is expected to be recognized over the next 1.9 years. The weighted average remaining contractual term is 8.7 years. 116 Restricted Stock Units During the year ended December 31, 2011, the Company issued a total of 288,898 restricted stock units (“RSU”) to certain employees for shares of the Company’s common stock. A total of 146,545 RSUs vest as follows: (1) 50 percent of each RSU award generally will vest in three equal annual installments, on the first, second and third anniversaries of the date of grant and (2) the remaining 50 percent of each RSU award will vest on the fourth anniversary of the date of grant (in each case subject to continued employment through the applicable vesting date). The Company issued 112,941 RSUs that will vest in three equal annual installments beginning on September 1, 2013. The Company also issued 29,412 RSUs that vest one year from the date of grant. All awards vest immediately upon a change in control as defined by the SunCoke LTPEP. During the year ended December 31, 2012, the Company issued a total of 83,082 restricted stock units (“RSU”) to certain employees for shares of the Company’s common stock. The RSUs vest in four annual installments beginning one year from the date of grant. All awards vest immediately upon a change in control as defined by the SunCoke LTPEP. The following table summarizes information with respect to RSUs: Nonvested at December 31, 2011 . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Number of RSUs 275,356 83,082 (50,219) (9,519) Nonvested at December 31, 2012 . . . . . . . . . . . . . . . . 298,700 Weighted Average Grant- Date Fair Value $17.19 $14.29 $17.16 $17.34 $16.38 The Company recognized $1.5 million, $0.9 million net of tax, and $0.7 million, $0.4 million net of tax, in compensation expense during the years ended December 31, 2012 and 2011, respectively, related to the above RSUs. As of December 31, 2012, there was $3.6 million of total unrecognized compensation cost related to nonvested RSUs. This compensation cost is expected to be recognized over the next 2.8 years. Modifications In connection with the Distribution, certain Sunoco common stock awards and stock options that were held by Sunoco employees, Sunoco directors and SunCoke Energy employees were modified and an anti-dilutive provision was added. In general, all Sunoco stock options held by Sunoco employees and Sunoco directors were converted into both Sunoco and SunCoke Energy stock options. Sunoco stock options held by SunCoke Energy employees were converted to SunCoke Energy stock options. All SunCoke Energy common stock issued as a result of option exercises or the vesting of common stock awards will be issued under the SunCoke LTPEP. At the Distribution Date, 1,219,842 SunCoke Energy stock options were issued in connection with the conversion of the outstanding Sunoco stock options to Sunoco employees and directors. The converted stock options for Sunoco employees and directors are fully vested and exercisable and any expense associated with the modification of these stock options was recognized by Sunoco. The exercise prices for these stock options range from $4.77 to $29.35 per share. The stock options expire 10 years from the date of the original grant and have a weighted average remaining life of 4.4 years. During the year ended December 31, 2012, 463,699 options were exercised and 14,481 options were cancelled in accordance with the terms of the Sunoco share-based compensation plan. At the Distribution Date, 295,854 SunCoke Energy stock options were issued in connection with the conversion of the outstanding Sunoco stock options for SunCoke Energy employees, of which 257,332 are fully vested and exercisable. The exercise prices for these stock options range from $8.93 to $22.31 per share. The 117 stock options expire 10 years from the date of the original grant and have a weighted average remaining contractual term of 5.7 years and an aggregate intrinsic value of $0.9 million. During the year ended December 31, 2012, 13,577 options were exercised with an intrinsic value of $0.1 million. In the first quarter of 2012, SunCoke Energy recorded a $0.5 million charge in connection with the award modification and the addition of an anti-dilution provision. The remaining 24,945 options continue to vest over a weighted average period of less than one year. SunCoke Energy recorded $0.7 million, $0.4 million net of tax, in compensation expense related to these awards during the year ended December 31, 2012. As of December 31, 2012, there was an insignificant amount of unrecognized compensation cost related to these nonvested stock options. Outstanding Sunoco common stock units held by SunCoke Energy employees were converted into 95,984 SunCoke Energy restricted stock units at the Distribution Date, 38,709 of which vested during 2012. The remaining 57,275 restricted stock units continue to vest over a weighted average period of less than one year. Compensation expense related to these awards was calculated based on the grant-date fair value of the original award and the addition of an anti-dilutive provision. SunCoke Energy recorded $0.5 million, $0.3 million net of tax, in compensation expense related to these awards during the year ended December 31, 2012, respectively. Outstanding Sunoco common stock units held by Sunoco employees were not converted into SunCoke Energy awards. As of December 31, 2012, there was $0.1 million of total unrecognized compensation cost related to these nonvested RSUs. 21. Earnings per Share The weighted average number of common shares for the 2011 and 2010 periods includes 70.0 million shares of common stock owned by Sunoco on the Separation Date as a result of its contribution of the assets of its cokemaking and coal mining operations to SunCoke Energy and related capitalization. The following table sets forth the reconciliation of the weighted-average number of common shares used to compute basic earnings per share (“EPS”) to those used to compute diluted EPS: Years Ended December 31, 2012 2011 2010 Weighted-average number of common shares outstanding-basic . . . . . . . . Add: effect of dilutive share-based compensation awards . . . . . . . . . . . . . . (Shares in millions) 70.0 — 70.0 — 70.0 0.3 Weighted-average number of shares-diluted . . . . . . . . . . . . . . . . . . . . . . . . 70.3 70.0 70.0 For the year ended December 31, 2012 and 2011, diluted earnings per share is calculated to give effect to share-based compensation awards granted using the treasury stock method. In 2012, the potential dilutive effect of 2.5 million stock options and 0.1 million restricted stock units was excluded from the computation of diluted weighted-average shares outstanding, as the shares would have been anti-dilutive. In 2011, the potential dilutive effect of 0.7 million stock options and 0.1 million restricted stock units was excluded from the computation of diluted earnings per share as the shares would have been anti-dilutive. 22. Supplemental Cash Flow Information Net cash provided by operating activities reflected cash payments for interest and income taxes as follows: Years Ended December 31, 2012 2011 2010 Interest paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income taxes paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118 (Dollars in millions) $2.8 $7.3 $ — $32.4 $44.0 $ 6.3 23. Fair Value Measurements The Company measures certain financial and non-financial assets and liabilities at fair value on a recurring basis. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants on the measurement date. Fair value disclosures are reflected in a three-level hierarchy, maximizing the use of observable inputs and minimizing the use of unobservable inputs. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability on the measurement date. The three levels are defined as follows: • • • Level 1—inputs to the valuation methodology are quoted prices (unadjusted) for an identical asset or liability in an active market. Level 2—inputs to the valuation methodology include quoted prices for a similar asset or liability in an active market or model-derived valuations in which all significant inputs are observable for substantially the full term of the asset or liability. Level 3—inputs to the valuation methodology are unobservable and significant to the fair value measurement of the asset or liability. Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are measured at fair value on a recurring basis. The Company’s cash equivalents, which amounted to $180.0 million at December 31, 2012 were measured at fair value based on quoted prices in active markets for identical assets. These inputs are classified as Level 1 within the valuation hierarchy. There were no cash equivalents at December 31, 2011. Foreign Currency Hedge From time to time, the Company utilizes foreign exchange derivatives to manage the risks associated with fluctuations in foreign currency exchange rates and accounts for them under ASC 815—Derivatives and Hedging, which requires all derivatives to be marked to market (fair value). The Company does not purchase or hold any derivatives for trading purposes. On November 26, 2012, the Company entered into agreements to purchase approximately 1.845 billion Indian Rupees at a weighted average rate of 56.075 with a settlement date of January 31, 2013. The Company did not elect hedge accounting treatment for this foreign exchange contract and, therefore, the changes in the fair value of the derivative are recorded in other income, net on the consolidated statement of income. The fair value of the foreign exchange contract at December 31, 2012 was an asset of approximately $0.6 million. There were no foreign exchange contracts outstanding at December 31, 2011. The mark to market impact of the foreign exchange contract on other income, net was an increase of approximately $0.6 million. In estimating the fair market value of the foreign exchange contract, the Company utilized published exchange rates at December 31, 2012 between the U.S. dollar and Indian rupee. Interest Rate Swap The Company utilizes interest rate swaps to manage the risk associated with changing interest rates and accounts for them under ASC 815—Derivatives and Hedging, which requires all derivatives to be marked to market (fair value). The Company does not purchase or hold any derivatives for trading purposes. On August 15, 2011, the Company entered into interest rate swap agreements with an aggregate notional amount of $125.0 million. These agreements expire three years from the forward effective date of October 11, 2011. Under the interest rate swap agreements, the Company will pay a weighted average fixed rate of 1.322 percent in exchange for receiving floating rate payments based on the greater of 1.0 percent or three-month LIBOR. The Company 119 did not elect hedge accounting treatment for these interest rate swaps and, therefore, the changes in the fair value of the interest rate swap agreements are recorded in interest expense. The counterparties of the interest rate swap agreements are large financial institutions which the Company believes are of high quality creditworthiness. While the Company may be exposed to potential losses due to the credit risk of nonperformance by these counterparties, such losses are not anticipated. The fair value of the swap agreement at December 31, 2012 and 2011 was a liability of approximately $0.8 million and $0.5 million, respectively. The mark to market impact of the swap arrangement on interest expense was an increase of approximately $0.2 million and $0.5 million in the years ended December 31, 2012 and 2011, respectively. In estimating the fair market value of interest rate swaps, the Company utilized a present value technique which discounts future cash flows against the underlying floating rate benchmark. Derivative valuations incorporate credit risk adjustments that are necessary to reflect the probability of default by the counterparty. These inputs are not observable in the market and are classified as Level 3 within the valuation hierarchy. Non-Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis Contingent consideration related to the HKCC acquisition (Note 4) is measured at fair value and amounted to $4.8 million and $9.0 million at December 31, 2012 and 2011, respectively. The estimated fair value is based on significant inputs that are not observable in the market, or Level 3 within the valuation hierarchy. Key assumptions at December 31, 2011 included (a) a risk-adjusted discount rate range of 2.400 percent to 8.665 percent, which reflects a credit spread adjustment for each period, and (b) production levels of HKCC operations between 300 thousand and 475 thousand tons per year. Key assumptions at December 31, 2012 include (a) a risk-adjusted discount rate range of 1.915 percent to 8.066 percent, which reflects a credit spread adjustment for each period, and (b) production levels of HKCC operations between 91 thousand and 318 thousand tons per year. The fair value adjustments to contingent consideration decreased cost of products sold by $4.2 million and $1.9 million in the years ended December 31, 2012 and 2011, respectively. Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). At December 31, 2012, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities. Certain Financial Assets and Liabilities not Measured at Fair Value At December 31, 2012, the estimated fair value of the Company’s long-term debt was estimated to be $741.5 million, compared to a carrying amount of $723.4 million, net of mandatory pre-payments made since issuance. The fair value was estimated by management based upon estimates of debt pricing provided by financial institutions and are considered Level 3 inputs. At December 31, 2011, the estimated fair value of the Company’s long-term debt was estimated to be $722.0 million, compared to a carrying amount of $726.4 million net of mandatory pre-payments made since issuance. The fair value was estimated by management based upon estimates of debt pricing provided by financial institutions and are considered Level 3 inputs. 24. Business Segment Information The Company is an independent owner and operator of five cokemaking facilities in the eastern and midwestern regions of the United States and operator of a cokemaking facility for a project company in Brazil in which it has a preferred stock investment. In addition to its cokemaking operations, the Company has 120 metallurgical coal mining operations in the eastern United States. The Company’s cokemaking operations are reported as three segments: Jewell Coke, Other Domestic Coke and International Coke. See Note 7 for further information regarding customer concentration. The Jewell Coke segment consists of the operations of the Company’s cokemaking facilities in Vansant, VA. The Indiana Harbor cokemaking facility located in East Chicago, IN, the Haverhill cokemaking facility, located in Franklin Furnace, OH, the Granite City cokemaking facility, located in Granite City, IL, and the Middletown cokemaking facility, located in Middletown, OH are individual operating segments that have been aggregated into the Other Domestic Coke segment. Each of these facilities produces coke and recovers waste heat which is converted to steam or electricity through a similar production process. The coke production for these facilities is sold directly to integrated steel producers under contracts which provide for the pass-through of coal costs subject to contractual coal-to-coke yields plus an operating cost component and fixed fee component received for each ton of coke sold. Accordingly, the Company’s management believes that the facilities in the Other Domestic Coke segment have similar long-term economic characteristics. The Middletown cokemaking facility commenced operations in October 2011 and beginning in the fourth quarter of 2011 is included in the Other Domestic Coke segment results. Prior to the commencement of operations, all costs associated with Middletown were included in Corporate and Other. The International Coke segment operates a cokemaking facility located in Vitória, Brazil for a project company. The International Coke segment also earns income from a dividend on its preferred stock investment assuming that certain minimum production levels are achieved at the plant. The Company’s Coal Mining segment conducts coal mining operations near the Company’s Jewell cokemaking facility, centered in Vansant, VA with mines located in Virginia and West Virginia. Currently, a substantial portion of the coal production is sold to the Jewell Coke segment for conversion into coke. Beginning in 2012, intersegment coal revenues for sales to Jewell Coke are reflective of the contract price that Jewell Coke charges its customer. Prior year periods have been adjusted to reflect this change. Some coal is also sold to the Other Domestic Coke facilities and third-parties. Intersegment coal revenues for sales to the Jewell Coke and Other Domestic Coke segments are based on the prices that the coke customers of the Other Domestic Coke segment have agreed to pay for the internally produced coal, which approximate the market prices for this quality of metallurgical coal. In January 2011, the Company acquired the HKCC Companies (Note 4), and the results of operations from the date of acquisition forward are included in the Coal Mining segment. Overhead expenses that can be identified with a segment have been included in determining segment results. The remainder is included in Corporate and Other. Total financing (expense) income, net, which consists principally of interest income, interest expense and interest capitalized, is also excluded from segment results. Identifiable assets are those assets that are utilized within a specific segment. The following table includes Adjusted EBITDA, which is the measure of segment profit or loss reported to the chief operating decision maker for purposes of allocating resources to the segments and assessing their performance: Sales and other operating revenue . . . . . . . . . . Intersegment sales . . . . . . . . . . . . . . . . . . . . . . Adjusted EBITDA (unaudited) . . . . . . . . . . . . Depreciation, depletion and amortization . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2012 (Dollars in millions) International Coke Coal Mining Corporate and Other Combined $36.9 $ — $11.9 $ 0.3 $ 1.5 $60.6 $ 48.3 $203.4 $ 33.4 $ 17.6 $ 34.3 $196.9 $ — $ — $ (29.0) 2.2 $ 2.5 $ $257.2 $1,902.0 $ — $ 265.7 80.8 $ 80.6 $ $2,011.0 Jewell Coke Other Domestic Coke $1,530.4 $286.4 $ — $ — $ 198.9 $ 50.5 55.3 $ 5.4 $ 37.4 $ 4.9 $ $1,413.9 $ 82.4 121 Year Ended December 31, 2011 (Dollars in millions) Jewell Coke Other Domestic Coke International Coke Coal Mining Corporate and Other Combined Sales and other operating revenue . . . . . . . . . . Intersegment sales . . . . . . . . . . . . . . . . . . . . . . Adjusted EBITDA (unaudited) . . . . . . . . . . . . Depreciation, depletion and amortization . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . $1,187.5 $257.6 $ — $ — 87.7 $ 46.1 $ $ 4.9 $ 38.7 $ 197.0(1) 1.2 $ $1,440.8 $ 81.6 $38.0 $ — $13.7 $ 0.2 $ 0.6 $62.7 $ 44.5 $183.6 $ 35.5 $ 12.9 $ 30.7 $182.1 $ — $ — $ (44.2) 1.7 $ 8.6 $ $174.6 $1,527.6 $ — $ 138.8 $ 58.4 $ 238.1 $1,941.8 (1) Includes $169.4 million attributable to the Middletown facility. Sales and other operating revenue . . . . . . . . . . Intersegment sales . . . . . . . . . . . . . . . . . . . . . . . Adjusted EBITDA (unaudited) . . . . . . . . . . . . . Depreciation, depletion and amortization . . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2010 (Dollars in millions) Jewell Coke $298.0 $ 5.8 $123.9 $ 4.4 1.8 $ $ 80.9 Other Domestic Coke $979.5 $ — $ 85.6 $ 35.0 $ 23.0 $962.6 International Coke Coal Mining Corporate and Other Combined $38.4 $ — $15.0 $ 0.1 $ 0.8 $59.7 0.6 $ $159.9 $ 24.0 $ 7.7 $ 18.4 $ 76.7 $1,316.5 $ — $ — $ — $ 234.4 $ (14.1) $ 48.2 $ 1.0 $171.6(1) $ 215.6 $538.5(2) $1,718.4 (1) (2) Includes $169.7 million attributable to the Middletown facility. Includes receivables from affiliate totaling $289.0 million and Middletown facility construction-in-progress totaling $242.2 million. The Company evaluates the performance of its segments based on segment Adjusted EBITDA, which is defined as earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) adjusted for sales discounts and the interest, taxes, depreciation, depletion and amortization attributable to equity earnings in our unconsolidated affiliates. EBITDA reflects sales discounts included as a reduction in sales and other operating revenue. The sales discounts represent the sharing with customers of a portion of nonconventional fuels tax credits, which reduce our income tax expense. However, we believe our Adjusted EBITDA would be inappropriately penalized if these discounts were treated as a reduction of EBITDA since they represent sharing of a tax benefit that is not included in EBITDA. Accordingly, in computing Adjusted EBITDA, we have added back these sales discounts. Our Adjusted EBITDA also includes EBITDA attributable to our unconsolidated affiliates. EBITDA and Adjusted EBITDA do not represent and should not be considered alternatives to net income or operating income under GAAP and may not be comparable to other similarly titled measures in other businesses. Management believes Adjusted EBITDA is an important measure of the operating performance of the Company’s net assets. Adjusted EBITDA does not represent and should not be considered as an alternative to net income as determined by GAAP, and calculations thereof may not be comparable to those reported by other companies. We believe Adjusted EBITDA is an important measure of operating performance and provides useful information to investors because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures and because it eliminates items that have less bearing on our operating performance. Adjusted EBITDA is a measure of operating performance that is not defined by GAAP and should not be considered a substitute for net income as determined in accordance with GAAP. Set forth below is additional detail as to how we use Adjusted EBITDA as a measure of operating performance, as well as a discussion of the limitations of Adjusted EBITDA as an analytical tool. 122 Operating Performance. Our management uses Adjusted EBITDA in a number of ways to assess our combined financial and operating performance, and we believe this measure is helpful to management in identifying trends in our performance. Adjusted EBITDA helps management identify controllable expenses and make decisions designed to help us meet our current financial goals and optimize our financial performance while neutralizing the impact of capital structure on financial results. Accordingly, we believe this metric measures our financial performance based on operational factors that management can impact in the short-term, namely our cost structure and expenses. Limitations. Other companies may calculate Adjusted EBITDA differently then we do, limiting its usefulness as a comparative measure. Adjusted EBITDA also has limitations as an analytical tool and should not be considered in isolation or as a substitute for an analysis of our results as reported under GAAP. Some of these limitations include that Adjusted EBITDA: • • • • • • does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments; does not reflect changes in, or cash requirement for, working capital needs; does not reflect our interest expense, or the cash requirements necessary to service interest on or principal payments of our debt; does not reflect certain other non-cash income and expenses; excludes income taxes that may represent a reduction in available cash; and includes net income (loss) attributable to noncontrolling interests. Below is a reconciliation of Adjusted EBITDA (unaudited) to net income, which is its most directly comparable financial measure calculated and presented in accordance with GAAP: Years Ended December 31, 2012 2011 2010 Adjusted EBITDA attributable to SunCoke Energy, Inc . . . . . . . . . . . . . . . . . . . . . . . . Subtract: Adjusted EBITDA attributable to noncontrolling interest . . . . . . . . . . . . . . . (Dollars in millions) $142.8 4.0 $262.7 (3.0) $230.1 (4.3) Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $265.7 $138.8 $234.4 Subtract: Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financing expense (income), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales discount provided to customers due to sharing of nonconventional fuels 80.8 47.8 23.4 58.4 1.4 7.2 48.2 (19.0) 46.9 tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.2 12.9 12.0 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $102.5 $ 58.9 $146.3 The following table sets forth the Company’s total sales and other operating revenue by product or service: Years Ended December 31, 2012 2011 2010 Coke sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Steam and electricity sales . . . . . . . . . . . . . . . . . . . . . . . Operating and licensing fees . . . . . . . . . . . . . . . . . . . . . . Metallurgical coal sales . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,750.5 62.5 36.9 47.9 4.2 (Dollars in millions) $1,397.7 47.7 38.0 44.2 — $1,237.2 40.4 38.4 0.2 0.3 $1,902.0 $1,527.6 $1,316.5 123 25. Selected Quarterly Data (unaudited) 2012 2011 First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter Second Quarter Third Quarter Fourth Quarter $480.6 $ 53.9 $ 16.6 $460.7 $ 63.1 $ 24.0 $480.1 $ 72.3 $ 32.9 (Dollars in millions) $480.6(1) $333.0 $ 20.0 $ 54.3 5.7 $ $ 29.0 $377.6 $ 43.8 $ 24.1 $403.1 $ 55.6 $ 21.6 $413.9(1) $ 25.4(3) 7.5 $ $ 16.9 $ 22.7 $ 31.6 $ 27.6 $ 11.9 $ 22.5 $ 18.2 $ 8.0 Sales and other operating revenue . . . Gross profit(2) . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . Net income attributable to SunCoke Energy, Inc. / net parent investment . . . . . . . . . . . . . . . . . . . Earnings attributable to SunCoke Energy, Inc. / net parent investment per share of common stock: Basic . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . $ 0.24 $ 0.24 $ 0.32 $ 0.32 $ 0.45 $ 0.45 $ 0.39 $ 0.39 $ 0.17 $ 0.17 $ 0.32 $ 0.32 $ 0.26 $ 0.26 $ 0.12 $ 0.12 (1) In the fourth quarter of 2011, we recorded approximately a $7.0 million reduction to revenue related to the resolution of certain contract and billing issues with our customer at our Indiana Harbor facility. The resolution of this matter favorably impacted revenues by approximately $4.2 million in the fourth quarter of 2012. (2) Gross profit equals sales and other operating revenue less cost of products sold, operating expenses, loss on firm purchase commitments and depreciation, depletion and amortization. (3) During the fourth quarter of 2011, an out-of-period adjustment of approximately $3.9 million was recorded to correct the costs of products sold for our Indiana Harbor facility related to the third quarter of 2011. Management believes the amount was not material individually or in the aggregate to current or prior interim periods. The adjustment had no impact on the full year fiscal 2011 financial results. 26. Supplemental Condensed Consolidating Financial Information Certain 100 percent owned subsidiaries of the Company serve as guarantors of the obligations under the Credit Agreement and $400 million Notes (“Guarantor Subsidiaries”). These guarantees are full and unconditional (subject, in the case of the Guarantor Subsidiaries, to customary release provisions as described below) and joint and several. For purposes of the following footnote, SunCoke Energy, Inc. is referred to as “Issuer.” The indenture dated July 26, 2011 among the Company, the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., governs subsidiaries designated as “Guarantor Subsidiaries.” All other consolidated subsidiaries of the Company are collectively referred to as “Non-Guarantor Subsidiaries.” Prior to the Separation Date, the Company was a wholly-owned subsidiary of Sunoco. Therefore, there is no parent entity for purposes of this footnote for periods prior to the Separation Date. The guarantee of a Guarantor Subsidiary will terminate upon: • • • • a sale or other disposition of the Guarantor Subsidiary or of all or substantially all of its assets; a sale of the majority of the Capital Stock of a Guarantor Subsidiary to a third party, after which the Guarantor Subsidiary is no longer a “Restricted Subsidiary” in accordance with the indenture governing the Notes the liquidation or dissolution of a Guarantor Subsidiary so long as no “Default” or “Event of Default,” as defined under the indenture governing the Notes, has occurred as a result thereof the designation of a Guarantor Subsidiary as an “unrestricted subsidiary” in accordance with the indenture governing the Notes 124 • • the requirements for defeasance or discharge of the indentures governing the Notes having been satisfied. the release, other than the discharge through payment by a Guarantor Subsidiary, from its guarantee under the Credit Agreement or other indebtedness that resulted in the obligation of the Guarantor Subsidiary under the indenture governing the Notes The following supplemental condensed combining and consolidating financial information reflects the Issuer’s separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Non-Guarantor Subsidiaries, the combining and consolidating adjustments and eliminations and the Issuer’s combined and consolidated accounts for the dates and periods indicated. For purposes of the following condensed combining and consolidating information, the Issuer’s investments in its subsidiaries and the Guarantor and Non-Guarantor Subsidiaries’ investments in its subsidiaries are accounted for under the equity method of accounting. 125 SunCoke Energy, Inc. Condensed Consolidating Statement of Income Year Ended December 31, 2012 (in millions) Issuer Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Total Revenues Sales and other operating revenue . . . . . . . . . . . . . . . Equity in earnings of subsidiaries . . . . . . . . . . . . . . . Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $1,352.8 25.5 138.9 2.7 — Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138.9 1,381.0 Costs and operating expenses Cost of products sold and operating expenses . . . . . . Selling, general and administrative expenses . . . . . . Depreciation, depletion, and amortization . . . . . . . . . Total costs and operating expenses . . . . . . . . . . . . . . — 10.6 — 10.6 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . 128.3 Interest income—affiliate . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost—affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost Total financing (expense) income, net . . . . . . . . . . . . Income before income tax expense . . . . . . . . . . . . . . Income tax (benefit) expense . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Net income attributable to noncontrolling — — — (48.0) (48.0) 80.3 (18.5) 98.8 1,060.5 61.8 70.7 1,193.0 188.0 5.5 1.9 — (0.2) 7.2 195.2 46.8 148.4 interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — Net income attributable to SunCoke Energy, $549.2 — 9.4 558.6 517.1 9.6 10.1 536.8 21.8 — (5.5) (1.5) (7.0) 14.8 (4.9) 19.7 3.7 $ (164.4) $1,902.0 — 12.1 (164.4) 1,914.1 1,577.6 82.0 80.8 1,740.4 173.7 — 0.4 — (48.2) (47.8) 125.9 23.4 102.5 3.7 (164.4) (5.5) (1.5) 5.5 1.5 (164.4) (164.4) Inc./net parent investment . . . . . . . . . . . . . . . . . $ 98.8 $ 148.4 $ 16.0 (164.4) $ 98.8 Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . Less: Comprehensive income attributable to $ 97.4 $ 148.1 $ 18.6 $(163.0) $ 101.1 noncontrolling interests . . . . . . . . . . . . . . . . . . . . . — — 3.7 3.7 Comprehensive income attributable to SunCoke Energy, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 97.4 $ 148.1 14.9 $(163.0) $ 97.4 126 SunCoke Energy, Inc. Condensed Combining and Consolidating Statement of Income Year Ended December 31, 2011 (in millions) Issuer Guarantor Subsidiaries Non- Guarantor Subsidiaries Combining and Consolidating Adjustments $ (15.5) Total $1,527.6 — 11.3 (15.5) 1,538.9 Revenues Sales and other operating revenue . . . . . . . . . . . . . . Equity in earnings (loss) of subsidiaries . . . . . . . . . Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $1,023.4 (19.4) 2.0 34.9 — Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34.9 1,006.0 Costs and operating expenses Cost of products sold and operating expenses . . . . . Loss on firm purchase commitment . . . . . . . . . . . . . Selling, general and administrative expenses . . . . . Depreciation, depletion, and amortization . . . . . . . . Total costs and operating expenses . . . . . . . . . . . . . — — 2.6 — 2.6 Operating income (loss) . . . . . . . . . . . . . . . . . . . . . 32.3 Interest income—affiliate . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost—affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost Capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . . . Total financing (expense) income, net . . . . . . . . . . . Income (loss) before income tax expense . . . . . . . . Income tax (benefit) expense . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Net loss attributable to noncontrolling — — — (20.6) — (20.6) 11.7 (8.3) 20.0 interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Net income (loss) attributable to SunCoke Energy, Inc./net parent investment . . . . . . . . . $ 20.0 Comprehensive income (loss) . . . . . . . . . . . . . . . . . Less: Comprehensive income attributable to $ 20.0 noncontrolling interests . . . . . . . . . . . . . . . . . . . . — $ $ Comprehensive income (loss) attributable to 815.1 — 78.0 51.1 944.2 61.8 7.6 3.4 (3.5) — 9.8 17.3 79.1 6.8 72.3 — 72.3 63.8 — $504.2 — 9.3 513.5 490.7 18.5 8.1 7.3 524.6 (11.1) 8.2 (3.3) (3.0) — 1.9 (9.2) 8.7 (1.7) $ (16.2) $ (19.3) (1.7) (15.5) (3.3) (3.0) 3.3 3.0 (15.5) (17.9) (15.5) 1,305.8 18.5 88.7 58.4 1,471.4 67.5 12.5 0.4 (3.5) (20.6) 9.8 (1.4) 66.1 7.2 58.9 (1.7) (15.5) $(15.5) $ $ 60.6 49.0 (1.7) SunCoke Energy, Inc. . . . . . . . . . . . . . . . . . . . . $ 20.0 $ 63.8 (17.6) $(15.5) $ 50.7 127 SunCoke Condensed Combining Statement of Income Year Ended December 31, 2010 (in millions) Guarantor Subsidiaries Non- Guarantor Subsidiaries Combining and Consolidating Adjustments Revenues Sales and other operating revenue . . . . . . . . . . . . . . . . . . . . . Equity in earnings of subsidiaries . . . . . . . . . . . . . . . . . . . . . Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Costs and operating expenses Cost of products sold and operating expenses . . . . . . . . . . . . Selling, general and administrative expenses . . . . . . . . . . . . . Depreciation, depletion, and amortization . . . . . . . . . . . . . . . Total costs and operating expenses . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest income—affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost—affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total financing income, net . . . . . . . . . . . . . . . . . . . . . . . . . . Income before income tax expense . . . . . . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Net income attributable to noncontrolling interests . . . $874.7 22.5 1.3 898.5 628.6 50.0 41.0 719.6 178.9 8.7 — (5.4) 0.7 4.0 182.9 43.1 139.8 — $447.6 — 8.7 456.3 414.1 17.2 7.2 438.5 17.8 15.0 — — — 15.0 32.8 3.8 29.0 7.1 $ (5.8) (22.5) Total $1,316.5 — 10.0 (28.3) 1,326.5 (5.8) (5.8) (22.5) (22.5) (22.5) 1,036.9 67.2 48.2 1,152.3 174.2 23.7 — (5.4) 0.7 19.0 193.2 46.9 146.3 7.1 Net income attributable to net parent investment . . . . . . . $139.8 $ 21.9 $(22.5) $ 139.2 Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . Less: Comprehensive income attributable to 162.2 noncontrolling interests . . . . . . . . . . . . . . . . . . . . . . . — 29.4 7.1 (22.5) 169.1 7.1 Comprehensive income attributable to SunCoke Energy, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $162.2 $ 22.3 $(22.5) $ 162.0 128 SunCoke Energy, Inc. Condensed Consolidating Balance Sheet December 31, 2012 (dollars in millions, except per share amounts) Issuer Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Total Assets Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 206.9 55.7 Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 120.4 Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 2.6 Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — Income taxes receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.1 17.6 Advances to affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65.8 403.2 Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81.9 89.0 Notes receivable from affiliate . . . . . . . . . . . . . . . . . . . . . . — — Investment in Brazilian cokemaking operations . . . . . . . . . — — 1,277.2 Properties, plants and equipment, net . . . . . . . . . . . . . . . . . 52.5 — Lease and mineral rights, net . . . . . . . . . . . . . . . . . . . . . . . 9.4 — Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2 Deferred charges and other assets . . . . . . . . . . . . . . . . . . . . 23.1 Investment in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . 1,250.9 77.8 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,355.9 $1,922.3 Liabilities and Equity Advances from affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current portion of long term debt . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payable to affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrual for black lung benefits . . . . . . . . . . . . . . . . . . . . . . Retirement benefit liabilities . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . Commitments and contingent liabilities Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity Preferred stock, $0.01 par value. Authorized 50,000,000 0.5 3.3 0.6 15.7 — 20.1 720.1 — — — (1.9) — 2.1 740.4 65.8 90.4 — 77.7 — 27.7 261.6 — 300.0 34.8 42.5 364.2 11.3 21.4 $ 32.3 14.3 39.7 — 7.7 — 94.0 300.0 41.0 119.4 — — 10.1 — $564.5 $ 17.6 42.0 — 12.9 — — 72.5 — 89.0 — — (0.8) 2.2 — $ (23.8) (83.4) (107.2) (389.0) $ 239.2 70.0 160.1 2.6 — — 471.9 — 41.0 1,396.6 52.5 9.4 39.6 — (6.8) (1,328.7) $(1,831.7) $2,011.0 $ (23.8) (107.2) (83.4) $ — 132.9 3.3 91.2 15.7 3.9 247.0 720.1 — 34.8 42.5 361.5 13.5 16.7 (6.8) (389.0) 1,035.8 162.9 (503.0) 1,436.1 — — shares; no issued and outstanding shares at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Common stock, $0.01 par value. Authorized 300,000,000 shares; issued and outstanding 69,988,728 shares at — December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Treasury stock, 603,528 shares at December 31, 2012 . . . 724.5 Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . (6.5) Accumulated other comprehensive loss . . . . . . . . . . . . . . . 168.5 Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 886.5 Total SunCoke Energy, Inc. stockholders’ equity . . . . . . . — Noncontrolling interests . . . . . . . . . . . . . . . . . . . . . . . . . . . 886.5 Total equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total liabilities and equity . . . . . . . . . . . . . . . . . . . . . . . . . $1,355.9 $1,922.3 0.7 (9.4) 505.4 — 118.8 615.5 — 615.5 — — — 353.6 (1.4) 13.6 365.8 35.8 401.6 $564.5 — (1,146.6) 0.7 (9.4) 436.9 (7.9) 118.8 539.1 35.8 574.9 (1,328.7) $(1,831.7) $2,011.0 (182.1) (1,328.7) 129 SunCoke Energy, Inc. Condensed Consolidating Balance Sheet December 31, 2011 (dollars in millions, except per share amounts) Issuer Guarantor Subsidiaries Non- Guarantor Subsidiaries Combining and Consolidating Adjustments Total Assets Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 109.4 49.1 Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 155.7 Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 0.6 Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . — 30.3 Advances from affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . 128.5 7.3 Interest receivable from affiliate . . . . . . . . . . . . . . . . . . . — 352.4 Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128.5 89.0 Notes receivable from affiliate . . . . . . . . . . . . . . . . . . . . . — — Investment in Brazilian cokemaking operations . . . . . . . — — 1,281.6 Properties, plants and equipment, net . . . . . . . . . . . . . . . . 53.2 — Lease and mineral rights, net . . . . . . . . . . . . . . . . . . . . . . 9.4 — Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.7 Deferred charges and other assets . . . . . . . . . . . . . . . . . . 18.5 Investment in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . 1,120.5 41.9 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,267.5 $1,838.2 Liabilities and Equity Advances from affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 128.5 147.9 Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Current portion of long term debt . . . . . . . . . . . . . . . . . . . 64.9 Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Interest payable to affiliate . . . . . . . . . . . . . . . . . . . . . . . . 341.3 Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . — Long term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 300.0 Payable to affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33.5 Accrual for black lung benefits . . . . . . . . . . . . . . . . . . . . 50.6 Retirement benefit liabilities . . . . . . . . . . . . . . . . . . . . . . 265.3 Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4 Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . Other deferred credits and liabilities . . . . . . . . . . . . . . . . 16.2 Commitments and contingent liabilities Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity Preferred stock, $0.01 par value. Authorized 50,000,000 — 3.3 0.6 15.9 — 19.8 723.1 — — — (1.0) — 0.1 1,017.3 742.0 $ 18.1 17.1 64.0 — — — 99.2 300.0 41.0 110.2 — — 3.2 — $553.6 $ 30.3 34.0 — 14.9 — 7.3 86.5 — 89.0 — — (3.2) 2.1 3.3 $ (158.8) (7.3) (166.1) (389.0) $ 127.5 66.2 219.7 0.6 — — 414.0 — 41.0 1,391.8 53.2 9.4 32.4 (1,162.4) — $(1,717.5) $1,941.8 (7.3) (166.1) $ (158.8) $ — 181.9 3.3 80.4 15.9 — 281.5 723.1 — 33.5 50.6 261.1 12.5 19.6 (389.0) 177.7 (555.1) 1,381.9 shares; no issued and outstanding shares at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . Common stock, $0.01 par value. Authorized — — — — 300,000,000 shares; issued and outstanding 70,012,702 shares at December 31, 2011 . . . . . . . . . . . — 807.0 Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . (6.2) Accumulated other comprehensive income . . . . . . . . . . . 20.1 Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 820.9 Total SunCoke Energy, Inc. stockholders’ equity . . . . . . — Noncontrolling interests . . . . . . . . . . . . . . . . . . . . . . . . . . 820.9 Total equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total liabilities and equity . . . . . . . . . . . . . . . . . . . . . . . . $1,267.5 $1,838.2 0.7 504.8 — 20.0 525.5 — 525.5 — 344.2 (0.3) (2.4) 341.5 34.4 375.9 $553.6 130 (1,144.7) (17.7) (1,162.4) 0.7 511.3 (6.5) 20.0 525.5 34.4 559.9 (1,162.4) $(1,717.5) $1,941.8 SunCoke Energy, Inc. Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2012 (in millions) Issuer Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Total $ 98.8 $148.4 $ 19.7 $(164.4) $102.5 Cash Flows from Operating Activities: Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation, depletion and amortization . . . . . Stock compensation expense . . . . . . . . . . . . . . . Deferred income tax expense . . . . . . . . . . . . . . . Payments in excess of expense for retirement plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity in earnings of subsidiaries . . . . . . . . . . . Changes in working capital pertaining to operating activities: Receivables . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . Interest payable . . . . . . . . . . . . . . . . . . . . . Taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Net cash (used in) provided by operating — 6.7 (1.0) 70.7 — 35.0 — (138.9) (6.6) (25.5) — — 0.5 — (0.2) (16.1) (4.9) (6.6) 35.3 (57.5) 17.2 7.3 6.4 1.6 10.1 — 0.3 — — 2.8 20.8 8.0 (2.0) (7.3) (7.7) (9.2) 164.4 activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (55.1) 225.7 35.5 Cash Flows from Investing Activities: Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition of business, net of cash received . . . . . . Net cash used in investing activities . . . . . . . . . . . . . Cash Flows from Financing Activities: Repayment of long-term debt . . . . . . . . . . . . . . . . . . Proceeds from exercise of stock options . . . . . . . . . . Net increase (decrease) in advances from affiliate . . Repurchase of common stock . . . . . . . . . . . . . . . . . . Cash distributions to noncontrolling interests in — — — (3.3) 4.7 63.1 (9.4) (64.8) (3.5) (68.3) — — (59.9) — cokemaking operations . . . . . . . . . . . . . . . . . . . . . — — Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55.1 Net increase in cash and cash equivalents . . . . . . . . . . . . . Cash and cash equivalents at beginning of year — — (59.9) 97.5 109.4 (15.8) — (15.8) — — (3.2) — (2.3) (5.5) 14.2 18.1 Cash and cash equivalents at end of year . . . . . . . . . . $ — $206.9 $ 32.3 $ 131 80.8 6.7 34.3 (6.6) — (3.8) 56.1 (49.0) 15.2 (0.2) (17.4) (12.5) 206.1 (80.6) (3.5) (84.1) (3.3) 4.7 — (9.4) (2.3) (10.3) 111.7 127.5 $239.2 SunCoke Energy, Inc. Condensed Combining and Consolidating Statement of Cash Flows Year Ended December 31, 2011 (in millions) Cash Flows from Operating Activities: Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 20.0 Adjustments to reconcile net income (loss) to net cash $ 72.3 $(17.9) $(15.5) $ 58.9 Issuer Guarantor Subsidiaries Non- Guarantor Subsidiaries Combining and Consolidating Adjustments Total provided by (used in) operating activities: . . . . . . . . . . . . . Loss on firm purchase commitment Depreciation, depletion and amortization . . . . . . . . . Deferred income tax (benefit) expense . . . . . . . . . . . Payments less than expense for retirement plans . . . Equity in (loss) earnings of subsidiaries . . . . . . . . . . Changes in working capital pertaining to operating activities: Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . Interest payable . . . . . . . . . . . . . . . . . . . . . . . . . Income taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Net cash (used in) provided by operating activities . . . . . . Cash Flows from Investing Activities: Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition of business . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from sales of assets . . . . . . . . . . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . . . . . . . . . . . . Cash Flows from Financing Activities: Proceeds from issuance of long-term debt . . . . . . . . . . . . . Debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repayment of long-term debt . . . . . . . . . . . . . . . . . . . . . . Purchase of noncontrolling interest in Indiana Harbor facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net (decrease) increase in advances from affiliate . . . . . . Repayments of notes payable assumed in acquisition . . . . Increase in payable to affiliate . . . . . . . . . . . . . . . . . . . . . . Cash distributions to noncontrolling interests in cokemaking operations . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by (used in) financing activities . . . . . . Net increase (decrease) in cash and cash equivalents . . . . Cash and cash equivalents at beginning of year . . . . . . . . — — (1.0) — (34.9) — — — 0.6 15.9 — (4.4) (3.8) — — — — 727.9 (19.1) (1.6) — (703.4) — — — 3.8 — — — 51.1 44.1 5.8 19.4 (13.8) (82.9) 63.5 18.3 — (48.5) (13.1) 116.2 (236.9) (37.6) — (274.5) — — — (34.0) 296.8 (2.3) 7.2 — 267.7 109.4 — 18.5 7.3 (19.1) — — (4.5) (27.2) (6.5) (3.2) — 27.2 14.3 (11.1) (1.2) — — (1.2) — — — — (6.2) — (1.9) (1.6) (9.7) (22.0) 40.1 15.5 18.5 58.4 24.0 5.8 — (18.3) (110.1) 57.0 15.7 15.9 (21.3) (3.2) 101.3 (238.1) (37.6) — (275.7) 727.9 (19.1) (1.6) (34.0) (412.8) (2.3) 5.3 (1.6) 261.8 87.4 40.1 Cash and cash equivalents at end of year . . . . . . . . . . . . . $ — $ 109.4 $ 18.1 $ $ 127.5 132 SunCoke Condensed Combining Statement of Cash Flows Year Ended December 31, 2010 (in millions) Guarantor Subsidiaries Non- Guarantor Subsidiaries Combining and Consolidating Adjustments Total $ 139.8 $ 29.0 $(22.5) $ 146.3 Cash Flows from Operating Activities: Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization . . . . . . . . . . . . Deferred income tax expense . . . . . . . . . . . . . . . . . . . . . . Payments in excess of expense for retirement plans . . . . Equity in earnings of subsidiaries . . . . . . . . . . . . . . . . . . Changes in working capital pertaining to operating activities: Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . Income taxes payable . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41.0 15.4 (6.0) (22.5) (5.9) (0.5) 27.5 12.7 — 3.0 Net cash provided by operating activities . . . . . . . . . . . . . . . . 204.5 Cash Flows from Investing Activities: Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from sales of assets . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . Cash Flows from Financing Activities: Net decrease in advances from affiliate . . . . . . . . . . . . . . . . . . Contribution from parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Increase in payable to affiliate . . . . . . . . . . . . . . . . . . . . . . . . . Cash distributions to noncontrolling interests in cokemaking operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by (used in) financing activities . . . . . . . . . Net increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents at beginning of year (214.0) 1.7 (212.3) (23.3) 1.0 30.1 — 7.8 — — 7.2 — — — 40.6 0.5 3.9 12.8 (0.8) (1.1) 92.1 (1.6) — (1.6) (32.9) — 0.7 (20.9) (53.1) 37.4 2.7 22.5 48.2 15.4 (6.0) — 34.7 — 31.4 25.5 (0.8) 1.9 296.6 (215.6) 1.7 (213.9) (56.2) 1.0 30.8 (20.9) (45.3) 37.4 2.7 Cash and cash equivalents at end of year . . . . . . . . . . . . . . . . . $ — $ 40.1 $ $ 40.1 133 27. Subsequent Events Formation of a Master Limited Partnership On January 24, 2013, we completed the initial public offering of a master limited partnership (“the Partnership”) through the sale of 13,500,000 common units of limited partner interests in the Partnership in exchange for $233.1 million of net proceeds. Of these net proceeds, $67 million was retained by the Partnership for environmental remediation capital expenditures and $12.4 million for sales discounts related to tax credits owed to our customers. Upon the closing of the Partnership offering (“the Partnership offering”), we own the general partner of the Partnership, which consists of a 2 percent ownership interest and incentive distribution rights, and we currently own a 55.9 percent interest in the Partnership. The key assets of the Partnership are a 65 percent interest in each of our Haverhill and Middletown cokemaking and heat recovery facilities. The operations of the Partnership will be consolidated in our results. We are also party to an omnibus agreement pursuant to which we will provide remarketing efforts to the Partnership upon the occurrence of certain potential adverse events under our coke sales agreements, indemnification of certain environmental costs and preferential rights for growth opportunities. In connection with the closing of the Partnership offering, we repaid $225.0 million of our Term Loan and entered into an amendment to our Credit Agreement. In conjunction with the repayment, we expect to incur a charge of approximately $4.7 million representing the write-off of unamortized debt issuance costs and original issue discount related to the portion of the Term Loan retired. The amendment to our Credit Agreement, among other things, amended certain provisions to reflect the Partnership offering including (i) modification of the definition of “Consolidated Net Income” to include cash distributions received by the Company or a Restricted Subsidiary from an Unrestricted Subsidiary that is controlled directly or indirectly by the Company when calculating “Consolidated Net Income”, (ii) clarifying that obligations incurred by certain subsidiaries of the Company at or about the timing of the closing of the Partnership offering shall not be included in the definition of “Indebtedness,” and (iii) permitted an allowance for Investments in Middletown Coke Company, LLC and Haverhill Coke Company LLC and certain other subsidiaries of the Company. In addition, we also designated Middletown Coke Company, LLC and Haverhill Coke Company LLC as unrestricted subsidiaries. Furthermore, the term of the Credit Agreement was extended to January 2018. In addition, with the closing the Partnership issued $150.0 million of Senior Notes (“Partnership Notes”). The Partnership Notes have an interest rate of 7.375 percent and mature on February 1, 2020. The Partnership may redeem some or all of the Partnership Notes at any time on or after February 1, 2016 and prior to February 1, 2016 may also redeem up to 35 percent of the Partnership Notes at a price equal to 107.35 percent of the principal amount, plus accrued and unpaid interest, if any, to the redemption date. In addition, at any time prior to February 1, 2016, the Partnership may redeem some or all of the Partnership Notes at a price equal to 100 percent of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If the Partnership sells certain of its assets or experiences specific kinds of changes in control, subject to certain exceptions, the Partnership must offer to purchase the Partnership Notes. In conjunction with the closing of the Partnership offering, we also entered into a $100.0 million revolving credit facility with a term extending through January 2018. Coal Mining Segment Restructuring During the first quarter of 2013, we continued with our plan to reduce costs and increase productivity and implemented a reduction in force at our Coal Mining segment. This reduction in force resulted in the termination of 52 employees eligible to receive certain payments. The Company expects to incur restructuring charges of $0.7 million related to this reduction in force during 2013. 134 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Management’s Evaluation of Disclosure Controls and Procedures SunCoke Energy’s principal executive officer and its principal financial officer are responsible for evaluating the effectiveness of SunCoke Energy’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately. Management’s Report on Internal Control over Financial Reporting SunCoke Energy management, including SunCoke Energy’s principal executive officer and principal financial officer, are responsible for establishing and maintaining SunCoke Energy’s internal control over financial reporting, as such term is defined under Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. However, management would note that a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. SunCoke Energy’s management has adopted the framework set forth in the Committee of Sponsoring Organizations of the Treadway Commission report, Internal Control—Integrated Framework, the most commonly used and understood framework for evaluating internal control over financial reporting, as its framework for evaluating the reliability and effectiveness of internal control over financial reporting. During 2012, SunCoke Energy conducted an evaluation of its internal control over financial reporting. Based on this evaluation, SunCoke Energy management concluded that SunCoke Energy’s internal control over financial reporting was effective as of the end of the period covered by this annual report. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by SunCoke Energy in the reports that it files or submits under the Exchange Act is accumulated and communicated to SunCoke Energy’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Ernst & Young LLP, SunCoke Energy’s independent registered public accounting firm, issued an attestation report on SunCoke Energy’s internal controls over financial reporting which is contained in Item 8, “Financial Statements and Supplementary Data.” Changes in Internal Control over Financial Reporting There was no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 135 PART III Item 10. Directors, Executive Officers and Corporate Governance The information called for by this Item 10 required by Item 401 of Regulation S-K relating to Directors and Nominees for election to the Board of Directors is incorporated herein by reference to the section entitled “Proposal 1- Election of Directors” in our definitive Proxy Statement for our 2013 Annual Meeting of Stockholders to be held on May 9, 2013 (the “Proxy Statement”). The information called for by this Item 10 required by Item 405 of Regulation S-K is incorporated herein by reference to the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” under the heading “Other Information,” in the Proxy Statement. The information called for by this Item 10 required by Item 406 of Regulation S-K is incorporated herein by reference to the the section entitled “Code of Business Conduct and Ethics” under the heading “Corporate Governance” in the Proxy Statement. The information called for by this Item 10 required by Item 407(c)(3) of Regulation S-K is incorporated herein by reference to the section entitled “Governance Committee Process for Director Nominations” under the heading “Corporate Governance” in the Proxy Statement. The information called for by this Item 10 required by Items 407(d)(4) and 407(d)(5) of Regulation S-K is incorporated herein by reference to the information under the heading entitled “The Board of Directors and its Committees” and in the section entitled “Audit Committee Report” under the heading entitled “Audit Committee Matters,” in the Proxy Statement. Information called for by this Item 10 concerning the Company’s executive officers appears in Part I of this Annual Report on Form 10-K. Item 11. Executive Compensation The information called for by this Item 11 required by Item 402 of Regulation S-K is incorporated herein by reference to the sections of the Proxy Statement appearing under the heading “Executive Compensation,” including the sections entitled “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan-Based Awards Table,” “Outstanding Equity Awards at Fiscal Year-End Table,” “Option Exercises and Stock Vested Table,” “Pension Benefits,” “Nonqualified Deferred Compensation” and “Potential Payments Upon Termination or Change in Control,” and the sections of the Proxy Statement appearing under the heading “Directors Compensation.” The information called for by this Item 11 required by Items 407(e)(4) and 407(e)(5) of Regulation S-K is incorporated herein by reference to the sections of the Proxy Statement appearing under the heading “Executive Compensation,” including the sections entitled “Compensation Committee Report” and “Compensation Committee Interlocks and Insider Participation.” Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters The information called for by this Item 12 required by Item 403 of Regulation S-K is incorporated herein by reference to the sections of the Proxy Statement appearing under the heading “Beneficial Stock Ownership of Directors, Executive Officers and Persons Owning More Than Five Percent of Common Stock.” The information called for by this Item 12 required by Item 201(d) of Regulation S-K is incorporated herein by reference to the section of the Proxy Statement entitled “Equity Compensation Plan Information.,” appearing under the heading “Other Information.” 136 Item 13. Certain Relationships and Related Transactions, and Director Independence The information called for by this Item 13 required by Item 404 of Regulation S-K is incorporated herein by reference to the sections of the Proxy Statement entitled “Transactions with Related Persons” under the heading “Governance Matters.” The information called for by this Item 14 required by Item 407(a) of Regulation S-K is incorporated herein by reference to the section of the Proxy Statement entitled “Director Independence,” under the heading “Governance Matters.” Item 14. Principal Accountant Fees Services The information called for by this Item 14 required by Item 9(e) of Schedule 14A is incorporated herein by reference to the sections of the Proxy Statement appearing under the heading “Audit Committee Matters.” 137 PART IV Item 15. Exhibits, Financial Statement Schedules (a) The following documents are filed as a part of this report: 1. Combined and Consolidated Financial Statements: The Combined and Consolidated Financial Statements are set forth under Item 8 of this report. 2. Financial Statements Schedules: These schedules are omitted because the required information is shown elsewhere in this report, is not necessary or is not applicable. 3. Exhibits: 3.1 3.2 4.1 4.2 4.3 10.1 10.2 10.3 10.4 Amended and Restated Certificate of Incorporation of the Company (incorporated by reference herein to Exhibit 3.1 to the Company’s Amendment No. 4 to Registration Statement on Form S-1 filed on July 6, 2011, File No. 333-35243) Amended and Restated Bylaws of the Company (incorporated by reference herein to Exhibit 3.2 to the Company’s Amendment No. 1 to Form S-1 filed on May 11, 2011, File No. 333-35243) Indenture by and among the Company, the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated July 26, 2011 (incorporated by reference to the Company’s Current Report on Form 8-K filed on August 1, 2011, File No. 333-35243) Form of 7 5⁄ 8 percent Senior Notes due 2019 (included in Exhibit A to the Indenture filed as Exhibit 4.1) Registration Rights Agreement, dated July 26, 2011, among SunCoke Energy, Inc., the guarantors party thereto and J.P. Morgan Securities LLC, acting as the representative of the initial purchasers (incorporated by reference herein to Exhibit 4.3 to the Company’s Form 8-K filed on August 1, 2011, File No. 333-35243) Separation and Distribution Agreement, dated as of July 18, 2011, between SunCoke Energy, Inc. and Sunoco, Inc. (incorporated by reference herein to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) Transition Services Agreement, dated as of July 18, 2011, between SunCoke Energy, Inc. and Sunoco, Inc. (incorporated by reference herein to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) Tax Sharing Agreement, dated as of July 18, 2011, between SunCoke Energy, Inc. and Sunoco, Inc. (incorporated by reference herein to Exhibit 10.3 to the Company’ Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) Guaranty, Keep Well, and Indemnification Agreement, dated as of July 18, 2011, between SunCoke Energy, Inc. and Sunoco, Inc. (incorporated by reference herein to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) 10.5* SunCoke Energy, Inc. Senior Executive Incentive Plan (Effective as of January 1, 2012) (incorporated by reference herein to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) 10.6* SunCoke Energy, Inc. Senior Executive Incentive Plan (Effective as of January 1, 2013) (filed herewith) 138 10.7* 10.8* 10.9* 10.10* 10.11* 10.12* 10.13* 10.14* 10.15* 10.16* 10.17* 10.18* 10.19* 10.20* SunCoke Energy, Inc. Long-Term Performance Enhancement Plan (Effective as of July 21, 2011) (incorporated by reference herein to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) SunCoke Energy, Inc. Special Executive Severance Plan (Effective as of July 27, 2011) (incorporated by reference herein to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) SunCoke Energy, Inc. Executive Involuntary Severance Plan (Effective as of July 27, 2011) (incorporated by reference herein to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) Letter Agreement between Frederick A. Henderson and Sunoco, dated September 2, 2010 (incorporated by reference herein to Exhibit 10.10 to the Company’s Registration Statement on Form S-1 filed on March 23, 2011, File No. 333-35243) Amendment No. 1 to Letter Agreement between Frederick A. Henderson and Sunoco dated May 25, 2011 (incorporated by reference herein to Exhibit 10.11 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Letter Agreement between Michael J. Thomson and Sunoco, dated September 2, 2010 (incorporated by reference herein to Exhibit 10.12 to the Company’s Amendment No. 3 on Registration Statement on Form S-1 filed on March 23, 2011, File No. 333-35243) Letter Agreement between Fay West and SunCoke Energy, Inc., dated January 16, 2011 (incorporated by reference herein to Exhibit 10.13 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Letter Agreement between Denise R. Cade and Sunoco, dated February 18, 2011 (incorporated by reference herein to Exhibit 10.14 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Letter Agreement between Mark E. Newman and Sunoco, dated March 10, 2011 (incorporated by reference herein to Exhibit 10.15 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) SunCoke Energy, Inc. Deferred Compensation Plan, effective as of June 1, 2011 (incorporated by reference herein to Exhibit 10.35 to the Company’s Amendment No. 4 to Registration Statement on Form S-1 filed on July 6, 2011, File No. 333-35243) SunCoke Energy, Inc. Retainer Stock Plan for Outside Directors, effective as of June 1, 2011 (incorporated by reference herein to Exhibit 10.36 to the Company’s Amendment No. 4 to Registration Statement on Form S-1 filed on July 6, 2011, File No. 333-35243) Form of Indemnification Agreement, individually entered into between SunCoke Energy, Inc. and each director of the Company (incorporated by reference herein to Exhibit 10.16 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 filed on November 2, 2012, File No. 33-35243) Restricted Share Unit Agreement under the SunCoke Energy, Inc. Long-Term Performance Enhancement Plan, entered into as of July 21, 2011, by and between SunCoke Energy, Inc. and Michael J. Thomson (incorporated by reference herein to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) Restricted Share Unit Agreement under the SunCoke Energy, Inc. Long-Term Performance Enhancement Plan, entered into as of July 21, 2011, by and between SunCoke Energy, Inc. and Frederick A. Henderson (incorporated by reference herein to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) 139 10.21* 10.22* 10.23* 10.24* 10.25* 10.26* Stock Option Agreement under the SunCoke Energy, Inc. Long-Term Performance Enhancement Plan, entered into as of July 21, 2011, by and between SunCoke Energy, Inc. and Frederick A. Henderson (incorporated by reference herein to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) Stock Option Agreement under the SunCoke Energy, Inc. Long-Term Performance Enhancement Plan, entered into as of July 21, 2011, by and between SunCoke Energy, Inc. and Frederick A. Henderson (incorporated by reference herein to Exhibit 10.16 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 filed on August 3, 2011, File No. 33-35243) Amendment to Stock Option Agreements under the SunCoke Energy, Inc. Long-Term Performance Enhancement, entered into as of July 18, 2013, applicable to all Stock Option Awards outstanding as of July 18, 2012 (filed herewith) Form of Stock Option Agreement under the SunCoke Energy, Inc. Long-Term Performance Enhancement Plan by and between SunCoke Energy, Inc. and employees of SunCoke Energy, Inc. or one of its Affiliates (filed herewith) Amendment to Restricted Share Unit Agreements under the SunCoke Energy, Inc. Long-Term Performance Enhancement, entered into as of July 18, 2013, applicable to all Awards of Restricted Share Units outstanding as of July 18, 2012 (filed herewith) Form of Restricted Share Unit Agreement under the SunCoke Energy, Inc. Long-Term Performance Enhancement Plan by and between SunCoke Energy, Inc. and employees of SunCoke Energy, Inc. or one of its Affiliates (filed herewith) 10.27* SunCoke Energy, Inc. Executive Annual Incentive Plan (incorporated by reference herein to Exhibit 10.2 to the Company’s Form 8-K filed on December 9, 2011, File No. 333-35243) 10.28* SunCoke Energy, Inc. 2013 Executive Annual Incentive Plan (filed herewith) 10.29* 10.30* 10.31 10.32 10.33 SunCoke Energy, Inc. Savings Restoration Plan (incorporated by reference herein to Exhibit 10.1 to the Company’s Form 8-K filed on December 9, 2011, File No. 333-35243) Amendment Number One to the SunCoke Energy, Inc. Savings Restoration Plan, effective as of January 1, 2012 (incorporated by reference herein to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012 filed on May 2, 2012, File No. 333-35243) Amended and Restated Coke Supply Agreement, dated as of October 28, 2003, by and between Jewell Coke Company, L.P., ArcelorMittal Cleveland Inc. (f/k/a ISG Cleveland Inc.) and ArcelorMittal Indiana Harbor (f/k/a ISG Indiana Harbor Inc.) (incorporated by reference herein to Exhibit 10.18 to the Company’s Amendment No. 4 to Registration Statement on Form S-1 filed on July 6, 2011, File No. 333-35243) Amendment No. 1 to Amended and Restated Coke Supply Agreement, dated as of December 5, 2003, by and between Jewell Coke Company, L.P., ArcelorMittal Cleveland Inc. (f/k/a ISG Cleveland Inc.) and ArcelorMittal Indiana Harbor (f/k/a ISG Indiana Harbor Inc.) (incorporated by reference herein to Exhibit 10.19 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Letter Agreement, dated as of May 7, 2008, between ArcelorMittal USA Inc., Haverhill North Coke Company, Jewell Coke Company, L.P. and ISG Sparrows Point LLC, serving as (1) Amendment No. 2 to the Amended and Restated Coke Supply Agreement, by and between Jewell Coke Company, L.P., ArcelorMittal Cleveland Inc. (f/k/a ISG Cleveland Inc.) and ArcelorMittal Indiana Harbor (f/k/a ISG Indiana Harbor Inc.) and (2) Amendment No. 2 to the Coke Purchase Agreement, by and between Haverhill North Coke Company, ArcelorMittal Cleveland Inc. (f/k/a ISG Cleveland Inc.) and ArcelorMittal Indiana Harbor (f/k/a ISG Indiana Harbor Inc.) (incorporated by reference herein to Exhibit 10.20 to the Company’s Amendment No. 3 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) 140 10.34 10.35 10.36 10.37 10.38 10.39 10.40 10.41 10.42 10.43 Amendment No. 3 to Amended and Restated Coke Supply Agreement, dated as of January 26, 2011, by and between Jewell Coke Company, L.P., ArcelorMittal Cleveland Inc. (f/k/a ISG Cleveland Inc.) and ArcelorMittal Indiana Harbor (f/k/a ISG Indiana Harbor Inc.) (incorporated by reference herein to Exhibit 10.21 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Coke Purchase Agreement, dated as of October 28, 2003, by and between Haverhill North Coke Company, ArcelorMittal Cleveland Inc. (f/k/a ISG Cleveland Inc.) and ArcelorMittal Indiana Harbor (f/k/a ISG Indiana Harbor Inc.) (incorporated by reference herein to Exhibit 10.22 to the Company’s Amendment No. 4 to Registration Statement on Form S-1 filed on July 6, 2011, File No. 333-35243) Amendment No. 1 to Coke Purchase Agreement, dated as of December 5, 2003, by and between Haverhill North Coke Company, ArcelorMittal Cleveland Inc. (f/k/a ISG Cleveland Inc.) and ArcelorMittal Indiana Harbor (f/k/a ISG Indiana Harbor Inc.) (incorporated by reference herein to Exhibit 10.23 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Credit Agreement, dated as of July 26, 2011, by and among SunCoke Energy, Inc., JPMorgan Chase Bank, N.A., as Administrative Agent, the lenders party thereto, Bank of America, N.A., as Revolving Facility Syndication Agent and Term Loan Documentation Agent, Credit Suisse Securities (USA) LLC, as Term Loan Syndication Agent, and The Royal Bank of Scotland PLC and KeyBank National Association, as Revolving Facility Co-Documentation Agents (incorporated by reference herein to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 1, 2011, File No. 333-35243) Amendment No. 3 to Coke Purchase Agreement, dated as of May 8, 2008, by and between Haverhill North Coke Company, ArcelorMittal Cleveland Inc. (f/k/a ISG Cleveland Inc.) and ArcelorMittal Indiana Harbor (f/k/a ISG Indiana Harbor Inc.) (incorporated by reference herein to Exhibit 10.25 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Amendment No. 4 to Coke Purchase Agreement, dated as of January 26, 2011, by and between Haverhill North Coke Company, ArcelorMittal Cleveland Inc. (f/k/a ISG Cleveland Inc.) and ArcelorMittal Indiana Harbor (f/k/a ISG Indiana Harbor Inc.) (incorporated by reference herein to Exhibit 10.26 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Coke Purchase Agreement, dated as of August 31, 2009, by and between Haverhill North Coke Company and AK Steel Corporation (incorporated by reference herein to Exhibit 10.27 to the Company’s Amendment No. 5 to Registration Statement on Form S-1 filed on July 18f, 2011, File No. 333-35243) Amended and Restated Coke Purchase Agreement, dated as of February 19, 1998, by and between Indiana Harbor Coke Company, L.P. and ArcelorMittal USA Inc. (f/k/a Inland Steel Company) (incorporated by reference herein to Exhibit 10.28 to the Company’s Amendment No. 6 to Registration Statement on Form S-1 filed on July 20, 2011, File No. 333-35243) Amendment No. 1 to Amended and Restated Coke Purchase Agreement, dated as of November 22, 2000, by and between Indiana Harbor Coke Company, L.P., a subsidiary of the Company, and ArcelorMittal USA Inc. (f/k/a Inland Steel Company) (incorporated by reference herein to Exhibit 10.29 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Amendment No. 2 to Amended and Restated Coke Purchase Agreement, dated as of March 31, 2001, by and between Indiana Harbor Coke Company, L.P. and ArcelorMittal USA Inc. (f/k/a Inland Steel Company) (incorporated by reference herein to Exhibit 10.30 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) 141 10.44 10.45 10.46 10.47 12.1 21.1 23.1 23.2 24.1 31.1 31.2 32.1 32.2 Supplement to Amended and Restated Coke Purchase Agreement, dated as of February 3, 2011, by and between Indiana Harbor Coke Company, L.P. and ArcelorMittal USA Inc. (f/k/a Inland Steel Company) (incorporated by reference herein to Exhibit 10.31 to the Company’s Amendment No. 5 to Registration Statement on Form S-1 filed on July 18, 2011, File No. 333-35243) Coke Sale and Feed Water Processing Agreement, dated as of February 28, 2008, by and between Gateway Energy & Coke Company, LLC and United States Steel Corporation (incorporated by reference herein to Exhibit 10.32 to the Company’s Amendment No. 7 to Registration Statement on Form S-1 filed on July 20, 2011, File No. 333-35243) Amendment No. 1 to Coke Sale and Feed Water Processing Agreement, dated as of November 1, 2010, by and between Gateway Energy & Coke Company, LLC and United States Steel Corporation (incorporated by reference herein to Exhibit 10.33 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 filed on June 3, 2011, File No. 333-35243) Amended and Restated Coke Purchase Agreement, dated as of September 1, 2009, by and between Middletown Coke Company, LLC, a subsidiary of the Company and AK Steel Corporation (incorporated by reference herein to Exhibit 10.34 to the Company’s Amendment No. 5 to Registration Statement on Form S-1 filed on July 18, 2011, File No. 333-35243) Consolidated Ratio of Earnings to Fixed Charges (filed herewith) Subsidiaries of the Registrant (filed herewith) Consent of Ernst & Young LLP (filed herewith) Consent of Marshall Miller & Associates, Inc. (filed herewith) Powers of Attorney (filed herewith) Chief Executive Officer Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith) Chief Financial Officer Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith) Chief Executive Officer Certification Pursuant to Exchange Act Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code, as Adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith) Chief Financial Officer Certification Pursuant to Exchange Act Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code, as Adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith) 95.1 Mine Safety Disclosure (filed herewith) 101.INS* XBRL Instance Document 101.SCH* XBRL Taxonomy Extension Schema Document 101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF* XBRL Taxonomy Extension Definition Linkbase Document 101.LAB* XBRL Taxonomy Extension Label Linkbase Document 101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document * Management contracts, compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 601 of Regulation S-K. SunCoke Energy will furnish copies of the above exhibits to a stockholder upon written request to Investor Relations, SunCoke Energy, Inc., 1011 Warrenville Road, Suite 600, Lisle, Illinois 60532. 142 SIGNATURES 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 on the 22nd day of February 2013. SUNCOKE ENERGY, INC. By: /s/ Mark E. Newman Mark E. Newman Senior Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 22, 2013. Signature Title /s/ Frederick A. Henderson Frederick A. Henderson /s/ Mark E. Newman Mark E. Newman /s/ Fay West Fay West /s/ Robert J. Darnall* Robert J. Darnall /s/ Alvin Bledsoe* Alvin Bledsoe /s/ Peter B. Hamilton* Peter B. Hamilton /s/ Karen B. Peetz* Karen B. Peetz /s/ John W. Rowe* John W. Rowe /s/ James E. Sweetnam* James E. Sweetnam Chairman, Chief Executive Officer and Director (Principal Executive Officer) Senior Vice President and Chief Financial Officer (Principal Financial Officer) Vice President and Controller (Principal Accounting Officer) Director Director Director Director Director Director * Mark E. Newman, pursuant to powers of attorney duly executed by the above officers and directors of SunCoke Energy, Inc. and filed with the SEC in Washington, D.C., hereby executes this Annual Report on Form 10-K on behalf of each of the persons named above in the capacity set forth opposite his or her name. /s/ Mark E. Newman Mark E. Newman February 22, 2013 143 Stockholder Return Performance The graph below compares the cumulative total return of a $100 investment in SunCoke common stock with the cumulative total return of a $100 investment in the S&P Small Cap 600 and Dow Jones U.S. Steel indices. It covers the period beginning with the date of our initial public offering of July 21, 2011 through December 31, 2012 and assumes the reinvestment of dividends. In selecting the indices for comparison, we considered market capitalization and industry or line-of- business. The S&P Small Cap 600 is a broad equity market index comprised of companies with market capitalizations of between $300 million and $1.4 billion. SunCoke is a part of this index. The Dow Jones U.S. Steel index is comprised of both U.S.-based steel and metals manufacturing and coal and iron ore mining companies. While we do not manufacture steel, we do produce coke, an essential ingredient in the blast furnace production of steel. Coke production represents more than 90% of our operating income. In addition, we have coal mining operations. Accordingly, we believe the Dow Jones U.S. Steel index is appropriate for comparison purposes. $120 $100 $80 $60 $40 $20 $0 7/21/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 2/12 3/12 4/12 5/12 6/12 7/12 8/12 9/12 10/12 11/12 12/12 SunCoke Energy, Inc. S&P Small Cap 600 Dow Jones U.S. Steel Copyright© 2013 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved. Copyright© 2013 Dow Jones & Co. All rights reserved. 144 Stockholder Information Corporate Headquarters SunCoke Energy, Inc. 1011 Warrenville Road Suite 600 Lisle, IL 60532 www.suncoke.com Annual Stockholders Meeting Thursday, May 9, 2013 9:00 a.m. Central Time Hotel Arista 2139 CityGate Lane Naperville, IL 60563 Stock Market Listing New York Stock Exchange Symbol: SXC Transfer Agent and Registrar SEC Reports and General Information We make available free of charge on our website, www.suncoke.com, all materials that we file electronically with the Securities and Exchange Commission, including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and any amendments to such reports. Requests for such reports and general inquiries regarding stock information, quarterly earnings and news releases may be directed to Investor Relations. Forward-Looking Statements Some of the statements included in this document constitute “forward-looking statements” (as defined in Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended). Such forward-looking statements are based on Computershare Investor Services management’s beliefs and assumptions and on Attn: SunCoke Shareholder Services information currently available. You should not put P.O. Box 43078 Providence, RI 02940-3078 www.computershare.com Phone: 855-879-4044 Investor Relations SunCoke Energy, Inc. Investor Relations 1011 Warrenville Road Suite 600 Lisle, IL 60532 Phone: 630-824-1907 undue reliance on any forward-looking statements. For more information about forward-looking statements and the risks and uncertainties that could cause actual results to differ materially from those expressed in forward-looking state- ments, please see the “Cautionary Statement Concerning Forward-Looking Statements” section in our Annual Report on Form 10-K, which is included herein. Non-GAAP Financial Measures This document includes certain non-GAAP financial Email: investorrelations@suncoke.com measures intended to supplement, not substitute Independent Registered Public Accounting Firm Ernst and Young LLP for, comparable GAAP measures. For reconciliations of non-GAAP financial measures to GAAP financial measures, please see the “Non-GAAP Financial Measures” section in our Annual Report on Form 10-K, which is included herein. Investors are urged to consider carefully the comparable GAAP measures and the reconciliations to those measures provided in our Annual Report on Form 10-K. 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