---

---

Item 1.	Business

---

•	Domestic Coke consists of our Jewell, Indiana Harbor, Haverhill, Granite City and Middletown cokemaking and heat recovery operations located in Vansant, Virginia; East Chicago, Indiana; Franklin Furnace, Ohio; Granite City, Illinois; and Middletown, Ohio, respectively.

•	Brazil Coke consists of our operations in Vitória, Brazil, where we operate a cokemaking facility for a Brazilian subsidiary of ArcelorMittal;

•	India Coke consists of our cokemaking joint venture with Visa Steel in Odisha, India.

•	Coal Logistics consists of our coal handling and/or mixing service operations in East Chicago, Indiana; Ceredo, West Virginia; Belle, West Virginia; Catlettsburg, Kentucky; and Convent, Louisiana.

---

(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 includes both blast furnace coke and small coke. Middletown capacity on a “run of oven” basis is approximately 578 thousand tons per year.

(2)	Cokemaking capacity represents 100 percent of VISA SunCoke.

---

---

---

---

---

•

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 and operating permits are found in the federal regulations. Once all requirements are satisfied, a state or local agency produces an initial draft permit. Generally, the facility reviews and comments 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 and makes the permit and supporting documents available for public review and comment. A public hearing may be scheduled, and the U.S. Environmental Protection Agency ("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 at least 18 months. Generally, construction commences during this period, while many states allow this period to be extended in certain situations.

•

Air quality. Our cokemaking facilities employ Maximum Available Control Technology (“MACT”) standards designed to limit emissions of certain hazardous air pollutants. 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 SunCoke's Jewell cokemaking facility located in Vansant, Virginia. Under applicable federal air quality regulations, permitting requirements may differ among facilities, 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” or "unclassifiable" area. The status of an area may change over time as new NAAQS standards are adopted, resulting in an area change from one status or classification to another. In an attainment area, the facility must install air pollution control equipment or employ Best Available Control Technology (“BACT”). 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, and emissions in a non-attainment area must be offset by emission reductions obtained from other sources.

•

Stringent NAAQS for ambient nitrogen dioxide and sulfur dioxide went into effect in 2010. In July 2013, the EPA identified or "designated" as nonattainment 29 areas in 16 states where monitored air quality showed violations of the 2010 1-hour SO2 NAAQS. In August 2015, the EPA finalized a new rulemaking to assist in implementation of the primary 1-hour SO2 NAAQS that requires either additional monitoring, or modeling of ambient air SO2 levels in various areas including where certain of our facilities are located. By July 2016, states subject to this rulemaking must provide EPA with either a modeling approach using existing emissions data, or a plan to undertake ambient air monitoring for SO2 to begin in 2017. For states that choose to install ambient air SO2 monitoring stations, after three years of data has been collected, or sometime in 2020, EPA will evaluate this data relative to the appropriate attainment designation for the areas under the 1-hour SO2 NAAQS. This rulemaking will require certain of our facilities to undertake this ambient air monitoring. We may be required to install yet additional pollution controls and incur greater costs of operating at those of our facilities located in areas that EPA determines to be non-attainment with the 1-hour SO2 NAAQS based on its evaluation of this data. In 2012, a NAAQS for fine particulate matter, or PM 2.5, went into effect. In November 2015, the EPA revised the existing NAAQS for ground level ozone to make the standard more stringent. These new standards and any future more stringent standard for ozone have two impacts on permitting: (1) demonstrating compliance with the standard using dispersion modeling from a new facility will be more difficult; and (2) additional areas of the country may become designated as non-attainment areas. Facilities operating in areas that become non-attainment areas due to the application of new standards may be required to install Reasonably Available Control Technology (“RACT”). A number of states have also filed or joined suits to challenge the EPA’s new standard in court. While we are not able to determine the extent to which this new standard will impact our business at this time, it does have the potential to have a material impact on our operations and cost structure.

•	The EPA adopted a rule in 2010 requiring a new facility that is a major source of greenhouse gases (“GHGs”) to install equipment or employ BACT procedures. Currently, there is little information on what may be acceptable as BACT to control GHGs (primarily carbon dioxide from our facilities), 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 flue gas desulfurization, 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 regulations 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 affected species. Based on the species that have been designated as endangered or threatened 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.

•

Permitting Process for Coal Mining Operations. The U.S. coal mining permit application process is initiated by collecting baseline data to adequately 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 this data to develop a mine and reclamation plan, which incorporate 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. SMCRA mine permits also take a significant period of time to be transferred.

•

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, 2015, we have posted an aggregate of approximately $48 million in surety bonds or other forms of financial security for reclamation purposes.

•

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”). 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 to make a risk-based determination for pushing and quenching emissions and determine whether additional emissions reductions are necessary, but the EPA has yet to publish or propose any residual risk standards; therefore, the impact of potential additional EPA regulation in this area 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.

---

•

Terminal Operations. Our terminal operations located along waterways and the Gulf of Mexico are also governed by permitting requirements under the CWA and CAA. These terminals are subject to U.S. Coast Guard regulations and comparable state statutes regarding design, installation, construction, and management. Many such terminals owned and operated by other entities that are also used to transport coal, including for export, have been pursued by environmental interest groups for alleged violations of their permits’ requirements, or have seen their efforts to obtain or renew such permits contested by such groups. While we believe that our operations are in material compliance with these permits, we cannot assure you that no such challenges or claims will be made against our operations in the future. Moreover, our terminal operations may be affected by the impacts of additional regulation on the mining of all types of coal and use of thermal coal for fuel, which is restricting supply in some markets and may reduce the volumes of coal that our terminals manage.

•

Federal Energy Regulatory Commission. The Federal Energy Regulatory Commission (“FERC”) regulates the sales of electricity from our Haverhill and Middletown facilities, including the implementation of the Federal Power Act (“FPA”) and the Public Utility Regulatory Policies Act of 1978 (“PURPA”). The nature of the operations of the Haverhill and Middletown facilities makes each facility a qualifying facility under PURPA, which exempts the facilities and the Company from certain regulatory burdens, including the Public Utility Holding Company Act of 2005 (“PUHCA”), limited provisions of the FPA, and certain state laws and regulation. FERC has granted requests for authority to sell electricity from the Haverhill and Middletown facilities at market-based rates and the entities are subject to FERC’s market-based rate regulations, which require regular regulatory compliance filings.

•

Clean Water Act of 1972. Although our cokemaking facilities generally do not have water discharge permits, 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.

•

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, or a past owner or operator, of facilities at which hazardous substances have been released. 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. The EPA also finalized a rule in 2010 requiring a new facility that is a major source of greenhouse gases (“GHGs”) to install equipment or employ BACT procedures. Currently there is little information as to what may constitute BACT for GHG in most industries. We may also be subject to the EPA’s “Tailoring Rule,” where certain modifications to our facilities could subject us to the additional permitting and other obligations relative to emissions of GSGs under the New Source Review/Prevention of Significant Deterioration (NSR/PSD) and Title V programs of the Clean Air Act based on whether the facility triggered NSR/PSD because of emissions of another pollutant such as SO2, NOx, PM, ozone or lead. The EPA has engaged in rulemakings to regulate GHG emissions from existing and new coal fired power plants, and we expect continued legal challenges to this rulemaking and any future rulemaking for other industries. For instance, in August 2015, the EPA issued its final Clean Power Plan rules establishing carbon pollution standards

---

•	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 significant increase in the dollar penalties assessed for citations issued.

•

Security. Our Convent Marine Terminal is subject to regulation by the United States Coast Guard pursuant to the Maritime Transportation Security Act. We have an internal inspection program designed to monitor and ensure compliance by the Convent Marine Terminal with these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of the facility.

•

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 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 was $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, 2015, we had asset retirement obligation of $13.8 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.

•

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

---

•

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.

---

---

Item 1A.	Risk Factors

---

---

---

•	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 the payment of dividends, 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.

---

---

---

•	earthquakes, subsidence and unstable ground or other conditions that may cause damage to infrastructure or personnel;

•	fire, explosion, or other major incident causing injury to personnel and/or equipment, resulting in all or part of the cokemaking operations at one of our facilities to cease, or be severely curtailed for a period of time;

•	processing and plant equipment failures, operating hazards and unexpected maintenance problems affecting our cokemaking operations or our customers; and

•	adverse weather and natural disasters, such as severe winds, heavy rains, snow, flooding, extremes of temperature, and other natural events affecting cokemaking operations, transportation, or our customers.

---

---

---

•

The demand for thermal coal can be impacted by changes in the energy consumption pattern of industrial consumers, electricity generators and residential users, as well as weather conditions and extreme temperatures. The amount of thermal coal consumed for electric power generation is affected primarily by the overall demand for electricity, the availability, quality and price of competing fuels for power generation, and governmental

---

•

The demand for metallurgical coal for use in the steel industry may be impacted adversely by economic downturns resulting in decreased demand for steel and an overall decline in steel production. A decline in blast furnace production of steel may reduce the demand for furnace coke, an intermediate product made from metallurgical coal. Decreased demand for metallurgical coal also may result from increased steel industry utilization of processes that do not use, or reduce the need for, furnace coke, such as electric arc furnaces, or blast furnace injection of pulverized coal or natural gas.

•	geological, hydrologic, or other conditions that may cause damage to infrastructure or personnel;

•	a major incident that causes all or part of the coal logistics operations at a site to cease for a period of time;

•	processing and plant equipment failures and unexpected maintenance problems;

•	adverse weather and natural disasters, such as heavy rains or snow, flooding, extreme temperatures and other natural events affecting coal logistics operations, transportation, or customers;

---

•	possible legal challenges to the renewal of key permits, which may lead to their renewal on terms that restrict our terminalling operations, or impose additional costs on our operations.

•	demand for electricity in the U.S. is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our coal logistics business;

•	demand for metallurgical coal depends on steel demand in the U.S. and globally, which if weakened would negatively impact the revenues, margins and profitability of our coal logistics business;

•	the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables; and

•	our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for potential acquisitions, or other growth opportunities.

•	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, extreme temperatures, 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.

•	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.

•	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, extreme temperatures, 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.

---

•	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.

---

---

•	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.

---

•

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 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.

---

---

---

Item 1B.	Unresolved Staff Comments

Item 2.	Properties

•

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.

•	Approximately 180 acres in Ceredo (Wayne County), West Virginia and approximately 36 acres in White Creek (Boyd County), Kentucky on which KRT has two coal terminals and one liquids terminal for its coal mixing and/or handling services along the Ohio and Big Sandy Rivers.

•	Approximately 174 acres in Convent (St. James Parish), Louisiana, on which Convent Marine Terminal is located.

•	Approximately 88 acres of land located in East Chicago (Lake County), Indiana, on which the Indiana Harbor cokemaking facility is located and the coal handling and/or mixing 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.

•	Approximately 25 acres in Belle (Kanawha County), West Virginia, on which KRT has a coal terminal for its coal mixing and/or handling services along the Kanawha River.

•	Our corporate headquarters is located in leased office space in Lisle, Illinois under an 11-year lease that commenced in 2011.

---

---

(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.

(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.

Item 3.	Legal Proceedings

---

Item 4.	Mine Safety Disclosures

---

Item 5.	Market for Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities

---

---

---

Item 6.	Selected Financial Data

(1)	During 2014, we recorded total impairment charges related to the Coal Mining business of $150.3 million, which included both long-lived asset and goodwill impairment charges.

(2)	During 2015 and 2014, we recorded other-than-temporary impairment charges on our investment in VISA SunCoke of $19.4 million and $30.5 million, respectively. The 2015 impairment charges brought our investment in VISA SunCoke to zero.

---

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

---

•

Total revenues were $1,362.7 million in 2015 compared to $1,503.8 million in 2014. The decrease in revenue primarily reflects the pass-through of lower coal prices and underperformance at Indiana Harbor. Excluding Indiana Harbor, we continue to produce coke tons at contract maximum levels, but volumes in excess of maximums as well as spot sales were lower in 2015 as compared to the prior year period. These decreases were partly offset by revenues contributed by CMT of $28.6 million, which was acquired in August 2015.

•	Adjusted EBITDA was $185.8 million in 2015 compared to $210.7 million in 2014. Underperformance and lower cost recovery at Indiana Harbor, which decreased Adjusted EBITDA $23.7 million, as well as the impact of the reorganization of Haverhill Chemicals more than offset the $21.0 million of Adjusted EBITDA contribution from the acquisition of CMT.

•

Net loss attributable to shareholders was $22.0 million, or $0.34 per share, in 2015 compared to net loss attributable to shareholders of $126.1 million, or $1.83 per share, in 2014. More than offsetting the decreases discussed above, the improvement over the prior year period was primarily driven by non-cash impairment charges related to the coal business of $150.3 million, or $92.2 million, net of tax, recorded in 2014. Additionally, we recorded non-cash impairment charges on our investment in VISA SunCoke, our Indian cokemaking joint venture, of $19.4 million and $30.5 million in 2015 and 2014, respectively.

---

•	Cash generated from operating activities was $141.1 million in 2015 compared to $112.3 million in 2014, driven by working capital changes largely due to the wind down of a strategic inventory build in the prior year and the timing of payments associated with accounts payable.

•	Sustained solid safety, environmental and operating performance across our Domestic Coke and Coal Logistics fleet, excluding Indiana Harbor;

•	Achieved significant growth at the Partnership through the successful acquisition of Convent Marine Terminal and the dropdown of our Granite City cokemaking operations;

•	Returned approximately $64 million to investors via dividends and share repurchases during 2015; and

•	Implemented a contract mining model and rationalized production at our coal mining operations.

---

•	Manage through the challenging market conditions;

•	Stabilize our Indiana Harbor cokemaking operations;

•	Deliver operational excellence; and

•	Achieve financial objectives and strengthen our balance sheet.

---

•	Coal Logistics. Coal Logistics reported revenues of $81.2 million, $55.0 million and $13.6 million, of which $20.4 million, $18.8 million and $5.5 million were intercompany revenues, and Adjusted EBITDA of $38.4 million, $14.3 million and $4.7 million during 2015, 2014 and 2013, respectively. Comparability between periods

---

•

Haverhill Chemicals. During the second quarter of 2015, Haverhill Chemicals, with whom we previously had a steam supply agreement at our Haverhill 1 cokemaking operations, announced plans to shut down their facility and later filed for relief under Chapter 11 of the U.S. Bankruptcy Code, which did not impact our ability to produce coke. Beginning in the fourth quarter of 2015, Haverhill 1 provides steam, at no cost, to Altivia, which purchased the facility from Haverhill Chemicals.  While the Company is not currently generating revenues from providing steam to Altivia, the current arrangement, for which rates may be renegotiated beginning in 2018, mitigates costs associated with disposing of steam as well as potential compliance issues.  These events decreased Adjusted EBITDA $6.4 million during 2015.

•	Severance. In 2015 and 2014, we reduced the workforce in our corporate office and incurred total charges of $4.1 million and $1.4 million in 2015 and 2014, respectively, in Corporate and Other. We expect the 2015 reduction in workforce at our corporate office to provide savings of approximately $3.5 million in 2016.

•

Pension Plan Termination. Effective May 30, 2014, Dominion Coal Corporation ("Dominion Coal"), a wholly-owned subsidiary of the Company, terminated its defined benefit plan, a plan that was previously offered generally to all full-time employees of Dominion Coal. In June 2015, the plan settled its obligations by purchasing annuities using plan assets, which triggered settlement accounting and resulted in a non-cash loss of $12.6 million recorded in cost of products sold and operating expense on the Consolidated Statements of Operations.

•

Black Lung Obligation. The Company recognized expense of $9.8 million and $14.3 million and income of $0.3 million during 2015, 2014, and 2013, respectively, in connection with our black lung obligation. Our obligation related to black lung benefits was estimated based on various assumptions, including actuarial estimates, discount rates and changes in health care costs. In addition to changes in assumptions, the estimated liability in 2015 and 2014 was impacted by a significant increase in the number of claims filed as well as the rate at which claims are awarded. The Company made payments related to black lung of $3.8 million, $2.8 million and $2.2 million during 2015, 2014, and 2013, respectively.

•

India Equity Method Investment. As a result of the continued deterioration of market factors, primarily the continuation of low-priced Chinese coke imports and the resulting deterioration of coke margins, we evaluated the recoverability of our equity method investment in Visa SunCoke in both 2015 and 2014. As a result of these analyses, we recorded impairment charges of $19.4 million and $30.5 million during 2015 and 2014, respectively. These impairment charges were included in loss from equity method investment on the Consolidated Statements of Operations. The 2015 impairment brought our investment in VISA SunCoke to zero, and consequently, we no longer include our share of VISA SunCoke in our financial results. Loss from our equity method investment in VISA SunCoke was $21.6 million, $35.0 million and $2.2 million during 2015, 2014 and 2013, respectively. See Note 6 and Note 24 to our consolidated financial statements.

•

Coal Mining Impairments. In the second quarter of 2014, we evaluated the recoverability of our long-lived coal asset group given the projected losses resulting from the weakening coal market. We recorded total impairment charges related to the coal business of $150.3 million, or $92.2 million net of tax, including long-lived asset and goodwill impairment charges. See Note 5 and Note 24 to the consolidated financial statements.

•	Interest Expense, net. Interest expense, net was $56.7 million, $63.2 million, and $52.3 million during 2015, 2014 and 2013, respectively, and was impacted by the following items:

◦

Net loss on extinguishment of debt was $0.5 million and $15.4 million in 2015 and 2014, respectively. The 2015 net loss includes losses of $9.4 million and $3.2 million in connection with the financing of the Granite City Dropdown and the repayment of $60.4 million of the Company's senior notes, respectively, net of a $12.1 million gain on the retirement of $47.5 million of the Partnership's senior notes. During 2014, the Company incurred a loss on the extinguishment of debt of $15.4 million in connection with the

---

◦	Interest of $3.7 million was capitalized in connection with the environmental remediation projects and the expansion capital improvement project at CMT during 2015. Interest of $3.2 million and $1.0 million was capitalized in connection with environmental remediation projects during 2014 and 2013, respectively.

◦	Interest on higher debt balances, primarily associated with the acquisition of CMT, attributed to the remaining increase in interest expense, net during 2015 and 2014. The 2015 average debt balance was $816.2 million as compared to the 2014 average debt balance of $649.8 million. See Note 16 to our consolidated financial statements.

•	Noncontrolling Interest. Income attributable to noncontrolling interest represents the common public unitholders’ interest in the Partnership as well as a third-party interest in our Indiana Harbor cokemaking facility. Income attributable to noncontrolling interest was $32.3 million, $24.3 million and $25.1 million during 2015, 2014 and 2013, respectively.

◦	The increase of $8.0 million in 2015 was primarily driven by the Granite City dropdowns along with the CMT acquisition, all of which increased the overall earnings of the Partnership. The acquisition and dropdown transactions also increased the public unitholders ownership percentage of the Partnership from 43.9 percent to 44.6 percent.

◦

The decrease of $0.8 million in 2014 compared to 2013 was driven by lower overall earnings of Haverhill and Middletown as well as dropdown transaction costs incurred by the Partnership during 2014. These decreases were partially offset by the Partnership's increased ownership in Haverhill and Middletown due to the dropdown transaction in May 2014, which increased the Company's noncontrolling interest. The Haverhill and Middletown dropdown transaction increased the public unitholders ownership percentage of the Partnership from 42.1 percent to 43.9 percent.

---

---

•	Domestic Coke consists of our Jewell, Indiana Harbor, Haverhill, Granite City and Middletown cokemaking and heat recovery operations located in Vansant, Virginia; East Chicago, Indiana; Franklin Furnace, Ohio; Granite City, Illinois; and Middletown, Ohio, respectively.

•	Brazil Coke consists of our operations in Vitória, Brazil, where we operate a cokemaking facility for a Brazilian subsidiary of ArcelorMittal;

•	India Coke consists of our cokemaking joint venture with Visa Steel in Odisha, India.

•	Coal Logistics consists of our coal handling and/or mixing service operations in East Chicago, Indiana; Ceredo, West Virginia; Belle, West Virginia; and Catlettsburg, Kentucky; and Convent, Louisiana.

•

Take-or-Pay Provisions. Substantially all of our coke sales at our domestic cokemaking facilities 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 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 generally do not have significant spot coke sales since our domestic capacity is consumed by long-term contracts; 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 domestic cokemaking facilities, 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. The coal component of the Jewell coke price is 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.

•

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 three coke sales agreements, the operating cost component for our coke sales are fixed subject to an annual adjustment based on an inflation index. Beginning in 2015, the operating and maintenance cost recovery mechanism in our Indiana Harbor coke sales agreement shifted from an annually negotiated budget amount with a cap to a fixed recovery per ton. Accordingly, actual operating costs can have a significant impact on the profitability of all our domestic cokemaking facilities. In 2018, the operating cost component of our contract at Indiana Harbor reverts to an annually negotiated budget, which is expected to have a favorable impact on our future results.

•

Fixed Fee Component. Our coke prices also include a per ton fixed fee component for each ton of coke sold to the customer, which is determined at the time the coke sales agreement is signed and is effective for the term of each sales agreement. The fixed fee is intended to provide an adequate return on invested capital to SunCoke and may differ based on investment levels, tax benefits and other considerations. The actual return on invested capital at any facility is based on the fixed fee per ton and favorable or unfavorable performance on pass-through cost items.

---

•	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.

---

(1)	See definition of Adjusted EBITDA and reconciliation to the most comparable GAAP measures at the end of this Item.

(2)	Legacy costs, net include costs associated with former mining employee-related liabilities prior to the implementation of our current contractor mining business, net of certain royalty revenues. See details of these legacy items below.

(3)	Excludes 22 thousand tons of consigned coke sales in the year ended December 31, 2013.

(4)	Reflects Domestic Coke Adjusted EBITDA divided by Domestic Coke sales volumes.

(5)	Represents tons the Company did not handle, but received payment for under the long-term, take-or-pay contracts.

---

---

---

---

---

---

•

Ongoing capital expenditures required to maintain equipment reliability, the integrity and safety of our coke ovens and steam generators and to comply with environmental regulations. Ongoing capital expenditures are 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 and also include new 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;

•	Environmental remediation project 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 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.

(1)	Includes $2.9 million, $3.2 million and $1.0 million of interest capitalized in connection with the environmental remediation project at Haverhill for the years ended December 31, 2015, 2014 and 2013, respectively.

(2)	Excludes the investment in VISA SunCoke and the acquisitions of Lake Terminal, KRT, and CMT.

(3)	Includes capital expenditures of $3.8 million for the ship loader and expansion project funded with cash withheld in conjunction with the acquisition of CMT. This also includes $0.8 million of interest capitalized in connection with these projects.

•	Total ongoing capital expenditures of approximately $38 million, of which $15 million will be spent at the Partnership;

•	Total capital expenditures on environmental remediation projects of approximately $3 million, all of which will be spent at the Partnership and was funded with a portion of the proceeds of the Partnership Offering and subsequent asset dropdowns; and

•	Total expansion capital of approximately $4 million.

•	We expect that capital expenditures will remain at this level in 2017 and 2018.

---