The table below summarizes information regarding the operating characteristics of each of our mines that were active in 2015 in the U.S. and Australia. The mines are listed within their respective mining segment in descending order, as determined by tons sold in 2015 .

Refer to the "Summary of Coal Production and Sulfur Content of Assigned Reserves" table within Part I, Item 2. "Properties," which is incorporated by reference herein, for additional information regarding coal reserves, product characteristics and production volume associated with each mine.

Trading and Brokerage Segment

Our Trading and Brokerage segment engages in the direct and brokered trading of coal and freight-related contracts through our trading and business offices. Coal brokering is conducted both as principal and agent in support of various coal production-related activities that may involve coal produced from our mines, coal sourcing arrangements with third-party mining companies or offtake agreements with other coal producers. The Trading and Brokerage segment also provides transportation-related services, which involves both financial derivative contracts and physical contracts. Collectively, coal and freight-related hedging activities include both economic hedging and, from time to time, cash flow hedging in support of our coal trading strategy.

Corporate and Other Segment

Our Corporate and Other segment includes selling and administrative expenses, corporate hedging activities, mining and export/transportation joint ventures, restructuring charges and activities associated with the optimization of our coal reserve and real estate holdings, minimum charges on certain transportation-related contracts, the closure of inactive mining sites and certain energy-related commercial matters.

Resource Management.   As of December 31, 2015 , we held approximately 6.3  billion tons of proven and probable coal reserves and approximately 500 thousand acres of surface property through ownership and lease agreements. We have an ongoing asset optimization program whereby our property management group regularly reviews these reserves and surface properties for opportunities to generate earnings and cash flow through the sale or exchange of non-strategic coal reserves and surface lands. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties and farm income from surface lands under third-party contracts.

Middlemount Mine.   We own a 50% equity interest in Middlemount Coal Pty Ltd., which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and LV PCI coal for sale into seaborne coal markets through rail and port capacity contracted through Abbot Point Coal Terminal, with future capacity also secured at Dalrymple Bay Coal Terminal. Mining operations first commenced at the Middlemount Mine in late 2011 and the mine continued to ramp up production and implement operational improvements through 2015. During the years ended December 31, 2015, 2014 and 2013, the mine sold 4.2 million, 3.7 million and 2.8 million tons of coal, respectively (on a 100% basis).

Export Facilities.   We have a 37.5% interest in Dominion Terminal Associates, a partnership that operates a coal export terminal in Newport News, Virginia that exports both metallurgical and thermal coal primarily to European and Brazilian markets.

Generation Development.   We own a 5.06% participating interest in the Prairie State Energy Campus (Prairie State), a 1,600 megawatt coal-fueled electricity generation plant and adjacent coal mine in Washington, St. Clair and Randolph counties in Illinois, which commenced commercial operations during 2012. We are responsible for our pro rata portion of Prairie State's production costs and marketing and selling our share of electricity generated by the facility. In January 2016, we entered into a definitive agreement to sell our subsidiary holding this participating interest in the Prairie State Energy Campus to the Wabash Valley Power Association for approximately $57 million, subject to certain customary closing adjustments and satisfaction of closing conditions.

Clean Coal Technology.   We continue to support clean coal technology development and initiatives seeking to be more energy efficient and reduce global atmospheric levels of carbon dioxide and other emissions. In China, we are the only non-Chinese equity partner in GreenGen, an integrated gasification combined cycle coal-fueled power plant near Tianjin, China that began electric generation for commercial consumption in 2012 and plans to utilize carbon capture and storage (CCS) in its next stage of development. We are also a founding member of the U.S.-China Energy Cooperation Program. In Australia, we have an ongoing commitment to the Australian COAL21 Fund, an industry effort to pursue a collection of low-carbon emission technologies in Australia, and are also a founding member of the Global Carbon Capture and Storage Institute, an international initiative launched by the Australian government. In the U.S., we are a founding member of the FutureGen Alliance in Illinois and continued to support the development of the FutureGen 2.0 project until the Department of Energy funding was terminated in 2015. We are also a founding member of the Consortium for Clean Coal Utilization at Washington University in St. Louis and support technology development at the University of Wyoming School of Energy Resources. During 2015, Peabody acknowledged the lowest SO ₂ , NO _X and CO ₂ emitting coal plants globally and in India, Europe, Asia (excluding China) and the U.S. through our Advanced Energy for Life Clean Coal Awards.

Coal Supply Agreements

Customers. Our coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers. Most of our sales (excluding trading transactions) are made under long-term coal supply agreements (those with initial terms longer than one year and which often include price reopener and/or extension provisions). A smaller portion of our sales are made under contracts with terms of less than one year, including sales made on a spot basis. Sales under long-term coal supply agreements comprised approximately 88% , 83% and 80% of our worldwide sales from our mining operations (by volume) for the years ended December 31, 2015 , 2014 and 2013 , respectively.

For the year ended December 31, 2015 , we derived 26% of our total revenues from our five largest customers. Those five customers were supplied primarily from 31 coal supply agreements (excluding trading transactions) expiring at various times from 2016 to 2026. The contract contributing the greatest amount of annual revenue in 2015 was approximately $ 285 million , or approximately 5% of our 2015 total revenues, and is due to expire in 2026.

Backlog. Our sales backlog (excluding trading transactions), which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 690 million and 800 million tons of coal as of January 1, 2016 and 2015 , respectively. Contracts in backlog have remaining terms ranging from one to 12  years and represent approximately three years of production based on our 2015 production volume of 208.7 million  tons. Approximately 74% of our backlog is expected to be filled beyond 2016 .

U.S. Mining Operations.   Revenues from our Powder River Basin Mining, Western U.S. Mining and Midwestern U.S. Mining segments, in aggregate, represented approximately 63%, 59% and 57% of our total revenue base for the years ended December 31, 2015 , 2014 and 2013 , respectively, during which periods the coal mining activities of those segments contributed respective aggregate amounts of approximately 83%, 83% and 84% of our sales volumes from mining operations. We expect to continue selling a significant portion of our Powder River Basin Mining, Western U.S. Mining and Midwestern U.S. Mining segment coal production under long-term supply agreements, and customers of those segments continue to pursue long-term sales agreements in recognition of the importance of reliability, service and predictable coal prices to their operations. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of those agreements vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Our approach is to selectively renew, or enter into new, long-term supply agreements when we can do so at prices we believe are favorable.

Australian Mining Operations.   Revenues from our Australian Metallurgical Mining and Australian Thermal Mining segments represented approximately 36%, 39% and 41% of our total revenue base for the years ended December 31, 2015 , 2014 and 2013 , respectively, during which periods the coal mining activities of those segments contributed respective amounts of 17% , 17% and 16% of our sales volumes from mining operations. Our production is primarily sold into the seaborne metallurgical and thermal markets, with a majority of those sales executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Industry commercial practice, and our typical practice, is to negotiate pricing for those metallurgical and seaborne thermal coal contracts on a quarterly and annual basis, respectively, with a portion sold and priced on a shorter-term basis. The portion of volume priced on a shorter-term basis has increased in recent years.

Transportation

Methods of Distribution. Coal consumed in the U.S. is usually sold at the mine with transportation costs borne by the purchaser. Our Australian export coal is usually sold at the loading port, with purchasers paying ocean freight. Our U.S. export coal is more typically sold on a delivered basis into the unloading port, and we pay ocean freight. In each case, exporters usually pay shipping costs from the mine to the port, including any demurrage costs (fees paid to third-party shipping companies for loading time that exceeded the stipulated time).

We believe we have good relationships with U.S. and Australian rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators. Refer to the table on page 4 in the foregoing "Mining Segments" section for a summary of transportation methods by mine.

Export Facilities. Our U.S. Mining operations exported 0%, 1% and 2% of its annual tons sold for the years ended December 31, 2015 , 2014 and 2013 , respectively. The primary ports used for U.S. exports are the United Bulk Terminal near New Orleans, Louisiana, the St. James Stevedoring Anchorages terminal in Convent, Louisiana and the Kinder Morgan terminal near Houston, Texas. In connection with our Trading and Brokerage operations, we also utilize the Dominion Terminal Associates coal terminal in Newport News, Virginia to export coal sourced from domestic third-party producers. We periodically assess opportunities for access to West Coast port facilities that will allow us to export our Powder River Basin coal products to serve demand in the Asian region, should market conditions warrant.

Our Australian Mining operations sold approximately 77%, 77% and 75% of its tons into the seaborne coal markets for the years ended December 31, 2015 , 2014 and 2013 , respectively. We have generally secured our ability to transport coal in Australia through rail and port contracts and interests in five east coast coa l export terminals that are primarily funded through take-or-pay arrangements (Refer to the "Liquidity and Capital Resources" section in Part II, Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information on our take-or-pay obligations). In Queensland, seaborne metallurgical and thermal coal from our mines is exported through the Dalrymple Bay Coal Terminal, in addition to the Abbot Point Coal Terminal used by our joint venture Middlemount Mine. In New South Wales, our primary ports for exporting metallurgical and thermal coal are at Port Kembla and Newcastle, which includes both the Port Waratah Coal Services terminal and the terminal operated by Newcastle Coal Infrastructure Group (NCIG).

Suppliers

Mining Supplies and Equipment. The principal goods we purchase in support of our mining activities are mining equipment and replacement parts, diesel fuel, ammonium-nitrate and emulsion-based explosives, off-the-road (OTR) tires, steel-related products (including roof control materials), lubricants and electricity. We have many well-established, strategic relationships with our key suppliers of goods and do not believe that we are overly dependent on any of our individual suppliers.

Historically, there has been some consolidation in the supplier base providing mining materials to the coal industry for certain of these goods, such as explosives in the U.S. and both surface and underground mining equipment globally, which has limited the number of sources for these materials. In situations where we have elected to concentrate a large portion of our purchases with one supplier in lieu of seeking other alternatives, it has been to take advantage of cost savings from larger volumes of purchases, benefit from long-term pricing for parts, ensure security of supply and/or allow for equipment fleet standardization. Supplier concentration related to our mining equipment also allows us to benefit from fleet standardization, which in turn improves asset utilization by facilitating the development of common maintenance practices across our global platform and enhancing our flexibility to move equipment between mines as necessary.

Surface and underground mining equipment demand and lead times have remained suppressed in recent periods due to challenged market conditions experienced across several extractive industry sectors. This is consistent with a decline in our own near-term demand for such equipment as we have sought to defer new and early stage development projects, while continuing to evaluate the timing associated with such projects based on changes in global coal market demand. We continue to use our global leverage with major suppliers to either ensure security of supply to meet the requirements of our active projects or to delay deliveries when warranted by coal market conditions.

Services. We also purchase services at our mine sites, including services related to maintenance for mining equipment, construction, temporary labor and other various contracted services, such as contract mining for both production and development and explosive services. We do not believe that we have undue operational or financial risk associated with our dependence on any individual service providers.

Technical Innovation

We continue to advance new technologies to maximize safety, including partnering with the Mine Safety and Health Administration (MSHA) and other government agencies to identify and test emerging safety technologies. We also partner with other companies and certain governmental agencies to pursue new technologies that have the potential to improve our safety performance and provide better safety protection for employees. We are currently exploring, implementing or using leading technology to assist with proximity detection and fatigue monitoring.

We pursue technical innovation to improve equipment performance and operating efficiencies. Development is typically undertaken and funded by equipment suppliers with our engineering, maintenance, continuous improvement and purchasing personnel providing input and expertise to suppliers to design and produce equipment that we believe will improve our safety, operating performance and mining capabilities.

We seek to deploy the best mining technologies available based on the specific geologic conditions of each of our mining operations. For example, we completed the commissioning of longwall top coal caving technology at our North Goonyella Mine in Australia in 2014 and in 2015, working with the manufacturer, have improved the design of the equipment to improve safety of the system for future longwall panels.

We leverage technology and data systems to enhance our operating and maintenance efforts through the integration of original equipment manufacturer systems, mobile technology solutions and automated reporting systems to provide an integrated, real time picture of our mining operations and equipment performance. We continue to advance the use of technology applications to schedule trains, monitor coal quality and customer shipments and manage mine operations and pit blending to enhance reliability and product consistency.

We employ maintenance standards based on reliability-centered maintenance practices at all operations to increase equipment utilization and reduce maintenance and capital spending over time by extending equipment life, while reducing the risk of premature failures. Specialized maintenance reliability software is used at many operations to better support improved equipment strategies, predict equipment condition and aid analysis necessary to continually improve component life, operator training and equipment reliability.

During 2015, Peabody has expanded several innovative programs to enhance safety and reduce costs, including;

Competition

Demand for coal and the prices that we will be able to obtain for our coal are influenced by factors beyond our control, including global economic conditions, the demand for electricity and steel, the cost of alternative fuels, the impact of weather on heating and cooling demand and taxes and environmental regulations imposed by the U.S. and foreign governments.

The markets in which we sell our coal are highly competitive. We compete directly with other coal producers and, with respect to our thermal coal products, also with producers of other energy products that provide an alternative to coal use. Metallurgical coal demand is also impacted by competing technologies used to make steel, some of which do not use coal as a manufacturing input. We compete on the basis of coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.

The use of thermal coal is heavily influenced by the availability and relative cost of alternative fuels, with customers focused on securing the lowest cost fuel supply in order to produce electric power reliably at a competitive price. Alternative fuels to thermal coal include natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power sources.

Due to domestic growth in the use of hydraulic fracturing, natural gas is the most significant substitute to thermal coal for electricity generation in the U.S., and vice versa. We believe the economics of gas-to-coal switching enable demand for thermal coals produced in the U.S. Powder River and Illinois basins in which we produce to benefit when natural gas prices rise above a range of $2.50 to $2.75 per mmBtu and $3.50 to $3.75 per mmBtu, respectively, and to decline when natural gas prices fall below those levels. The U.S. Energy Information Administration (EIA) reported in its February 2016 “Short Term Energy Outlook” that coal’s share of U.S. electricity generation for all sectors was 33% in 2015, down from 39% in 2014.  Electricity generation from coal was negatively impacted by a 40% decline in average U.S. natural gas prices, which fell to an average price of $2.63 per mmBtu in 2015.  The EIA expects full year average U.S. natural gas prices to remain in line with 2015 prices at an average of $2.64 per mmBTU.    

Our principal U.S. direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners, Alpha Natural Resources, Inc., Arch Coal, Inc., the Cline Group and Cloud Peak Energy Inc., which collectively accounted for approximately 37% of total U.S. coal production in 2014 according to the National Mining Association's "2014 Coal Producer Survey," the most recent data publicly available as of March 15, 2016 . Major international direct competitors (listed alphabetically) include Anglo-American PLC, BHP Billiton, China Coal, Glencore PLC, PT Bumi Resources Tbk., Rio Tinto and Shenhua Group.

Working Capital

We generally fund our working capital requirements through a combination of existing cash and cash equivalents and proceeds from the sale of our coal production to customers and our trading and brokerage activities. Our revolving credit facility (as amended, the 2013 Revolver) under our secured credit agreement entered into in 2013 (as amended, the 2013 Credit Facility), which was fully drawn in February 2016 as a means to provide us with the maximum amount of control and flexibility with respect to our liquidity position, and our accounts receivable securitization program, which expires in April 2016, are also available to fund our working capital requirements. The Company has started the process of renewing the Accounts Receivable Securitization program. Refer to the "Liquidity and Capital Resources" section of Part II, Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information regarding working capital.

⁽¹⁾     As of March 8, 2016 .

Glenn L. Kellow was named our President and Chief Operating Officer in August 2013, our President, Chief Executive Officer-elect and a director in January 2015 and our President and Chief Executive Officer in May 2015. Mr. Kellow has extensive experience in the global resource industry, where he has served in multiple executive, operational and financial roles in coal and other commodities in the United States, Australia and South America. From 1985 to 2013, Mr. Kellow served in a number of roles with BHP Billiton, the world’s largest mining company, including senior appointments as President, Aluminum and Nickel (2012-2013), President, Stainless Steel Materials (2010-2012), President and Chief Operating Officer, New Mexico Coal (2007-2010), and Chief Financial Officer, Base Metals (2003-2007). He is a director and executive committee member of the World Coal Association, the U.S. National Mining Association and the International Energy Agency Coal Industry Advisory Board. He is the former Chairman of Worsley Alumina in Australia, Chairman of Mozal in Mozambique, and Chairman of the global Nickel Institute. In addition, he is a past member of the executive committee of the Western Australian Chamber of Minerals and Energy and the advisory board of the Energy and Mining Institute of the University of Western Australia. Mr. Kellow is a graduate of the advanced management program at the University of Pennsylvania’s Wharton School of Business and holds a master’s degree in business administration and a bachelor’s degree in commerce from the University of Newcastle.  He holds an honorary Doctor of Science degree from the South Dakota School of Mines and Technology.

Amy B. Schwetz was named our Executive Vice President and Chief Financial Officer in July 2015. Ms. Schwetz serves as our principal accounting officer. She has previously served as our Senior Vice President of Finance and Administration - Australia, from June 2013 to June 2015; Senior Vice President of Finance and Administration - Americas, from March 2012 to June 2013; Vice President of Investor Relations, from December 2011 to March 2012; Vice President of Capital and Financial Planning, from November 2009 to December 2011; Director of Financial Planning, from August 2007 to October 2009; and Director of Compliance and Accounting Policies, from August 2005 to August 2007. Prior to joining us, Ms. Schwetz was employed by Ernst & Young LLP, an international accounting firm, where she held multiple audit roles over eight years. She holds a bachelor’s degree in Accounting from Indiana University, and is a Certified Public Accountant.

Bryan A. Galli was named our Group Executive of Marketing and Trading in March 2014.  He has executive responsibility for our Global Marketing and Trading Group, with oversight of sales, marketing, logistics and trading and brokerage activities across the global enterprise. Mr. Galli has held a variety of roles at Peabody since 2002. He most recently served as our Group Executive of Sales and Marketing - Australia, and previously served as President of COALSALES, Group Executive for Midwest Operations and Vice President of Sales and Marketing for COALSALES in the Midwestern U.S. Mr. Galli holds a Bachelor of Science in mining engineering from the School of Mines at the University of Missouri (Rolla) (now called the Missouri University of Science and Technology), and serves as a member of its Mining Engineering Foundation Board.

Christopher J. Hagedorn was named our Group Executive of Strategy and Development in March 2014.  He has executive responsibility for our Global Development and Strategy Group, which includes global market analytics, strategy, portfolio optimization and business development activities, along with emerging opportunities. He most recently served as our President - Asia and Trading, and previously served as our Senior Vice President Global Sales and Trading Support, Senior Vice President, Chief Procurement Officer, and Vice President - Business Performance.  Prior to joining us in August, 2006, he was an Associate Principal at McKinsey & Company in Cleveland, Ohio, where he provided management consulting services on various operations, marketing and business strategy topics to international clients in the energy, metals and mining and chemicals sectors. Mr. Hagedorn holds a Bachelor of Science in chemical engineering from Washington University in St. Louis and a Doctorate in chemical engineering from the University of California - Santa Barbara.  He is a member of the Board of Directors of the Sheldon Concert Hall in St. Louis and a member of St. Louis Children’s Hospital Board of Trustees.

Charles F. Meintjes was named our President - Australia in October 2012. He has executive responsibility for our Australia operating platform, which includes overseeing the areas of health and safety, operations, sales and marketing, product delivery and support functions. Mr. Meintjes has extensive senior operational, strategy, continuous improvement and information technology experience with mining companies on three continents. He joined us in 2007, and most recently served as Acting President - Americas. Other past positions with us include Group Executive of Midwest and Colorado Operations, Senior Vice President of Operations Improvement and Senior Vice President Engineering and Continuous Improvement. Prior to joining us, Mr. Meintjes served as a consultant to Exxaro Resources Limited in South Africa, and is a former Executive Director and Board Member for Kumba Resources Limited in South Africa. He also served on the boards of two public companies, AST Gijima in South Africa and Ticor Limited in Australia and has senior management experience in the steel and the aluminum industry with Iscor and Alusaf in South Africa. Mr. Meintjes holds dual Bachelor of Commerce degrees in accounting from Rand Afrikaans University and the University of South Africa. He is a Chartered Accountant in South Africa and completed the advanced management program at the University of Pennsylvania’s Wharton School of Business.

A. Verona Dorch was named our Executive Vice President, Chief Legal Officer, Governmental Affairs and Corporate Secretary in August 2015.  She has executive responsibility for providing comprehensive legal counsel for Peabody business activities and leads the company’s global legal compliance and government affairs functions.  From July 2006 to March 2015, she served in a variety of roles at Harsco Corporation, a diversified, worldwide industrial services company, most recently serving as its Chief Legal Officer and Chief Compliance Officer. Ms. Dorch also has experience in corporate and securities law from top-tier law firms and with the Sumitomo Chemical Co.  Ms. Dorch holds a bachelor’s degree from Dartmouth College and a Juris Doctor degree from Harvard Law School.

Andrew P. Slentz was named our Executive Vice President Human Resources and Administration in April 2014.  He has executive responsibility for organizational and employee development, benefits, compensation, international human resources, security, travel and facilities management. Mr. Slentz joined us in June 2010 as our Senior Vice President of Global Human Resources. Prior to joining us, he held senior human resource positions in the natural resources and telecommunications industries, including serving as Senior Vice President of Human Resources for People & Organization Support at Rio Tinto, Head of Human Resources for Drummond Company and Vice President of Human Resources, Commercial Development and Shared Services for BHP Billiton. Mr. Slentz holds a bachelor’s degree from Hamilton College and a master’s degree in industrial and labor relations from Cornell University.

Kemal Williamson was named our President - Americas in October 2012. He has executive responsibility for our U.S. operating platform, which includes overseeing the areas of health and safety, operations, product delivery and support functions. Mr. Williamson has more than 30 years of experience in mining engineering and operations roles across North America and Australia. He most recently served as Group Executive Operations for the Peabody Energy Australia operations. He also has held executive leadership roles across project development, as well as in positions overseeing our Western U.S., Powder River Basin and Midwest operations. Mr. Williamson joined us in 2000 as Director of Land Management. Prior to that, he served for two years at Cyprus Australia Coal Corporation as Director of Operations and managed coal operations in Australia for half a decade. He also has mining engineering, financial analysis and management experience across Colorado, Kentucky and Illinois. Mr. Williamson holds a Bachelor of Science degree in mining engineering from Pennsylvania State University as well as a Master of Business Administration degree from the Kellogg School of Management, Northwestern University in Evanston, Illinois.

Regulatory Matters — U.S.

Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations.

We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. None of our violations to date or the monetary penalties assessed have been material.

Mine Safety and Health

We are subject to health and safety standards both at the federal and state level. The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters.

MSHA is the entity responsible for monitoring compliance with the federal mine health and safety standards. MSHA has various enforcement tools that it can use, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine. Some, but not all, of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to customers.

MSHA has taken a number of actions to identify mines with safety issues, and has engaged in a number of targeted enforcement, awareness, outreach and rulemaking activities to reduce the number of mining fatalities, accidents and illnesses. There has also been an industry-wide increase in the monetary penalties assessed for citations of a similar nature.

In Part I, Item 4. "Mine Safety Disclosures" and in Exhibit 95 to this Annual Report on Form 10-K, we provide additional details on how we monitor safety performance and MSHA compliance, as well as provide the mine safety disclosures required by SEC regulations.

Black Lung

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, 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 must also 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. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits; however, the approval rate has increased following implementation of black lung provisions contained in the Affordable Care Act. The trust fund is funded by an excise tax on U.S. 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% of the gross sales price.

Environmental Laws and Regulations

We are subject to various federal, state, local and tribal environmental laws and regulations. These laws and regulations place substantial requirements on our coal mining operations, and require regular inspection and monitoring of our mines and other facilities to ensure compliance. We are also affected by various other federal, state, local and tribal environmental laws and regulations that impact our customers.

Surface Mining Control and Reclamation Act. In the U.S., the Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSM), established mining, environmental protection and reclamation standards for all aspects of U.S. surface mining and many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority. Except for Arizona, states in which we have active mining operations have achieved primary control of enforcement through federal authorization. In Arizona, we mine on tribal lands and are regulated by the OSM because the tribes do not have SMCRA authorization.

After a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can 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 public hearings and through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation obligations.

In situations where our coal resources are federally owned, the U.S. Bureau of Land Management oversees a substantive exploration and leasing process. If surface land is managed by the U.S. Forest Service, that agency serves as the cooperating agency during the federal coal leasing process. Federal coal leases also require an approved federal mining permit under the signature of the Assistant Secretary of the Department of the Interior.

The SMCRA Abandoned Mine Land Fund requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. The fee amount can change periodically. Pursuant to the Tax Relief and Health Care Act of 2006, from October 1, 2007 to September 30, 2012, the fee was $0.315 and $0.135 per ton of surface-mined and underground-mined coal, respectively. From October 1, 2012 through September 30, 2021, the fee is $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively.

Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect our U.S. coal mining operations both directly and indirectly.

Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to particulate matter (PM), sulfur dioxide and ozone. It is possible that modifications to the national ambient air quality standards (NAAQS) could directly impact our mining operations in a manner that includes, but is not limited to, requiring changes in vehicle emissions standards or resulting in newly designated non-attainment areas. Furthermore, the U.S. Environmental Protection Agency (EPA) in 2009 adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. Since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions.

The CAA indirectly, but more significantly, affects the U.S. coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury, PM and other substances emitted by coal-fueled electricity generating plants. The air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, interstate transport rules, New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and New Source Review.  In addition, in recent years the EPA has adopted more stringent NAAQS for PM, nitrogen oxide and sulfur dioxide. In November 2014, the EPA proposed a more stringent NAAQS for ozone. Issuance of the proposed rule complies with a decision of the U.S. District Court for the Northern District of California in April 2014 ordering the EPA to propose a new ozone NAAQS by December 1, 2014 and issue a final rule by October 1, 2015. On October 1, 2015, the EPA issued a final rule setting the ozone standard at 70 parts per billion (ppb). More stringent standards may trigger additional control technology for mining equipment, or result in additional challenges to permitting and expansion efforts. Many of these air emissions programs and regulations, including the 2015 ozone standard, have resulted in litigation which has not been completely resolved.

Proposed NSPS for Fossil Fuel-Fired Electricity Utility Generating Units (EGUs). On April 13, 2012, the EPA published for comment a proposed NSPS for emissions of carbon dioxide for new, modified and reconstructed fossil fuel-fired EGUs (proposed NSPS for new power plants). On September 20, 2013, the EPA revoked its April 13, 2012 proposal and issued a new proposed NSPS for new power plants, using section 111(b) of the CAA. On January 8, 2014, the re-proposal was published in the Federal Register. In the February 26, 2014 Federal Register, the EPA issued a Notice of Data Availability (NODA) and technical support document in support of the proposed NSPS for new power plants. After extensions, the public comment period for the re-proposed NSPS and the NODA closed on May 9, 2014. The EPA released the final rule on August 3, 2015, and published it in the Federal Register on October 23, 2015.

The final rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb CO2/MWh-gross. The standard is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture and storage (CCS). Modified and reconstructed fossil fuel fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance. Reconstructed units must implement the most efficient generating technology based on the size of the unit (supercritical steam conditions for larger units, to meet a standard of 1,800 lb CO2/MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb CO2/MWh-gross.).

Numerous legal challenges to the final rule have been filed in the United States Court of Appeals (D.C. Circuit). Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody Energy), labor unions, trade organizations and other groups. The cases have been consolidated under the case filed by North Dakota. States and other organizations have intervened on behalf of the EPA. A briefing and argument schedule has not been set by the Court.

Proposed Rules for Regulating Carbon Dioxide Emissions From Existing Fossil Fuel-Fired EGUs. On June 2, 2014, the EPA issued and later formally published for comment proposed rules for regulating carbon dioxide emissions from existing fossil fuel-fired EGUs under section 111(d) of the CAA. On August 3, 2015, the EPA announced the final rule, and published the rule in the Federal Register on October 23, 2015. In the final rule, the EPA is establishing final emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs. These final guidelines require that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders. Individual states are required to submit their proposed implementation plans to the EPA by September 6, 2016, unless an extension is approved, in which case the states will have until September 6, 2018. The rule sets emission performance rates to be phased in over the period from 2022 through 2030. The rule is intended to reduced carbon dioxide emissions from the 2005 baseline by 28% in 2025 and 32% in 2030.  

Legal challenges to the rule began when it was still being proposed. One action by an industry petitioner, joined by intervenors, including us, and another by a coalition of states led by West Virginia, asserted that the EPA does not have the authority to issue the regulations of existing power plants under section 111(d) of the CAA. The D.C. Circuit heard oral arguments on the challenges in April 2015. The petitions to enjoin the proposed rulemaking were denied as premature in June 2015.  However, the D.C. Circuit court acknowledged that a legal challenge could be filed after the EPA issued a final rule.  In September 2015 the D.C. Circuit Court refused to stay the rule, holding that it could not review the rule until it was published in the Federal Register which is occurred on October 23, 2015. 

Since Federal Register publication on October 23, 2015, 39 separate petitions for review by approximately 157 entities have been filed in the U.S. Court of Appeals for the D.C. Circuit challenging the final rule. The petitions reflect challenges by 27 states and governmental entities, as well as challenges by utilities, industry groups, trade associations, coal companies, and other entities.  All together, the petitions include legal challenges by over 100 entities.  The lawsuits have been consolidated with the case filed by West Virginia and Texas (in which other States have also joined).  On October 29, 2015, we filed a motion to intervene in the case filed by West Virginia and Texas, in support of the petitioning States.  The motion was granted on January 11, 2016. Numerous states and cities have also been allowed to intervene in support of EPA.

On January 21, 2016, the D.C. Circuit Court denied the state and industry petitioners’ motions to stay the implementation of the rule but provided for an expedited schedule for review of the rule, with oral arguments beginning on June 2, 2016. The state and industry petitioners appealed and filed application for state with the United States Supreme Court on January 27, 2016. On February 9, 2016, the Supreme Court overruled the lower court and granted the motion to stay implementation of the rule until its legal challenges are resolved.

EPA's Greenhouse Gas (GHG) Permitting Regulations for Major Emission Sources. In December 2009, the EPA published its finding that atmospheric concentrations of greenhouse gases endanger public health and welfare within the meaning of the CAA, and that emissions of greenhouse gases from new motor vehicles and motor vehicle engines are contributing to air pollution that are endangering public health and welfare within the meaning of the CAA. In May 2010, the EPA published final greenhouse gas emission standards for new motor vehicles pursuant to the CAA.  Also in May 2010, the EPA published final rules requiring permitting and control technology requirements for GHGs under the Prevention of Significant Deterioration (PSD) and Title V permitting programs, for major stationary emission sources, as defined by statutory emission thresholds, finding that such rules were necessitated or “triggered” by the EPA’s regulation of GHG’s from motor vehicles. These rules were upheld by the U.S. Court of Appeals (D.C. Circuit) on June 26, 2012. The U.S. Supreme Court granted certiorari to review the limited question of whether the EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases. On June 23, 2014, the U.S. Supreme Court ruled that EPA could not require PSD and Title V permitting for stationary sources that were not otherwise major sources of conventional pollutants, based solely on their potential GHG emissions. The Court upheld EPA’s rule that a major emission source that is subject to the PSD program because of its emission of conventional pollutants must also employ the best available control technology for GHGs that exceed a certain threshold as determined by the EPA. EPA now requires sources that are otherwise “major” sources of conventional pollutants to apply best available control technology for GHG emissions, if those emissions would have the potential to exceed 75,000 tons per year. Individual states may have additional permitting requirements for GHGs.

Cross State Air Pollution Rule (CSAPR). On July 6, 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions was to commence in 2012 with further reductions effective in 2014. In October 2011, the EPA proposed amendments to the CSAPR to increase emission budgets in ten states, including Texas, and ease limits on market-based compliance options. While the CSAPR had an initial compliance deadline of January 1, 2012, the rule was challenged and, on December 30, 2011, the D.C. Circuit stayed the rule and advised that the EPA was expected to continue administering the Clean Air Interstate Rule until the pending challenges are resolved. The court vacated the CSAPR on August 21, 2012, in a two-to-one decision, concluding that the rule was beyond the EPA's statutory authority. The U.S. Supreme Court on April 29, 2014 reversed the D.C. Circuit and upheld the CSAPR, concluding generally that the EPA’s development and promulgation of CSAPR was lawful, while acknowledging the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. In October 2014, the D.C. Circuit filed an order lifting its stay of CSAPR and addressing a number of preliminary motions regarding the implementation of the Supreme Court’s remand. On remand, the D.C. Circuit court held on July 28, 2015 that certain of EPA’s Phase II emission budgets were invalid because they required more emissions reductions than necessary to achieve the desired air pollutant reduction in the relevant downwind states. The court did not vacate the rule but required the EPA to reconsider the invalid emissions budgets as to those states. On November 16, 2015, the EPA proposed the CSAPR Update Rule to address implementation of the 2008 ozone national air quality standards, proposing further reductions in nitrogen oxides to begin in 2017 in 23 states subject to CSAPR.

Mercury and Air Toxic Standards (MATS). On December 16, 2011, the EPA announced the MATS rule and published it in the Federal Register on February 16, 2012. The MATS rulemaking collectively revised the NSPS for nitrogen oxides, sulfur dioxides and particulate matter for new and modified coal-fueled electricity generating plants, and imposed Maximum Achievable Control Technology (MACT) emission limits on hazardous air emissions from new and existing coal-fueled and oil-fueled electric generating plants. The rule provided three years for compliance and a possible fourth year as a state permitting agency may deem necessary. Some utilities have been moving forward with installation of equipment necessary to comply with MATS, and the EPA and states have been granting additional time beyond the 2015 deadline (but no more than one extra year) for facilities that needed more time to upgrade and complete those installations. The D.C. Circuit upheld the NSPS portion of the rulemaking in a unanimous decision on March 11, 2014, and upheld the limits on hazardous air emissions against all challenges on April 15, 2014, in a two-to-one decision. Industry groups and a number of states filed and were granted review of the D.C. Circuit decision in the U.S. Supreme Court. On June 29, 2015 the U.S. Supreme Court held that the EPA interpreted the CAA unreasonably when it deemed cost irrelevant to the decision to regulate power plants. The court reversed the D.C. Circuit Court and remanded the case for further proceedings. On December 1, 2015, in response to the court’s decision the EPA published in the Federal Register a proposed supplemental finding that consideration of costs does not alter the EPA’s previous determination to implement the MATS rule. On December 15, 2015, the D.C. Circuit Court issued an order providing that the rule will remain in effect while the EPA responds to the U.S. Supreme Court decision.

Stream Protection Rule. On July 27, 2015, the OSM issued its proposed Stream Protection Rule (SPR). The proposed rule would impact both surface and underground mining operations and would increase testing and monitoring requirements related to the quality or quantity of surface water and groundwater or the biological condition of streams.  The SPR will also require the collection of increased pre-mining data about the site of the proposed mining operation and adjacent areas to establish a baseline for evaluation of the impacts of mining and the effectiveness of reclamation associated with returning streams to pre-mining conditions.  The SPR was issued as a result of the D.C. Circuit Court’s decision in 2014 to vacate the then existing Stream Buffer Zone Rule. Peabody along with many other groups and operators have responded with to the proposed rule via the public comment process, which ended October 26, 2015. The final rule is expected in August 2016.

Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.

The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain Corps permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.

States are empowered to develop and apply “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. 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. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.

A draft rule called the Waters of the United States (WOTUS) was proposed by the EPA in June 2014. A preliminary injunction was issued by the U.S. District Court in North Dakota in August 2015 and, on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit stayed the Clean Water Rule nationwide pending further action of the court. If CWA authority is eventually expanded, it may impact our operations in some areas by way of additional requirements.

National Environmental Policy Act (NEPA). NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. We must provide information to agencies when we propose actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes.

Resource Conservation and Recovery Act (RCRA). RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are those from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA.

Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. On December 19, 2014, the EPA announced the final rule on coal combustion residuals (that is, coal ash). As finalized, the rule continues the exemption of CCR from regulation as a hazardous waste, but does impose new requirements at existing CCR surface impoundments and landfills that will need to be implemented over a number of different time-frames in the coming months and years, as well as at new surface impoundments and landfills. Generally these requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous. This EPA initiative is separate from the OSM CCR rulemaking mentioned above.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). Although generally not a prominent environmental law in the coal mining sector, CERCLA, which was enacted in 1980, nonetheless may affect U.S. coal mining operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under CERCLA, joint and several liabilities may be imposed on waste generators, site owners or operators and others, regardless of fault.

Toxic Release Inventory. Arising out of the passage of the Emergency Planning and Community Right-to-Know Act in 1986 and the Pollution Prevention Act passed in 1990, the EPA's Toxic Release Inventory program requires companies to report the use, manufacture or processing of listed toxic materials that exceed established thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.

Endangered Species Act (ESA). The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on our costs or our ability to mine some of our properties in accordance with our current mining plans.

Use of Explosives. Our 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. The storage of explosives is subject to strict federal regulatory requirements. The U.S. Bureau of Alcohol, Tobacco and Firearms (ATF) regulates the use of explosive blasting materials. In addition to ATF regulation, the Department of Homeland Security is expected to finalize an ammonium nitrate security program rule. The OSM has also recently initiated a rulemaking addressing nitrous clouds that may be produced during blasting. While such new regulations may result in additional costs related to our surface mining operations, such costs are not expected to have a material adverse effect on our results of operations, financial condition or cash flows.

Regulatory Matters — Australia

The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines) and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed.

Native Title and Cultural Heritage.   Since 1992, the Australian courts have recognized that native title to lands, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the Federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established. Native title rights do not extend to minerals; however, native title rights can be affected by the mining process unless those rights have previously been extinguished thereby requiring negotiation with the traditional owners (and potentially the payment of compensation) prior to the grant of certain mining tenements. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.

Mining Tenements and Environmental.   In Queensland and New South Wales, the development of a mine requires both the grant of a right to extract the resource and an approval which authorizes the environmental impact. These approvals are obtained under separate legislation from separate government authorities. However, the application processes run concurrently and are also concurrent with any native title or cultural heritage process that is required. The environmental impacts of mining projects are regulated by state and federal governments. Federal regulation will only apply if the particular project will significantly impact a matter of national environmental significance (for example, a water resource, an endangered species or particular protected places). Environmental approvals processes involve complex issues that, on occasion, require lengthy studies and documentation. Typically mining proponents must also reach agreement with the owners of land underlying proposed mining tenements prior to the grant and/or conduct of mining activities or otherwise acquire the land. These arrangements generally involve the payment of compensation in lieu of the impacts of mining on the land.

Our Australian mining operations are generally subject to local, state and federal laws and regulations. At the federal level, these legislative acts include, but are not limited to, the Environment Protection and Biodiversity Conservation Act 1999, Native Title Act 1993, Fair Work Act 2009 and the Aboriginal and Torres Strait Islander Heritage Protection Act 1984.

In Queensland, laws and regulations related to mining include, but are not limited to, the Mineral Resources Act 1989, Environmental Protection Act 1994 (EP Act), Environmental Protection Regulation 1998, Sustainable Planning Act 2009, Building Act 1975, Explosives Act 1999, Aboriginal Cultural Heritage Act 2003, Water Act 2000, State Development and Public Works Organisation Act 1971, Queensland Heritage Act 1992, Transport Infrastructure Act 1994, Nature Conservation Act 1992, Vegetation Management Act 1999, Land Protection (Pest and Stock Route Management) Act 2002, Land Act 1994, Regional Planning Interests Act 2014, Fisheries Act 1994 and Forestry Act 1959. Under the EP Act, policies have been developed to achieve the objectives of the law and provide guidance on specific areas of the environment, including air, noise, water and waste management. State planning policies address matters of Queensland State interest, and must be adhered to during mining project approvals. Increased emphasis has recently been placed on topics including, but not limited to, hazardous dams assessment and the protection of strategic cropping land. The Mineral Resources Act 1989 is currently undergoing a thorough review and revision including significant changes to the management of overlapping coal and coal seam gas tenements and the coordination of activities. It is expected these new laws will come into effect in late 2016.

In New South Wales, laws and regulations related to mining include, but are not limited to, the Mining Act 1992, Work Health and Safety (Mines) Act 2013, Mine Subsidence Compensation Act 1961, Environmental Planning and Assessment Act 1979 (EP&A Act), Environmental Planning and Assessment Regulations 2000, Protection of the Environment Operations Act 1997, Contaminated Land Management Act 1997, Explosives Act 2003, Water Management Act 2000, Water Act 1912, Radiation Control Act 1990, Heritage Act 1977, Aboriginal Land Rights Act 1983, Crown Lands Act 1989, Dangerous Goods (Road and Rail Transport) Act 2008, Fisheries Management Act 1994, Forestry Act 1916, Native Title (New South Wales) Act 1994, Native Vegetation Act 2003, Noxious Weeds Act 1993, Roads Act 1993 and National Parks & Wildlife Act 1974. Under the EP&A Act, environmental planning instruments must be considered when approving a mining project development application. There are multiple State Environmental Planning Policies (SEPPs) relevant to coal projects in New South Wales. Amendments to the SEPPs that cover mining have occurred in the past two years and are aimed at protecting agriculture, water resources and critical industry clusters. One SEPP, referred to as the Mining SEPP, was amended in late 2013 to make it mandatory for decision makers to consider the economic significance of coal resources when determining a development application for a mine and to give primacy to that consideration. This amendment was repealed in 2015. However, decision makers still have regard to the significance of a resource and the State and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” head of consideration contained in the legislation.

Occupational Health and Safety.   State legislation requires us to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision. In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry. There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation.

In light of the recent discovery of six cases of pneumoconiosis in current and former coal mine workers in Queensland, the Department of Natural Resources has commissioned a review of the current coal mine workers’ health assessment process to ensure it is effective in the early detection of respirable lung diseases such as pneumoconiosis.

Industrial Relations.   A national industrial relations system administered by the federal government applies to all private sector employers and employees. The matters regulated under the national system include employment conditions, unfair dismissal, enterprise bargaining, bullying claims, industrial action and resolution of workplace disputes. Many of the workers employed in our mines are covered by enterprise agreements approved under the national system.

National Greenhouse and Energy Reporting Act 2007 (NGER Act).   In 2007, a single, national reporting system relating to greenhouse gas emissions, energy use and energy production was introduced. The NGER Act imposes requirements for corporations meeting a certain threshold to register and report greenhouse gas emissions and abatement actions, as well as energy production and consumption. The Clean Energy Regulator administers the NGER Act. The Department of Environment is responsible for NGER Act-related policy developments and review. Both foreign and local corporations that meet the prescribed carbon dioxide and energy production or consumption limits in Australia (Controlling Corporations) must comply with the NGER Act. One of our subsidiaries is now registered as a Controlling Corporation and must report annually on the greenhouse gas emissions and energy production and consumption of our Australian entities.

On July 1, 2016, amendments to the NGER Act will come into force which implement the Emission Reduction Fund Safeguard Mechanism.  From that date, large designated facilities such as coal mines will be issued with a baseline for their covered emissions and must take steps to keep their emissions below the baseline or face penalties.

Queensland Royalty . In September 2012, the State of Queensland announced new royalty rates on coal prices. The royalty change went into effect on October 1, 2012 and raised the royalty payment to the State of Queensland on coal prices over $100 Australian dollars per tonne from 10% to 12.5% for pricing up to $150 Australian dollars per tonne and 15% on pricing over $150 Australian dollars per tonne. There was no change to the 7% rate for coal sold below $100 Australian dollars per tonne. The periodic impact of these royalty rates is dependent upon the volume of tonnes produced at each of our Queensland mining locations and coal prices received for those tonnes. The Queensland Office of State Revenue issues determinations setting out its interpretation of the laws that impose royalties and provide guidance on how royalty rates should be calculated .

New South Wales Royalty. In New South Wales, the royalty applicable to coal is charged as a percentage of the value of production (total revenue less allowable deductions). This is equal to 6.2% for deep underground mines (coal extracted at depths greater than 400 meters below ground surface), 7.2% for underground mines and 8.2% for open-cut mines.

Carbon Pricing Framework. The Australian government's carbon pricing framework commenced on July 1, 2012, with an initial carbon price of $23.00 Australian dollars per tonne of carbon dioxide equivalent emissions, scheduled to rise by 2.5% per year over a three year period and transition to an emissions trading scheme after June 30, 2015. All of our Australian operations were impacted by the fugitive emissions portion of the framework (defined as the methane and carbon dioxide which escapes into the atmosphere when coal is mined and gas is produced). On July 16, 2014, Australia's Senate voted to repeal the legislation, which was retrospectively abolished from July 1, 2014. Net of transition benefits, we recognized no expense related to the carbon pricing framework in 2015 and approximately $25 million and $40 million in 2014 and 2013, respectively. Accordingly, we anticipate a modest improvement in our future operating costs and expenses as a result of the repeal of this legislation.

Global Climate

In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date nothing has been enacted. While it is possible that the U.S. will adopt legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of new U.S. federal legislation, the EPA is undertaking steps to regulate greenhouse gas emissions pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA has commenced several rulemaking projects as described under “Regulatory Matters-U.S. - Environmental Laws and Regulations.” In particular, on August 3, 2015, the EPA announced the final rules (which were published in the Federal Register on October 23, 2015) for regulating carbon dioxide emissions from existing and new fossil fuel-fired EGUs. EPA has set emission performance rates for existing plants to be phased in over the period from 2022 through 2030. This rule is intended to reduce carbon dioxide emissions from the 2005 baseline by 28% in 2025 and 32% in 2030. EPA has also set standards applying to new, modified and reconstructed sources beginning in 2015.

A number of states in the U.S. have adopted programs to regulate greenhouse gas emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, which is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. In 2011, New Jersey announced its withdrawal from RGGI effective January 1, 2012. Six midwestern states (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) and one Canadian province have entered into the Midwestern Regional Greenhouse Gas Reduction Accord (MGGRA) to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets. It has been reported that, while the MGGRA has not been formally suspended, the participating states are no longer pursuing it. Seven western states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces entered into the Western Climate Initiative (WCI) in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions. However, in November 2011, the WCI announced that six states had withdrawn from the WCI, leaving California and four Canadian provinces as the remaining members. Of those five jurisdictions, only California and Quebec have adopted greenhouse gas cap-and-trade regulations to date and both programs have begun operating. Many of the states and provinces that left WCI, RGGI and MGGRA, along with many that continue to participate, have joined the new North America 2050 initiative, which seeks to reduce greenhouse gas emissions and create economic opportunities in ways not limited to cap-and-trade programs.

In the U.S., several states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. Some states have initiated public utility proceedings that may establish values for carbon emissions. In a proceeding before the Minnesota Public Utilities Commission, a decision by an Administrative Law Judge is expected in April 2016 in which she will either recommend acceptance or rejection of (1) the Federal Social Cost of Carbon, (2) a different externality value or (3) maintenance of the current externality value.

We participated in the Department of Energy's Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and regularly disclose in our Corporate and Social Responsibility Report the quantity of emissions per ton of coal produced by us in the U.S. The vast majority of our emissions are generated by the operation of heavy machinery to extract and transport material at our mines and fugitive emissions from the extraction of coal.

In 2013, the U.S. and a number of international development banks, including the World Bank, the European Investment Bank and the European Bank for Reconstruction and Development, announced that they would no longer provide financing for the development of new coal-fueled power plants or would do so only in narrowly defined circumstances. Other international development banks, such as the Asian Development Bank and the Japanese Bank for International Cooperation, have continued to provide such financing.

The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of greenhouse gas emission targets for developed nations. The U.S. signed the Kyoto Protocol but it has never been ratified by the U.S. Senate. Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008.  There were discussions to develop a treaty to replace the Kyoto Protocol after the expiration of its commitment period in 2012, including at the UNFCCC conferences in Cancun (2010), Durban (2011), Doha (2012) and Paris (2015). At the Durban conference, an ad hoc working group was established to develop a protocol, another legal instrument or an agreed outcome with legal force under the UNFCCC, applicable to all parties. At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which included new commitments for certain parties in a second commitment period, from 2013 to 2020. In December 2012, Australia signed on to the second commitment period. During the UNFCCC conference in Paris, France in late 2015, an agreement was adopted calling for voluntary emissions reductions contributions after the second commitment period ends in 2020. The agreement will enter into force upon ratification and execution by 55 countries that account for at least 55% of global greenhouse gas emissions.

Australia's Parliament passed carbon pricing legislation in November 2011. The first three years of the program involved the imposition of a carbon tax that commenced in July 2012 and a mandatory greenhouse gas emissions trading program commencing in 2015. On July 16, 2014, Australia's Parliament repealed the legislation, which was retrospectively abolished from July 1, 2014.

Enactment of laws or passage of regulations by the U.S. or some of its states or by other countries regarding emissions from the mining of coal, or other actions to limit such emissions, are not expected to have a material adverse effect on our results of operations, financial condition or cash flows.

Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on us of future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of commercial development and deployment of CCS technologies and the alternative markets for coal. From time to time, we attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require that we make significant assumptions as to the specific provisions of such potential laws, regulations and policies. These analyses sometimes show that certain potential laws, regulations and policies, if implemented in the manner assumed by the analyses, could result in material adverse impacts on our operations, financial condition or cash flow, in view of the significant uncertainty surrounding each of these potential laws, regulations and policies. We do not believe that such analyses reasonably predict the quantitative impact that future laws, regulations or other policies may have on our results of operations, financial condition or cash flows.

Available Information

We file or furnish annual, quarterly and current reports (including any exhibits or amendments to those reports), proxy statements and other information with the SEC. These materials are available free of charge through our website (www.peabodyenergy.com) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information included on our website does not constitute part of this document. These materials may also be accessed through the SEC's website (www.sec.gov) or in the SEC’s Public Reference Room located at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling 1-800-SEC-0330.

In addition, copies of our filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at: Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St. Louis, Missouri 63101-1826, attention: Investor Relations.