PEABODY ENERGY CORP - Annual Report: 2015 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

FORM 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2015

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-16463

____________________________________________

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



Delaware (State or other jurisdiction of incorporation or organization)		13-4004153 (I.R.S. Employer Identification No.)
701 Market Street, St. Louis, Missouri (Address of principal executive offices)		63101 (Zip Code)

(314) 342-3400

Registrant’s telephone number, including area code

Securities Registered Pursuant to Section 12(b) of the Act:



Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share		New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Aggregate market value of the voting stock held by non-affiliates (shareholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2015: Common Stock, par value $0.01 per share, $606.1 million.

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of March 8, 2016: Common Stock, par value $0.01 per share, 18,538,665 shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company’s 2016 Annual Meeting of Shareholders (the Company’s 2016 Proxy Statement) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations. We use words such as “anticipate,” “believe,” “expect,” “may,” "forecast," “project,” “should,” “estimate,” “plan,” "outlook" or other similar words to identify forward-looking statements.

Without limiting the foregoing, all statements relating to our future operating results, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ materially are:


•	supply and demand for our coal products;


•	sustained depressed levels or further declines in coal prices;


•	competition in coal markets;


•	price volatility, particularly in international seaborne products and in our trading and brokerage businesses;


•	adequate liquidity to operate our business and service our debt obligations;


•	impacts of our high leverage and our ability to comply with the covenants in our credit agreements, particularly our leverage ratio and interest coverage covenants;


•	our ability to successfully negotiate transactions with debt holders, including debt exchanges and debt buybacks;


•	our ability to successfully consummate the planned sale of our assets in New Mexico and Colorado, including the purchaser's ability to successfully obtain financing, and the divestiture of our interest in the Prairie State Energy Campus;


•	the cost, availability and access to capital and financial markets, including the ability to secure new financing;


•	ability to appropriately secure our obligations for reclamation, federal and state workers' compensation, federal coal leases and other obligations related to our operations, including our ability to remain eligible for self-bonding and/ or successfully access the commercial surety bond market;


•	customer procurement practices and contract duration;


•	impact of alternative energy sources, including natural gas and renewables;


•	global steel demand and the downstream impact on metallurgical coal prices;


•	lower demand for our products by electric power generators;


•	impact of weather and natural disasters on demand, production and transportation;


•	reductions and/or deferrals of purchases by major customers and our ability to renew sales contracts;


•	credit and performance risks associated with customers, suppliers, contract miners, co-shippers and trading, banks and other financial counterparties;


•	geologic, equipment, permitting, site access, operational risks and new technologies related to mining;


•	transportation availability, performance and costs;


•	availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;


•	impact of take-or-pay arrangements for rail and port commitments for the delivery of coal;


•	successful implementation of business strategies, including, without limitation, the actions we are implementing to improve our organization and respond to current market conditions;


•	negotiation of labor contracts, employee relations and workforce availability, including, without limitation, attracting and retaining key personnel;


•	changes in postretirement benefit and pension obligations and their related funding requirements;


•	replacement and development of coal reserves;


•	impacts of our high leverage and our ability to comply with the covenants in our credit agreements, particularly our leverage ratio and interest coverage covenants;


•	effects of changes in interest rates and currency exchange rates (primarily the Australian dollar);


•	effects of acquisitions or divestitures;


•	economic strength and political stability of countries in which we have operations or serve customers;



Peabody Energy Corporation	2015 Form 10-K	i


•	legislation, regulations and court decisions or other government actions, including, but not limited to, new environmental and mine safety laws, regulations or requirements, changes in income tax regulations, sales-related royalties or other regulatory taxes and changes in derivatives laws and regulations;


•	our ability to obtain and renew permits necessary for our operations;


•	litigation or other dispute resolution, including, but not limited to, claims not yet asserted;


•	any additional liabilities or obligations that we may have as a result of the bankruptcy of Patriot Coal Corporation (Patriot), including, without limitation, as a result of litigation filed by third parties in relation to that bankruptcy;


•	terrorist attacks or security threats, including, but not limited to, cybersecurity threats;


•	impacts of pandemic illnesses; and


•	other factors, including those discussed in "Legal Proceedings," set forth in Part I, Item 3 of this report and "Risk Factors," set forth in Part I, Item 1A of this report.

When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (SEC) filings. These forward-looking statements speak only as of the date on which such statements were made, and we undertake no obligation to update these statements, except as required by the federal securities laws.



Peabody Energy Corporation	2015 Form 10-K	i

TABLE OF CONTENTS



		Page
PART I.
Item 1.	Business	2
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	44
Item 4.	Mine Safety Disclosures	44

PART II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	44
Item 6.	Selected Financial Data	46
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	80
Item 8.	Financial Statements and Supplementary Data	83
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	83
Item 9A.	Controls and Procedures	83
Item 9B.	Other Information	86

PART III.
Item 10.	Directors, Executive Officers and Corporate Governance	86
Item 11.	Executive Compensation	86
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	86
Item 13.	Certain Relationships and Related Transactions, and Director Independence	86
Item 14.	Principal Accountant Fees and Services	87

PART IV.
Item 15.	Exhibits and Financial Statement Schedules	87



Peabody Energy Corporation	2015 Form 10-K	1

Table of Contents



Note:	The words “we,” “our,” “Peabody” or “the Company” as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Annual Report on Form 10-K relate only to our continuing operations.
	When used in this filing, the term "ton" refers to short or net tons, equal to 2,000 pounds (907.18 kilograms), while "tonne" refers to metric tons, equal to 2,204.62 pounds (1,000 kilograms).

PART I

Item 1. Business.

Overview

We are the world’s largest private-sector coal company (by volume). As of December 31, 2015, we owned interests in 26 active coal mining operations located in the United States (U.S.) and Australia. We have a majority interest in 25 of those mining operations and a 50% equity interest in the Middlemount Mine in Australia. In addition to our mining operations, we market and broker coal from other coal producers, both as principal and agent, and trade coal and freight-related contracts through trading and business offices in Australia, China, Germany, India, the United Kingdom and the U.S. (listed alphabetically).

History and Development

We were incorporated in Delaware in 1998 and became a public company in 2001. Our history in the coal business dates back to 1883. Over the past decade, we have made strategic acquisitions and divestitures to position our company to serve U.S. and international coal markets with the highest demand. Acquisitions and divestitures of note include the following:


•	In 2006, we further expanded our presence in Australia with the acquisition of Excel Coal Limited.


•	In 2007, we spun off Patriot Coal Corporation (Patriot), which included mines in West Virginia and Kentucky and coal reserves in the Illinois Basin and Appalachia, through a dividend of all outstanding Patriot shares.


•	In 2011, we acquired PEA-PCI (formerly Macarthur Coal Limited), an independent coal company in Australia, which included two operating mines, a 50% equity-affiliate joint venture arrangement and several development projects.

In 2015, we achieved a record global safety performance for us, and we advanced operational and capital projects focused on operational efficiency and maintaining a competitive position in the market segments in which we operate. Such advancements included advancing the development at the planned Gateway North Mine in the U.S. to replace production from the existing Gateway Mine as its reserves were exhausted in the second half of 2015 and continuing our ongoing cost containment initiatives across our global platform in response to challenged global coal market segment conditions.



Peabody Energy Corporation	2015 Form 10-K	2

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Segment and Geographic Information

During the second quarter of 2015, we elected a new chief executive officer, who is also considered our chief operating decision maker (CODM). Due to that change, we updated our reportable segments to reflect the manner in which our new CODM views our businesses for purposes of reviewing performance, allocating resources and assessing future prospects and strategic execution. We now report our results of operations primarily through the following reportable segments: "Powder River Basin Mining," "Midwestern U.S. Mining," "Western U.S. Mining," "Australian Metallurgical Mining," "Australian Thermal Mining," "Trading and Brokerage" and "Corporate and Other."

Segment and geographic financial information is contained in Note 27. "Segment and Geographic Information" to our consolidated financial statements and is incorporated herein by reference.

Mining Segments

U.S. Mining Operations

The principal business of our mining segments in the U.S. is the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S. under long-term contracts, with a portion sold into the seaborne markets as market conditions warrant. Our Powder River Basin Mining operations consist of our mines in Wyoming. The mines in that segment are characterized by surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). Our Midwestern U.S. Mining operations include our Illinois and Indiana mining operations, which are characterized by a mix of surface and underground mining extraction processes, coal with a higher Btu and sulfur content and lower customer transportation costs (due to shorter shipping distances). Our Western U.S. Mining operations reflect the aggregation of our New Mexico, Arizona and Colorado mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes, and of coal with mid-range sulfur and Btu content. Geologically, our Powder River Basin Mining operations mine sub-bituminous coal deposits, our Midwestern U.S. Mining operations mine bituminous coal deposits and our Western operations mine both bituminous and sub-bituminous coal deposits.

Australian Mining Operations

The business of our Australian operating platform is primarily export focused with customers spread across several countries, while a portion of our thermal coal is sold within Australia. Generally, revenues from individual countries vary year by year based on electricity and steel demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. Our Australian Metallurgical Mining operations consist of mines in Queensland and one in New South Wales, Australia. The mines in that segment are characterized by both surface and underground extraction processes used to mine various qualities of metallurgical coal (low-sulfur, high Btu coal). The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coal and pulverized coal injection (PCI) coal. Our Australian Thermal Mining operations consist of mines in New South Wales, Australia. The mines in that segment are characterized by both surface and underground extraction processes used to mine low-sulfur, high Btu thermal coal. We classify our Australian mines within the Australian Metallurgical Mining or Australian Thermal Mining segments based on the primary customer base and coal reserve type of each mining operation. A small portion of the coal mined by the Australian Metallurgical Mining segment is of a thermal grade. Similarly, a small portion of the coal mined by the Australian Thermal Mining segment is of a metallurgical grade. Additionally, the Company may market some of its metallurgical coal products as a thermal coal product from time to time depending on market conditions.



Peabody Energy Corporation	2015 Form 10-K	3

Table of Contents

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.

Segment/Mining Complex

Location

Mine

Type

Mining

Method

Coal

Type

Primary

Transport

Method

2015 Tons Sold

(In millions)

Powder River Basin Mining

North Antelope Rochelle

Wyoming

D, DL, T/S

109.3

Rawhide

Wyoming

D, T/S

15.2

Caballo

Wyoming

D, T/S

11.4

Other ⁽¹⁾

—

2.9

Midwestern U.S. Mining

Bear Run

Indiana

DL, D, T/S

Tr, R

7.9

Francisco Underground

Indiana

2.9

Somerville Central

Indiana

DL, D, T/S

R, R/B, T/B, T/R

2.1

Wild Boar

Indiana

D, T/S

Tr, R, R/B, T/B

2.0

Wildcat Hills Underground

Illinois

T/B

1.7

Gateway ⁽²⁾

Illinois

Tr, R, R/B, T/B

1.3

Cottage Grove

Illinois

D, T/S

T/B

1.3

Somerville North

Indiana

D, T/S

Tr, R, R/B, T/B, T/R

0.8

Somerville South

Indiana

D, T/S

Tr, R, R/B, T/B,

0.7

Gateway North

Illinois

Tr, R, R/B, T/B

0.5

Western U.S. Mining

El Segundo

New Mexico

D, DL, T/S

8.1

Kayenta

Arizona

DL, T/S

6.6

Twentymile

Colorado

R, Tr

3.2

Lee Ranch

New Mexico

T/S

—

Australian Metallurgical Mining

Millennium

Queensland

D, T/S

M, P

R, EV

4.6

Coppabella ⁽³⁾

Queensland

DL, D, T/S

R, EV

2.9

North Goonyella

Queensland

LTCC

R, EV

2.7

Moorvale ⁽³⁾

Queensland

T/S

R, EV

2.3

Metropolitan

New South Wales

R, EV

2.0

Burton *

Queensland

T/S

M, T

R, EV

1.2

Middlemount ⁽⁴⁾

Queensland

T/S

M, P

R, EV

—

Australian Thermal Mining

Wilpinjong

New South Wales

D, T/S

R, EV

13.5

Wambo Open-Cut ⁽⁵⁾

New South Wales

T/S

R, EV

3.5

North Wambo Underground ⁽⁵⁾

New South Wales

M, T

R, EV

3.1



Legend:		R	Rail
S	Surface Mine	Tr	Truck
U	Underground Mine	R/B	Rail to Barge
DL	Dragline	T/B	Truck to Barge
D	Dozer/Casting	T/R	Truck to Rail
T/S	Truck and Shovel	EV	Export Vessel
LW	Longwall	T	Thermal/Steam
LTCC	Longwall Top Coal Caving	M	Metallurgical
CM	Continuous Miner	P	Pulverized Coal Injection
*	Mine operated by a contract miner


⁽¹⁾	“Other” in Powder River Basin Mining primarily consists of purchased coal used to satisfy certain specific coal supply agreements.


⁽²⁾	Mine ceased production in 2015 due to exhaustion of reserves.


⁽³⁾	We own a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines.


⁽⁴⁾	We own a 50.0% equity interest in Middlemount Coal Pty Ltd., which owns the Middlemount Mine. Because that entity is accounted for as an unconsolidated equity affiliate, 2015 tons sold from that mine, which totaled 4.2 million tons (on a 100% basis), have been excluded from the table above.


⁽⁵⁾	Represents our majority-owned mines in which there is an outside non-controlling ownership interest.

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.



Peabody Energy Corporation	2015 Form 10-K	4

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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 SO₂, NO_X and CO₂ emitting coal plants globally and in India, Europe, Asia (excluding China) and the U.S. through our Advanced Energy for Life Clean Coal Awards.



Peabody Energy Corporation	2015 Form 10-K	5

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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.



Peabody Energy Corporation	2015 Form 10-K	6

Table of Contents

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 coal 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.



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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;


•	The use of unmanned drones for aerial pit and stockpile surveys and plan to use them for inspection of equipment (dragline booms) that cannot easily be accessed;


•	Began testing of autonomous blast hole drills;


•	Expanded the utilization of remote equipment health monitoring to several mines and established a regional monitoring center in Brisbane; and


•	Enhanced real time monitoring of prep plants through the installation of the AMPLA product at several sites.

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.



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Employees

We had approximately 7,600 employees as of December 31, 2015, including approximately 5,700 hourly employees. Additional information on our employees and related labor relations matters is contained in Note 22. "Management - Labor Relations" to our consolidated financial statements, which information is incorporated herein by reference.

Executive Officers of the Company

Set forth below are the names, ages and positions of our executive officers. Executive officers are appointed by, and hold office at the discretion of, our Board of Directors, subject to the terms of any employment agreements.



Name	Age ⁽¹⁾	Position ⁽¹⁾
Glenn L. Kellow	48	President and Chief Executive Officer
Amy B. Schwetz	41	Executive Vice President and Chief Financial Officer
Bryan A. Galli	55	Group Executive of Marketing and Trading
Christopher J. Hagedorn	43	Group Executive of Strategy and Development
Charles F. Meintjes	53	President - Australia
A. Verona Dorch	48	Executive Vice President, Chief Legal Officer, Government Affairs and Corporate Secretary
Andrew P. Slentz	54	Executive Vice President Human Resources and Administration
Kemal Williamson	56	President - Americas

⁽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.



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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.



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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.



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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.).



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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.



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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.



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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.



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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.



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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.



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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.



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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.



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Item 1A. Risk Factors.

We operate in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect our business, financial condition, prospects, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with our business. New factors may emerge or changes to these risks could occur that could materially affect our business.

Risks Associated with Our Operations

As a result of operating losses and negative cash flows from operations and our election to exercise a 30-day grace period with respect to certain interest payments, together with other factors, including the possibility that a covenant default or other event of default could cause certain of our indebtedness to become immediately due and payable (after the expiration of any applicable grace period), we may not have sufficient liquidity to sustain operations and to continue as a going concern.

We incurred a substantial loss from operations and had negative cash flows from operating activities for the year ended December 31, 2015. Our current operating plan indicates that we will continue to incur losses from operations and generate negative cash flows from operating activities. These projections and certain liquidity risks raise substantial doubt about whether we will meet our obligations as they become due within one year after the date of issuance of this report. We have also elected to exercise the 30-day grace period with respect to a $21.1 million semi-annual interest payment due March 15, 2016 on the 6.50% Senior Notes due September 2020 and a $50.0 million semi-annual interest payment due March 15, 2016 on the 10.00% Senior Secured Second Lien Notes due March 2022, as provided for in the indentures governing these notes. Failure to pay these interest amounts on March 15, 2016 is not immediately an event of default under the indentures governing these notes, but would become an event of default if the payment is not made within 30 days of such date. As a result of these factors, as well as the continued uncertainty around global coal fundamentals, the stagnated economic growth of certain major coal-importing nations, and the potential for significant additional regulatory requirements imposed on coal producers, among others, there exists substantial doubt whether we will be able to continue as a going concern. In addition, in February 2016, we borrowed approximately $945 million under the 2013 Revolver, the maximum amount available, for general corporate purposes.

The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from uncertainty about our ability to continue as a going concern, other than the reclassification of certain long-term debt and the related debt issuance costs to current liabilities and current assets, respectively. The report from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2015 includes an uncertainty paragraph that summarizes the salient facts and conditions that raise substantial doubt about our ability to continue as a going concern.

Our 2013 Credit Facility and its related governing documents contain requirements (as more fully described under "Risks Associated with Our Indebtedness" below) that, among other things, require us to comply with certain financial covenants and furnish our audited financial statements as soon as available, but in any event within 90 days after the fiscal year end without a “going concern” uncertainty paragraph in the auditor’s opinion. Our consolidated financial statements for the year ended December 31, 2015 included herein contain a "going concern" uncertainty paragraph. In addition, we currently anticipate that our reported Adjusted EBITDA and other sources of earnings or adjustments used to calculate Consolidated EBITDA (if such other sources of earnings or adjustments do not include the proceeds of certain targeted asset sales) will fall below our Consolidated Net Cash Interest Charges during 2016, and we anticipate we will not comply with our financial covenants as of March 31, 2016. Absent waivers or cures, non-compliance with such covenants would constitute a default under the 2013 Credit Facility. As a result, all indebtedness under the 2013 Credit Facility could be declared immediately due and payable upon the occurrence of an event of default (after the expiration of any applicable grace period). It is possible we could obtain waivers from our lenders; however, the aforementioned projections and certain liquidity risks raise substantial doubt about whether we will meet our obligations as they become due within one year after the date of issuance of this report.

We are currently exploring alternatives for other sources of capital for ongoing liquidity needs and transactions to enhance our ability to comply with the financial covenants under our 2013 Credit Facility. We are working to improve our operating performance and our cash, liquidity and financial position. This includes: pursuing the sale of non-strategic surplus land and coal reserves as well as existing mines, particularly the sale of our El Segundo and Lee Ranch coal mines and related assets located in New Mexico and our Twentymile Mine in Colorado; continuing to drive cost improvements across the company, attempting to negotiate alternative payment terms with creditors; maintaining our current level of self-bonding and/or replacing self-bonding with other financial instruments on reasonable terms; evaluating potential debt buybacks, debt exchanges and new financing to improve our liquidity and reduce our financial obligations; and obtaining waivers of going concern and financial covenant violations under the 2013 Credit Facility. We have engaged financial and other advisors to assist us in those efforts.



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However, there can be no assurance that our plan to improve our operating performance and financial position will be successful or that we will be able to obtain additional financing on commercially reasonable terms or at all. As a result, our liquidity and ability to timely pay our obligations when due could be adversely affected. Furthermore, our creditors may resist renegotiation or lengthening of payment and other terms through legal action or otherwise. If we are not able to timely, successfully or efficiently implement the strategies that we are pursuing to improve our operating performance and financial position, obtain alternative sources of capital or otherwise meet our liquidity needs, we may need to voluntarily seek protection under Chapter 11 of the U.S. Bankruptcy Code.

Our profitability depends upon the prices we receive for our coal.

Depressed coal prices have reduced our revenues, and sustained prices at current levels or further declines in coal prices will adversely affect our operating results and financial condition. Further declines in coal prices will adversely affect the value of our coal reserves.

Coal prices are dependent upon factors beyond our control, including:


•	the strength of the global economy;


•	the demand for electricity;


•	the demand for steel, which may lead to price fluctuations in the periodic repricing of our metallurgical coal contracts;


•	the global supply and production costs of thermal and metallurgical coal;


•	changes in the fuel consumption patterns of electric power generators;


•	weather patterns and natural disasters;


•	competition within our industry and the availability, quality and price of alternative fuels, including natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power;


•	the proximity, capacity and cost of transportation and terminal facilities;


•	coal and natural gas industry output and capacity;


•	governmental regulations and taxes, including those establishing air emission standards for coal-fueled power plants or mandating or subsidizing increased use of electricity from renewable energy sources;


•	regulatory, administrative and judicial decisions, including those affecting future mining permits and leases; and


•	technological developments, including those related to alternative energy sources, those intended to convert coal-to-liquids or gas and those aimed at capturing, using and storing carbon dioxide.

Coal prices are currently depressed based on a number of factors, many of which are outside our control. If coal prices decline further, our operating results and profitability and value of our coal reserves could be materially and adversely affected. For example, our revenues decreased during the year ended December 31, 2015, as compared to the prior year by $1,183.0 million, primarily due to lower realized coal pricing and lower sales volumes driven by demand and production factors described in this risk factor.

In the U.S., our strategy is to selectively renew, or enter into new, long-term supply agreements when we can do so at prices we believe are favorable. In Australia, current industry practice, and our typical practice, is to negotiate pricing for metallurgical coal contracts quarterly and seaborne thermal coal contracts annually, with a portion sold on a shorter-term basis.

Thermal coal accounted for the majority of our coal sales during 2015. The majority of our sales of thermal coal were to electric power generators. The demand for coal consumed for electric power generation is affected by many of the factors described above, but primarily by (i) the overall demand for electricity; (ii) the availability, quality and price of competing fuels, such as natural gas, nuclear fuel, oil and alternative energy sources; (iii) increasingly stringent environmental and other governmental regulations; and (iv) the coal inventories of utilities. Gas-fueled generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators. Many of the new power plants in the U.S. may be fueled by natural gas because gas-fired plants are viewed as cheaper to construct and permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fueled generators. Increasingly stringent regulations have also reduced the number of new power plants being built. These trends have reduced demand for our coal and the related prices. Any further reduction in the amount of coal consumed by electric power generators could reduce the price of coal that we mine and sell.



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Lower demand for metallurgical coal by steel producers would reduce our revenues and could further reduce the price of our metallurgical coal. We produce metallurgical coal that is used in the global steel industry. Metallurgical coal accounted for approximately 21.4% and 24.1% of our coal sales revenue in 2015 and 2014, respectively. Any deterioration in conditions in the steel industry, including the demand for steel and the continued financial condition of the industry, would reduce the demand for our metallurgical coal. Lower demand for metallurgical coal in international markets would reduce the amount of metallurgical coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

Additionally, we compete with numerous other domestic and foreign coal producers for domestic and international sales. This competition affects domestic and foreign coal prices and our ability to attract and retain customers. Overcapacity and increased production within the coal industry, both domestically and internationally, could materially reduce coal prices and therefore materially reduce our revenues and profitability. In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas. Further declines in the price of natural gas, or continued low natural gas prices, could cause demand for coal to decrease and adversely affect the price of coal. Sustained periods of low natural gas prices or other fuels may also cause utilities to phase out or close existing coal-fired power plants or reduce construction of new coal-fired power plants, which could have a material adverse effect on demand and prices for our coal, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

If a substantial number of our long-term coal supply agreements terminate, our revenues and operating profits could suffer if we are unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts.

Most of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract, particularly in the U.S.

Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. We may adjust these contract prices based on inflation or deflation and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. We sometimes experience a reduction in coal prices in new long-term coal supply agreements replacing some of our expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.

The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Market prices for coal vary by mining region and country. As a result, we cannot predict the future strength of the coal market overall or by mining region and cannot provide assurance that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire.

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.

For the year ended December 31, 2015, we derived 26% of our total revenues from our five largest customers, similar to the prior year. 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 revenue base. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be successful and those customers may not continue to purchase coal from us under long-term coal supply agreements. If a number of these customers significantly reduce their purchases of coal from us, or if we are unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially. In addition, our revenue could be adversely affected by a decline in customer purchases (including contractually obligated purchases) due to lack of demand and oversupply, cost of competing fuels and environmental and other governmental regulations.



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Our trading and hedging activities may expose us to earnings volatility and other risks.

We enter into hedging arrangements designed primarily to manage market price volatility of foreign currency (primarily the Australian dollar), diesel fuel and coal. Also, from time to time, we manage the interest rate risk associated with our variable and fixed rate borrowings and commodity price risk associated with explosives using swaps. Generally, we attempt to designate hedging arrangements as cash flow hedges with gains or losses recorded as a separate component of stockholders’ equity until the hedged transaction occurs (or until hedge ineffectiveness is determined). While we utilize a variety of risk monitoring and mitigation strategies, those strategies require judgment and they cannot anticipate every potential outcome or the timing of such outcomes. As such, there is potential for these hedges to no longer qualify for hedge accounting, which occurred at December 31, 2015. As such, beginning January 1, 2016, we will be required to recognize the mark-to-market movements through current year earnings, possibly resulting in increased volatility in our income in future periods. In addition, to the extent that we engage in hedging activities, we may be prevented from realizing the benefits of future price changes of foreign currency, diesel fuel and coal.

We also enter into derivative trading instruments, some of which require us to post margin based on the value of those instruments and other credit factors. If our credit is downgraded, the fair value of our hedge portfolio moves significantly, or laws or regulations are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, we could be required to post additional margin, which could impact our liquidity.

Through our trading and hedging activities, we are also exposed to the nonperformance and credit risk with various counterparties, including exchanges and other financial intermediaries. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements, which could negatively impact our profitability and/or liquidity. In addition, some of our trading and brokerage activities include an increasing number of exchange-settled transactions, which expose us to the margin requirements of the exchange for daily changes in the value of our positions. If there are significant and extended unfavorable price movements against our positions, or if there are future regulations that impose new margin requirements, position limits and capital charges, even if not directly applicable to us, our liquidity could be impacted.

Our operating results could be adversely affected by unfavorable economic and financial market conditions.

In recent years, the global economic recession and the worldwide financial and credit market disruptions had a negative impact on us and on the coal industry generally. If any of these conditions return, if coal prices continue at or below levels experienced in 2015 for a prolonged period or if there are further downturns in economic conditions, particularly in developing countries such as China and India, our business, financial condition or results of operations could be adversely affected. While we are focused on cost control, productivity improvements, increased contributions from our higher-margin operations and capital discipline, there can be no assurance that these actions, or any others we may take, will be sufficient in response to challenging economic and financial conditions.

Our ability to collect payments from our customers could be impaired if their creditworthiness or contractual performance deteriorates.

Our ability to receive payment for coal sold and delivered or for financially settled contracts depends on the continued creditworthiness and contractual performance of our customers and counterparties. Our customer base has changed with deregulation in the U.S. as utilities have sold their power plants to their non-regulated affiliates or third parties. These new customers may have credit ratings that are below investment grade or are not rated. If deterioration of the creditworthiness of our customers occurs or they fail to perform the terms of their contracts with us, our accounts receivable securitization program and our business could be adversely affected.

Risks inherent to mining could increase the cost of operating our business.

Our mining operations are subject to conditions that can impact the safety of our workforce, or delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include fires and explosions from methane gas or coal dust; accidental mine water discharges; weather, flooding and natural disasters; unexpected maintenance problems; unforeseen delays in implementation of mining technologies that are new to our operations; key equipment failures; variations in coal seam thickness; variations in coal quality; variations in the amount of rock and soil overlying the coal deposit; variations in rock and other natural materials and variations in geologic conditions. We maintain insurance policies that provide limited coverage for some of these risks, although there can be no assurance that these risks would be fully covered by our insurance policies. Despite our efforts, such conditions could occur and have a substantial impact on our results of operations, financial condition or cash flows.



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If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer.

Transportation costs represent a significant portion of the total cost of coal use and the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs and the lack of sufficient rail and port capacity could lead to reduced coal sales.

We depend upon rail, barge, trucking, overland conveyor and ocean-going vessels to deliver coal to our customers. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, underperformance of the port and rail infrastructure, congestion and balancing systems which are imposed to manage vessel queuing and demurrage, non-performance or delays by co-shippers, transportation delays or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations.

A decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires could decrease our anticipated profitability.

Our mining operations require a reliable supply of mining equipment, replacement parts, fuel, explosives, tires, steel-related products (including roof control materials), lubricants and electricity. There has been some consolidation in the supplier base providing mining materials to the coal industry, such as with suppliers of explosives in the U.S. and both surface and underground equipment globally, that has limited the number of sources for these materials. In situations where we have chosen to concentrate a large portion of purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases and to ensure security of supply. If the cost of any of these inputs increased significantly, or if a source for these supplies or mining equipment were unavailable to meet our replacement demands, our profitability could be reduced or we could experience a delay or halt in our production.

Take-or-pay arrangements within the coal industry could unfavorably affect our profitability.

We have substantial take-or-pay arrangements, predominately in Australia, totaling $2.2 billion, with terms ranging up to 27 years, that commit us to pay a minimum amount for rail and port commitments for the delivery of coal even if those commitments go unused. The take-or-pay provisions in these contracts allow us to subsequently apply take-or-pay payments made to deliveries subsequently taken, but these provisions have limitations and we may not be able to utilize all such amounts paid if the limitations apply or if we do not subsequently take sufficient volumes to utilize the amounts previously paid. Additionally, coal companies, including us, may continue to deliver coal during times when it might otherwise be optimal to suspend operations because these take-or-pay provisions effectively convert a variable cost of selling coal to a fixed operating cost.

An inability of trading, brokerage, mining or freight counterparties to fulfill the terms of their contracts with us could reduce our profitability.

In conducting our trading, brokerage and mining operations, we utilize third-party sources of coal production and transportation, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. While we have completed several conversions to owner-operator status at certain of our Australian operations, a portion of our sales volume continues to come from mines that utilize contract miners. Employee relations at mines that use contract miners are the responsibility of the contractor.

Our profitability or exposure to loss on transactions or relationships is dependent upon the reliability (including financial viability) and price of the third-party suppliers; our obligation to supply coal to customers in the event that weather, flooding, natural disasters or adverse geologic mining conditions restrict deliveries from our suppliers; our willingness to participate in temporary cost increases experienced by our third-party coal suppliers; our ability to pass on temporary cost increases to our customers; the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market and the ability of our freight sources to fulfill their delivery obligations. Market volatility and price increases for coal or freight on the international and domestic markets could result in non-performance by third-party suppliers under existing contracts with us, in order to take advantage of the higher prices in the current market. Such non-performance could have an adverse impact on our ability to fulfill deliveries under our coal supply agreements.



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We may not recover our investments in our mining, exploration and other assets, which may require us to recognize impairment charges related to those assets.

The value of our assets may be adversely affected by numerous uncertain factors, some of which are beyond our control, including unfavorable changes in the economic environments in which we operate, lower-than-expected coal pricing, technical and geological operating difficulties, an inability to economically extract our coal reserves and unanticipated increases in operating costs. These may cause us to fail to recover all or a portion of our investments in those assets and may trigger the recognition of impairment charges in the future, which could have a substantial impact on our results of operations.

As described in Note 2. "Asset Impairment" to the accompanying consolidated financial statements, we recognized aggregate asset impairment and mine closure costs of $1,277.8 million, $154.4 million and $528.3 million in 2015, 2014 and 2013, respectively. Because of the volatile and cyclical nature of U.S. and international coal markets, it is reasonably possible that our current estimates of projected future cash flows from our mining assets may change in the near term, which may result in the need for further adjustments to the carrying value of those assets or adjustments to assets not previously impaired.

Our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.

We manage our business with a number of key personnel, the loss of whom could have a material adverse effect on us, absent the completion of an orderly transition. In addition, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel, particularly personnel with mining experience. We cannot provide assurance that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on us.

We could be negatively affected if we fail to maintain satisfactory labor relations.

As of December 31, 2015, we had approximately 7,600 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 5,700 hourly employees. Approximately 37% of our hourly employees were represented by organized labor unions and generated 20% of 2015 coal production. Additionally, those employed through contract mining relationships in Australia are also members of trade unions. Relations with our employees and, where applicable, organized labor are important to our success. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if we fail to maintain good relations with our union workforce, we could experience labor disputes, work stoppages or other disruptions in production that could negatively impact our profitability.

Our mining operations could be adversely affected if we fail to appropriately secure our obligations.

U.S. federal and state laws and Australian laws require us to secure certain of our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. The primary methods we use to meet those obligations are to post a corporate guarantee (i.e., self bond), provide a third-party surety bond or provide a letter of credit. As of December 31, 2015, we had $1,430.8 million of self bonding in place for our reclamation obligations. As of December 31, 2015, we also had outstanding surety bonds with third parties, bank guarantees and letters of credit of $1,045.7 million, of which $592.3 million was for post-mining reclamation, $75.0 million related to workers’ compensation obligations, $110.5 million was for coal lease obligations and $267.9 million was for other obligations, including road maintenance and performance guarantees. During 2015, we were required to increase our total posted letters of credit by $429.2 million to the issuing parties of certain of our surety bonds and bank guarantees, whereas we had not previously been required to do so. Surety bonds are typically renewable on a yearly basis. Surety bond issuers may not continue to renew the bonds or may demand additional collateral upon those renewals, which may in turn affect our available liquidity. Our ability to maintain and acquire letters of credit is subject to us maintaining compliance under our two primary facilities used for such items, which are our 2013 Credit Facility and our accounts receivable securitization program.

Our failure to retain, or inability to acquire, surety bonds, bank guarantees or letters of credit, or to provide a suitable alternative, would have a material adverse effect on us. That failure could result from a variety of factors including the following:


•	lack of availability, higher expense or unfavorable market terms of new surety bonds;


•	restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indentures or our 2013 Credit Facility;


•	the exercise by third-party surety bond issuers of their right to refuse to renew the surety; and


•	the inability to renew our 2013 Credit Facility or our accounts receivable securitization program or a default or lack of availability of letters of credit thereunder.



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Our ability to self-bond reduces our costs of providing financial assurances. To the extent we are unable to maintain our current level of self-bonding due to legislative or regulatory changes, changes in our financial condition or for any other reason, we would be required to obtain replacement financial assurances. Further, self-bonding is permitted at the discretion of each state. While we have historically demonstrated compliance with the applicable financial requirements in the states in which we self-bond, our self-bonding status may be challenged or withdrawn at any time. The OSM has recently issued notices to one or more states alleging possible violations relating to the continued self-bonding by coal companies, including us, in that state. The notices require the violation to be corrected or for the state to explain why a violation does not exist. As a result of any adverse change in our ability to self-bond, our costs would increase and our liquidity available for other uses would be reduced to the extent of any collateral required to obtain replacement financial assurances.

Our mining operations are extensively regulated, which impose significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal.

The coal mining industry is subject to regulation by federal, state and local authorities with respect to matters such as:


•	employee health and safety;


•	limitations on land use;


•	mine permitting and licensing requirements;


•	reclamation and restoration of mining properties after mining is completed;


•	the storage, treatment and disposal of wastes;


•	remediation of contaminated soil and groundwater;


•	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; and


•	the effects of mining on surface water and groundwater quality and availability.

Regulatory agencies have the authority under certain circumstances following significant health and safety incidents to order a mine to be temporarily or permanently closed. In the event that such agencies ordered the closing of one of our mines, our production and sale of coal would be disrupted and we may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on our financial condition, results of operations and cash flows.

The possibility exists that new legislation or regulations and orders, including without limitation related to the environment or employee health and safety may be adopted and may materially adversely affect our mining operations, our cost structure or our customers’ ability to use coal. New legislation or administrative regulations (or new interpretations by the relevant government of existing laws and regulations), including proposals related to the protection of the environment or the reduction of greenhouse gas emissions that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. Some of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations.

For additional information, see the sections entitled "Regulatory Matters-U.S.” and “Regulatory Matters-Australia” for more information about the various regulations affecting us.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. A number of laws, including in the U.S., CERCLA and the Resource Conservation and Recovery Act (RCRA), impose liability relating to contamination by hazardous substances. Such liability may involve the costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly, as well as currently, owned or operated properties, and at properties to which hazardous substances have been sent for treatment, disposal or other handling. Liability under RCRA, CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all, of the liability involved.



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In addition, we have accrued for liability arising out of contamination associated with Gold Fields Mining, LLC (Gold Fields), a dormant, non-coal-producing subsidiary of ours that was previously managed and owned by Hanson PLC, or with Gold Fields’ former affiliates. Hanson PLC, which is a predecessor owner of ours, transferred ownership of Gold Fields to us in the February 1997 spin-off of its energy business. Gold Fields is currently a defendant in several lawsuits and has received notices of several other potential claims arising out of lead contamination from mining and milling operations. Gold Fields is also involved in investigating or remediating a number of other contaminated sites. See Note 24. "Commitments and Contingencies" to our consolidated financial statements for a description of pending legal proceedings involving Gold Fields.

We may be unable to obtain and renew permits necessary for our operations, which would reduce our production, cash flows and profitability.

Numerous governmental and tribal permits and approvals are required for mining operations. The permitting rules, and the interpretations of these rules, are complex and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical. As part of this process, we are required to prepare and present to governmental authorities data pertaining to the effect that any proposed exploration for or production of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.

The costs, liabilities and requirements associated with these regulations and opposition may be costly and time-consuming and may delay commencement or continuation of exploration or production and as a result, adversely affect our coal production, cash flows and profitability. Further, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may be conditioned in a manner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cash flow and profitability.

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 Clean Water Act (CWA) requires mining companies like us 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. In recent years, the Section 404 permitting process has been subject to increasingly stringent regulatory and administrative requirements and a series of court challenges, which have resulted in increased costs and delays in the permitting process. Additionally, increasingly stringent requirements governing coal mining also are being considered or implemented under the Surface Mining Control and Reclamation Act, the National Pollution Discharge Elimination System permit process and various other environmental programs. Potential laws, regulations and policies 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.

Our mining operations are subject to extensive forms of taxation, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal competitively.

Federal, state, provincial or local governmental authorities in nearly all countries across the global coal mining industry impose various forms of taxation, including production taxes, sales-related taxes, royalties, environmental taxes, mining profits taxes and income taxes. If new legislation or regulations related to various forms of coal taxation, which increase our costs or limit our ability to compete in the areas in which we sell our coal, are adopted, our business, financial condition or results of operations could be adversely affected.

If the assumptions underlying our asset retirement obligations for reclamation and mine closures are materially inaccurate, our costs could be significantly greater than anticipated.

Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws in the U.S. and Australia as defined by each mining permit. These obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, which is driven by the estimated economic life of the mine and the applicable reclamation laws. These cash flows are discounted using a credit-adjusted, risk-free rate. Our management and engineers periodically review these estimates. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation, mine closing and post-closure activities. The resulting estimated asset retirement obligation could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.



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Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable.

Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Moreover, the amount of proven and probable coal reserves described in Part I, Item 2. “Properties” involved the use of certain estimates and those estimates could be inaccurate. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include geological conditions, historical production from the area compared with production from other producing areas, the assumed effects of regulations and taxes by governmental agencies and assumptions governing future prices and future operating costs. Actual production, revenues and expenditures with respect to our coal reserves may vary materially from estimates.

Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties and infrastructure. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of our reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the U.S. federal government limits the amount of federal land that may be leased by any company to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2015, we leased a total of 69,145 acres from the federal government subject to those limitations. On January 15, 2016, the Interior Department announced that it will perform a review of the federal coal leasing program. The Secretary of the Interior Sally Jewell ordered a pause on issuing new coal leases which the Interior Department expects to continue for three years. If this limitation were to continue significantly beyond three years, it could restrict our ability to lease additional U.S. federal lands and coal reserves critical to our Western U.S mining and Powder River Basin mining segments.

Our planned mine development projects and acquisition activities may not result in significant additional reserves, and we may not have success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Because we do not thoroughly verify title to most of our leased properties and mineral rights until we obtain a permit to mine the property, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, in order to develop our reserves, we must also own the rights to the related surface property and receive various governmental permits. We cannot predict whether we will continue to receive the permits or appropriate land access necessary for us to operate profitably in the future. We may not be able to negotiate new leases from the government or from private parties, obtain mining contracts for properties containing additional reserves or maintain our leasehold interest in properties on which mining operations have not commenced or have not met minimum quantity or product royalty requirements. From time to time, we have experienced litigation with lessors of our coal properties and with royalty holders. In addition, from time to time, our permit applications have been challenged, causing production delays.

To the extent that our existing sources of liquidity are not sufficient to fund our planned mine development projects and reserve acquisition activities, we may require access to capital markets, which may not be available to us or, if available, may not be available on satisfactory terms. If we are unable to fund these activities, we may not be able to maintain or increase our existing production rates and we could be forced to change our business strategy, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Our global operations increase our exposure to risks unique to international mining and trading operations.

Our international platform increases our exposure to country risks and the effects of changes in currency exchange rates. Some of our international activities are in developing countries where the economic strength, business practices and counterparty reputations may not be as well developed as in our U.S. or Australian operations. We are exposed to various political risks, including political instability, the potential for expropriation of assets, costs associated with the repatriation of earnings and the potential for unexpected changes in regulatory requirements. Despite our efforts to mitigate these risks, our results of operations, financial position or cash flow could be adversely affected by these activities.



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Joint ventures, partnerships or non-managed operations may not be successful and may not comply with our operating standards.

We participate in several joint venture and partnership arrangements and may enter into others, all of which necessarily involve risk. Whether or not we hold majority interests or maintain operational control in our joint ventures, our partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, ours; (2) seek to block actions that we believe are in our or the joint venture’s best interests or (3) be unable or unwilling to fulfill their obligations under the joint venture or other agreements, such as contributing capital, each of which may adversely impact our results of operations and our liquidity or impair our ability to recover our investments.

Where our joint ventures are jointly controlled or not managed by us, we may provide expertise and advice but have limited control over compliance with our operational standards. We also utilize contractors across our mining platform, and may be similarly limited in our ability to control their operational practices. Failure by non-controlled joint venture partners or contractors to adhere to operational standards that are equivalent to ours could unfavorably affect operating costs and productivity and adversely impact our results of operations and reputation.

As a result of our continuing efforts to reduce costs and optimize our organizational structure, we may undertake further restructuring plans that would require additional charges.

In 2015, we expanded our repositioning efforts to include voluntary and involuntary workforce reductions and office closures and initiated plans to consolidate certain shared services globally, and correspondingly incurred $23.5 million in aggregate charges during that period. As a result of our continuing review of our business, we may choose to further reduce our workforce and close additional offices in the future, which may result in further restructuring charges and cash expenditures and the consumption of management resources, any of which could cause our operating results to decline and may fail to yield the expected benefits.

We could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks if we sustain cyber attacks or other security breaches that disrupt our operations or result in the dissemination of proprietary or confidential information about us, our customers or other third-parties.

We have implemented security protocols and systems with the intent of maintaining the physical security of our operations and protecting our and our counterparties' confidential information and information related to identifiable individuals against unauthorized access. Despite such efforts, we may be subject to security breaches which could result in unauthorized access to our facilities or the information we are trying to protect. Unauthorized physical access to one of our facilities or electronic access to our information systems could result in, among other things, unfavorable publicity, litigation by affected parties, damage to sources of competitive advantage, disruptions to our operations, loss of customers, financial obligations for damages related to the theft or misuse of such information and costs to remediate such security vulnerabilities, any of which could have a substantial impact on our results of operations, financial condition or cash flows.



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Risks Associated with Our Indebtedness

Our financial performance could be adversely affected by our substantial indebtedness.

As of December 31, 2015, our total indebtedness was $6.3 billion, and we had $940.0 million of maximum borrowing capacity under the 2013 Revolver portion of our 2013 Credit Facility, net of outstanding letters of credit. Our 2013 Credit Facility and our Senior Secured Second Lien Notes contain covenants limiting the amount of indebtedness we may incur, however, the indentures governing our Convertible Junior Subordinated Debentures (the Debentures) and the 7.875%, 6.50%, 6.25% and 6.00% Senior Notes (collectively our Senior Notes) do not limit the amount of indebtedness that we may issue. The addition of new debt to our current debt levels could increase the related risks that we now face. Our substantial indebtedness could have important consequences, including, but not limited to:


•	increasing the costs of borrowing under our existing credit facilities or newly issued debt obligations;


•	making it more difficult for us to satisfy the financial covenants in our 2013 Revolver;


•	increasing our vulnerability to general adverse economic and industry conditions;


•	requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, business development or other general corporate requirements;


•	limiting our ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements;


•	limiting our ability to refinance our indebtedness when it becomes due;


•	making it more difficult to obtain bank guarantees, surety bonds, letters of credit or other financing, particularly during periods in which credit markets are weak;


•	limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry;


•	demands by contract counterparties for adequate assurances or the refusal of third parties to contract with us could impact performance and reduce liquidity;


•	requiring us to provide credit support, or additional credit support, for our current obligations and future obligations which we may seek to incur;


•	causing a decline in our credit ratings; and


•	placing us at a competitive disadvantage compared to less leveraged competitors.

In addition, our debt agreements subject us to financial and other restrictive covenants. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on us and result in amounts outstanding thereunder to be immediately due and payable, which could also result in a cross-default or cross-acceleration of our other indebtedness. As noted above, our current operating plan indicates that we will incur a loss from operations, generate negative cash flows and, unless we achieve certain targeted asset sales, violate certain financial and restrictive covenants. The inclusion of a "going concern" explanatory paragraph in the auditor's opinion covering our audited financial statements contained herein, absent a waiver or cure, would constitute a default under the 2013 Credit Facility after the expiration of any applicable grace period.

Previous downgrades in our credit ratings have resulted in us posting additional collateral with respect to derivative trading instruments and certain agreements with our customers. Any future downgrade in our credit ratings could result in additional requirements to post collateral on derivative trading instruments and certain agreements with our customers, the loss of trading counterparties for corporate hedging and trading and brokerage activities or an increase in the cost of, or a limit on our access to, various forms of credit used in operating our business.

If our cash flows and capital resources are insufficient to fund our debt services obligations, we may be forced to sell assets, seek additional capital to attempt to meet our debt service and other obligations or seek to restructure or refinance certain debt obligations. We have engaged in discussions with certain holders of our debt regarding debt exchanges and debt buybacks, as well as new financings. However, these alternative measures may not be successful and may not permit us to meet our scheduled debt services obligations. In this regard, certain agreements governing our indebtedness restrict our ability to sell assets and the manner in which we may use proceeds from asset sales. We also may not be able to complete any such asset sales or realize sufficient proceeds to meet debt service obligations then due. In addition, our ability to restructure our debt obligations may be impacted by cash tax liabilities that result from the cancellation of debt income if we are unable to offset that income with tax losses or other tax planning strategies. If the actions described above are not successful and we are unable to meet our debt service obligations when due, we could be required to reorganize our company in its entirety, including through bankruptcy proceedings.



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Our ability to meet our financial obligations and fund our operations is dependent upon market conditions and our continued access to borrowing capacity of our existing borrowing facilities.

Liquidity risk refers to the risk that we may not be able to generate or otherwise obtain funds at reasonable rates to meet our financial obligations and fund our operations. In addition to cash and cash equivalents, our liquidity typically includes the available balances from the 2013 Revolver under the 2013 Credit Facility and our accounts receivable securitization program that expires in April 2016. In February 2016, we borrowed approximately $945 million under our 2013 Revolver, which represented the then-remaining undrawn available amount. In order for our liquidity to be sufficient to meet our anticipated capital requirements, we must maintain our cash or, to the extent amounts once again become available for borrowing, continue to have access to a substantial portion of our maximum borrowing capacity under the 2013 Revolver. Our ability to borrow under the 2013 Revolver is dependent upon our ability to comply with the covenants in the 2013 Credit Facility. As noted above, our current operating plan indicates that we will incur a loss from operations, generate negative cash flows and, unless we achieve certain targeted asset sales, violate certain financial and restrictive covenants. The inclusion of a "going concern" explanatory paragraph in the auditor's opinion covering our audited financial statements contained herein, absent a waiver or cure, would constitute a default under the 2013 Credit Facility after the expiration of any applicable grace period.

As of March 11, 2016, our available liquidity declined to $0.9 billion, which consisted primarily of cash and cash equivalents. The decline since December 31, 2015 was primarily due to operational expenditures and the issuance of additional letters of credit.

Due to significant pressure on our business and current market conditions facing the coal industry, we have experienced losses of $1,996.0 million and $787.0 million in 2015 and 2014, respectively, and cash outflows from operations of $14.4 million in 2015. We expect to continue to experience operating losses and cash outflows from operations in the coming quarters, until the coal industry stabilizes. We have taken steps to reduce the cash outflow from operations in the near term through a realignment of our cost structure and anticipated reductions in production volumes, but these actions will not entirely address our cash outflows from operations.

Other factors that could materially adversely impact our liquidity include an inability to maintain our current level of self-bonding, requirements to provide additional collateral to support our operations, an inability to renew our accounts receivable securitization program at an appropriate capacity when it expires in April 2016, further downgrades of our credit ratings and additional obligations or liabilities that we may incur as a result of the Patriot bankruptcy. Access to additional funds from liquidity-generating transactions or other sources of external financing may not be available to us and, if available, would be subject to market conditions and certain limitations including our credit rating and covenant restrictions in the agreements governing our debt, including our 2013 Credit Facility.

We have engaged in discussions with holders of our debt regarding new financings as well as debt exchanges and debt buybacks to improve our liquidity and reduce our financial obligations. If we are not able to timely, successfully or efficiently implement the strategies that we are pursuing to improve our operating performance and financial position, obtain alternative sources of capital or otherwise meet our liquidity needs or maintain covenant compliance under our 2013 Credit Facility, we may need to voluntarily seek protection under Chapter 11 of the U.S. Bankruptcy Code.

The covenants in our 2013 Credit Facility, and the indentures governing our Senior Notes, Senior Secured Second Lien Notes and Debentures impose restrictions that may limit our operating and financial flexibility.

Our 2013 Credit Facility, the indentures governing our Senior Notes, and our Senior Secured Second Lien Notes and the instruments governing our other indebtedness contain certain restrictions and covenants which restrict our ability to incur liens and/or debt or provide guarantees in respect of obligations of any other person. Under our 2013 Credit Facility, we must comply with certain financial covenants on a quarterly basis, including a maximum consolidated net secured first lien leverage ratio and a minimum consolidated interest coverage ratio, each as defined therein. The covenants also place limitations on our investments in joint ventures and unrestricted subsidiaries, indebtedness and the imposition of liens on our assets. Also, because our ability to borrow under the 2013 Credit Facility is conditioned upon compliance with these covenants, any available borrowing capacity under the 2013 Credit Facility may be limited or may be altogether precluded. If we do not remain in compliance with the covenants in our 2013 Credit Facility, we may be restricted in our ability to pay dividends, sell assets and make redemptions or repurchase capital stock. Also, because our ability to borrow under the 2013 Credit Facility is conditioned upon compliance with these covenants, our borrowing capacity under the 2013 Credit Facility may be limited or may be altogether precluded. As noted above, our current operating plan indicates that we will incur a loss from operations, generate negative cash flows and, unless we achieve certain targeted asset sales, violate certain financial and restrictive covenants in 2016. The inclusion of a "going concern" explanatory paragraph in the auditor's opinion covering our audited financial statements contained herein, absent a waiver or cure, would constitute a default under the 2013 Credit Facility after the expiration of any applicable grace period.



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We currently anticipate that our reported Adjusted EBITDA and other sources of earnings or adjustments used to calculate Consolidated EBITDA (if such other sources of earnings or adjustments do not include the proceeds of certain targeted asset sales) will fall below our Consolidated Net Cash Interest Charges during 2016, and we anticipate we will not comply with our financial covenants as of March 31, 2016. If we violate these covenants and are unable to obtain waivers from our lenders and the debt under our 2013 Credit Facility is accelerated, there would be an event of default under our Senior Notes, and our Senior Secured Second Lien Notes and the debt owing thereunder could be accelerated. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to us. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may also cause us to take actions that are not favorable to holders of our debt or equity securities and may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.

Under the indentures governing our Senior Notes, the amount of Indebtedness (as defined in the indentures governing the Senior Notes) that may be secured by Principal Property and Capital Stock (each as defined in the Senior Notes indentures) is limited in amount, unless the Senior Notes are secured on an equal and ratable basis. Our 2013 Credit Facility and our Senior Secured Second Lien Notes are secured by Principal Property and Capital Stock, among other collateral, in a manner that uses substantially all of such limited amount. While the 2013 Credit Facility and our Senior Secured Second Lien Notes provide us with flexibility to secure certain other debt with Principal Property and Capital Stock while maintaining compliance with the terms of our Senior Notes indentures and not requiring such notes to be equally and ratably secured, our ability to incur such other secured debt is limited, and our ability to secure any debt in the future, whether or not secured by Principal Property and Capital Stock, may be negatively affected by such constraints. In addition, under the 2013 Credit Facility, if we cannot meet our debt service obligations, payment of our outstanding debt could be accelerated, the lenders could terminate their commitments to loan money, the lenders could foreclose against the assets securing their borrowings and we could be forced into bankruptcy.

The conversion of our Debentures, sales of additional shares of our common stock and the exercise or granting of additional equity securities may result in the dilution of the ownership interests of our existing stockholders.

If the conditions permitting the conversion of our Debentures are met and holders of the Debentures exercise their conversion rights, any conversion value in excess of the principal amount will be delivered in shares of our common stock. If any common stock is issued in connection with a conversion of our Debentures, our existing stockholders will experience dilution in the voting power of their common stock.

Provisions of our Debentures could discourage an acquisition of us by a third-party.

Certain provisions of our Debentures could make it more difficult or more expensive for a third-party to acquire us. Upon the occurrence of certain transactions constituting a “change of control” as defined in the indenture relating to our Debentures, holders of our Debentures will have the right, at their option, to convert their Debentures and thereby require us to pay the principal amount of such Debentures in cash and, if applicable, shares of our Common Stock. Future issuances of equity securities, including issuances pursuant to outstanding stock-based awards under our long-term incentive plans, could dilute the interests of our existing stockholders and could cause the market price for our common stock to decline. We may issue equity or equity-linked securities in the future for a number of reasons, including to finance our operations and business strategy, adjust our ratio of debt to equity, satisfy claims or obligations or for other reasons.

We may be unable to repurchase or make payments associated with our debt if we experience a change of control

If we experiences specific kinds of changes in control and the credit rating assigned to our Senior Notes declines below specified levels within 90 days of that time, holders of such notes have the right to require us to repurchase their notes at a repurchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase. In addition, as discussed above, certain provisions of our Debentures provide that upon the occurrence of certain transactions constituting a change of control, holders of our Debentures will have the right, at their option, to convert their Debentures and thereby require us to pay the principal amount of such Debentures in cash and, if applicable, shares of our Common Stock. If a change of control were to occur, we may not have sufficient funds to purchase our Senior Notes or pay amounts required by our Debentures. We also might not be able to obtain additional financing to fund those purchases and payments. Our failure to repurchase or make payments with respect to our Senior Notes and Debentures upon a change of control would cause a default under the relevant indentures and a cross default under our other indentures and our credit facility. A change of control (as defined for purposes of our credit facility) is also an event of default under the credit facility that would permit lenders to accelerate the maturity of certain borrowings.



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Other Business Risks

We may not be able to fully utilize our deferred tax assets.

We are subject to income and other taxes in the U.S. and numerous foreign jurisdictions, most significantly Australia. As of December 31, 2015, we had gross deferred income tax assets and liabilities of $2,597.1 million and $1,167.0 million, respectively, as described further in Note 10. “Income Taxes” to the accompanying consolidated financial statements. At that date, we also had recorded a valuation allowance of $1,447.3 million, substantially comprised of a full valuation allowance against our net deferred tax asset positions in the U.S. and Australia driven by recent cumulative book losses, as determined by considering all sources of available income (including items classified as discontinued operations or recorded directly to "Accumulated other comprehensive loss"), which limited our ability to look to future taxable income in assessing the likelihood of realizing those assets.

Although we may be able to utilize some or all of those deferred tax assets in the future if we have income of the appropriate character in those jurisdictions (subject to loss carryforward and tax credit expiry, in certain cases), there is no assurance that we will be able to do so. Further, we are presently unable to record tax benefits on future losses in the U.S. and Australia until such time as sufficient income is generated by our operations in those jurisdictions to support the realization of the related net deferred tax asset positions. Our results of operations, financial condition and cash flows may adversely be affected in future periods by these limitations.

We are exposed to risk of loss due to Patriot's bankruptcy.

In 2012, Patriot Coal Company and certain of its wholly owned subsidiaries (Patriot) filed voluntary petitions for relief under Chapter 11 of Title 11 of the U.S. Code. In 2013, we entered into a definitive settlement agreement with Patriot and the United Mine Workers of America (UMWA), on behalf of itself, its represented Patriot employees and its represented Patriot retirees, to resolve all disputed issues related to Patriot’s bankruptcy. In May 2015, Patriot again filed voluntary petitions for relief under Chapter 11 of Title 11 of the U.S. Code in the Eastern District of Virginia and subsequently initiated a process to sell some or all of its assets to qualified third-party bidders. On October 9, 2015, the bankruptcy court overseeing Patriot's current bankruptcy confirmed a plan of reorganization that sold substantially all of Patriot's assets to two buyers and contributed the remainder to a liquidating trust. The plan became effective in late October 2015.

We have exposure related to a total of $83.1 million of credit support we provided to Patriot pursuant to the 2013 definitive settlement agreement (net of $8.5 million of underlying liabilities assumed and $29.9 million of financial instruments drawn upon in 2015). Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" to the accompanying consolidated financial statements for additional information surrounding these risks.

By statute, we remain secondarily liable for the black lung liabilities related to Patriot’s workers employed by our former subsidiaries. Whether we will ultimately be required to fund certain of those obligations in the future as a result of Patriot’s May 2015 bankruptcy remains uncertain. We do believe that it is probable that we will be required to fund a portion of these obligations in the future and recorded a charge to "Loss from discontinued operations, net of income taxes" of $114.4 million, net of $15.0 million previously accrued credit support related to Patriot's federal black lung obligations, during the year ended December 31, 2015. Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" to the accompanying consolidated financial statements for additional information surrounding these risks.

Additionally, we are a party to proceedings alleging we have withdrawal liability of $644.2 million to the UMWA 1974 Pension Plan, which is discussed in Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation". Other parties may make claims against us in relation to Patriot's bankruptcy, although we are unaware of any other claims at this time.

Our expenditures for postretirement benefit and pension obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.

We provide postretirement health and life insurance benefits to eligible employees. Our total accumulated postretirement benefit obligation related to such benefits was a liability of $776.1 million as of December 31, 2015, of which $53.2 million was classified as a current liability. Certain of our U.S. subsidiaries also sponsor defined benefit pension plans. Net pension liabilities were $182.0 million as of December 31, 2015, of which $1.6 million was classified a current liability.



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These liabilities are actuarially determined and we use various actuarial assumptions, including the discount rate, future cost trends, and rates of return on plan assets to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities. A decrease in the discount rate used to determine our postretirement benefit and defined benefit pension obligations could result in an increase in the valuation of these obligations, thereby increasing the cost in subsequent fiscal years. We have made assumptions related to future trends for medical care costs in the estimates of retiree health care obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes or changes in healthcare benefits provided by the government could increase our obligation to satisfy these or additional obligations. Additionally, our reported defined benefit pension funding status may be affected, and we may be required to increase employer contributions, due to increases in our defined benefit pension obligation or poor financial performance in asset markets in future years.

Our defined benefit pension plans are subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). It is implicit in our underlying assumptions that those plans continue to operate in the normal course of business. However, the Pension Benefit Guarantee Corporation (PBGC) may terminate our plans under certain circumstances pursuant to ERISA laws, including in the event that the PBGC concludes that its risk may increase unreasonably if such plans continue to operate based on its assessment of the plans’ funded status, our financial condition or other factors. Termination of the plans would require us to provide immediate funding or other financial assurance to the PBGC for all or a substantial portion of the underfunded amounts, as determined by the PBGC based on its own assumptions. Those assumptions may differ from our own. Any of those consequences could have a material adverse effect on our results of operations, financial conditions or available liquidity.

Our common stock could be delisted or be suspended from trading.

Our common stock is currently listed on the New York Stock Exchange (NYSE). In order for our common stock to continue to be listed on the NYSE, we are required to comply with various quantitative and qualitative listing standards. A renewed or continued decline in the closing price of our common stock on the NYSE could result in a breach of these requirements. If we were not able to cure the breach, the NYSE could commence suspension or delisting procedures in respect of our common stock. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange.

If a suspension or delisting were to occur, there would be significantly less liquidity in the suspended or delisted securities. In addition, our ability to raise capital and compensate personnel by means of share-based compensation would be greatly impaired. Furthermore, with respect to any suspended or delisted securities, we would expect decreases in institutional and other investor demand, analyst coverage, market making activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such securities. A suspension or delisting would likely decrease the attractiveness of our common stock to investors and cause the trading volume of our common stock to decline, which could result in a further decline in the market price of our common stock.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by government-backed lending institutions and development banks toward the financing of new overseas coal-fueled power plants and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities.

Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth (and, more recently, the Fifth) Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of what are commonly referred to as greenhouse gases, including emissions of carbon dioxide from coal combustion by power plants.



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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 or coal-fueled power plant closures. Further, policies limiting available financing for the development of new coal-fueled power plants 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.

There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.

Our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.

Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control.

Diversity in interpretation and application of accounting literature in the mining industry may impact our reported financial results.

The mining industry has limited industry-specific accounting literature and, as a result, we understand diversity in practice exists in the interpretation and application of accounting literature to mining-specific issues. As diversity in mining industry accounting is addressed, we may need to restate our reported results if the resulting interpretations differ from our current accounting practices. Refer to Note 1. "Summary of Significant Accounting Policies" to the accompanying consolidated financial statements for a summary of our significant accounting policies.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Coal Reserves

We had an estimated 6.3 billion tons of proven and probable coal reserves as of December 31, 2015. An estimated 5.5 billion tons of our attributable proven and probable coal reserves are in the U.S., with the remainder in Australia. Approximately 73% of our Australian proven and probable coal reserves, or 624 million tons, are metallurgical coal, comprised of approximately 268 million and 356 million tons of coking coal and low volatile pulverized coal injection (LV PCI) coals, respectively. The remainder of our Australian coal reserves consists of thermal coal. Approximately 64% of our reserves, or 4.0 billion tons, are compliance coal and 36% are non-compliance coal (assuming application of the U.S. industry standard definition of compliance coal to all of our reserves). We own approximately 27% of these reserves and lease property containing the remaining 73%. Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.



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Below is a table summarizing the locations and proven and probable coal reserves of our major operating regions.



		Proven and Probable Reserves as of December 31, 2015 ⁽¹⁾
		Owned Tons	Leased Tons	Total Tons
Operating Regions	Locations	Owned Tons	Leased Tons	Total Tons
		(Tons in millions)
Midwest	Illinois, Indiana and Kentucky	1,497	492	1,989
Powder River Basin	Wyoming	—	2,960	2,960
Southwest	Arizona and New Mexico ⁽³⁾	171	229	400
Colorado	Colorado ⁽³⁾	18	108	126
Total United States		1,686	3,789	5,475
New South Wales	Australia	—	290	290
Queensland	Australia	—	571	571
Total Australia		—	861	861
Total Proven and Probable Coal Reserves		1,686	4,650	6,336


⁽¹⁾	Estimated proven and probable coal reserves have been adjusted to account for estimated processing losses involved in producing a saleable coal product.

Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:

•

Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

•

Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

Our estimates of proven and probable coal reserves are established within these guidelines. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density.

Our guidelines for geologic assurance surrounding estimated proven and probable U.S. and Australian coal reserves generally follow the respective industry-accepted practices of those countries. In the U.S., our estimated proven coal reserves lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas, while our estimated probable coal reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. In Australia, our estimated proven coal reserves generally lie within 250 meters of a point of observation, while our estimated probable coal reserves may lie more than 250 meters, but less than 500 meters, from a point of observation. For some of our Australian coal reserves, the distance between points of observation is determined by a geostatistical study.

The preparation of our coal reserve estimates is completed in accordance with our prescribed internal control procedures, which include verification of input data into a coal reserve forecasting and economic evaluation software system, as well as multi-functional management review. Our reserve estimates are prepared by our staff of experienced geologists. Our corporate Geological Services group is responsible for tracking changes in reserve estimates, supervising our other geologists and coordinating periodic third-party reviews of our reserve estimates by qualified mining consultants.



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Our coal reserve estimates are predicated on information obtained from an extensive historical database of drill holes and information obtained from our ongoing drilling program. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal is determined. The density of a drill pattern determines whether the related coal reserves will be classified as proven or probable. Our coal reserve estimates are then input into our computerized land management system, which overlays that geological data with data on ownership or control of the mineral and surface interests to determine the extent of our attributable coal reserves in a given area. Our land management system contains reserve information, including the quantity and quality (where available) of reserves, as well as production rates, surface ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our coal reserve estimates to reflect production of coal from those reserves and new drilling or other data received. Accordingly, our coal reserve estimates will change from time to time to reflect the effects of our mining activities, analysis of new engineering and geological data, changes in coal reserve holdings, modification of mining methods and other factors.

Our estimate of the economic recoverability of our coal reserves is generally based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to expected market prices for the quality of coal expected to be mined and take into consideration typical contractual sales agreements for the region and product. Where possible, we also review coal production by competitors in similar mining areas. Only coal reserves expected to be mined economically are included in our reserve estimates. Finally, our coal reserve estimates include reductions for recoverability factors to estimate a saleable product. Factors impacting our assessment include geological conditions, production expectations for certain areas, the effects of regulation and taxes by governmental agencies, future price and operating cost assumptions and adverse changes in certain coal market segment conditions and mine closure activities. The estimates are also impacted by decreases resulting from current year production and increases resulting from information obtained from additional drilling. Our estimation as of December 31, 2015 reflected a net reduction compared to the prior year of 1.2 billion tons of coal reserves. The decrease was driven by adverse changes in economic factors, mine plan changes and the sale of non-strategic coal reserves, partially offset from acquisitions and new drilling with the addition of 50.5 million production tons.

We periodically engage independent mining and geological consultants and consider their input regarding the procedures used by us to prepare our internal estimates of coal reserves, selected property reserve estimates and tabulation of reserve groups according to standard classifications of reliability. Our December 31, 2015 reserve estimates for New South Wales region in Australia were audited by Palaris Australia Pty Ltd, an independent mining and geological consulting firm, which included a review of the data, procedures and parameters employed by us in developing our New South Wales reserve estimates. The audit found that (1) the reserve estimates we prepared for the region were properly calculated in accordance with our stated procedures, (2) the procedures used by us are reasonable and comply with accepted industry standards and (3) our New South Wales reserve estimates, as a whole, provided a reasonable estimate of available controlled mineralization that can be expected to be legally and economically extractable at the time of determination. We plan to complete additional audits of our reserve estimates on a cycled basis for each of our major operating regions.

With respect to the accuracy of our coal reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification.

We have numerous U.S. federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in the Powder River Basin and other reserves in Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The U.S. Bureau of Land Management (BLM) has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The U.S. federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2015, we leased 7,687 acres of federal land in Colorado, 640 acres in New Mexico and 52,556 acres in Wyoming, for a total of 60,883 nationwide subject to those limitations. An additional 8,262 acres in Wyoming are held under Lease by Application with the BLM, which are also subject to the U.S. federal government limits.

Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 64,858 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments in the U.S.



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Private U.S. coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private U.S. leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many U.S. leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of our private U.S. leases are normally extended by active production at or near the end of the lease term. U.S. leases containing undeveloped reserves may expire or these leases may be renewed periodically.

Mining and exploration in Australia is generally carried out under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price. Generally landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is payable to landowners for loss of access to the land, and the amount of compensation can be determined by agreement or arbitration. Surface rights are typically acquired directly from landowners and, in the absence of agreement, there is an arbitration provision in the mining law.

Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.

With a portfolio of approximately 6.3 billion tons, we believe that we have sufficient coal reserves to replace capacity from depleting mines for the foreseeable future and that our significant coal reserve holdings is one of our competitive strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.



Peabody Energy Corporation	2015 Form 10-K	38

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The following charts provide a summary, by mining complex, of production (in descending order by region) for the years ended December 31, 2015, 2014 and 2013, tonnage of coal reserves that is assigned to our active operating mines, our property interest in those reserves and other characteristics of the facilities.



SUMMARY OF COAL PRODUCTION AND SULFUR CONTENT OF ASSIGNED RESERVES
(Tons in Millions)
	Production				Sulfur Content of Assigned Reserves as of December 31, 2015 ⁽¹⁾
					<1.2 lbs.	>1.2 to 2.5 lbs.	>2.5 lbs.	As
					Sulfur	Sulfur	Sulfur	Received
Geographic Region /	Year Ended December 31,			Type of	Dioxide per	Dioxide per	Dioxide per	Btu per
Mining Complex	2015	2014	2013	Coal	Million Btu	Million Btu	Million Btu	pound ⁽²⁾
Midwest:
Bear Run	7.9	8.4	8.2	T	4	26	220	11,500
Francisco Underground	2.9	3.1	2.9	T	—	—	27	11,500
Gateway/Gateway North	1.8	2.5	2.8	T	—	—	66	10,800
Wild Boar	2.7	3.5	3.6	T	—	—	38	11,100
Wildcat Hills Underground	1.7	2.0	1.6	T	—	—	24	12,100
Cottage Grove	1.1	1.9	2.0	T	—	—	5	12,200
Somerville Central	3.0	3.4	4.1	T	—	—	20	11,200
Viking - Corning Pit (Closed in 2014)	—	0.1	1.1	T	—	—	—	NA
Total	21.1	24.9	26.3		4	26	400

Powder River Basin:
North Antelope Rochelle	109.3	118.0	111.0	T	2,018	—	—	8,800
Rawhide	15.2	15.4	14.2	T	254	57	2	8,300
Caballo	11.4	8.0	9.0	T	594	31	4	8,400
Total	135.9	141.4	134.2		2,866	88	6

Southwest:
El Segundo ⁽³⁾	7.5	8.4	8.7	T	16	42	40	9,000
Kayenta	6.8	8.1	7.2	T	142	63	3	10,600
Lee Ranch⁽³⁾	—	—	—	T	18	67	9	9,400
Total	14.3	16.5	15.9		176	172	52

Colorado:
Twentymile ⁽³⁾	3.5	6.7	7.2	T	42	—	—	11,200

Australia:
Wilpinjong	12.0	14.4	13.3	T	154	—	—	10,000
Wambo ⁽⁴⁾	6.5	6.5	6.9	M/T	108	—	—	11,800
Millennium	4.4	3.9	3.5	M/P	18	—	—	12,600
Coppabella	2.8	3.2	3.2	P	54	—	—	12,600
North Goonyella	2.6	2.9	2.3	M	96	—	—	12,700
Moorvale	2.2	2.4	2.1	P	11	—	—	12,300
Metropolitan	2.1	2.5	1.5	M	28	—	—	12,600
Burton	1.3	1.9	2.0	M/T	9	—	—	12,700
Middlemount ⁽⁵⁾	—	—	—	M/P	30	—	—	12,300
Total	33.9	37.7	34.8		508	—	—
Total Continuing Operations	208.7	227.2	218.4		3,596	286	458
Discontinued Operations	—	—	4.0		—	—	—
Total Assigned	208.7	227.2	222.4		3,596	286	458

T: Thermal

M: Metallurgical

P: Pulverized Coal Injection Metallurgical



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ASSIGNED RESERVES ⁽⁶⁾
AS OF DECEMBER 31, 2015

		Attributable Ownership					100% Project Basis
(Tons in Millions)		Proven and					Proven and
Geographic Region/Mining Complex	Interest	Probable Reserves	Owned	Leased	Surface	Underground	Probable Reserves	Owned	Leased	Surface	Underground
Midwest:
Bear Run	100%	250	109	141	250	—	250	109	141	250	—
Gateway/Gateway North	100%	66	64	2	—	66	66	64	2	—	66
Francisco Underground	100%	27	5	22	—	27	27	5	22	—	27
Wildcat Hills Underground	100%	24	11	13	—	24	24	11	13	—	24
Somerville Central	100%	20	17	3	20	—	20	17	3	20	—
Wild Boar	100%	38	21	17	38	—	38	21	17	38	—
Cottage Grove	100%	5	3	2	5	—	5	3	2	5	—
Total		430	230	200	313	117

Powder River Basin:
North Antelope Rochelle	100%	2,018	—	2,018	2,018	—	2,018	—	2,018	2,018	—
Caballo	100%	629	—	629	629	—	629	—	629	629	—
Rawhide	100%	313	—	313	313	—	313	—	313	313	—
Total		2,960	—	2,960	2,960	—

Southwest:
Kayenta	100%	208	—	208	208	—	208	—	208	208	—
El Segundo ⁽³⁾	100%	98	80	18	98	—	98	80	18	98	—
Lee Ranch ⁽³⁾	100%	94	91	3	94	—	94	91	3	94	—
Total		400	171	229	400	—

Colorado:
Twentymile ⁽³⁾	100%	42	11	31	—	42	42	11	31	—	42

Australia:
Wilpinjong	100%	154	—	154	154	—	154	—	154	154	—
Wambo ⁽⁴⁾	100%	108	—	108	25	83	108	—	108	25	83
North Goonyella	100%	96	—	96	—	96	96	—	96	—	96
Coppabella	73.3%	54	—	54	54	—	74	—	74	74	—
Metropolitan	100%	28	—	28	—	28	28	—	28	—	28
Millennium	100%	18	—	18	18	—	18	—	18	18	—
Moorvale	73.3%	11	—	11	11	—	15	—	15	15	—
Burton	100%	9	—	9	9	—	9	—	9	9	—
Middlemount ⁽⁵⁾	50.0%	30	—	30	30	—	60	—	60	60	—
Total		508	—	508	301	207
Total Assigned		4,340	412	3,928	3,974	366



Peabody Energy Corporation	2015 Form 10-K	40

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ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES ⁽⁶⁾
AS OF DECEMBER 31, 2015
(Tons in Millions)

	Attributable Ownership					100% Project Basis

			Proven and					Proven and
	Total Tons		Probable			Total Tons		Probable
Coal Seam Location	Assigned	Unassigned	Reserves	Proven	Probable	Assigned	Unassigned	Reserves	Proven	Probable
Midwest:
Illinois	95	1,409	1,504	674	830	95	1,409	1,504	674	830
Indiana	335	26	361	297	64	335	26	361	297	64
Kentucky ⁽⁷⁾	—	124	124	55	69	—	124	124	55	69
Total	430	1,559	1,989	1,026	963

Powder River Basin (Wyoming)	2,960	—	2,960	2,831	129	2,960	—	2,960	2,831	129

Southwest:
Arizona	208	—	208	208	—	208	—	208	208	—
New Mexico ⁽³⁾	192	—	192	192	—	192	—	192	192	—
Total	400	—	400	400	—

Colorado ⁽³⁾	42	84	126	81	45	42	84	126	81	45

Australia:
New South Wales	290	—	290	235	55	290	—	290	235	55
Queensland	218	353	571	295	276	272	432	704	357	347
Total	508	353	861	530	331
Total Proven and Probable	4,340	1,996	6,336	4,868	1,468



Peabody Energy Corporation	2015 Form 10-K	41

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ASSIGNED AND UNASSIGNED - RESERVE CONTROL AND MINING METHOD
AS OF DECEMBER 31, 2015
(Tons in Millions)


	Attributable Ownership				100% Project Basis

	Reserve Control		Mining Method		Reserve Control		Mining Method
Coal Seam Location	Owned	Leased	Surface	Underground	Owned	Leased	Surface	Underground
Midwest:
Illinois	1,283	221	10	1,494	1,283	221	10	1,494
Indiana	172	189	319	42	172	189	319	42
Kentucky ⁽⁷⁾	42	82	—	124	42	82	—	124
Total	1,497	492	329	1,660

Powder River Basin (Wyoming)	—	2,960	2,960	—	—	2,960	2,960	—

Southwest:
Arizona	—	208	208	—	—	208	208	—
New Mexico ⁽³⁾	171	21	192	—	171	21	192	—
Total	171	229	400	—

Colorado ⁽³⁾	18	108	—	126	18	108	—	126

Australia:
New South Wales	—	290	179	111	—	290	179	111
Queensland	—	571	362	209	—	704	430	274
Total	—	861	541	320
Total Proven and Probable	1,686	4,650	4,230	2,106



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ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES - SULFUR CONTENT
AS OF DECEMBER 31, 2015
(Tons in Millions)

		Attributable Ownership			100% Project Basis
		Sulfur Content ⁽¹⁾			Sulfur Content ⁽¹⁾
		<1.2 lbs.	>1.2 to 2.5 lbs.	>2.5 lbs.	<1.2 lbs.	>1.2 to 2.5 lbs.	>2.5 lbs.	As
		Sulfur Dioxide	Sulfur Dioxide	Sulfur Dioxide	Sulfur Dioxide	Sulfur Dioxide	Sulfur Dioxide	Received
	Type of	per	per	per	per	per	per	Btu
Coal Seam Location	Coal	Million Btu	Million Btu	Million Btu	Million Btu	Million Btu	Million Btu	per Pound⁽²⁾
Midwest:
Illinois	T	—	—	1,504	—	—	1,504	10,800
Indiana	T	4	26	331	4	26	331	11,400
Kentucky ⁽⁷⁾	T	—	—	124	—	—	124	12,000
Total		4	26	1,959

Powder River Basin (Wyoming)	T	2,866	88	6	2,866	88	6	8,700

Southwest:
Arizona	T	142	63	3	142	63	3	10,600
New Mexico ⁽³⁾	T	34	109	49	34	109	49	9,100
Total		176	172	52

Colorado ⁽³⁾	T	126	—	—	126	—	—	11,200

Australia:
New South Wales	T/M	290	—	—	290	—	—	11,400
Queensland	T/M/P	571	—	—	704	—	—	12,400
Total		861	—	—
Total Proven and Probable		4,033	286	2,017

T: Thermal

M: Metallurgical

P: Pulverized Coal Injection Metallurgical



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⁽¹⁾

Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.


⁽²⁾	As-received Btu per pound includes the weight of moisture in the coal on an as sold basis. The range of variability of the moisture content in coal across a given region may affect the actual shipped Btu content of current production from assigned reserves.


⁽³⁾	Bowie Natural Resources entered into an agreement in 2015 to purchase all of our operations and coal reserves in New Mexico and Colorado. This transaction is expected to close in the first quarter of 2016, subject to the satisfaction of customary closing conditions.


⁽⁴⁾	Includes the Wambo Open-Cut Mine and the North Wambo Underground Mine areas.

⁽⁵⁾

Represents our 50.0% interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine in Queensland, Australia. Because that entity is accounted for as an unconsolidated equity affiliate, 2015, 2014 and 2013 tons produced by Middlemount have been excluded from the "Summary of Coal Production and Sulfur Content of Assigned Reserves" table. Middlemount produced 4.8 million tons of coal in 2015 (on a 100% basis).


⁽⁶⁾	Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations as of December 31, 2015. Unassigned reserves represent coal at currently non-producing locations that would require new mine development, mining equipment or plant facilities before operations could begin on the property.


⁽⁷⁾	All coal reserves in Kentucky are leased out to third parties.

Item 3. Legal Proceedings.

See Note 24. "Commitments and Contingencies" and Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" to our consolidated financial statements for a description of our pending legal proceedings, which information is incorporated herein by reference.

Item 4. Mine Safety Disclosures.

Our "Safety a Way of Life Management System" has been designed to set clear and consistent expectations for safety and health across our business. It aligns to the National Mining Association's CORESafety® framework and encompasses three fundamental areas: leadership and organization, safety and health risk management and assurance. 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 continually monitor our safety performance and regulatory compliance. The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95 to this Annual Report on Form 10-K.

PART II

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

Our common stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of March 8, 2016 there were 950 holders of record of our common stock.

All share and per share data have been retroactively restated to reflect the September 30, 2015 1-for-15 reverse stock split.



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The table below sets forth the range of quarterly high and low sales prices (including intraday prices) for our common stock on the New York Stock Exchange and the amount of cash dividends paid per share of our common stock during the calendar quarters indicated.



	Share Price				Dividends
	High		Low		Paid
2015
First Quarter	$	123.45	$	71.40	$	0.0375
Second Quarter	84.00		28.80		0.0375
Third Quarter	41.10		14.85		—
Fourth Quarter	28.00		7.06		—
2014
First Quarter	$	299.10	$	227.70	$	1.275
Second Quarter	294.45		236.85		1.275
Third Quarter	250.65		178.20		1.275
Fourth Quarter	186.15		108.45		1.275

Dividend Policy

In connection with our ongoing efforts to manage our cash and preserve liquidity, our Board of Directors suspended our quarterly dividend beginning in the third quarter of 2015. Our Board of Directors will continue to evaluate the appropriate dividend rate over time. The declaration and payment of dividends in the future and the amount of those dividends will depend on our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by our debt covenants and other factors that our Board of Directors may deem relevant to such evaluations. Limitations on our ability to pay dividends imposed by our debt instruments are discussed in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Share Repurchases

On October 24, 2008, we announced that our Board of Directors approved an amendment to the then existing share repurchase program to authorize repurchases of up to $1.0 billion of the then outstanding shares of our common stock (Repurchase Program). The Repurchase Program does not have an expiration date and may be discontinued at any time. Through December 31, 2015, we have repurchased a total of 0.5 million shares under the Repurchase Program at a cost of $299.6 million, leaving $700.4 million available for share repurchases under the Repurchase Program. Repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. No share repurchases were made under the Repurchase Program during the years ended December 31, 2015, 2014 or 2013.

Limitations on share repurchases imposed by our debt instruments are discussed in Part II, Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Share Relinquishments

We routinely allow employees to relinquish common stock to pay estimated taxes upon the vesting of restricted stock and the payout of performance units that are settled in common stock under our equity incentive plans. The value of common stock tendered by employees is determined based on the closing price of our common stock on the dates of the respective relinquishments.



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Purchases of Equity Securities

The following table summarizes all share purchases for the three months ended December 31, 2015:



Period	Total Number of Shares Purchased ⁽¹⁾	Average Price per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Dollar Value that May Yet Be Used to Repurchase Shares Under the Publicly Announced Program (In millions)
October 1 through October 31, 2015	974	$	23.70	—	$	700.4
November 1 through November 30, 2015	240	12.79		—	700.4
December 1 through December 31, 2015	1,210	7.73		—	700.4
Total	2,424	$	14.65	—

⁽¹⁾Represents shares withheld to cover the withholding taxes upon the vesting of restricted stock, which are not a part of the Repurchase Program.

Item 6. Selected Financial Data.

This item presents selected financial and other data about us for the most recent five fiscal years.

The table that follows and the discussion of our results of operations in 2015, 2014 and 2013 in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” includes references to and analysis of Adjusted EBITDA, Adjusted (Loss) Income from Continuing Operations and Adjusted Diluted EPS, which are financial measures not recognized in accordance with U.S. generally accepted accounting principles (GAAP). These financial measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.

Adjusted EBITDA is used by management as the primary metric to measure our segments’ operating performance. We also believe non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. Adjusted EBITDA is defined as (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense, depreciation, depletion and amortization, asset impairment and mine closure costs, charges for the settlement of claims and litigation related to previously divested operations, changes in deferred tax asset valuation allowance and amortization of basis difference related to equity affiliates. A reconciliation of income (loss) from continuing operations to Adjusted EBITDA is included in this report. Adjusted EBITDA is not intended to serve as an alternative to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.

Adjusted (Loss) Income from Continuing Operations and Adjusted Diluted EPS are defined as (loss) income from continuing operations and diluted earnings per share from continuing operations, respectively, excluding the impacts of asset impairment and mine closure costs and charges for the settlement of claims and litigation related to previously divested operations, net of tax, and the remeasurement of foreign income tax accounts on the company’s income tax provision. The company calculates income tax benefits related to asset impairment and mine closure costs and charges for the settlement of claims and litigation related to previously divested operations based on the enacted tax rate in the jurisdiction in which they have been or will be realized, adjusted for the estimated recoverability of those benefits. Management also believes that excluding the impact of the remeasurement of foreign income tax accounts represents a meaningful indicator of the company's ongoing effective tax rate.

Reconciliations of Adjusted EBITDA, Adjusted (Loss) Income from Continuing Operations and Adjusted Diluted EPS to their most comparable measures under U.S. GAAP are included below.

The selected financial data for all periods presented reflect the classification as discontinued operations of certain operations previously divested (by sale or otherwise).

On October 26, 2011, we acquired Macarthur Coal Limited (PEA-PCI). Our results of operations include PEA-PCI's results of operations from that date.

We have derived the selected historical financial data as of and for the years ended December 31, 2015, 2014, 2013, 2012 and 2011 from our audited financial statements, adjusted retrospectively for items subsequently classified as discontinued operations and the implementation of certain accounting literature. Also, all share and per share data have been retroactively restated to reflect the September 30, 2015 1-for-15 reverse stock split. The following table should be read in conjunction with the accompanying financial statements, including the related notes to those financial statements, and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”



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The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, Part I, Item 1A. “Risk Factors” of this report includes a discussion of risk factors that could impact our future results of operations.



	Year Ended December 31,
	2015			2014			2013			2012			2011
	(In millions, except per share data)
Results of Operations Data
Total revenues	$	5,609.2		$	6,792.2		$	7,013.7		$	8,077.5		$	7,895.9
Costs and expenses	7,074.0			6,927.3			7,338.5			7,905.0			6,300.2
Operating (loss) profit	(1,464.8		)	(135.1		)	(324.8		)	172.5			1,595.7
Interest expense, net	525.5			412.8			409.5			381.1			219.7
(Loss) income from continuing operations before income taxes	(1,990.3		)	(547.9		)	(734.3		)	(208.6		)	1,376.0
Income tax (benefit) provision	(176.4		)	201.2			(448.3		)	262.3			363.2
(Loss) income from continuing operations, net of income taxes	(1,813.9		)	(749.1		)	(286.0		)	(470.9		)	1,012.8
Loss from discontinued operations, net of income taxes	(175.0		)	(28.2		)	(226.6		)	(104.2		)	(66.5		)
Net (loss) income	(1,988.9		)	(777.3		)	(512.6		)	(575.1		)	946.3
Less: Net income (loss) attributable to noncontrolling interests	7.1			9.7			12.3			10.6			(11.4		)
Net (loss) income attributable to common stockholders	$	(1,996.0	)	$	(787.0	)	$	(524.9	)	$	(585.7	)	$	957.7

Basic EPS - (Loss) income from continuing operations	$	(100.34	)	$	(42.52	)	$	(16.80	)	$	(26.95	)	$	56.74
Diluted EPS - (Loss) income from continuing operations	$	(100.34	)	$	(42.52	)	$	(16.80	)	$	(26.95	)	$	56.50
Weighted average shares used in calculating basic EPS	18.1			17.9			17.8			17.9			17.9
Weighted average shares used in calculating diluted EPS	18.1			17.9			17.8			17.9			18.0
Dividends declared per share	$	0.075		$	5.100		$	5.100		$	5.100		$	5.100
Other Data
Tons sold	228.8			249.8			251.7			248.5			249.4
Net cash provided by (used in) continuing operations:
Operating activities	$	18.9		$	441.0		$	780.1		$	1,599.8		$	1,652.1
Investing activities	(290.0		)	(314.5		)	(514.2		)	(1,070.1		)	(3,737.2		)
Financing activities	267.7			(168.1		)	(321.5		)	(663.3		)	1,678.5
Adjusted EBITDA	434.6			814.0			1,047.2			1,836.5			2,122.6
Adjusted (Loss) Income from Continuing Operations	(611.9		)	(597.4		)	104.5			238.7			1,011.9
Adjusted Diluted EPS	$	(34.11	)	$	(34.03	)	$	5.12		$	12.64		$	56.45
Balance Sheet Data (at period end)
Total assets	$	11,021.3		$	13,191.1		$	14,133.4		$	15,809.0		$	16,733.0
Total long-term debt (including capital leases)	6,315.6			5,986.8			6,002.4			6,252.9			6,657.5
Total stockholders’ equity	918.5			2,726.5			3,947.9			4,938.8			5,515.8



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Adjusted EBITDA is calculated as follows:



	Year Ended December 31,
	2015			2014			2013			2012			2011
				(Dollars in millions)
(Loss) income from continuing operations, net of income taxes	$	(1,813.9	)	$	(749.1	)	$	(286.0	)	$	(470.9	)	$	1,012.8
Depreciation, depletion and amortization	572.2			655.7			740.3			663.4			474.3
Asset retirement obligation expenses	45.5			81.0			66.5			67.0			52.6
Asset impairment and mine closure costs	1,277.8			154.4			528.3			929.0			—
Settlement charges related to the Patriot bankruptcy reorganization	—			—			30.6			—			—
Change in deferred tax asset valuation allowance related to equity affiliates	(1.0		)	52.3			—			—			—
Amortization of basis difference related to equity affiliates	4.9			5.7			6.3			4.6			—
Interest expense, net	525.5			412.8			409.5			381.1			219.7
Income tax (benefit) provision	(176.4		)	201.2			(448.3		)	262.3			363.2
Adjusted EBITDA	$	434.6		$	814.0		$	1,047.2		$	1,836.5		$	2,122.6

Adjusted (Loss) Income from Continuing Operations is calculated as follows:



	Year Ended December 31,
	2015			2014			2013			2012			2011
	(Dollars in millions)
(Loss) income from continuing operations, net of income taxes	$	(1,813.9	)	$	(749.1	)	$	(286.0	)	$	(470.9	)	$	1,012.8
Asset impairment and mine closure costs	1,277.8			154.4			528.3			929.0			—
Settlement charges related to the Patriot bankruptcy reorganization	—			—			30.6			—			—
Income tax benefit related to asset impairment and mine closure costs	(75.3		)	—			(112.8		)	(227.3		)	—
Income tax benefit related to the settlement charges related to the Patriot bankruptcy reorganization	—			—			(11.3		)	—			—
Remeasurement (benefit) expense related to foreign income tax accounts	(0.5		)	(2.7		)	(44.3		)	7.9			(0.9		)
Adjusted (Loss) Income from Continuing Operations	$	(611.9	)	$	(597.4	)	$	104.5		$	238.7		$	1,011.9

Adjusted Diluted EPS is calculated as follows:



	Year Ended December 31,
	2015			2014			2013			2012			2011
Diluted EPS - (Loss) income from continuing operations	$	(100.34	)	$	(42.52	)	$	(16.80	)	$	(26.95	)	$	56.50
Asset impairment and mine closure costs, net of income taxes	66.26			8.63			23.34			38.91			—
Settlement charges related to the Patriot bankruptcy reorganization, net of income taxes	—			—			1.08			—			—
Remeasurement (benefit) expense related to foreign income tax accounts	(0.03		)	(0.14		)	(2.50		)	0.68			(0.05		)
Adjusted Diluted EPS	$	(34.11	)	$	(34.03	)	$	5.12		$	12.64		$	56.45



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

Overview

We are the world’s largest private sector coal company (by volume). As of December 31, 2015, we owned interests in 26 active coal mining operations located in the United States (U.S.) and Australia. We have a majority interest in 25 of those mining operations and a 50% equity interest in Middlemount Coal Pty Ltd (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to our mining operations, we market and broker coal from other coal producers, both as principal and agent, and trade coal and freight-related contracts through trading and business offices in Australia, China, Germany, India, the United Kingdom and the U.S. (listed alphabetically).

In 2015, we produced and sold 208.7 million and 228.8 million tons of coal, respectively, from continuing operations. During that period, 78% of our total sales (by volume) were to U.S. electricity generators, 21% were to customers outside the U.S. and 1% were to the U.S. industrial sector, with approximately 88% of our worldwide sales (by volume) delivered under long-term contracts.

During the second quarter of 2015, we elected a new chief executive officer, who is also considered our chief operating decision maker (CODM). Due to that change, we have updated our reportable segments to reflect the manner in which our new CODM views our businesses for purposes of reviewing performance, allocating resources and assessing future prospects and strategic execution. We now report our results of operations primarily through the following reportable segments: "Powder River Basin Mining," “Midwestern U.S. Mining," “Western U.S. Mining,” “Australian Metallurgical Mining," "Australian Thermal Mining," “Trading and Brokerage” and “Corporate and Other.” Periods presented in this document have been recast for comparability.

The principal business of our mining segments in the U.S. is the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S. under long-term contracts, with a portion sold into the seaborne markets as market conditions warrant. Our Powder River Basin Mining operations consist of our mines in Wyoming. The mines in that segment are characterized by surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). Our Midwestern U.S. Mining operations reflect our Illinois and Indiana mining operations, which are characterized by a mix of surface and underground mining extraction processes, coal with a higher sulfur content and Btu and lower customer transportation costs (due to shorter shipping distances). Our Western U.S. Mining operations reflect the aggregation of the New Mexico, Arizona and Colorado mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes, coal with a lower sulfur content and Btu and generally higher customer transportation costs (due to longer shipping distances). Geologically, our Powder River Basin operations mine sub-bituminous coal deposits, our Midwestern operations mine bituminous coal deposits and our Western operations mine both bituminous and sub-bituminous coal deposits.

The business of our Australian operating platform is primarily export focused with customers spread across several countries, while a portion of the coal is sold within Australia. Generally, revenues from individual countries vary year by year based on electricity demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. Our Australian Metallurgical Mining operations consist of mines in Queensland and New South Wales. The mines in that segment are characterized by both surface and underground extraction processes used to mine various qualities of metallurgical coal (low-sulfur, high Btu coal). The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coal and pulverized coal injection coal. Our Australian Thermal Mining operations predominantly consist of mines in New South Wales, Australia. The mines in that segment are characterized by both surface and underground extraction processes used to mine low-sulfur, high Btu thermal coal. We classify our Australian mines within the Australian Metallurgical Mining or Australian Thermal Mining segments based on the primary customer base and coal reserve type of each mining operation. A small portion of the coal mined by the Australian Metallurgical Mining segment is of a thermal grade. Similarly, a small portion of the coal mined by the Australian Thermal Mining segment is of a metallurgical grade. Additionally, we may market some of our metallurgical coal products as a thermal coal product from time to time depending on market conditions.

Our Trading and Brokerage segment engages in the direct and brokered trading of coal and freight-related contracts through the trading and business offices mentioned above. 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. Our 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 cash flow hedging in support of our coal trading strategy, and cash flow hedging in support of sales from our mining operations.



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Our seventh segment, Corporate and Other, 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.

As discussed more fully in Part I, Item 1A. “Risk Factors,” our results of operations in the near term could be negatively impacted by our indebtedness, weather conditions, the commodity price of coal, cost of competing fuels, availability of transportation for coal shipments, labor relations, unforeseen geologic conditions or equipment problems at mining locations and adverse changes in economic conditions in the regions in which we sell coal. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, competition from other fuel sources or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections. We may adjust our future production levels in response to changes in market demand.

Results of Operations

Going Concern

We incurred a substantial loss from operations and had negative cash flows from operating activities for the year ended December 31, 2015. Our current operating plan indicates that we will continue to incur losses from operations and generate negative cash flows from operating activities. These projections and other liquidity risks raise substantial doubt about whether we will meet our obligations as they become due within one year after the date of this report. We have also elected to exercise the 30-day grace period with respect to a $21.1 million semi-annual interest payment due March 15, 2016 on the 6.50% Senior Notes due September 2020 and a $50.0 million semi-annual interest payment due March 15, 2016 on the 10.00% Senior Secured Second Lien Notes due March 2022, as provided for in the indentures governing these notes. Failure to pay these interest amounts on March 15, 2016 is not immediately an event of default under the indentures governing these notes, but would become an event of default if the payment is not made within 30 days of such date. As a result of these factors, as well as the continued uncertainty around global coal fundamentals, the stagnated economic growth of certain major coal-importing nations, and the potential for significant additional regulatory requirements imposed on coal producers, among other matters, there exists substantial doubt whether we will be able to continue as a going concern.

The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from uncertainty about our ability to continue as a going concern, other than the reclassification of certain long-term debt and the related debt issuance costs to current liabilities and current assets, respectively. The report from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2015 includes an uncertainty paragraph that summarizes the salient facts or conditions that raise substantial doubt about our ability to continue as a going concern.



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However, there can be no assurance that management’s plan to improve our operating performance and financial position will be successful or that we will be able to obtain additional financing on commercially reasonable terms or at all. As a result, our liquidity and ability to timely pay our obligations when due could be adversely affected. Furthermore, our creditors may resist renegotiation or lengthening of payment and other terms through legal action or otherwise. If we are not able to timely, successfully or efficiently implement the strategies that we are pursuing to improve our operating performance and financial position, obtain alternative sources of capital or otherwise meet our liquidity needs, we may need to voluntarily seek protection under Chapter 11 of the U.S. Bankruptcy Code.

Reverse Stock Split

Pursuant to the authorization provided at a special meeting of our stockholders held on September 16, 2015, we completed a 1-for-15 reverse stock split of the shares of our common stock on September 30, 2015 (the Reverse Stock Split). As a result of the Reverse Stock Split, every 15 shares of issued and outstanding common stock were combined into one issued and outstanding share of Common Stock, without any change in the par value per share. Our common stock began trading on a reverse stock split-adjusted basis on the New York Stock Exchange on October 1, 2015. All share and per share data included in this report has been retroactively restated to reflect the Reverse Stock Split.

Non-U.S. GAAP Financial Measures

The following discussion of our results of operations includes references to and analysis of Adjusted EBITDA, Adjusted (Loss) Income from Continuing Operations and Adjusted Diluted EPS, which are financial measures not recognized in accordance with U.S. generally accepted accounting principles (GAAP). These financial measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.

A reconciliation of Adjusted EBITDA to its most comparable measure under U.S. GAAP is included in Note 27. "Segment and Geographic Information" of the consolidated financial statements, which information is incorporated herein by reference. Adjusted (Loss) Income from Continuing Operations and Adjusted Diluted EPS are reconciled to their most comparable measures under U.S. GAAP in the sections that follow.



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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Summary

Demand for seaborne metallurgical coal for the year ended December 31, 2015 was adversely impacted by a 2.5% decrease in worldwide steel production compared to the prior year, according to data recently published by the World Steel Association (WSA). Policy measures in China aimed toward supporting the domestic coal industry also limited imports into China during 2015. Such measures, along with a lack of growth in global electricity generation from coal also hampered demand for seaborne thermal coal in 2015.

These adverse demand factors and the impact of excess met and thermal supply have continued to weigh on international coal prices. Benchmark pricing for seaborne premium high quality hard coking coal (HQHCC), premium low volatile pulverized coal injections products (LV PCI) and thermal coal originating from Newcastle, Australia (NEWC) for the first, second, and third quarters of 2015 and 2014 were as follows (on a per tonne basis):



Contract Commencement Month:	HQHCC				Increase (Decrease) to Prices %		LV PCI				Increase (Decrease) to Prices %		NEWC				Increase (Decrease) to Prices %
Contract Commencement Month:	2015		2014		Increase (Decrease) to Prices %		2015		2014		Increase (Decrease) to Prices %		2015		2014		Increase (Decrease) to Prices %
January	$	117	$	143	(18	)%	$	99	$	116	(15	)%	$	70	$	87	(20	)%
April	$	110	$	120	(8	)%	$	93	$	100	(7	)%	$	68	$	82	(17	)%
July	$	93	$	120	(23	)%	$	73	$	100	(27	)%	$	68	$	76	(11	)%
October	$	89	$	119	(25	)%	$	71	$	99	(28	)%	$	65	$	74	(12	)%

In the U.S., electricity generation from coal decreased 13% during the year ended December 31, 2015 compared to 2014, according to the U.S. Energy Information Administration (EIA). U.S. electricity generation from coal was unfavorably affected during that period by coal-to-gas switching due to relatively lower natural gas prices and lower heating-degree days due to mild winter weather. Production in the U.S. Powder River Basin was also impacted by higher-than-average rainfall in the second quarter of 2015, which further contributed, along with the above factors, to a decrease in sales volumes in our total U.S. mining platform of 7% for the year ended December 31, 2015 compared to the prior year.

Our revenues decreased during the year ended December 31, 2015 compared to the prior year ($1,183.0 million) primarily due to lower realized pricing and lower sales volumes driven by the demand and production factors mentioned above.

To mitigate the impact of lower coal pricing, we have continued to drive operational efficiencies, optimize production across our mining platform and control expenses at all operational and administrative levels of the organization, which has led to year-over-year decreases in our operating costs and expenses ($709.2 million) and selling and administrative expenses ($50.7 million). Also included in operating results for the year ended December 31, 2015 were aggregate restructuring charges of $23.5 million, recognized in connection with certain actions initiated to reduce headcount and costs at several operating sites in Australia and to amend our administrative organizational structure, which actions are expected to improve our cost position moving forward.

Overall, Adjusted EBITDA of $434.6 million for the year ended December 31, 2015 reflected a year-over-year decrease of $379.4 million. Net results attributable to common stockholders decreased for the the year ended December 31, 2015 compared to the prior year by $1,209.0 million. In addition to lower Adjusted EBITDA, those results also reflected an adverse impact from asset impairment charges and unfavorable results from discontinued operations. Those factors were partially offset by a favorable income tax variance.

As mentioned above, we recognized material impairments during the year ended December 31, 2015 ($1,277.8 million). Additional information surrounding those charges may be found in Note 2. "Asset Impairment" to the accompanying consolidated financial statements as of December 31, 2015.

As of December 31, 2015, our available liquidity was approximately $1.2 billion, in line with the prior year. Refer to the "Liquidity and Capital Resources" section contained within this Item 7 for further discussion of factors affecting our available liquidity.



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Tons Sold

The following table presents tons sold by operating segment for the years ended December 31, 2015 and 2014:



	Year Ended December 31,		Increase (Decrease) to Tons Sold
	2015	2014	Tons		%
	(Tons in millions)
Australian Metallurgical	15.7	17.2	(1.5	)	(8.7	)%
Australian Thermal	20.1	21.0	(0.9	)	(4.3	)%
Powder River Basin Mining	138.8	142.6	(3.8	)	(2.7	)%
Western U.S. Mining	17.9	23.8	(5.9	)	(24.8	)%
Midwestern U.S. Mining	21.2	25.0	(3.8	)	(15.2	)%
Total tons sold from mining segments	213.7	229.6	(15.9	)	(6.9	)%
Trading and Brokerage	15.1	20.2	(5.1	)	(25.2	)%
Total tons sold	228.8	249.8	(21.0	)	(8.4	)%

Revenues

The following table presents revenues by operating segment for the years ended December 31, 2015 and 2014:



	Year Ended December 31,				Increase (Decrease) to Revenues
	2015		2014		$			%
	(Dollars in millions)
Australian Metallurgical	$	1,181.9	$	1,613.8	$	(431.9	)	(26.8	)%
Australian Thermal	823.5		1,058.0		(234.5		)	(22.2	)%
Powder River Basin Mining	1,865.9		1,922.9		(57.0		)	(3.0	)%
Western U.S. Mining	682.3		902.8		(220.5		)	(24.4	)%
Midwestern U.S. Mining	981.2		1,198.1		(216.9		)	(18.1	)%
Trading and Brokerage	42.8		58.4		(15.6		)	(26.7	)%
Corporate and Other	31.6		38.2		(6.6		)	(17.3	)%
Total revenues	$	5,609.2	$	6,792.2	$	(1,183.0	)	(17.4	)%

Australia Metallurgical Mining. The decrease in our Australian Metallurgical Mining segment revenues for the year ended December 31, 2015 compared to the prior year was driven by lower realized coal prices ($279.9 million) and the unfavorable impact of changes in volume and mix ($152.0 million). The volume decrease reflected lower sales volumes from our Burton Mine due to an amended agreement with the contract miner reached in the second half of 2014 that provided for reduced production from the site and the exhaustion of reserves at our Eaglefield Mine in the fourth quarter of 2014. Those negative volume drivers were partially offset by increased production and yield at our Millennium and North Goonyella Mines.

Australia Thermal Mining. The decrease in our Australian Thermal Mining segment revenues for the year ended December 31, 2015 compared to the prior year was primarily driven by lower realized coal prices ($176.0 million) and the unfavorable impact of changes in volume and mix ($58.5 million) as demand for seaborne thermal coal declined. The decrease in tons sold reflected the unfavorable production impact of weather-related adverse mining conditions and mine sequencing at our surface operations.

Powder River Basin Mining. The decrease in Powder River Basin Mining segment revenues for the year ended December 31, 2015 compared to the prior year was largely driven by a 3.8 million ton reduction in sales volume as realized coal prices were flat. The decline in volume reflected the impacts on customer demand of low natural gas prices and a decrease in heating-degree days during the winter months, as well as production difficulties caused by severe rains and pit flooding, primarily in the second quarter.

Western U.S. Mining. The decrease in Western U.S. Mining segment revenues for the year ended December 31, 2015 compared to the prior year was driven by an unfavorable volume and mix variance ($232.7 million) primarily due to lower market demand and a lack of export opportunities at current coal pricing. The effect of lower volumes was partially offset by slightly higher realized coal pricing ($12.2 million) on improved customer mix.



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Midwestern U.S. Mining. Revenues from our Midwestern U.S. Mining segment were adversely impacted during the year ended December 31, 2015 compared to the prior year by unfavorable volume and mix variance ($180.1 million) driven by market demand due to lower natural gas prices and transition of production from our Gateway Mine to our new Gateway North Mine in the fourth quarter of 2015. Revenues for the segment were also impacted by lower realized coal pricing ($36.8 million) due to the effect of contract price re-openers and the renewal of sales contracts at less favorable prices.

Trading and Brokerage. The decline in Trading and Brokerage segment revenues for the year ended December 31, 2015 compared to the prior year reflected lower physical volumes shipped due to the opportunity-limiting impact of depressed coal market pricing, partially offset by improved mark-to-market earnings from financial contract trading.

Segment Adjusted EBITDA

The following table presents Segment Adjusted EBITDA for the years ended December 31, 2015 and 2014:



	Year Ended December 31,						Increase (Decrease) to Segment Adjusted EBITDA
	2015			2014			$			%
	(Dollars in millions)
Australian Metallurgical	$	(18.2	)	$	(151.1	)	$	132.9		88.0	%
Australian Thermal	193.6			264.1			(70.5		)	(26.7	)%
Powder River Basin Mining	482.9			509.0			(26.1		)	(5.1	)%
Western U.S. Mining	184.6			266.9			(82.3		)	(30.8	)%
Midwestern U.S. Mining	269.7			306.9			(37.2		)	(12.1	)%
Trading and Brokerage	27.0			14.9			12.1			81.2	%
Total Segment Adjusted EBITDA	$	1,139.6		$	1,210.7		$	(71.1	)	(5.9	)%

Australian Metallurgical Mining. The improvement in Australian Metallurgical Mining segment Adjusted EBITDA during the year ended December 31, 2015 compared to the prior year reflected (1) the impact of exchange rate movements ($239.5 million), (2) favorable cost performance from our surface mining operations driven by an amended agreement with the contract miner at the Burton Mine reached in the second half of 2014 and the owner-operator conversion of our Moorvale Mine completed at the end of the third quarter of 2014 ($81.2 million), (3) lower diesel fuel prices ($49.8 million), and (4) improved longwall performance from our underground mines driven by longwall top coal caving technology issues experienced at our North Goonyella Mine in the prior year ($41.1 million). The above factors were partially offset by lower coal pricing, net of sales-related costs ($260.3 million).

Australian Thermal Mining. The decrease in Australian Thermal Mining segment Adjusted EBITDA during the year ended December 31, 2015 compared to the prior year reflected lower coal pricing, net of sales-related costs ($161.5 million) and lower production due to mine sequencing at our Wilpinjong Mine ($67.7 million). Those adverse factors were partially offset by the net impact of exchange rate movements ($133.0 million) and lower fuel pricing ($21.5 million).

Powder River Basin Mining. The decrease in Powder River Basin Mining segment Adjusted EBITDA during the year ended December 31, 2015 compared to the prior year was driven by a decline in sales volume ($42.8 million) and costs associated with higher overburden ratios due to mine sequencing ($11.0 million). Those negative factors were partially offset by the favorable net impact from the pricing and usage of fuel and explosives ($31.4 million).

Western U.S. Mining. The decrease in Western U.S. Mining segment Adjusted EBITDA during the year ended December 31, 2015 compared to the prior year was driven by a decline in volume ($88.7 million) and costs associated with higher overburden ratios due to mine sequencing ($8.3 million), partially offset by favorable fuel pricing ($13.6 million).

Midwestern U.S. Mining. The decrease in Midwestern U.S. Mining segment Adjusted EBITDA for the year ended December 31, 2015 compared to the prior year was driven by a decline in volumes ($60.8 million), lower realized coal prices, net of sales-related costs ($34.2 million), and costs associated with higher overburden ratios at certain of our surface mines due to mine sequencing ($15.2 million). These adverse factors were partially offset by lower fuel pricing ($38.8 million) and reduced year-over-year expenditures related to materials and supplies, labor and other operations support spending from ongoing cost containment initiatives ($33.3 million).

Trading and Brokerage. The increase in Trading and Brokerage segment Adjusted EBITDA during the year ended December 31, 2015 compared to the prior year reflected the impact of damages awarded in the first quarter of 2014 relating to the Eagle Mining, LLC (Eagle) arbitration and the settlement of the matter reached in the third quarter of 2015, in addition to improved mark-to-market earnings on financial contract trading. Refer to Note 24. "Commitments and Contingencies" to the accompanying consolidated financial statements for additional information related to the Eagle matter.



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Loss From Continuing Operations Before Income Taxes

The following table presents loss from continuing operations before income taxes for the years ended December 31, 2015 and 2014:



	Year Ended December 31,						Increase (Decrease) to Income
	2015			2014			$			%
	(Dollars in millions)
Total Segment Adjusted EBITDA	$	1,139.6		$	1,210.7		$	(71.1	)	(5.9	)%
Corporate and Other Adjusted EBITDA	(705.0		)	(396.7		)	(308.3		)	(77.7	)%
Subtotal - Adjusted EBITDA	434.6			814.0			(379.4		)	46.6	%
Depreciation, depletion and amortization	(572.2		)	(655.7		)	83.5			12.7	%
Asset retirement obligation expenses	(45.5		)	(81.0		)	35.5			43.8	%
Asset impairment	(1,277.8		)	(154.4		)	(1,123.4		)	(727.6	)%
Change in deferred tax asset valuation allowance related to equity affiliates	1.0			(52.3		)	53.3			101.9	%
Amortization of basis difference related to equity affiliates	(4.9		)	(5.7		)	0.8			14.0	%
Interest expense	(465.4		)	(426.6		)	(38.8		)	(9.1	)%
Loss on early debt extinguishment	(67.8		)	(1.6		)	(66.2		)	(4,137.5	)%
Interest income	7.7			15.4			(7.7		)	(50.0	)%
Loss from continuing operations before income taxes	$	(1,990.3	)	$	(547.9	)	$	(1,442.4	)	(263.3	)%

Results from continuing operations before income taxes for the year ended December 31, 2015 declined compared to the prior year primarily due to higher asset impairment charges and lower Corporate and Other Adjusted EBITDA (discussed below). Refer to Note 2. "Asset Impairment" to the accompanying consolidated financial statements for further information regarding the nature and composition of impairment charges.

Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA for the years ended December 31, 2015 and 2014:



	Year Ended December 31,						Increase (Decrease) to Income
	2015			2014			$			%
	(Dollars in millions)
Resource management activities ⁽¹⁾	$	32.2		$	30.9		$	1.3		4.2	%
Selling and administrative expenses	(176.4		)	(227.1		)	50.7			22.3	%
Restructuring and pension settlement costs	(23.5		)	(26.0		)	2.5			9.6	%
Corporate hedging	(436.8		)	(49.6		)	(387.2		)	(780.6	)%
Other items, net ⁽²⁾	(100.5		)	(124.9		)	24.4			19.5	%
Corporate and Other Adjusted EBITDA	$	(705.0	)	$	(396.7	)	$	(308.3	)	(77.7	)%


⁽¹⁾	Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues.


⁽²⁾	Includes results from equity affiliates (before the impact of related changes in deferred tax asset valuation allowance and amortization of basis difference), costs associated with post mining activities, and minimum charges on certain transportation-related contracts.

Resource management earnings increased slightly during the year ended December 31, 2015 compared to the prior year due to increased gains from the disposal of non-core assets, primarily from surplus lands in the Midwestern U.S. The significant reduction in selling and administrative expenses during the year ended December 31, 2015 compared to the prior year largely reflected the impact of our ongoing cost containment efforts. The decrease in restructuring and pension settlement costs during the year ended December 31, 2015 compared to the prior year was driven by a lump sum payout option offered to certain qualifying participants of one of our plans in 2014, partially offset by an increase in voluntary and involuntary workforce reduction activity in 2015 related to our ongoing repositioning efforts to appropriately align our cost structure relative to prevailing global coal industry conditions. The unfavorable variance associated with corporate hedging results, which includes foreign currency and commodity hedging, resulted from the year-over-year weakening of the Australian dollar and decrease in fuel prices. The improvement in "Other items, net" during the year ended 2015 compared to the prior year reflected improved Middlemount results, as lower foreign currency rates and operational improvements at the mine more than outpaced the effect of lower coal pricing, offset by higher minimum charges on certain transportation-related contracts.



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Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment for the years ended December 31, 2015 and 2014:



							Increase (Decrease)
	Year Ended December 31,						to Income
	2015			2014			$		%
	(Dollars in millions)
Australian Metallurgical	$	(178.9	)	$	(221.5	)	$	42.6	19.2	%
Australian Thermal	(108.0		)	(118.9		)	10.9		9.2	%
Powder River Basin Mining	(138.5		)	(146.4		)	7.9		5.4	%
Western U.S. Mining	(55.3		)	(66.6		)	11.3		17.0	%
Midwestern U.S. Mining	(69.0		)	(69.6		)	0.6		0.9	%
Trading and Brokerage	(0.6		)	(1.2		)	0.6		50.0	%
Corporate and Other	(21.9		)	(31.5		)	9.6		30.5	%
Total	$	(572.2	)	$	(655.7	)	$	83.5	12.7	%

Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments for the years ended December 31, 2015 and 2014:



	Year Ended December 31,
	2015		2014
Australian Metallurgical	$	5.27	$	4.86
Australian Thermal	2.51		3.09
Powder River Basin Mining	0.69		0.70
Western U.S. Mining	0.93		0.94
Midwestern U.S. Mining	0.45		0.46

The decrease in depreciation, depletion and amortization expense during the year ended December 31, 2015 compared to the prior year reflected lower sales volumes from our mining platform. Depreciation, depletion and amortization was also impacted compared to the prior year by a reduction in the asset bases at several of our mines due to impairment charges recognized during the second quarter of 2015 and the fourth quarter of 2014. Refer to Note 2. "Asset Impairment" to the accompanying consolidated financial statements for further information regarding these impairments. These factors were slightly offset by additional depreciation related to assets placed into service in the fourth quarter of 2015 in connection with our new Gateway North Mine.

Asset Retirement Obligation Expenses. The decrease in asset retirement obligation expenses during the year ended December 31, 2015 compared to the prior year was driven by an asset retirement obligation liability of $22.2 million recorded in the fourth quarter of 2014 due to the nonperformance of a contract miner at a coal reserve property in the Eastern U.S. Because mining operations have ceased at that operation, a corresponding charge for the full amount of the liability was recorded to “Asset retirement obligation expenses” in the consolidated statement of operations during 2014. The year-over-year decrease in 2015 also reflected lower amortization that results from an overall decrease in tons sold across our mining segments and lower expense for ongoing reclamation in certain U.S. regions due to a reduction in affected acreage.

Asset Impairment. We recognized $1,277.8 million and $154.4 million in aggregate asset impairment charges during the years ended December 31, 2015 and 2014, respectively. Refer to Note 2. "Asset Impairment" to the accompanying consolidated financial statements for further information regarding the nature and composition of those charges, which information is incorporated herein by reference.

Change in Deferred Tax Asset Valuation Allowance Related to Equity Affiliates. During the year ended December 31, 2014, we recognized a $52.3 million charge for our pro-rata share of a valuation allowance on Middlemount's Australian net deferred tax assets. Based on available sources of taxable income, we determined that the net deferred tax assets are no longer considered more likely than not of being realized. That conclusion was driven by a recent history of operating losses, as sustained weakness in seaborne metallurgical coal prices have more than offset a successful owner-operator conversion completed in 2013 and an ongoing series of operational efficiency initiatives conducted at the site that have improved the mine's cost structure.



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Interest Expense. The increase in interest expense for the year ended December 31, 2015 compared to the prior year reflected higher interest rates, as compared with previously outstanding debt, related to the $1.0 billion aggregate principal amount of 10.00% Senior Secured Second Lien Notes due March 2022 (the Senior Secured Second Lien Notes) issued in March 2015 and higher overall debt levels and costs associated with additional letters of credit that were issued in 2015. Those factors were partially offset by lower interest charges recognized in 2015 for litigation matters primarily due to charges recorded in the third quarter of 2014 related to the Sumiseki Materials Co. Ltd. (Sumiseki) litigation. Refer to Note 24. "Commitments and Contingencies" to the accompanying consolidated financial statements for additional information related to the Sumiseki matter.

Loss on Early Debt Extinguishment. The loss on early debt extinguishment charges recorded during the year ended December 31, 2015 related to the repurchase of our 2016 Senior Notes. Refer to Note 12. "Long-term Debt" to the accompanying consolidated financial statements for additional information related to the repurchase.

Loss from Continuing Operations, Net of Income Taxes

The following table presents loss from continuing operations, net of income taxes, for the years ended December 31, 2015 and 2014:



	Year Ended December 31,						Increase (Decrease) to Income
	2015			2014			$			%
	(Dollars in millions)
Loss from continuing operations before income taxes	$	(1,990.3	)	$	(547.9	)	$	(1,442.4	)	(263.3	)%
Income tax (benefit) provision	(176.4		)	201.2			377.6			187.7	%
Loss from continuing operations, net of income taxes	$	(1,813.9	)	$	(749.1	)	$	(1,064.8	)	(142.1	)%

Results from continuing operations, net of income taxes, declined for the year ended December 31, 2015 compared to the prior year due to the effect lower before-tax earnings, partially offset by the favorable effect of income taxes.

Income Tax (Benefit) Provision. The year-over-year favorable effect of income taxes was driven by the tax effect of lower earnings, the tax allocation to continuing operations related to the tax effects of items credited directly to "Other comprehensive income", the election to carry back specified liability losses ten years, and a lower foreign valuation allowance in 2015 compared to 2014. These favorable factors were partially offset by a lower 2015 release of reserves related to uncertain tax positions compared to similar releases in 2014. Refer to Note 10. "Income Taxes" to the accompanying consolidated financial statements for additional information.

Adjusted Loss From Continuing Operations

The following table presents Adjusted Loss from Continuing Operations for the years ended December 31, 2015 and 2014:



	Year Ended December 31,						Increase (Decrease) to Income
	2015			2014			$			%
	(Dollars in millions)
Loss from continuing operations, net of income taxes	$	(1,813.9	)	$	(749.1	)	$	(1,064.8	)	(142.1	)%
Asset impairment	1,277.8			154.4			1,123.4			727.6	%
Income tax benefit related to asset impairment	(75.3		)	—			(75.3		)	n.m.
Remeasurement benefit related to foreign income tax accounts	(0.5		)	(2.7		)	2.2			81.5	%
Adjusted Loss from Continuing Operations	$	(611.9	)	$	(597.4	)	$	(14.5	)	(2.4	)%

Adjusted Loss from Continuing Operations changed unfavorably for the year ended December 31, 2015 compared to the prior year. The change in results reflected lower Adjusted EBITDA and debt extinguishment charges recorded during 2015. Those factors were offset by a favorable income tax variance and lower depreciation, depletion and amortization, each factor as discussed above.



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Net Loss Attributable to Common Stockholders

The following table presents net loss attributable to common stockholders for the years ended December 31, 2015 and 2014:



	Year Ended December 31,						Increase (Decrease) to Income
	2015			2014			$			%
	(Dollars in millions)
Loss from continuing operations, net of income taxes	$	(1,813.9	)	$	(749.1	)	$	(1,064.8	)	(142.1	)%
Loss from discontinued operations, net of income taxes	(175.0		)	(28.2		)	(146.8		)	(520.6	)%
Net loss	(1,988.9		)	(777.3		)	(1,211.6		)	(155.9	)%
Net income attributable to noncontrolling interests	7.1			9.7			2.6			26.8	%
Net loss attributable to common stockholders	$	(1,996.0	)	$	(787.0	)	$	(1,209.0	)	(153.6	)%

Net results attributable to common stockholders declined during the year ended December 31, 2015 compared to the prior year largely due to the unfavorable change in results from continuing operations, net of income taxes, as discussed above, and the unfavorable impact of changes in results from discontinued operations.

Loss from Discontinued Operations, Net of Income Taxes. The unfavorable change in results from discontinued operations for the year ended December 31, 2015 compared to the prior year was driven by Patriot bankruptcy related charges associated with black lung liabilities and the UMWA Combined Benefit Fund totaling $132.5 million. Results for the year ended December 31, 2015 also reflected a $34.7 million charge related to credit support that we provide to Patriot and a contingent loss accrual of $9.7 million associated with the Queensland Bulk Handling Pty Ltd. litigation. Those matters are discussed further in Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" and Note 24. "Commitments and Contingencies" to the accompanying consolidated financial statements.

Diluted EPS

The following table presents diluted EPS for the years ended December 31, 2015 and 2014:



	Year Ended December 31,						Increase (Decrease) to EPS
	2015			2014			$			%
Diluted EPS attributable to common stockholders:
Loss from continuing operations	$	(100.34	)	$	(42.52	)	$	(57.82	)	(136.0	)%
Loss from discontinued operations	(9.64		)	(1.57		)	(8.07		)	(514.0	)%
Net loss	$	(109.98	)	$	(44.09	)	$	(65.89	)	(149.4	)%

Diluted EPS declined in the year ended December 31, 2015 compared to the prior year commensurate with the unfavorable change in results from continuing and discontinued operations between those periods.

All share and per share data in this report have been retroactively restated to reflect the September 30, 2015 reverse stock split.

Adjusted Diluted EPS

The following table presents Adjusted Diluted EPS for the years ended December 31, 2015 and 2014:



	Year Ended December 31,						Increase (Decrease) to EPS
	2015			2014			$			%
Adjusted Diluted EPS Reconciliation:
Loss from continuing operations	$	(100.34	)	$	(42.52	)	$	(57.82	)	(136.0	)%
Asset impairment, net of income taxes	66.26			8.63			57.63			667.8	%
Remeasurement benefit related to foreign income tax accounts	(0.03		)	(0.14		)	0.11			78.6	%
Adjusted Diluted EPS	$	(34.11	)	$	(34.03	)	$	(0.08	)	(0.2	)%

Adjusted Diluted EPS for the year ended December 31, 2015 decreased compared to the prior year commensurate with the decline in Adjusted Loss from Continuing Operations during that period.



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Other

The net fair value of our liabilities associated with diesel fuel contracts and foreign currency forward contracts decreased by $252.7 million for the year ended December 31, 2015 compared to the prior year, primarily due to contract settlements during that period. The change is reflected in “Other current assets,” “Investments and other assets,” "Accounts payable and accrued expenses" and “Other noncurrent liabilities” in the consolidated balance sheets.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Summary

Conditions in the coal market segments that we serve were varied in 2014, characterized by (1) continued pricing declines in international seaborne markets based on an abundance of supply and slowing demand growth, and (2) stable demand in the U.S. in spite of certain transportation- and weather-related headwinds.

In global metallurgical coal market segments, demand remained relatively flat during the year ended December 31, 2014 compared to the prior year and failed to provide a catalyst for a pricing rebound from 2013. Worldwide steel production increased only slightly during that period (1.2%) according to data recently published by the World Steel Association (WSA), driven by marginal growth in production out of Asia, the U.S. and the European Union. Demand for international seaborne thermal coal declined modestly in 2014 compared to 2013, as growth in imports into India only partially offset a decline in Chinese imports compared to the prior year.

Overall, sluggish demand and the impact of continued growth in supply drove a further decline in international seaborne coal prices in 2014. Benchmark pricing for seaborne premium high quality hard coking coal (HQHCC), premium low volatile pulverized coal injections products (LV PCI) and thermal coal originating from Newcastle, Australia (NEWC) for 2014 and 2013 were as follows (on a per tonne basis):



Contract Commencement Month:	HQHCC				Increase (Decrease) to Prices %		LV PCI				Increase (Decrease) to Prices %		NEWC				Increase (Decrease) to Prices %
Contract Commencement Month:	2014		2013		Increase (Decrease) to Prices %		2014		2013		Increase (Decrease) to Prices %		2014		2013		Increase (Decrease) to Prices %
January	$	143	$	165	(13	)%	$	116	$	124	(6	)%	$	87	$	91	(4	)%
April	$	120	$	172	(30	)%	$	100	$	141	(29	)%	$	82	$	95	(14	)%
July	$	120	$	145	(17	)%	$	100	$	116	(14	)%	$	76	$	90	(16	)%
October	$	119	$	152	(22	)%	$	99	$	121	(18	)%	$	74	$	86	(14	)%

In the U.S., electricity generation from coal was stable during the year ended December 31, 2014 compared to the prior year and maintained a share of 38.9% of total electricity generation during that period according to the U.S. Energy Information Administration (EIA). U.S. electricity generation from coal benefited during 2014 compared to the prior year from higher natural gas prices and colder first quarter weather, which offset the effects of poor rail performance and mild weather in the second half of the year. Overall, our total U.S. volumes shipped increased in the year ended December 31, 2014, as customers continued to replenish depleted stockpile inventories in the second half of the year even as electricity demand fell due to weather conditions.

Our revenues decreased during the year ended December, 2014 compared to the prior year ($221.5 million) due to lower overall realized pricing from our mining platform ($602.6 million), partially offset by an overall increase in tons sold from our mining platform.

In order to mitigate the impact of lower coal pricing, we continued to focus on driving operational efficiencies, optimizing production across our mining platform and controlling expenses at all levels of the organization in 2014. Overall, Adjusted EBITDA decreased during the year ended December 31, 2014 compared to the prior year ($233.2 million). Net results attributable to common stockholders also decreased in the year ended December 31, 2014 compared to the prior year ($262.1 million). In addition to lower Adjusted EBITDA, our 2014 results also reflected an adverse impact from income taxes, a change in valuation allowance related to an equity affiliate and higher asset retirement obligation expenses, partially offset by lower asset impairment charges, a decrease in depreciation, depletion and amortization, improved results from discontinued operations and the impact of a 2013 settlement charge related to the bankruptcy of Patriot Coal Corporation, which are discussed further in the sections that follow.



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Tons Sold

The following table presents tons sold by operating segment for the years ended December 31, 2014 and 2013:



	Year Ended December 31,		Increase (Decrease) to Tons Sold
	2014	2013	Tons		%
	(Tons in millions)
Australian Metallurgical	17.2	15.0	2.2		14.7	%
Australian Thermal	21.0	19.9	1.1		5.5	%
Powder River Basin Mining	142.6	135.2	7.4		5.5	%
Western U.S. Mining	23.8	23.6	0.2		0.8	%
Midwestern U.S. Mining	25.0	26.3	(1.3	)	(4.9	)%
Total tons sold from mining segments	229.6	220.0	9.6		4.4	%
Trading and Brokerage	20.2	31.7	(11.5	)	(36.3	)%
Total tons sold	249.8	251.7	(1.9	)	(0.8	)%

Revenues

The following table presents revenues for the years ended December 31, 2014 and 2013:



	Year Ended December 31,				Increase (Decrease) to Revenues
	2014		2013		$			%
	(Dollars in millions)
Australian Metallurgical	$	1,613.8	$	1,773.4	$	(159.6	)	(9.0	)%
Australian Thermal	1,058.0		1,131.2		(73.2		)	(6.5	)%
Powder River Basin Mining	1,922.9		1,767.3		155.6			8.8	%
Western U.S. Mining	902.8		902.3		0.5			0.1	%
Midwestern U.S. Mining	1,198.1		1,335.5		(137.4		)	(10.3	)%
Trading and Brokerage	58.4		66.0		(7.6		)	(11.5	)%
Corporate and Other	38.2		38.0		0.2			0.5	%
Total revenues	$	6,792.2	$	7,013.7	$	(221.5	)	(3.2	)%

Australia Metallurgical Mining. The decrease in our Australian Metallurgical Mining segment revenues for the year ended December 31, 2014 compared to the prior year was primarily driven by lower realized coal prices ($416.7 million), partially offset by the favorable impact of changes in volume and mix ($257.1 million). The increase in production volumes reflected the 2014 ramp-ups of longwall top coal caving technology (LTCC) at our North Goonyella Mine and a new longwall at our Metropolitan Mine, in addition to the effect of prior year roof stability issues at those sites and a 2013 industrial action at the Metropolitan Mine. Those positive volume drivers were partially offset by lower production from our Eaglefield Mine due to the exhaustion of coal reserves at that site.

Australia Thermal Mining. The decrease in our Australian Thermal Mining segment revenues for the year ended December 31, 2014 compared to the prior year was primarily driven by lower realized coal prices ($160.3 million), partially offset by the favorable impact of changes in volume and mix ($87.1 million). The increase in production volumes reflected higher volumes from our Wambo open-cut mine resulting from improved productivity and favorable geological conditions. Those positive volume drivers were partially offset by extended overall longwall move downtimes at our North Wambo Underground Mine.

Powder River Basin Mining. The increase in Powder River Basin Mining segment revenues for the year ended December 31, 2014 compared to the prior year was largely driven by a 5.5% rise in sales volumes ($106.5 million). That growth reflected the impacts on customer demand of higher natural gas prices, lower customer coal stockpile levels and an increase in heating-degree days during the winter months, tempered by the adverse effect of poor rail performance and lower cooling-degree days in the summer months. The segment also benefited in 2014 from higher realized coal prices ($49.1 million) due to $33.5 million of additional contract revenue from finalized pricing under one of our sales agreements and favorable customer mix.



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Western U.S. Mining. The small increase in Western U.S. Mining segment revenues for the year ended December 31, 2014 compared to the prior year was driven by a 0.8% rise in sales volumes as a small increase in sales volumes from our New Mexico and Arizona mines were partially offset by higher longwall move downtime at our Twentymile mine.

Midwestern U.S. Mining. Revenues from our Midwestern U.S. Mining segment were adversely impacted during the year ended December 31, 2014 compared to the prior year by lower realized coal prices ($80.1 million) due to the effect of contract price re-openers and the renewal of sales contracts at less favorable prices. The decline in revenues was also partially attributed to an unfavorable volume and mix variance ($57.3 million), which reflected the first quarter 2014 exhaustion of coal reserves at our Viking-Corning Pit Mine.

Trading and Brokerage. The decline in Trading and Brokerage segment revenues for the year ended December 31, 2014 compared to the prior year reflected lower pass-through charges for transportation costs due to a decrease in physical volumes, partially offset by an improvement in net realized contract margins.

Segment Adjusted EBITDA

The following table presents Segment Adjusted EBITDA for the years ended December 31, 2014 and 2013:



							Decrease to
	Year Ended December 31,						Segment Adjusted EBITDA
	2014			2013			$			%
	(Dollars in millions)
Australian Metallurgical	$	(151.1	)	$	(120.0	)	$	(31.1	)	(25.9	)%
Australian Thermal	264.1			270.0			(5.9		)	(2.2	)%
Powder River Basin Mining	509.0			435.4			73.6			16.9	%
Western U.S. Mining	266.9			258.0			8.9			3.4	%
Midwestern U.S. Mining	306.9			426.0			(119.1		)	(28.0	)%
Trading and Brokerage	14.9			(19.9		)	34.8			174.9	%
Total Segment Adjusted EBITDA	$	1,210.7		$	1,249.5		$	(38.8	)	(3.1	)%

Australian Metallurgical Mining. Adjusted EBITDA from our Australian Metallurgical Mining segment was adversely affected during the year ended December 31, 2014 compared to the prior year by lower realized coal pricing, net of sales-related costs ($384.2 million) and inflationary cost escalations ($26.5 million). Those factors were partially offset by the improved longwall performance from our underground mines due to the factors noted above ($189.2 million), the net impact of exchange rate movements ($108.2 million) and higher productivity and lower costs at one of our surface mines ($54.3 million) driven by an owner-operator conversion. While tons sold increased by 14.7% in 2014 compared to the prior year, the resulting benefits were largely offset by lower weighted-average margins experienced across the platform.

Australian Thermal Mining. Adjusted EBITDA from our Australian Thermal Mining segment was adversely affected during the year ended December 31, 2014 compared to the prior year by lower realized coal pricing, net of sales-related costs ($147.8 million). That factor was partially offset by higher productivity and lower costs at our Australian surface mines ($83.1 million) driven by owner-operator conversions at certain sites and the net impact of exchange rate movements ($59.6 million).

Powder River Basin Mining. The increase in Powder River Basin Mining segment Adjusted EBITDA during the year ended December 31, 2014 compared to the prior year reflected a favorable volume and mix variance ($51.7 million) and higher realized pricing, net of sales-related costs ($48.8 million) due to $27.1 million of additional contract revenue, net of sales-related costs, recognized from finalized pricing under one of our sales agreements.

Western U.S. Mining. The increase in Western U.S. Mining segment Adjusted EBITDA during the year ended December 31, 2014 compared to the prior year was driven by reduced year-over-year expenditures related to materials and supplies, labor and other operations support spending attributed to ongoing cost containment initiatives.

Midwestern U.S. Mining. The decrease in Midwestern U.S. Mining segment Adjusted EBITDA for the year ended December 31, 2014 compared to the prior year was driven by lower realized coal prices, net of sales-related costs ($76.4 million), a decline in volumes ($19.6 million) and costs associated with higher overburden ratios at certain of our surface mines due to mine sequencing ($18.1 million).



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Trading and Brokerage. The increase in Trading and Brokerage segment Adjusted EBITDA during the year ended December 31, 2014 compared to the prior year reflected improved net contract margins and the effect of expenses associated with a third-party contract miner that were incurred in the prior year. Trading and Brokerage results also benefited in 2014 compared to the prior year from a $12.8 million decline in charges associated with litigation and arbitration matters. Refer to Note 24. "Commitments and Contingencies" to the accompanying consolidated financial statements for additional information surrounding the Eagle arbitration and the Gulf Power Company (Gulf Power) litigation, for which matters we recorded aggregate charges of $15.6 million and $28.4 million during the years ended December 31, 2014 and 2013, respectively.

Loss From Continuing Operations Before Income Taxes

The following table presents loss from continuing operations before income taxes for the years ended December 31, 2014 and 2013:



							Increase (Decrease)
	Year Ended December 31,						to Income
	2014			2013			$			%
	(Dollars in millions)
Total Segment Adjusted EBITDA	$	1,210.7		$	1,249.5		$	(38.8	)	(3.1	)%
Corporate and Other Adjusted EBITDA	(396.7		)	(202.3		)	(194.4		)	(96.1	)%
Subtotal - Adjusted EBITDA	814.0			1,047.2			(233.2		)	(22.3	)%
Depreciation, depletion and amortization	(655.7		)	(740.3		)	84.6			11.4	%
Asset retirement obligation expenses	(81.0		)	(66.5		)	(14.5		)	(21.8	)%
Asset impairment and mine closure costs	(154.4		)	(528.3		)	373.9			70.8	%
Settlement charges related to the Patriot bankruptcy reorganization	—			(30.6		)	30.6			100.0	%
Change in deferred tax asset valuation allowance related to equity affiliates	(52.3		)	—			(52.3		)	n.m.
Amortization of basis difference related to equity affiliates	(5.7		)	(6.3		)	0.6			9.5	%
Interest expense	(428.2		)	(425.2		)	(3.0		)	(0.7	)%
Interest income	15.4			15.7			(0.3		)	(1.9	)%
Loss from continuing operations before income taxes	$	(547.9	)	$	(734.3	)	$	186.4		25.4	%

Results from continuing operations before income taxes for the year ended December 31, 2014 improved compared to the prior year. The decrease in Segment Adjusted EBITDA discussed above, an adverse change in valuation allowance related to the Middlemount equity affiliate and higher asset retirement obligation expenses were more than offset by lower asset impairment charges and depreciation, depletion and amortization, the effect of a 2013 settlement charge related to the bankruptcy of Patriot and an improvement in Corporate and Other Adjusted EBITDA.

Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA for the years ended December 31, 2014 and 2013:



	Year Ended December 31,						Increase (Decrease) to Income
	2014			2013			$			%
	(Dollars in millions)
Resource management activities ⁽¹⁾	$	30.9		$	49.5		$	(18.6	)	(37.6	)%
Selling and administrative expenses	(227.1		)	(244.2		)	17.1			7.0	%
Restructuring and pension settlement costs	(26.0		)	(11.9		)	(14.1		)	118.5	%
Corporate hedging	(49.6		)	173.8			(223.4		)	(128.5	)%
Other operating costs, net ⁽²⁾	(124.9		)	(169.5		)	44.6			26.3	%
Corporate and Other Adjusted EBITDA	$	(396.7	)	$	(202.3	)	$	(194.4	)	(96.1	)%


⁽¹⁾	Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues.


⁽²⁾	Includes results from equity affiliates (before the impact of related changes in deferred tax asset valuation allowance and amortization of basis difference), costs associated with past mining activities, certain coal royalty expenses, gains (losses) on certain asset disposals and expenses related to our other commercial activities.



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Resource management earnings decreased during the year ended December 31, 2014 compared to the prior year due to reduced gains from the disposal of non-core assets. That decline was driven by the effect of the 2013 sale of non-strategic coal reserves and surface lands located in Kentucky, partially offset by the 2014 sale of non-strategic coal reserves located in Kentucky and surplus lands in the Midwestern U.S. The reduction in selling and administrative expenses during the year ended December 31, 2014 compared to the prior year largely reflected the impact of our ongoing cost containment efforts. The decrease in corporate hedge results reflects the weakening of the Australian dollar and a decline in diesel fuel prices. The increase in restructuring and pension settlement costs during the year ended December 31, 2014 compared to the prior year was driven by the effect of a lump sum payout option offered to certain qualifying participants of one of our plans in the fourth quarter of 2014. That unfavorable change also reflected an increase in voluntary and involuntary workforce reduction activity in 2014 related to our ongoing repositioning efforts to appropriately align our cost structure relative to prevailing global coal industry conditions.

The improvement in "Other items, net" during the year ended December 31, 2014 compared to the prior year was driven by:


•	Lower costs associated with past mining activities ($13.0 million) driven by the elimination of postretirement healthcare expenses for which the liabilities were settled with Patriot and certain of its wholly-owned subsidiaries and the UMWA pursuant to the definitive settlement agreement that became effective on December 18, 2013;


•	A decrease in pension and other postretirement benefit costs primarily due to an increase in discount rates as of the beginning of each fiscal period ($12.2 million);


•	The impact of charges of $8.0 million and $20.0 million recorded in 2014 and 2013, respectively, for environmental clean-up related costs associated with Gold Fields Mining, LLC, a dormant, non-coal producing entity that was previously managed and owned by our predecessor owner and transferred to us in a 1997 spin-off; and


•	The third quarter 2014 receipt of $9.4 million of insurance proceeds related to equipment damage losses incurred in a previous period.

Those positive factors were partially offset by an unfavorable change in results from equity affiliates (before the impact of related changes in deferred tax asset valuation allowance and amortization of basis difference) driven by lower coal pricing, as tempered by the benefit of productivity advancements resulting from the third quarter 2013 conversion of the Middlemount Mine to owner-operator status ($15.7 million).

Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment for the years ended December 31, 2014 and 2013:



							Increase (Decrease)
	Year Ended December 31,						to Income
	2014			2013			$			%
	(Dollars in millions)
Australian Metallurgical	$	(221.5	)	$	(274.0	)	$	52.5		19.2	%
Australian Thermal	(118.9		)	(132.4		)	13.5			10.2	%
Powder River Basin Mining	(146.4		)	(151.4		)	5.0			3.3	%
Western U.S. Mining	(66.6		)	(68.8		)	2.2			3.2	%
Midwestern U.S. Mining	(69.6		)	(80.4		)	10.8			13.4	%
Trading and Brokerage	(1.2		)	(0.7		)	(0.5		)	(71.4	)%
Corporate and Other	(31.5		)	(32.6		)	1.1			3.4	%
Total	$	(655.7	)	$	(740.3	)	$	84.6		11.4	%

Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments for the years ended December 31, 2014 and 2013:



	Year Ended December 31,
	2014		2013
Australian Metallurgical	$	4.86	$	7.28
Australian Thermal	3.09		3.33
Powder River Basin Mining	0.70		0.76
Western U.S. Mining	0.94		1.08
Midwestern U.S. Mining	0.46		0.66



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The decrease in depreciation, depletion and amortization expense during the year ended December 31, 2014 compared to the prior year was predominantly driven by lower expense from our Australian Mining segments. Those decreases reflected lower depletion rates at certain sites with historically higher rates due to an increase in estimated proven and probable reserves at those sites and a reduction in the asset base of one of our metallurgical surface mines from asset impairment charges recognized in the fourth quarter of 2013. Those drivers were partially offset by the effect of a year-over-year increase in tons sold.

The decline in expense from our Midwestern U.S. Mining during the year ended December 31, 2014 compared to the prior year reflected a favorable shift in production mix toward lower depletion rate coal reserves and lower tons sold.

Expense from our Western U.S. and Powder River Basin Mining segments also decreased during the year ended December 31, 2014 compared to the prior year due to the effect of a shift in production mix towards lower depletion rate coal reserve locations. That effect more than offset the increase in tons sold during the year ended December 31, 2014 compared to the prior year.

Asset Retirement Obligation Expenses. In December 2014, we recognized an asset retirement obligation liability of $22.2 million due to the nonperformance of a contract miner at a coal reserve property in the Eastern U.S. Because mining operations have ceased at that operation, a corresponding charge for the full amount of the liability was recorded to “Asset retirement obligation expenses” in the consolidated statement of operations for the year then ended. The year-over-year increase in 2014 compared to the prior year also reflected higher amortization that results from an overall increase in tons sold across our mining segments, partially offset by lower expense for ongoing reclamation in certain U.S. regions due to a reduction in affected acreage.

Asset Impairment. We recognized $154.4 million and $528.3 million in aggregate asset impairment charges during the years ended December 31, 2014 and 2013, respectively. Refer to Note 2. "Asset Impairment" to the accompanying consolidated financial statements for further information regarding the nature and composition of those charges, which information is incorporated herein by reference.

Settlement Charges Related to the Patriot Bankruptcy. Results from continuing operations before income taxes for the year ended December 31, 2013 included $30.6 million in before-tax charges associated with the settlement of claims and litigation related to the Patriot bankruptcy. Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" to the accompanying consolidated financial statements for additional information surrounding the related matters.

Change in Deferred Tax Asset Valuation Allowance Related to Equity Affiliates. During the year ended December 31, 2014, we recognized a $52.3 million charge for our pro-rata share of a valuation allowance on Middlemount's Australian net deferred tax assets. Based on available sources of taxable income, we determined that the net deferred tax assets are no longer considered more likely than not of being realized. That conclusion was driven by a history of operating losses, as sustained weakness in seaborne metallurgical coal prices have more than offset a successful owner-operator conversion completed in 2013 and an ongoing series of operational efficiency initiatives conducted at the site that have improved the mine's cost structure.

Interest Expense. Interest expense for year ended December 31, 2014 included an aggregate charge of $12.6 million related to the Sumiseki litigation and Eagle arbitration. Interest expense for the year ended December 31, 2014 also included $1.6 million of professional fees associated with the 2014 consent solicitation and related supplemental indenture for our Convertible Junior Subordinated Debentures due December 2066 (the Debentures). Interest expense for year ended December 31, 2013 included an aggregate early debt extinguishment charge of $16.9 million associated with the prior year execution of our secured credit agreement dated September 24, 2013 (as amended, the 2013 Credit Facility) and prior year voluntary debt prepayments and repurchases. Interest expense for the year ended December 31, 2013 also included a $6.9 million charge for pre-judgment interest related to the Gulf Power litigation. Changes in interest expense during the year ended December 31, 2014 compared to the prior year also reflected the unfavorable effect of higher interest rates associated with our term loan borrowings, partially offset by the beneficial impact of lower overall debt balances.

Refer to Note 24. "Commitments and Contingencies" to the accompanying consolidated financial statements for additional information surrounding the foregoing litigation and arbitration matters.



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Loss from Continuing Operations, Net of Income Taxes

The following table presents loss from continuing operations, net of income taxes, for the years ended December 31, 2014 and 2013:



	Year Ended December 31,						Increase (Decrease) to Income
	2014			2013			$			%
	(Dollars in millions)
Loss from continuing operations before income taxes	$	(547.9	)	$	(734.3	)	$	186.4		25.4	%
Income tax provision (benefit)	201.2			(448.3		)	(649.5		)	144.9	%
Loss from continuing operations, net of income taxes	$	(749.1	)	$	(286.0	)	$	(463.1	)	(161.9	)%

Results from continuing operations, net of income taxes, declined for the year ended December 31, 2014 compared to the prior year due to the effect of income taxes, partially offset by improved before-tax earnings.

Income Tax Provision (Benefit). The year-over-year negative effect of income taxes was driven by:

•

An increase in valuation allowance on certain U.S. and Australian deferred tax assets that was recognized during the year ended December 31, 2014 driven by recent cumulative book losses, as determined by considering all sources of available taxable income (including items classified as discontinued operations or recorded directly to "Accumulated other comprehensive loss"), which limited our ability to look to future taxable income in assessing the realizability of those assets ($569.4 million);


•	The aggregate impact of the write-off of a net deferred tax asset in 2014 due to the repeal of the Australian Minerals and Resource Rent Tax (MRRT) compared with MRRT royalty allowance benefits recognized in the prior year ($78.3 million);


•	The effect of improved before-tax earnings, including the 2013 income tax effects of asset impairments and charges associated with claims and litigation related to the Patriot bankruptcy ($47.8 million); and


•	Lower remeasurement benefits related to foreign income tax accounts ($41.6 million).

Those factors were partially offset in the year ended December 31, 2014 by a decrease in net unrecognized tax benefits, interest and penalties, primarily due to amended returns filed and the finalization of audits by the Australian Tax Office for certain tax years ($99.4 million).

Adjusted (Loss) Income From Continuing Operations

The following table presents Adjusted Income from Continuing Operations for the years ended December 31, 2014 and 2013:



	Year Ended December 31,						Increase (Decrease) to Income
	2014			2013			$			%
	(Dollars in millions)
Loss income from continuing operations, net of income taxes	$	(749.1	)	$	(286.0	)	$	(463.1	)	(161.9	)%
Asset impairment and mine closure costs	154.4			528.3			(373.9		)	(70.8	)%
Settlement charges related to the Patriot bankruptcy reorganization	—			30.6			(30.6		)	(100.0	)%
Income tax benefit related to asset impairment and mine closure costs	—			(112.8		)	112.8			100.0	%
Income tax benefit related to the settlement charges related to the Patriot bankruptcy reorganization	—			(11.3		)	11.3			(100.0	)%
Remeasurement (benefit) expense related to foreign income tax accounts	(2.7		)	(44.3		)	41.6			(93.9	)%
Adjusted (Loss) Income from Continuing Operations	$	(597.4	)	$	104.5		$	(701.9	)	(671.7	)%

Adjusted (Loss) Income from Continuing Operations changed unfavorably for the year ended December 31, 2014 compared to the prior year. The decline in results reflected the adverse effect of income taxes, lower Adjusted EBITDA, an adverse change in valuation allowance related to the Middlemount Mine equity affiliate and higher asset retirement obligation expenses, partially offset by lower depreciation, depletion and amortization, as discussed above.



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Net Loss Attributable to Common Stockholders

The following table presents net loss attributable to common stockholders for the years ended December 31, 2014 and 2013:



	Year Ended December 31,						Increase (Decrease) to Income
	2014			2013			$			%
	(Dollars in millions)
Loss from continuing operations, net of income taxes	$	(749.1	)	$	(286.0	)	$	(463.1	)	(161.9	)%
Loss from discontinued operations, net of income taxes	(28.2		)	(226.6		)	198.4			87.6	%
Net loss	(777.3		)	(512.6		)	(264.7		)	(51.6	)%
Net income attributable to noncontrolling interests	9.7			12.3			2.6			21.1	%
Net loss attributable to common stockholders	$	(787.0	)	$	(524.9	)	$	(262.1	)	(49.9	)%

Net results attributable to common stockholders declined during the year ended December 31, 2014 compared to the prior year largely due to the unfavorable change in results from continuing operations, net of income taxes, discussed above, partially offset by the favorable impact of changes in results from discontinued operations.

Loss from Discontinued Operations, Net of Income Taxes. Results from discontinued operations improved during the year ended December 31, 2014 compared to the prior year, mainly driven by the following:

•

Changes in results from the Wilkie Creek Mine that was closed in the fourth quarter of 2013 ($157.6 million), which reflected after-tax asset impairment and mine closure costs of $117.2 million recognized in 2013, the effect of 2013 operating losses and a net gain of $4.6 million recognized in 2014 related to the termination of a sale and purchase agreement with a potential buyer of that mine due to the inability of that buyer to meet the necessary conditions for closing; and


•	Prior year after-tax charges of $61.8 million associated with the settlement of claims and litigation related to the Patriot bankruptcy pursuant to the definitive settlement agreement that we reached with Patriot and the UMWA effective December 18, 2013; partially offset by


•	A charge of $34.1 million recorded in 2014 related to an adverse change in the fair value of the credit support we have provided to Patriot in connection with the settlement agreement due to a credit downgrade of Patriot issued by one of the major credit rating agencies in the fourth quarter of 2014.

Additional information surrounding the aforementioned asset impairment and mine closure costs and charges for the settlement of claims and litigation related to the Patriot bankruptcy is included in Note 2. "Asset Impairment" and Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" to the accompanying consolidated financial statements, respectively.

Diluted EPS

The following table presents diluted EPS for the years ended December 31, 2014 and 2013:



	Year Ended December 31,						Increase (Decrease) to EPS
	2014			2013			$			%
Diluted EPS attributable to common stockholders:
Loss from continuing operations	$	(42.52	)	$	(16.80	)	$	(25.72	)	(153.1	)%
Loss from discontinued operations	(1.57		)	(12.73		)	11.16			87.7	%
Net loss	$	(44.09	)	$	(29.53	)	$	(14.56	)	(49.3	)%

Diluted EPS declined in the year ended December 31, 2014 compared to the prior year commensurate with the unfavorable change in results from continuing operations between those periods, partially offset by improved results from discontinued operations.

All share and per share data in this report have been retroactively restated to reflect the September 30, 2015 reverse stock split.



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Adjusted Diluted EPS

The following table presents Adjusted Diluted EPS for the years ended December 31, 2014 and 2013:



	Year Ended December 31,							Increase (Decrease) to EPS
	2014				2013			$			%
Adjusted Diluted EPS Reconciliation:
Loss from continuing operations	$	(42.52	)		$	(16.80	)	$	(25.72	)	(153.1	)%
Asset impairment and mine closure costs, net of income taxes	8.63				23.34			(14.71		)	(63.0	)%
Settlement charges related to the Patriot bankruptcy reorganization, net of income taxes	—			—	1.08			(1.08		)	(100.0	)%
Remeasurement (benefit) expense related to foreign income tax accounts	(0.14		)		(2.50		)	2.36			(94.4	)%
Adjusted Diluted EPS	$	(34.03	)		$	5.12		$	(39.15	)	(764.6	)%

Adjusted Diluted EPS for the year ended December 31, 2014 decreased compared to the prior year commensurate with the decline in Adjusted (Loss) Income from Continuing Operations during that period.

Other

The net fair value of our diesel fuel cash flow hedge contract portfolio decreased from a net asset of $6.4 million at December 31, 2013 to a net liability of $167.1 million at December 31, 2014 primarily due to the decline in forward diesel prices during that period. The change is reflected in “Other current assets,” “Investments and other assets,” "Accounts payable and accrued expenses" and “Other noncurrent liabilities” in the consolidated balance sheets.

Outlook

Our near-term outlook is intended to coincide with the next 12 to 24 months, with subsequent periods addressed in our long-term outlook.

Near-Term Outlook

Coal markets continue to be pressured by reduced coal demand, limited supply reductions, significantly lower Chinese imports and weak natural gas prices. We expect modest seaborne metallurgical coal supply reductions in 2016 as further declines in the U.S. overcome small production increases from other exporting nations.

Global Macroeconomic Indicators. The World Bank revised its global economic growth estimates downward in its January 2016 Global Economic Prospects. 2015 saw continued deceleration of economic activity in emerging and developing economies amid weakening commodity prices, global trade and capital flows. Selected regional and worldwide projections of 2016 and 2017 macroeconomic growth, as measured by recent World Bank forecasts of gross domestic product (GDP), are presented below. The World Bank notes the forecast below is subject to substantial downside risks, including a sharper-than-expected slowdown in major developing economies or financial market turmoil arising from a sudden increase in borrowing costs that could combine with deteriorating fundamentals.



	GDP Growth (%)
Region:	2016		2017
U.S.	2.7	%	2.4	%
China	6.7	%	6.5	%
India	7.8	%	7.9	%
Worldwide	2.9	%	3.1	%

Seaborne Thermal Coal Market Segments and Our Position. Seaborne thermal coal demand continues to be impacted by sluggish coal generation growth and declining imports in China and Europe. In 2015, seaborne thermal demand declined 8 percent on a nearly 75 million tonne decline in Chinese imports, lower European demand and a decline in international liquefied natural gas prices. The seaborne thermal coal market segment remains well-supplied, which has led to continued decreases in prices for thermal coal originating from Newcastle, Australia. We are targeting thermal coal exports of 12 million to 13 million tons from our Australian platform in 2016.



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Seaborne Metallurgical Coal Market Segments and Our Position. The World Steel Association (WSA) reported that world crude steel output declined by 2.8 percent in 2015, compared to growth of 1.2 percent in 2014. Crude steel production decreased in all one but one region in 2015, with China’s production down 2.3 percent compared to the prior year. In its October 2015 Short Range Outlook, the WSA forecasted apparent steel use growth of 0.7% in 2016.

Seaborne metallurgical coal prices for HQHCC and LV PCI settled at approximately $81 and $69 per tonne, respectively, for quarterly contracts commencing in January 2016, falling 9 and 3 percent, respectively, versus prior quarter price levels. We are targeting total 2016 metallurgical coal sales from our Australian platform at 14 million to 15 million tons.

Our total Australian coal sales for 2016 are targeted at 34 million to 36 million tons, including both metallurgical and thermal coal products supplied for export and within Australia.

U.S. Thermal Coal Market Segments and Our Position. In its February 2016 Short Term Energy Outlook, the EIA estimates that U.S. thermal coal consumption decreased by 12 percent in 2015 primarily due to lower natural gas prices, resulting in coal’s market share of power generation falling to 34 percent in 2015, from approximately 40 percent in 2014.

According to the EIA, coal consumption in the electric power sector is forecasted to remain relatively unchanged in 2016, as increases in consumption because of projected rising natural gas prices are offset by reductions in consumption because of growing renewables generation and coal-plant retirements.

We are targeting our 2016 U.S. volumes at 150 million to 160 million tons, with all of those volumes priced as of December 31, 2015. We anticipate that average realized pricing from our U.S. mining operations be between $19.65 per ton and $19.95 per ton in 2016 compared with $19.84 per ton in 2015.

We also remain focused on efficiently controlling and allocating capital. We are targeting 2016 capital spending levels of $120 million to $140 million, in line with our 2015 spend of $126.8 million.

Long-Term Outlook

The International Energy Agency (IEA) regularly makes projections about world coal demand based on various future scenarios for energy development. The scenarios used by the IEA as the bases for these projections vary by time and publication. Further details are available to the public directly from the IEA, including through the IEA’s website: http://www.iea.org/publications/scenariosandprojections/. Information contained on or accessible through the IEA’s website is not incorporated by reference into this Annual Report on Form 10-K.

The “New Policies Scenario” is IEA’s central scenario in its World Energy Outlook report (WEO). It incorporates policies and measures affecting energy markets that have already been adopted, as well as other relevant commitments and plans that have been announced by countries, including national pledges to reduce emissions and plans to phase-out fossil fuel subsidies, even if the measures to implement these commitments have yet to be identified or announced.

Different scenarios used by the IEA in its projections of energy demand have different implications for coal usage. Projected coal usage is highest in the “Current Policies Scenario” and lowest in the “450 Scenario.” The Current Policies Scenario (previously called the “Reference Scenario”) assumes no changes in policies from the mid-point of the year of publication, thus considering policies and measures that have already been formally enacted, but assuming that governments do not implement any commitments that have yet to be finalized by legislation and will not introduce any new policies affecting coal usage.

Finally, the 450 Scenario assumes implementation of a set of government policies consistent with a goal of limiting long-term increases in the average global temperature to two degrees Celsius, a limit determined by various governments and non-governmental organizations and recognized by nations of the world in the 2010 United Nations Climate Change Conference in Cancun, Mexico.

The Company has historically emphasized the Current Policies Scenario in its strategic planning processes and its investor communications. We believe that the Current Policies Scenario is the most appropriate for our investors to consider because we believe that it has proven to be the scenario that has yielded the most accurate projections of coal usage. Although the New Policies Scenario is the IEA's central scenario, the IEA does not endorse any particular scenario as being a more probable forecast than the others.

The IEA estimates in its WEO 2015, Current Policies Scenario, that worldwide primary energy demand will grow 45% (32% under the New Policies Scenario) between 2013 and 2040. Demand for coal during this time period is projected to rise 43% (12% under the New Policies Scenario)



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Under its Current Policies Scenario, the IEA expects coal to retain its prominent presence as a fuel for the power sector worldwide. Coal's share of the power generation mix was 41% in 2013. By 2040, the IEA’s Current Policies Scenario estimates that coal's fuel share of global power generation will be 38% as it continues to have the largest share of worldwide electric power production (30%, slightly less than the share attributable to hydro and renewables, under the New Policies Scenario). Under the Current Policies Scenario, the IEA also projects that global natural gas-fueled electricity generation will have a compound annual growth rate of 2.7% from 2013-2040 (2.1% annual growth rate under the New Policies Scenario). The total amount of electricity generated from natural gas is expected to be approximately 36% below the total for coal (approximately 24% below the total for coal under the New Policies Scenario), even in 2040. Hydro and other renewables are projected to comprise a combined 27% of the 2040 fuel mix (34% under the New Policies Scenario) versus 22% in 2013. Electricity generation from nuclear power is expected to fall from 11% to 9% (while growing from 11% to 12% under the New Policies Scenario) between 2013 and 2040.

As noted above, projected coal usage is highest under the Current Policies Scenario. Future energy use consistent with the 450 Scenario would likely yield results materially lower than the projections noted above under the Current Policies Scenario or the New Policies Scenario.

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.

As discussed in more detail in the section entitled “Regulatory Matters - U.S. - Environmental Laws and Regulations,”, 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 fossil fuel-fired EGUs. The EPA expects the rule to have a significant impact on demand for coal-fired electricity generation in the U.S. and, depending upon the implementation methods adopted by the various states, we believe the rule could have a material adverse effect on our results of operations, financial condition and cash flows in future periods. On February 9, 2016, the U.S. Supreme Court granted a motion to stay the implementation of the rule until its legal challenges are resolved.

Liquidity and Capital Resources

Capital Resources

Our primary sources of cash are proceeds from the sale of our coal production to customers. We also generate cash from the sale of non-strategic assets, including coal reserves and surface lands, borrowings under our committed credit facilities and, from time to time, the issuance of securities.

As of December 31, 2015, our available liquidity was $1.2 billion, which was substantially comprised of $940.0 million available for borrowing under a $1.65 billion revolving credit facility (as amended, the 2013 Revolver) and $261.3 million of cash and cash equivalents. During February 2016, we borrowed the maximum amount available under the 2013 Revolver for general corporate purposes. As of March 11, 2016, our available liquidity declined to $0.9 billion, which consisted primarily of cash and cash equivalents. The decline since December 31, 2015 was primarily due to operational expenditures and the issuance of additional letters of credit.



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We incurred a substantial loss from operations and had negative cash flows from operating activities for the year ended December 31, 2015. Our current operating plan indicates that we will continue to incur losses from operations and generate negative cash flows from operating activities. These projections and certain liquidity risks raise substantial doubt about whether we will meet our obligations as they become due within one year after the date of this report. We have also elected to exercise the 30-day grace period with respect to a $21.1 million semi-annual interest payment due March 15, 2016 on the 6.50% Senior Notes due September 2020 and a $50.0 million semi-annual interest payment due March 15, 2016 on the 10.00% Senior Secured Second Lien Notes due March 2022, as provided for in the indentures governing these notes. Failure to pay these interest amounts on March 15, 2016 is not immediately an event of default under the indentures governing these notes, but would become an event of default if the payment is not made within 30 days of such date. As a result of these factors, as well as the continued uncertainty around global coal fundamentals, the stagnated economic growth of certain major coal-importing nations, and the potential for significant additional regulatory requirements imposed on coal producers, among other matters, there exists substantial doubt whether we will be able to continue as a going concern.

The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from uncertainty about our ability to continue as a going concern, other than the reclassification of certain long-term debt and the related debt issuance costs to current liabilities and current assets, respectively. The report from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2015 includes an uncertainty paragraph that summarizes the salient facts or conditions that raise substantial doubt about our ability to continue as a going concern.

Our 2013 Credit Facility and the indentures governing our 6.00%, 6.25%, 6.50% and 7.875 Senior Notes and our Senior Secured Second Lien Notes and the instruments governing our capital leases include cross-acceleration provisions whereby the debt owing under such agreements and instruments would be accelerated upon certain events, including a failure by us to service the debt in accordance with the relevant agreement. Our 2013 Credit Facility and its governing documents contain covenants that, among other things, require us to furnish audited financial statements as soon as available, but in any event within 90 days after the fiscal year end without a “going concern” uncertainty paragraph in the auditor’s opinion. Our consolidated financial statements for the year ended December 31, 2015 included herein contain a "going concern" uncertainty paragraph. In addition, we currently anticipate that our reported Adjusted EBITDA and other sources of earnings or adjustments used to calculate Consolidated EBITDA (if such other sources of earnings or adjustments do not include the proceeds of certain targeted asset sales) will fall below our Consolidated Net Cash Interest Charges during 2016, and we anticipate we will not comply with our financial covenants as of March 31, 2016. Absent waivers or cures, non-compliance with such covenants would constitute a default under the 2013 Credit Facility (after the expiration of any applicable grace period). It is possible we could obtain waivers from our lenders; however, since there is substantial doubt about whether we will meet our obligations as they become due within one year after the date of issuance of this report, the Company has classified debt that become accelerated as current in the consolidated financial statements as of December 31, 2015.



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Factors that could adversely impact our liquidity and ability to comply with our debt covenants include the following:


•	If we are unable to maintain our current level of self bonding for any reason. This would cause us to seek replacement financial assurances, which could include the need to provide collateral in the form of letters of credit or cash;

•

If we are required to provide additional collateral to support our operations. During the year ended December 31, 2015, we were required to increase our total posted letters of credit by $429.2 million to the issuing parties of certain of our surety bonds and bank guarantees, whereas we have not previously been required to do so, and we may be required to post additional collateral in the future to support such instruments or other operating requirements;


•	If we are unable to renew our accounts receivable securitization program at an appropriate capacity when it expires in April 2016; and


•	If we incur any additional liabilities or obligations as a result of the Patriot bankruptcy or other contingencies, as more fully described in Note 24. "Commitments and Contingencies" to the accompanying consolidated financial statements.

Debt Modification, Issuance and Refinancing. On February 5, 2015, we entered into the Omnibus Amendment Agreement (the First Amendment) related to our secured credit agreement dated September 24, 2013 (as amended, the 2013 Credit Facility) to enhance our financial flexibility. In addition to the pledge of certain collateral, among other things, the First Amendment:


•	amended the financial maintenance covenants to provide greater financial flexibility by lowering the minimum interest coverage ratio and increasing the maximum net secured first lien leverage ratio for the term of the 2013 Credit Facility;


•	amended the liens covenant to allow for second lien debt issuances, so long as we remain in compliance with the 2013 Credit Facility;

•

amended certain other negative covenants to (1) reduce the annual cash dividend payments basket to a maximum of $27.5 million (with carryforward permitted), (2) reduce the additional general restricted payments basket, which includes dividends, stock repurchases and certain investments, to a maximum of $100.0 million (though we may also make restricted payments using another basket whose size is based on, among other things, positive earnings during the term of the agreement) and (3) further limit our ability to incur liens, incur debt and make investments; and


•	provided for certain additional mandatory prepayments including with the net cash proceeds of certain asset sales, subject to customary reinvestment rights.

We paid aggregate modification costs of $11.8 million related to the First Amendment during the year ended December 31, 2015, which will be amortized over the remaining term of the facility.

On March 16, 2015, we completed the offering of $1.0 billion aggregate principal amount of our 10.00% Senior Secured Second Lien Notes due March 2022 (the Senior Secured Second Lien Notes). The Senior Secured Second Lien Notes are secured by a second-priority lien on all of the assets that secure the Company's obligations under the 2013 Credit Facility on a first-priority basis, subject to permitted liens and other limitations. Additional information surrounding the collateral securing the 2013 Credit Facility and the Senior Secured Second Lien Notes is included in Note 12. "Long-term Debt" to the accompanying consolidated financial statements.

The notes were issued at an issue price of 97.566% of principal amount, resulting in original issue discount of $24.3 million that will be amortized through maturity. The Company also paid aggregate debt issuance costs of $16.9 million during the year ended December 31, 2015 related to the offering, which will also be amortized over the life of the Senior Secured Second Lien Notes.

We used the net proceeds from the sale of the notes, in part, to fund (1) the March 2015 tender offer through which we repurchased $566.9 million aggregate principal amount of the 2016 Senior Notes and (2) the April 2015 redemption of $83.1 million aggregate principal amount of the 2016 Senior Notes that was not tendered in the tender offer. We used the remaining proceeds for general corporate purposes.

In connection with the tender offer, we recognized an aggregate loss on debt extinguishment of $67.8 million in the audited consolidated statement of operations for the year ended December 31, 2015. That charge was comprised of tender offer premiums paid of $66.4 million and the write-off of associated unamortized debt issuance costs of $1.4 million. As market conditions warrant, we may from time to time continue to repurchase debt securities issued by us, in the open market, in privately negotiated transactions, by tender offer, by exchange offer or otherwise.



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Cash and Cash Equivalents. We follow a diversified investment approach for our cash and cash equivalents by maintaining such funds with a diversified portfolio of banks in high quality, highly liquid investments with original maturities of three months or less, generally comprised of money market funds, term deposits and government securities. We monitor the amounts held with each bank on a routine basis and do not believe our cash and cash equivalents are exposed to any material risk of principal loss.

We hold cash balances within the U.S. and in several foreign locations around the world. As of December 31, 2015, approximately $18.6 million of our cash was held by U.S. entities, with the remaining balance held by foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by our foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia and the foreign operations of our Trading and Brokerage segment. Under current law, earnings repatriated to the U.S. are subject to U.S. federal income tax, less applicable foreign tax credits. We had no undistributed earnings of foreign subsidiaries as of December 31, 2015. Historically, we have not provided deferred taxes on undistributed earnings of foreign subsidiaries because such earnings are considered to be indefinitely reinvested outside of the U.S. We utilize a variety of tax planning and financing strategies with the objective of having our worldwide cash available in the locations where it is needed. When appropriate, we may access our foreign cash in a tax efficient manner. Where local regulations or other circumstances may limit an efficient intercompany transfer of amounts held outside of the U.S., we will continue to utilize those funds for local liquidity needs. We do not expect restrictions or potential taxes on the repatriation of amounts held by our foreign subsidiaries to have a material effect on our overall liquidity, financial condition or results of operations.

Proceeds from Asset Sales. During the year ended December 31, 2015, we generated $70.4 million in proceeds from the disposal of assets, largely driven by the sale of surplus surface lands in the U.S. and Australia. We will continue to monitor our portfolio for opportunities to divest assets as a source of potential liquidity. We evaluate potential asset sales using several criteria including strategic fit, value consideration, potential growth and cash requirements. We are currently advancing multiple asset sale processes.

Capital Requirements

Our primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs (including interest and principal), capital and operating lease payments, postretirement plans, take or pay obligations and past mining retirement obligations.

We had various bilateral credit and liquidity arrangements with banks, lenders and other counterparties that we used to support the ongoing requirements of our operations, where possible. In the second half of 2015, we were notified by several of such counterparties that our bilateral creditline would not be renewed unless we posted additional collateral. We posted additional collateral in the form of letters of credit.

We continually monitor capital and financial market conditions to evaluate the availability of alternative financing sources, including our ability to offer and sell securities. Our ability to obtain external financing and the cost of such financing is affected by our credit ratings, which are periodically reviewed by the three major credit rating agencies. In 2015, each of the three agencies downgraded our corporate credit rating and in early 2016 two of the three agencies again downgraded our corporate rating. The credit downgrades were, in part, due to continued weakness in seaborne coal prices. Given our financial condition, liquidity and credit ratings, and the uncertainty in capital and financial markets, our ability to access the capital markets, on commercially reasonable terms or at all, has been negatively impacted, which in turn, may impair our ability to fund our capital requirements.

While we were not required to post additional collateral as a direct result of our credit downgrades for counterparties to any of our derivative contracts, we have experienced an unfavorable change in payment terms and willingness to transact from certain coal trading counterparties. Also, we were required to issue a letter of credit of $65.0 million in the first quarter of 2015 (which has subsequently been reduced to $53.6 million) due to the downgrades to the benefit of one of our customers for a pricing rebate agreed to in 2014 in connection with an arbitration process, which correspondingly reduced our available liquidity as of December 31, 2015.

Additions to Property, Plant, Equipment and Mine Development. We evaluate our capital project portfolio on an ongoing basis and believe we have the appropriate flexibility to adjust our growth capital spending as appropriate based on any material changes in our cash flows from operations and liquidity position.

Additions to property, plant, equipment and mine development during the year ended December 31, 2015 included expenditures associated with advancing the reserve development at the Gateway North Mine in the U.S., which replaces production from the existing Gateway Mine as its reserves are exhausted in the second half of 2015.



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In response to the challenging global environment, we have sought to maintain a controlled, disciplined approach to capital spending in order to preserve liquidity. In 2015, we reduced our additions to property, plant, equipment and mine development to $126.8 million, a 35% decrease compared to the prior year. For 2016, we are again targeting a tightly controlled capital expenditure level of $120 million to $140 million. We plan to defer any significant growth and development projects across our global platform to time periods beyond 2016 and will continue to evaluate the timing associated with those projects based on changes in global coal supply and demand.

Coal Lease Expenditures. Federal coal lease expenditures, which pertain to U.S. federal coal reserves we lease from the U.S. Bureau of Land Management in support of our Western U.S. Mining segment operations, amounted to $277.2 million in 2015. We currently anticipate that our annual federal coal lease expenditures will total approximately $250 million and $1 million in 2016 and 2017, respectively. In January 2016, Secretary of the Interior Sally Jewell ordered a three-year pause on new leases for coal mined on federal land as part of a review of the government's management of vast amounts of taxpayer-owned coal throughout the West.

Total Indebtedness. Our total indebtedness as of December 31, 2015 and 2014 consisted of the following:



	December 31,
	2015			2014
	(Dollars in millions)
2013 Term Loan Facility due September 2020	$	1,164.9		$	1,175.1
7.375% Senior Notes due November 2016	—			650.0
6.00% Senior Notes due November 2018	1,518.8			1,518.8
6.50% Senior Notes due September 2020	650.0			650.0
6.25% Senior Notes due November 2021	1,339.6			1,339.6
10.00% Senior Secured Second Lien Notes due March 2022	978.4		—	—
7.875% Senior Notes due November 2026	247.7			247.6
Convertible Junior Subordinated Debentures due December 2066	385.2			382.3
Capital lease obligations	30.3			22.2
Other	0.7			1.2
Total	$	6,315.6		$	5,986.8

The carrying amounts of the 2013 Term Loan Facility due September 2020, the 10.00% Senior Secured Second Lien Notes due March 2022, the 7.875% Senior Notes due November 2026 and the Convertible Junior Subordinated Debentures due December 2066 (the Debentures) have been presented above net of the respective unamortized original issue discounts.

Long-term Debt Covenants. Certain of our long-term debt arrangements contain various administrative, reporting, legal and financial covenants. We are permitted to pay dividends, buy and sell assets and make redemptions or repurchases of capital stock, subject to restrictions imposed by the 2013 Credit Facility. Our negative covenants also collectively limit our ability to pay dividends from the top-level Gibraltar holding company of our Australian operations to our domestic subsidiaries in an amount in excess of $500 million per year. We were in compliance with our long-term debt covenants as of December 31, 2015.

The financial covenants included in our 2013 Credit Facility require us to maintain a maximum Consolidated Net Secured First Lien Leverage Ratio, as defined in the 2013 Credit Facility, and a minimum Consolidated Interest Coverage Ratio, as defined in the 2013 Credit Facility. More specifically, we are required to maintain, as of the end of any fiscal quarter, (1) a Consolidated Net Secured First Lien Leverage Ratio, which is the ratio of Consolidated Net Senior First Lien Secured Debt, as defined in the 2013 Credit Facility, to Consolidated EBITDA, as defined in the 2013 Credit Facility, not to exceed 4.5 to 1.0 and (2) a Consolidated Interest Coverage Ratio, which is the ratio of Consolidated EBITDA to Consolidated Net Cash Interest Charges, as defined in the 2013 Credit Facility, of at least 1.0 to 1.0, in each case calculated for the four prior consecutive fiscal quarters. Our Consolidated Net Secured First Lien Leverage Ratio was approximately 1.6 to 1.0 and our Consolidated Interest Coverage Ratio was approximately 1.3 to 1.0, in each case, as of December 31, 2015. and our borrowing capacity under the 2013 Credit Facility may be less than the maximum borrowing capacity. The maximum borrowing capacity under the 2013 Credit Facility is limited by our Consolidated Net Secured First Lien Leverage Ratio, as described above, such that any borrowings under the 2013 Revolver plus outstanding borrowings under the 2013 Term Loan Facility and any other senior secured first lien debt, less cash and cash equivalents, cannot exceed our Consolidated EBITDA, as defined in the 2013 Credit Facility, as of the end of any computation period by a ratio of more than 4.5 to 1.0.



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We have a history of engaging with our lenders to proactively address ongoing financial covenant compliance and our liquidity and financial flexibility, as evidenced by the First Amendment discussed above. Nonetheless, we cannot guarantee that such endeavors, if necessary, would prove successful in the future. If we are unable to maintain compliance with these financial covenants and are unable to obtain waivers or amendments from our revolving lenders, the revolving lenders may declare revolving loans under our 2013 Credit Facility due and begin to exercise remedies. If such event occurs and the exercise of remedies are material, the term loans and revolver under our 2013 Credit Facility may be declared due by lenders, which would trigger the cross-acceleration provisions in our Senior Notes, and our Senior Secured Second Lien Notes meaning that the debt owing under such agreements could be accelerated. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to us. If our debt is in default for any reason and we are unable to successfully restructure our debt, our business, financial condition and results of operations could be materially and adversely affected, which could require us to reorganize our company in its entirety, including through bankruptcy proceedings. Refer to Part I, Item 1A. “Risk Factors” of this Annual Report on Form 10-K for a discussion of the risks associated with our indebtedness, liquidity and debt covenants.

Dividends. We had declared and paid quarterly dividends since our initial public offering in 2001, including $1.4 million paid in 2015 ($0.0375 per share each quarter). In connection with our ongoing efforts to manage our cash and preserve liquidity in light of the challenged global coal market conditions experienced in recent years, our Board of Directors suspended our quarterly dividend beginning in the third quarter of 2015. Our Board of Directors will continue to evaluate the appropriate dividend rate over time. The declaration and payment of dividends in the future and the amount of those dividends will depend on our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by our debt covenants and other factors that our Board of Directors may deem relevant to such evaluations.

Settlement Agreement with Patriot and the UMWA. In connection with our settlement agreement with Patriot and the UMWA, on behalf of itself, its represented Patriot employees and its represented Patriot retirees, that became effective in December 2013 (2013 Agreement), we were required to provide total payments of $310 million payable over four years through 2017 to partially fund the newly established voluntary employee beneficiary association (VEBA) and settle all Patriot and UMWA claims involving Patriot's first bankruptcy. Those payments included an initial payment of $90 million made in January 2014, comprised of $70 million paid to Patriot and $20 million paid to the VEBA, and subsequent payments of $75 million in 2015, $75 million in 2016 and $70 million in 2017 to be paid to the VEBA.

We, Patriot and the UMWA signed a new settlement agreement (2015 Agreement) on December 30, 2015 that became effective in early January 2016. The 2015 Agreement partially amended the 2013 Agreement, including the required payments to the UMWA VEBA. Under the 2015 Agreement, we are required to pay the VEBA $7.5 million per month for ten months beginning January 2016 for total payments to the VEBA of $75 million. Under no circumstances can we be forced to pay more than $75 million to the VEBA. The 2015 Agreement will provide cash savings of approximately $70 million as compared to the payment provisions of the 2013 Agreement.

Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" to the accompanying consolidated financial statements for additional information surrounding the settlement agreement.

Pension Contributions. Annual contributions to qualified plans are made in accordance with minimum funding standards and the Company's agreement with the Pension Benefit Guaranty Corporation. Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006 (generally 80%). During the year ended December 31, 2015, we contributed $4.5 million and $1.7 million to our qualified and non-qualified pension plans, respectively. We expect to contribute approximately $2.2 million to our pension plans to meet minimum funding requirements for our qualified plans and benefit payments for our non-qualified plans in 2017 after all contingencies were satisfied.

Share Repurchases. As of December 31, 2015, our remaining available capacity for share repurchases under our publicly-announced repurchase program authorized by our Board of Directors was $700.4 million. Repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options.



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Historical Cash Flows

The following table summarizes our cash flows for the years ended December 31, 2015 and 2014, as reported in the accompanying consolidated financial statements:



	Year Ended December 31,						Increase (Decrease) to Cash Flow
	2015			2014			$			%
	(Dollars in millions)
Net cash (used in) provided by operating activities	$	(14.4	)	$	336.6		$	(351.0	)	(104.3	)%
Net cash used in investing activities	(290.0		)	(314.5		)	24.5			7.8	%
Net cash provided by (used in) financing activities	267.7			(168.1		)	435.8			259.3	%
Net change in cash and cash equivalents	(36.7		)	(146.0		)	109.3			74.9	%
Cash and cash equivalents at beginning of period	298.0			444.0			(146.0		)	(32.9	)%
Cash and cash equivalents at end of period	$	261.3		$	298.0		$	(36.7	)	(12.3	)%

Operating Activities. The decrease in net cash provided by operating activities for the year ended December 31, 2015 compared to the prior year was driven by the decline in results from operations due to a decline in coal pricing and demand during 2015.

Investing Activities. The favorable change in cash results from investing activities for the year ended December 31, 2015 compared to the prior year was mainly due to:


•	Lower current year capital spending as we continue to tightly control capital to preserve liquidity ($67.6 million);


•	Higher net proceeds from debt and equity security investment transactions ($76.8 million) due mainly from the fourth quarter 2015 sale of debt securities and the second quarter 2015 divestment of our prior holdings of Winsway Enterprises Holdings Limited marketable equity securities; partially offset by


•	Lower proceeds from the disposal of assets driven by cash received from the first quarter 2014 sale of a non-strategic exploration tenement asset in Australia and certain sale-leaseback transactions completed in the prior year ($133.3 million).

Financing Activities. The increase in net cash provided by financing activities for the year ended December 31, 2015 compared to the prior year was reflective of:


•	Proceeds from the issuance of our Senior Secured Second Lien Notes ($975.7 million, net of original issue discount); and


•	Lower dividend payments due to the elimination of our quarterly dividend in the third quarter of 2015 ($90.9 million); partially offset by


•	The extinguishment of $650.0 million aggregate principal amount of our 2016 Senior Notes using a portion of the proceeds from our Senior Secured Second Lien Notes.



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Contractual Obligations

The following is a summary of our contractual obligations as of December 31, 2015:



	Payments Due By Year
	Total		Less than 1 Year		2 - 3 Years		4 - 5 Years		More than 5 Years
	(Dollars in millions)
Long-term debt obligations (principal and interest)	$	9,727.2	$	6,694.7	$	894.7	$	670.1	$	1,467.7
Capital lease obligations (principal and interest)	40.1		12.9		16.1		1.0		10.1
Operating lease obligations⁽¹⁾	598.8		191.5		283.2		87.6		36.5
Unconditional purchase obligations⁽²⁾	20.0		20.0		—		—		—
Coal reserve lease and royalty obligations⁽³⁾	363.6		254.3		40.2		38.3		30.8
Take or pay obligations⁽⁴⁾	2,236.0		301.3		564.7		401.7		968.3
Other long-term liabilities⁽⁵⁾	3,049.7		295.2		348.1		366.7		2,039.7
Total contractual cash obligations	$	16,035.4	$	7,769.9	$	2,147.0	$	1,565.4	$	4,553.1


⁽¹⁾	Excludes contingent rents. Refer to Note 13. "Leases" to the accompanying consolidated financial statements for additional discussion of contingent rental agreements.

⁽²⁾

We routinely enter into purchase agreements with approved vendors for most types of operating expenses in the ordinary course of business. Our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements, combined with any other open purchase orders, are not material and though they are considered enforceable and legally binding, the related terms generally allow us the option to cancel, reschedule or adjust our requirements based on our business needs prior to the delivery of goods or performance of services. Accordingly, the commitments in the table above relate to orders to suppliers for capital purchases.


⁽³⁾	Includes $0.2 billion of federal coal lease expenditures due in annual installments through 2018, the substantial majority of which end after 2016.

⁽⁴⁾

Represents various short- and long-term take or pay arrangements in Australia and the U.S. associated with rail and port commitments for the delivery of coal, including amounts relating to export facilities. Also includes commitments under electricity, water and coal washing agreements with joint ventures. Subsequent to December 31, 2015, the Company amended certain contracts to reduce U.S. transportation and logistics costs. In connection with these amendments, Peabody will realize a net reduction of approximately $45 million in estimated liquidated damage payments that otherwise would have become due with respect to these take-or-pay arrangements in 2017. The amounts above are shown net of amendment.

⁽⁵⁾

Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans, mine reclamation and end of mine closure costs and exploration obligations. Also includes $75 million of required payments to the VEBA established in connection with Patriot's bankruptcy, as discussed in further detail in the "Capital Requirements" section above.

We do not expect any of the $19.6 million of net unrecognized tax benefits reported in our consolidated financial statements to require cash settlement within the next year. Beyond that, we are unable to make reasonably reliable estimates of periodic cash settlements with respect to such unrecognized tax benefits.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to guarantees and financial instruments with off-balance-sheet risk, most of which are not reflected in the accompanying consolidated balance sheets. As of March 15, 2016, we do not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities already provided for in the consolidated balance sheet as of December 31, 2015. However, we could experience a decline in our liquidity as financial assurances associated with reclamation obligations, bank guarantees, surety bonds or other obligations are required to be collateralized by cash or letters of credit.

Guarantees and Other Financial Instruments with Off-Balance Sheet Risk. See Note 23. "Financial Instruments, Guarantees with Off-Balance Sheet Risk and Other Guarantees" to our consolidated financial statements for a discussion of our accounts receivable securitization program and guarantees and other financial instruments with off-balance sheet risk.



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As previously noted, we had various bilateral credit and liquidity arrangements with banks, lenders and other counterparties that were generally provided on an uncommitted basis and were subject to be repriced, or the related capacity reduced or withdrawn, with limited or no notice by such counterparties. Earlier this year, we were notified by several of such counterparties that our bilateral credit lines would not be renewed, which may limit our ability to conduct our corporate hedging activities or to obtain sufficient bank guarantees required by our operations in Australia without posting additional collateral in the form of letters of credit. To the extent that our creditworthiness, as determined by such counterparties, deteriorates further, such credit arrangements may continue to become more costly and/or less available.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with U.S. GAAP. We are also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

Impairment of Long-Lived Assets. We evaluate our long-lived assets used in operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends and a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition. We generally do not view short-term declines in thermal and metallurgical coal prices in the markets in which we sell those products as a triggering event for conducting impairment tests because such markets have a history of price volatility. However, we view a sustained trend of depressed coal market pricing (for example, over periods exceeding one year) as an indicator of potential impairment.

Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. For our active mining operations, we generally group such assets at the mine level, or the mining complex level for mines that share infrastructure, with the exception of impairment evaluations triggered by mine closures. In those cases involving mine closures, the related assets are evaluated at the individual asset level for transferability to ongoing operating sites, remaining economic life for use in reclamation-related activities or for expected salvage. For our development and exploration properties and portfolio of surface land and coal reserve holdings, we consider several factors to determine whether to evaluate those assets individually or on a grouped basis for purposes of impairment testing. Such factors include geographic proximity to one another, the expectation of shared infrastructure upon development based on future mining plans and whether it would be most advantageous to bundle such assets in the event of a sale to a third party.

When indicators of impairment are present, we evaluate our long-lived assets used in operations for recoverability by comparing the estimated undiscounted cash flows expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. As quoted market prices are unavailable for our individual mining operations, fair value is determined through the use of an expected present value technique based on the income approach, except for non-strategic coal reserves, surface lands and undeveloped coal properties excluded from our long-range mine planning. In those cases, a market approach is utilized based on the most comparable market multiples available. The estimated future cash flows and underlying assumptions used to assess recoverability and, if necessary, measure the fair value of our long-lived assets are derived from those developed in connection with our planning and budgeting process. We believe our assumptions are consistent with those a market participant would use for valuation purposes. The most critical assumptions underlying our projections include those surrounding future coal prices for unpriced coal, production costs (including costs for labor, commodity supplies and contractors), transportation costs, foreign currency exchange rates and a risk-adjusted, after-tax cost of capital (all of which generally constitute unobservable Level 3 inputs under the fair value hierarchy), in addition to market multiples for non-strategic coal reserves, surface lands and undeveloped coal properties excluded from our long-range mine planning (which generally constitute Level 3 inputs under the fair value hierarchy).



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Impairment of long-lived assets included in continuing operations was $1,001.3 million for the year ended December 31, 2015. The assumptions used are based on our best knowledge at the time we prepare our analysis but can vary significantly due to changes in coal supply and demand, regulatory issues, unforeseen mining conditions, commodity prices and cost of labor. These types of changes may cause us to be unable to recover all or a portion of the carrying value of its long-lived assets. Because of the volatile and cyclical nature of the international seaborne coal markets, it is reasonably possible that seaborne metallurgical coal prices may not improve or decrease further in the near term, which, absent sufficient mitigation such as an offsetting reduction in the Company's operating costs, may result in the need for future adjustments to the carrying value of our long-lived mining assets. The Company's assets whose recoverability and values are most sensitive to near-term pricing include certain Australian metallurgical and thermal assets for which impairment charges were recorded in 2015 and certain U.S. coal properties being leased to unrelated mining companies under agreements that require royalties to be paid as the coal is mined. Such assets had an aggregate carrying value of $186.1 million as of December 31, 2015. We conducted a review of those assets for recoverability as of December 31, 2015 and determined that, other than the charges described above, no further impairment charge was necessary as of that date.

See Note 2. "Asset Impairment" to our consolidated financial statements for additional information regarding impairment charges.

Income Taxes. We account for income taxes in accordance with accounting guidance which requires deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. The guidance also requires that deferred tax assets be reduced by a valuation allowance if it is “more likely than not” that some portion or all of the deferred tax asset will not be realized. In our evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income in carryback years. As of December 31, 2015, we had valuation allowances for income taxes totaling $1,447.3 million. If actual results differ from the assumptions made in our annual evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period such determination is made.

Our liability for unrecognized tax benefits contains uncertainties because management is required to make assumptions and to apply judgment to estimate the exposures associated with our various filing positions. We recognize the tax benefit from an uncertain tax position only if it is “more likely than not” that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position must be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. As of December 31, 2015, we had net unrecognized tax benefits of $19.6 million included in recorded liabilities in the consolidated balance sheet. We believe that our judgments and estimates are reasonable; however, to the extent we prevail in matters for which liabilities have been established, or are required to pay amounts in excess of our recorded liabilities, our effective tax rate in a given period could be materially affected.

See Note 10. "Income Taxes" in the accompanying consolidated financial statements for additional information regarding valuation allowances and unrecognized tax benefits.

Postretirement Benefit and Pension Liabilities. We have long-term liabilities for our employees’ postretirement benefit costs and defined benefit pension plans. Liabilities for postretirement benefit costs are not funded. Our pension obligations are funded in accordance with the provisions of applicable laws. Expense for the year ended December 31, 2015 for postretirement benefit costs and pension liabilities totaled $98.6 million, while employer contributions were $51.0 million.

Each of these liabilities is actuarially determined and we use various actuarial assumptions, including the discount rate, future cost trends, demographic assumptions and expected asset returns to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities. We make assumptions related to future trends for medical care costs in the estimates of postretirement benefit costs. Our medical trend assumption is developed by annually examining the historical trend of cost per claim data. In addition, we make assumptions related to rates of return on plan assets in the estimates of pension obligations. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could affect our obligation to satisfy these or additional obligations.



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For our postretirement benefit obligation, assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for our health care plans. Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.



	For Year Ended December 31, 2015
	One-Percentage- Point Increase		One-Percentage- Point Decrease
	(Dollars in millions)
Health care cost trend rate:
Effect on total net periodic postretirement benefit cost	$	10.7	$	(9.4	)
Effect on total postretirement benefit obligation	$	71.3	$	(62.3	)



	For Year Ended December 31, 2015
	One-Half Percentage- Point Increase			One-Half Percentage- Point Decrease
	(Dollars in millions)
Discount rate:
Effect on total net periodic postretirement benefit cost	$	(2.3	)	$	2.1
Effect on total postretirement benefit obligation	$	(38.2	)	$	40.2

For our pension obligation, assumed discount rates and expected returns on assets have a significant effect on the expense and funded status amounts reported for our defined benefit pension plans. Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.



	For Year Ended December 31, 2015
	One-Half Percentage- Point Increase			One-Half Percentage- Point Decrease
	(Dollars in millions)
Discount rate:
Effect on total net periodic pension cost	$	(7.0	)	$	7.6
Effect on defined benefit pension plans' funded status	$	46.7		$	(51.1	)

Expected return on assets:
Effect on total net periodic pension cost	$	(3.9	)	$	3.9

See Note 15. "Postretirement Health Care and Life Insurance Benefits" and Note 16. "Pension and Savings Plans" to our consolidated financial statements for additional information regarding postretirement benefit and pension plans.

Asset Retirement Obligations. Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws in the U.S. and Australia as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, discounted using a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the reclamation activities), the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expenses for the year ended December 31, 2015 were $45.5 million, and payments totaled $21.6 million. See Note 14. "Asset Retirement Obligations" to our consolidated financial statements for additional information regarding our asset retirement obligations.

Fair Value Measurements of Financial Instruments. We evaluate the quality and reliability of the assumptions and data used in our foreign currency forward and option contracts, commodity futures, swaps and options and physical commodity purchase/sale contracts (collectively referred to as “Instruments and Contracts”) to measure fair value in the three level hierarchy, Levels 1, 2 and 3. Level 3 fair value measurements are those where inputs are unobservable or observable but cannot be market-corroborated, requiring us to make assumptions about pricing by market participants.



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Generally, these Instruments and Contracts are valued using internally generated models that include forward pricing curve quotes from one to three reputable brokers. Our valuation techniques also include basis adjustments for heat rate, sulfur and ash content, port and freight costs, and credit risk. We validate our valuation inputs with third-party information and settlement prices from other sources where available. We also consider credit and nonperformance risk in the fair value measurement by analyzing the counterparty’s exposure balance, credit rating and average default rate, net of any counterparty credit enhancements (e.g., collateral), as well as our own credit rating for financial liability trading positions. Certain Instruments and Contracts include a credit valuation adjustment based on credit and non-performance risk. If the relative value of the credit valuation adjustment to total fair value is greater than 10%, the Company considers the adjustment to be an unobservable input. Thus, the Instrument or Contract is considered Level 3.

We have consistently applied these valuation techniques in all periods presented, and believe we have obtained the most accurate information reasonably available for the types of Instruments and Contracts held. Valuation changes from period to period for each level will increase or decrease depending on: (1) the relative change in fair value for positions held, (2) new positions added, (3) realized amounts for completed trades, and (4) transfers between levels. Our strategies utilize various Instruments and Contracts. Periodic changes in fair value for purchase and sale positions occur in each level and therefore, the overall change in value of our Instruments and Contracts requires consideration of valuation changes across all levels.

At December 31, 2015 we had liabilities of $324.4 million of Non Coal Trading Instruments and Contracts categorized as Level 3. See Note 6. "Derivatives and Fair Value Measurements" to our consolidated financial statements for additional information regarding fair value measurements of our net financial asset trading positions.

At December 31, 2015 and 2014, we had liabilities of $15.6 million and assets of $2.1 million, respectively, of Coal Trading Instruments and Contracts categorized as Level 3. See Note 7. "Coal Trading" to our consolidated financial statements for additional information regarding fair value measurements of our net financial asset trading positions.

Contingent liabilities. From time to time, we are subject to legal and environmental matters related to our continuing and discontinued operations and certain historical, non-coal producing operations. In connection with such matters, we are required to assess the likelihood of any adverse judgments or outcomes, as well as potential ranges of probable losses.

A determination of the amount of reserves required for these matters is made after considerable analysis of each individual issue. We accrue for legal and environmental matters within "Operating costs and expenses" when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We provide disclosure surrounding loss contingencies when we believe that it is at least reasonably possible that a material loss may be incurred or an exposure to loss in excess of amounts already accrued may exist. Adjustments to contingent liabilities are made when additional information becomes available that affects the amount of estimated loss, which information may include changes in facts and circumstances, changes in interpretations of law in the relevant courts, the results of new or updated environmental remediation cost studies and the ongoing consideration of trends in environmental remediation costs.

Accrued contingent liabilities exclude claims against third parties and are not discounted. The current portion of these accruals is included in “Accounts payables and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in our consolidated balance sheets. In general, legal fees related to environmental remediation and litigation are charged to expense. We include the interest component of any litigation-related penalties within "Interest expense" in our consolidated statements of operations.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

See Note 1. "Summary of Significant Accounting Policies" to our consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

The potential for changes in the market value of our coal and freight-related trading, crude oil, diesel fuel, natural gas and foreign currency contract portfolios, as applicable, is referred to as “market risk.” Market risk related to our coal trading and freight-related contract portfolio, which includes bilaterally-settled and over-the-counter (OTC) exchange-settled trading, in addition to, from time to time, the brokered trading of coal, is evaluated using a value at risk (VaR) analysis. VaR analysis is not used to evaluate our non-trading diesel fuel or foreign currency hedging portfolios, as applicable, or coal trading activities we employ in support of coal production (as discussed below). We attempt to manage market price risks through diversification, controlling position sizes and executing hedging strategies. Due to a lack of quoted market prices and the long-term, illiquid nature of the positions, we have not quantified market price risk related to our non-trading, long-term coal supply agreement portfolio.



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Coal Trading Activities and Related Commodity Price Risk

Coal Price Risk Monitored Using VaR. We engage in direct and brokered trading of physical coal and freight-related commodities in OTC markets. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor, manage and hedge market price risk due to current and anticipated trading activities to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of market price risk, as measured by VaR, that we may assume at any point in time from our trading and brokerage activities.

We generally account for our coal trading activities using the fair value method, which requires us to reflect contracts with third parties that meet the definition of a derivative at market value in our consolidated financial statements, with the exception of contracts for which we have elected to apply the normal purchases and normal sales exception. Our trading portfolio included futures, forwards, swaps and options as of December 31, 2015. The use of VaR allows us to quantify in dollars, on a daily basis, a measure of price risk inherent in our trading portfolio. VaR represents the expected loss in portfolio value due to adverse market price movements over a defined time horizon (liquidation period) within a specified confidence level. Our VaR model is based on a variance/co-variance approach, which captures our potential loss exposure related to future, forward, swap and option positions. Our VaR model assumes a 5- to 15-day holding period, dependent upon the products within our portfolio, at the time of VaR measurement and produces an output corresponding with a 95% one-tailed confidence interval, which means that there is a one in 20 statistical chance that our portfolio could lose more than the VaR estimates during the assumed liquidation period. Our volatility calculation incorporates an exponentially weighted moving average algorithm based on price movements during the previous 60 market days, which makes our volatility more representative of recent market conditions while still reflecting an awareness of historical price movements. VaR does not estimate the maximum potential loss expected in the 5% of the time that changes in the portfolio value during the assumed liquidation period is expected to exceed measured VaR. We use stress testing and scenario analysis to help provide visibility in such cases, as discussed further below.

VaR analysis allows us to aggregate market price risk across products in the portfolio, compare market price risk on a consistent basis and identify the drivers of risk and changes thereto over time. We use historical data to estimate price volatility as an input to VaR. Given our reliance on historical data, we believe VaR is reasonably effective in characterizing market price risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. Nonetheless, an inherent limitation of VaR is that past changes in market price risk factors may not produce accurate predictions of future market price risk. Due to that limitation, combined with the subjectivity in the choice of the liquidation period and reliance on historical data to calibrate our models, we perform stress and scenario analyses as needed to estimate the impacts of market price changes on the value of the portfolio. Additionally, back-testing is regularly performed to monitor the effectiveness of our VaR measure. The results of these analyses are used to supplement the VaR methodology and identify additional market price-related risks.

During the year ended December 31, 2015, the actual low, high and average VaR was $1.0 million, $8.3 million and $3.4 million, respectively.

Other Risk Exposures. We also use our coal trading and brokerage platform to support various coal production-related activities. These transactions may involve coal to be produced from our mines, coal sourcing arrangements with third-party mining companies, joint venture positions with producers or offtake agreements with producers. While the support activities (such as the forward sale of coal to be produced and/or purchased) may ultimately involve instruments sensitive to market price risk, the sourcing of coal in these arrangements does not involve market risk sensitive instruments and does not encompass the commodity price risks that we monitor through VaR analysis, as discussed above.

Future Realization. As of December 31, 2015, the timing of the estimated future realization of the value of our trading portfolio was as follows:



	Percentage of
Year of Expiration	Portfolio Total
2016	109	%
2017	(11	)%
2018	2	%
	100	%

We also monitor other types of risk associated with our coal trading activities, including credit, market liquidity and counterparty nonperformance.



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Credit and Nonperformance Risk

Coal Trading. The fair value of our coal trading assets and liabilities reflects adjustments for credit risk. Our exposure is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If we engage in a transaction with a counterparty that does not meet our credit standards, we seek to protect its position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by our credit management function), we have taken steps to reduce our exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay or perform. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset asset and liability positions with such counterparties and, to the extent required, we will post or receive margin amounts associated with exchange-cleared and certain over-the-counter positions. We also continually monitor counterparty and contract nonperformance risk, if present, on a case-by-case basis.

Non-Coal Trading. The fair value of our non-coal trading derivative assets and liabilities reflects adjustments for credit risk. We manage our counterparty risk from our hedging activities related to foreign currency and fuel exposures, as applicable, through established credit standards, diversification of counterparties, utilization of investment grade commercial banks, adherence to established tenor limits based on counterparty creditworthiness and continual monitoring of that creditworthiness. To reduce our credit exposure for these hedging activities, we seek to enter into netting agreements with counterparties that permit us to offset receivable and payables with such counterparties in the event of default. We also continually monitor counterparties for nonperformance risk, if present, on a case-by-case basis.

Foreign Currency Risk

We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. The accounting for these derivatives is discussed in Note 6 "Derivatives and Fair Value Measurements" to our consolidated financial statements. At December 31, 2015, the majority of our derivative contracts used to hedge foreign currency risk were no longer considered highly effective at offsetting changes in cash flows. As a result, we could experience additional volatility in our earnings. Assuming we had no foreign currency hedging instruments in place, our exposure in operating costs and expenses due to a $0.05 change in the Australian dollar/U.S. dollar exchange rate is approximately $103 million for 2016. Taking into consideration the derivative contracts in place as of December 31, 2015, our net exposure to the same rate change is approximately $27 million for 2016. The notional amounts of our foreign currency hedge contracts as of December 31, 2015 are noted in the "Notional Amounts and Fair Value" section of Note 6 to our consolidated financial statements, which information is incorporated herein by reference.

Other Non-Coal Trading Activities — Commodity Price Risk

Long-Term Coal Contracts. We predominantly manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements (those with terms longer than one year) to the extent possible, rather than through the use of derivative instruments. Sales under such agreements comprised approximately 88%, 83% and 80% of our worldwide sales (by volume) for the years ended December 31, 2015, 2014 and 2013, respectively. As of December 31, 2015, approximately 100% of our projected 2016 U.S. coal production is priced at planned production levels of 150 million to 160 million tons. We had 40% to 45% of expected full year 2016 seaborne thermal coal volumes of 9 million to 10 million tons available for pricing at December 31, 2015. We expect near-term macroeconomic movements to dictate quarterly metallurgical coal pricing for the remainder of 2016 and we are targeting total 2016 metallurgical coal sales of approximately 14 million to 15 million tons.

Diesel Fuel and Explosives Hedges. We manage commodity price risk of the diesel fuel and explosives used in our mining activities through the use of cost pass-through contracts and derivatives, primarily swaps. Notional amounts outstanding under fuel-related and explosives-related derivative swap contracts are noted in the "Notional Amounts and Fair Value" section of Note 6 to our consolidated financial statements, which information is incorporated herein by reference. At December 31, 2015, the majority of our derivative contracts used to manage commodity price risk of the diesel fuel used in our mining activities were no longer considered highly effective at offsetting changes in cash flows. As a result, we could experience additional volatility in our earnings.

We expect to consume 125 to 135 million gallons of diesel fuel in 2016. Assuming we had no hedges in place, a $10 per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease our annual diesel fuel costs by approximately $30 million based on our expected usage. Taking into consideration hedges in place as of December 31, 2015, our net exposure to the same change in the price of crude oil is approximately $(5) million.



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Interest Rate Risk

Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. From time to time, we manage our debt to achieve a certain ratio of fixed-rate debt and variable-rate debt as a percent of net debt through the use of various hedging instruments. As of December 31, 2015, we had $5.2 billion of fixed-rate borrowings and $1.2 billion of variable-rate borrowings outstanding and had no interest rate swaps in place. A one percentage point increase in interest rates would result in an annualized increase to interest expense of approximately $5 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $18 million in the estimated fair value of these borrowings.

Item 8. Financial Statements and Supplementary Data.

See Part IV, Item 15. "Exhibits and Financial Statement Schedules" of this report for the information required by this Item 8, which information is incorporated by reference herein.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including the principal executive officer and principal accounting officer, on a timely basis. As of December 31, 2015, the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of December 31, 2015, and concluded that such controls and procedures are effective to provide reasonable assurance that the desired control objectives were achieved.

Changes in Internal Control Over Financial Reporting

We periodically review our internal control over financial reporting as part of our efforts to ensure compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. In addition, we routinely review our system of internal control over financial reporting to identify potential changes to our processes and systems that may improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new systems, consolidating the activities of acquired business units, migrating certain processes to our shared services organizations, formalizing and refining policies and procedures, improving segregation of duties and adding monitoring controls. In addition, when we acquire new businesses, we incorporate our controls and procedures into the acquired business as part of our integration activities. There have been no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Report on Internal Control Over Financial Reporting

Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.



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Management conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company's internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved as of December 31, 2015.

Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited our internal control over financial reporting, as stated in their unqualified opinion report included herein.



/s/ Glenn L. Kellow			/s/ Amy B. Schwetz
Glenn L. Kellow President and Chief Executive Officer			Amy B. Schwetz Executive Vice President and Chief Financial Officer

March 15, 2016



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Peabody Energy Corporation

We have audited Peabody Energy Corporation’s (the Company’s) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Peabody Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Peabody Energy Corporation as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015 of Peabody Energy Corporation and our report dated March 15, 2016 expressed an unqualified opinion thereon that included an explanatory paragraph regarding Peabody Energy Corporation’s ability to continue as a going concern.

/s/ Ernst & Young LLP

St. Louis, Missouri

March 15, 2016



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Item 9B. Other Information.

None.

PART III

Item 10.Directors, Executive Officers and Corporate Governance.

The information required by Item 401 of Regulation S-K is included under the caption “Election of Directors-Director Qualifications” in our 2016 Proxy Statement and in Part I, Item 1. "Business" of this report under the caption “Executive Officers of the Company.” The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions “Ownership of Company Securities — Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance Matters” and “Information Regarding Board of Directors and Committees-Committees of the Board of Directors-Audit Committee” in our 2016 Proxy Statement. Such information is incorporated herein by reference.

Item 11.Executive Compensation.

The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K is included under the captions “Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Report of the Compensation Committee” in our 2016 Proxy Statement and is incorporated herein by reference.

Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by Item 403 of Regulation S-K is included under the caption “Ownership of Company Securities” in our 2016 Proxy Statement and is incorporated herein by reference.

Equity Compensation Plan Information

As required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2015:



	(a) Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights			Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Plan Category
Equity compensation plans approved by security holders	164,260	⁽¹⁾	$	541.09	⁽²⁾	1,482,417
Equity compensation plans not approved by security holders	—		—			—
Total	164,260		$	541.09		1,482,417


⁽¹⁾	Includes 15,201 shares issuable pursuant to outstanding deferred stock units and 17,337 shares issuable pursuant to outstanding performance units.


⁽²⁾	The weighted-average exercise price shown in the table does not take into account outstanding deferred stock units or performance awards.

Refer to Note 18. "Share-Based Compensation" to the accompanying consolidated financial statements for additional information regarding the material features of our equity compensation plans.

Item 13.Certain Relationships and Related Transactions, and Director Independence.

The information required by Items 404 and 407(a) of Regulation S-K is included under the captions “Policy for Approval of Related Person Transactions” and “Information Regarding Board of Directors and Committees-Director Independence” in our 2016 Proxy Statement and is incorporated herein by reference.



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Item 14.Principal Accountant Fees and Services.

The information required by Item 9(e) of Schedule 14A is included under the caption “Fees Paid to Independent Registered Public Accounting Firm” in our 2016 Proxy Statement and is incorporated herein by reference.

PART IV

Item 15.Exhibits and Financial Statement Schedules.

(a) Documents Filed as Part of the Report

(1) Financial Statements.

The following consolidated financial statements of Peabody Energy Corporation and the report thereon of the independent registered public accounting firm are included herein on the pages indicated:



	Page
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Statements of Operations — Years Ended December 31, 2015, 2014 and 2013	F-2
Consolidated Statements of Comprehensive Income — Years Ended December 31, 2015, 2014 and 2013	F-3
Consolidated Balance Sheets — December 31, 2015 and 2014	F-4
Consolidated Statements of Cash Flows — Years Ended December 31, 2015, 2014 and 2013	F-5
Consolidated Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2015, 2014 and 2013	F-7
Notes to Consolidated Financial Statements	F-8

(2) Financial Statement Schedules.

The following financial statement schedule of Peabody Energy Corporation is at the page indicated:



	Page
Valuation and Qualifying Accounts	F- 93

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are not applicable and, therefore, have been omitted.

(3) Exhibits.

See Exhibit Index hereto.

Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the Company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Securities and Exchange Commission upon request.



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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	PEABODY ENERGY CORPORATION

	/s/ GLENN L. KELLOW
	Glenn L. Kellow President and Chief Executive Officer

Date: March 15, 2016

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ GLENN L. KELLOW	President and Chief Executive Officer, Director (principal executive officer)	March 15, 2016
Glenn L. Kellow

/s/ AMY B. SCHWETZ	Executive Vice President and Chief Financial Officer (principal financial and accounting officer)	March 15, 2016
Amy B. Schwetz

/s/ WILLIAM A. COLEY	Director	March 15, 2016
William A. Coley	Director

/s/ WILLIAM E. JAMES	Director	March 15, 2016
William E. James	Director

/s/ ROBERT B. KARN III	Director	March 15, 2016
Robert B. Karn III	Director

/s/ HENRY E. LENTZ	Director	March 15, 2016
Henry E. Lentz	Director

/s/ ROBERT A. MALONE	Chairman	March 15, 2016
Robert A. Malone	Chairman

/s/ WILLIAM C. RUSNACK	Director	March 15, 2016
William C. Rusnack	Director

/s/ MICHAEL W. SUTHERLIN	Director	March 15, 2016
Michael W. Sutherlin	Director

/s/ JOHN F. TURNER	Director	March 15, 2016
John F. Turner	Director

/s/ SANDRA A. VAN TREASE	Director	March 15, 2016
Sandra A. Van Trease	Director

/s/ HEATHER A. WILSON	Director	March 15, 2016
Heather A. Wilson	Director



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Peabody Energy Corporation

We have audited the accompanying consolidated balance sheets of Peabody Energy Corporation (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Peabody Energy Corporation at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects the information set forth therein.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company incurred a substantial loss from operations and had negative cash flows from operating activities for the year ended December 31, 2015. The Company’s operating plan indicates that it will continue to incur losses from operations, generate negative cash flows from operating activities and violate certain debt covenants during the year ended December 31, 2016. These projections and certain liquidity risks raise substantial doubt about the Company’s ability to meet its obligations as they become due within one year after the date of this report and continue as a going concern. Management’s plans in regards to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty, other than the reclassification of long-term debt and the related debt issuance costs to current liabilities and current assets, respectively.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 15, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

St. Louis, Missouri

March 15, 2016



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PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions, except per share data)
Revenues
Sales	$	5,138.3		$	6,132.7		$	6,380.0
Other revenues	470.9			659.5			633.7
Total revenues	5,609.2			6,792.2			7,013.7
Costs and expenses
Operating costs and expenses (exclusive of items shown separately below)	5,007.7			5,716.9			5,729.1
Depreciation, depletion and amortization	572.2			655.7			740.3
Asset retirement obligation expenses	45.5			81.0			66.5
Selling and administrative expenses	176.4			227.1			244.2
Restructuring and pension settlement charges	23.5			26.0			11.9
Other operating (income) loss:
Net gain on disposal of assets	(45.0		)	(41.4		)	(52.6		)
Asset impairment	1,277.8			154.4			528.3
Settlement charges related to the Patriot bankruptcy reorganization	—			—			30.6
Loss from equity affiliates	15.9			107.6			40.2
Operating loss	(1,464.8		)	(135.1		)	(324.8		)
Interest expense	465.4			426.6			408.3
Loss on early debt extinguishment	67.8			1.6			16.9
Interest income	(7.7		)	(15.4		)	(15.7		)
Loss from continuing operations before income taxes	(1,990.3		)	(547.9		)	(734.3		)
Income tax (benefit) provision	(176.4		)	201.2			(448.3		)
Loss from continuing operations, net of income taxes	(1,813.9		)	(749.1		)	(286.0		)
Loss from discontinued operations, net of income taxes	(175.0		)	(28.2		)	(226.6		)
Net loss	(1,988.9		)	(777.3		)	(512.6		)
Less: Net income attributable to noncontrolling interests	7.1			9.7			12.3
Net loss attributable to common stockholders	$	(1,996.0	)	$	(787.0	)	$	(524.9	)

Loss from continuing operations
Basic loss per share	$	(100.34	)	$	(42.52	)	$	(16.80	)
Diluted loss per share	$	(100.34	)	$	(42.52	)	$	(16.80	)
Net loss attributable to common stockholders
Basic loss per share	$	(109.98	)	$	(44.09	)	$	(29.53	)
Diluted loss per share	$	(109.98	)	$	(44.09	)	$	(29.53	)

Dividends declared per share	$	0.075		$	5.100		$	5.100

See accompanying notes to consolidated financial statements



Peabody Energy Corporation	2015 Form 10-K	F- 2

Table of Contents

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Net loss	$	(1,988.9	)	$	(777.3	)	$	(512.6	)
Other comprehensive income (loss), net of income taxes:
Net change in unrealized (losses) gains on available-for-sale securities (net of respective tax (benefit) provision of ($0.1), ($0.5) and $0.5)
Unrealized holding losses on available-for-sale securities	—			(3.7		)	(12.3		)
Reclassification for realized losses included in net loss	—			2.9			12.8
Net change in unrealized (losses) gains on available-for-sale securities	—			(0.8		)	0.5
Net unrealized gains (losses) on cash flow hedges (net of respective tax provision (benefit) of $72.2, ($54.6) and ($300.0))
Decrease in fair value of cash flow hedges	(131.3		)	(195.0		)	(333.6		)
Reclassification for realized losses (gains) included in net loss	251.7			(10.2		)	(209.6		)
Net unrealized gains (losses) on cash flow hedges	120.4			(205.2		)	(543.2		)
Postretirement plans and workers' compensation obligations (net of respective tax provision (benefit) of $36.2, $(10.3) and $121.7)
Prior service credit (cost) for the period	10.4			11.4			(1.4		)
Net actuarial gain (loss) for the period	18.1			(142.7		)	110.9
Amortization of actuarial loss and prior service cost included in net loss	31.9			32.7			95.7
Postretirement plans and workers' compensation obligations	60.4			(98.6		)	205.2
Foreign currency translation adjustment	(34.9		)	(41.0		)	(92.7		)
Other comprehensive income (loss), net of income taxes	145.9			(345.6		)	(430.2		)
Comprehensive loss	(1,843.0		)	(1,122.9		)	(942.8		)
Less: Comprehensive income attributable to noncontrolling interests	7.1			9.7			12.3
Comprehensive loss attributable to common stockholders	$	(1,850.1	)	$	(1,132.6	)	$	(955.1	)

See accompanying notes to consolidated financial statements



Peabody Energy Corporation	2015 Form 10-K	F- 3

Table of Contents

PEABODY ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS



	December 31,
	2015			2014
	(Amounts in millions, except per share data)
ASSETS
Current assets
Cash and cash equivalents	$	261.3		$	298.0
Accounts receivable, net of allowance for doubtful accounts of $6.6 at December 31, 2015 and $5.8 at December 31, 2014	228.8			563.1
Inventories	307.8			406.5
Assets from coal trading activities, net	23.5			57.6
Deferred income taxes	53.5			80.0
Other current assets	503.1			305.8
Total current assets	1,378.0			1,711.0
Property, plant, equipment and mine development, net	9,258.5			10,577.3
Deferred income taxes	2.2			0.7
Investments and other assets	382.6			902.1
Total assets	$	11,021.3		$	13,191.1
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	5,930.4		$	21.2
Liabilities from coal trading activities, net	15.6			32.7
Accounts payable and accrued expenses	1,446.3			1,809.2
Total current liabilities	7,392.3			1,863.1
Long-term debt, less current portion	385.2			5,965.6
Deferred income taxes	69.1			89.1
Asset retirement obligations	686.6			722.3
Accrued postretirement benefit costs	722.9			781.9
Other noncurrent liabilities	846.7			1,042.6
Total liabilities	10,102.8			10,464.6
Stockholders’ equity
Preferred Stock — $0.01 per share par value; 10.0 shares authorized, no shares issued or outstanding as of December 31, 2015 or December 31, 2014	—			—
Perpetual Preferred Stock — 0.8 shares authorized, no shares issued or outstanding as of December 31, 2015 or December 31, 2014	—			—
Series Common Stock — $0.01 per share par value; 40.0 shares authorized, no shares issued or outstanding as of December 31, 2015 or December 31, 2014	—			—
Common Stock — $0.01 per share par value; 53.3 shares authorized, 19.3 shares issued and 18.5 shares outstanding as of December 31, 2015 and 19.0 shares issued and 18.1 shares outstanding as of December 31, 2014	0.2			0.2
Additional paid-in capital	2,410.7			2,386.0
Treasury stock, at cost — 0.8 shares as of December 31, 2015 and 0.9 shares as of December 31, 2014	(371.7		)	(467.1		)
(Accumulated deficit) retained earnings	(503.4		)	1,570.5
Accumulated other comprehensive loss	(618.9		)	(764.8		)
Peabody Energy Corporation stockholders’ equity	916.9			2,724.8
Noncontrolling interests	1.6			1.7
Total stockholders’ equity	918.5			2,726.5
Total liabilities and stockholders’ equity	$	11,021.3		$	13,191.1

See accompanying notes to consolidated financial statements



Peabody Energy Corporation	2015 Form 10-K	F- 4

Table of Contents

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Cash Flows From Operating Activities
Net loss	$	(1,988.9	)	$	(777.3	)	$	(512.6	)
Loss from discontinued operations, net of income taxes	175.0			28.2			226.6
Loss from continuing operations, net of income taxes	(1,813.9		)	(749.1		)	(286.0		)
Adjustments to reconcile loss from continuing operations, net of income taxes to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization	572.2			655.7			740.3
Noncash interest expense	30.6			23.6			32.0
Deferred income taxes	(107.6		)	231.9			(434.1		)
Noncash share-based compensation	28.2			46.8			50.9
Asset impairment	1,277.8			154.4			528.3
Settlement charges related to the Patriot bankruptcy	—			—			30.6
Net gain on disposal of assets	(45.0		)	(41.4		)	(52.6		)
Loss from equity affiliates	15.9			107.6			40.2
Gains on previously monetized foreign currency hedge positions	(14.9		)	(136.9		)	—
Changes in current assets and liabilities:
Accounts receivable	188.0			55.4			104.8
Change in receivable from accounts receivable securitization program	138.5			(70.0		)	75.0
Inventories	96.2			104.9			39.9
Net assets from coal trading activities	(27.3		)	(10.1		)	(83.7		)
Other current assets	14.8			7.7			3.1
Accounts payable and accrued expenses	(381.7		)	(29.2		)	(108.9		)
Asset retirement obligations	23.9			60.3			45.5
Workers’ compensation obligations	(4.2		)	2.2			7.3
Accrued postretirement benefit costs	18.7			9.6			17.0
Accrued pension costs	29.6			28.3			51.8
Other, net	(20.9		)	(10.7		)	(21.3		)
Net cash provided by continuing operations	18.9			441.0			780.1
Net cash used in discontinued operations	(33.3		)	(104.4		)	(57.7		)
Net cash (used in) provided by operating activities	(14.4		)	336.6			722.4
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	(126.8		)	(194.4		)	(328.4		)
Changes in accrued expenses related to capital expenditures	(9.2		)	(16.6		)	(120.7		)
Federal coal lease expenditures	(277.2		)	(276.7		)	(276.8		)
Proceeds from disposal of assets, net of notes receivable	70.4			203.7			178.3
Purchases of debt and equity securities	(28.8		)	(15.1		)	(22.8		)
Proceeds from sales and maturities of debt and equity securities	90.3			13.5			22.9
Maturity of short-term investments	—			—			4.8
Contributions to joint ventures	(425.4		)	(529.8		)	(671.7		)
Distributions from joint ventures	422.6			534.2			722.9
Advances to related parties	(3.7		)	(33.7		)	(42.1		)
Repayment of loans from related parties	0.9			5.4			25.2
Other, net	(3.1		)	(5.0		)	(5.8		)
Net cash used in continuing operations	(290.0		)	(314.5		)	(514.2		)
Net cash used in discontinued operations	—			—			(1.5		)
Net cash used in investing activities	(290.0		)	(314.5		)	(515.7		)

See accompanying notes to consolidated financial statements



Peabody Energy Corporation	2015 Form 10-K	F- 5

Table of Contents

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Cash Flows From Financing Activities
Proceeds from long-term debt	$	975.7		$	1.1		$	1,188.0
Repayments of long-term debt	(671.3		)	(21.0		)	(1,390.2		)
Payment of deferred financing costs	(28.7		)	(10.1		)	(22.8		)
Dividends paid	(1.4		)	(92.3		)	(91.7		)
Restricted cash for distributions to noncontrolling interests	—			(42.5		)	—
Other, net	(6.6		)	(3.3		)	(4.8		)
Net cash provided by (used in) financing activities	267.7			(168.1		)	(321.5		)
Net change in cash and cash equivalents	(36.7		)	(146.0		)	(114.8		)
Cash and cash equivalents at beginning of year	298.0			444.0			558.8
Cash and cash equivalents at end of year	$	261.3		$	298.0		$	444.0

See accompanying notes to consolidated financial statements



Peabody Energy Corporation	2015 Form 10-K	F- 6

Table of Contents

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY



	Peabody Energy Corporation Stockholders’ Equity
	Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests				Total Stockholders’ Equity
	(Dollars in millions)
December 31, 2012	$	0.2	$	2,288.9		$	(461.6	)	$	3,066.4		$	11.0		$	33.9			$	4,938.8
Net (loss) income	—		—			—			(524.9		)	—			12.3				(512.6		)
Net change in unrealized gains on available-for-sale securities (net of $0.5 tax provision)	—		—			—			—			0.5			—				0.5
Net unrealized losses on cash flow hedges (net of $300.0 tax benefit)	—		—			—			—			(543.2		)	—				(543.2		)
Postretirement plans and workers’ compensation obligations (net of $121.7 tax provision)	—		—			—			—			205.2			—				205.2
Foreign currency translation adjustment	—		—			—			—			(92.7		)	—				(92.7		)
Dividends paid	—		—			—			(91.7		)	—			—				(91.7		)
Share-based compensation for equity-classified awards	—		50.9			—			—			—			—				50.9
Write-off of excess tax benefits related to share-based compensation	—		(4.5		)	—			—			—			—				(4.5		)
Stock options exercised	—		1.0			—			—			—			—				1.0
Employee stock purchases	—		6.3			—			—			—			—				6.3
Repurchase of employee common stock relinquished for tax withholding	—		—			(3.1		)	—			—			—				(3.1		)
Distributions to noncontrolling interests	—		—			—			—			—			(7.0		)		(7.0		)
December 31, 2013	$	0.2	$	2,342.6		$	(464.7	)	$	2,449.8		$	(419.2	)	$	39.2			$	3,947.9
Net (loss) income	—		—			—			(787.0		)	—			9.7				(777.3		)
Net change in unrealized losses on available-for-sale securities (net of $0.5 tax benefit)	—		—			—			—			(0.8		)	—				(0.8		)
Net unrealized losses on cash flow hedges (net of $54.6 tax benefit)	—		—			—			—			(205.2		)	—				(205.2		)
Postretirement plans and workers’ compensation obligations (net of $10.3 tax benefit)	—		—			—			—			(98.6		)	—				(98.6		)
Foreign currency translation adjustment	—		—			—			—			(41.0		)	—				(41.0		)
Dividends paid	—		—			—			(92.3		)	—			—				(92.3		)
Share-based compensation for equity-classified awards	—		46.1			—			—			—			—				46.1
Write-off of excess tax benefits related to share-based compensation	—		(8.3		)	—			—			—			—				(8.3		)
Stock options exercised	—		0.5			—			—			—			—				0.5
Employee stock purchases	—		5.1			—			—			—			—				5.1
Repurchase of employee common stock relinquished for tax withholding	—		—			(2.4		)	—			—			—				(2.4		)
Distributions to noncontrolling interests	—		—			—			—			—			(4.7		)		(4.7		)
Dividend payable to noncontrolling interests	—		—			—			—			—			(42.5		)		(42.5		)
December 31, 2014	$	0.2	$	2,386.0		$	(467.1	)	$	1,570.5		$	(764.8	)	$	1.7			$	2,726.5
Net (loss) income	—		—			—			(1,996.0		)	—			7.1				(1,988.9		)
Net change in unrealized losses on available-for-sale-securities (net of $0.1 tax benefit)	—		—			—			—			—			—				—
Net unrealized gains on cash flow hedges (net of $72.2 tax provision)	—		—			—			—			120.4			—				120.4
Postretirement plans and workers' compensation obligations (net of $36.2 tax provision)	—		—			—			—			60.4			—				60.4
Foreign currency translation adjustment	—		—			—			—			(34.9		)	—				(34.9		)
Dividends paid	—		—			—			(1.4		)	—			—				(1.4		)
Share-based compensation for equity-classified awards	—		26.2			—			—			—			—				26.2
Employee stock purchases	—		3.4			—			—			—			—				3.4
Repurchase of employee common stock relinquished for tax withholding	—		—			(2.1		)	—			—			—				(2.1		)
Defined contribution plan share contribution	—		(1.4		)	97.5			(76.5		)	—			—				19.6
Purchase of interest of noncontrolling shareholders	—		(3.5		)	—			—			—			(0.5		)		(4.0		)
Consolidation of noncontrolling interests	—		—			—			—			—			1.6				1.6
Distributions to noncontrolling interests	—		—			—			—			—			(6.3		)		(6.3		)
Dividend payable to noncontrolling interests	—		—			—			—			—			(2.0		)	—	(2.0		)
December 31, 2015	$	0.2	$	2,410.7		$	(371.7	)	$	(503.4	)	$	(618.9	)	$	1.6			$	918.5

See accompanying notes to consolidated financial statements



Peabody Energy Corporation	2015 Form 10-K	F- 7

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)	Summary of Significant Accounting Policies

Basis of Presentation

The consolidated financial statements include the accounts of Peabody Energy Corporation (the Company) and its affiliates. Interests in subsidiaries controlled by the Company are consolidated with any outside shareholder interests reflected as noncontrolling interests, except when the Company has an undivided interest in an unincorporated joint venture. In those cases, the Company includes its proportionate share in the assets, liabilities, revenues and expenses of the jointly controlled entities within each applicable line item of the consolidated financial statements. All intercompany transactions, profits and balances have been eliminated in consolidation. Certain amounts from prior years have been reclassified to conform with the 2015 presentation.

Pursuant to the authorization provided at a special meeting of the Company's stockholders held on September 16, 2015, the Company completed a 1-for-15 reverse stock split of the shares of the Company’s common stock on September 30, 2015 (the Reverse Stock Split). As a result of the Reverse Stock Split, every 15 shares of issued and outstanding common stock were combined into one issued and outstanding share of Common Stock, without any change in the par value per share. No fractional shares were issued as a result of the Reverse Stock Split and any fractional shares that would otherwise have resulted from the Reverse Stock Split were paid in cash. The Reverse Stock Split reduced the number of shares of common stock outstanding from approximately 278 million shares to approximately 19 million shares. The number of authorized shares of common stock was also decreased from 800 million shares to 53.3 million shares. The Company's common stock began trading on a reverse stock split-adjusted basis on the New York Stock Exchange on October 1, 2015. All share and per share data included in this report has been retroactively restated to reflect the Reverse Stock Split. Since the par value of the common stock remained at $0.01 per share, the value for "Common stock" recorded to the Company's condensed consolidated balance sheets has been retroactively reduced to reflect the par value of restated outstanding shares, with a corresponding increase to "Additional paid-in capital."

The Company has classified items within discontinued operations in the audited consolidated financial statements for disposals (by sale or otherwise) that have occurred prior to January 1, 2015 when the operations and cash flows of a disposed component of the Company were eliminated from the ongoing operations of the Company as a result of the disposal and the Company no longer had any significant continuing involvement in the operation of that component.

Description of Business

The Company is engaged in the mining of thermal coal for sale primarily to electric utilities and metallurgical coal for sale to industrial customers. The Company’s mining operations are located in the United States (U.S.) and Australia, including an equity-affiliate mining operation in Australia. The Company also markets and brokers coal from other coal producers, both as principal and agent, and trades coal and freight-related contracts through trading and business offices in Australia, China, Germany, India, Indonesia, the United Kingdom and the U.S. (listed alphabetically). The Company’s other energy-related commercial activities include participating in operations of a mine-mouth coal-fueled generating plant, managing its coal reserve and real estate holdings, evaluating Btu Conversion projects and supporting the development of clean coal technologies.

Going Concern, Liquidity and Management's Plan

As of December 31, 2015, the Company’s available liquidity was $1.2 billion, which was substantially comprised of $940.0 million available for borrowing under a $1.65 billion revolving credit facility (the 2013 Revolver, as more fully described in Note 12. "Long-term Debt") and $261.3 million of cash and cash equivalents. During February 2016, the Company borrowed the maximum amount available under the 2013 Revolver for general corporate purposes. As of March 11, 2016, our available liquidity declined to $0.9 billion, which consisted primarily of cash and cash equivalents.



Peabody Energy Corporation	2015 Form 10-K	F- 8

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company incurred a substantial loss from operations and had negative cash flows from operating activities for the year ended December 31, 2015. The Company's current operating plan indicates that it will continue to incur losses from operations and generate negative cash flows from operating activities. These projections and certain liquidity risks raise substantial doubt about whether the Company will meet its obligations as they become due within one year after the date of this report. The Company also elected to exercise the 30-day grace period with respect to a $21.1 million semi-annual interest payment due March 15, 2016 on its 6.50% Senior Notes due September 2020 and a $50.0 million semi-annual interest payment due March 15, 2016 on its 10.00% Senior Secured Second Lien Notes due March 2022, as provided for in the indentures governing these notes. Failure to pay these interest amounts on March 15, 2016 is not immediately an event of default under the indentures governing the Notes, but would become an event of default if the payment is not made within 30 days of such date. As a result of these factors, as well as the continued uncertainty around global coal fundamentals, the stagnated economic growth of certain major coal-importing nations, and the potential for significant additional regulatory requirements imposed on coal producers, among other matters, there exists substantial doubt whether the Company will be able to continue as a going concern.

The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from uncertainty about our ability to continue as a going concern, other than the reclassification of certain long-term debt and the related debt issuance costs to current liabilities and current assets, respectively. The report from the Company's independent registered public accounting firm on its consolidated financial statements included herein includes an uncertainty paragraph that summarizes the salient facts or conditions that raise substantial doubt about the Company's ability to continue as a going concern.

The Company is currently exploring alternatives for other sources of capital for ongoing liquidity needs and transactions to enhance its ability to comply with the financial covenants under its 2013 Credit Facility. The Company is working to improve its operating performance and its cash, liquidity and financial position. This includes: pursuing the sale of non-strategic surplus land and coal reserves as well as existing mines, particularly the sale of the Company's El Segundo and Lee Ranch coal mines and related assets located in New Mexico and its Twentymile Mine in Colorado; continuing to drive cost improvements across the company, attempting to negotiate alternative payment terms with creditors; maintaining its current level of self-bonding and/or replacing self-bonding with other financial instruments on reasonable terms; evaluating potential debt buybacks, debt exchanges and new financing to improve its liquidity and reduce its financial obligations; and obtaining waivers of going concern and financial covenant violations under the 2013 Credit Facility. The Company has engaged financial and other advisors to assist in those efforts.

However, there can be no assurance that management’s plan to improve the Company’s operating performance and financial position will be successful or that the Company will be able to obtain additional financing on commercially reasonable terms or at all. As a result, the Company’s liquidity and ability to timely pay its obligations when due could be adversely affected. Furthermore, the Company’s creditors may resist renegotiation or lengthening of payment and other terms, or could seek shorter payment terms, through legal action or otherwise. If the Company is not able to timely, successfully or efficiently implement the strategies that it is pursuing to improve its operating performance and financial position, obtain alternative sources of capital or otherwise meet its liquidity needs, the Company may need to voluntarily seek protection under Chapter 11 of the U.S. Bankruptcy Code.

The 2013 Credit Facility and the indentures governing our 6.00%, 6.25%, 6.50% and 7.875% Senior Notes and our Senior Secured Second Lien Notes and the instruments governing our capital leases include cross-acceleration provisions, whereby the debt owing under such agreements would be accelerated upon certain events, include a failure by us to service the debt in accordance with the relevant agreement. The 2013 Credit Facility and its governing documents contain covenants that, among other things, require the Company to furnish audited financial statements as soon as available, but in any event within 90 days after the fiscal year end without a "going concern" uncertainty paragraph in the auditor's opinion. The consolidated financial statements for the year ended December 31, 2015 included herein contain such a paragraph. In addition, the Company currently anticipates that its reported Adjusted EBITDA and other sources of earnings or adjustments used to calculate Consolidated EBITDA (if such other sources of earnings or adjustments do not include the proceeds of certain targeted asset sales) will fall below its Consolidated Net Cash Interest Charges during 2016, and it anticipates it will not comply with its financial covenants as of March 31, 2016. Absent waivers or cures, non-compliance with such covenants would constitute a default under the 2013 Credit Facility. It is possible the Company could obtain waivers from its lenders; however, since there is substantial doubt about whether the Company will meet its obligations as they become due within one year after the date of issuance of this report, the Company has classified debt that could become accelerated as current in the consolidated financial statements as of December 31, 2015. To the extent that the lenders demand payment, the Company will then write-off any remaining original issue discounts and any unamortized debt issuance costs related to the debt, which totaled $75.9 million at December 31, 2015.



Peabody Energy Corporation	2015 Form 10-K	F- 9

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Newly Adopted Accounting Standards

Discontinued Operations. In April 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance that raised the threshold for disposals to qualify as discontinued operations to a disposal of a component or group of components that is disposed of or is classified as held for sale and represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results. Such a strategic shift may include the disposal of (1) a major geographical area of operations, (2) a major line of business, (3) a major equity method investment or (4) other major parts of an entity. Provided that the major strategic shift criterion is met, the new guidance does allow entities to have significant continuing involvement and continuing cash flows with the discontinued operation, unlike prior U.S. GAAP. The new standard also requires additional disclosures for discontinued operations and new disclosures for individually material disposal transactions that do not meet the definition of a discontinued operation. The new guidance became effective prospectively for disposals that occur in interim and annual periods beginning on or after December 31, 2014 (January 1, 2015 for the Company). The adoption of the guidance beginning January 1, 2015 had no material effect on the Company's results of operations, financial condition, cash flows or financial statement presentation at that time. The ultimate impact on the Company's financial statements will depend on any prospective disposal activity.

Accounting Standards Not Yet Implemented

Revenue Recognition. In May 2014, the FASB issued a comprehensive revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The new standard provides a single principles-based, five-step model to be applied to all contracts with customers, which steps are to (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract and (5) recognize revenue when each performance obligation is satisfied. More specifically, revenue will be recognized when promised goods or services are transferred to the customer in an amount that reflects the consideration expected in exchange for those goods or services. The standard also requires entities to disclose sufficient qualitative and quantitative information to enable financial statement users to understand the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers.

Under the originally issued standard, the new guidance will be effective for interim and annual periods beginning after December 15, 2016 (January 1, 2017 for the Company). On July 9, 2015, the FASB decided to delay the effective date of the new revenue recognition standard by one year with early adoption permitted, but not before the original effective date. The standard allows for either a full retrospective adoption or a modified retrospective adoption. The Company is in the process of evaluating the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.

Going Concern. In August 2014, the FASB issued disclosure guidance that requires management to evaluate, at each annual and interim reporting period, whether substantial doubt exists about an entity's ability to continue as a going concern and, if applicable, to provide related disclosures. As outlined by that guidance, substantial doubt about an entity's ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that an entity will be unable to meet its obligations as they become due within one year after the date that the financial statements are issued (or are available to be issued). The new guidance will be effective for annual reporting periods ending after December 15, 2016 (the year ending December 31, 2016 for the Company) and interim periods thereafter, with early adoption permitted.

Deferred Financing Costs. On April 7, 2015, the FASB issued accounting guidance that requires deferred financing costs to be presented as a direct reduction from the related debt liability in the financial statements rather than as a separately recognized asset, as is the current requirement under U.S. GAAP. Under the new guidance, amortization of such costs will continue to be reported as interest expense. In August 2015, an update was issued that clarified that debt issuance costs associated with line-of-credit arrangements may continue to be reported as an asset. The new guidance will be effective for interim and annual periods beginning after December 15, 2015 (January 1, 2016 for the Company) and must be adopted on a retrospective basis. While the Company does not anticipate an impact to its results of operations, financial condition or cash flows in connection with the adoption of the guidance, there will be an impact on the presentation of the Company's condensed consolidated balance sheets. More specifically, the Company's audited consolidated balance sheets as of December 31, 2015 and 2014 includes $74.4 million and $64.7 million, respectively, of deferred financing cost assets (excluding $20.4 million and $14.0 million, respectively, related to line-of-credit arrangements) that would, under the new guidance, be presented as a direct reduction to liabilities.



Peabody Energy Corporation	2015 Form 10-K	F- 10

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Inventory. In July 2015, the FASB issued guidance which requires entities to measure most inventory “at the lower of cost and net realizable value“, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market (market in this context is defined as one of three different measures, one of which is net realizable value). The guidance does not apply to inventories that are measured by using either the last-in, first-out method or the retail inventory method. The new guidance will be effective prospectively for annual periods beginning after December 15, 2016 (January 1, 2017 for the Company), and interim periods therein, with early adoption permitted.The Company is in the process of evaluating the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.

Business Combinations. In September 2015, in the interest of simplification, the FASB issued new guidance which requires that measurement period adjustments be recognized in the reporting period in which the adjustment amount is determined. Before the new guidance, an acquirer was required to adjust such provisional amounts by restating prior period financial statements as long as the information necessary to complete the measurement was received within the measurement period. The new standard should be applied prospectively to measurement period adjustments that occur after the effective date. The new standard is effective for interim and annual reporting periods ending after December 15, 2015 and interim periods beginning after December 15, 2017, with early adoption permitted. The impact to the Company's financial statements will depend on any acquisition activity that occurs subsequent to adoption in 2016.

Income Taxes. In November 2015, the FASB issued accounting guidance that requires entities to classify all deferred tax assets and liabilities, along with any related valuation allowance as noncurrent on the balance sheet. Under the new guidance, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. The new guidance does not change the existing requirement that only permits offsetting within a jurisdiction. The new guidance will be effective prospectively or retrospectively for annual periods beginning after December 15, 2016 and interim periods therein, with early adoption permitted. The Company is in the process of evaluating the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.

Lease accounting. In February 2016, FASB issued accounting guidance that will require a lessee to recognize in is balance sheet a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases with lease terms of more than 12 months. Consistent with current U.S. GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. Additional qualitative disclosures along with specific quantitative disclosures will also be required. The new guidance will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after Dec. 15, 2018 (January 1, 2019 for the Company), with early adoption permitted. Upon adoption, the Company will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company is in the process of evaluating the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.

Sales

The Company’s revenue from coal sales is realized and earned when risk of loss passes to the customer. Under the typical terms of the Company’s coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the transportation source(s) that serves each of the Company’s mines. The Company incurs certain “add-on” taxes and fees on coal sales. Reported coal sales include taxes and fees charged by various federal and state governmental bodies and the freight charged on destination customer contracts.

Other Revenues

"Other revenues" include net revenues from coal trading activities as discussed in Note 7. "Coal Trading," as well as coal sales revenues that were derived from the Company’s mining operations and sold through the Company’s coal trading business. Also included are revenues from customer contract-related payments, royalties related to coal lease agreements, sales agency commissions, farm income, property and facility rentals and generation development activities. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced.

Discontinued Operations and Assets Held for Sale

The Company classifies items within discontinued operations in the consolidated financial statements when the operations and cash flows of a particular component of the Company have been (or will be) eliminated from the ongoing operations of the Company as a result of a disposal (by sale or otherwise) and represents a strategic shift that has (or will have) a major effect on the entity's operations and financial results. Refer to Note 3. "Discontinued Operations" for additional details related to discontinued operations.



Peabody Energy Corporation	2015 Form 10-K	F- 11

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.

Inventories

Coal is reported as inventory at the point in time the coal is extracted from the mine. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Saleable coal represents coal stockpiles which require no further processing prior to shipment to a customer.

Coal inventory is valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment (including depreciation thereto) and operating overhead and other related costs incurred at or on behalf of the mining location. Market represents the estimated net realizable value of the inventory, which considers the projected future sales price of the particular coal product, less applicable selling costs, and, in the case of raw coal, estimated remaining processing costs. The valuation of coal inventory is subject to several additional estimates, including those related to ground and aerial surveys used to measure quantities and processing recovery rates.

Materials and supplies inventory is valued at the lower of average cost or market, less a reserve for obsolete or surplus items. This reserve incorporates several factors, such as anticipated usage, inventory turnover and inventory levels.

Investments in Marketable Securities

The Company’s short-term investments in marketable securities, which are included in "Other current assets" in the consolidated balance sheets, are defined as those investments with original maturities upon purchase of greater than three months and up to one year. Long-term investments, which are included in "Investments and other assets" in the consolidated balance sheets, are defined as those investments with original maturities upon purchase of greater than one year.

The Company classifies its investments in debt securities as either held-to-maturity or available-for-sale at the time of purchase and reevaluates such designation periodically. Such investments are classified as held-to-maturity when the Company has the intent and ability to hold the securities to maturity. Investments in debt securities not classified as held-to-maturity and investments in marketable equity securities are classified as available-for-sale. Available-for-sale securities are carried at fair value, with unrealized gains and losses, net of income taxes, generally reported in “Accumulated other comprehensive loss” in the consolidated balance sheets. Realized gains and losses, determined on a specific identification method, are included in “Interest income” in the consolidated statements of operations.

At each reporting date, the Company performs separate evaluations of its marketable securities to determine if any unrealized losses present are other-than-temporary. Such evaluations involve the consideration of several factors, including, but not limited to, the length of time the market value has been less than cost, the financial condition and near-term prospects of the issuer of the securities and whether the Company has the positive intent and ability to hold the securities until recovery. No such impairment losses were recorded during the year ended December 31, 2015. Refer to Note 2. "Asset Impairment" and Note 5. "Investments" for details regarding other-than-temporary impairment losses of $4.7 million and $21.5 million recognized during the years ended December 31, 2014 and 2013, respectively, related to the Company's marketable equity securities holdings.

Property, Plant, Equipment and Mine Development

Property, plant, equipment and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Capitalized interest in 2015, 2014 and 2013 was immaterial. Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs are charged to operating costs as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Costs incurred to maintain current production capacity at a mine are charged to operating costs as incurred. Costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.

Coal reserves are recorded at cost, or at fair value in the case of nonmonetary exchanges, of reserves or business acquisitions.



Peabody Energy Corporation	2015 Form 10-K	F- 12

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Depletion of coal reserves and amortization of advance royalties is computed using the units-of-production method utilizing only proven and probable reserves (as adjusted for recoverability factors) in the depletion base. Mine development costs are principally amortized over the estimated lives of the mines using the straight-line method. Depreciation of plant and equipment is computed using the straight-line method over the shorter of the asset's estimated useful life or the life of the mine. The estimated useful lives by category of assets are as follows:



			Years
Building and improvements			1 to 32
Machinery and equipment			1 to 32
Leasehold improvements			Shorter of Useful Life or Remaining Life of Lease

Equity and Cost Method Investments

The Company accounts for its investments in less than majority owned corporate joint ventures under either the equity or cost method. The Company applies the equity method to investments in joint ventures when it has the ability to exercise significant influence over the operating and financial policies of the joint venture. Investments accounted for under the equity method are initially recorded at cost and any difference between the cost of the Company’s investment and the underlying equity in the net assets of the joint venture at the investment date is amortized over the lives of the related assets that gave rise to the difference. The Company’s pro-rata share of the operating results of joint ventures and basis difference amortization is reported in the consolidated statements of operations in “Loss from equity affiliates.” Similarly, the Company's pro-rata share of the cumulative foreign currency translation adjustment of its equity method investments whose functional currency is not the U.S. dollar is reported in the consolidated balance sheet as a component of "Accumulated other comprehensive loss," with periodic changes thereto reflected in the consolidated statements of comprehensive income.

The Company monitors its equity and cost method investments for indicators that a decrease in investment value has occurred that is other than temporary. Examples of such indicators include a sustained history of operating losses and adverse changes in earnings and cash flow outlook. In the absence of quoted market prices for an investment, discounted cash flow projections are used to assess fair value, the underlying assumptions to which are generally considered unobservable Level 3 inputs under the fair value hierarchy. If the fair value of an investment is determined to be below its carrying value and that loss in fair value is deemed other than temporary, an impairment loss is recognized. Refer to Note 2. "Asset Impairment" and Note 5. "Investments" for details regarding other-than-temporary impairment losses of $276.5 million and $43.2 million recorded during the years ended December 31, 2015 and 2013, respectively, related to certain of the Company's equity and cost method investments. No such impairment losses were recorded during the year ended December 31, 2014.

Asset Retirement Obligations

The Company’s asset retirement obligation (ARO) liabilities primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws in the U.S. and Australia as defined by each mining permit.

The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at the credit-adjusted, risk-free rate. The Company records an ARO asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. The ARO asset is amortized on the units-of-production method over its expected life and the ARO liability is accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free rate. The Company also recognizes an obligation for contemporaneous reclamation liabilities incurred as a result of surface mining. Contemporaneous reclamation consists primarily of grading, topsoil replacement and re-vegetation of backfilled pit areas.

Contingent Liabilities

From time to time, the Company is subject to legal and environmental matters related to its continuing and discontinued operations and certain historical, non-coal producing operations. In connection with such matters, the Company is required to assess the likelihood of any adverse judgments or outcomes, as well as potential ranges of probable losses.



Peabody Energy Corporation	2015 Form 10-K	F- 13

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A determination of the amount of reserves required for these matters is made after considerable analysis of each individual issue. The Company accrues for legal and environmental matters within "Operating costs and expenses" when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. The Company provides disclosure surrounding loss contingencies when it believes that it is at least reasonably possible that a material loss may be incurred or an exposure to loss in excess of amounts already accrued may exist. Adjustments to contingent liabilities are made when additional information becomes available that affects the amount of estimated loss, which information may include changes in facts and circumstances, changes in interpretations of law in the relevant courts, the results of new or updated environmental remediation cost studies and the ongoing consideration of trends in environmental remediation costs.

Accrued contingent liabilities exclude claims against third parties and are not discounted. The current portion of these accruals is included in “Accounts payables and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in the consolidated balance sheets. In general, legal fees related to environmental remediation and litigation are charged to expense. The Company includes the interest component of any litigation-related penalties within "Interest expense" in the consolidated statements of operations.

Income Taxes

Income taxes are accounted for using a balance sheet approach. The Company accounts for deferred income taxes by applying statutory tax rates in effect at the reporting date of the balance sheet to differences between the book and tax basis of assets and liabilities. A valuation allowance is established if it is “more likely than not” that the related tax benefits will not be realized. Significant weight is given to evidence that can be objectively verified including history of tax attribute expiration and cumulative income or loss. In determining the appropriate valuation allowance, the Company considers the projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income in carryback years.

The Company recognizes the tax benefit from uncertain tax positions only if it is “more likely than not” the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. To the extent the Company’s assessment of such tax positions changes, the change in estimate will be recorded in the period in which the determination is made. Tax-related interest and penalties are classified as a component of income tax expense.

Postretirement Health Care and Life Insurance Benefits

The Company accounts for postretirement benefits other than pensions by accruing the costs of benefits to be provided over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the accumulated postretirement benefit obligations of its postretirement benefit plans. The Company accounts for changes in its postretirement benefit obligations as a settlement when an irrevocable action has been effected that relieves the Company of its actuarially-determined liability to individual plan participants and removes substantial risk surrounding the nature, amount and timing of the obligation’s funding and the assets used to effect the settlement. See Note 15. "Postretirement Health Care and Life Insurance Benefits" for information related to postretirement benefits.

Pension Plans

The Company sponsors non-contributory defined benefit pension plans accounted for by accruing the cost to provide the benefits over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the funded status of the defined benefit pension plans. See Note 16. "Pension and Savings Plans" for information related to pension plans.

Restructuring Activities

From time to time, the Company initiates restructuring activities in connection with its repositioning efforts to appropriately align its cost structure or optimize its coal production relative to prevailing global coal industry conditions. Costs associated with restructuring actions can include early mine closures, voluntary and involuntary workforce reductions, office closures and other related activities. Costs associated with restructuring activities are recognized in the period incurred.

Included as a component of "Restructuring and pension settlement charges" in the the Company's consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 were aggregate restructuring charges of $23.5 million, $15.7 million and $11.9 million, respectively, primarily associated with voluntary and involuntary workforce reductions. The majority of the cash expenditures associated with the charges recognized in 2015 were paid in 2015.



Peabody Energy Corporation	2015 Form 10-K	F- 14

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Derivatives

The Company recognizes at fair value all contracts meeting the definition of a derivative as assets or liabilities in the consolidated balance sheets, with the exception of certain coal trading contracts for which the Company has elected to apply a normal purchases and normal sales exception.

With respect to derivatives used in hedging activities, the Company assesses, both at inception and at least quarterly thereafter, whether such derivatives are highly effective at offsetting the changes in the anticipated exposure of the hedged item. The effective portion of the change in the fair value of derivatives designated as a cash flow hedge is recorded in “Accumulated other comprehensive loss” until the hedged transaction impacts reported earnings, at which time any gain or loss is reclassified to earnings. To the extent that periodic changes in the fair value of derivatives deemed highly effective exceeds such changes in the hedged item, the ineffective portion of the periodic non-cash changes are recorded in earnings in the period of the change. If the hedge ceases to qualify for hedge accounting, the Company prospectively recognizes changes in the fair value of the instrument in earnings in the period of the change. The potential for hedge ineffectiveness is present in the design of certain of the Company’s cash flow hedge relationships and is discussed in detail in Note 6. "Derivatives and Fair Value Measurements" and Note 7. "Coal Trading." Gains or losses from derivative financial instruments designated as fair value hedges are recognized immediately in earnings, along with the offsetting gain or loss related to the underlying hedged item.

The Company’s asset and liability derivative positions are offset on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract.

Non-derivative contracts and derivative contracts for which the Company has elected to apply the normal purchases and normal sales exception are accounted for on an accrual basis.

Business Combinations

The Company accounts for business combinations using the purchase method of accounting. The purchase method requires the Company to determine the fair value of all acquired assets, including identifiable intangible assets and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.

Impairment of Long-Lived Assets

The Company evaluates its long-lived assets held and used in operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends and a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition. The Company generally does not view short-term declines in thermal and metallurgical coal prices in the markets in which it sells those products as a triggering event for conducting impairment tests because such markets have a history of price volatility. However, the Company generally does view a sustained trend of depressed coal market pricing (for example, over periods exceeding one year) as an indicator of potential impairment.

Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. For its active mining operations, the Company generally groups such assets at the mine level, or the mining complex level for mines that share infrastructure, with the exception of impairment evaluations triggered by mine closures. In those cases involving mine closures, the related assets are evaluated at the individual asset level for remaining economic life based on transferability to ongoing operating sites and for use in reclamation-related activities, or for expected salvage. For its development and exploration properties and portfolio of surface land and coal reserve holdings, the Company considers several factors to determine whether to evaluate those assets individually or on a grouped basis for purposes of impairment testing. Such factors include geographic proximity to one another, the expectation of shared infrastructure upon development based on future mining plans and whether it would be most advantageous to bundle such assets in the event of sale to a third party.



Peabody Energy Corporation	2015 Form 10-K	F- 15

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

When indicators of impairment are present, the Company evaluates its long-lived assets for recoverability by comparing the estimated undiscounted cash flows expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. As quoted market prices are unavailable for the Company's individual mining operations, fair value is determined through the use of an expected present value technique based on the income approach, except for non-strategic coal reserves, surface lands and undeveloped coal properties excluded from the Company's long-range mine planning. In those cases, a market approach is utilized based on the most comparable market multiples available. The estimated future cash flows and underlying assumptions used to assess recoverability and, if necessary, measure the fair value of the Company's long-lived mining assets are derived from those developed in connection with the Company's planning and budgeting process. The Company believes its assumptions to be consistent with those a market participant would use for valuation purposes. The most critical assumptions underlying the Company's projections and fair value estimates include those surrounding future tons sold, coal prices for unpriced coal, production costs (including costs for labor, commodity supplies and contractors), transportation costs, foreign currency exchange rates and a risk-adjusted, after-tax cost of capital (all of which generally constitute unobservable Level 3 inputs under the fair value hierarchy), in addition to market multiples for non-strategic coal reserves, surface lands and undeveloped coal properties excluded from the Company's long-range mine planning (which generally constitute Level 2 inputs under the fair value hierarchy).

Refer to Note 2. "Asset Impairment" for details regarding impairment charges related to long-lived assets of $1,001.3 million, $149.7 million and $463.6 million recognized during the years ended December 31, 2015, 2014 and 2013, respectively.

Fair Value

For assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Foreign Currency

Functional currency is determined by the primary economic environment in which an entity operates, which for the Company's foreign operations is generally the U.S. dollar because sales prices in international coal markets and the Company's sources of financing those operations is denominated in that currency. Accordingly, substantially all of the Company’s consolidated foreign subsidiaries utilize the U.S. dollar as their functional currency. Monetary assets and liabilities are remeasured at year-end exchange rates while non-monetary items are remeasured at historical rates. Income and expense accounts are remeasured at the average rates in effect during the year, except for those expenses related to balance sheet amounts that are remeasured at historical exchange rates. Gains and losses from foreign currency remeasurement related to tax balances are included as a component of "Income tax (benefit) provision," while all other remeasurement gains and losses are included in "Operating costs and expenses." The total impact of foreign currency remeasurement on the consolidated statements of operations was a net loss of $6.4 million and $1.3 million for the years ended December 31, 2015 and 2014, respectively, and a net gain of $34.1 million for the year ended December 31, 2013.

The Company owns a 50% equity interest Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine in Queensland, Australia. Middlemount utilizes the Australian dollar as its functional currency. Accordingly, the assets and liabilities of that equity investee are translated to U.S. dollars at the year-end exchange rate and income and expense accounts are translated at the average rate in effect during the year. The Company's pro-rata share of the translation gains and losses of the equity investee are recorded as a component of "Accumulated other comprehensive loss." Australian dollar denominated shareholder loans to the Middlemount Mine, which are long term in nature, are considered part of the Company's net investment in that operation. Accordingly, foreign currency gains or losses on those loans are recorded as a component of foreign currency translation adjustment. The Company recorded foreign currency translation losses of $34.9 million, $41.0 million and $92.7 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Share-Based Compensation

The Company accounts for share-based compensation at the grant date fair value of awards and recognizes the related expense over the service period of the awards. See Note 18. "Share-Based Compensation" for information related to share-based compensation.

Exploration and Drilling Costs

Exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.



Peabody Energy Corporation	2015 Form 10-K	F- 16

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Advance Stripping Costs

Pre-production. At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, expand the workforce, build or improve existing haul roads and create the initial pre-production box cut to remove overburden (that is, advance stripping costs) for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal (that is, advance stripping costs incurred for the initial box cuts) for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices.

Post-production. Advance stripping costs related to post-production are expensed as incurred. Where new pits are routinely developed as part of a contiguous mining sequence, the Company expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.

Use of Estimates in the Preparation of the Consolidated Financial Statements

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.


(2)	Asset Impairment

Year Ended December 31, 2015

The following costs are reflected in "Asset impairment" in the consolidated statement of operations for the year ended December 31, 2015:



	Reportable Segment
	Australian Metallurgical Mining		Australian Thermal Mining		Midwestern U.S. Mining		Corporate and Other		Consolidated
	(Dollars in millions)
Asset impairment charges:
Long-lived assets	$	675.2	$	17.5	$	40.2	$	268.4	$	1,001.3
Equity method investment	—		—		—		276.5		276.5
Total	$	675.2	$	17.5	$	40.2	$	544.9	$	1,277.8

Australian Metallurgical and Thermal Mining

The Company generally does not view short-term declines in metallurgical and thermal coal prices in the markets in which it sells its products as an indicator of impairment. However, due to the severity of the decline in seaborne metallurgical and thermal coal pricing observed during 2015 and other adverse market conditions noted during the year that drove an unfavorable change in the expected timing of eventual seaborne market rebalancing, the Company concluded that indicators of impairment existed surrounding its Australian mining platform as of June 30, 2015 and December 31, 2015. Accordingly, the Company reviewed its Australian mining assets for recoverability at those dates and determined that the carrying values of three of its active mines that produce metallurgical coal were not recoverable and recognized impairment charges of $230.5 million and $144.5 million during the three-month periods ended June 30, 2015 and December 31, 2015, respectively, to write those assets down to their estimated fair value.

Also during 2015, the Company reviewed its portfolio of mining tenements and surface lands to identify non-strategic assets that could be monetized. In connection with that review, certain of such assets were deemed to meet held-for-sale accounting criteria or were otherwise deemed more likely to generate cash flows through divestiture rather than development, with the long-term plans for certain adjacent assets also consequently affected. Accordingly, the Company recognized an aggregate impairment charge of $317.7 million to write down the targeted divestiture assets and abandoned assets to their estimated fair value.



Peabody Energy Corporation	2015 Form 10-K	F- 17

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Midwestern U.S. Mining

The Company identified indicators of impairment to be present for one of its inactive surface mines due to the property no longer being part of the Company's long-term mining plan as a result of the decline in thermal coal prices and a lack of observed interest from potential buyers in acquiring the asset. Accordingly, the Company recognized an impairment charge of $30.5 million to write down the asset to its estimated fair value.

The Company generally does not view short-term declines in thermal coal prices in the markets in which it sells its products as an indicator of impairment. However, due to the severity of the decline in thermal coal pricing observed during 2015 and other adverse market conditions noted during 2015, the Company identified indicators of impairment to be present for one of its Midwestern U.S. Mining assets. Due to the adverse conditions, the Company's long-term mining plan changed and the asset was no longer part of the long-term mining plan. Accordingly, the Company recognized an impairment charge of $9.7 million to write down the asset to its estimated fair value.

Corporate and Other

Long-lived Assets. In connection with a similar review of the Company's asset portfolio conducted during 2015 to identify non-strategic domestic assets that could be monetized, the Company identified non-strategic, non-coal-supplying assets as held-for-sale rather than held-for-use as of December 31, 2015. Accordingly, the Company recognized an impairment charge of $182.2 million to write the assets down to estimated fair value.

The Company also identified indicators of impairment to be present for several of its non-strategic undeveloped coal properties due to properties that are no longer part of the Company's long-term mining plan as a result of the decline in thermal coal prices and a lack of observed interest from potential buyers in acquiring those assets. Accordingly, the Company recognized an aggregate impairment charge of $86.2 million to write down the assets to their estimated fair value.

Equity Method Investment. Due to the impairment indicators noted above surrounding the Company's Australian platform, the Company similarly reviewed its total investment in Middlemount, which owns the Middlemount Mine in Queensland, Australia, as of December 31, 2015. As a result of that review, the Company determined that the carrying value of its equity investment in Middlemount was other-than-temporarily impaired and recorded a charge of $46.6 million to write-off the investment.

The Company, along with the other equity interest holder, also periodically makes loans to Middlemount pursuant to the related shareholders’ agreement for purposes of funding capital expenditures and working capital requirements. The Company reviewed the loans for impairment and recorded a charge of $229.9 million to write down the full carrying value of the Subordinated Loans. The Subordinated Loans are provided on an equal and shared basis with the other equity interest holder, and the Company's and the other equity interest holder's claims under the Subordinated Loans are on equal footing. The Company also has Priority Loans of $65.2 million which have seniority over the fully impaired Subordinated Loans. The Priority Loans were not impaired as of December 31, 2015 as the Company had the intent and ability to hold the loans to payoff and Middlemount had sufficient assets to settle.

The fair value estimates made during the Company's impairment assessments were determined in accordance with the methods outlined in Note 1. "Summary of Significant Accounting Policies", except in certain instances where indicative bids were received related to non-strategic assets being marketed for divestiture. In those instances, the indicative bids were also considered in estimating fair value.

Risks and Uncertainties

The Company's mining and exploration assets and mining-related investments may be adversely affected by numerous uncertain factors that may cause the Company to be unable to recover all or a portion of the carrying value of those assets. The Company generally does not view short-term declines in thermal and metallurgical coal prices in the markets in which it sells its products as an indicator of impairment. However, the Company generally views a sustained trend (for example, over periods exceeding one year) of adverse coal market pricing or unfavorable changes thereto as a potential indicator of impairment. Because of the volatile and cyclical nature of U.S. and international seaborne coal markets, it is reasonably possible that prices in those market segments may decrease and/or fail to improve in the near term, which, absent sufficient mitigation such as an offsetting reduction in the Company's operating costs, may result in the need for future adjustments to the carrying value of the Company's long-lived mining assets and mining-related investments.



Peabody Energy Corporation	2015 Form 10-K	F- 18

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company's assets whose recoverability and values are most sensitive to near-term pricing include certain Australian metallurgical and thermal assets for which impairment charges were recorded in 2015 and certain U.S. coal properties being leased to unrelated mining companies under agreements that require royalties to be paid as the coal is mined. Such assets had an aggregate carrying value of $186.1 million as of December 31, 2015. The Company conducted a review of those assets for recoverability as of December 31, 2015 and determined that, other than the charges described above, no further impairment charge was necessary as of that date.

Year Ended December 31, 2014

The following costs are reflected in "Asset impairment" in the consolidated statement of operations for the year ended December 31, 2014:



	Reportable Segment
	Australian Metallurgical Mining		Australian Thermal Mining		Western U.S. Mining		Corporate and Other		Consolidated
	(Dollars in millions)
Asset impairment charges:
Long-lived assets	$	66.7	$	11.9	$	2.7	$	68.4	$	149.7
Marketable securities	—		—		—		4.7		4.7
Total	$	66.7	$	11.9	$	2.7	$	73.1	$	154.4

Australian Metallurgical and Thermal Mining

In 2014, the Company observed continued weakness in seaborne metallurgical and thermal coal pricing that has persisted longer than the Company previously anticipated and, accordingly, conducted a review of its Australian Metallurgical Mining and Australian Thermal Mining segment assets for recoverability. Based on that evaluation, the following Australian segments were impacted as follows:

Australian Metallurgical Mining. The Company determined that the carrying value of one of its active surface mines and a non-strategic undeveloped coal property were not recoverable and correspondingly recognized an aggregate impairment charge of $66.7 million to write those assets down from their carrying value to their estimated fair value. In addition to the impairment indicators surrounding the segment, the fair value of the impaired surface mining operation was affected by a short remaining economic life compared to those of other operations and the incremental cost associated with utilizing a contractor to operate the mine.

Australian Thermal Mining. The Company determined that the carrying values of a non-strategic undeveloped coal property was not recoverable and correspondingly recognized an aggregate impairment charge of $11.9 million to write those assets down from its carrying value to their estimated fair value.

Corporate and Other. The Company also identified indicators of impairment to be present in 2014 for certain assets in its Corporate and Other segment. Those assets were certain non-strategic undeveloped coal properties in Indiana and Colorado that were found to be impaired due to a lack of observed interest from potential buyers in acquiring those assets, properties that are no longer part of the Company's long-term mining plan and, in the case of certain of the assets, an election by the Company to terminate or allow the lapse of mining-related leases. The Company determined the carrying value of those holdings to not be recoverable and recognized an aggregate impairment charge of $68.4 million to write down the carrying value of the related properties.

Marketable Securities

Refer to Note 5. "Investments" for additional details surrounding an other-than-temporary impairment charge of $4.7 million recorded during the fourth quarter of 2014 related to the Company's investment in the marketable equity securities of Winsway Enterprises Holdings Limited (Winsway), formally referred to as Winsway Coking Coal Holdings Limited.



Peabody Energy Corporation	2015 Form 10-K	F- 19

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Year Ended December 31, 2013

The following costs are reflected in "Asset impairment" in the consolidated statement of operations for the year ended December 31, 2013:



	Reportable Segment
	Australian Metallurgical Mining		Corporate and Other		Consolidated
	(Dollars in millions)
Asset impairment charges:
Long-lived assets	$	390.8	$	72.8	$	463.6
Equity method investment	—		43.2		$	43.2
Marketable securities	—		21.5		$	21.5
Total	$	390.8	$	137.5	$	528.3

Australian Metallurgical Mining

In 2013, the Company determined that the long-lived assets of one of its active surface mines, one of its surface mining development projects that the Company instead decided to pursue as an underground operation and an exploration tenement were not recoverable, in whole or in part, and correspondingly recognized an aggregate impairment charge of $390.8 million to write each of those assets down from its carrying value to its estimated fair value. In addition to weakness in seaborne metallurgical and thermal coal pricing, the fair value of the impaired surface mining operation was affected by a short remaining economic life compared to those of other operations and site-specific adverse changes in 2013 surrounding realized coal quality yields, contractor performance and contract mining terms, the latter of which were amended during the fourth quarter of that period. With respect to the exploration tenement, the Company determined the fair value of that asset based on an indicative sale offer received in December 2013, which constituted a Level 2 input under the fair value hierarchy. That sale was executed in January 2014, as described further in Note 20. "Resource Management and Other Commercial Events."

Corporate and Other

Long-lived Assets. In December 2013, contract mining at a coal reserve property in the Eastern U.S. substantially ended upon completion of mining within the existing permit area and new permits were not obtained for the remaining reserves at that property due to new permitting conditions that the Company deemed unacceptable and projected poor near-term economic performance. As a result of that decision and a lack of observed interest from certain financial and strategic buyers in acquiring the remaining coal reserves, the Company recorded an impairment charge of $66.3 million to write down the carrying value of the related reserves. Also, in connection with a review of its portfolio of surface land and coal reserve holdings, the Company determined the carrying value of one of its coal reserve holdings leased to a third-party underground miner to not be fully recoverable and recognized an impairment charge of $6.5 million to write down the carrying value of those reserves to their estimated fair value.

Equity Method Investment. Refer to Note 5. "Investments" for additional details surrounding an other-than-temporary impairment charge of $43.2 million recognized in 2013 associated with the Company's 50% equity interest in Middlemount.

Marketable Securities. Refer to Note 5. "Investments" for additional details surrounding an other-than-temporary impairment charge of $21.5 million recorded during the second quarter of 2013 related to the Company's investment in Winsway marketable equity securities.

(3) Discontinued Operations

Discontinued operations include former Australian Thermal Mining and Midwestern U.S. Mining segment assets that have ceased production and other previously divested legacy operations, including Patriot Coal Corporation and certain of its wholly-owned subsidiaries (Patriot).



Peabody Energy Corporation	2015 Form 10-K	F- 20

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Summarized Results of Discontinued Operations

Results from discontinued operations were as follows during the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Loss from discontinued operations before income taxes	$	(182.2	)	$	(23.8	)	$	(329.7	)
Income tax (provision) benefit	7.2			(4.4		)	103.1
Loss from discontinued operations, net of income taxes	$	(175.0	)	$	(28.2	)	$	(226.6	)

There were no significant revenues from discontinued operations during the years ended December 31, 2015 and 2014. Total revenues associated with discontinued operations amounted to $136.5 million during the year ended December 31, 2013.

Assets and Liabilities of Discontinued Operations

Assets and liabilities classified as discontinued operations included in the Company's consolidated balance sheets were as follows:



	December 31,
	2015		2014
	(Dollars in millions)
Assets:
Other current assets	$	3.1	$	0.3
Investments and other assets	13.2		16.3
Total assets classified as discontinued operations	$	16.3	$	16.6

Liabilities:
Accounts payable and accrued expenses	$	60.0	$	12.5
Other noncurrent liabilities	203.7		109.8
Total liabilities classified as discontinued operations	$	263.7	$	122.3

Patriot-Related Matters. Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" for information surrounding charges recorded during the year ended December 31, 2015 associated with the bankruptcy of Patriot.

Wilkie Creek Mine. In December 2013, the Company ceased production and started reclamation of the Wilkie Creek Mine in Queensland, Australia. On June 30, 2014, Queensland Bulk Handling Pty Ltd (QBH) commenced litigation against Peabody (Wilkie Creek) Pty Limited, the indirect wholly-owned subsidiary of the Company that owns the Wilkie Creek Mine, alleging breach of a Coal Port Services Agreement (CPSA) between the parties. Included in "(Loss) income from discontinued operations, net of income taxes" for the year ended December 31, 2015 is a $9.7 million charge related to that litigation. Refer to Note 24. "Commitments and Contingencies" for additional information surrounding the QBH matter.

In June 2015, the Company entered into an agreement to sell the Wilkie Creek Mine in exchange for potential cash proceeds of up to $20 million and the assumption of certain liabilities. That agreement was subsequently terminated in October 2015 in conjunction with entering into a new agreement with similar terms. The closing of the sale remains subject to certain material conditions, including without limitation the purchaser’s ability to obtain financing for the transaction and negotiation of satisfactory port access arrangements.



Peabody Energy Corporation	2015 Form 10-K	F- 21

Table of Contents


(4)	Inventories

Inventories as of December 31, 2015 and December 31, 2014 consisted of the following:



	December 31,
	2015		2014
	(Dollars in millions)
Materials and supplies	$	115.9	$	143.6
Raw coal	75.9		115.0
Saleable coal	116.0		147.9
Total	$	307.8	$	406.5

Materials and supplies inventories presented above have been shown net of reserves of $4.7 million and $4.6 million as of December 31, 2015 and 2014, respectively.


(5)	Investments

Investments in Marketable Securities

Investments in available-for-sale securities were liquidated prior to December 31, 2015. Investments in available-for-sale securities at December 31, 2014 were as follows:



Available-for-sale securities	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
			(Dollars in millions)
Current:
U.S. corporate bonds	11.2		—		—		11.2
Noncurrent:
Marketable equity securities	6.2		—		—		6.2
Federal government securities	32.0		—		—		32.0
U.S. corporate bonds	12.4		—		—		12.4
Total	$	61.8	$	—	$	—	$	61.8

The Company classifies its investments as short-term if, at the time of purchase, remaining maturities are greater than three months and up to one year. Such investments are included in "Other current assets" in the consolidated balance sheets. Investments with remaining maturities of greater than one year are classified as long-term and are included in "Investments and other assets" in the consolidated balance sheets. The Company’s previous investments in marketable equity securities consisted of an investment in Winsway Enterprises Holdings Limited. That investment was disposed of during the year ended December 31, 2015, resulting in a less than $0.1 million gain compared to the adjusted cost basis of the securities.

Proceeds from sales and maturities of available-for-sale debt securities amounted to $90.3 million, $13.5 million and $22.9 million for the years ended December 31, 2015, 2014 and 2013, respectively. The Company realized zero net gains associated with those sales and maturities during the years ended December 31, 2015 and 2014 and $0.2 million during the year ended December 31, 2013.

At each reporting date, the Company performs separate evaluations of debt and equity securities to determine if any unrealized losses are other-than-temporary. Given the duration and severity of the market losses incurred and in certain historical periods in connection with Winsway's credit downgrades, the Company recognized other-than-temporary impairment losses of $4.7 million, and $21.5 million during the fourth quarter of 2014 and second quarter of 2013, respectively, each time resetting the cost basis of the Company's investment.

In November 2012, the Company purchased $4.8 million of time deposits denominated in Chinese Renminbi with six month maturities. Proceeds from the maturity of those investments amounted to $4.8 million in the year ended December 31, 2013. The Company had no held-to-maturity securities at December 31, 2015 and 2014.



Peabody Energy Corporation	2015 Form 10-K	F- 22

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Equity Method Investments

The Company’s equity method investments include its joint venture interest in Middlemount, which was acquired in connection with the 2011 acquisition of PEA-PCI (formerly Macarthur Coal Limited), in addition to certain other equity method investments. The table below summarizes the book value of those investments, which is reported in “Investments and other assets” in the consolidated balance sheets, and the related loss from equity affiliates:



	Book Value at December 31,				Loss from Equity Affiliates for the Year Ended December 31,
	2015		2014		2015		2014		2013
	(Dollars in millions)
Equity interest in Middlemount Coal Pty Ltd	$	—	$	58.0	$	7.0	$	98.5	$	33.5
Other equity method investments	4.7		7.3		8.9		9.1		6.7
Total equity method investments	$	4.7	$	65.3	$	15.9	$	107.6	$	40.2

During the years ended December 31, 2015, 2014 and 2013, Middlemount generated revenues of approximately $160 million, $165 million and $157 million (on a 50% basis). During the year ended December 31, 2015, due to sustained weakness in seaborne metallurgical coal prices that had persisted longer than the Company had previously anticipated, a history of operating losses at the mine and the magnitude of the difference between the estimated fair value and the carrying value of its equity investment, the Company determined the carrying value of its equity investment in Middlemount to be other-than-temporarily impaired. Correspondingly, the Company recorded an impairment charge of $46.6 million to write down the carrying value of its equity investment. The Company determined its Subordinated Loans to Middlemount were also fully impaired resulting in an additional impairment charge of $229.9 million. A total impairment charge related to Middlemount of $276.5 million was reflected in "Asset impairment" in the consolidated statement of operations for year ended December 31, 2015. Refer to Note 2. "Asset Impairment" for additional background surrounding the impairment charge recognized in 2015. At December 31, 2015, the Company had priority loans related to Middlemount with a carrying value of $65.2 million reflected in "Investments and other assets". Refer to Note 8. "Financing Receivables" for additional background on the Company's loans with Middlemount as of December 31, 2015.

In 2014, the Company recorded to "Loss from equity affiliates" its pro-rata share of a valuation allowance of $52.3 million on Middlemount's Australian net deferred tax assets. Based on a Middlemount's history of operating losses driven by sustained weakness in seaborne metallurgical coal prices, and considering available sources of taxable income, it was determined in 2014 that the net deferred tax assets are no longer considered more likely than not of being realized.

There is no remaining unamortized basis difference as of December 31, 2015 between the amount at which the Company's equity investment in Middlemount is carried and the amount of underlying equity in net assets of Middlemount. Middlemount had current assets, noncurrent assets, current liabilities and noncurrent liabilities of $31.7 million, $348.0 million, $362.2 million and $10.5 million, respectively, as of December 31, 2015 and $27.8 million, $424.4 million, $382.9 million and $11.3 million, respectively, as of December 31, 2014 (on a 50% basis).

In addition to its equity method investment, the Company periodically makes loans to Middlemount pursuant to the related shareholders' agreement. Refer to Note 8. "Financing Receivables" for additional details surrounding those loans.


(6)	Derivatives and Fair Value Measurements

Risk Management — Non Coal Trading Activities

The Company is exposed to several risks in the normal course of business, including (1) foreign currency exchange rate risk for non-U.S. dollar expenditures and balances, (2) price risk on commodities produced by and utilized in the Company's mining operations and (3) interest rate risk that has been partially mitigated by fixed rates on long-term debt. The Company manages a portion of its commodity price risk related to the sale of coal (excluding coal trading activities) using long-term coal supply agreements (those with terms longer than one year), rather than using derivative instruments. Derivative financial instruments are, or have been, used to manage the Company's risk exposure to prices of certain commodities used in production, foreign currency exchange rates and, from time to time, interest rates (collectively referred to as "Corporate Hedging"). These risks are actively monitored for compliance with the Company's risk management policies.



Peabody Energy Corporation	2015 Form 10-K	F- 23

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Foreign Currency Hedges. The Company is exposed to foreign currency exchange rate risk, primarily on Australian dollar expenditures made in its Australian Mining platform. This risk has historically been managed using forward contracts and options designated as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted foreign currency expenditures. The Company intends to allow a substantial portion of its positions to settle without adding further positions of a comparable notional amount.

Diesel Fuel Hedges. The Company is exposed to commodity price risk associated with diesel fuel utilized in production in the U.S. and Australia. This risk is managed through the use of derivatives, such as swaps or options, and to a lesser extent through the use of cost pass-through contracts. The Company generally designates the swap contracts as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted diesel fuel purchases.

Notional Amounts and Fair Value. The following summarizes the Company’s foreign currency and commodity positions at December 31, 2015:



	Notional Amount by Year of Maturity
	Total		2016		2017
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	1,530.0	$	1,007.0	$	523.0
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	148.8		89.5		59.3



	Instrument Classification by
	Cash Flow Hedge		Fair Value Hedge		Economic Hedge		Fair Value of Net Liability
							(Dollars in millions)
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	1,530.0	$	—	$	—	$	(200.7	)
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	148.8		—		—		(123.7		)

Based on the net fair value of the Company’s non-coal trading commodity contract hedge positions held in “Accumulated other comprehensive loss” at December 31, 2015, the Company expects to reclassify net unrealized losses associated with the Company’s diesel fuel hedge programs of approximately $86 million from comprehensive income into earnings over the next 12 months. Based on net unrealized losses associated with the Company's foreign currency hedge contract portfolio, partially offset by unrecognized realized gains related to foreign currency cash flow hedge contracts monetized in the fourth quarter of 2012 held in "Accumulated other comprehensive loss" at December 31, 2015, the net loss expected to be reclassified from comprehensive income to earnings over the next 12 months associated with that hedge program is approximately $146 million. The actual amounts that will impact earnings will exclude the reserve within accumulated other comprehensive income associated with credit and non-performance risk. As these realized and unrealized gains and losses are associated with derivative instruments that represent hedges of forecasted transactions, the amounts reclassified to earnings are expected to partially offset the effect of any changes in the hedged exposure related to the underlying transaction, when realized.

Hedge Ineffectiveness. A measure of ineffectiveness is inherent in hedging future diesel fuel purchases with derivative positions based on refined petroleum products as a result of location and/or product differences. Transportation surcharges, which may vary over time, for purchased diesel fuel in certain regions can also result in ineffectiveness, though such surcharges have historically changed infrequently and comprise a small portion of the total cost of delivered diesel.

The Company’s derivative positions for the hedging of forecasted foreign currency expenditures contain a small measure of ineffectiveness due to timing differences between the hedge settlement and the purchase transaction, which could differ by less than a day and up to a maximum of 30 days.



Peabody Energy Corporation	2015 Form 10-K	F- 24

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The tables below show the classification and amounts of pre-tax gains and losses related to the Company’s non-coal trading hedges during the years ended December 31, 2015, 2014 and 2013:



		Year Ended December 31, 2015
	Income Statement Classification Losses - Realized	Loss recognized in other comprehensive income on derivative (effective portion)			Loss reclassified from other comprehensive income into income (effective portion) ⁽¹⁾			Gain reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument	Income Statement Classification Losses - Realized
		(Dollars in millions)
Commodity swap contracts	Operating costs and expenses	$	(77.0	)	$	(122.0	)	$	1.6
Foreign currency forward contracts	Operating costs and expenses	(122.0		)	(316.4		)	—
Total		$	(199.0	)	$	(438.4	)	$	1.6


⁽¹⁾	Includes the reclassification from "Accumulated other comprehensive loss" into earnings of $14.9 million of previously unrecognized gains on foreign currency cash flow hedge contracts monetized in the fourth quarter of 2012.



		Year Ended December 31, 2014
	Income Statement Classification Losses - Realized	Loss recognized in other comprehensive income on derivative (effective portion)			Loss reclassified from other comprehensive income into income (effective portion)⁽¹⁾			Loss reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument	Income Statement Classification Losses - Realized
		(Dollars in millions)
Commodity swap contracts	Operating costs and expenses	$	(194.5	)	$	(20.6	)	$	(1.7	)
Foreign currency forward contracts	Operating costs and expenses	(100.9		)	(27.3		)	—
Total		$	(295.4	)	$	(47.9	)	$	(1.7	)


⁽¹⁾	Includes the reclassification from "Accumulated other comprehensive loss" into earnings of $136.9 million of previously unrecognized gains on foreign currency cash flow hedge contracts monetized in the fourth quarter of 2012.



		Year Ended December 31, 2013
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in other comprehensive income on derivative (effective portion)			Gain reclassified from other comprehensive income into income (effective portion)		Loss reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument	Income Statement Classification Gains (Losses) - Realized
		(Dollars in millions)
Commodity swap contracts	Operating costs and expenses	$	12.5		$	11.9	$	(0.5	)
Foreign currency forward contracts	Operating costs and expenses	(597.8		)	162.4		—
Total		$	(585.3	)	$	174.3	$	(0.5	)



Peabody Energy Corporation	2015 Form 10-K	F- 25

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash Flow Presentation. The Company classifies the cash effects of its non-coal trading derivatives within the "Cash Flows From Operating Activities" section of the consolidated statements of cash flows during the period of settlement for those instruments. In November 2012, with the Australian dollar trading at elevated levels against the U.S. dollar, the Company terminated certain of its Australian dollar forward contracts in exchange for aggregate realized cash proceeds of $151.8 million. Prior to discontinuation, those contracts comprised an aggregate notional amount of $1.9 billion originally contracted for settlement during 2014 and 2015 and were designated as cash flow hedges of Australian dollar expenditures forecasted to occur at those times. Upon termination, the Company executed at-market Australian dollar forward contracts with notional amounts and forward settlement dates identical to the terminated contracts and designated those replacement contracts as cash flow hedges of the anticipated future Australian dollar expenditures previously hedged by the terminated contracts. Because those forecasted expenditures remained probable of occurring upon termination, the Company continued to reflect the effective portion of the realized gains on the terminated forward contracts in "Accumulated other comprehensive loss." During the year ended December 31, 2014, the Company reclassified $136.9 million of those gains from "Accumulated other comprehensive loss" into earnings, with the remaining $14.9 million reclassified during the year ended December 31, 2015.

Offsetting and Balance Sheet Presentation

The Company's non-coal trading derivative financial instruments are transacted in over-the-counter (OTC) markets with financial institutions under International Swaps and Derivatives Association (ISDA) Master Agreements. Those agreements contain symmetrical default provisions which allow for the net settlement of amounts owed by either counterparty in the event of default or contract termination. The Company offsets its non-coal trading asset and liability derivative positions on a counterparty-by-counterparty basis in the condensed consolidated balance sheets, with the fair values of those respective derivatives reflected in “Other current assets,” “Investments and other assets,” “Accounts payable and accrued expenses” and “Other noncurrent liabilities." Though the symmetrical default provisions associated with the Company's non-coal trading derivatives exist at the overall counterparty level across its foreign currency and diesel fuel hedging strategy derivative contract portfolios, it is the Company's accounting policy to apply counterparty offsetting separately within those derivative contract portfolios for presentation in the condensed consolidated balance sheets because that application is more consistent with the fact that the Company generally net settles its non-coal trading derivatives with each counterparty by derivative contract portfolio on a routine basis.

The classification and amount of non-coal trading derivative financial instruments presented on a gross and net basis as of December 31, 2015 and 2014 are presented in the table that follows.



	Fair Value of Liabilities Presented in the Consolidated Balance Sheet as of December 31, 2015 ⁽¹⁾		Fair Value of Liabilities Presented in the Consolidated Balance Sheet as of December 31, 2014 ⁽¹⁾
Financial Instrument

Current Liabilities:
Commodity swap contracts	$	86.1	$	100.1
Foreign currency forward contracts	145.6		241.0
Total	$	231.7	$	341.1

Noncurrent Liabilities:
Commodity swap contracts	$	37.6	$	67.0
Foreign currency forward contracts	55.1		169.0
Total	$	92.7	$	236.0


⁽¹⁾	All commodity swap contracts and foreign currency forward contracts were in a liability position as of December 31, 2015 and 2014.

The Company's Corporate Hedging derivative financial instruments are generally considered Swap Obligations, as that term is defined in the Company's secured credit agreement dated September 24, 2013 (as amended, the 2013 Credit Facility). Accordingly, such instruments, when in a liability position, are first lien obligations secured by collateral and all of the property that is subject to liens under the 2013 Credit Facility. Refer to Note 12. "Long-term Debt" for additional information surrounding that collateral.

See Note 7. "Coal Trading" for information on balance sheet offsetting related to the Company’s coal trading activities.



Peabody Energy Corporation	2015 Form 10-K	F- 26

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fair Value Measurements

The Company uses a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1 - inputs are quoted prices in active markets for the identical assets or liabilities; Level 2 - inputs are other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3 - inputs are unobservable, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.

Financial Instruments Measured on a Recurring Basis. The following tables set forth the hierarchy of the Company’s net financial (liability) asset positions for which fair value is measured on a recurring basis:



	December 31, 2015
	Level 1		Level 2		Level 3			Total
			(Dollars in millions)
Investments in debt and equity securities	$	—	$	—	$	—		$	—
Commodity swap contracts	—		—		(123.7		)	(123.7		)
Foreign currency forward contracts	—		—		(200.7		)	(200.7		)
Total net financial liabilities	$	—	$	—	$	(324.4	)	$	(324.4	)



	December 31, 2014
	Level 1		Level 2			Level 3		Total
			(Dollars in millions)
Investments in debt and equity securities	$	26.1	$	35.7		$	—	$	61.8
Commodity swap contracts	—		(167.1		)	—		(167.1		)
Foreign currency forward contracts	—		(410.0		)	—		(410.0		)
Total net financial assets (liabilities)	$	26.1	$	(541.4	)	$	—	$	(515.3	)

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including interest rate yield curves, exchange indices, broker/dealer quotes, published indices, issuer spreads, benchmark securities and other market quotes. In the case of certain debt securities, fair value is provided by a third-party pricing service. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:


•	Investments in debt and equity securities: U.S. government securities and marketable equity securities are valued based on quoted prices in active markets (Level 1) and investment-grade corporate bonds and U.S. government agency securities are valued based on the various inputs listed above that may preclude the security from being measured using an identical asset in an active market (Level 2).


•	Commodity swap contracts — diesel fuel and explosives: valued based on a valuation that is corroborated by the use of market-based pricing (Level 2) except when credit and non-performance risk is considered to be a significant input, then the Company classifies such contracts as level 3.


•	Foreign currency forward and option contracts: valued utilizing inputs obtained in quoted public markets (Level 2) except when credit and non-performance risk is considered to be a significant input (greater than 10% of fair value), then the Company classifies such contracts as level 3.

Foreign currency and commodity purchase/sale contracts include a credit valuation adjustment based on credit and non-performance risk (Level 3). The credit valuation adjustment has not historically had a material impact on the valuation of the contracts resulting in Level 2 classification. However, due to the Company's corporate credit rating downgrades in 2015, the credit valuation adjustments as of December 31, 2015 are considered to be significant unobservable inputs in the valuation of the contracts resulting in Level 3 classification.

The following table summarizes the quantitative unobservable input utilized in the Company's internally-developed valuation models for foreign currency and commodity purchase/sale contracts classified as Level 3 as of December 31, 2015:



	Range				Weighted
Input	Low		High		Average
Credit and non-performance risk	26	%	36	%	30	%



Peabody Energy Corporation	2015 Form 10-K	F- 27

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Significant increases or decreases in the credit and non-performance risk adjustment could result in a significantly higher or lower fair value measurement.

The following table summarizes the changes related to the Company’s Corporate Hedging derivative financial instruments recurring Level 3 financial liabilities:



		Year Ended
		December 31, 2015
		Commodity Contracts			Foreign Currency Contracts			Total
	(Dollars in millions)
Beginning of period		$	—		$	—		$	—
Transfers into Level 3		76.0			259.8			335.8
Total net losses realized/unrealized:
Included in earnings		(0.2		)	—			(0.2		)
Included in other comprehensive income		112.8			103.0			215.8
Settlements		(64.9		)	(162.1		)	(227.0		)
End of period		$	123.7		$	200.7		$	324.4

The Company had no transfers between Levels 1 and 2 or transfers out of Level 3 during the year ended December 31, 2015 and 2014 or transfers into Level 3 for the year ended December 31, 2014. Transfers into Level 3 of liabilities previously classified in Level 2 during the year ended December 31, 2015 were due to the relative value of unobservable inputs to the total fair value measurement of certain derivative contracts rising above the 10% threshold. The Company’s policy is to value all transfers between levels using the beginning of period valuation.

The following table summarizes the changes in net unrealized losses relating to Level 3 financial liabilities held both as of the beginning and the end of the period:



		Year Ended
		December 31, 2015
		Commodity Contracts		Foreign Currency Contracts		Total
	(Dollars in millions)
Changes in net unrealized losses ⁽¹⁾		$	56.7	$	31.7	$	88.4


⁽¹⁾	Within the consolidated statements of operations and condensed consolidated statements of comprehensive income for the periods presented, unrealized losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.

Other Financial Instruments. The following methods and assumptions were used by the Company in estimating fair values for other financial instruments as of December 31, 2015 and 2014:


•	Cash and cash equivalents, accounts receivable, including those within the Company’s accounts receivable securitization program, notes receivable and accounts payable have carrying values which approximate fair value due to the short maturity or the liquid nature of these instruments.


•	Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available (Level 2), and otherwise on estimated borrowing rates to discount the cash flows to their present value (Level 3).

The carrying amounts and estimated fair values of the Company’s long-term debt are summarized as follows:



	December 31, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			(Dollars in millions)
Long-term debt	$	6,315.6	$	1,372.7	$	5,986.8	$	5,227.9



Peabody Energy Corporation	2015 Form 10-K	F- 28

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Credit and Nonperformance Risk

The fair value of the Company’s non-coal trading derivative assets and liabilities reflects adjustments for credit risk. The Company manages its counterparty risk through established credit standards, diversification of counterparties, utilization of investment grade commercial banks, adherence to established tenor limits based on counterparty creditworthiness and continual monitoring of that creditworthiness. To reduce its credit exposure for these hedging activities, the Company seeks to enter into netting agreements with counterparties that permit the Company to offset asset and liability positions with such counterparties in the event of default. The Company also continually monitors counterparties for nonperformance risk, if present, on a case-by-case basis.

The Company performed an assessment of its own nonperformance risk in light of the three rating agencies downgrading the Company's corporate credit rating during 2015 and declining financial results. The Company determined its hedging relationships were expected to be "highly effective" throughout 2015 based on its quarterly assessments. However, as a result of a deterioration in the Company's credit profile, the Company could no longer assert, as of December 31, 2015, that its hedging relationships were expected to be "highly effective" at offseting the changes in the anticipated exposure of the hedged item. Therefore, previous fair value adjustments recorded in Accumulated Other Comprehensive Loss will be frozen until the underlying transaction impacts the Company's earnings and subsequent fair value adjustments will be recorded directly to income.


(7)	Coal Trading

The Company engages in the direct and brokered trading of coal and freight-related contracts (coal trading). Except those for which the Company has elected to apply a normal purchases and normal sales exception, all derivative coal trading contracts are accounted for at fair value.

The Company includes instruments associated with coal trading transactions as a part of its trading book. Trading revenues from such transactions are recorded in “Other revenues” in the consolidated statements of operations and include realized and unrealized gains and losses on derivative instruments, including those that arise from coal deliveries related to contracts accounted for on an accrual basis under the normal purchases and normal sales exception. Therefore, the Company has elected the trading exemption surrounding disclosure of its coal trading activities.

Trading revenues recognized during the years ended December 31, 2015, 2014 and 2013 were as follows:



	Year Ended December 31,
Trading Revenues by Type of Instrument	2015			2014			2013
	(Dollars in millions)
Commodity futures, swaps and options	$	107.3		$	92.3		$	183.9
Physical commodity purchase/sale contracts	(64.5		)	(33.9		)	(117.9		)
Total trading revenues	$	42.8		$	58.4		$	66.0

Risk Management

Hedge Ineffectiveness. In some instances, the Company has designated an existing coal trading derivative as a hedge and, thus, the derivative has a non-zero fair value at hedge inception. The “off-market” nature of these derivatives, which is best described as an embedded financing element within the derivative, is a source of ineffectiveness. In other instances, the Company uses a coal trading derivative that settles at a different time, has different quality specifications or has a different location basis than the occurrence of the cash flow being hedged. These collectively yield ineffectiveness to the extent that the derivative hedge contract does not exactly offset changes in the fair value or expected cash flows of the hedged item.

The Company had no coal trading positions designated as cash flow hedges of forecasted sales as of December 31, 2015, while the gross fair value of coal trading positions designated as cash flow hedges of forecasted sales was an asset of $44.3 million as of December 31, 2014.



Peabody Energy Corporation	2015 Form 10-K	F- 29

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Offsetting and Balance Sheet Presentation

The Company's coal trading assets and liabilities include financial instruments, such as swaps, futures and options, cleared through various commodities exchanges, which involve the daily net settlement of closed positions. The Company must post cash collateral, known as variation margin, on exchange-cleared positions that are in a net liability position and receives variation margin when in a net asset position. The Company also transacts in coal trading financial swaps and options through OTC markets with financial institutions and other non-financial trading entities under ISDA Master Agreements, which contain symmetrical default provisions. Certain of the Company's coal trading agreements with OTC counterparties also contain credit support provisions that may periodically require the Company to post, or entitle the Company to receive, initial and variation margin. Physical coal and freight-related purchase and sale contracts included in the Company's coal trading assets and liabilities are executed pursuant to master purchase and sale agreements that also contain symmetrical default provisions and allow for the netting and setoff of receivables and payables that arise during the same time period. The Company offsets its coal trading asset and liability derivative positions, and variation margin related to those positions, on a counterparty-by-counterparty basis in the consolidated balance sheets, with the fair values of those respective derivatives reflected in “Assets from coal trading activities, net” and “Liabilities from coal trading activities, net."

The fair value of assets and liabilities from coal trading activities presented on a gross and net basis as of December 31, 2015 and 2014 is set forth below:



Affected line item in the consolidated balance sheets	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Balance Sheets			Variation margin (held) posted ⁽¹⁾			Net Amounts of Assets (Liabilities) Presented in the Consolidated Balance Sheets
	(Dollars in millions)
	Fair Value as of December 31, 2015
Assets from coal trading activities, net	$	128.6		$	(87.3	)	$	(17.8	)	$	23.5
Liabilities from coal trading activities, net	(110.0		)	87.3			7.1			(15.6		)
Total, net	$	18.6		$	—		$	(10.7	)	$	7.9

	Fair Value as of December 31, 2014
Assets from coal trading activities, net	$	342.5		$	(248.3	)	$	(36.6	)	$	57.6
Liabilities from coal trading activities, net	(285.0		)	248.3			4.0			(32.7		)
Total, net	$	57.5		$	—		$	(32.6	)	$	24.9


⁽¹⁾	$0.8 million and none of the net variation margin held at December 31, 2015 and 2014, respectively, related to cash flow hedges.

See Note 6. "Derivatives and Fair Value Measurements" for information on balance sheet offsetting related to the Company’s Corporate Hedging activities.

Fair Value Measurements

The following tables set forth the hierarchy of the Company’s net financial asset (liability) coal trading positions for which fair value is measured on a recurring basis as of December 31, 2015 and 2014:



	December 31, 2015
	Level 1		Level 2		Level 3			Total
	(Dollars in millions)
Commodity futures, swaps and options	$	—	$	3.3	$	—		$	3.3
Physical commodity purchase/sale contracts	—		20.2		(15.6		)	4.6
Total net financial (liabilities) assets	$	—	$	23.5	$	(15.6	)	$	7.9



Peabody Energy Corporation	2015 Form 10-K	F- 30

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	December 31, 2014
	Level 1			Level 2			Level 3		Total
				(Dollars in millions)
Commodity futures, swaps and options	$	(0.2	)	$	32.6		$	—	$	32.4
Physical commodity purchase/sale contracts	—			(9.6		)	2.1		(7.5		)
Total net financial (liabilities) assets	$	(0.2	)	$	23.0		$	2.1	$	24.9

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including U.S. interest rate curves; LIBOR yield curves; Chicago Mercantile Exchange (CME) Group, Intercontinental Exchange (ICE), LCH.Clearnet (formerly known as the London Clearing House), NOS Clearing ASA and Singapore Exchange (SGX) contract prices; broker quotes; published indices and other market quotes. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:


•	Commodity futures, swaps and options: generally valued based on unadjusted quoted prices in active markets (Level 1) or a valuation that is corroborated by the use of market-based pricing (Level 2).


•	Physical commodity purchase/sale contracts: purchases and sales at locations with significant market activity corroborated by market-based information (Level 2) except when credit and non-performance risk is considered to be a significant input (greater than 10% of fair value), then the company classifies as Level 3.

Physical commodity purchase/sale contracts include a credit valuation adjustment based on credit and non-performance risk (Level 3). The credit valuation adjustment has not historically had a material impact on the valuation of the contracts resulting in Level 2 classification. However, due to the Company's corporate credit rating downgrades in 2015, the credit valuation adjustments as of December 31, 2015 are considered to be significant unobservable inputs in the valuation of the contracts resulting in Level 3 classification.

The Company had transfers into Level 3 of liabilities previously classified in Level 2 during the year ended December 31, 2015 due to the relative value of unobservable inputs to the total fair value measurement of certain derivative contracts rising above the 10% threshold. The Company had no transfers between Levels 1 and 2 or transfers out of Level 3 during the year ended December 31, 2015 or 2014 or transfers into Level 3 for the year ended December 31, 2014.

The Company's risk management function, which is independent of the Company's commercial trading function, is responsible for valuation policies and procedures, with oversight from executive management. Generally, the Company's Level 3 instruments or contracts are valued using bid/ask price quotations and other market assessments obtained from multiple, independent third-party brokers or other transactional data incorporated into internally-generated discounted cash flow models. While the Company does not anticipate any decrease in the number of third-party brokers or market liquidity, the occurrence of such events could erode the quality of market information and therefore the valuation of its market positions. The Company's valuation techniques include basis adjustments to the foregoing price inputs for quality, such as heat rate and sulfur and ash content, location differentials, expressed as port and freight costs, and credit risk. The Company's risk management function independently validates the Company's valuation inputs, including unobservable inputs, with third-party information and settlement prices from other sources where available. A daily process is performed to analyze market price changes and changes to the portfolio. Further periodic validation occurs at the time contracts are settled with the counterparty. These valuation techniques have been consistently applied in all periods presented, and the Company believes it has obtained the most accurate information available for the types of derivative contracts held.

The following table summarizes the quantitative unobservable inputs utilized in the Company's internally-developed valuation models for physical commodity purchase/sale contracts classified as Level 3 as of December 31, 2015:



	Range				Weighted
Input	Low		High		Average
Quality adjustments	1	%	13	%	4	%
Location differentials	11	%	11	%	11	%
Credit and non-performance risk	26	%	26	%	26	%

Significant increases or decreases in the inputs in isolation could result in a significantly higher or lower fair value measurement. The unobservable inputs do not have a direct interrelationship; therefore, a change in one unobservable input would not necessarily correspond with a change in another unobservable input.



Peabody Energy Corporation	2015 Form 10-K	F- 31

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the changes in the Company’s recurring Level 3 net financial assets:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Beginning of period	$	2.1		$	2.1		$	5.2
Transfers into Level 3	(4.4		)	—			—
Total gains realized/unrealized:
Included in earnings	(10.1		)	6.7			0.3
Purchases	(0.5		)	—			—
Sales	(0.1		)	—			—
Settlements	(2.6		)	(6.7		)	(3.4		)
End of period	$	(15.6	)	$	2.1		$	2.1

The Company had no transfers between Levels 1 and 2 or transfers out of Level 3 during the year ended December 31, 2015, 2014 or 2013 or transfers into Level 3 for the years ended December 31, 2014 and 2013. Transfers into Level 3 of liabilities previously classified in Level 2 during the year ended December 31, 2015 were due to the relative value of unobservable inputs to the total fair value measurement of certain derivative contracts rising above the 10% threshold. The Company’s policy is to value all transfers between levels using the beginning of period valuation.

The following table summarizes the changes in net unrealized (losses) gains relating to Level 3 net financial assets held both as of the beginning and the end of the period:



	Year Ended December 31,
	2015			2014		2013
	(Dollars in millions)
Changes in unrealized (losses) gains ⁽¹⁾	$	(6.2	)	$	2.1	$	(0.4	)


⁽¹⁾	Within the consolidated statements of operations and consolidated statements of comprehensive income for the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.

As of December 31, 2015, the Company's trading portfolio was expected to have positive net cash realizations in 2015 and 2016, reaching substantial maturity in 2016 on a fair value basis.

As of December 31, 2015, the timing of the estimated future realization of the value of the Company’s trading portfolio, on a cumulative cash basis, was as follows:



	Percentage of
Year of Expiration	Portfolio Total

2016	109	%
2017	(11	)%
2018	2	%
	100	%



Peabody Energy Corporation	2015 Form 10-K	F- 32

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Credit and Nonperformance Risk. The fair value of the Company’s coal derivative assets and liabilities reflects adjustments for credit risk. The Company’s exposure is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses. The Company’s policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If the Company engages in a transaction with a counterparty that does not meet its credit standards, the Company seeks to protect its position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by its credit management function), the Company has taken steps to reduce its exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for the Company’s benefit to serve as collateral in the event of a failure to pay or perform. To reduce its credit exposure related to trading and brokerage activities, the Company seeks to enter into netting agreements with counterparties that permit the Company to offset asset and liability positions with such counterparties and, to the extent required, the Company will post or receive margin amounts associated with exchange-cleared and certain OTC positions. The Company also continually monitors counterparty and contract nonperformance risk, if present, on a case-by-case basis.

As of December 31, 2015, 70% of the Company’s credit exposure related to coal trading activities with investment grade counterparties, while 14% was with non-investment grade counterparties and 16% was with counterparties that are not rated.

Performance Assurances and Collateral

Certain of the Company’s derivative trading instruments require the parties to provide additional performance assurances whenever a material adverse event jeopardizes one party’s ability to perform under the instrument. If the Company was to sustain a material adverse event (using commercially reasonable standards), its counterparties could request collateralization on derivative trading instruments in net liability positions which, based on an aggregate fair value at December 31, 2015 and 2014, would have amounted to collateral postings to counterparties of approximately $21 million and $31 million, respectively. As of December 31, 2015 and 2014, no collateral was posted to counterparties for such positions.

Certain of the Company’s other derivative trading instruments require the parties to provide additional performance assurances whenever a credit downgrade occurs below a certain level, as specified in each underlying contract. The terms of such derivative trading instruments typically require additional collateralization, which is commensurate with the severity of the credit downgrade. During 2015, each of the three agencies downgraded the Company's corporate credit rating. The credit downgrades were, in part, due to continued weakness in seaborne coal prices. The Company was not required to post additional collateral as a direct result of those downgrades for its derivative trading instruments. Even if a credit downgrade were to have occurred below contractually specified levels, the Company’s additional collateral requirement owed to its counterparties for these derivative trading instruments would have been zero at December 31, 2015 and 2014 based on the aggregate fair value of all derivative trading instruments with such features. As of December 31, 2015 and 2014, no collateral was posted to counterparties to support such derivative trading instruments.

The Company is required to post variation margin on positions that are in a net liability position and is entitled to receive and hold variation margin on positions that are in a net asset position with an exchange and certain of its OTC derivative contract counterparties. At December 31, 2015 and 2014, the Company held net variation margin of $10.7 million and $32.6 million, respectively.

In addition to the requirements surrounding variation margin, the Company is required by the exchanges upon which it transacts and by certain of its OTC arrangements to post certain additional collateral, known as initial margin, which represents an estimate of potential future adverse price movements across the Company’s portfolio under normal market conditions. As of December 31, 2015 and 2014, the Company had posted initial margin of $9.2 million and $15.2 million, respectively, which is reflected in “Other current assets” in the consolidated balance sheets. The Company had posted $0.7 million of margin in excess of the required variation and initial margin as of December 31, 2015, while it had posted $6.1 million of excess margin as of December 31, 2014.



Peabody Energy Corporation	2015 Form 10-K	F- 33

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(8)	Financing Receivables

The Company's total financing receivables as of December 31, 2015 and 2014 consisted of the following:



Balance Sheet Classification	December 31, 2015		December 31, 2014
	(Dollars in millions)
Other current assets	$	20.0	$	—
Investments and other assets	65.2		347.2
Total financing receivables	$	85.2	$	347.2

The Company periodically assesses the collectability of accounts and loans receivable by considering factors such as specific evaluation of collectability, historical collection experience, the age of the receivable and other available evidence. Below is a description of the Company's financing receivables outstanding as of December 31, 2015.

Codrilla Mine Project. In 2011, a wholly-owned subsidiary of PEA-PCI, then Macarthur Coal Limited, completed the sale of a portion of its 85% interest in the Codrilla Mine Project to the other participants of the Coppabella Moorvale Joint Venture, afterward retaining 73.3% ownership. The final outstanding installment payment of 40% of the sale price is due upon the earlier of the mine's first coal shipment or a specified date. The sales agreement was amended in the second quarter of 2013 to delay the specified date from March 31, 2015 to June 30, 2016, resulting in an adjustment to the discounted value of the note receivable in the amount of $1.6 million. This adjustment was recorded as a reduction to "Interest income" in the consolidated statements of operations for the year ended December 31, 2013. There are currently no indications of impairment on the remaining installment and the Company expects to receive full payment by June 30, 2016. The remaining balance associated with these receivables totaled $20.0 million and $27.6 million at December 31, 2015 and 2014, respectively, and was recorded in "Other current assets" and "Investments and other assets" in the consolidated balance sheets, respectively.

Middlemount Mine. The Company periodically makes loans to Middlemount, in which the Company owns a 50% equity interest, pursuant to the related shareholders' agreement for purposes of funding capital expenditures and working capital requirements. Middlemount is required to pay down the loans as excess cash is generated pursuant to its shareholders’ agreement. The Priority Loans bear interest at a rate equal to the monthly average 30-day Australian Bank Bill Swap Reference Rate plus 3.5% and expire on December 31, 2016. Based on the expected timing of repayment of these loans, which is projected to extend beyond the stated expiration date, the Company considers these loans to be of a long-term nature. As a result, (1) the foreign currency impact related to the shareholder loans is included in foreign currency translation adjustment in the consolidated balance sheets and the consolidated statements of comprehensive income and (2) interest income on the Priority Loans is recognized when cash is received. Refer to Note 2. "Asset Impairment" for background surrounding the impairment charge recognized in 2015 related to Middlemount. The carrying value of the loans of $65.2 million and $319.6 million was reflected in "Investments and other assets" in the consolidated balance sheets as of December 31, 2015 and 2014, respectively.



Peabody Energy Corporation	2015 Form 10-K	F- 34

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(9)	Property, Plant, Equipment and Mine Development

Property, plant, equipment and mine development, net, as of December 31, 2015 and December 31, 2014 consisted of the following:



	December 31,
	2015			2014
	(Dollars in millions)
Land and coal interests	$	10,503.7		$	11,021.1
Buildings and improvements	1,506.0			1,569.1
Machinery and equipment	2,280.4			2,685.7
Less: Accumulated depreciation, depletion and amortization	(5,031.6		)	(4,698.6		)
Total, net	$	9,258.5		$	10,577.3

The net book value of coal reserves totaled $5.7 billion as of December 31, 2015 and $6.2 billion as of December 31, 2014, which excludes the carrying value of acquired interests in mineral rights at certain Australian exploration properties of $1.2 billion and $1.3 billion, respectively. The coal reserves include mineral rights for leased coal interests and advance royalties that had a net book value of $4.6 billion as of December 31, 2015 and $5.0 billion as of December 31, 2014. The remaining net book value of coal reserves of $1.1 billion at December 31, 2015 and $1.2 billion at December 31, 2014 relates to coal reserves held by fee ownership. Amounts attributable to coal reserves at properties where the Company was not currently engaged in mining operations or leasing to third parties and, therefore, the coal reserves were not currently being depleted, was $1.7 billion as of December 31, 2015 and $2.1 billion as of December 31, 2014.


(10)	Income Taxes

Loss from continuing operations before income taxes for the years ended December 31, 2015, 2014 and 2013 consisted of the following:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
U.S.	$	(515.9	)	$	268.9		$	220.6
Non-U.S.	(1,474.4		)	(816.8		)	(954.9		)
Total	$	(1,990.3	)	$	(547.9	)	$	(734.3	)

Total income tax (benefit) provision for the years ended December 31, 2015, 2014 and 2013 consisted of the following:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Current:
U.S. federal	$	(71.9	)	$	27.1		$	(47.9	)
Non-U.S.	3.7			(61.1		)	38.4
State	(0.6		)	3.3			(4.7		)
Total current	(68.8		)	(30.7		)	(14.2		)
Deferred:
U.S. federal	(117.4		)	111.0			4.8
Non-U.S.	15.7			122.3			(440.3		)
State	(5.9		)	(1.4		)	1.4
Total deferred	(107.6		)	231.9			(434.1		)
Total income tax (benefit) provision	$	(176.4	)	$	201.2		$	(448.3	)



Peabody Energy Corporation	2015 Form 10-K	F- 35

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following is a reconciliation of the expected statutory federal income tax benefit to the Company’s income tax (benefit) provision for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Expected income tax benefit at U.S. federal statutory rate	$	(696.6	)	$	(191.7	)	$	(257.0	)
Changes in valuation allowance, income tax	462.0			569.4			(29.4		)
Changes in tax reserves	(21.4		)	(81.5		)	8.8
Excess depletion	(53.7		)	(65.3		)	(72.7		)
Foreign earnings repatriation	—			(71.4		)	—
Foreign earnings provision differential	146.5			28.8			62.7
General business tax credits	(15.7		)	(19.2		)	(18.9		)
Minerals resource rent tax, net of federal tax	—			16.1			(87.4		)
Remeasurement of foreign income tax accounts	(0.5		)	(2.7		)	(44.3		)
State income taxes, net of federal tax benefit	(20.1		)	(2.3		)	(0.2		)
Other, net	23.1			21.0			(9.9		)
Total income tax (benefit) provision	$	(176.4	)	$	201.2		$	(448.3	)

Certain reconciliation items included in the above table exclude the remeasurement of foreign income tax accounts as these foreign currency effects are separately presented.



Peabody Energy Corporation	2015 Form 10-K	F- 36

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities as of December 31, 2015 and 2014 consisted of the following:



	December 31,
	2015			2014
	(Dollars in millions)
Deferred tax assets:
Tax credits and loss carryforwards	$	1,817.4		$	1,723.5
Accrued postretirement benefit obligations	372.4			372.3
Asset retirement obligations	160.9			167.0
Employee benefits	69.6			70.7
Payable to voluntary employee beneficiary association for certain Patriot retirees ⁽¹⁾	52.9			79.2
Hedge activities	26.6			44.2
Environmental contingencies	—			29.9
Deferred revenue	—			29.1
Financial guarantees	16.9			16.9
Workers’ compensation obligations	13.7			6.2
Other	66.7			50.5
Total gross deferred tax assets	2,597.1			2,589.5
Deferred tax liabilities:
Property, plant, equipment and mine development, principally due to differences in depreciation, depletion and asset impairments	966.6			1,223.4
Unamortized discount on Convertible Junior Subordinated Debentures	130.3			131.0
Investments and other assets	70.1			73.4
Other	—			1.1
Total gross deferred tax liabilities	1,167.0			1,428.9
Valuation allowance, income tax	(1,447.3		)	(1,169.0		)
Net deferred tax liability	$	(17.2	)	$	(8.4	)
Deferred taxes are classified as follows:
Current deferred income taxes	$	49.7		$	80.0
Noncurrent deferred income taxes	(66.9		)	(88.4		)
Net deferred tax liability	$	(17.2	)	$	(8.4	)


⁽¹⁾	Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" herein for additional details related to this transaction.

The Company's tax credits and tax effected loss carryforwards included U.S. alternative minimum tax (AMT) credits of $272.5 million, foreign tax credits of $247.0 million, tax general business credits of $105.4 million, U.S. capital losses of $65.9 million, federal net operating loss (NOL) carryforwards of $9.9 million, state NOL carryforwards of $41.3 million, charitable contribution carryforwards of $0.9 million and foreign NOL carryforwards of $1,074.5 million as of December 31, 2015. The AMT credits and foreign NOLs have no expiration date. The federal NOLs expire in 2036. The U.S. capital losses and state NOLs begin to expire in 2017 and 2018, respectively. The foreign tax credits and general business credits begin to expire in 2020 and 2027, respectively.

In assessing the near-term use of NOLs and tax credits and corresponding valuation allowance adjustments, the Company evaluated the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income in carryback years. During the year ended December 31, 2015, the Company continued to record valuation allowance against net deferred tax asset positions in the U.S. and Australia of $177.0 million and $101.3 million, respectively. Recognition of those valuation allowances was driven by recent cumulative book losses, as determined by considering all sources of available income (including items classified as discontinued operations or recorded directly to "Accumulated other comprehensive loss"), which limited the Company’s ability to look to future taxable income in assessing the realizability of the related assets. Of the $177.0 million increase in U.S. valuation allowance during the year ended December 31, 2015, $182.7 million and $(5.7) million were reflected in "Income tax (benefit) provision" and "Accumulated other comprehensive loss," respectively.



Peabody Energy Corporation	2015 Form 10-K	F- 37

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unrecognized Tax Benefits

Net unrecognized tax benefits (excluding interest and penalties) were recorded as follows in the consolidated balance sheets as of December 31, 2015 and 2014:



	December 31,
	2015		2014
	(Dollars in millions)
Accounts payable and accrued expenses	$	—	$	—
Deferred income taxes	7.9		6.2
Other noncurrent liabilities	11.7		34.7
Net unrecognized tax benefits	$	19.6	$	40.9
Gross unrecognized tax benefits	$	22.9	$	44.5

The amount of the Company's gross unrecognized tax benefits decreased by $21.6 million since January 1, 2015 due to the finalization of IRS audits on the 2009 through 2013 tax years, offset by additions for current positions. The amount of the net unrecognized tax benefits that, if recognized, would directly affect the effective tax rate was $19.6 million and $40.9 million at December 31, 2015 and 2014, respectively. A reconciliation of the beginning and ending amount of gross unrecognized tax benefits for the years ended December 31, 2015, 2014 and 2013 is as follows:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Balance at beginning of period	$	44.5		$	143.9		$	122.8
Additions for current year tax positions	2.3			12.0			6.3
(Reductions) additions for prior year tax positions	(23.5		)	—			63.8
Reductions for settlements with tax authorities	(0.4		)	(111.4		)	—
Reductions for expirations of statutes of limitations	—			—			(49.0		)
Balance at end of period	$	22.9		$	44.5		$	143.9

The Company recognizes interest and penalties related to unrecognized tax benefits in its income tax provision. The Company reversed gross interest and penalties of $2.1 million, $8.0 million and $36.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. The Company had $0.4 million and $3.4 million of accrued gross interest and penalties related to unrecognized tax benefits at December 31, 2015 and 2014, respectively.

The Company expects that during the next twelve months there will be no changes to its net unrecognized tax benefits due to potential audit settlements and the expiration of statutes of limitations.

Tax Returns Subject to Examination

The IRS completed its audit of 2009 through 2013 income tax years. The Company's state income tax returns for the tax years 1999 and thereafter remain potentially subject to examination by various state taxing authorities due to NOL carryforwards. The ATO completed its audit of the Company's Australian income tax returns for the tax years 2004 through 2009 as well as its review of the tax years 2010 through 2012. Australian income tax returns for tax years 2010 through 2013 continue to be subject to potential examinations by the ATO.

Foreign Earnings

The Company had immaterial undistributed earnings of foreign subsidiaries as of December 31, 2015. Historically, the Company has not provided for deferred taxes on undistributed earnings because such earnings are considered to be indefinitely reinvested outside of the U.S.



Peabody Energy Corporation	2015 Form 10-K	F- 38

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Tax Payments and Refunds

The following table summarizes the Company’s income tax (refunds) payments, net for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
U.S. — federal	$	(38.1	)	$	(7.7	)	$	(0.8	)
U.S. — state and local	0.4			(6.8		)	2.9
Non-U.S.	11.9			(2.2		)	79.8
Total income tax (refunds) payments, net	$	(25.8	)	$	(16.7	)	$	81.9


(11)	Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consisted of the following:



	December 31,
	2015			2014
	(Dollars in millions)
Trade accounts payable	$	333.3		$	461.7
Commodity and foreign currency hedge contracts	231.7			341.1
Other accrued expenses	225.8			298.8
Accrued payroll and related benefits	191.9			268.7
Accrued taxes other than income	135.9			175.3
Payable to voluntary employee beneficiary association for certain Patriot retirees ⁽¹⁾	75.0			75.0
Accrued interest	68.8			48.4
Accrued royalties	41.0			61.5
Asset retirement obligations	25.5			30.2
Accrued environmental cleanup-related costs	23.9			19.4
Accrued health care insurance	15.8			2.4
Workers’ compensation obligations	8.6			10.9
Income taxes payable	6.8			3.3
Other	2.3		—	—
Liabilities associated with discontinued operations	60.0			12.5
Total accounts payable and accrued expenses	$	1,446.3		$	1,809.2


⁽¹⁾	Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" herein for additional details related to this transaction.



Peabody Energy Corporation	2015 Form 10-K	F- 39

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(12)	Long-term Debt

The Company’s total indebtedness as of December 31, 2015 and 2014 consisted of the following:



	December 31,
	2015			2014
	(Dollars in millions)
2013 Term Loan Facility due September 2020	$	1,164.9		$	1,175.1
7.375% Senior Notes due November 2016	—			650.0
6.00% Senior Notes due November 2018	1,518.8			1,518.8
6.50% Senior Notes due September 2020	650.0			650.0
6.25% Senior Notes due November 2021	1,339.6			1,339.6
10.00% Senior Secured Second Lien Notes due March 2022	978.4		—	—
7.875% Senior Notes due November 2026	247.7			247.6
Convertible Junior Subordinated Debentures due December 2066	385.2			382.3
Capital lease obligations	30.3			22.2
Other	0.7			1.2
Total	$	6,315.6		$	5,986.8

The carrying amounts of the 2013 Term Loan Facility due September 2020, the 10.00% Senior Secured Second Lien Notes due March 2022 (the Senior Secured Second Lien Notes), the 7.875% Senior Notes due December 2026 and the Convertible Junior Subordinated Debentures due December 2066 (the Debentures) have been presented above net of the respective unamortized original issue discounts.

As described in Note 1. "Summary of Significant Accounting Policies", the Company has classified as current all of its long-term debt with the exception of the Debentures as of December 31, 2015.

2013 Credit Facility

On September 24, 2013, the Company entered into a secured credit agreement (as amended, the 2013 Credit Facility), which provides for a $1.65 billion revolving credit facility (the 2013 Revolver) and a $1.20 billion term loan facility (the 2013 Term Loan Facility). In connection with the closing of the 2013 Credit Facility, the Company borrowed $1.19 billion under the 2013 Term Loan Facility, net of original issue discount of $12.0 million that will be amortized over its seven-year term, and transferred $94.7 million of existing letters of credit from its unsecured credit agreement dated as of June 18, 2010 (as amended, the 2010 Credit Agreement). The 2013 Revolver commitment will mature on September 24, 2018, or on August 15, 2018 if the Company’s 6.00% Senior Notes due 2018 are still in existence on such date. The 2013 Term Loan Facility matures on September 24, 2020. The Company capitalized total deferred financing costs of $18.3 million and $10.1 million related to the 2013 Revolver and 2013 Term Loan Facility, respectively, to be amortized over the respective five- and seven-year terms of those facilities.

Proceeds of the 2013 Term Loan Facility were used primarily to pay off amounts outstanding under the 2010 Credit Agreement and the Company's unsecured credit agreement dated October 28, 2011 (as amended), which had then-outstanding principal amounts of $301.8 million and $862.5 million, respectively. The Company recognized expense of $11.5 million on the write-off of previously deferred financing costs related to those facilities during the year ended December 31, 2013, which was classified in "Interest expense" in the consolidated statement of operations.

All borrowings under the 2013 Credit Facility (other than swingline borrowings and borrowings denominated in currencies other than U.S. dollars) bear interest, at the Company’s option, at either a base rate (subject to a floor of 2.00% for borrowings under the 2013 Term Loan Facility) or a eurocurrency rate (subject to a floor of 1.00% for borrowings under the 2013 Term Loan Facility), each as defined in the 2013 Credit Facility, plus: (1) in the case of the 2013 Term Loan Facility, a margin of 2.25% and 3.25% per year for borrowings bearing interest at the base rate and the eurocurrency rate, respectively; or (2) in the case of the 2013 Revolver, a margin dependent on the Company's consolidated net leverage ratio, as defined in the 2013 Credit Facility, ranging from 0.75% to 1.50% and 1.75% to 2.50% per year for borrowings bearing interest at the base rate and eurocurrency rate, respectively.

As of December 31, 2015 the Company had $1,164.9 million outstanding under the 2013 Term Loan Facility with an interest rate payable of LIBOR (with a floor of 1.00%) plus 3.25%, or 4.25% in total.



Peabody Energy Corporation	2015 Form 10-K	F- 40

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company pays a usage-dependent commitment fee under the 2013 Revolver, which is dependent upon the Company's consolidated net leverage ratio, as defined in the 2013 Credit Facility, and ranges from 0.375% to 0.500% of the available unused commitment. In addition, the Company pays a letter of credit fee, which is also dependent upon the Company's leverage ratio and ranges from 1.75% to 2.50% per year of the undrawn amount of each letter of credit, and a fronting fee equal to 0.125% per year of the face amount drawn under each letter of credit.

The 2013 Term Loan Facility is subject to quarterly amortization of 0.25% per quarter that commenced on October 1, 2013, with the final payment of all amounts outstanding (including accrued interest) being due on September 24, 2020. Subject to customary reinvestment rights, the 2013 Credit Facility is subject to mandatory prepayment and permanent commitment reduction provisions. These provisions include a requirement to prepay the loans with total net proceeds from certain asset sales exceeding $500 million in the aggregate, including certain asset sales by domestic unrestricted subsidiaries or domestic joint ventures of 50% or more of their assets or equity individually or in the aggregate exceeding $200 million. To the extent that mandatory prepayments and or permanent commitment reductions are required, prepayments shall be applied to prepay the term loan borrowings and, once no term loan borrowings are outstanding, the revolving commitments shall be permanently reduced by an amount that depends on the amount of revolving commitments in existence at the time of such reduction.

Under the 2013 Revolver, the Company must comply with two financial covenants on a quarterly basis, which are a maximum net secured first lien leverage ratio and a minimum interest coverage ratio. The Company's Consolidated Net Secured First Lien Leverage Ratio was approximately 1.6 to 1.0 and the Consolidated Interest Coverage Ratio was approximately 1.3 to 1.0, in each case, as of December 31, 2015. The Company was in compliance with those covenants as of December 31, 2015. The Company is permitted to pay dividends, buy and sell assets and make redemptions or repurchases of capital stock, subject to restrictions imposed by the 2013 Credit Facility. That agreement also imposes certain restrictions on the Company's ability to incur liens, incur debt, make investments (including acquisitions), engage in fundamental changes such as mergers and dissolutions, dispose of assets, change the nature of its business, enter into transactions with affiliates, enter into agreements that restrict the Company's ability to make dividends or distributions, enter into agreements with negative pledge clauses, make dividends from the top-level Gibraltar holding company of the Company's Australian operations to the Company's domestic subsidiaries in an amount in excess of $500 million per year and incur liens securing indebtedness on the Company’s “Principal Property” and “Capital Stock” (as such quoted terms are used in the Company’s Senior Notes indentures). It also contains customary events of default. The agreement generally does not restrict the intercompany loans and advances, provided that certain of such loans and advances are subordinated to the Company’s and its subsidaries obligations under the 2013 Credit Facility.

As of December 31, 2015, the Company had no borrowings under the 2013 Revolver, but had $710.0 million of letters of credit outstanding. The remaining capacity under the 2013 Revolver at December 31, 2015 was $940.0 million. The interest rate payable on the 2013 Revolver was LIBOR plus 2.25%, or 2.67% at December 31, 2015. During February 2016, the Company borrowed the maximum amount available under the 2013 Revolver, leaving no remaining capacity.

The Company's obligations under the 2013 Credit Facility are guaranteed by the Company and substantially all of its domestic subsidiaries and are secured by (1) a pledge of 65% of the stock of Peabody Investments (Gibraltar) Limited, a holding company for the Australian operations of the Company, (2) a pledge of the stock of Peabody IC Funding Corp., whose assets are substantially comprised of intercompany debt owed to it by Peabody IC Holdings LLC, a holding company whose sole asset is intercompany debt, which had a book value of $5.5 billion at December 31, 2015, owed to it by the top-level Gibraltar subsidiary of the Company’s Australian platform, an entity which previously owed such debt directly to Peabody IC Funding Corp. and (3) after the effectiveness of the First Amendment described below, substantially all of the Company’s U.S. assets and 65% of the equity interests of its first-tier foreign subsidiaries, subject to certain exceptions. Under the 2013 Credit Facility, the amount of such obligations that are secured by Principal Property and Capital Stock (each as defined in the indentures for the Company's 6.00%, 6.25%, 6.50%, and 7.875% Senior Notes (collectively, the Senior Notes) is limited for the Company to utilize the general liens basket in the Company’s Senior Notes indentures.

On February 5, 2015, the Company entered into the Omnibus Amendment Agreement (the First Amendment) related to its 2013 Credit Facility.



Peabody Energy Corporation	2015 Form 10-K	F- 41

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In addition to the pledge of certain collateral, among other things, the First Amendment:


•	amended the financial maintenance covenants to provide the Company with greater financial flexibility by lowering the minimum interest coverage ratio and increasing the maximum net secured first lien leverage ratio for the term of the 2013 Credit Facility;


•	amended the liens covenant to allow for second lien debt issuances, so long as the Company remains in compliance with the covenants in the 2013 Credit Facility;

•

amended certain other negative covenants to (1) reduce the annual cash dividend payments basket to a maximum of $27.5 million (with carryforward permitted), (2) reduce the additional general restricted payments basket, which includes dividends, stock repurchases and certain investments, to a maximum of $100.0 million (though the Company may also make restricted payments using another basket whose amount is based on, among other things, positive earnings during the term of the agreement) and (3) further limit the Company’s ability to incur liens, incur debt and make investments; and


•	provided for certain additional mandatory prepayments including with the net cash proceeds of certain asset sales, subject to customary reinvestment rights.

The Company paid aggregate modification costs of $11.8 million related to the First Amendment during the year ended December 31, 2015, which will be amortized over the remaining terms of the 2013 Revolver and the 2013 Term Loan Facility.

Under the 2013 Credit Facility, the secured obligations include: term loans outstanding, revolver borrowings, letters of credit outstanding, Swap Obligations and Cash Management Obligations, each as defined in the 2013 Credit Facility.

6.00%, 6.25%, 6.50% and 7.875% Senior Notes (collectively the Senior Notes)

The Senior Notes are senior unsecured obligations and rank senior in right of payment to any subordinated indebtedness; equally in right of payment with any senior indebtedness; are effectively junior in right of payment to the Company’s secured indebtedness, to the extent of the value of the collateral securing that indebtedness; and effectively junior to all the indebtedness and other liabilities of its subsidiaries that do not guarantee the notes.

The Senior Notes are jointly and severally guaranteed by nearly all of the Company’s domestic subsidiaries, as defined in the note indentures. The note indentures contain covenants that, among other things, limit the Company’s ability to create liens and enter into sale and lease-back transactions. The Senior Notes are redeemable at a redemption price equal to 100% of the principal amount of the notes being redeemed plus a make-whole premium and any accrued unpaid interest to the redemption date. If the Company experiences specific kinds of changes in control and the credit rating assigned to the Senior Notes declines below specified levels within 90 days of that time, holders of such notes have the right to require the Company to repurchase their notes at a repurchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase.

Interest payments on the Senior Notes are scheduled to occur each year as follows:



Senior Notes		Interest Payment Dates
6.00% Senior Notes		May 15 and November 15
6.25% Senior Notes		May 15 and November 15
6.50% Senior Notes		March 15 and September 15
7.875% Senior Notes		May 1 and November 1

Senior Secured Second Lien Notes Offering

On March 16, 2015, the Company completed the offering of $1.0 billion aggregate principal amount of the Senior Secured Second Lien Notes. The notes were offered to qualified institutional buyers under Rule 144A of the Securities Act, and to non-U.S. persons in transactions outside the U.S. under Regulation S of the Securities Act.

The Senior Secured Second Lien Notes are secured by a second-priority lien on all of the assets that secure the Company's obligations under the 2013 Credit Facility on a first-lien basis, subject to permitted liens and other limitations. The Company's Senior Secured Second Lien Notes indenture contains a limit, consistent with the 2013 Credit Facility, on the amount of debt that may be secured by Principal Property and Capital Stock.

The Company used the net proceeds from the sale of the notes, in part, to fund the tender offer to purchase its 7.375% Senior Notes due November 2016 (the 2016 Senior Notes) and to redeem the aggregate principal amount of the 2016 Senior Notes that was not tendered in the tender offer. The remaining proceeds were used for general corporate purposes.



Peabody Energy Corporation	2015 Form 10-K	F- 42

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company must pay interest on the notes semi-annually on March 15 and September 15 of each year until maturity on March 15, 2022. The Company may redeem the Senior Secured Second Lien Notes at any time on or after March 15, 2018 at the redemption prices specified in the related indenture and, prior to that date, at a redemption price equal to 100% of the principal amount of the notes being redeemed plus a make whole premium, in addition to any accrued and unpaid interest. Prior to March 15, 2018, the Company may also redeem up to 35% of the aggregate principal amount of the Senior Secured Second Lien Notes with the net cash proceeds from certain equity offerings.

The notes were issued at an issue price of 97.566% of principal amount, resulting in an original issue discount of $24.3 million that will be amortized through maturity. The Company also paid aggregate debt issuance costs of $16.9 million during the year ended December 31, 2015 related to the offering, which will also be amortized over the term of the Senior Secured Second Lien Notes.

2016 Senior Notes Tender Offer and Redemption

Concurrently with the offering of the Senior Secured Second Lien Notes, the Company commenced a tender offer to repurchase the $650.0 million aggregate principal amount then outstanding of the 2016 Senior Notes. Consequently, the Company repurchased $566.9 million aggregate principal amount of the 2016 Senior Notes that were validly tendered and not validly withdrawn during the tender offer. The Company redeemed the remaining $83.1 million aggregate principal amount of the 2016 Senior Notes on April 15, 2015. In connection with those repurchases, the Company recognized an aggregate loss on early debt extinguishment of $67.8 million in the consolidated statement of operations for the year ended December 31, 2015 comprised of aggregate tender offer and make-whole premiums paid of $66.4 million and the non-cash write-off of associated unamortized debt issuance costs of $1.4 million.

Convertible Junior Subordinated Debentures

As of December 31, 2015, the Company had $732.5 million aggregate principal outstanding of Debentures that generally require interest to be paid semiannually at a rate of 4.75% per year. The Debentures are convertible at any time on or prior to December 15, 2036 if any of the following conditions occur: (1) the Company’s closing common stock price exceeds 140% of the then applicable conversion price for the Debentures (currently $1,200.23 per share) for at least 20 of the final 30 trading days in any quarter; (2) a notice of redemption is issued with respect to the Debentures; (3) a change of control, as defined in the indenture governing the Debentures; (4) satisfaction of certain trading price conditions; and (5) other specified corporate transactions described in the indenture governing the Debentures. In addition, the Debentures are convertible at any time after December 15, 2036 to December 15, 2041, the scheduled maturity date. In the case of conversion following a notice of redemption or upon a non-stock change of control, as defined in the indenture governing the Debentures, holders may convert their Debentures into cash in the amount of the principal amount of their Debentures and shares of the Company’s common stock for any conversion value in excess of the principal amount. In all other conversion circumstances, holders will receive perpetual preferred stock (see Note 17. "Stockholders' Equity") with a liquidation preference equal to the principal amount of their Debentures, and any conversion value in excess of the principal amount will be settled with the Company’s common stock. As a result of the Patriot spin-off, the conversion rate was adjusted. The conversion rate has also been adjusted when there has been a change in the Company’s dividend distribution rate. The current conversion rate is 1.1664 shares of common stock per $1,000 principal amount of Debentures effective October 1, 2015. This adjusted conversion rate represents a conversion price of $857.30.

Between December 20, 2011 and December 19, 2036, the Company may redeem the Debentures, in whole or in part, if for at least 20 out of the 30 consecutive trading days immediately prior to the date on which notice of redemption is given, the Company’s closing common stock price has exceeded 130% of the then applicable conversion price for the Debentures (currently $1,114.50 per share). On or after December 20, 2036, whether or not the redemption condition is satisfied, the Company may redeem the Debentures, in whole or in part. The Company may not redeem any Debentures unless (1) all accrued and unpaid interest on the Debentures has been paid in full on or prior to the redemption date and (2) if any perpetual preferred stock is outstanding, the Company has first given notice to redeem the perpetual preferred stock in the same proportion as the redemption of the Debentures. Any redemption of the Debentures will be at a cash redemption price of 100% of the principal amount of the Debentures to be redeemed, plus accrued and unpaid interest to the date of redemption.

On December 15, 2041, the scheduled maturity date, the Company is required to use commercially reasonable efforts, subject to the occurrence of a market disruption event, as defined in the indenture governing the Debentures, to issue securities of equivalent equity content in an amount sufficient to pay the principal amount of the Debentures, together with accrued and unpaid interest. At the final maturity date of the Debentures on December 15, 2066, the entire principal amount will become due and payable, together with accrued and unpaid interest.



Peabody Energy Corporation	2015 Form 10-K	F- 43

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In connection with the issuance of the Debentures, the Company entered into a Capital Replacement Covenant (the CRC). Pursuant to the CRC, the Company covenanted for the benefit of holders of covered debt, as defined in the CRC (currently the Company’s 7.875% Senior Notes, issued in an aggregate principal amount of $250.0 million), that neither the Company nor any of its subsidiaries shall repay, redeem or repurchase all or any part of the Debentures on or after December 15, 2041 and prior to December 15, 2046, except to the extent that the total repayment, redemption or repurchase price does not exceed the sum of: (1) 400% of the Company’s net cash proceeds from the sale of its common stock and rights to acquire its common stock (including common stock issued pursuant to the Company’s dividend reinvestment plan or employee benefit plans); (2) the Company’s net cash proceeds from the sale of its mandatorily convertible preferred stock, as defined in the CRC, or debt exchangeable for equity, as defined in the CRC; and (3) the Company’s net cash proceeds from the sale of other replacement capital securities, as defined in the CRC, in each case, during the six months prior to the notice date for the relevant payment, redemption or repurchase.

The Debentures are unsecured obligations of the Company, ranking junior to all existing and future senior and subordinated debt (excluding trade accounts payable or accrued liabilities arising in the ordinary course of business) except for any future debt that ranks equal to or junior to the Debentures. The Debentures rank equal in right of payment with the Company’s obligations to trade creditors. In addition, the Debentures are effectively subordinated to all indebtedness of the Company’s subsidiaries. The indenture governing the Debentures places no limitation on the amount of additional indebtedness that the Company or any of the Company’s subsidiaries may incur.

In June 2014, the Company received sufficient consents from holders of the Debentures to amend the related indenture and eliminate the provisions relating to the mandatory and optional deferral of interest, thereby providing the Company greater financial and operational flexibility and increased ease of administration with respect to the Debentures. After receiving those consents, the Company entered into a supplemental indenture reflecting the amendments, which binds all holders of the Debentures. The eliminated provisions related to the mandatory deferral of interest (1) required that the Company defer interest payments on the Debentures under specified circumstances unless it obtained funds for those payments through the sale of qualifying warrants or qualifying preferred stock, (2) subject to limitations, required that the Company obtain the necessary funds through such a sale, and (3) prohibited the Company from making certain distributions (including dividends) with respect to its capital stock during any mandatory extension period (as defined in the original indenture governing the Debentures) and until the Company paid all accrued but unpaid interest on the Debentures. The eliminated provisions related to the optional deferral of interest allowed the Company to defer interest payments on the Debentures at its discretion, in certain circumstances.

Holders of the Debentures that validly consented to the amendments received a consent fee of $15.00 per $1,000 principal amount of the Debentures. The Company paid aggregate consent fees of $10.1 million in June 2014 in connection with the Debentures consent solicitation, which will be amortized over the remaining term of the Debentures. Additionally, the Company incurred $1.6 million in fees to third parties related to the consent solicitation and supplemental indenture, which were classified in "Loss on early debt extinguishment" in the consolidated statement of operations for the year ended December 31, 2014.

The Company accounts for the liability and equity components of the Debentures in a manner that reflects the nonconvertible debt borrowing rate when recognizing interest cost in subsequent periods. The following table illustrates the carrying amount of the equity and debt components of the Debentures:



	December 31,
	2015			2014
	(Dollars in millions)
Carrying amount of the equity component	$	215.4		$	215.4

Principal amount of the liability component	$	732.5		$	732.5
Unamortized discount	(347.3		)	(350.2		)
Net carrying amount	$	385.2		$	382.3



Peabody Energy Corporation	2015 Form 10-K	F- 44

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table illustrates the effective interest rate and the interest expense related to the Debentures:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Effective interest rate	4.9		%	4.9		%	4.9		%
Interest expense — contractual interest coupon	$	34.8		$	34.8		$	34.8
Interest expense — amortization of debt discount	2.9			2.6			2.3

The remaining period over which the discount will be amortized is 26 years as of December 31, 2015.

Capital Lease Obligations

Refer to Note 13. "Leases" for additional information associated with the Company's capital leases, which pertain to the financing of mining equipment used in operations.

Debt Maturities, Interest Paid and Financing Costs

The aggregate amounts of long-term debt maturities (including unamortized debt discounts) subsequent to December 31, 2015, including capital lease obligations, were as follows:




Year of Maturity	(Dollars in millions)
2016	$	5,930.4
2017	—
2018	—
2019	—
2020	—
2021 and thereafter	385.2
Total	$	6,315.6

Interest paid on long-term debt was $414.2 million, $404.4 million and $388.2 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Financing costs incurred with the issuance of the Company’s debt are being amortized to interest expense over the remaining term of the associated debt. The remaining balance at December 31, 2015 was $94.8 million, of which $70.6 million will be amortized to interest expense over the next five years.


(13)	Leases

The Company leases equipment and facilities under various noncancelable lease agreements. Certain lease agreements are subject to the restrictive covenants of the Company's credit facilities and include cross-acceleration provisions, under which the lessor could require certain remedies including, but not limited to, immediate recovery of the present value of any remaining lease payments. Rental expense under operating leases, including expense related to short-term operating leases, was $290.1 million, $306.0 million and $305.9 million for the years ended December 31, 2015, 2014 and 2013, respectively. One of the Company's operating lease agreements for underground mining equipment in Australia entered into in 2013 requires contingent rent to be paid only if and when certain coal is mined at a specified margin as defined in the agreements. There was no contingent expense related to that arrangement for the years ended December 31, 2015, 2014 and 2013. The gross value of property, plant, and equipment under capital leases was $125.6 million and $175.1 million as of December 31, 2015 and 2014, respectively, related primarily to the leasing of mining equipment. The accumulated depreciation for these items was $111.4 million and $138.4 million at December 31, 2015 and 2014, respectively, and changes thereto have been included in "Depreciation, depletion and amortization" in the consolidated statements of operations.

The Company also leases coal reserves under agreements that require royalties to be paid as the coal is mined. Certain agreements also require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Total royalty expense was $444.5 million, $507.8 million and $546.0 million for the years ended December 31, 2015, 2014 and 2013, respectively.



Peabody Energy Corporation	2015 Form 10-K	F- 45

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A substantial amount of the coal mined by the Company is produced from mineral reserves leased from the owner. One of the major lessors is the U.S. government, from which the Company leases substantially all of the coal it mines in Wyoming under terms set by Congress and administered by the U.S. Bureau of Land Management. These leases are generally for an initial term of ten years but may be extended by diligent development and mining of the reserves until all economically recoverable reserves are depleted. The Company has met the diligent development requirements for substantially all of these federal leases either directly through production, by including the lease as a part of a logical mining unit with other leases upon which development has occurred, or by paying an advance royalty in lieu of continued operations. Annual production on these federal leases must total at least 1.0% of the leased reserve or the original amount of coal in the entire logical mining unit in which the leased reserve resides. In addition, royalties are payable monthly at a rate of 12.5% of the gross realization from the sale of the coal mined using surface mining methods and at a rate of 8.0% of the gross realization for coal produced using underground mining methods. The Company also leases coal reserves in Arizona from The Navajo Nation and the Hopi Tribe under leases that are administered by the U.S. Department of the Interior. These leases expire upon exhaustion of the leased reserves or upon the permanent ceasing of all mining activities on the related reserves as a whole. The royalty rates are also generally based upon a percentage of the gross realization from the sale of coal. These rates are subject to redetermination every ten years under the terms of the leases. The remainder of the leased coal is generally leased from state governments, land holding companies and various individuals. The duration of these leases varies greatly. Typically, the lease terms are automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal.

Mining and exploration in Australia is generally conducted under leases, licenses or permits granted by state governments. Mining and exploration licenses and their associated environmental protection approvals contain conditions relating to such matters as minimum annual expenditures, environmental compliance, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price (less certain allowable deductions in some cases). Generally landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is often payable to landowners, occupiers and Aboriginal traditional owners with residual native title rights and interests for the loss of access to the land from the proposed mining activities. The amount and type of compensation and the ability to proceed to grant of a mining tenement may be determined by agreement or court determination, as provided by law.

Future minimum lease and royalty payments as of December 31, 2015 are as follows:



	Capital Leases		Operating Leases		Coal Lease and Royalty Obligations
Year Ending December 31,	Capital Leases		Operating Leases		Coal Lease and Royalty Obligations
	(Dollars in millions)
2016	$	12.9	$	191.5	$	254.3
2017	7.3		173.8		20.3
2018	8.8		109.4		19.9
2019	0.5		64.2		19.4
2020	0.5		23.4		18.9
2021 and thereafter	10.1		36.5		30.8
Total minimum lease payments	40.1		$	598.8	$	363.6
Less interest	9.8
Present value of minimum capital lease payments	$	30.3

As of December 31, 2015, certain of the Company’s coal lease obligations were secured by outstanding surety bonds totaling $110.5 million.



Peabody Energy Corporation	2015 Form 10-K	F- 46

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(14)	Asset Retirement Obligations

Reconciliations of the Company’s asset retirement obligations are as follows:



	December 31,
	2015			2014
	(Dollars in millions)
Balance at beginning of year	$	752.5		$	712.8
Liabilities incurred or acquired	1.3			22.7
Liabilities settled or disposed	(53.3		)	(19.7		)
Accretion expense	42.7			39.3
Revisions to estimates	(31.1		)	(2.6		)
Balance at end of year	$	712.1		$	752.5
Less: Current portion (included in "Accounts payable and accrued expenses")	25.5			30.2
Noncurrent obligation (included in "Asset Retirement Obligations")	686.6			722.3
Balance at end of year — active locations	$	656.8		$	676.2
Balance at end of year — closed or inactive locations	$	55.3		$	76.3

In 2014, the Company recognized an asset retirement obligation of $22.2 million due to the nonperformance of a contract miner at a coal reserve property in the Eastern U.S. Because mining operations have ceased at that operation, a corresponding charge was recorded to “Asset retirement obligation expenses” in the consolidated statement of operations for the year ended December 31, 2014. During 2015, the Company sold its interests in the coal reserve property, with the buyer assuming the related asset retirement obligation. The Company recorded a gain of $9.6 million in connection with the transaction.

The credit-adjusted, risk-free interest rates were 50.83%, 6.82%, and 6.44% at December 31, 2015, 2014 and 2013, respectively.

As of December 31, 2015 and 2014, the Company had $609.4 million and $645.0 million, respectively, in surety bonds and bank guarantees outstanding to secure reclamation obligations. The amount of reclamation self-bonding in certain states in which the Company qualifies was $1,430.8 million and $1,361.4 million as of December 31, 2015 and 2014, respectively. Additionally, the Company had $126.6 million and $17.6 million, respectively, of letters of credit in support of reclamation obligations as of December 31, 2015 and 2014.


(15)	Postretirement Health Care and Life Insurance Benefits

The Company currently provides health care and life insurance benefits to qualifying salaried and hourly retirees and their dependents from benefit plans established by the Company. Plan coverage for health benefits is provided to future hourly and salaried retirees in accordance with the applicable plan document. Life insurance benefits are provided to future hourly retirees in accordance with the applicable labor agreement.

Net periodic postretirement benefit cost included the following components:



	Year Ended December 31,
	2015			2014		2013
	(Dollars in millions)
Service cost for benefits earned	$	11.2		$	12.2	$	15.8
Interest cost on accumulated postretirement benefit obligation	33.8			36.4		41.8
Amortization of prior service (credit) cost	(6.8		)	1.3		(1.7		)
Amortization of actuarial loss	24.9			14.5		24.1
Settlement related to the Patriot bankruptcy ⁽¹⁾	—			—		63.2
Special termination benefits ⁽²⁾	—			1.6		0.9
Net periodic postretirement benefit cost	$	63.1		$	66.0	$	144.1


⁽¹⁾	Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" herein for additional details related to this transaction.


⁽²⁾	Reflected in "Restructuring and pension settlement charges" in the consolidated statement of operations for the year ended December 31, 2014.



Peabody Energy Corporation	2015 Form 10-K	F- 47

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following includes pre-tax amounts recorded in "Accumulated other comprehensive loss":



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Net actuarial (gain) loss arising during year	$	(35.1	)	$	115.8		$	(24.3	)
Prior service credit arising during year	—			(18.0		)	—
Amortization:
Actuarial loss	(24.9		)	(14.5		)	(24.1		)
Prior service credit (cost)	6.8			(1.3		)	1.7
Settlement related to the Patriot bankruptcy: ⁽¹⁾
Actuarial loss	—			—			(61.3		)
Prior service cost	(16.6		)	—			(1.9		)
Total recorded in other comprehensive (income) loss	$	(69.8	)	$	82.0		$	(109.9	)


⁽¹⁾	Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" herein for additional details related to this transaction.

The Company amortizes actuarial gain and loss using a 0% corridor with an amortization period that covers the average future working lifetime of active employees (10.49 years and 11.00 years at January 1, 2016 and 2015, respectively). The estimated net actuarial loss and prior service credit that will be amortized from accumulated other comprehensive (loss) income into net periodic postretirement benefit cost during the year ending December 31, 2016 are $20.4 million and $11.0 million, respectively.



Peabody Energy Corporation	2015 Form 10-K	F- 48

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth the plans' funded status reconciled with the amounts shown in the consolidated balance sheets:



	December 31,
	2015				2014
	(Dollars in millions)
Change in benefit obligation:
Accumulated postretirement benefit obligation at beginning of period	$	839.1			$	735.4
Service cost	11.2				12.2
Interest cost	33.8				36.4
Participant contributions	1.7				2.2
Plan changes⁽¹⁾	(16.6		)		(18.0		)
Benefits paid	(46.5		)		(46.5		)
Actuarial (gain) loss ⁽²⁾	(35.1		)		115.8
Settlement related to the Patriot bankruptcy ⁽³⁾	(15.2		)		—
Special termination benefits	—				1.6
Other	3.7			—	—
Accumulated postretirement benefit obligation at end of period	776.1				839.1
Change in plan assets:
Fair value of plan assets at beginning of period	—				—
Employer contributions	44.8				44.3
Participant contributions	1.7				2.2
Benefits paid and administrative fees (net of Medicare Part D reimbursements)	(46.5		)		(46.5		)
Fair value of plan assets at end of period	—				—
Funded status at end of year	(776.1		)		(839.1		)
Less: Current portion (included in "Accounts payable and accrued expenses")	53.2				57.2
Noncurrent obligation (included in "Accrued postretirement benefit costs")	$	(722.9	)		$	(781.9	)

⁽¹⁾

Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" herein for additional details related to the reduction in the benefit obligation for 2015. In 2014, the Company made various plan changes that became effective January 1, 2015 for certain plan participants designed to bring consistency amongst the various retiree medical programs which resulted in a $45.4 million reduction to the benefit obligation. In addition, the Company made a plan change effective April 1, 2014 for certain plan participants' benefits no longer funded through a Medicare Advantage Program which resulted in a $27.6 million increase to the benefit obligation. The plan changes will not affect participant benefits.


⁽²⁾	In 2014, the Company reviewed its demographic assumptions (including mortality, retirements and terminations) in conjunction with the recently-issued mortality tables published by the Society of Actuaries, to select assumptions that are aligned with the Company’s experience. The updated demographic assumptions increased the December 31, 2014 benefit obligation by approximately $63 million.


⁽³⁾	Refer to Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" herein for additional details related to this transaction.

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:



	December 31,
	2015		2014
Discount rate	4.50	%	4.10	%
Measurement date	December 31, 2015		December 31, 2014



Peabody Energy Corporation	2015 Form 10-K	F- 49

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The weighted-average assumptions used to determine net periodic benefit cost during each year were as follows:



	Year Ended December 31,
	2015		2014		2013
Discount rate	4.10	%	4.90	%	4.21	%
Measurement date	December 31, 2014		December 31, 2013		December 31, 2012

The following presents information about the assumed health care cost trend rate:



	Year Ended December 31,
	2015		2014
Pre-Medicare:
Health care cost trend rate assumed for next year	6.60	%	7.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.75	%	4.75	%
Year that the rate reaches the ultimate trend rate	2021		2021

Post-Medicare:
Health care cost trend rate assumed for next year	5.80	%	6.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.75	%	4.75	%
Year that the rate reaches the ultimate trend rate	2021		2021

Assumed health care cost trend rates have a significant effect on the expense and liability amounts reported for health care plans. A one-percentage-point change in the assumed health care cost trend would have the following effects:



	One Percentage- Point Increase		One Percentage- Point Decrease
	(Dollars in millions)
Effect on total service and interest cost components ⁽¹⁾	$	3.8	$	(3.4	)
Effect on total postretirement benefit obligation ⁽¹⁾	$	71.3	$	(62.3	)


⁽¹⁾	In addition to the effect on total service and interest cost components of expense, changes in trend rates would also increase or decrease the actuarial gain or loss amortization expense component. The impact on actuarial gain or loss amortization would approximate the increase or decrease in the obligation divided by 10.49 years at January 1, 2016.

Plan Assets

The Company’s postretirement benefit plans are unfunded.

Estimated Future Benefit Payments

The following benefit payments (net of retiree contributions), which reflect expected future service, as appropriate, are expected to be paid by the Company:



	Postretirement
	Benefits
	(Dollars in millions)
2016	$	53.2
2017	55.2
2018	56.7
2019	57.7
2020	58.1
Years 2021-2025	291.8



Peabody Energy Corporation	2015 Form 10-K	F- 50

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(16)	Pension and Savings Plans

One of the Company’s subsidiaries, Peabody Investments Corp. (PIC), sponsors a defined benefit pension plan covering certain U.S. salaried employees and eligible hourly employees at certain PIC subsidiaries (the Peabody Plan). A subsidiary of PIC also has a defined benefit pension plan covering eligible employees who are represented by the United Mine Workers of America (UMWA) under the Western Surface Agreement (the Western Plan). PIC also sponsors an unfunded supplemental retirement plan to provide senior management with benefits in excess of limits under the federal tax law (collectively, the Plans).

Effective May 31, 2008, the Peabody Plan was frozen in its entirety for both participation and benefit accrual purposes. The Company adopted an enhanced savings plan contribution structure in lieu of benefits formerly accrued under the Peabody Plan. In August 2014, the Company announced a program to offer voluntary lump-sum pension payout to eligible former salaried employees in the Peabody Plan that settled the Company’s obligation to them. The program provided participants with a one-time choice of electing to receive a lump-sum settlement of their pension benefit. As part of this voluntary lump-sum program, the Company settled $41.7 million of its pension obligations for U.S. salaried retirees and former salaried employees in the Peabody Plan with an equal amount paid from plan assets. As a result, the Company recorded a settlement charge of $8.7 million reflecting the accelerated recognition of unamortized actuarial losses in the Peabody Plan proportionate to the obligation that was settled. The settlement charge was reflected in “Restructuring and pension settlement charges” on the consolidated statement of operations with a corresponding reduction in “Accumulated other comprehensive loss” on the consolidated balance sheet.

Net periodic pension cost included the following components:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Service cost for benefits earned	$	2.7		$	2.1		$	2.2
Interest cost on projected benefit obligation	40.4			45.4			42.2
Expected return on plan assets	(48.2		)	(54.3		)	(59.5		)
Amortization of prior service cost	1.0			1.3			1.0
Amortization of net actuarial losses	39.6			30.2			65.7
Settlement charge	—			8.7			—
Total net periodic pension cost	$	35.5		$	33.4		$	51.6

The following includes pre-tax amounts recorded in "Accumulated other comprehensive loss":



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Net actuarial loss (gain) arising during year	$	30.6		$	79.2		$	(133.8	)
Prior service cost arising during year	—			—			2.2
Amortization:
Net actuarial loss	(39.6		)	(30.2		)	(65.7		)
Prior service cost	(1.0		)	(1.3		)	(1.0		)
Settlement charge	—			(8.7		)	—
Total recorded in other comprehensive (income) loss	$	(10.0	)	$	39.0		$	(198.3	)

The Company amortizes actuarial gain and loss using a 5% corridor with a five-year amortization period. The estimated net actuarial loss and prior service cost that will be amortized from "Accumulated other comprehensive loss" into net periodic pension cost during the year ending December 31, 2016 are $24.7 million and $0.3 million, respectively.



Peabody Energy Corporation	2015 Form 10-K	F- 51

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following summarizes the change in benefit obligation, change in plan assets and funded status of the Plans:



	December 31,
	2015			2014
	(Dollars in millions)
Change in benefit obligation:
Projected benefit obligation at beginning of period	$	1,002.5		$	947.3
Service cost	2.7			2.1
Interest cost	40.4			45.4
Benefits paid	(62.6		)	(57.2		)
Actuarial (gain) loss ⁽¹⁾	(43.7		)	106.6
Settlement	—			(41.7		)
Projected benefit obligation at end of period	939.3			1,002.5
Change in plan assets:
Fair value of plan assets at beginning of period	839.8			851.4
Actual (loss) return on plan assets	(26.1		)	81.7
Employer contributions	6.2			5.6
Benefits paid	(62.6		)	(57.2		)
Settlement	—			(41.7		)
Fair value of plan assets at end of period	757.3			839.8
Funded status at end of year	$	(182.0	)	$	(162.7	)
Amounts recognized in the consolidated balance sheets:
Current obligation (included in "Accounts payable and accrued expenses")	$	(1.6	)	$	(1.7	)
Noncurrent obligation (included in "Other noncurrent liabilities")	(180.4		)	(161.0		)
Net amount recognized	$	(182.0	)	$	(162.7	)

⁽¹⁾During 2014, the Company reviewed its demographic assumptions (such as mortality, retirements and terminations) in conjunction with the recently-issued mortality tables published by the Society of Actuaries, to select assumptions that are aligned with the Company’s experience. The updated demographic assumptions increased the December 31, 2014 benefit obligation by approximately $36 million.

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:



	December 31,
	2015		2014
Discount rate	4.55	%	4.15	%
Measurement date	December 31, 2015		December 31, 2014

The weighted-average assumptions used to determine net periodic benefit cost during each year were as follows:



	Year Ended December 31,
	2015		2014		2013
Discount rate	4.15	%	4.95	%	4.10	%
Expected long-term return on plan assets	6.25	%	6.85	%	7.75	%
Measurement date	December 31, 2014		December 31, 2013		December 31, 2012

The expected rate of return on plan assets is determined by taking into consideration expected long-term returns associated with each major asset class based on long-term historical ranges, inflation assumptions and the expected net value from active management of the assets based on actual results. Effective January 1, 2016, the Company lowered its expected rate of return on plan assets from 6.25% to 6.00%, reflecting the impact of the Company's asset allocation and capital market expectations.



Peabody Energy Corporation	2015 Form 10-K	F- 52

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The projected benefit obligation and the accumulated benefit obligation exceeded plan assets for all plans as of December 31, 2015 and 2014. The accumulated benefit obligation for all plans was $939.3 million and $1,002.5 million as of December 31, 2015 and 2014, respectively.

Assets of the Plans

Assets of the PIC Master Trust (the Master Trust) are invested in accordance with investment guidelines established by the Peabody Plan Retirement Committee and the Peabody Western Plan Retirement Committee (collectively, the Retirement Committees) after consultation with outside investment advisors and actuaries.

The asset allocation targets have been set with the expectation that the assets of the Master Trust will be managed with an appropriate level of risk to fund each Plan's expected liabilities. To determine the appropriate target asset allocations, the Retirement Committees consider the demographics of each Plan's participants, the funded status of each Plan, the business and financial profile of the Company and other associated risk preferences. These allocation targets are reviewed by the Retirement Committees on a regular basis and revised as necessary. The Retirement Committees have developed and implemented a dynamic asset-liability management investment strategy (the Dynamic Investment Strategy) designed to reduce each Plan's funded status volatility risk as funded status increases resulting from changes in liabilities due to discount rates and other factors, investment returns and funding contributions. The Dynamic Investment Strategy adjusts allocations between return-seeking (i.e., equities and other similar investments) and liability hedging (i.e., fixed income duration and spread exposure) portfolios in a pre-established manner, with changes triggered when the Plans reach certain funded status thresholds. As of December 31, 2015 and 2014, the Master Trust investment portfolio reflected the Company's target asset mix of 31% and 35% equity securities, respectively, and 69% and 65% fixed income investments, respectively. Master Trust assets also include funds invested in various real estate properties representing approximately 3% and 4% of total Master Trust assets as of December 31, 2015 and 2014, respectively. The Retirement Committees' intention is to liquidate these real estate holdings when allowable per the terms of the limited partnership agreements. Generally, dissolution and liquidation of the limited partnerships is required before the Master Trust’s real estate holdings can be liquidated and is estimated to occur at various times through 2021.

Assets of the Master Trust are either under active management by third-party investment advisors or in index funds, all of which are selected and monitored by the Retirement Committees. Specific investment guidelines have been established by the Retirement Committees for each major asset class including performance benchmarks, allowable and prohibited investment types and concentration limits. In general, investment guidelines do not permit leveraging the assets held in the Master Trust. However, investment managers may employ various strategies and derivative instruments in establishing overall portfolio characteristics consistent with the guidelines and investment objectives established by the Retirement Committees for their portfolios. Equity investment guidelines do not permit entering into put or call options (except as deemed appropriate to manage currency risk), and futures contracts are permitted only to the extent necessary to facilitate liquidity management. Fixed income investment guidelines only allow for exchange-traded derivatives if the investment manager deems the derivative vehicle to be more attractive than a similar direct investment in an underlying cash market or to manage the duration of the fixed income portfolio.

A financial instrument’s level within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Following is a description of the valuation techniques and inputs used for investments measured at fair value, including the general classification of such investments pursuant to the valuation hierarchy.

U.S. equity securities. The Master Trust invests in U.S. equity securities for growth and diversification. Investment vehicles include a mutual fund (benchmarked against the performance of the S&P 500 Index) that invests in large-cap publicly traded common stocks and a common/collective trust (benchmarked against the performance of the Russell 2000 Index) that invests in small-cap publicly traded common stocks. The mutual fund, which is traded on a national securities exchange in an active market, is valued using daily publicly quoted net asset value (NAV) prices and accordingly classified within Level 1 of the valuation hierarchy. The common/collective trust (CCT), which is not publicly traded on a national securities exchange, is valued using a NAV that is based on a derived price in an active market and accordingly classified within Level 2 of the valuation hierarchy. U.S. equity securities are not subject to liquidity redemption restrictions.



Peabody Energy Corporation	2015 Form 10-K	F- 53

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

International equity securities. The Master Trust invests in international equity securities for growth and diversification. Investment vehicles include a CCT that invests in publicly traded non-U.S. equity securities (the Equity CCT) and another CCT (benchmarked against the performance of the MSCI Emerging Markets Index) that primarily invests in equity index securities of companies in global emerging markets (the Equity Index CCT), collectively, the CCTs. Equity and equity index securities within both CCTs are valued using the closing price reported by their primary stock exchange and translated at each valuation date from local currency into U.S. dollars based on independently published currency exchange rates. The NAV is determined in U.S. dollars and calculated as of the last business day of each month for the Equity CCT and daily for the Equity Index CCT. Both CCTs are classified within the Level 2 valuation hierarchy since NAV is based on a derived price in an active market and is not traded on a national securities exchange. Redemptions for both CCTs are at NAV. Equity CCT redemptions can only occur on the first business day of each month subject to a notification period and minimum withdrawal limits. Equity Index CCT redemptions can occur daily.

Debt securities. The Master Trust invests in debt securities for diversification, volatility reduction of equity securities and to provide a hedge to interest rate movements affecting liabilities. Investment vehicles include U.S. government and agency securities, investment-grade corporate bonds, U.S. municipal bonds, non-U.S. government bonds and an institutional mutual fund that holds a diversified portfolio of long-duration corporate fixed income investments. Fair value for these securities is provided by a third-party pricing service that utilizes various inputs such as benchmark yields, reported trades, broker/dealer quotes, issuer spreads and benchmark securities as well as other relevant economic measures. If fair value is based on quoted prices in active markets and traded on a national securities exchange, debt securities are classified within the Level 1 valuation hierarchy; otherwise, debt securities are classified within the Level 2 valuation hierarchy. NAV for the institutional mutual fund is calculated daily in actively traded markets and is classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the fund is not traded on a national securities exchange. Debt securities are not subject to liquidity redemption restrictions.

Short-term investments. The Master Trust invests in short-term investments to manage liquidity required for payment of participant benefits and certain administrative fees. Investment vehicles primarily include a non-interest bearing cash fund with an earnings credit allowance feature; an institutional mutual fund that consists of a diversified portfolio of liquid, short-term instruments of varying maturities; and various exchange-traded derivative instruments consisting of futures and interest rate swap agreements used to manage the duration of certain liability-hedging investments. The non-interest bearing cash fund is classified within the Level 1 valuation hierarchy. The institutional mutual fund is classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the fund is not traded on a national securities exchange. Exchange traded derivatives, such as options and futures, for which market quotations are readily available, are valued at the last reported sale price or official closing price on the primary market or exchange on which they are traded and are classified within the Level 1 valuation hierarchy. Short-term investments are not subject to liquidity redemption restrictions.

Interests in real estate. The Master Trust invests in real estate interests for diversification. Investments in real estate represent interests in several limited partnerships, which invest in various real estate properties. Interests in real estate are valued using various methodologies, including independent third party appraisals; fair value measurements are not developed by the Company. For some investments, little market activity may exist and determination of fair value is then based on the best information available in the circumstances. This involves a significant degree of judgment by taking into consideration a combination of internal and external factors. Accordingly, interests in real estate are classified within the Level 3 valuation hierarchy. Some limited partnerships issue dividends to their investors in the form of cash distributions that the Plans invest elsewhere within the Master Trust. Certain interests in real estate are subject to liquidity redemption restrictions and voluntary redemptions are generally not permitted. Upon liquidation of the limited partnerships, redemptions will generally be in the form of cash distributions and invested elsewhere within the Master Trust.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. The inputs or methodologies used for valuing investments are not necessarily an indication of the risk associated with investing in those investments.



Peabody Energy Corporation	2015 Form 10-K	F- 54

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables present the fair value of assets in the Master Trust by asset category and by fair value hierarchy:



	December 31, 2015
	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
U.S. equity securities	$	107.1	$	40.2	$	—	$	147.3
International equity securities	—		57.1		—		57.1
U.S. debt securities	26.8		26.6		—		53.4
International debt securities	—		15.0		—		15.0
Corporate debt securities	—		443.1		—		443.1
Short-term investments	18.2		0.2		—		18.4
Interests in real estate	—		—		23.0		23.0
Total assets at fair value	$	152.1	$	582.2	$	23.0	$	757.3



	December 31, 2014
	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
U.S. equity securities	$	141.7	$	48.6	$	—	$	190.3
International equity securities	—		69.8		—		69.8
U.S. debt securities	25.3		29.1		—		54.4
International debt securities	—		23.5		—		23.5
Corporate debt securities	—		447.8		—		447.8
Short-term investments	17.5		6.3		—		23.8
Interests in real estate	—		—		30.2		30.2
Total assets at fair value	$	184.5	$	625.1	$	30.2	$	839.8

The table below sets forth a summary of changes in the fair value of the Master Trust’s Level 3 investments:



	Year Ended December 31,
	2015			2014
	(Dollars in millions)
Balance, beginning of year	$	30.2		$	29.9
Realized gains	3.2			0.2
Unrealized gains relating to investments still held at the reporting date	0.2			4.9
Purchases, sales and settlements, net	(10.6		)	(4.8		)
Balance, end of year	$	23.0		$	30.2



Peabody Energy Corporation	2015 Form 10-K	F- 55

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Contributions

Annual contributions to qualified plans are made in accordance with minimum funding standards and the Company's agreement with the Pension Benefit Guaranty Corporation (PBGC). Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006 (generally 80%). During the year ended December 31, 2015, the Company contributed $4.5 million and $1.7 million, respectively, to its qualified and non-qualified pension plans. As of December 31, 2015, the Company's qualified plans are expected to be at or above the Pension Protection Act thresholds and will therefore avoid benefit restrictions and at-risk penalties for 2016. On November 2, 2015, the Bipartisan Budget Act of 2015 (BBA15) was signed into law, which extends pension funding stabilization provisions that were part of the Highway and Transportation Funding Act of 2014 (HATFA) and the Moving Ahead for Progress in the 21^st Century Act of 2012 (MAP-21). Under BBA15, the pension funding stabilization provisions temporarily increased the interest rates used to determine pension liabilities for purposes of minimum funding requirements through 2020. Similar to MAP-21, BBA15 is not expected to change the Company's total required cash contributions over the long term, but is expected to reduce the Company's required cash contributions through 2020 if current interest rate levels persist. Based upon minimum funding requirements in accordance with HATFA and BBA15, the Company expects to contribute approximately $2.2 million to its pension plans to meet minimum funding requirements for its qualified plans and benefit payments for its non-qualified plans in 2016.

Estimated Future Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in connection with the Company's benefit obligation:



	Pension Benefits
	(Dollars in millions)
2016	$	62.8
2017	63.4
2018	64.0
2019	64.0
2020	65.6
Years 2021-2025	325.2

Defined Contribution Plans

The Company sponsors employee retirement accounts under two 401(k) plans for eligible U.S. employees. The Company matches voluntary contributions to each plan up to specified levels. The expense for these plans was $22.0 million, $44.7 million and $46.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. A performance contribution feature in one of the plans allows for additional contributions from the Company based upon meeting specified Company performance targets. Performance contributions paid during the years ended December 31, 2015, 2014 and 2013 were $19.5 million, $18.3 million and $16.5 million, respectively. The performance contribution was paid in Peabody Energy Corporation common stock for the year ended December 31, 2015 and cash for the years ended December 31, 2014 and 2013, respectively.



Peabody Energy Corporation	2015 Form 10-K	F- 56

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(17)	Stockholders’ Equity

Common Stock

Pursuant to the authorization provided at a special meeting of the Company's stockholders held on September 16, 2015, the Company completed a 1-for-15 reverse stock split of the shares of the Company’s common stock on September 30, 2015 (the Reverse Stock Split). Refer to Note 1. "Summary of Significant Accounting Policies" for additional details surrounding the Reverse Stock Split. As a result of the Reverse Stock Split, the Company has 53.3 million authorized shares of $0.01 par value common stock. Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. The holders of common stock do not have cumulative voting rights in the election of directors. Holders of common stock are entitled to receive ratably dividends if, as and when dividends are declared from time to time by the Company's Board of Directors out of funds legally available for that purpose, after payment of dividends required to be paid on outstanding preferred stock or series common stock, as described below. Upon liquidation, dissolution or winding up, any business combination or a sale or disposition of all or substantially all of the assets, the holders of common stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and accrued but unpaid dividends and liquidation preferences on any outstanding preferred stock or series common stock. The common stock has no preemptive or conversion rights and is not subject to further calls or assessment by us. There are no redemption or sinking fund provisions applicable to the common stock.

The following table summarizes common stock activity from January 1, 2013 to December 31, 2015:



	2015	2014	2013
	(In millions)
Shares outstanding at the beginning of the year	18.1	18.0	17.9
Stock grants to employees	0.2	0.1	0.1
Performance share contribution 401k	0.2	—	—
Shares outstanding at the end of the year	18.5	18.1	18.0

Preferred Stock and Series Common Stock

The Board of Directors is authorized to issue up to 10.0 million shares of preferred stock and up to 40.0 million shares of series common stock, both with a $0.01 per share par value. The Board of Directors can determine the terms and rights of each series, whether dividends (if any) will be cumulative or non-cumulative and the dividend rate of the series, redemption or sinking fund provisions, conversion terms, prices and rates and amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Company and whether the shares of the series will be convertible into shares of any other class or series, or any other security, of the Company or any other corporation. The Board of Directors may also determine restrictions on the issuance of shares of the same series or of any other class or series, and the voting rights (if any) of the holders of the series. There were no outstanding shares of preferred stock or series common stock as of December 31, 2015.

Perpetual Preferred Stock

As discussed in Note 12. "Long-term Debt," the Company had $732.5 million aggregate principal amount of the Debentures outstanding as of December 31, 2015. Perpetual preferred stock issued upon a conversion of the Debentures will be fully paid and non-assessable, and holders will have no preemptive or preferential right to purchase any of the Company’s other securities. The perpetual preferred stock has a liquidation preference of $1,000 per share, is not convertible and is redeemable at the Company’s option at any time at a cash redemption price per share equal to the liquidation preference plus any accumulated dividends. Holders are entitled to receive cumulative dividends at an annual rate of 3.0875% if and when declared by the Company’s Board of Directors. If the Company fails to pay dividends on the perpetual preferred stock for five years, the Company generally must sell warrants or preferred stock with specified characteristics and use the funds from that sale to pay accumulated dividends after the payment in full of any deferred interest on the Debentures, subject to certain limitations. Additionally, holders of the perpetual preferred stock are entitled to elect two additional members to serve on the Company’s Board of Directors if (1) prior to any remarketing of the perpetual preferred stock, the Company fails to declare and pay dividends with respect to the perpetual preferred stock for 10 consecutive years or (2) after any successful remarketing or any final failed remarketing of the perpetual preferred stock, the Company fails to declare and pay six dividends thereon, whether or not consecutive. The perpetual preferred stock may be remarketed at the holder’s election after December 15, 2046 or earlier, upon the first occurrence of a change of control if the Company does not redeem the perpetual preferred stock. There were no outstanding shares of perpetual preferred stock as of December 31, 2015.



Peabody Energy Corporation	2015 Form 10-K	F- 57

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Treasury Stock

Share repurchases. The Company has a share repurchase program for its common stock with an authorized amount of $1.0 billion in which repurchases may be made from time to time based on an evaluation of the Company’s outlook and general business conditions, as well as alternative investment and debt repayment options (Repurchase Program). The Repurchase Program does not have an expiration date and may be discontinued at any time. Through December 31, 2015, the Company had made total repurchases of 0.5 million shares at a cost of $299.6 million ($199.8 million in 2008 and $99.8 million in 2006), leaving $700.4 million available under the Repurchase Program. No share repurchases were made under the Repurchase Program during the years ended December 31, 2015, 2014 and 2013.

Shares relinquished. The Company routinely allows employees to relinquish common stock to pay estimated taxes upon the payout of performance units that are settled in common stock and the vesting of restricted stock. The number of shares of common stock relinquished was less than 0.1 million for the years ended December 31, 2015, 2014 and 2013, respectively. The value of the common stock tendered by employees was based upon the closing price on the dates of the respective transactions.


(18)	Share-Based Compensation

In 2015, the Company established the 2015 Long-Term Incentive Plan (the 2015 Plan) for employees and non-employee directors that allows for the issuance of share-based compensation in various forms including stock appreciation rights, restricted stock, performance awards, incentive stock options, nonqualified stock options, deferred stock units, restricted stock units and cash incentive awards. The 2015 Plan superseded the Company’s 2011 Long-term Equity Incentive Plan (the 2011 Plan). The 2015 Plan became effective on May 4, 2015, which was the date approval by the Company’s stockholders was obtained. Subsequent to May 4, 2015, the Company can only issue awards under the 2015 Plan. Awards previously issued under the 2011 Plan (or any other prior equity plan) will remain outstanding under their terms. Under the 2015 Plan, 1.2 million shares of the Company’s common stock were authorized for issuance. The pool of shares authorized for issuance is intended to be fungible. As a result, the number of shares available under the 2015 Plan is reduced by the number of shares underlying any stock appreciation right or stock option granted, and awards other than a stock option or stock appreciation right will reduce the number of shares available under the 2015 Plan by two shares. As of December 31, 2015, there are approximately 1.2 million shares of the Company’s common stock available for grant. The Company had two employee stock purchase plans, which provided for the purchase of up to 0.1 million shares of the Company’s common stock. Due to the low number of shares available for employee purchase, coupled with the Company’s low stock price, both employee stock purchase plans terminated in October 2015.

Share-Based Compensation Expense and Cash Flows

The Company’s share-based compensation expense is recorded in “Selling and administrative expenses” in the consolidated statements of operations. Cash received by the Company upon the exercise of stock options and when employees purchase stock under the employee stock purchase plans is reflected as a financing activity in the consolidated statements of cash flows. Share-based compensation expense and cash flow amounts were as follows:



	Year Ended December 31,
	2015		2014			2013
	(Dollars in millions)
Share-based compensation expense - equity classified awards	$	26.2	$	46.1		$	50.9
Share-based compensation expense - liability classified awards	2.0		0.7			—
Total share-based compensation expense	28.2		46.8			50.9
Tax benefit	10.4		17.3			18.8
Share-based compensation expense, net of tax benefit	17.8		29.5			32.1
Cash received upon the exercise of stock options and from employee stock purchases	3.4		5.5			7.3
Write-off tax benefits related to share-based compensation	—		(8.3		)	(4.5		)

As of December 31, 2015, the total unrecognized compensation cost related to nonvested awards was $17.2 million, net of taxes, which is expected to be recognized over three years with a weighted-average period of 0.7 years.



Peabody Energy Corporation	2015 Form 10-K	F- 58

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Deferred Stock Units

In 2015, 2014 and 2013, the Company granted deferred stock units to each of its non-employee directors. The fair value of these units is equal to the market price of the Company’s common stock at the date of grant. These deferred stock units generally vest after one year and are settled in common stock on the specified distribution date elected by each non-employee director. Non-employee directors are also given the option to receive their total annual cash retainer in the form of additional deferred stock units (based on the fair market value of the Company's common stock on the date of grant). The additional grant of deferred stock units is subject to the same grant timing, vesting and distribution date elections as the annual equity compensation grant.

Restricted Stock Awards

The primary share-based compensation tool used by the Company for its employees is awards of restricted stock. The majority of restricted stock awards are granted in January of each year, with a lesser portion granted in the first month of the subsequent three quarters. Awards generally cliff vest after three years of service and only contain a service condition, with compensation cost recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. For awards with service and performance conditions, the Company recognizes compensation cost using the graded-vesting method, net of estimated forfeitures. The fair value of restricted stock is equal to the market price of the Company’s common stock at the date of grant.

A summary of restricted stock award activity is as follows:



	Year Ended December 31, 2015		Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2014	212,506		$	384.45
Granted	234,651		110.81
Vested	(81,453	)	438.22
Forfeited	(58,773	)	162.25
Nonvested at December 31, 2015	306,931		$	184.09

The total fair value at grant date of restricted stock awards granted during the years ended December 31, 2015, 2014 and 2013, was $26.0 million, $25.5 million and $29.2 million, respectively. The total fair value of restricted stock awards vested during the years ended December 31, 2015, 2014 and 2013, was $35.7 million, $24.5 million and $13.2 million, respectively.

Restricted Stock Units

In 2013, the Company began granting restricted stock units to certain senior management and non-senior management employees. One of the restricted stock unit grants contained market conditions valued utilizing a Monte Carlo simulation model and was made as an inducement award for a certain senior management employee. The Monte Carlo simulation model incorporated the total stockholder return hurdles set for each grant and included the following assumptions: risk free interest rate of 1.7%; expected volatility of 48.1% and dividend yield of 1.6%. The Company grants restricted stock units to non-senior management employees who either met the Company's retirement eligibility guidelines or would meet the guidelines during the vesting period of the award. For units granted to both senior and non-senior management employees containing only service conditions, the fair value of the award is equal to the market price of the Company’s common stock at the date of grant. Units granted to non-senior management retirement-eligible employees vest quarterly. Units granted to senior management employees vest at various times (none of which exceed five years) in accordance with the underlying award agreement. Compensation cost for both senior and non-senior management employees is recognized on a straight-line basis over the requisite service period. The payouts for active grants awarded in 2014 and 2013 will be settled in the Company's common stock. All awards granted in 2015 will be settled in the Company's common stock with the exception of a grant awarded in 2015 to a member of senior management which will be settled in cash instead of the Company's common stock.



Peabody Energy Corporation	2015 Form 10-K	F- 59

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of restricted stock unit activity is as follows:



	Year Ended December 31, 2015		Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2014	33,140		$	291.60
Granted	47,752		114.49
Vested	(10,435	)	199.27
Forfeited	(21,677	)	179.68
Nonvested at December 31, 2015	48,780		$	170.42

The total fair value at grant date of restricted stock units granted during the years ended December 31, 2015, 2014 and 2013 was $5.5 million, $4.2 million and $7.6 million, respectively. The total fair value of restricted stock units vested was $2.1 million during the year ended December 31, 2015 and less than $0.1 million during each of the years ended December 31, 2014 and 2013.

Stock Options

The Company’s stock option awards have been primarily limited to senior management personnel. All stock options are granted at an exercise price equal to the market price of the Company’s common stock at the date of grant. Stock options generally vest in one-third increments over a period of three years or cliff vest after three years, and expire after 10 years from the date of grant. Expense is recognized ratably over the service period, net of estimated forfeitures. Option grants are typically made in January of each year or upon hire for eligible plan participants. The payouts for active grants awarded in 2014 and 2013 will be settled in the Company's common stock. All awards granted in 2015 will be settled in the Company's common stock with the exception of a grant awarded in 2015 to a certain senior management employee which will be settled in cash instead of the Company's common stock.

The Company used the Black-Scholes option pricing model to determine the fair value of stock options. The Company utilized U.S. Treasury yields as of the grant date for its risk-free interest rate assumption, matching the U.S. Treasury yield terms to the expected life of the option. The Company utilized historical company data to develop its dividend yield, expected volatility and expected option life assumptions.

A summary of outstanding option activity under the plans is as follows:



	Year Ended December 31, 2015		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value (in millions)
Options Outstanding at December 31, 2014	201,067		$	473.55	6.39	$	—
Granted	85,263		116.10
Forfeited	(45,902	)	284.45
Options Outstanding at December 31, 2015	240,428		$	388.16	6.28	$	—
Vested and Exercisable	131,722		$	541.09	4.50	$	—



Peabody Energy Corporation	2015 Form 10-K	F- 60

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

There were no stock options exercised during the year ended December 31, 2015. During the years ended December 31, 2014 and 2013, the total intrinsic value of options exercised, defined as the excess fair value of the underlying stock over the exercise price of the options, was $0.4 million and $0.9 million, respectively. The weighted-average fair values of the Company’s stock options and the assumptions used in applying the Black-Scholes option pricing model were as follows:



	Year Ended December 31,
	2015			2014			2013
Weighted-average fair value	$	43.66		$	110.70		$	181.95
Risk-free interest rate	1.7		%	1.7		%	0.7		%
Expected option life	5 years			5 years			5 years
Expected volatility	45.2		%	48.4		%	64.1		%
Dividend yield	2.4		%	1.7		%	1.2		%

Performance Units

Performance units are typically granted annually in January and vest over a three-year measurement period and are primarily limited to senior management personnel. The performance units are usually subject to the achievement of goals based on the following conditions or any combination thereof: three-year stock price performance compared to both an industry peer group and a S&P index (market condition) and/or three-year return on capital or mining asset targets (performance condition). Generally, three performance unit grants are outstanding for any given year. The payouts for active grants awarded in 2013 will be settled in the Company’s common stock. All awards granted in 2014 will be settled in the Company's common stock with the exception of a grant awarded in 2014 to a certain senior management employee, which was later modified to be settled in cash instead of the Company's common stock. At the date of the modification, the Company reclassified the award from an equity award to a liability award. There was no incremental cost recognized since the fair value of the modified liability award at the modification date was less than the grant-date fair value of the original equity award. To the extent that the fair value of the modified liability award may exceed the recognized compensation cost associated with the grant-date fair value of the original equity award in the future, changes in the liability award's fair value will be recognized as compensation cost prospectively. Awards granted in 2015 to certain senior management employees will be settled in cash. All other awards granted in 2015 will be settled in the Company's common stock.

A summary of performance unit activity is as follows:



	Year Ended December 31, 2015		Weighted Average Remaining Contractual Life
Nonvested at December 31, 2014	50,011		1.5
Granted	72,215
Forfeited	(22,889	)
Vested	(17,525	)
Nonvested at December 31, 2015	81,812		1.7

As of December 31, 2015, there were 17,525 performance units vested that had an aggregate intrinsic value of less than $0.1 million and a conversion price per share of $8.50.

The performance condition awards were valued utilizing the grant date fair values of the Company’s stock adjusted for dividends foregone during the vesting period. The market condition awards were valued utilizing a Monte Carlo simulation model which incorporates the total stockholder return hurdles set for each grant. The assumptions used in the valuations for grants were as follows:



	Year Ended December 31,
	2015		2014		2013
Risk-free interest rate	1.1	%	0.8	%	0.4	%
Expected volatility	45.0	%	45.3	%	47.3	%
Dividend yield	2.4	%	1.7	%	1.4	%



Peabody Energy Corporation	2015 Form 10-K	F- 61

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Employee Stock Purchase Plans

Prior to October 2015, the Company’s eligible full-time and part-time employees were able to contribute up to 15% of their base compensation into the employee stock purchase plans, subject to an annual limit of $25,000 per person. Employees were able to purchase Company common stock at a 15% discount to the lower of the fair market value of the Company’s common stock on the initial or final trading dates of each six-month offering period. Offering periods began on January 1 and July 1 of each year. The Company used the Black-Scholes option pricing model to determine the fair value of employee stock purchase plan share-based payments. The fair value of the six-month “look-back” option in the Company’s employee stock purchase plans was estimated by adding the fair value of 0.15 of one share of stock to the fair value of 0.85 of an option on one share of stock. The Company utilized U.S. Treasury yields as of the grant date for its risk-free interest rate assumption, matching the Treasury yield terms to the six-month offering period. The Company utilized historical company data to develop its dividend yield and expected volatility assumptions. The plans were terminated in October 2015.

Shares purchased under the plans were less than 0.1 million for each of the years ended December 31, 2015, 2014 and 2013.


(19)	Accumulated Other Comprehensive Income (Loss)

The following table sets forth the after-tax components of comprehensive income (loss):



	Foreign Currency Translation Adjustment			Net Actuarial Loss Associated with Postretirement Plans and Workers’ Compensation Obligations			Prior Service Cost Associated with Postretirement Plans			Cash Flow Hedges			Available-For-Sale Securities			Total Accumulated Other Comprehensive Income (Loss)
	(Dollars in millions)
December 31, 2012	$	22.2		$	(411.7	)	$	12.7		$	387.5		$	0.3		$	11.0
Net change in fair value	—			—			—			(333.6		)	(12.3		)	(345.9		)
Reclassification from other comprehensive income to earnings	—			95.0			0.7			(209.6		)	12.8			(101.1		)
Current period change	(92.7		)	110.9			(1.4		)	—			—			16.8
December 31, 2013	(70.5		)	(205.8		)	12.0			(155.7		)	0.8			(419.2		)
Net change in fair value	—			—			—			(195.0		)	(3.7		)	(198.7		)
Reclassification from other comprehensive income to earnings	—			31.0			1.7			(10.2		)	2.9			25.4
Current period change	(41.0		)	(142.7		)	11.4			—			—			(172.3		)
December 31, 2014	(111.5		)	(317.5		)	25.1			(360.9		)	—			(764.8		)
Net change in fair value	—			—			—			(131.3		)	—			(131.3		)
Reclassification from other comprehensive income to earnings	—			35.6			(3.7		)	251.7			—			283.6
Current period change	(34.9		)	18.1			10.4			—			—			(6.4		)
December 31, 2015	$	(146.4	)	$	(263.8	)	$	31.8		$	(240.5	)	$	—		$	(618.9	)



Peabody Energy Corporation	2015 Form 10-K	F- 62

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table provides additional information regarding items reclassified out of "Accumulated other comprehensive loss" into earnings during the year ended December 31, 2015:



	Year Ended December 31, 2015			Year Ended December 31, 2014
Details about accumulated other comprehensive (loss) income components	Amount reclassified from accumulated other comprehensive (loss) income ⁽¹⁾			Amount reclassified from accumulated other comprehensive (loss) income ⁽¹⁾			Affected line item in the consolidated statement of operations
	(Dollars in millions)			(Dollars in millions)
Net actuarial loss associated with postretirement plans and workers' compensation obligations:
Postretirement health care and life insurance benefits	$	(24.9	)	$	(14.5	)	Operating costs and expenses
Defined benefit pension plans	(32.9		)	(24.8		)	Operating costs and expenses
Defined benefit pension plans	—			(8.7		)	Restructuring and pension settlement charges
Defined benefit pension plans	(6.7		)	(5.4		)	Selling and administrative expenses
Insignificant items	8.0			4.1
	(56.5		)	(49.3		)	Total before income taxes
	20.9			18.3			Income tax benefit
	$	(35.6	)	$	(31.0	)	Total after income taxes

Prior service credit (cost) associated with postretirement plans:
Postretirement health care and life insurance benefits	$	6.8		$	(1.3	)	Operating costs and expenses
Defined benefit pension plans	(1.0		)	(1.3		)	Operating costs and expenses
	5.8			(2.6		)	Total before income taxes
	(2.1		)	0.9			Income tax benefit
	$	3.7		$	(1.7	)	Total after income taxes

Cash flow hedges:
Foreign currency forward contracts	$	(316.4	)	$	(27.3	)	Operating costs and expenses
Fuel and explosives commodity swaps	(120.4		)	(22.3		)	Operating costs and expenses
Coal trading commodity futures, swaps and options	51.8			63.9			Other revenues
Insignificant items	(0.7		)	(0.4		)
	(385.7		)	13.9			Total before income taxes
	134.0			(3.7		)	Income tax provision
	$	(251.7	)	$	10.2		Total after income taxes

Available-for-sale securities:
Debt securities	$	—		$	—		Interest income
Equity securities	—			(4.7		)	Asset impairment and mine closure costs
	—			(4.7		)	Total before income taxes
	—			1.8			Income tax benefit
	$	—		$	(2.9	)	Total after income taxes

⁽¹⁾ Presented as gains (losses) in the consolidated statements of operations.



Peabody Energy Corporation	2015 Form 10-K	F- 63

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Comprehensive (loss) income differs from net loss by the amount of unrealized gain or loss resulting from valuation changes of the Company’s cash flow hedges (see Note 6. "Derivatives and Fair Value Measurements" and Note 7. "Coal Trading" for information related to the Company’s cash flow hedges), changes in the fair value of available-for-sale securities (see Note 5. "Investments" for information related to the Company's investments in available-for-sale securities), the change in actuarial loss and prior service cost of postretirement plans and workers' compensation obligations (see Note 15. "Postretirement Health Care and Life Insurance Benefits," Note 16. "Pension and Savings Plans" and Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation" for information related to the Company's postretirement and pension plans) and foreign currency translation adjustment related to the Company's investments in Middlemount, whose functional currency is the Australian dollar. The values of the Company’s cash flow hedging instruments are primarily affected by the U.S. dollar/Australian dollar exchange rate and changes in the prices of certain coal and diesel fuel products.


(20)	Resource Management, Acquisitions and Other Commercial Events

Organizational Realignment

In 2015, the Company has eliminated corporate and regional staff positions in the U.S. and implemented workforce reductions of employee and contractor positions at multiple mines in Australia. Included in the Company's consolidated statements of operations for the year ended December 31, 2015 were aggregate restructuring charges of $23.5 million, primarily comprised of cash severance costs. Of that amount, $3.0 million remained accrued as of December 31, 2015.

Coal Supply Agreement

During April 2014, the Company finalized pricing under a sales agreement for one of its Western U.S. Mining segment customers. As a result of that agreement, the Company recognized additional contract revenue and sales-related expenses totaling $33.5 million and $6.4 million, respectively, during the year ended December 31, 2014 and will continue to realize higher prices for coal supplied pursuant to that agreement.

Divestitures

The Company initiated a review of its asset portfolio during the second quarter of 2015. In connection with that review and related marketing and divestiture approval processes conducted during the period, certain assets were classified as held-for-sale. Subsequent to the related write-downs, these assets had an aggregate carrying value of approximately $125 million and were included in "Other current assets" in the Company's consolidated balance sheet as of December 31, 2015. The results of operations and cash flows of such assets were not material to the consolidated financial statements for the periods presented in this report.

In January 2016, the Company entered into a definitive agreement to sell its 5.06 percent participation 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 condition and expiration of certain purchase rights, with the closing expected to occur in the second quarter of 2016.

In November 2015, the Company entered into a definitive agreement to sell its El Segundo and Lee Ranch mines in New Mexico and its Twentymile Mine in Colorado to Bowie Resource Partners, LLC in exchange for cash proceeds of $358 million and the assumption of approximately $105 million in related liabilities. The transaction is scheduled to be completed during the first quarter of 2016. The mines were not classified as discontinued operations in the accompanying consolidated financial statements due to the level of uncertainty associated with completing the transaction at December 31, 2015.

In January 2014, the Company sold a non-strategic exploration tenement asset in Australia in exchange for cash proceeds of $62.6 million. The Company had previously recorded an impairment charge in December 2013 to write down the carrying value of that asset to its fair value as discussed in Note 2. "Asset Impairment." Accordingly, there was no gain or loss recognized on the disposal during the year ended December 31, 2015.

In December 2014, the Company sold non-strategic coal reserves located in Kentucky in exchange for cash proceeds of $29.6 million. The company recognized a gain on sale of $13.6 million related to the transaction, which was classified in "Net gain on disposal or exchange of assets" in the consolidated statement of operations for the year ended December 31, 2014.



Peabody Energy Corporation	2015 Form 10-K	F- 64

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Joint Venture

In 2014, the Company agreed to establish an unincorporated joint venture project with Glencore plc (Glencore), in which each party will hold a 50% interest, to combine the existing operations of the Company's Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore's United Mine. The Company expects the project to result in several operation synergies, including improved mining productivity, lower per-unit operating costs and an extended mine life. The joint venture operations are expected to commence in 2017, subject to substantive contingencies, including the requisite regulatory and permitting approvals. At such time as those contingencies have been resolved or are no longer considered to be substantive, the Company will account for its beneficial interest in the combined operations at fair value.


(21)	Earnings per Share (EPS)

Basic and diluted EPS are computed using the two-class method, which is an earnings allocation that determines EPS for each class of common stock and participating securities according to dividends declared and participation rights in undistributed earnings. The Company’s restricted stock awards are considered participating securities because holders are entitled to receive non-forfeitable dividends during the vesting term. Diluted EPS includes securities that could potentially dilute basic EPS during a reporting period, for which the Company includes the Debentures and share-based compensation awards. Dilutive securities are not included in the computation of loss per share when a company reports a net loss from continuing operations as the impact would be anti-dilutive.

For all but the performance units, the potentially dilutive impact of the Company’s share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. For the Company’s performance units, their contingent features result in an assessment for any potentially dilutive common stock by using the end of the reporting period as if it were the end of the contingency period for all units granted. For further discussion of the Company’s share-based compensation awards, see Note 18. "Share-Based Compensation."

A conversion of the Debentures may result in payment for any conversion value in excess of the principal amount of the Debentures in the Company’s common stock. For diluted EPS purposes, potential common stock is calculated based on whether the market price of the Company’s common stock at the end of each reporting period is in excess of the conversion price of the Debentures. For a full discussion of the conditions under which the Debentures may be converted, the conversion rate to common stock and the conversion price, see Note 12. "Long-term Debt." The effect of the Debentures was excluded from the calculation of diluted EPS for all periods presented herein because to do so would have been anti-dilutive for those periods.

The computation of diluted EPS also excluded aggregate share-based compensation awards of approximately 0.6 million for the year ended December 31, 2015 and 0.2 million for the years ended December 31, 2014 and 2013, respectively, because to do so would have been anti-dilutive for those periods. Because the potential dilutive impact of such share-based compensation awards is calculated under the treasury stock method, anti-dilution generally occurs when the exercise prices or unrecognized compensation cost per share of such awards are higher than the Company’s average stock price during the applicable period.



Peabody Energy Corporation	2015 Form 10-K	F- 65

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS. The number of shares and per share amounts for all period presented below have been retroactively restated to reflect the Reverse Stock Split discussed in Note 1. "Summary of Significant Accounting Policies.":



	Year Ended December 31,
	2015			2014			2013
	(In millions, except per share amounts)
EPS numerator:
Loss from continuing operations, net of income taxes	$	(1,813.9	)	$	(749.1	)	$	(286.0	)
Less: Net income attributable to noncontrolling interests	7.1			9.7			12.3
Loss from continuing operations attributable to common stockholders, before allocation of earnings to participating securities	(1,821.0		)	(758.8		)	(298.3		)
Less: Earnings allocated to participating securities	—			1.0			0.8
Loss from continuing operations attributable to common stockholders, after allocation of earnings to participating securities	(1,821.0		)	(759.8		)	(299.1		)
Loss from discontinued operations attributable to common stockholders, after allocation of earnings to participating securities	(175.0		)	(28.2		)	(226.6		)
Net loss attributable to common stockholders, after earnings allocated to participating securities	$	(1,996.0	)	$	(788.0	)	$	(525.7	)
EPS denominator:
Weighted average shares outstanding — basic and diluted	18.1			17.9			17.8
Basic and diluted EPS attributable to common stockholders:
Loss from continuing operations	$	(100.34	)	$	(42.52	)	$	(16.80	)
Loss from discontinued operations	(9.64		)	(1.57		)	(12.73		)
Net loss attributable to common stockholders	$	(109.98	)	$	(44.09	)	$	(29.53	)

(22) Management — Labor Relations

On December 31, 2015, the Company had approximately 7,600 employees worldwide, including approximately 5,700 hourly employees; the employee amounts exclude employees that were employed at operations classified as discontinued operations. Approximately 37% of those hourly employees were represented by organized labor unions and were employed by mines that generated 20% of the Company's 2015 coal production from continuing operations. In the U.S., one surface mine is represented by an organized labor union. In Australia, the coal mining industry is unionized and the majority of hourly workers employed at the Company’s Australian Mining operations are members of trade unions. The Construction Forestry Mining and Energy Union generally represents the Company’s Australian subsidiaries’ hourly production and engineering employees, including those employed through contract mining relationships. The Company believes labor relations with its employees are good. Should that condition change, the Company could experience labor disputes, work stoppages or other disruptions in production that could negatively impact the Company’s results of operations and cash flows.



Peabody Energy Corporation	2015 Form 10-K	F- 66

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the Company's active mining operations as of December 31, 2015 in which the employees are represented by organized labor unions:



Mine		Current Agreement Expiration Date

U. S.
Kayenta ⁽¹⁾		September 2019

Australia
Owner-operated mines:
Wambo Open-Cut		December 2018
North Wambo Underground ⁽²⁾		April 2016
North Goonyella		December 2018
Metropolitan ⁽³⁾		August 2015
Millennium ⁽³⁾		October 2015
Wilpinjong		May 2016
Coppabella ⁽⁴⁾		October 2016
Moorvale ⁽⁴⁾		June 2017

Contractor-operated mines:
Burton		December 2016


⁽¹⁾	Hourly workers at the Company’s Kayenta Mine in Arizona are represented by the UMWA under the Western Surface Agreement, which is effective through September 16, 2019. This agreement covers approximately 8% of the Company’s U.S. subsidiaries’ hourly employees, who generated approximately 4% of the Company’s U.S. production during the year ended December 31, 2015.


⁽²⁾	Employees of the Company's North Wambo Underground Mine also operate under a separate enterprise agreement. That agreement expired in April 2015 and negotiations are underway. The parties agreed to a rollover for 12 months through April 2016. There have been no disruptions to the operations of the plant as a result of the expiration of the agreement.


⁽³⁾	Negotiations for the Metropolitan and Millennium mines are underway or have been scheduled and the mines continue to operate. Hourly employees of these mines comprise approximately 28% of the Company's Australian subsidiaries hourly employees, who generated approximately 19% of the Company's Australian production during the year ended December 31, 2015.


⁽⁴⁾	Employees of the Company's Coppabella/Moorvale Coal Handling and Preparation Plant facility also operate under a separate enterprise agreement. That agreement expired in March 2014. After negotiations, the Company's final offer was rejected by employees. The Company applied to terminate the employment agreement with a hearing set in early 2016.


(23)	Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees

In the normal course of business, the Company is a party to guarantees and financial instruments with off-balance-sheet risk, most of which are not reflected in the accompanying consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and the likelihood of required performance. As of March 15, 2016, management does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in the consolidated balance sheet as of December 31, 2015.



Peabody Energy Corporation	2015 Form 10-K	F- 67

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Financial Instruments with Off-Balance Sheet Risk

As of December 31, 2015, the Company had the following financial instruments with off-balance-sheet risk:



	Reclamation Obligations		Coal Lease Obligations		Workers’ Compensation Obligations		Other⁽¹⁾		Total		Letters of Credit in Support of Financial Instruments
	(Dollars in millions)
Self bonding	$	1,430.8	$	—	$	—	$	—	$	1,430.8	$	—
Surety bonds ⁽²⁾	293.2		110.5		19.1		14.9		437.7		75.6
Bank guarantees	299.1		—		—		102.6		401.7		353.6
Other letters of credit	—		—		55.9		150.4		206.3		—
Total	$	2,023.1	$	110.5	$	75.0	$	267.9	$	2,476.5	$	429.2


⁽¹⁾	Other includes the $79.7 million in letters of credit related to Dominion Terminal Associates and the PBGC, as described below, and an additional $188.2 million in bank guarantees, letters of credit and surety bonds related to road maintenance, performance guarantees and other operations.


⁽²⁾	A total of $75.9 million of letters of credit issued as collateral to support surety bonds related to Patriot have been excluded from above as they no longer represent off-balance sheet obligations as discussed in Note 25. "Matters Related to the Bankruptcy of Patriot Coal Corporation".

The Company owns a 37.5% interest in Dominion Terminal Associates, a partnership that operates a coal export terminal in Newport News, Virginia under a 30-year lease that permits the partnership to purchase the terminal at the end of the lease term for a nominal amount. The partners have severally (but not jointly) agreed to make payments under various agreements which in the aggregate provide the partnership with sufficient funds to pay rents and to cover the principal and interest payments on the floating-rate industrial revenue bonds issued by the Peninsula Ports Authority which become due in 2016, and which are supported by letters of credit from a commercial bank. As of December 31, 2015, the Company’s maximum reimbursement obligation to the commercial bank was in turn supported by four letters of credit totaling $42.7 million.

The Company is party to an agreement with the PBGC and TXU Europe Limited, an affiliate of the Company’s former parent corporation, under which the Company is required to make special contributions to two of the Company’s defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If the Company or the PBGC gives notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if the Company fails to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guarantee in place from TXU Europe Limited in favor of the PBGC before it draws on the Company’s letter of credit. On November 19, 2002, TXU Europe Limited was placed under the administration process in the U.K. (a process similar to bankruptcy proceedings in the U.S.) and continues under this process as of December 31, 2015. As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.

Accounts Receivable Securitization

The Company has an accounts receivable securitization program (securitization program) with a maximum capacity of $275.0 million through its wholly-owned, bankruptcy-remote subsidiary (Seller). At December 31, 2015, the Company had no remaining capacity available under the securitization program. Under the securitization program, the Company contributes trade receivables of most of the Company's U.S. subsidiaries on a revolving basis to the Seller, which then sells the receivables in their entirety to a consortium of unaffiliated asset-backed commercial paper conduits and banks (the Conduits). After the sale, the Company, as servicer of the assets, collects the receivables on behalf of the Conduits for a nominal servicing fee. The Company utilizes proceeds from the sale of its accounts receivable as an alternative to short-term borrowings under the 2013 Revolver portion of the Company’s 2013 Credit Facility, effectively managing its overall borrowing costs and providing an additional source of working capital. The securitization program will expire in April 2016. The Company has started the process of renewing the program.



Peabody Energy Corporation	2015 Form 10-K	F- 68

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Seller is a separate legal entity whose assets are available first and foremost to satisfy the claims of its creditors. Of the receivables sold to the Conduits, a portion of the amount due to the Seller is deferred until the ultimate collection of the underlying receivables. During the year ended December 31, 2015, the Company received total consideration of $3,703.2 million related to accounts receivable sold under the securitization program, including $2,595.1 million of cash up front from the sale of the receivables, an additional $1,096.4 million of cash upon the collection of the underlying receivables and $11.7 million that had not been collected at December 31, 2015 and was recorded at carrying value, which approximates fair value. The reduction in accounts receivable as a result of securitization activity with the Conduits was $168.5 million and $30.0 million at December 31, 2015 and 2014, respectively.

The securitization activity has been reflected in the consolidated statements of cash flows as an operating activity because both the cash received from the Conduits upon sale of receivables as well as the cash received from the Conduits upon the ultimate collection of receivables are not subject to significantly different risks given the short-term nature of the Company’s trade receivables. The Company recorded expense associated with securitization transactions of $1.8 million, $1.5 million and $1.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Other

Included in "Other noncurrent liabilities" in the Company's consolidated balance sheets as of December 31, 2015 and 2014 is a liability of $38.4 million and $44.7 million, respectively, related to reclamation, bonding commitments and worker's compensation provided on behalf of a third-party coal producer associated with a 2007 purchase of coal reserves and surface lands in the Illinois Basin.

The Company is the lessee under numerous equipment and property leases. It is common in such commercial lease transactions for the Company, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property, if any, would be covered by insurance (subject to deductibles). The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under various lease obligations. Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments, and the Company assumes that no amounts could be recovered from third parties.

The Company has provided financial guarantees under certain long-term debt agreements entered into by its subsidiaries and substantially all of the Company’s U.S. subsidiaries provide financial guarantees under long-term debt agreements entered into by the Company. The maximum amounts payable under the Company’s debt agreements are equal to the respective principal and interest payments.


(24)	Commitments and Contingencies

Commitments

Unconditional Purchase Obligations

As of December 31, 2015, purchase commitments for capital expenditures were $20.0 million, all of which is obligated within the next year. In Australia, the Company has generally secured the ability to transport coal through rail contracts and ownership interests in five east coast coal export terminals that are primarily funded through take-or-pay arrangements with terms ranging up to 27 years. In the U.S., the Company has entered into certain long-term coal export terminal agreements to secure export capacity through the Gulf Coast. As of December 31, 2015, these Australian and U.S. commitments under take-or-pay arrangements totaled $2,236.0 million, of which $301.3 million is obligated within the next year. Subsequent to December 31, 2015, the Company amended certain contracts to reduce U.S. transportation and logistics costs. In connection with these amendments, the Company will realize a net reduction of approximately $45 million in estimated liquidated damage payments that otherwise would have become due with respect to these take-or-pay arrangements in 2017.

Federal Coal Leases

In the second quarter of 2012, the Company was named by the U.S. Department of the Interior, Bureau of Land Management (BLM) as the winning bidder for control of approximately 1.1 billion tons of federal coal reserves adjacent to its North Antelope Rochelle Mine in the Southern Powder River Basin of Wyoming, with a weighted average bid price of approximately $1.10 per mineable ton. Consequently, the Company made aggregate payments of $247.9 million during each of the years ended December 31, 2015, 2014 and 2013 pursuant to the two associated federal coal leases, with one remaining annual payment of $247.9 million due in 2016.



Peabody Energy Corporation	2015 Form 10-K	F- 69

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In July 2011, the Company was named by the BLM as the winning bidder for control of approximately 220 million tons of federal coal reserves adjacent to its Caballo Mine in the Powder River Basin at a bid price of $0.95 per mineable ton, with payments of $42.1 million due annually in each of the years from 2011 through 2015 pursuant to the associated federal coal lease (the Belle Ayr North Lease). Similarly, in September 2011, a subsidiary of Alpha Natural Resources, Inc. (Alpha) was named by the BLM as the winning bidder for control of approximately 130 million tons of federal coal reserves in the Powder River Basin at a bid price of $1.10 per mineable ton, with contractual payments of $28.6 million due annually in each of the years from 2011 through 2015 under the associated federal coal lease (the Caballo West Lease). In July 2012, the Company and Alpha executed a lease exchange agreement with the BLM whereby the Company agreed to sell, assign and transfer its interest in the Belle Ayr North Lease in exchange for (1) Alpha's interest in the Caballo West Lease, (2) reimbursement of $13.5 million for the difference in the related federal coal lease payments made by each party in 2011 and (3) five annual true up payments of $3.9 million for the excess of the $1.10 bid price per mineable ton assumed under the Caballo West Lease over the $0.95 price under the transferred lease. The Company received true up payments during each of the years ended December 31, 2014 and 2013. Those cash receipts are classified in "Proceeds from disposal of assets, net of notes receivable" in the consolidated statement of cash flows. During 2015, Alpha filed voluntary petitions for reorganization under Chapter 11 of the U.S. Code and no true up payment was received.

The federal coal leases executed with the BLM described above expire after a 20-year initial term, unless at such time there is ongoing production on the subject leases or within an active logical mining unit of which they are part.

Contingencies

From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities. The Company discusses its significant legal proceedings below, including ongoing proceedings and those that impacted the Company's results of operations for the periods presented.

Litigation Relating to Continuing Operations

Peabody Monto Coal Pty Ltd, Monto Coal 2 Pty Ltd and Peabody Energy Australia PCI Pty Ltd (PEA-PCI). In October 2007, a statement of claim was delivered to Peabody Monto Coal Pty Ltd, a wholly-owned subsidiary of PEA-PCI, then Macarthur Coal Limited, and Monto Coal 2 Pty Ltd, an equity accounted investee, from the minority interest holders in the Monto Coal Joint Venture, alleging that Monto Coal 2 Pty Ltd breached the Monto Coal Joint Venture Agreement and Peabody Monto Coal Pty Ltd breached the Monto Coal Management Agreement. Peabody Monto Coal Pty Ltd is the manager of the Monto Coal Joint Venture pursuant to the Management Agreement. Monto Coal 2 Pty Ltd holds a 51% interest in the Monto Coal Joint Venture. The plaintiffs are Sanrus Pty Ltd, Edge Developments Pty Ltd and H&J Enterprises (Qld) Pty Ltd. An additional statement of claim was delivered to PEA-PCI in November 2010 from the same minority interest holders in the Monto Coal Joint Venture, alleging that PEA-PCI induced Monto Coal 2 Pty Ltd and Peabody Monto Coal Pty Ltd to breach the Monto Coal Joint Venture Agreement and the Monto Coal Management Agreement, respectively. The plaintiffs later amended their claim to allege damages for lost opportunities to sell their joint venture interest. These actions, which are pending before the Supreme Court of Queensland, Australia, seek damages from the three defendants collectively of amounts ranging from $15.6 million Australian dollars to $1.8 billion Australian dollars, plus interest and costs. The defendants dispute the claims and are vigorously defending their positions. Based on the Company's evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated.

Sumiseki Materials Co. Ltd. In 2010, Sumiseki Materials Co. Ltd. (Sumiseki), the Class B shareholder (noncontrolling interest holder) in Wambo Coal Pty Ltd (Wambo), an Australian subsidiary of the Company, filed a lawsuit against Wambo in the Supreme Court of New South Wales, Australia, alleging that it was entitled to certain dividends from Wambo (subject to limited exceptions) and requested payment of those dividends for periods from 2009 to 2012. In March 2013, the Supreme Court ruled Sumiseki was entitled to the disputed dividends (subject to limited exceptions). In May 2013, the Supreme Court issued finalized orders, which included the amounts due for the disputed dividends including interest. Wambo appealed the Supreme Court's decision to the New South Wales Court of Appeal and obtained a stay of the Supreme Court judgment. In accordance with the terms of the stay, Wambo posted security with the court in an interest-bearing trust account jointly operated by the parties.

On September 17, 2014, the Court of Appeal upheld the Supreme Court's ruling (with a minor exception), finding Sumiseki was entitled to the disputed dividends plus interest and costs. In its ruling, the Court of Appeal noted that while payment of dividends is usually a matter for a company's directors, the Class B dividend is a mandatory dividend, regardless of any decision by the directors, and that the amount of the dividend is based on a percentage of the company's net profit, unless there is a legal prohibition that precludes the dividend being paid. Wambo filed an application for leave to appeal the ruling to the High Court of Australia, but the application was denied. Wambo has satisfied the terms of the Court of Appeal’s judgment, including the remittance of the restricted security previously posted with the court, and the litigation is over.



Peabody Energy Corporation	2015 Form 10-K	F- 70

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Eagle Mining, LLC Arbitration. On May 3, 2013, Eagle Mining, LLC (Eagle) filed an arbitration demand against a Company subsidiary under a contract mining agreement, asserting various claims for damages. An arbitration hearing was held in January 2014 before a single arbitrator. As a result of the damages awarded to Eagle in arbitration, the Company recorded a charge of $15.6 million in "Operating costs and expenses" in the consolidated statement of operations for the year ended December 31, 2014 to increase the associated liability accrual to $23.4 million. On April 18, 2014, the Company subsidiary filed a petition to partially vacate and modify the arbitration award in the United States District Court for the Southern District of West Virginia, Charleston Division. On July 29, 2015, the District Court issued a Memorandum Opinion and Order denying the petition to partially vacate and modify the arbitration award and granting Eagle’s motion to confirm the arbitration award.

In September 2015, Eagle and the Company's subsidiary settled all claims and agreed to dismiss with prejudice all pending litigation between the parties. In connection with this settlement, the Company recorded a gain totaling $10.8 million during the year ended December 31, 2015 to reduce the accrued liability to the amount paid. The matter has concluded.

Queensland Bulk Handling Pty Ltd. On June 30, 2014, QBH filed a statement of claim with the Supreme Court of Queensland, Australia, against Peabody (Wilkie Creek) Pty Limited, an indirect wholly-owned subsidiary of the Company, alleging breach of a CPSA between the parties. QBH originally sought damages of $113.1 million Australian dollars, plus interest and costs. However, it later altered its claim to seek a declaration that the Company subsidiary had exercised an option to renew the contract for a further term, and withdrew its claim for money damages.

On February 27, 2015, the Supreme Court of Queensland, Australia ruled that QBH and the Company subsidiary were bound to enter into a new CPSA upon substantially the same terms as the 2009 CPSA, within 30 days of July 8, 2013. Under the 2009 CPSA, QBH provided services to Peabody (Wilkie Creek) Pty Limited for operations at the Wilkie Creek Mine, which was closed in 2013. The term of the potential new CPSA would commence January 1, 2015 and expire on December 31, 2026 and, assuming substantially the same contractual terms, would require annual minimum payments of approximately $11.8 million Australian dollars. The Company subsidiary appealed this ruling, which was heard by the Court of Appeal on July 30, 2015. On October 23, 2015, the appellate court upheld this ruling and dismissed the appeal. The Company subsidiary was ordered to pay QBH’s costs of the appeal. On December 8, 2015, QBH filed a claim in the Supreme Court of Queensland, Australia seeking specific performance of the Company subsidiary’s obligation to enter into a new CPSA as described above and payment of $11.8 million Australian dollars representing amounts invoiced by QBH from January through November 2015, plus additional amounts for interest and attorney fees. On January 29, 2016, the Company subsidiary filed a defense to these claims. On February 15, 2016, QBH filed an application for summary judgment, which QBH subsequently agreed to adjourn to a date to be fixed, seeking an order requiring the Company subsidiary to execute a new CPSA and seeking additional amounts invoiced by QBH through February 2016, plus additional interest on these amounts and attorney fees. On February 29, 2016 QBH filed an amended statement claim. The Company subsidiary is due to file a defense to the amended statement of claim by March 22, 2016. In February 2016, QBH served costs statements on the Company subsidiary for attorneys' fees for the appeal and trial and the Company subsidiary is in the process of objecting to the amount of those costs.

While the ultimate impact of the litigation is subject to a wide range of uncertainty, the Company recognized a charge of $9.7 million to discontinued operations for year ended December 31, 2015. That amount represents the low end of the range of loss that the Company considers probable. It is reasonably possible that additional exposure may exist up to and including the aggregate annual minimum payments under the potential new CPSA noted above.

Lori J. Lynn Class Action. On June 11, 2015, a former Peabody Investments Corp. (PIC) employee filed a putative class action lawsuit in the United States District Court, Eastern District of Missouri on behalf of three of the Company’s or its subsidiaries' 401(k) retirement plans and certain participants and beneficiaries of the plans. The lawsuit, which was brought against the Company, Peabody Holding Company, LLC (PHC), PIC and a number of the Company’s and PIC’s current and former executives and employees, alleges breach of fiduciary duties under the Employee Retirement Income Security Act of 1974 (ERISA) relating to the offering of the Peabody Energy Stock Fund as an investment option in the 401(k) retirement plans.

On September 8, 2015, the plaintiffs filed an amended complaint which, among other things, named a new plaintiff and named all of the current members and two former members of the board as defendants. The class period (December 2012 to present) remains unchanged. On November 9, 2015, the defendants filed a motion seeking dismissal of all claims.



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PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On January 14, 2016, the plaintiffs filed a motion requesting leave to file a second amended complaint, which seeks to name the boards of directors of PIC and PHC as defendants and include new allegations against the Company related to the Company’s disclosure to investors of risks associated with climate change and related legislation and regulations. The Company agreed not to oppose the plaintiff's motion on the condition that the plaintiffs dismiss the Company's independent directors from the lawsuit. The defendants dispute the allegations of the lawsuit and plan to vigorously defend their positions. Based on current information the Company believes these claims are likely to be finalized without a material adverse effect of its financial condition, results of operations or cash flows.

Contract Pricing Arbitration. In December 2014, the Company resolved an arbitration process with one of its U.S. customers related to the negotiated price of coal delivered pursuant to a long-term coal supply agreement. During the year ended December 31, 2014, the Company shipped 4.8 million tons subject to that agreement. In connection with the settlement, the Company agreed to provide the customer with a pricing rebate of $68.7 million, which represents a portion of the total amount that was invoiced and collected upon in 2014 based on contract prices in effect in 2013. The Company decreased revenue recognized for the year ended December 31, 2014 by the rebate amount and recorded a corresponding liability, which will be ratably relieved through credits against future customer billings through 2017.

Gulf Power Company. On June 22, 2006, Gulf Power Company (Gulf Power) filed a breach of contract lawsuit against a Company subsidiary in the U.S. District Court, Northern District of Florida, contesting the force majeure declaration by the Company's subsidiary under a coal supply agreement with Gulf Power and seeking damages for alleged past and future tonnage shortfalls of nearly five million tons under the agreement, which expired in 2007. After the proceedings, the District Court awarded Gulf Power damages of $20.6 million for its 2007 cover coal purchases and prejudgment interest of $6.9 million plus post-judgment interest. The Company's subsidiary and Gulf Power both appealed and, in June 2013, the U.S. Court of Appeals for the Eleventh Circuit issued its order affirming the District Court's judgment in all respects. The Company subsidiary and Gulf Power agreed not to seek judicial review of the Eleventh Circuit's order, and the Company subsidiary paid the judgment during the third quarter of 2013. In connection with the order, the Company recorded a charge for the judgment amount of $20.6 million in "Operating costs and expenses" and $6.9 million in "Interest expense" in the consolidated statements of operations for the year ended December 31, 2013.

Claims, Litigation and Settlements Relating to Indemnities or Historical Operations

Environmental Claims and Litigation Arising From Historical, Non-Coal Producing Operations. Gold Fields Mining, LLC (Gold Fields) is a dormant, non-coal producing entity that was previously managed and owned by Hanson plc, the Company's predecessor owner. In a February 1997 spin-off, Hanson plc transferred ownership of Gold Fields to the Company despite the fact that Gold Fields had no ongoing operations and the Company had no prior involvement in its past operations. Gold Fields is currently one of the Company's subsidiaries. The Company indemnified TXU Group with respect to certain claims relating to the historical operations of a former affiliate of Gold Fields.

Environmental claims for remediation, past costs, future costs, and/or natural resource damages have been asserted against Gold Fields related to historical activities of Gold Fields or a former affiliate. Gold Fields or the former affiliate has been named a potentially responsible party (PRP) at six national priority list sites based on the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The most recent addition occurred in December 2015, when Gold Fields was named a PRP by the US EPA at a site near Galena, Illinois. CERCLA claims were asserted at 13 additional sites, bringing the total to 19, which have since been reduced to seven by completion of work, settlement, transfer or regulatory inactivity. The number of CERCLA sites alone is not a relevant measure of liability because the nature and extent of environmental concerns and costs varies by site, as does the estimated share of responsibility relative to other PRPs for Gold Fields or the former affiliate.

Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above were $66.9 million as of December 31, 2015 and $69.4 million as of December 31, 2014, of which $23.9 million and $19.4 million was reflected as a current liability, respectively, in the consolidated balance sheets as of those dates. These amounts represent those costs that the Company believes are probable and reasonably estimable.

Significant uncertainty exists as to whether claims will be pursued against Gold Fields or the former affiliate in all cases, and where they are pursued, the amount and timing of the eventual costs and liabilities, which could be greater or less than the liabilities recorded in the consolidated balance sheets. Changes to cost estimates associated with a particular site can occur for many reasons, including, but not limited to, the gathering of additional information at the site, the completion of the remedial design phase of the CERCLA remediation process, changes in anticipated remediation standards or labor and material costs or the reaching of a settlement agreement or consent order by the parties at the site. Based on the Company's evaluation of the issues and their potential impact, the total amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes these claims are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.



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PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other

In June 2007, the NYAG served a letter and subpoena on the Company, seeking information and documents relating to the Company's disclosure to investors of risks associated with possible climate change and related legislation and regulations. The Company believes it has made full and proper disclosure of these potential risks. In late 2013, the NYAG submitted a letter to the Company requesting additional information and documents. On November 8, 2015, the NYAG and the Company entered into an agreement pursuant to which the Company agreed to make certain disclosures concerning the issues raised by the NYAG.

In January 2013, the Securities and Exchange Commission (SEC) staff served a subpoena on the Company seeking information and documents relating to the development of Prairie State Energy Campus, a 1,600 megawatt coal-fueled electricity generation plant and adjacent coal mine in Illinois in which the Company owns a 5.06% undivided interest. The Company cooperated with the SEC's investigation and has not received any related communication from the SEC since August 2013. The Company will cooperate with the SEC, to the extent is requests any additional information in the future and will provide updated with respect to this matter as appropriate.

At times the Company becomes a party to other disputes, including those related to contract miner performance, claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where the Company does business. Based on current information, the Company believes that such other pending or threatened proceedings are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.


(25)	Matters Related to the Bankruptcy of Patriot Coal Corporation

In 2012, Patriot filed voluntary petitions for relief under Chapter 11 of Title 11 of the U.S. Code. In 2013, the Company entered into a definitive settlement agreement (2013 Agreement) with Patriot and the UMWA, on behalf of itself, its represented Patriot employees and its represented Patriot retirees, to resolve all then disputed issues related to Patriot’s bankruptcy. In May 2015, Patriot again filed voluntary petitions for relief under Chapter 11 of Title 11 of the U.S. Code in the Eastern District of Virginia and subsequently initiated a process to sell some or all of their assets to qualified bidders. On October 9, 2015, Patriot's bankruptcy court entered an order confirming Patriot's plan of reorganization, which provides, among other things, for the sale of substantially all of Patriot's assets to two different buyers.

Credit Support

As part of the 2013 Agreement, the Company has provided $121.5 million of credit support to Patriot, with $81.0 million in the form of surety bonds issued for the benefit of Patriot beneficiaries; $22.4 million in the form of letters of credit issued for the benefit of Patriot beneficiaries; and $18.1 million in the form of corporate guarantees to Patriot beneficiaries. Those surety bonds, corporate guarantees and letters of credit are excluded in the financial instruments with off-balance sheet risk table presented in Note 23. " Financial Instruments, Guarantees with Off-Balance Sheet Risk and Other Guarantees". A total of $35.3 million of the credit support relates to certain of Patriot’s Coal Act obligations that a subsidiary of the Company agreed to fund at the time of the Patriot spin-off pursuant to the Coal Act Liabilities Assumption Agreement. During the year ended December 31, 2015, the Company assumed $8.5 million of underlying liabilities for which credit support was previously provided and $29.9 million of cash drawdowns were made by the beneficiaries of the financial instruments, leaving $83.1 million remaining as a liability on our condensed consolidated balance sheet as of December 31, 2015.

Due to Patriot’s May 2015 bankruptcy filing, the Company recorded a net charge of $34.7 million to increase its liability related to the credit support to the estimated fair value of the portion of the credit support exposed to nonperformance by Patriot. That net charge included a $16.6 million correction of an error reflected in the year ended December 31, 2015 to derecognize a liability that had been previously recorded to the Company’s historical financial statements in 2014 and 2013. The Company reflected the correction as an out-of-period adjustment because it considers the impact of the error to be immaterial quantitatively and qualitatively to the total mix of information available in the Company’s 2015 and historical financial statements.

Black Lung Occupational Disease Liabilities

Patriot had federal and state black lung occupational disease liabilities related to workers employed in periods prior to Patriot’s spin-off from the Company in 2007. Upon spin-off, Patriot indemnified the Company against any claim relating to these liabilities, which amounted to approximately $150 million at that time. The indemnification included any claim made by the U.S. Department of Labor (DOL) against the Company with respect to these obligations as a potentially liable operator under the Federal Coal Mine Health and Safety Act of 1969. The definitive settlement agreement reached in 2013 included Patriot’s affirmance of all indemnities provided in the spin-off agreements, including the indemnity relating to such black lung liabilities.



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PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

By statute, the Company remains secondarily liable for the black lung liabilities related to Patriot’s workers employed by former subsidiaries of the Company. Whether the Company will ultimately be required to fund certain of those obligations in the future as a result of Patriot’s May 2015 bankruptcy remains uncertain. The Company does believe that it is probable that it will be required to fund a portion of these obligations in the future and recorded a charge to "Loss from discontinued operations, net of income taxes" of $114.4 million, net of $15.0 million previously accrued credit support related to Patriot's federal black lung obligations, during the year ended December 31, 2015. The liability recorded for black lung occupational disease liability is based on information provided by Patriot which the Company continues to evaluate. As a result of the complexity of this estimate and the limited amount of time the Company has had to evaluate the underlying data, this estimate may change in future periods. The amount of the Company's recorded liability reflects only Patriot workers employed by former subsidiaries of the Company that are presently retired, disabled or otherwise not actively employed, which the Company believes reflects the low end of the range of potential loss. The Company cannot reliably estimate the potential liabilities for Patriot's workers employed by former subsidiaries of the Company that are presently active in the workforce because of the potential for such workers to continue to work for another coal operator that is a going concern. The Company estimates that the annual cash cost to fund these potential Black Lung liabilities will range between $10 million and $15 million.

Combined Benefit Fund (Combined Fund)

The Combined Fund was created by the Coal Act in 1992 as a multi-employer plan to provide health care benefits to a closed group of retirees who last worked prior to 1976, as well as orphaned beneficiaries of bankrupt companies who were receiving benefits as orphans prior to the passage of the Coal Act. No new retirees will be added to this group, which includes retirees formerly employed by certain Patriot subsidiaries and their predecessors. Former employers are required to contribute to the Combined Fund according to a formula.

Under the terms of the Patriot spin-off, Patriot was primarily liable for the obligations of its subsidiaries to the Combined Fund, which obligations were actuarially estimated to be approximately $40 million at that time. Once Patriot ceased meeting its obligations, the Company was held responsible for these costs and, as a result, recorded a "Loss from discontinued operations, net of income taxes" charge of $24.6 million during the year ended December 31, 2015. The Company estimates that the annual cash cost to fund these potential Combined Fund liabilities will range between $2 million and $3 million in the near-term, with those premiums expected to decline over time because the fund is closed to new participants.

VEBA Payments

In connection with the 2013 agreement, the Company was required to provide total payments of $310.0 million, payable over four years through 2017, to partially fund the newly established voluntary employee beneficiary association (VEBA) and settle all Patriot and UMWA claims involving the Patriot bankruptcy. Those payments included an initial payment of $90.0 million made in January 2014, comprised of $70.0 million paid to Patriot and $20.0 million paid to the VEBA, and a payment of $75.0 million made in January 2015 to the VEBA. The 2013 Agreement also contemplated subsequent payments to be made to the VEBA of $75.0 million in 2016 and $70.0 million in 2017.

As a result of Patriot’s failure to reimburse the Company for the draws on the credit support that the Company provided under the 2013 Settlement Agreement, Patriot materially breached the 2013 Agreement. The Company and the UMWA disagreed about the impact that Patriot's breaches had on the Company's future obligations under the 2013 Settlement Agreement, including the payment of the two remaining VEBA payments. Accordingly, on August 28, 2015, the Company sought to-reopen Patriot’s first bankruptcy cases that were pending in the United States Bankruptcy Court for the Eastern District of Missouri (Missouri Bankruptcy Court) for the limited purpose of having the Missouri Bankruptcy Court decide this issue. The Missouri Bankruptcy Court granted the Company’s motion, and the Company filed in the Missouri Bankruptcy Court a declaratory judgment action against the UMWA seeking a declaration that the Company’s obligations to make the final two VEBA payments were excused as a result of Patriot’s breaches of the 2013 Agreement (Missouri Declaratory Judgment Action). Patriot's appeal of the Missouri Bankruptcy Court's order was dismissed on October 26, 2015.

On October 16, 2015 the UMWA filed a motion to withdraw the reference with respect to the Missouri Declaratory Judgment Action to the United States District Court for the Eastern District of Missouri (Withdrawal Motion), with the stated intent of thereafter seeking a transfer of the case ultimately to the United States Bankruptcy Court for the Eastern District of Virginia (Virginia Bankruptcy Court) where Patriot’s second bankruptcy cases are pending. On October 23, 2015, the Company filed an objection to this motion. The UMWA subsequently filed a notice of settlement and withdrawal of the Withdrawal Motion with the United States District Court for the Eastern District of Missouri.



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PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On October 19, 2015, Patriot and the UMWA filed a declaratory judgment action in the Virginia Bankruptcy Court (Virginia Declaratory Judgment Action) against the Company and one of its subsidiaries seeking, among other things, a declaration that the Company must make the remaining two VEBA payments notwithstanding Patriot’s breach of the 2013 Agreement. On November 3, 2015, Patriot and the UMWA filed a motion for a preliminary and permanent injunction to prevent the Company from proceeding with the Missouri Declaratory Judgment Action (Injunction Motion). On November 4, 2015, the Company filed a motion to dismiss the Virginia Declaratory Judgment Action for lack of subject matter jurisdiction or, in the alternative, to transfer it to the Missouri Bankruptcy Court. On December 2, 2015, the Virginia Bankruptcy Court denied the Injunction Motion and deferred ruling on the Company's motion to dismiss the Virginia Declaratory Judgment Action.

The parties agreed to a settlement of the Company’s obligations for payment of the remaining VEBA payments, which was approved by the Missouri Bankruptcy Court on January 5, 2016 and the Virginia Bankruptcy Court on January 6, 2016. Under this settlement, the Company agreed to pay $75 million to the VEBA, payable in equal monthly installments of $7.5 million beginning on January 4, 2016. The remaining monthly installments will be made at the beginning of each successive month ending October 2016. These monthly VEBA payments will terminate early if VEBA participants can receive healthcare benefits that are reasonably similar to or greater than healthcare benefits provided under VEBA as a result of new legislation.

Retiree Health Care Obligations for Certain Salaried Patriot Personnel

In connection with the 2007 spin-off of Patriot from the Company, the Company and one of its subsidiaries entered into a Salaried Employee Liabilities Assumption Agreement (“SELAA”) pursuant to which its subsidiary agreed fund the healthcare benefits that Patriot was obligated to provide for a group of Patriot’s salaried retirees and accounts for the related liabilities within continuing operations. On October 9, 2015, Patriot’s bankruptcy court entered an order approving a stipulation and settlement among the Company and its subsidiary, Patriot and its affiliates and the Official Committee of Retirees in Patriot’s second chapter 11 cases (on behalf of itself and the retirees that it represented), pursuant to which, among other things, (i) the SELAA terminated as of October 31, 2015; (ii) the Company and its subsidiary agreed to pay a total of $16.1 million in five annual installments to a VEBA to be established by the Official Committee of Retirees; (iii) the Company agreed to pay $100,000 to the VEBA for its start-up and administrative costs; and (iv) the parties exchanged mutual releases. The Company reduced its obligations to match the payments to the VEBA, with the difference accounted for as negative plan amendment and the corresponding prior service credit to be amortized over the same four-year period the payments to the VEBA will occur.

UMWA 1974 Pension Plan (Plan) Litigation

On July 16, 2015, a lawsuit was filed by the Plan, the UMWA 1974 Pension Trust (Trust) and the Trustees of the Plan and Trust (Trustees) in the United States District Court for the District of Columbia, against the Company, PHC, a subsidiary of the Company, and Arch Coal, Inc. (Arch). The plaintiffs are seeking, pursuant to ERISA and the Multiemployer Pension Plan Amendments Act of 1980 (MPPAA), a declaratory judgment that the defendants are obligated to arbitrate any opposition to the Trustees’ determination that the defendants have statutory withdrawal liability as a result of the 2015 Patriot bankruptcy. The plaintiffs' July lawsuit claimed that the defendants' withdrawal liability will result in at least $767 million owed to the Plan. On October 29, 2015, the plaintiffs filed an amended complaint, alleging that the plaintiffs had determined that Peabody has $644.2 million and Arch has $299.8 million in withdrawal liabilities to the 1974 Pension Plan.

Also on October 29, 2015, the Trustees issued a withdrawal liability assessment against the Company in the amount of $644.2 million (“October 29 Assessment”). The Trustees claim that a principal purpose of the Company’s 2007 spin-off of Patriot was to “evade or avoid” withdrawal liability to the Plan, and they assert that the Company is therefore liable for Patriot's withdrawal from the Plan due to Patriot terminating certain collective bargaining agreements with the UMWA eight years later, during its current bankruptcy proceeding. The October 29 Assessment does not contain the payment schedule required by ERISA. Instead, the Trustees assert that the Company was in default on the $644.2 million liability assessment as of the moment it was assessed. The Company and PHC dispute this withdrawal liability claim -- including the notion that the Company could be in default on the withdrawal liability assessment prior to being given an opportunity to make any payments on the assessment -- and are vigorously defending their positions.



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PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

ERISA provides a process to adjudicate withdrawal liability disputes, which consists of administrative review by the Plan followed by arbitration, after which either side can appeal to the appropriate United States district court. The Company and PHC have been dismissed from the lawsuit and have agreed with the plaintiffs to arbitrate the dispute pursuant to the arbitration process. Because more than five years have elapsed since the spin-off, the Company is exempt from making any payments toward the October 29 Assessment unless and until an arbitrator issues a final decision in favor of the Trustees on the "evade or avoid" theory of liability. The Company also anticipates that during arbitration it will receive a decision on the legality of the Fund's determination that the Company was in default. The Company anticipates that as a consequence of such decision, the Fund will be required to issue a payment schedule setting forth the annual payments required to pay the alleged withdrawal liability over time. On January 26, 2016, the Company took the first step of the adjudication process by requesting administrative review of the October 29 Assessment. If the Fund fails to respond to the Company’s request for review within 120 days, or if the Company disagrees with the results of the Fund’s review, then the Company will initiate arbitration. If the proceeding is ongoing in January 2017, the Company will be required to post a bond or an escrow of approximately $18.8 million until the decision is final. The bond would remain in place until an arbitration decision is reached on the underlying withdrawal liability issue. If it is decided in the Company's favor, the Company will not owe any amounts to the Plan.


(26)	Summary of Quarterly Financial Information (Unaudited)

A summary of the unaudited quarterly results of operations for the years ended December 31, 2015 and 2014 is presented below.



	Year Ended December 31, 2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(In millions, except per share data)
Revenues	$	1,537.9		$	1,339.3		$	1,418.9		$	1,313.1
Operating profit (loss)	2.2			(975.8		)	(20.4		)	(470.8		)
Loss from continuing operations, net of income taxes	(164.4		)	(1,007.2		)	(144.4		)	(497.9		)
Net loss	(173.3		)	(1,043.5		)	(301.9		)	(470.2		)
Net loss attributable to common stockholders	(176.6		)	(1,045.3		)	(304.7		)	(469.4		)
Basic and diluted EPS — continuing operations⁽¹⁾	$	(9.31	)	$	(55.59	)	$	(8.08	)	$	(27.28	)
Weighted average shares used in calculating basic and diluted EPS	18.0			18.2			18.2			18.2


⁽¹⁾	EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis.

Operating loss for the fourth quarter of 2015 reflected $377.0 million of asset impairment costs. Operating loss for the second quarter of 2015 included $900.8 million of asset impairment costs and $21.2 million of restructuring and pension settlement charges. Loss from continuing operations for the first and second quarter of 2015 included losses on early debt extinguishment of $59.5 million and $8.3 million, respectively. Loss from continuing operations, net of income taxes for the first, third, and fourth quarters of 2015 included benefits (expenses) related to the remeasurement of foreign income tax accounts of $0.2 million, $0.8 million and $(0.5) million, respectively. Loss from continuing operations, net of income taxes, for the second quarter and fourth quarter of 2015 included a tax benefit related to asset impairment of $67.4 million and $7.9 million, respectively. Loss from continuing operations, net of income taxes, for the fourth quarter of 2015 included an increase in valuation allowance on certain U.S. deferred tax assets of $177.0 million. Loss from discontinued operations, net of income taxes, for the third quarter of 2015 included $155.1 million of Patriot bankruptcy related charges associated with black lung liabilities and the UMWA Combined Benefit Fund. Loss from discontinued operations, net of income taxes, for the second quarter of 2015 reflected a $34.7 million charge, net of taxes, related to adverse changes in the fair value of credit support provided to Patriot. Loss from discontinued operations for the first quarter of 2015 included a contingent loss accrual of $7.6 million associated with the QBH litigation.



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PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Year Ended December 31, 2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(In millions, except per share data)
Revenues	$	1,626.8		$	1,758.0		$	1,722.9		$	1,684.5
Operating profit (loss)	2.9			32.8			36.2			(207.0		)
Loss from continuing operations, net of income taxes	(44.3		)	(72.0		)	(154.0		)	(478.8		)
Net loss	(44.1		)	(71.2		)	(149.0		)	(513.0		)
Net loss attributable to common stockholders	(48.5		)	(73.3		)	(150.6		)	(514.6		)
Basic and diluted EPS — continuing operations⁽¹⁾	$	(2.74	)	$	(4.16	)	$	(8.72	)	$	(26.88	)
Weighted average shares used in calculating basic and diluted EPS	17.9			17.9			17.9			17.9


⁽¹⁾	EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis.

Revenues for the second quarter of 2014 included $43.2 million of additional contract revenue, resulting from finalized pricing under a customer sales agreement. Operating loss for the fourth quarter of 2014 reflected $154.4 million of asset impairment costs. Operating loss for the fourth quarter of 2014 also included $26.0 million of restructuring and pension settlement charges and a deferred tax asset valuation allowance charge related to an equity affiliate of $52.3 million. Operating profit for the first quarter of 2014 included a charge of $15.6 million related to an adverse judgment in an arbitration proceeding. Loss from continuing operations for the third quarter of 2014 reflected $10.6 million of interest charges related to litigation. Loss from continuing operations for the second quarter of 2014 included $1.6 million of third-party fees related to the debentures consent solicitation. Loss from continuing operations, net of income taxes for the first, second, third and fourth quarters of 2014 included benefits (expenses) related to the remeasurement of foreign income tax accounts of $1.4 million, $1.3 million, $1.2 million and $(1.2) million, respectively. Loss from continuing operations, net of income taxes for the third quarter of 2014 reflected a $70.1 million write-off of a net deferred tax asset due to the repeal of the Australian Minerals and Resource Rent Tax in that period (which included $54.0 million of royalty allowance credits recognized during the first half of 2014). Loss from continuing operations, net of income taxes for the first, second, third and fourth quarters of 2014 also reflected respective increases in valuation allowance on certain Australian deferred tax assets of $42.6 million, $75.7 million, $80.6 million and $90.4 million. Loss from continuing operations, net of income taxes, for the fourth quarter of 2014 included an increase in valuation allowance on certain U.S. deferred tax assets of $280.1 million. Loss from discontinued operations, net of income taxes, for the fourth quarter of 2014 reflected a $34.1 million charge, net of tax, related to an adverse change in the fair value of credit support provided to Patriot.


(27)	Segment and Geographic Information

During the second quarter of 2015, the Company elected a new chief executive officer, who is also considered the Company's chief operating decision maker (CODM). Due to that change, the Company updated its reportable segments to reflect the manner in which its new CODM views the Company's businesses for purposes of reviewing performance, allocating resources and assessing future prospects and strategic execution. The Company now reports its results of operations primarily through the following reportable segments: "Powder River Basin Mining," “Midwestern U.S. Mining," “Western U.S. Mining,” “Australian Metallurgical Mining," "Australian Thermal Mining," “Trading and Brokerage” and “Corporate and Other.” Periods presented in this note have been recast for comparability.

The principal business of the Company's mining segments in the U.S. is the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S. under long-term contracts, with a portion sold into the seaborne markets as market conditions warrant. The Company's Powder River Basin Mining operations consist of its mines in Wyoming. The mines in that segment are characterized by surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). The Company's Midwestern U.S. Mining operations reflect the Company’s Illinois and Indiana mining operations, which are characterized by a mix of surface and underground mining extraction processes, coal with a higher sulfur content and Btu and lower customer transportation costs (due to shorter shipping distances). The Company's Western U.S. Mining operations reflect the aggregation of the New Mexico, Arizona and Colorado mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes, coal with a lower sulfur content and Btu and generally higher customer transportation costs (due to longer shipping distances). Geologically, the Company's Powder River Basin Mining operations mine sub-bituminous coal deposits, its Midwestern U.S. Mining operations mine bituminous coal deposits and its Western operations mine both bituminous and sub-bituminous coal deposits.



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PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The business of the Company's Australian operating platform is primarily export focused with customers spread across several countries, while a portion of the coal is sold within Australia. Generally, revenues from individual countries vary year by year based on electricity demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. The Company’s Australian Metallurgical Mining operations consist of mines in Queensland and New South Wales, Australia. The mines in that segment are characterized by both surface and underground extraction processes used to mine various qualities of metallurgical coal (low-sulfur, high Btu coal). The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coal and pulverized coal injection coal. The Company's Australian Thermal Mining operations predominantly consist of mines in New South Wales, Australia. The mines in that segment are characterized by both surface and underground extraction processes used to mine low-sulfur, high Btu thermal coal. The Company classifies its Australian mines within the Australian Metallurgical Mining or Australian Thermal Mining segments based on the primary customer base and coal reserve type of each mining operation. A small portion of the coal mined by the Australian Metallurgical Mining segment is of a thermal grade. Similarly, a small portion of the coal mined by the Australian Thermal Mining segment is of a metallurgical grade. Additionally, the Company may market some of its metallurgical coal products as a thermal coal product from time to time depending on market conditions.

The Company's Trading and Brokerage segment engages in the direct and brokered trading of coal and freight-related contracts through the 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 the Company's 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 the Company's coal trading strategy.

The Company's 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 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.

The Company’s CODM uses Adjusted EBITDA as the primary metric to measure the segments' operating performance. Adjusted EBITDA is defined as (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense, depreciation, depletion and amortization, asset impairment and mine closure costs, charges for the settlement of claims and litigation related to previously divested operations and changes in deferred tax asset valuation allowance and amortization of basis difference related to equity affiliates. Adjusted EBITDA is not intended to serve as an alternative to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.

Segment results for the year ended December 31, 2015 were as follows:



	Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Australian Metallurgical Mining			Australian Thermal Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	1,865.9	$	981.2	$	682.3	$	1,181.9		$	823.5	$	42.8	$	31.6		$	5,609.2
Adjusted EBITDA	482.9		269.7		184.6		(18.2		)	193.6		27.0		(705.0		)	434.6
Additions to property, plant, equipment and mine development	15.0		51.3		19.3		25.5			13.6		—		2.1			126.8
Federal coal lease expenditures	276.9		—		0.3		—			—		—		—			277.2
Loss from equity affiliates	—		—		—		—			—		—		15.9			15.9



Peabody Energy Corporation	2015 Form 10-K	F- 78

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Segment results for the year ended December 31, 2014 were as follows:



	Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Australian Metallurgical Mining			Australian Thermal Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	1,922.9	$	1,198.1	$	902.8	$	1,613.8		$	1,058.0	$	58.4	$	38.2		$	6,792.2
Adjusted EBITDA	509.0		306.9		266.9		(151.1		)	264.1		14.9		(396.7		)	814.0
Additions to property, plant, equipment and mine development	19.7		57.4		18.2		53.9			30.2		—		15.0			194.4
Federal coal lease expenditures	276.5		—		0.2		—			—		—		—			276.7
Loss from equity affiliates	—		—		—		—			—		—		107.6			107.6

Segment results for the year ended December 31, 2013 were as follows:



	Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Australian Metallurgical Mining			Australian Thermal Mining		Trading and Brokerage			Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	1,767.3	$	1,335.5	$	902.3	$	1,773.4		$	1,131.2	$	66.0		$	38.0		$	7,013.7
Adjusted EBITDA	435.4		426.0		258.0		(120.0		)	270.0		(19.9		)	(202.3		)	1,047.2
Additions to property, plant, equipment and mine development	15.8		27.2		32.2		165.7			64.6		0.1			22.8			328.4
Federal coal lease expenditures	276.5		—		0.3		—			—		—			—			276.8
Loss from equity affiliates	—		—		—		—			—		—			40.2			40.2



Peabody Energy Corporation	2015 Form 10-K	F- 79

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Asset details are reflected at the division level only for the Company's mining segments and are not allocated between each individual segment as such information is not regularly reviewed by the Company's CODM. Further, some assets service more than one segment within the division and an allocation of such assets would not be meaningful or representative on a segment by segment basis.

Assets as of December 31, 2015 were as follows:



	U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other		Consolidated
	(Dollars in millions)
Total assets	$	4,180.2	$	5,319.9	$	217.2	$	1,304.0	$	11,021.3
Property, plant, equipment and mine development, net	3,854.5		4,469.6		0.5		933.9		9,258.5

Assets as of December 31, 2014 were as follows:



	U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other		Consolidated
	(Dollars in millions)
Total assets	$	4,099.1	$	6,623.9	$	300.7	$	2,167.4	$	13,191.1
Property, plant, equipment and mine development, net	3,739.9		5,503.7		1.1		1,332.6		10,577.3

Assets as of December 31, 2013 were as follows:



	U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other		Consolidated
	(Dollars in millions)
Total assets	$	4,024.4	$	7,081.2	$	389.6	$	2,638.2	$	14,133.4
Property, plant, equipment and mine development, net	3,654.4		5,947.1		1.8		1,479.2		11,082.5

A reconciliation of Adjusted EBITDA to consolidated loss from continuing operations, net of income taxes follows:



	Year Ended December 31,
	2015			2014			2013
	(Dollars in millions)
Total Adjusted EBITDA	$	434.6		$	814.0		$	1,047.2
Depreciation, depletion and amortization	(572.2		)	(655.7		)	(740.3		)
Asset retirement obligation expenses	(45.5		)	(81.0		)	(66.5		)
Asset impairment	(1,277.8		)	(154.4		)	(528.3		)
Settlement charges related to the Patriot bankruptcy reorganization	—			—			(30.6		)
Change in deferred tax asset valuation allowance related to equity affiliates	1.0			(52.3		)	—
Amortization of basis difference related to equity affiliates	(4.9		)	(5.7		)	(6.3		)
Interest expense	(533.2		)	(428.2		)	(425.2		)
Interest income	7.7			15.4			15.7
Income tax benefit (provision)	176.4			(201.2		)	448.3
Loss from continuing operations, net of income taxes	$	(1,813.9	)	$	(749.1	)	$	(286.0	)



Peabody Energy Corporation	2015 Form 10-K	F- 80

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents revenues as a percent of total revenue from external customers by geographic region:



	Year Ended December 31,
	2015		2014		2013
U.S.	57.4	%	59.5	%	61.1	%
Japan	8.1	%	9.5	%	9.8	%
China	7.1	%	6.1	%	10.2	%
South Korea	4.1	%	5.2	%	3.8	%
Other	23.3	%	19.7	%	15.1	%
Total	100.0	%	100.0	%	100.0	%

The Company attributes revenue to individual countries based on the location of the physical delivery of the coal.


(28)	Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the Senior Notes, certain 100% owned U.S. subsidiaries of the Company (each, a Guarantor Subsidiary) have fully and unconditionally guaranteed the Senior Notes, on a joint and several basis. The indentures governing the Senior Notes contain customary exceptions under which a guarantee of a Guarantor Subsidiary will terminate, including (a) the release or discharge of the guarantee of the Company’s 2013 Credit Facility by such Guarantor Subsidiary, except a discharge or release by or as a result of payment under such guarantee, (b) a sale or other disposition, by way of merger, consolidation or otherwise, of all of the capital stock of such Guarantor Subsidiary, and (c) the legal defeasance or discharge of the indentures. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the holders of the Senior Notes. The following historical financial statement information is provided for the Guarantor/Non-Guarantor Subsidiaries.



Peabody Energy Corporation	2015 Form 10-K	F- 81

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS



	Year Ended December 31, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	3,443.0		$	2,215.3		$	(49.1	)	$	5,609.2
Costs and expenses
Operating costs and expenses (exclusive of items shown separately below)	436.6			2,618.4			2,001.8			(49.1		)	5,007.7
Depreciation, depletion and amortization	—			281.3			290.9			—			572.2
Asset retirement obligation expenses	—			17.2			28.3			—			45.5
Selling and administrative expenses	32.1			132.6			11.7			—			176.4
Restructuring and pension settlement charges	(3.9		)	11.4			16.0			—			23.5
Other operating (income) loss:
Net gain on disposal of assets	(2.3		)	(29.4		)	(13.3		)	—			(45.0		)
Asset impairment	—			308.6			969.2			—			1,277.8
Loss from equity affiliates and investment in subsidiaries	933.9			6.9			9.0			(933.9		)	15.9
Interest expense	468.4			8.7			24.7			(36.4		)	465.4
Loss on early debt extinguishment	67.8			—			—			—			67.8
Interest income	(14.0		)	(11.9		)	(18.2		)	36.4			(7.7		)
(Loss) income from continuing operations before income taxes	(1,918.6		)	99.2			(1,104.8		)	933.9			(1,990.3		)
Income tax (benefit) provision	(87.4		)	(108.2		)	19.2			—			(176.4		)
(Loss) income from continuing operations, net of income taxes	(1,831.2		)	207.4			(1,124.0		)	933.9			(1,813.9		)
(Loss) income from discontinued operations, net of income taxes	(164.8		)	1.6			(11.8		)	—			(175.0		)
Net (loss) income	(1,996.0		)	209.0			(1,135.8		)	933.9			(1,988.9		)
Less: Net income attributable to noncontrolling interests	—			—			7.1			—			7.1
Net (loss) income attributable to common stockholders	$	(1,996.0	)	$	209.0		$	(1,142.9	)	$	933.9		$	(1,996.0	)



Peabody Energy Corporation	2015 Form 10-K	F- 82

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS



	Year Ended December 31, 2014
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	3,964.8		$	2,902.1		$	(74.7	)	$	6,792.2
Costs and expenses
Operating costs and expenses (exclusive of items shown separately below)	49.6			2,927.3			2,814.7			(74.7		)	5,716.9
Depreciation, depletion and amortization	—			310.4			345.3			—			655.7
Asset retirement obligation expenses	—			25.3			55.7			—			81.0
Selling and administrative expenses	46.8			161.1			19.2			—			227.1
Restructuring and pension settlement charges	—			23.8			2.2			—			26.0
Other operating (income) loss:
Net gain on disposal of assets	—			(18.5		)	(22.9		)	—			(41.4		)
Asset impairment	4.7			71.1			78.6			—			154.4
Loss from equity affiliates and investment in subsidiaries	431.1			6.6			101.0			(431.1		)	107.6
Interest expense	423.1			6.4			34.6			(37.5		)	426.6
Loss on early debt extinguishment	1.6			—			—			—			1.6
Interest income	(15.3		)	(10.3		)	(27.3		)	37.5			(15.4		)
(Loss) income from continuing operations before income taxes	(941.6		)	461.6			(499.0		)	431.1			(547.9		)
Income tax (benefit) provision	(186.2		)	316.7			70.7			—			201.2
(Loss) income from continuing operations, net of income taxes	(755.4		)	144.9			(569.7		)	431.1			(749.1		)
(Loss) income from discontinued operations, net of income taxes	(31.6		)	(7.2		)	10.6			—			(28.2		)
Net (loss) income	(787.0		)	137.7			(559.1		)	431.1			(777.3		)
Less: Net income attributable to noncontrolling interests	—			—			9.7			—			9.7
Net (loss) income attributable to common stockholders	$	(787.0	)	$	137.7		$	(568.8	)	$	431.1		$	(787.0	)



Peabody Energy Corporation	2015 Form 10-K	F- 83

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS



	Year Ended December 31, 2013
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	4,027.9		$	3,230.3		$	(244.5	)	$	7,013.7
Costs and expenses
Operating costs and expenses (exclusive of items shown separately below)	(173.6		)	3,471.7			2,675.5			(244.5		)	5,729.1
Depreciation, depletion and amortization	—			329.4			410.9			—			740.3
Asset retirement obligation expenses	—			33.3			33.2			—			66.5
Selling and administrative expenses	50.9			167.9			25.4			—			244.2
Restructuring and pension settlement charges	—			11.9			—			—			11.9
Other operating (income) loss:
Net gain on disposal of assets	—			(52.6		)	—			—			(52.6		)
Asset impairment	21.5			6.5			500.3			—			528.3
Settlement charges related to the Patriot bankruptcy reorganization	30.6			—			—			—			30.6
Loss from equity affiliates and investment in subsidiaries	272.5			8.3			31.9			(272.5		)	40.2
Interest expense	403.9			244.5			169.0			(409.1		)	408.3
Loss on early debt extinguishment	16.9			—			—			—			16.9
(Gain) loss from extinguishment of affiliate debt	—			(155.5		)	155.5			—			—
Interest income	(79.6		)	(311.6		)	(33.6		)	409.1			(15.7		)
Unrealized loss (gain) on derivatives	—			34.0			(34.0		)	—			—
(Loss) income from continuing operations before income taxes	(543.1		)	240.1			(703.8		)	272.5			(734.3		)
Income tax benefit	(92.2		)	(110.9		)	(245.2		)	—			(448.3		)
(Loss) income from continuing operations, net of income taxes	(450.9		)	351.0			(458.6		)	272.5			(286.0		)
Loss from discontinued operations, net of income taxes	(74.0		)	(5.6		)	(147.0		)	—			(226.6		)
Net (loss) income	(524.9		)	345.4			(605.6		)	272.5			(512.6		)
Less: Net income attributable to noncontrolling interests	—			—			12.3			—			12.3
Net (loss) income attributable to common stockholders	$	(524.9	)	$	345.4		$	(617.9	)	$	272.5		$	(524.9	)



Peabody Energy Corporation	2015 Form 10-K	F- 84

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended December 31, 2015
	Parent Company			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(Dollars in millions)
Net (loss) income	$	(1,996.0	)	$	209.0	$	(1,135.8	)	$	933.9	$	(1,988.9	)
Other comprehensive income (loss), net of income taxes:
Net change in unrealized losses on available-for-sale securities (net of $0.1 tax benefit)	—			—		—			—		—
Net unrealized gains (losses) on cash flow hedges (net of $72.2 tax provision)
(Decrease) increase in fair value of cash flow hedges	(137.1		)	—		5.8			—		(131.3		)
Reclassification for realized losses (gains) included in net (loss) income	292.1			—		(40.4		)	—		251.7
Net unrealized gains (losses) on cash flow hedges	155.0			—		(34.6		)	—		120.4
Postretirement plans and workers' compensation obligations (net of $36.2 tax provision)
Prior service credit for the period	—			10.4		—			—		10.4
Net actuarial gain for the period	5.5			12.6		—			—		18.1
Amortization of actuarial loss (gain) and prior service cost included in net (loss) income	7.2			36.6		(11.9		)	—		31.9
Postretirement plans and workers' compensation obligations	12.7			59.6		(11.9		)	—		60.4
Foreign currency translation adjustment	—			—		(34.9		)	—		(34.9		)
Other comprehensive loss from investment in subsidiaries	(21.8		)	—		—			21.8		—
Other comprehensive income (loss), net of income taxes	145.9			59.6		(81.4		)	21.8		145.9
Comprehensive (loss) income	(1,850.1		)	268.6		(1,217.2		)	955.7		(1,843.0		)
Less: Comprehensive income attributable to noncontrolling interests	—			—		7.1			—		7.1
Comprehensive (loss) income attributable to common stockholders	$	(1,850.1	)	$	268.6	$	(1,224.3	)	$	955.7	$	(1,850.1	)



Peabody Energy Corporation	2015 Form 10-K	F- 85

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended December 31, 2014
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(Dollars in millions)
Net (loss) income	$	(787.0	)	$	137.7		$	(559.1	)	$	431.1	$	(777.3	)
Other comprehensive loss, net of income taxes:
Net change in unrealized losses on available-for-sale securities (net of $0.5 tax benefit)
Unrealized holding losses on available-for-sale securities	(3.7		)	—			—			—		(3.7		)
Reclassification for realized losses included in net (loss) income	2.9			—			—			—		2.9
Net change in unrealized losses on available-for-sale securities	(0.8		)	—			—			—		(0.8		)
Net unrealized losses on cash flow hedges (net of $54.6 tax benefit)
(Decrease) increase in fair value of cash flow hedges	(225.9		)	—			30.9			—		(195.0		)
Reclassification for realized losses (gains) included in net (loss) income	31.3			—			(41.5		)	—		(10.2		)
Net unrealized losses on cash flow hedges	(194.6		)	—			(10.6		)	—		(205.2		)
Postretirement plans and workers' compensation obligations (net of $10.3 tax benefit)
Prior service credit for the period	—			11.4			—			—		11.4
Net actuarial (loss) gain for the period	—			(150.2		)	7.5			—		(142.7		)
Amortization of actuarial loss (gain) and prior service cost included in net (loss) income	—			35.5			(2.8		)	—		32.7
Postretirement plans and workers' compensation obligations	—			(103.3		)	4.7			—		(98.6		)
Foreign currency translation adjustment	—			—			(41.0		)	—		(41.0		)
Other comprehensive loss from investment in subsidiaries	(150.2		)	—			—			150.2		—
Other comprehensive loss, net of income taxes	(345.6		)	(103.3		)	(46.9		)	150.2		(345.6		)
Comprehensive (loss) income	(1,132.6		)	34.4			(606.0		)	581.3		(1,122.9		)
Less: Comprehensive income attributable to noncontrolling interests	—			—			9.7			—		9.7
Comprehensive (loss) income attributable to common stockholders	$	(1,132.6	)	$	34.4		$	(615.7	)	$	581.3	$	(1,132.6	)



Peabody Energy Corporation	2015 Form 10-K	F- 86

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended December 31, 2013
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Net (loss) income	$	(524.9	)	$	345.4		$	(605.6	)	$	272.5		$	(512.6	)
Other comprehensive (loss) income, net of income taxes:
Net change in unrealized gains (losses) on available-for-sale securities (net of $0.5 tax provision)
Unrealized holding losses on available-for-sale securities	(12.2		)	—			(0.1		)	—			(12.3		)
Reclassification for realized losses (gains)included in net (loss) income	13.0			—			(0.2		)	—			12.8
Net change in unrealized gains (losses) on available-for-sale securities	0.8			—			(0.3		)	—			0.5
Net unrealized losses on cash flow hedges (net of $300.0 tax benefit)
(Decrease) increase in fair value of cash flow hedges	(368.4		)	—			34.8			—			(333.6		)
Reclassification for realized gains included in net (loss) income	(109.0		)	—			(100.6		)	—			(209.6		)
Net unrealized losses on cash flow hedges	(477.4		)	—			(65.8		)	—			(543.2		)
Postretirement plans and workers' compensation obligations (net of $121.7 tax provision)
Prior service cost for the period	—			(1.4		)	—			—			(1.4		)
Net actuarial gain for the period	—			103.8			7.1			—			110.9
Amortization of actuarial loss (gain) and prior service cost included in net (loss) income	—			95.8			(0.1		)	—			95.7
Postretirement plans and workers' compensation obligations	—			198.2			7.0			—			205.2
Foreign currency translation adjustment	—			—			(92.7		)	—			(92.7		)
Other comprehensive income from investment in subsidiaries	46.4			—			—			(46.4		)	—
Other comprehensive (loss) income, net of income taxes	(430.2		)	198.2			(151.8		)	(46.4		)	(430.2		)
Comprehensive (loss) income	(955.1		)	543.6			(757.4		)	226.1			(942.8		)
Less: Comprehensive income attributable to noncontrolling interests	—			—			12.3			—			12.3
Comprehensive (loss) income attributable to common stockholders	$	(955.1	)	$	543.6		$	(769.7	)	$	226.1		$	(955.1	)



Peabody Energy Corporation	2015 Form 10-K	F- 87

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS



	December 31, 2015
	Parent Company		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Reclassifications/ Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	7.2	$	0.3	$	253.8	$	—		$	261.3
Accounts receivable, net	—		8.7		220.1		—			228.8
Receivables from affiliates, net	582.1		—		121.1		(703.2		)	—
Inventories	—		153.7		154.1		—			307.8
Assets from coal trading activities, net	—		3.2		20.3		—			23.5
Deferred income taxes	—		65.3		—		(11.8		)	53.5
Other current assets	78.6		127.9		296.6		—			503.1
Total current assets	667.9		359.1		1,066.0		(715.0		)	1,378.0
Property, plant, equipment and mine development, net	—		4,722.9		4,535.6		—			9,258.5
Deferred income taxes	—		33.1		—		(30.9		)	2.2
Investments and other assets	8,495.1		3.7		185.4		(8,301.6		)	382.6
Notes receivable from affiliates, net	—		1,665.8		—		(1,665.8		)	—
Total assets	$	9,163.0	$	6,784.6	$	5,787.0	$	(10,713.3	)	$	11,021.3
Liabilities and Stockholders’ Equity
Current liabilities
Current portion of long-term debt	$	5,899.5	$	23.2	$	7.7	$	—		$	5,930.4
Payables to affiliates, net	—		703.2		—		(703.2		)	—
Deferred income taxes	11.8		—		3.8		(11.8		)	3.8
Liabilities from coal trading activities, net	—		4.8		10.8		—			15.6
Accounts payable and accrued expenses	494.8		527.2		420.5		—			1,442.5
Total current liabilities	6,406.1		1,258.4		442.8		(715.0		)	7,392.3
Long-term debt, less current portion	385.2		—		—		—			385.2
Deferred income taxes	98.6		—		1.4		(30.9		)	69.1
Notes payable to affiliates, net	1,032.6		—		633.2		(1,665.8		)	—
Other noncurrent liabilities	323.6		1,588.6		344.0		—			2,256.2
Total liabilities	8,246.1		2,847.0		1,421.4		(2,411.7		)	10,102.8
Peabody Energy Corporation stockholders’ equity	916.9		3,937.6		4,364.0		(8,301.6		)	916.9
Noncontrolling interests	—		—		1.6		—			1.6
Total stockholders’ equity	916.9		3,937.6		4,365.6		(8,301.6		)	918.5
Total liabilities and stockholders’ equity	$	9,163.0	$	6,784.6	$	5,787.0	$	(10,713.3	)	$	11,021.3



Peabody Energy Corporation	2015 Form 10-K	F- 88

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS



	December 31, 2014
	Parent Company		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Reclassifications/ Eliminations			Consolidated
			(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	188.7	$	1.2	$	108.1	$	—		$	298.0
Accounts receivable, net	—		14.5		548.6		—			563.1
Receivables from affiliates, net	258.4		—		105.9		(364.3		)	—
Inventories	—		191.8		214.7		—			406.5
Assets from coal trading activities, net	—		53.8		3.8		—			57.6
Deferred income taxes	64.5		8.6		6.9		—			80.0
Other current assets	—		44.5		261.3		—			305.8
Total current assets	511.6		314.4		1,249.3		(364.3		)	1,711.0
Property, plant, equipment and mine development, net	—		5,005.2		5,572.1		—			10,577.3
Deferred income taxes	—		8.2		—		(7.5		)	0.7
Investments and other assets	10,209.4		4.0		621.6		(9,932.9		)	902.1
Notes receivable from affiliates, net	—		1,655.7		—		(1,655.7		)	—
Total assets	$	10,721.0	$	6,987.5	$	7,443.0	$	(11,960.4	)	$	13,191.1
Liabilities and Stockholders’ Equity
Current liabilities
Current portion of long-term debt	$	12.0	$	0.1	$	9.1	$	—		$	21.2
Payables to affiliates, net	—		364.3		—		(364.3		)	—
Liabilities from coal trading activities, net	—		10.7		22.0		—			32.7
Accounts payable and accrued expenses	474.5		682.5		652.2		—			1,809.2
Total current liabilities	486.5		1,057.6		683.3		(364.3		)	1,863.1
Long-term debt, less current portion	5,951.6		6.3		7.7		—			5,965.6
Deferred income taxes	90.5		—		6.1		(7.5		)	89.1
Notes payable to affiliates, net	1,033.4		—		622.3		(1,655.7		)	—
Other noncurrent liabilities	434.2		1,717.4		395.2		—			2,546.8
Total liabilities	7,996.2		2,781.3		1,714.6		(2,027.5		)	10,464.6
Peabody Energy Corporation stockholders’ equity	2,724.8		4,206.2		5,726.7		(9,932.9		)	2,724.8
Noncontrolling interests	—		—		1.7		—			1.7
Total stockholders’ equity	2,724.8		4,206.2		5,728.4		(9,932.9		)	2,726.5
Total liabilities and stockholders’ equity	$	10,721.0	$	6,987.5	$	7,443.0	$	(11,960.4	)	$	13,191.1



Peabody Energy Corporation	2015 Form 10-K	F- 89

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS



	Year Ended December 31, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash (used in) provided by continuing operations	$	(692.9	)	$	593.5		$	118.3		$	18.9
Net cash used in discontinued operations	(27.4		)	(2.9		)	(3.0		)	(33.3		)
Net cash (used in) provided by operating activities	(720.3		)	590.6			115.3			(14.4		)
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(87.2		)	(39.6		)	(126.8		)
Changes in accrued expenses related to capital expenditures	—			(3.6		)	(5.6		)	(9.2		)
Federal coal lease expenditures	—			(277.2		)	—			(277.2		)
Proceeds from disposal of assets, net of notes receivable	—			36.3			34.1			70.4
Purchases of debt and equity securities	—			—			(28.8		)	(28.8		)
Proceeds from sales and maturities of debt and equity securities	—			—			90.3			90.3
Contributions to joint ventures	—			—			(425.4		)	(425.4		)
Distributions from joint ventures	—			—			422.6			422.6
Advances to related parties	—			—			(3.7		)	(3.7		)
Repayment of loans from related parties	—			—			0.9			0.9
Other, net	—			(3.2		)	0.1			(3.1		)
Net cash (used in) provided by investing activities	—			(334.9		)	44.9			(290.0		)
Cash Flows From Financing Activities
Proceeds from long-term debt	975.7			—			—			975.7
Repayments of long-term debt	(662.0		)	(0.2		)	(9.1		)	(671.3		)
Payment of deferred financing costs	(28.7		)	—			—			(28.7		)
Dividends paid	(1.4		)	—			—			(1.4		)
Other, net	1.4			(1.8		)	(6.2		)	(6.6		)
Transactions with affiliates, net	253.8			(254.6		)	0.8			—
Net cash provided by (used in) financing activities	538.8			(256.6		)	(14.5		)	267.7
Net change in cash and cash equivalents	$	(181.5	)	$	(0.9	)	$	145.7		$	(36.7	)
Cash and cash equivalents at beginning of year	188.7			1.2			108.1			298.0
Cash and cash equivalents at end of year	$	7.2		$	0.3		$	253.8		$	261.3



Peabody Energy Corporation	2015 Form 10-K	F- 90

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS



	Year Ended December 31, 2014
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash (used in) provided by continuing operations	$	(369.0	)	$	776.1		$	33.9		$	441.0
Net cash used in discontinued operations	(73.3		)	(4.6		)	(26.5		)	(104.4		)
Net cash (used in) provided by operating activities	(442.3		)	771.5			7.4			336.6
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(108.5		)	(85.9		)	(194.4		)
Changes in accrued expenses related to capital expenditures	—			3.4			(20.0		)	(16.6		)
Federal coal lease expenditures	—			(276.7		)	—			(276.7		)
Proceeds from disposal of assets, net of notes receivable	—			105.9			97.8			203.7
Purchases of debt and equity securities	—			—			(15.1		)	(15.1		)
Proceeds from sales and maturities of debt and equity securities	—			—			13.5			13.5
Contributions to joint ventures	—			—			(529.8		)	(529.8		)
Distributions from joint ventures	—			—			534.2			534.2
Advances to related parties	—			—			(33.7		)	(33.7		)
Repayment of loan from related parties	—			—			5.4			5.4
Other, net	—			(4.4		)	(0.6		)	(5.0		)
Net cash used in investing activities	—			(280.3		)	(34.2		)	(314.5		)
Cash Flows From Financing Activities
Proceeds from long-term debt	—			—			1.1			1.1
Repayments of long-term debt	(12.0		)	(0.1		)	(8.9		)	(21.0		)
Payment of deferred financing costs	(10.1		)	—			—			(10.1		)
Dividends paid	(92.3		)	—			—			(92.3		)
Restricted cash for distributions to noncontrolling interest	—			—			(42.5		)	(42.5		)
Other, net	3.1			(1.7		)	(4.7		)	(3.3		)
Transactions with affiliates, net	441.6			(488.5		)	46.9			—
Net cash provided by (used in) financing activities	330.3			(490.3		)	(8.1		)	(168.1		)
Net change in cash and cash equivalents	$	(112.0	)	$	0.9		$	(34.9	)	$	(146.0	)
Cash and cash equivalents at beginning of year	300.7			0.3			143.0			444.0
Cash and cash equivalents at end of year	$	188.7		$	1.2		$	108.1		$	298.0



Peabody Energy Corporation	2015 Form 10-K	F- 91

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS



	Year Ended December 31, 2013
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash (used in) provided by continuing operations	$	(24.3	)	$	778.7		$	25.7		$	780.1
Net cash used in discontinued operations	(20.4		)	(7.6		)	(29.7		)	(57.7		)
Net cash (used in) provided by operating activities	(44.7		)	771.1			(4.0		)	722.4
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(95.9		)	(232.5		)	(328.4		)
Changes in accrued expenses related to capital expenditures	—			(1.2		)	(119.5		)	(120.7		)
Federal coal lease expenditures	—			(276.8		)	—			(276.8		)
Proceeds from disposal of assets, net of notes receivable	—			93.0			85.3			178.3
Purchases of debt and equity securities	—			—			(22.8		)	(22.8		)
Proceeds from sales and maturities of debt and equity securities	—			—			22.9			22.9
Maturity of short-term investments	—			—			4.8			4.8
Contributions to joint ventures	—			—			(671.7		)	(671.7		)
Distributions from joint ventures	—			—			722.9			722.9
Advances to related parties	—			—			(42.1		)	(42.1		)
Repayment of loans from related parties	—			—			25.2			25.2
Other, net	—			(5.7		)	(0.1		)	(5.8		)
Net cash used in continuing operations	—			(286.6		)	(227.6		)	(514.2		)
Net cash used in discontinued operations	—			—			(1.5		)	(1.5		)
Net cash used in investing activities	—			(286.6		)	(229.1		)	(515.7		)
Cash Flows From Financing Activities
Proceeds from long-term debt	1,188.0			—			—			1,188.0
Repayments of long-term debt	(1,334.2		)	(0.2		)	(55.8		)	(1,390.2		)
Payment of deferred financing costs	(22.8		)	—			—			(22.8		)
Dividends paid	(91.7		)	—			—			(91.7		)
Other, net	4.2			(1.6		)	(7.4		)	(4.8		)
Transactions with affiliates, net	332.3			(482.7		)	150.4			—
Net cash provided by (used in) financing activities	75.8			(484.5		)	87.2			(321.5		)
Net change in cash and cash equivalents	$	31.1		$	—		$	(145.9	)	$	(114.8	)
Cash and cash equivalents at beginning of year	269.6			0.3			288.9			558.8
Cash and cash equivalents at end of year	$	300.7		$	0.3		$	143.0		$	444.0



Peabody Energy Corporation	2015 Form 10-K	F- 92

Table of Contents

PEABODY ENERGY CORPORATION

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS



Description	Balance at Beginning of Period		Charged to Costs and Expenses			Deductions⁽¹⁾				Other				Balance at End of Period
	(Dollars in millions)
Year Ended December 31, 2015
Reserves deducted from asset accounts:
Advance royalty recoupment reserve	$	7.6	$	—		$	(0.9	)	⁽²⁾	$	1.6		⁽³⁾	$	8.3
Reserve for materials and supplies	4.6		0.4			(0.3		)		—				4.7
Allowance for doubtful accounts	5.8		8.0			(7.2		)		—				6.6
Tax valuation allowances	1,169.0		462.0			—				(183.7		)	⁽⁴⁾	1,447.3
Year Ended December 31, 2014
Reserves deducted from asset accounts:
Advance royalty recoupment reserve	$	9.7	$	(0.2	)	$	(1.9	)	⁽²⁾	$	—			$	7.6
Reserve for materials and supplies	7.4		(0.1		)	(2.7		)		—				4.6
Allowance for doubtful accounts	7.4		1.5			(1.4		)		(1.7		)	⁽⁵⁾	5.8
Tax valuation allowances	1,634.1		569.4			—				(1,034.5		)	⁽⁶⁾	1,169.0
Year Ended December 31, 2013
Reserves deducted from asset accounts:
Advance royalty recoupment reserve	$	15.3	$	0.1		$	(5.7	)	⁽²⁾	$	—			$	9.7
Reserve for materials and supplies	16.0		1.7			(10.3		)		—				7.4
Allowance for doubtful accounts	13.7		4.3			(10.1		)		(0.5		)	⁽⁵⁾	7.4
Tax valuation allowances	1,481.8		(29.4		)	—				181.7			⁽⁷⁾	1,634.1


⁽¹⁾	Reserves utilized, unless otherwise indicated.


⁽²⁾	Deductions to advance royalty recoupment reserve represents the termination of federal and state leases.


⁽³⁾	Balances transferred from other accounts.


⁽⁴⁾	Includes a decrease in valuation allowance during the period reflected directly in "Accumulated other comprehensive loss" and the impact of the 2015 decrease in Australian dollar exchange rates.


⁽⁵⁾	Represents subsequent recovery of receivable amounts previously reserved.


⁽⁶⁾	Includes the write-off of valuation allowance against deferred tax assets related to the Australian Minerals and Resource Rent Tax (MRRT) due to the repeal of that legislation in 2014, along with an increase in valuation allowance during the period reflected directly in "Accumulated other comprehensive loss" and the impact of the 2014 decrease in Australian dollar exchange rates.

⁽⁷⁾ Related to the MRRT, as offset by the impact of the 2013 decrease in Australian dollar exchange rates.



Peabody Energy Corporation	2015 Form 10-K	F- 93

Table of Contents

EXHIBIT INDEX

The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.



Exhibit No.		Description of Exhibit

3.1		Third Amended and Restated Certificate of Incorporation of the Registrant, as amended (Incorporated by reference to Exhibit 3.1 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2011) and Certificate of Amendment of Third Amended and Restated Certificate of Incorporation of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed October 6, 2015).
3.2		Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant's Current Report on Form 8-K filed December 16, 2015).
4.1		Specimen of stock certificate representing the Registrant's common stock, $.01 par value (Incorporated by reference to Exhibit 4.13 to Amendment No. 4 to the Registrant's Form S-1 Registration Statement No. 333-55412, filed May 1, 2001).
4.2		Indenture, dated as of March 19, 2004, between the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.12 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.3		Subordinated Indenture, dated as of December 20, 2006, between the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant's Current Report on Form 8-K, filed December 20, 2006).
4.4		Indenture, dated as of November 15, 2011, among Peabody, the Guarantors named therein and U.S. Bank National Association, as trustee, governing the 6.00% Senior Notes Due 2018 and 6.25% Senior Notes Due 2021 (Incorporated by reference to Exhibit 4.1 of the Registrant's Current Report on Form 8-K, filed November 17, 2011).
4.5		Indenture, dated as of March 16, 2015, among Peabody, the Guarantors named therein and U.S. Bank National Association, as Trustee and Collateral Agent, governing 10% Senior Secured Second Lien Notes due 2022 (Incorporated by reference to Exhibit 4.1 of the Registrant's Current Report on Form 8-K, filed March 17, 2015). Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of the Registrant. The Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon its request.
10.1		Amended and Restated Credit Agreement, as amended and restated as of September 24, 2013, by and among Peabody Energy Corporation, Citibank, N.A., as administrative agent, swing line lender and L/C issuer, Citigroup Global Markets, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, BNP Paribas Securities Corp., Crédit Agricole Corporate and Investment Bank, HSBC Securities (USA) Inc., Morgan Stanley Senior Funding, Inc., PNC Capital Markets LLC and RBS Securities Inc., as joint lead arrangers and joint book managers, and the other agents and lending institutions identified in the Credit Agreement (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013).
10.2		Share Charge, dated as of September 24, 2013, between Peabody Holdings (Gibraltar) Limited, as grantor, and Citibank, N.A., as administrative agent. (Incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on September 30, 2013).
10.3		Pledge Agreement, dated as of September 24, 2013, among Peabody Investments Corp., as grantor, and Citibank, N.A., as administrative agent. (Incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on September 30, 2013).
10.4		Omnibus Amendment Agreement, dated as of February 5, 2015, to the Amended and Restated Credit Agreement, dated September 24, 2013, by and among Peabody Energy Corporation, Citibank, N.A., as administrative agent, swing line lender and L/C issuer, Citigroup Global Markets, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, BNP Paribas Securities Corp., Crédit Agricole Corporate and Investment Bank, HSBC Securities (USA) Inc., Morgan Stanley Senior Funding, Inc., PNC Capital Markets LLC and RBS Securities Inc., as joint lead arrangers and joint book managers, and the other agents and lending institutions identified in the Credit Agreement. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K filed on February 25, 2015).
10.5		Fourth Amended and Restated Receivables Purchase Agreement, dated as of May 1, 2013, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 3, 2013).

Table of Contents



Exhibit No.		Description of Exhibit

10.6		First Lien/Second Lien Intercreditor Agreement, dated March 16, 2015, among Peabody Energy Corporation, the other grantors party thereto, U.S. Bank, National Association, as second priority representative and Citibank, N.A., as senior representative (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed on March 17, 2015).
10.7		Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant's Form S-4 Registration Statement No. 333-59073).
10.8		Federal Coal Lease WYW119554: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant's Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.9		Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant's Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.10		Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant's Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.11		Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant's Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.12		Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 to the Registrant's Form S-4 Registration Statement No. 333-59073, filed September 8, 1998).
10.13		Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (Incorporated by reference to Exhibit 10.9 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998).
10.14		Federal Coal Lease WYW154001: North Antelope Rochelle South (Incorporated by reference to Exhibit 10.68 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2004).
10.15		Federal Coal Lease WYW150210: North Antelope Rochelle Mine (Incorporated by reference to Exhibit 10.8 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
10.16		Federal Coal Lease WYW151134 effective May 1, 2005: West Roundup (Incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).
10.17		Federal Coal Lease Readjustment WYW78663: Caballo (Incorporated by reference to Exhibit 10.24 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.18		Transfer by Assignment and Assumption of Federal Coal Lease WYW172657: Caballo West (Incorporated by reference to Exhibit 10.25 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.19		Federal Coal Lease WYW176095: Porcupine South (Incorporated by reference to Exhibit 10.26 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.20		Federal Coal Lease WYW173408: North Porcupine (Incorporated by reference to Exhibit 10.27 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.21		Federal Coal Lease WYW172413: School Creek (Incorporated by reference to Exhibit 10.28 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.22		Separation Agreement, Plan of Reorganization and Distribution, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed October 25, 2007).
10.23		Tax Separation Agreement, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed October 25, 2007).
10.24		Coal Act Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K, filed October 25, 2007).
10.25		Salaried Employee Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC, Peabody Coal Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.5 of the Registrant's Current Report on Form 8-K, filed October 25, 2007).

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Exhibit No.		Description of Exhibit

10.26		Coal Supply Agreement, dated October 22, 2007, between Patriot Coal Sales LLC and COALSALES II, LLC (Incorporated by reference to Exhibit 10.6 of the Registrant's Current Report on Form 8-K, filed October 25, 2007).
10.27		Settlement Agreement entered into as of October 24, 2013, by and among Patriot Coal Corporation, on behalf of itself and its affiliates, the Registrant, on behalf of itself and its affiliates, and the United Mine Workers of America, on behalf of itself and the UMWA Employees and UMWA Retirees (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed October 30, 2013).
10.28†		Purchase and Sale Agreement, dated as of November 20, 2015, by and between Four Star Holdings, LLC and Western Megawatt Resources, LLC.
10.29*		1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 4.9 of the Registrant's Form S-8 Registration Statement No. 333-105456, filed May 21, 2003).
10.30*		Amendment to the 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.4 of the Registrant's Current Report on Form 8-K, filed October 17, 2007).
10.31*		Amendment No. 2 to the 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed December 11, 2007).
10.32*		Amendment No. 3 to the 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).
10.33*		Form of Non-Qualified Stock Option Agreement under the Registrant's 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.15 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003).
10.34*		Form of Amendment to Non-Qualified Stock Option Agreement under the Registrant's 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.16 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003).
10.35*		Form of Amendment, dated as of June 15, 2004, to Non-Qualified Stock Option Agreement under the Registrant's 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.65 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
10.36*		Form of Incentive Stock Option Agreement under the Registrant's 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.17 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003).
10.37*		Long-Term Equity Incentive Plan of the Registrant (Incorporated by reference to Exhibit 99.2 of the Registrant's Form S-8 Registration Statement No. 333-61406, filed May 22, 2001).
10.38*		Amendment to the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K, filed October 17, 2007).
10.39*		Amendment No. 2 to the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).
10.40*		Form of Non-Qualified Stock Option Agreement under the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.18 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003).
10.41*		Form of Performance Unit Award Agreement under the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.19 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003).
10.42*		Form of Non-Qualified Stock Option Agreement for Outside Directors under the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K, filed December 14, 2005).
10.43*		Form of Restricted Stock Award Agreement for Outside Directors under the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K, filed December 14, 2005).
10.44*		Equity Incentive Plan for Non-Employee Directors of the Registrant (Incorporated by reference to Exhibit 99.3 of the Registrant's Form S-8 Registration Statement No. 333-61406, filed May 22, 2001).
10.45*		Amendment No. 1 to the Equity Incentive Plan for Non-Employee Directors of the Registrant (Incorporated by reference to Exhibit 10.3 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).

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Exhibit No.		Description of Exhibit

10.46*		Form of Non-Qualified Stock Option Agreement under the Registrant's Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.20 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003).
10.47*		The Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Annex A to the Registrant's Proxy Statement for the 2004 Annual Meeting of Stockholders, filed April 2, 2004).
10.48*		Amendment No. 1 to the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.67 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2004).
10.49*		Amendment No. 2 to the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed October 17, 2007).
10.50*		Amendment No. 3 to the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed October 17, 2007).
10.51*		Amendment No. 4 to the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed December 11, 2007).
10.52*		Amendment No. 5 to the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.4 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).
10.53*		Form of Non-Qualified Stock Option Agreement under the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K, filed January 7, 2005).
10.54*		Form of Performance Units Agreement under the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed January 7, 2005).
10.55*		Form of Performance Units Agreement under the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.36 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2007).
10.56*		Form of Performance Units Award Agreement under the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009).
10.57*		Form of Deferred Stock Units Agreement for Non-Employee Directors under the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.43 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2010).
10.58*		Peabody Energy Corporation 2011 Long-Term Equity Incentive Plan (Incorporated by reference to Appendix A of the Registrant's Proxy Statement, filed March 22, 2011).
10.59*		Amendment No. 1 to the Registrant's 2011 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.5 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).
10.60*		Form of Non-Qualified Stock Option Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.59 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2011).
10.61*		Form of Performance Units Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.60 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2011).
10.62*		Form of Restricted Stock Award Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.61 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2011).
10.63*		Form of Deferred Stock Unit Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.62 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2011).
10.64*		Form of Non-Qualified Stock Option Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan (effective for awards to executive officers than Gregory H. Boyce on and after January 2, 2014) (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K, filed April 25, 2014).
10.65*		Form of Restricted Stock Award Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan (effective for awards on and after January 2, 2014) (Incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K, filed April 25, 2014).

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Exhibit No.		Description of Exhibit

10.66*		Form of Performance Units Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan. (effective for awards on and after January 2, 2014) (Incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K, filed April 25, 2014).
10.67*		Form of Non-Qualified Stock Option Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan (effective for awards to Gregory H. Boyce on and after January 2, 2014) (Incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K, filed April 25, 2014).
10.68*		Peabody Energy Corporation 2015 Long-Term Incentive Plan (Incorporated by reference to Appendix B of the Registrant's Proxy Statement, filed March 24, 2015).
10.69*†		Form of Performance-Based Restricted Stock Unit Agreement under the Registrant's 2015 Long-Term Incentive Plan.
10.70*†		Form of Performance-Based Restricted Stock Unit Agreement under the Registrant's 2015 Long-Term Incentive Plan (effective for Australia).
10.71*†		Form of Service-Based Cash Award Agreement under the Registrant's 2015 Long-Term Incentive Plan.
10.72*†		Form of Service-Based Cash Award Agreement under the Registrant’s 2015 Long-Term Incentive Plan.
10.73*†		Form of Service-Based Cash Award Agreement for Non-Employee Directors under the Registrant's 2015 Long-Term Incentive Plan.
10.74*†		Form of Deferred Stock Unit Agreement under the Registrant's 2015 Long-Term Incentive Plan.
10.75*†		Form of Restrictive Covenant Agreement under the Registrant's 2015 Long-Term Incentive Plan.
10.76*†		Form of Restrictive Covenant Agreement under the Registrant's 2015 Long-Term Incentive Plan (Australia).
10.77*		Cash-Settled Performance Units Agreement between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.5 to the Registrant's Current Report on Form 8-K, filed April 25, 2014).
10.78*		2009 Amendment entered into effective December 31, 2009 to the Stock Grant Agreement dated as of October 1, 2003 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.45 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009).
10.79*		2009 Amendment entered into effective December 31, 2009 to the Non-Qualified Stock Option Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.46 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009).
10.80*		2009 Amendment entered into effective December 31, 2009 to the Non-Qualified Stock Option Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.47 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009).
10.81*		2009 Amendment entered into effective December 31, 2009 to the Performance Units Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.48 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009).
10.82*		2009 Amendment entered into effective December 31, 2009 to the Performance Units Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.49 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009).
10.83*		2010 Amendment entered into effective March 17, 2010, to the 2008 Performance Units Award Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.3 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).
10.84*		2010 Amendment entered into effective March 17, 2010, to the 2009 Performance Units Award Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.4 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).
10.85*		Amended and Restated Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.44 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).

Table of Contents



Exhibit No.		Description of Exhibit

10.86*		Amendment to the Amended and Restated Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.51 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009).
10.87*		Amended and Restated Australian Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.45 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).
10.88*		Amendment to the Amended and Restated Australian Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.53 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009).
10.89*		2008 Management Annual Incentive Compensation Plan (Incorporated by reference to Appendix B to the Registrant's Proxy Statement for the 2008 Annual Meeting of Shareholders, filed March 27, 2008).
10.90*		The Registrant's Deferred Compensation Plan (Incorporated by reference to Exhibit 10.30 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).
10.91*		First Amendment to the Registrant's Deferred Compensation Plan (Incorporated by reference to Exhibit 10.49 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2004).
10.92*		Letter Agreement, dated as of March 1, 2005, by and between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed March 4, 2005).
10.93*		Restated Employment Agreement effective December 31, 2009 by and between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed December 24, 2009).
10.94*		Amended and Restated Transition Agreement effective May 8, 2014 by and between Peabody Energy Corporation and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 13, 2014).
10.95*		2013 Restricted Stock Unit Agreement by and between Peabody Energy Corporation and Gregory H. Boyce (Incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on May 3, 2013).
10.96*		Employment Agreement entered into as of August 21, 2013, by and between Peabody Energy Corporation and Glenn L. Kellow (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on August 27, 2013).
10.97*		Restrictive Covenant Agreement entered into as of August 21, 2013, by and between Peabody Energy Corporation and Glenn L. Kellow (Incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on August 27, 2013).
10.98*		Letter dated January 27, 2015 to Glenn L. Kellow from the Chairman of the Compensation Committee of the Peabody Energy Corporation Board of Directors (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 28, 2015).
10.99*		Letter Agreement entered into as of January 27, 2015, by and between Peabody Energy Corporation and Glenn L. Kellow (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on January 28, 2015).
10.100*		Letter Agreement entered into as of April 21, 2015, by and between Peabody Energy Corporation and Gregory H. Boyce (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on April 21, 2015).
10.101*		Letter Agreement entered into as of April 20, 2015, by and between Peabody Energy Corporation and Glenn L. Kellow (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on April 21, 2015).
10.102*		Employment Agreement entered into as of December 31, 2008 by and between the Registrant and Michael C. Crews (Incorporated by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K, filed December 31, 2008).
10.103*		Restated Employment Agreement entered into as of January 7, 2013 by and between the Registrant and Charles F. Meintjes (Incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed January 10, 2013).
10.104*		Restated Employment Agreement entered into as of December 20, 2012 by and between the Registrant and Kemal Williamson (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 26, 2012).

Table of Contents



Exhibit No.		Description of Exhibit

10.105*		Peabody Energy Corporation Executive Severance Plan. (Incorporated by reference to Exhibit 10.92 to the Registrant’s Annual Report on Form 10-K filed on February 25, 2015).
10.106*		Peabody Energy Corporation 2015 Amended and Restated Executive Severance Plan. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on November 23, 2015).
10.107*		Form of Director and Executive Officer Indemnification Agreement between the Registrant and each of its directors and executive officers. (Incorporated by reference to Exhibit 10.93 to the Registrant’s Annual Report on Form 10-K filed on February 25, 2015).
10.108*		Peabody Investments Corp. Supplemental Employee Retirement Account (Incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007).
21†		List of Subsidiaries.
23.1†		Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.
23.2†		Consent of Palaris Australia Pty Ltd.
31.1†		Certification of periodic financial report by the Registrant's Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2†		Certification of periodic financial report by the Registrant's Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1†		Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant's Chief Executive Officer.
32.2†		Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant's Chief Financial Officer.
95†		Mine Safety Disclosure required by Item 104 of Regulation S-K.
101†		Interactive Data File (Form 10-K for the year ended December 31, 2015 filed in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”

The agreements and other documents filed as exhibits to this report are not intended to provide factual information or other disclosure other than with respect to the terms of the agreements or other documents themselves, and you should not rely on them for that purpose. In particular, any representations and warranties made by us in these agreements or other documents were made solely within the specific context of the relevant agreement or document and may not describe the actual state of affairs as of the date they were made or at any other time.



*	These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 15(a)(3) and 15(b) of this report.

†	Filed herewith.