PEABODY ENERGY CORP - Annual Report: 2016 (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, 2016 |
or |
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:
None
Securities Registered Pursuant to Section 12(g) of the Act:
Title of Each Class |
Common Stock, par value $0.01 per share |
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 o | Accelerated filer o | Non-accelerated filer þ | 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 (stockholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2016: Common Stock, par value $0.01 per share, $25.3 million.
Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of March 15, 2017: Common Stock, par value $0.01 per share, 18,491,188 shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None.
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," "target," "likely," "will," "to be" 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. These factors are difficult to accurately predict and may be beyond our control. Factors that could affect our results or an investment in our securities include, but are not limited to:
Factors related to our Chapter 11 Cases (as defined herein)
• | our ability to consummate the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession, dated January 27, 2017 (as further modified, the Plan) as confirmed by an order of the Bankruptcy Court entered on March 17, 2017; |
• | the effects of the Chapter 11 Cases on our operations, including customer, supplier, banking, insurance and other relationships and agreements; |
• | Bankruptcy Court rulings in the Chapter 11 Cases as well as the outcome of all other pending litigation and the outcome of the Chapter 11 Cases in general; |
• | the length of time that we will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings; |
• | the risks associated with third-party motions in the Chapter 11 Cases, which may interfere with our ability to consummate the Plan and restructuring generally; |
• | increased advisory costs to execute a plan of reorganization; |
• | the volatility of the trading price of our common stock and the absence of correlation between any increases in the trading price and our expectation that the common stock will be canceled and extinguished upon the Plan's effective date (Plan Effective Date); |
• | the risk that the Plan does not become effective, in which case there can be no assurance that the Chapter 11 Cases will continue rather than be converted to Chapter 7 liquidation cases or that any alternative plan of reorganization would be on terms as favorable to holders of claims and interests as the terms of the Plan; |
• | Peabody Energy’s ability to use cash collateral and the possibility that Peabody Energy may be required to post additional cash collateral to secure its obligations; |
• | the effect of the Chapter 11 Cases on our relationships with third parties, regulatory authorities and employees; |
• | the potential adverse effects of the Chapter 11 Cases on our liquidity, results of operations, or business prospects; |
• | our ability to execute our business and restructuring plan; |
• | increased administrative and legal costs related to the Chapter 11 Cases and other litigation and the inherent risks involved in a bankruptcy process; |
• | the cost, availability and access to capital and financial markets, including the ability to secure new financing after emerging from the Chapter 11 Cases; and |
• | the risk that the Chapter 11 Cases will disrupt or impede our international operations, including our business operations in Australia. |
Peabody Energy Corporation | 2016 Form 10-K | i |
Other factors
• | competition in the energy market and supply and demand for our coal products, including the impact of alternative energy sources, such as natural gas and renewables; |
• | global steel demand and the downstream impact on metallurgical coal prices, and lower demand for our products by electric power generators; |
• | our ability to successfully consummate planned divestitures, including the planned sale of all of our equity interests in Metropolitan Collieries Pty Ltd, the entity that owns the Metropolitan coal mine in New South Wales, Australia (the Metropolitan Mine); |
• | our ability to appropriately secure our requirements for reclamation, federal and state workers’ compensation, federal coal leases and other obligations related to our operations, including our ability to utilize self-bonding and/or successfully access the commercial surety bond market; |
• | customer procurement practices and contract duration; |
• | the 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, bank 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; |
• | 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; |
• | legislation, regulations and court decisions or other government actions, including, but not limited to, new environmental and mine safety requirements, changes in income tax regulations, sales-related royalties, or other regulatory taxes and changes in derivative 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; |
• | terrorist attacks or security threats, including, but not limited to, cybersecurity breaches; and |
• | impacts of pandemic illnesses. |
Factors related to our indebtedness and expected post-emergence capital structure under the Plan
• | the fact that our common stock will be canceled and extinguished upon the Plan Effective Date, if the Plan becomes effective, with no payments made to the holders of our common stock; |
• | the lack of an established market for the shares of new common stock (Reorganized PEC Common Stock) or the preferred stock (Preferred Equity) to be issued pursuant to the Plan on the Plan Effective Date, and potential dilution of Reorganized PEC Common Stock due to future issuances of equity securities; |
• | our ability to generate sufficient cash to service all of our expected post-emergence indebtedness; |
• | our post-emergence debt instruments and capital structure will place certain limits on our ability to pay dividends and repurchase common stock; |
• | our ability to comply with financial and other restrictive covenants in various agreements, including the credit facility contemplated by the Plan; and |
• | other risks and factors, including those discussed in "Legal Proceedings," set forth Part I, Item 3 of this report and “Risk Factors,” set forth in Part I, Item 1A of this report. |
Peabody Energy Corporation | 2016 Form 10-K | ii |
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 | 2016 Form 10-K | iii |
TABLE OF CONTENTS
Page | ||
Principal Accountant Fees and Services | ||
Exhibits and Financial Statement Schedules | ||
Peabody Energy Corporation | 2016 Form 10-K | 1 |
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. We own interests in 23 coal mining operations located in the United States (U.S.) and Australia. We have previously reported owning interests in 25 mining operations, but have combined the Somerville North Mine with the Somerville Central Mine, and the Somerville South Mine with the Wild Boar Mine (all part of our Midwestern operating segment) to create more efficient mining complexes, which reduces our reported number of operations by two. We have a majority interest in 22 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, the United Kingdom and the U.S. (listed alphabetically).
History and Development
We were incorporated in Delaware in 1998 and became a publicly traded company in 2001. Our history in the coal business dates back to 1883. In 2016, we achieved a global safety incidence rate of 1.22 incidents per 200,000 hours worked, marking a new company record, and a 35% improvement in our global safety performance over the past five years. We were also recognized by the U.S. National Mining Association as the first in the industry to achieve independent certification under the CORESafety® system.
Filing Under Chapter 11 of the United States Bankruptcy Code
On April 13, 2016 (the Petition Date), Peabody and a majority of its wholly owned domestic subsidiaries as well as one international subsidiary in Gibraltar (the Filing Subsidiaries, and together with Peabody, the Debtors) filed voluntary petitions for reorganization (the petitions collectively, the Bankruptcy Petitions) under Chapter 11 of Title 11 of the U.S. Code (the Bankruptcy Code) in the United States Bankruptcy Court for the Eastern District of Missouri (the Bankruptcy Court). The Company’s Australian operations and other international subsidiaries are not included in the filings. The Debtors' Chapter 11 cases (collectively, the Chapter 11 Cases) are being jointly administered under the caption In re Peabody Energy Corporation, et al., Case No. 16-42529 (Bankr. E.D. Mo.). The Debtors continue to operate their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In general, as debtors-in-possession, the Debtors are authorized under Chapter 11 to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court.
On January 27, 2017, we filed with the Bankruptcy Court the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, the Plan). Subsequently, the Debtors solicited votes on the Plan. On March 15, 2017, the Debtors filed a revised version of the Plan. On March 16, 2017, the Bankruptcy Court held a hearing to determine whether the Plan should be confirmed. On March 17, 2017, the Bankruptcy Court entered an order confirming the Plan.
Although the Bankruptcy Court has confirmed the Plan, the Debtors have not yet consummated all of the transactions that are contemplated by the Plan. Rather, the Debtors intend to consummate these transactions in the near future, on or before the Plan Effective Date. As set forth in the Plan, there are certain conditions precedent to the occurrence of the Plan Effective Date, which must be satisfied or waived in accordance with the Plan in order for the Plan to become effective and the Debtors to emerge from the Chapter 11 Cases. The Debtors anticipate that each of these conditions will be either satisfied or waived by early April 2017, which is the target for the Debtors' emergence from the Chapter 11 Cases. On the Plan Effective Date, the Debtors will, generally, no longer be governed by the Bankruptcy Court's oversight.
Peabody Energy Corporation | 2016 Form 10-K | 2 |
Under the Plan, current holders of our equity securities will not receive any distributions, and the equity securities will be canceled upon the Plan Effective Date. Accordingly, we urge that caution be exercised with respect to existing and future investments in our equity or other securities. Additional information about our Chapter 11 Cases is available on the Internet at www.peabodyenergy.com. Bankruptcy Court filings, claims information and our Plan are available at www.kccllc.net/peabody. Information contained on these websites is not part of, and is not incorporated by reference in, this Form 10-K.
Segment and Geographic Information
We conduct business through six operating segments: Powder River Basin Mining, Midwestern U.S. Mining, Western U.S. Mining, Australian Metallurgical Mining, Australian Thermal Mining and Trading and Brokerage. Segment and geographic financial information is contained in Note 29. "Segment and Geographic Information" to our consolidated financial statements and is incorporated herein by reference.
Mining Segments
U.S. Mining Operations - Powder River Basin, Midwestern, Western
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 as international exports as 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 sulfur content and Btu 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, coal with a mid-range sulfur content and Btu. 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 U.S. Mining operations mine both bituminous and sub-bituminous coal deposits.
Australian Mining Operations - Metallurgical, Thermal
The business of our Australian operating platform is primarily export focused with customers spread across several countries, while a portion of our metallurgical and 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 coking coal and low-volatile pulverized coal injection (LV 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, we may market some of our metallurgical coal products as a thermal coal product from time to time depending on supply and demand conditions.
Peabody Energy Corporation | 2016 Form 10-K | 3 |
The table below summarizes information regarding the operating characteristics of each of our mines that were active in 2016 in the U.S. and Australia. The mines are listed within their respective mining segment in descending order, as determined by tons sold in 2016.
Segment/Mining Complex | Location | Mine Type | Mining Method | Coal Type | Primary Transport Method | 2016 Tons Sold (In millions) | |||||||
Powder River Basin Mining | |||||||||||||
North Antelope Rochelle | Wyoming | S | D, DL, T/S | T | R | 92.9 | |||||||
Caballo | Wyoming | S | D, T/S | T | R | 11.2 | |||||||
Rawhide | Wyoming | S | D, T/S | T | R | 8.1 | |||||||
Third party (1) | — | — | — | — | — | 0.9 | |||||||
Midwestern U.S. Mining | |||||||||||||
Bear Run | Indiana | S | DL, D, T/S | T | Tr, R | 7.4 | |||||||
Wild Boar | Indiana | S | D, T/S | T | Tr, R, R/B, T/B | 2.7 | |||||||
Somerville Central | Indiana | S | DL, D, T/S | T | R, R/B, T/B, T/R | 2.4 | |||||||
Francisco Underground | Indiana | U | CM | T | R | 2.1 | |||||||
Gateway North | Illinois | U | CM | T | Tr, R, R/B, T/B | 1.8 | |||||||
Wildcat Hills Underground | Illinois | U | CM | T | T/B | 1.6 | |||||||
Cottage Grove | Illinois | S | D, T/S | T | T/B | 0.3 | |||||||
Western U.S. Mining | |||||||||||||
Kayenta | Arizona | S | DL, T/S | T | R | 5.8 | |||||||
El Segundo | New Mexico | S | D, DL, T/S | T | R | 4.9 | |||||||
Twentymile | Colorado | U | LW | T | R, Tr | 2.6 | |||||||
Lee Ranch | New Mexico | S | T/S | T | R | 0.4 | |||||||
Australian Metallurgical Mining | |||||||||||||
Millennium | Queensland | S | D, T/S | M, P | R, EV | 3.8 | |||||||
Coppabella (2) | Queensland | S | DL, D, T/S | P | R, EV | 2.4 | |||||||
Metropolitan (3) | New South Wales | U | LW | M | R, EV | 2.0 | |||||||
Moorvale (2) | Queensland | S | D, T/S | P | R, EV | 1.9 | |||||||
Burton* (4) | Queensland | S | DL, T/S | M, T | R, EV | 1.7 | |||||||
North Goonyella (5) | Queensland | U | LW, LTCC | M | R, EV | 1.6 | |||||||
Middlemount (6) | Queensland | S | D, T/S | M, P | R, EV | — | |||||||
Australian Thermal Mining | |||||||||||||
Wilpinjong | New South Wales | S | D, T/S | T | R, EV | 14.1 | |||||||
Wambo Open-Cut (7) | New South Wales | S | T/S | T | R, EV | 3.7 | |||||||
Wambo Underground (7) | New South Wales | U | LW | M, T | R, EV | 3.5 | |||||||
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) | Third party purchased coal used to satisfy certain specific coal supply agreements. |
(2) | We own a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines. |
(3) | On November 3, 2016, we entered into a definitive share sale and purchase agreement (SPA) for the sale of all of our equity interest in the Metropolitan Mine to a subsidiary of South32 Limited (South32). The closing of the transaction is conditional upon receipt of approval from the Australian Competition and Consumer Commission (ACCC). On February 22, 2017, the ACCC issued a Statement of Issues relating to the transaction, noting that the ACCC is continuing to review the transaction. On February 24, 2017, pursuant to its right under the SPA, South32 extended the CP End Date (as defined in the SPA) from March 3, 2017 to April 17, 2017. On March 21, 2017, the ACCC notified us that it has extended the date on which it intends to render its decision regarding the transaction to April 27, 2017, which date extends beyond the CP End Date. As a result, we are assessing our options under the SPA. |
(4) | Mine status changed to care and maintenance during 2016 and operations ceased. |
(5) | A significant geological event has resulted in the cessation of the longwall top coal caving system, which will result in the mine operating conventional longwall equipment for at least the remainder of the current panel. |
(6) | We own a 50% equity interest in Middlemount, which owns the Middlemount Mine. Because that entity is accounted for as an unconsolidated equity affiliate, 2016 tons sold from that mine, which totaled 4.5 million tons (on a 100% basis), have been excluded from the table above. |
(7) | Represents our majority-owned mines in which there is an outside non-controlling ownership interest. |
Peabody Energy Corporation | 2016 Form 10-K | 4 |
Refer to the "Summary of Coal Production and Sulfur Content of Assigned Reserves" table within Part I, Item 2. "Properties," which is incorporated by reference herein, for additional information regarding coal reserves, product characteristics and production volume associated with each mine.
Trading and Brokerage Segment
Our Trading and Brokerage segment engages in the direct and brokered trading of coal and freight-related contracts through our trading and business offices. Coal brokering is conducted both as principal and agent in support of various coal production-related activities that may involve coal produced from our mines, including optimization and blending of such coal, 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, 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, including our shared services functions, 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, 2016, we controlled approximately 5.6 billion tons of proven and probable coal reserves and approximately 600,000 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. These surface lands include acres where we have completed post-mining reclamation. 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, 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 2016. During the years ended December 31, 2016, 2015 and 2014, the mine sold 4.5 million, 4.2 million and 3.7 million tons of coal, respectively (on a 100% basis).
U.S. 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 Europe and Brazil. On January 30, 2017, the Bankruptcy Court issued an order authorizing certain subsidiaries of the Company to enter into a stalking horse purchase agreement and approved bidding procedures for the sale of this interest. Pursuant to that order, the deadline to submit qualified bids for the purchase of this interest was set for March 2, 2017 at 4:00 p.m. (Central) and the related auction was scheduled to begin on March 6, 2017 at 10:00 a.m. (Central). On February 10, 2017, Contura Terminal and Ashland Terminal, Inc., both of which are partners of the Dominion Terminal Associates partnership, filed an appeal of the January 30, 2017 order. On March 6, 2017, the Company held the auction relating to the sale of this interest. At the auction, Contura Terminal, LLC and Ashland Terminal, Inc., who bid at the auction together, were declared the successful bidder. On March 7, 2017, the Company filed a notice with the Bankruptcy Court indicating the identity of the successful bidder. On March 9, 2017, the Bankruptcy Court entered an order approving the sale of the Company's interest in Dominion Terminal Associates to Contura Terminal, LLC and Ashland Terminal, Inc. On March 14, 2017, the Bankruptcy Appellate Panel for the Eighth Circuit entered an order dismissing the appeal of Contura Terminal, LLC and Ashland Terminal, Inc. to the Bankruptcy Court's January 26, 2017 order. The sale of the Company's interest in Dominion Terminal Associates is expected to close prior to the Plan Effective Date.
Clean Coal Technology. We continue to advocate for policies in support of clean coal technology development and initiatives seeking to be more energy efficient and reduce global atmospheric levels of carbon dioxide and other emissions.
Peabody Energy Corporation | 2016 Form 10-K | 5 |
Coal Supply Agreements
Customers. Our coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers. Most of our sales (excluding trading and brokerage transactions) are made under long-term coal supply agreements (those with initial terms of one year or longer 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 86%, 88% and 83% of our worldwide sales from our mining operations (by volume) for the years ended December 31, 2016, 2015 and 2014, respectively. A recent trend has been for our customers under long-term coal supply agreements to seek contracts of shorter duration.
For the year ended December 31, 2016, we derived 28% of our total revenues from our five largest customers. Those five customers were supplied primarily from 24 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2017 to 2026. The contract contributing the greatest amount of annual revenue in 2016 was approximately $250 million, or approximately 5% of our 2016 total revenues, and is due to expire in 2026.
Backlog. Our sales backlog (excluding trading and brokerage transactions), which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 587 million and 690 million tons of coal as of January 1, 2017 and 2016, respectively. Contracts in backlog have remaining terms ranging from one to 12 years and represent approximately three years of production based on our 2016 production volume of 175.6 million tons. Approximately 72% of our backlog is expected to be filled beyond 2017.
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 59%, 63% and 59% of our total revenue base for the years ended December 31, 2016, 2015 and 2014, respectively, during which periods the coal mining activities of those segments contributed respective aggregate amounts of approximately 81%, 83% and 83% 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 41%, 36% and 39% of our total revenue base for the years ended December 31, 2016, 2015 and 2014, respectively, during which periods the coal mining activities of those segments contributed respective amounts of 19%, 17% and 17% 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, port 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%, 0% and 1% of its annual tons sold for the years ended December 31, 2016, 2015 and 2014, 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 | 2016 Form 10-K | 6 |
Our Australian Mining operations sold approximately 75%, 77% and 77% of its tons into the seaborne coal markets for the years ended December 31, 2016, 2015 and 2014, 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.
In the past, there has been consolidation in the supplier base providing certain mining materials and equipment to the coal industry. This has limited the number of global sources for these items, such as surface and underground mining equipment. 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 extend the lives of existing equipment through improved maintenance practices and equipment rebuilds in order to defer the requirement for larger capital purchases. We continue to use our global leverage with major suppliers to ensure security of supply to meet the requirements of our active mines.
Services. We also purchase services at our mine sites, including services related to maintenance for mining equipment, construction, temporary labor, use of explosives and various other requirements. We do not believe that we have undue operational or financial risk associated with our dependence on any individual service providers.
Competition
Demand for coal and the prices that we will be able to obtain for our coal are highly competitive and influenced by factors beyond our control, including but not limited to global economic conditions, the demand for electricity and steel, the cost of alternative fuels, the cost of electricity generation from alternative fuels, including wind, solar, oil, hydro, nuclear, natural gas and biomass, the impact of weather on heating and cooling demand and taxes and environmental regulations imposed by the U.S. and foreign governments.
Thermal Coal
Demand for our thermal coal products is impacted by economic conditions and demand for electricity and the cost of electricity generation from coal and alternative fuels, and our products compete with producers of other forms of electric generation, including natural gas, oil, nuclear, hydro, wind, solar and biomass, that provide an alternative to coal use. The use and price of thermal coal is heavily influenced by the availability and relative cost of alternative fuels and the generation of electricity utilizing alternative fuels, with customers focused on securing the lowest cost fuel supply in order to coordinate the most efficient utilization of generating resources in the economic dispatch of the power grid at the most competitive price.
In the U.S., natural gas is highly competitive (along with other alternative fuel sources) with thermal coal for electricity generation. The competitiveness of natural gas has been strengthened by accelerated growth in domestic natural gas production and transmission facilities over the last five years and comparatively low natural gas prices (versus historic levels). In 2016, electricity generation from coal was negatively impacted primarily by low-priced natural gas, which fell to an average price of $2.55 per mmBtu, as well as by the relatively mild temperatures in the first half of 2016 that reduced overall electricity demand. Gas prices averaged $2.12 per mmBtu in the first half of 2016, and $2.98 per mmBtu in the second half of 2016. These natural gas price trends significantly impacted U.S. coal burn and production in 2016, where major producers’ shipments in the second half of 2016 were substantially higher than in the first half. We believe the U.S. Powder River and Illinois basins in which we produce are competitive against natural gas when natural gas prices are in excess of $3.00 per mmBtu. In addition, the competitiveness of other alternative fuel sources for electricity generation with coal has been strengthened by the growth of low-cost generation fueled by other alternative fuel sources.
Peabody Energy Corporation | 2016 Form 10-K | 7 |
Internationally, thermal coal also competes with alternative forms of electric generation. The competitiveness and availability of natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of indigenous coal production, particularly in the two leading coal import countries, China and India, among others, and the competitiveness of seaborne supply from leading thermal coal exporting countries, including Indonesia, Australia, Russia, Colombia and South Africa, among others.
In addition to our alternative fuel source competitors, 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., Cloud Peak Energy Inc., and Murray Energy Corporation, which collectively accounted for approximately 42% of total U.S. coal production in 2015 according to the National Mining Association's "2015 Coal Producer Survey," the most recent data publicly available as of March 20, 2017. Major international direct coal supply competitors (listed alphabetically) include Anglo-American PLC, BHP Billiton, China Coal, Coal India Limited, Glencore PLC, PT Bumi Resources Tbk., Rio Tinto and Shenhua Group, among others.
Metallurgical Coal
Demand for our metallurgical coal products is impacted by economic conditions and demand for steel, and 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.
Seaborne metallurgical coal import demand can be significantly impacted by the availability of indigenous coal production, particularly in leading metallurgical coal import countries of China, India, Japan, South Korea and Brazil, among others, and the competitiveness of seaborne metallurgical coal supply, including from leading metallurgical coal exporting countries of Australia, U.S., Russia, Canada, and Mongolia, among others.
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, among others.
Working Capital
We generally fund our working capital requirements through a combination of existing cash and cash equivalents, proceeds from the sale of our coal production to customers and our trading and brokerage activities. Our current accounts receivable securitization program is also available to fund our working capital requirements to the extent we have remaining availability under the program. On January 27, 2017, we obtained a commitment letter (Commitment Letter) from PNC Bank, National Association (PNC), pursuant to which PNC has agreed to amend and restate our existing securitization program effective as of the Plan Effective Date to, among other things, provide for the exit from the Chapter 11 Cases, add certain Australian subsidiaries as originators, extend the termination date to three years from the Plan Effective Date and increase the maximum funding limit to up to $250 million (subject to reductions prior to the Plan Effective Date to an amount no less than $200 million). PNC's obligation to provide the new securitization program is also subject to a number of customary conditions precedent. On February 15, 2017, the Bankruptcy Court issued an order authorizing the Company’s entry into and performance under the Commitment Letter. 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.
Employees
We had approximately 6,700 employees as of December 31, 2016, including approximately 5,100 hourly employees. Additional information on our employees and related labor relations matters is contained in Note 24. "Management - Labor Relations" to our consolidated financial statements, which information is incorporated herein by reference.
Peabody Energy Corporation | 2016 Form 10-K | 8 |
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 | 49 | President and Chief Executive Officer | ||
Amy B. Schwetz | 42 | Executive Vice President and Chief Financial Officer | ||
A. Verona Dorch | 50 | Executive Vice President, Chief Legal Officer, Government Affairs and Corporate Secretary | ||
Bryan A. Galli | 56 | Group Executive of Marketing and Trading | ||
Charles F. Meintjes | 54 | President - Australia | ||
Kemal Williamson | 57 | President - Americas | ||
(1) As of March 15, 2017.
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, holds a master’s degree in business administration and a bachelor’s degree in commerce from the University of Newcastle, and is a Fellow of CPA Australia. 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.
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 legal and government relations 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, Chief Compliance Officer and Corporate Secretary. Ms. Dorch also has experience in corporate and securities law from various law firms and with Sumitomo Chemical Co. Ms. Dorch holds a bachelor’s degree from Dartmouth College and a Juris Doctor degree from Harvard Law School.
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.
Peabody Energy Corporation | 2016 Form 10-K | 9 |
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.
On March 15, 2017, we announced that Mr. Meintjes will assume the role of Executive Vice President - Corporate Services and Chief Commercial Officer effective following our emergence from our Chapter 11 Cases and George J. Schuller, the current Chief Operations Officer in Australia, will fill the role of President - Australia.
Kemal Williamson was named our President - Americas in October 2012. He has executive responsibility for our U.S. operating platform, which includes overseeing the areas of health and safety, operations, product delivery and support functions. Mr. Williamson has more than 30 years of experience in mining engineering and operations roles across North America and Australia. He most recently served as Group Executive Operations for the Peabody Energy Australia operations. He also has held executive leadership roles across project development, as well as in positions overseeing our Western U.S., Powder River Basin and Midwest operations. Mr. Williamson joined us in 2000 as Director of Land Management. Prior to that, he served for two years at Cyprus Australia Coal Corporation as Director of Operations and managed coal operations in Australia for half a decade. He also has mining engineering, financial analysis and management experience across Colorado, Kentucky and Illinois. Mr. Williamson holds a Bachelor of Science degree in mining engineering from Pennsylvania State University as well as a Master of Business Administration degree from the Kellogg School of Management, Northwestern University in Evanston, Illinois.
Regulatory Matters — U.S.
Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations.
We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry.
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.
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 MSHA compliance, through the mine safety disclosures required by SEC regulations.
Peabody Energy Corporation | 2016 Form 10-K | 10 |
Black Lung (Coal Worker's Pneumoconiosis)
Under the U.S. 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 who last worked for the operator after July 1, 1973, and whose claims for benefits are allowed. 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, very few of the miners who sought federal black lung benefits were 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 underground 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 primary regulatory authority, with oversight from OSM. 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.
SMCRA provides for three categories of bonds: surety bonds, collateral bonds and self-bonds. A surety bond is an indemnity agreement in a sum certain payable to the regulatory authority, executed by the permittee as principal and which is supported by the performance guarantee of a surety corporation. A collateral bond can take several forms, including cash, letters of credit, first lien security interest in property or other qualifying investment securities. A self-bond is an indemnity agreement in a sum certain executed by the permittee or by the permittee and any corporate guarantor made payable to the regulatory authority.
Our total reclamation bonding requirements in the U.S. were $1,413.8 million as of December 31, 2016. The bond requirements for a mine represent the calculated cost to reclaim the current operations of a mine if it ceased to operate in the current period. The cost calculation for each bond must be completed according to the regulatory authority of each state. Our asset retirement obligations calculated in accordance with generally accepted accounting principles for our U.S. operations were $471.1 million as of December 31, 2016. The bond requirement amount for our U.S. operations significantly exceeds the financial liability for final mine reclamation because the asset retirement obligation liability is discounted from the end of the mine’s economic life to the balance sheet date in recognition that the final reclamation cash outlay is a number of years (and in some cases decades) away. The bond amount, in contrast with the asset retirement obligation, presumes reclamation begins immediately.
As a condition precedent to the occurrence of the Effective Date of the Plan, we were required to put in place mutually acceptable forms of bonding for coal mine reclamation requirements in Wyoming, New Mexico, Illinois and Indiana subsequent to the Effective Date. On March 6, 2017, we notified the Bankruptcy Court that we had determined to secure all our coal mine reclamation obligations, including those in Wyoming, New Mexico, Illinois and Indiana, by arranging for approximately $1.3 billion in surety bonds.
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 bonding requirements.
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.
Peabody Energy Corporation | 2016 Form 10-K | 11 |
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 based on changes in federal legislation. 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. We recognized expense related to the fees of $38.7 million, $47.0 million and $50.5 million for the years ended December 31, 2016, 2015 and 2014, 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, designating new nonattainment areas or expanding existing nonattainment areas, requiring changes in vehicle emission standards or prompting additional local control measures pursuant to state implementation plans required to address revised NAAQS.
In recent years the United States Environmental Protection Agency (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. The EPA subsequently issued a final rule setting the ozone standard at 70 parts per billion (ppb). (80 Fed. Reg. 65,292, (Oct. 25, 2015)). This final rule has been challenged in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit) and the oral argument is scheduled for April 19, 2017. More stringent ozone standards require new state implementation plans to be developed and filed with the EPA, may trigger additional control technology for mining equipment, or result in additional challenges to permitting and expansion efforts.
In 2009, the EPA also adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. The PM NAAQS was thereafter revised and made more stringent. The D.C. Circuit subsequently upheld the revised PM NAAQS (National Association of Manufacturers v. EPA, Nos. 13-1069, 13-1071 (May 9, 2014)). In addition, since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions.
The CAA also indirectly, but 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, imposing more capital and operating costs on such facilities. In addition, other CAA programs may require further emission reductions to address the interstate transport of air pollution or regional haze. 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 such as the Cross-State Air Pollution Rule, New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and source permitting programs, including requirements related to New Source Review.
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, utilization and storage (CCUS). 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.).
Peabody Energy Corporation | 2016 Form 10-K | 12 |
Numerous legal challenges to the final rule have been filed in the 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. Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Generating Units; Notice of final action denying petitions for reconsideration.” States and other organizations have intervened on behalf of the EPA. Upon petitioners’ request, the D.C. Circuit suspended the briefing schedule and consolidated the challenges to the EPA’s denial of petitions for reconsideration with the previously filed North Dakota case. On August 30, 2016, the Court entered a briefing schedule under which final briefs were due February 6, 2017. Oral arguments have been scheduled for April 17, 2017.
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 were required to submit their proposed implementation plans to the EPA by September 6, 2016, unless an extension was 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 reduce 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 acknowledged that a legal challenge could be filed after the EPA issued a final rule. In September 2015 the D.C. Circuit refused to stay the rule, holding that it could not review the rule until it was published in the Federal Register which occurred on October 23, 2015.
Following Federal Register publication of the rule on October 23, 2015, 39 separate petitions for review by approximately 157 entities were filed in 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 the EPA.
On January 21, 2016, the D.C. Circuit 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 stay 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. The stay provides that, if a writ of certiorari is sought and the Supreme Court denies the petition, the stay will terminate automatically. The stay also provides that, if the Supreme Court grants the petition for a writ of certiorari, the stay will terminate when the Supreme Court enters its judgment. Briefing on the merits of the petitions for review in the D.C. Circuit has concluded. The case was heard en banc by ten active D.C. Circuit judges on September 27, 2016.
Peabody Energy Corporation | 2016 Form 10-K | 13 |
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 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 the 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 the 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. The EPA now requires sources that are otherwise “major” sources of conventional pollutants to apply best available control technology for GHG emissions, if those emissions would have the potential to exceed 75,000 tons per year. Individual states may have additional permitting requirements for GHGs.
Cross State Air Pollution Rule (CSAPR). On July 6, 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions was to commence in 2012 with further reductions effective in 2014. In October 2011, the EPA proposed amendments to the CSAPR to increase emission budgets in ten states, including Texas, and ease limits on market-based compliance options. While the CSAPR had an initial compliance deadline of January 1, 2012, the rule was challenged and, on December 30, 2011, the D.C. Circuit stayed the rule and advised that the EPA was expected to continue administering the Clean Air Interstate Rule until the pending challenges are resolved. The court vacated the CSAPR on August 21, 2012, in a two-to-one decision, concluding that the rule was beyond the EPA's statutory authority. The U.S. Supreme Court on April 29, 2014 reversed the D.C. Circuit and upheld the CSAPR, concluding generally that the EPA’s development and promulgation of CSAPR was lawful, while acknowledging the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. In October 2014, the D.C. Circuit filed an order lifting its stay of CSAPR and addressing a number of preliminary motions regarding the implementation of the Supreme Court’s remand. On remand, the D.C. Circuit held on July 28, 2015 that certain of the 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. The EPA indicated that this rule was a “partial response” to the D.C. Circuit’s remand of CSAPR as well as to address implementation of the 2008 ozone NAAQS. This rule, known as the CSAPR Update Rule, was signed by the EPA Administrator on September 7, 2016. The CSAPR Update Rule implements further reductions in nitrogen oxides in 2017 in 22 states subject to CSAPR during the summertime ozone season. The EPA did not address other aspects of the remand involving the CSAPR budgets for sulfur dioxide in four states. Several states and utilities as well as agricultural and industry groups utilities have filed petitions for review of the CSAPR Update Rule in the D.C. Circuit. Other states and interest groups have filed to intervene on behalf of the EPA. These petitions have been consolidated under D.C. Cir. No. 16-1406.
Mercury and Air Toxic Standards (MATS). The EPA published the final MATS rule in the Federal Register on February 16, 2012. The MATS rule revised the NSPS for nitrogen oxides, sulfur dioxides and particulate matter for new and modified coal-fueled electricity generating plants, and imposed MACT emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. The rule provided three years for compliance with MACT standards and a possible fourth year if a state permitting agency determined that such was necessary for the installation of controls.
Following issuance of the final rule, numerous petitions for review were filed. The D.C. Circuit upheld the NSPS portion of the rulemaking in a unanimous decision on March 11, 2014, and upheld the limits on HAPs 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 HAPs from power plants. The court reversed the D.C. Circuit and remanded the case for further proceedings. On December 1, 2015, in response to the court’s decision the EPA published a proposed supplemental finding in the Federal Register that consideration of costs does not alter the EPA’s previous determination regarding the control of HAPs in the MATS rule. On December 15, 2015, the D.C. Circuit issued an order providing that the rule will remain in effect while the EPA responds to the U.S. Supreme Court decision.
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On April 14, 2016, the EPA issued a final supplemental finding that largely tracked its proposed finding. Several states, companies and industry groups challenged that supplemental finding in the D.C. Circuit in separate petitions for review, which were subsequently consolidated. Several states and environmental groups also filed as intervenors for the respondent EPA. Briefing commenced in December 2016 and has now concluded. Oral argument has been scheduled for May 18, 2017.
Stream Protection Rule. On July 27, 2015, the OSM issued its proposed Stream Protection Rule (SPR). The proposed rule would have impacted both surface and underground mining operations and would have increased testing and monitoring requirements related to the quality or quantity of surface water and groundwater or the biological condition of streams. The SPR would have also required 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. Both chambers of Congress have already passed legislation to repeal and invalidate the rulemaking, pursuant to the Congressional Review Act. The House passed H.J. Res. 38 on February 1, 2017 and the Senate passed the bill the next day. On February 16, 2017, President Trump signed H.J. Res. 38, resulting in the repeal of the SPR and preventing the OSMRE from promulgating any substantially similar rule.
Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.
The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain Corps permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.
States are empowered to develop and apply “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the CWA section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.
A final rule defining the scope of waters protected under the Clean Water Act (commonly called the Waters of the United States (WOTUS) Rule) was published by the EPA and the Corps in June 2015. Numerous lawsuits were filed in district courts and courts of appeals nationwide, and all courts of appeals challenges were consolidated in the U.S. Court of Appeals for the Sixth Circuit. District courts in Oklahoma and Georgia dismissed challenges for lack of jurisdiction, but a preliminary injunction was issued by the U.S. District Court in North Dakota in August 2015. On October 9, 2015, the Sixth Circuit stayed the WOTUS Rule nationwide pending further action of the court. On February 22, 2016, a three member panel of the Sixth Circuit held that the Sixth Circuit has exclusive jurisdiction to review challenges to the rule. A request for an en banc hearing was denied. The Tenth and Eleventh Circuits, which are presiding over appeals of the dismissals from Oklahoma and Georgia (respectively), have since stayed proceedings in those appeals. On October 7, 2016, several industry trade organizations and associations filed a petition requesting that the U.S. Supreme Court review the decision of the Sixth Circuit to exercise exclusive jurisdiction over challenges to the rule. The petition was granted on January 13, 2017. Since the Supreme Court agreed to take the case, it has extended the briefing schedule and postponed oral argument until late 2017 at the earliest. On February 28, 2017 the Trump Administration released an Executive Order directing the EPA and the Corps to consider rescinding or revising the WOTUS Rule, and the EPA and the Corps issued a similar notice that same day. The Department of Justice has notified the courts of this development and has filed a motion in the Supreme Court to halt all proceedings. The Supreme Court is scheduled to consider all briefing on that motion during its March 31, 2017 conference. Additionally, because the Sixth Circuit did not automatically halt its briefing schedule on the merits of the WOTUS Rule after the Supreme Court decided to hear the appeal of the jurisdictional decision, the industry coalition filed a petition asking the Sixth Circuit to do so. That petition was granted two days later and, as such, the Sixth Circuit litigation is now being held in abeyance pending the Supreme Court’s decision. Importantly, the Sixth Circuit’s order holding the case in abeyance did not lift the current nationwide stay against implementation of the WOTUS Rule, and therefore the stay will remain effective during the Supreme Court’s review, which could be held in abeyance if the Supreme Court grants the Department of Justice's recent motion. 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.
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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 (CCR or 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 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.
Office of Surface Mining Reclamation and Enforcement Self-Bonding Notice of Rulemaking. On August 16, 2016, the Office of Surface Mining Reclamation and Enforcement (OSMRE) announced a decision to initiate a rulemaking process to update OSMRE’s bonding regulations. The decision stated that the OSMRE will be reviewing the self-bonding program and will consider revising the review process for determining if a company qualifies for self-bonding as well as the process for replacing self-bonds in the event a company no longer qualifies for self-bonding. There is no anticipated timing for the proposed rule and it is unknown whether the new Director of OSMRE will continue with the proposed rulemaking.
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 was amended effective September 27, 2016 to include significant changes to the management of overlapping coal and coal seam gas tenements and the coordination of activities and access to private and public land. In November 2016, amendments to the EP Act and the Water Act 2000 became effective and facilitate regulatory scrutiny of the environmental impacts of underground water extraction during the operational phase of resource projects for all tenements yet to commence mineral extraction. The ‘Chain of Responsibility’ provisions of the EP Act, effective in April 2016, allow the regulator to issue an environmental protection order (EPO) to a related person of a company in two circumstances; (a) if an EPO has been issued to the company, an EPO can also be issued to a related person of the company (at the same time or later); or (b) if the company is a high risk company (as defined in the EP Act), an EPO can be issued to a related person of the company (whether or not an EPO has also been issued to the company). A guideline has been issued to provide more certainty to industry on the circumstances when an EPO may be issued.
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.
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Mining Rehabilitation (Reclamation). Mine reclamation is regulated by state specific legislation. As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding to the relevant state government as a safeguard to cover the costs of reclamation in circumstances where mine operators are unable to do so. Self-bonding is not permitted. Our mines hold bonds with the relevant authorities which are calculated in accordance with current regulatory requirements. We operate in both the Queensland and New South Wales state jurisdictions.
Our reclamation bonding requirements in Australia were $379.4 million Australian dollars as of December 31, 2016. The bond requirements represent the calculated cost to reclaim the current operations of a mine if it ceased to operate in the current period less any discounts agreed with the state. The cost calculation for each bond must be completed according to the regulatory authority of each state. The costs associated with our Australian asset retirement obligations are calculated in accordance with generally accepted accounting principles and were $287.7 million as of December 31, 2016. The total bonding requirements for our Australian operations differ from the calculated costs associated with the asset retirement obligations because the costs associated with asset retirement obligations are discounted from the end of the mine’s economic life to the balance sheet date in recognition of the economic reality that reclamation is conducted progressively and final reclamation is a number of years (and in some cases decades) away, whereas the bonding amount represents the cost of reclamation if a mine ceases to operate immediately.
New South Wales reclamation. The Mining Act 1992 (Mining Act) is administered by the Department of Industry - Resources & Energy and authorizes the holder of a mining tenement to extract a mineral subject to obtaining consent under the Environmental Planning & Assessment Act 1979 and other auxiliary approvals and licenses.
Through the Mining Act, environmental protection and reclamation are regulated by conditions in all mining leases including requirements for the submission of a Mining Operations Plan (MOP) prior to the commencement of operations. All mining operations must be carried out in accordance with the MOP which describes site activities and the progress toward environmental and reclamation outcomes and are updated on a regular basis or if mine plans change. The mines publicly report their reclamation performance on an annual basis.
In support of the MOP process, a reclamation cost estimate is calculated periodically to determine the amount of bond support required to cover the cost of reclamation based on extent of disturbance during the MOP period.
Queensland reclamation. The Environmental Protection Act 1994 (EP Act) is administered by the Department of Environment and Heritage Protection which authorizes environmentally relevant activities such as mining activities relating to a mining lease through an Environmental Authority (EA). Environmental protection and reclamation activities are regulated by conditions in the EA, including the requirement for the submission of a Plan of Operations (PO) prior to the commencement of operations. All mining operations must be carried out in accordance with the PO which describes site activities and the progress toward environmental and rehabilitation outcomes and are updated on a regular basis or if mine plans change. The mines submit an annual return reporting on their EA compliance including reclamation performance.
As a condition of the EA, bonding requirements are calculated to determine the amount of bonding required to cover the cost of reclamation based on extent of disturbance during the PO period.
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.
A small number of coal mine workers in Queensland and New South Wales have been diagnosed with coal worker's pneumoconiosis (CWP, also known as black lung) following decades of assumed eradication of the disease. This has led the Queensland government to sponsor review of the system of screening coal mine workers for the disease with a view to improving early detection. The Queensland government has instituted increased reporting requirements for dust monitoring results, broader coal mine worker health assessment requirements and voluntary retirement examinations for coal mine workers to be arranged by the relevant employer and further reform may follow. Peabody has undertaken a review of its practices and offered its Queensland workers the opportunity for additional CWP screening.
The Queensland government is holding a Parliamentary inquiry into the re-emergence of CWP in the State and is holding public hearings with representatives of the coal mining industry, including Peabody, coal mine workers, the Department of Natural Resources and others appearing. The inquiry is due to report to the Queensland Parliament in April 2017
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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 implemented the Emission Reduction Fund Safeguard Mechanism. From that date, large designated facilities such as coal mines were issued with a baseline for their covered emissions and must take steps to keep their emissions below the baseline or face penalties.
Queensland Royalty. Royalties are payable to the State of Queensland at a rate of 12.5% on coal prices over $100 Australian dollars per tonne and up to $150 Australian dollars per tonne and 15% on pricing over $150 Australian dollars per tonne. The rate is 7% 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.
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 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. The 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. The EPA has also set standards applying to new, modified and reconstructed sources beginning in 2015.
A number of states in the U.S. have adopted programs to regulate greenhouse gas emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, which is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. In 2011, New Jersey announced its withdrawal from RGGI effective January 1, 2012. Six mid-western 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.
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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 Minnesota, an administrative proceeding recommended an approach based on the Federal Social Cost of Carbon to the Minnesota Public Utilities Commission. The Minnesota Public Utilities Commission will hold hearings on the recommendation in the first and second quarter of 2017. In 2016, the state of Washington considered Ballot Initiative 732, the "Washington Carbon Emission Tax and Sales Tax Reduction," which proposed to impose a new tax on carbon emissions beginning at $15 per metric ton in 2017, and increasing each year until it reached $100 per metric ton. The proposal was ultimately voted down in the November 8 election, with 60% opposed.
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 was entered into force on November 4, 2016 after ratification and execution by more than 55 countries that account for at least 55% of global greenhouse gas emissions.
Australia's Parliament passed carbon pricing legislation in November 2011. The first three years of the program involved the imposition of a carbon tax that commenced in July 2012 and a mandatory greenhouse gas emissions trading program commencing in 2015. On July 16, 2014, Australia's Parliament repealed the legislation, which was retrospectively abolished from July 1, 2014.
Enactment of laws or passage of regulations by the U.S. or some of its states or by other countries regarding emissions from the mining of coal, or other actions to limit such emissions, are not expected to have a material adverse effect on our results of operations, financial condition or cash flows.
Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on us of future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of commercial development and deployment of CCUS technologies and the alternative uses 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.
Peabody Energy Corporation | 2016 Form 10-K | 20 |
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.
Peabody Energy Corporation | 2016 Form 10-K | 21 |
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 Chapter 11 Cases
We are subject to risks and uncertainties associated with our Chapter 11 Cases.
On April 13, 2016 (Petition Date), we and a majority of our wholly owned domestic subsidiaries as well as one international subsidiary in Gibraltar (the Filing Subsidiaries, and together with Peabody, the Debtors) filed voluntary petitions for reorganization under Chapter 11 of Title 11 of the U.S. Code in the United States Bankruptcy Court for the Eastern District of Missouri (the Bankruptcy Court). Our Australian Operations are not included in the filings. Our Chapter 11 Cases are being jointly administered under the caption In re Peabody Energy Corporation, et al., Case No. 16-42529 (the Chapter 11 Cases). On January 27, 2017, the Debtors filed with the Bankruptcy Court the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, the Plan). On March 15, 2017, the Debtors filed an amended version of the Plan, which was confirmed by the Bankruptcy Court by order entered March 17, 2017. There can be no assurance that the Plan will be implemented successfully. Until the Plan Effective Date, the Debtors will continue to operate the business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
We are subject to a number of risks and uncertainties associated with the Chapter 11 Cases, which may lead to potential adverse effects on our liquidity, results of operations, condition (financial or otherwise), brand or business prospects. Our operations, our ability to develop and execute our business plan, our financial condition, our liquidity, and our continuation as a going concern, are all subject to the risks and uncertainties associated with our Chapter 11 Cases. These risks and uncertainties include, but are not limited to, the following:
• | whether the conditions to consummate the transactions contemplated by the Plan will be satisfied or waived; |
• | our ability to comply with and operate under any cash management orders by the Bankruptcy Court from time to time; |
• | the high costs of Chapter 11 proceedings and related professional costs and fees; |
• | our ability to attract, motivate, and retain key personnel, especially in our current constrained compensation environment; |
• | our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties; |
• | our ability to maintain critical contracts on reasonably acceptable terms and conditions; |
• | the ability of third parties to seek and obtain relief from the automatic stay to terminate contracts and other agreements with us; |
• | the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans; |
• | our ability to self-bond or obtain adequate surety bonds with respect to our reclamation obligations, both during the Chapter 11 Cases and upon emergence from our Chapter 11 Cases; and |
• | the possibility that the Chapter 11 Cases will disrupt or impede our international operations, including our Australian Operations. |
These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with our Chapter 11 Cases could adversely affect our relationships with our suppliers, vendors, customers, and employees. In particular, critical suppliers, vendors and customers may determine not to do business with us due to our Chapter 11 Cases, and we may not be successful in securing alternative sources or markets. Under Chapter 11 of the Bankruptcy Code, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities. Additionally, further losses of key personnel or erosion of employee morale could have a material adverse effect on our ability to meet customer expectations, thereby adversely affecting our business and results of operations. The failure to retain or attract and maintain members of our management team, and other key personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations. As a result of these risks and uncertainties, we cannot predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.
Peabody Energy Corporation | 2016 Form 10-K | 22 |
The Plan may not become effective.
While the Plan has been confirmed by the Bankruptcy Court, it may not become effective because it is subject to the satisfaction of certain conditions precedent (some of which are beyond our control). There can be no assurance that such conditions will be satisfied, and therefore, that the Plan will become effective and that the Debtors will emerge from the Chapter 11 Cases as contemplated by the Plan. If the Plan Effective Date is delayed, the Debtors may not have sufficient cash available in order to operate their business. In that case, the Debtors may need new or additional post-petition financing, which may increase the costs of consummating the Plan. There is no assurance of the terms on which such financing may be available or if such financing will be available. If the transactions contemplated by the Plan are not completed, it may become necessary to amend the Plan. The terms of any such amendment are uncertain and could result in material additional expense and result in material delays in the Chapter 11 Cases.
If the Plan does not become effective, if current financing is insufficient, or if other financing is not available, we could be required to seek a sale of the Company or certain of its material assets pursuant to Section 363 of the Bankruptcy Code, or be required to liquidate under Chapter 7 of the Bankruptcy Code.
In order to successfully emerge from Chapter 11 bankruptcy protection, a plan of reorganization must become effective. There can be no assurance that the Plan Effective Date will occur, which would permit us to emerge from our Chapter 11 Cases and continue operations. If we are unable to meet our liquidity needs, we may have to take other actions to seek additional financing to the extent available or we could be forced to consider other alternatives to maximize potential recovery for the creditors, including possible sale of the Company or certain material assets pursuant to Section 363 of the Bankruptcy Code, or liquidate under Chapter 7 of the Bankruptcy Code.
There can be no assurance that our current cash position, as well as funds available from our accounts receivable securitization program, and amounts of cash from future operations, will be sufficient to fund ongoing operations during the Chapter 11 Cases. In the event that we do not have sufficient cash to meet our liquidity requirements, and our current financing is insufficient or exit financing is not available in connection with our emergence under a Chapter 11 plan of reorganization, we may be required to seek additional financing. There can be no assurance that such additional financing would be available, or, if available, would be available on reasonably acceptable terms. Failure to secure any necessary exit financing, or additional financing, would have a material adverse effect on our operations and ability to continue as a going concern.
Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, or adverse market conditions persist or worsen, our plan may be unsuccessful in its execution.
Any plan of reorganization that we may implement, including the Plan, will affect our capital and the ownership and structure of our business, and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions, and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to: (i) our ability to substantially change our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and coal industries, both in the U.S. and in global markets. The failure of any of these factors could materially and adversely affect the successful reorganization of our business.
In addition, any plan of reorganization, including the Plan, will rely upon financial projections, including with respect to revenues, Adjusted EBITDA, capital expenditures, debt service, cash flow and coal price projections. Financial projections are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be realized. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us or our business or operations. The failure of any such results or developments to materialize as anticipated could materially and adversely affect the successful execution of any plan of reorganization.
Peabody Energy Corporation | 2016 Form 10-K | 23 |
Certain claims may not be discharged and could have a material adverse effect on our financial condition and results of operations.
The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to our filing a petition for reorganization under the Bankruptcy Code or before the confirmation of the Plan (a) were subject to compromise and/or treatment under the Plan and/or (b) will be discharged in accordance with the terms of the Plan on the Plan Effective Date. Any claims not ultimately discharged through the Plan could be asserted against us and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.
Operating in bankruptcy for a long period of time may harm our business.
Our future results will be dependent upon the successful implementation of a plan of reorganization. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations, and liquidity. So long as the proceedings related to these cases continue, senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on business operations. A prolonged period of operating under Bankruptcy Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the proceedings related to the Chapter 11 Cases continue, the more likely it is that customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships.
So long as the proceedings related to these cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases, including the cost of litigation. In general, litigation can be expensive and time consuming to bring or defend against. Such litigation could result in settlements or damages that could significantly affect our financial results. It is also possible that certain parties will commence litigation with respect to the treatment of their claims under the Plan. It is not possible to predict the potential litigation that we may become party to, nor the final resolution of such litigation. The impact of any such litigation on our business and financial stability, however, could be material.
Should the Chapter 11 proceedings continue beyond our current targeted emergence date in early April 2017, we may also need to seek new financing to fund operations. If we are unable to obtain such financing on favorable terms or at all, the chances of successfully reorganizing our business may be seriously jeopardized and the likelihood that we will instead be required to liquidate our assets may increase.
As a result of the Chapter 11 Cases, our historical financial information will not be indicative of our future financial performance and realization of assets and liquidation of liabilities are subject to uncertainty.
Our capital structure will be significantly altered through the implementation of the Plan. As a result of the consummation of the Plan and the transactions contemplated thereby, we expect to be subject to the fresh start reporting rules required under the Financial Accounting Standards Board Accounting Standards Codification Topic 852, Reorganizations. Under applicable fresh start reporting rules that may apply to us upon the Plan Effective Date, our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, our consolidated financial condition and results of operations from and after the Plan Effective Date will not be comparable to the financial condition or results of operations reflected in our consolidated historical financial statements.
In connection with the implementation of the Plan, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such sales, disposals, liquidations, settlements, or charges could be material to our consolidated financial position and the results of operations in any given period.
Peabody Energy Corporation | 2016 Form 10-K | 24 |
Our ability to use our pre-emergence tax attributes may be significantly limited under the U.S. federal income tax rules.
We have generated net operating losses and certain tax credits for U.S. federal income tax purposes (NOLs) through the taxable year ending December 31, 2016. We expect to incur substantial additional NOLs through the Plan Effective Date. Our NOLs and other tax attributes, including our tax basis in assets, are subject to reduction on account of cancellation of indebtedness income. Moreover, our ability to use any remaining NOLs and other tax attributes, and possibly any recognized built in losses, to offset future taxable income or taxes owed may be significantly limited if we undergo an “ownership change” as defined in section 382 of the Internal Revenue Code of 1986 as amended (the Code) in connection with the Plan and do not qualify or elect to use a special bankruptcy rule. An entity that experiences an ownership change generally is subject to an annual limitation on its use of its pre-ownership change NOLs and other tax attributes after the ownership change equal to the equity value of the corporation immediately before the ownership change, multiplied by the long term tax exempt rate posted by the Internal Revenue Service (subject to certain adjustments). If we undergo an ownership change in connection with the Plan, however, we will be allowed to calculate the limitation on NOLs and other tax attributes, in general, by reference to our equity value immediately after the ownership change (rather than the equity value immediately before the ownership change, as is the case under the general rule for non-bankruptcy ownership changes), thus generally reflecting any increase in the value of the stock due to the cancellation of debt resulting from the Plan. The annual limitation could also be increased each year to the extent that there is an unused limitation in a prior year. Alternatively, if we qualify for and elect to use a special bankruptcy rule that would prevent a limitation on use of the tax attributes from applying, our NOLs would first be reduced to the extent of certain prior interest deductions taken on account of indebtedness that will be converted into equity under the Plan, but the annual limitation would be zero and we will lose the use of the entire NOLs in the event we experience another ownership change within two years after the Plan Effective Date. We anticipate that we will experience an ownership change as a result of the Plan; accordingly, the ability to use pre-change tax attributes to offset our future taxable income or taxes owed pre-ownership may be significantly limited.
Consummation of the Plan may impair certain of the tax assets of our Australian operations.
Our Australian operations have had significant net operating losses for Australian income tax purposes (Australian NOLs) through the taxable year ending December 31, 2016. The use of Australian NOLs is subject to our Australian operations satisfying the Continuity of Ownership Test (COT) in the first instance, or if that test is failed, the Same Business Test (the SBT). If our Australian operations satisfy either the COT or the SBT, they can apply Australian NOLs against Australian taxable income.
Our Australian operations currently rely on concessional ownership tracing rules to support the position that the operations continue to satisfy the COT. However, continuing to satisfy the COT depends upon there being at least 50 stockholders at all times prior to, during and immediately after the consummation of the Plan, of which 20 stockholders or fewer are not able to control 75% of the rights to vote, entitlement to dividends or rights to distributions on winding up. It is possible that the consummation of the Plan may cause our Australian operations to fail the COT. Should that happen, our Australian operations are able to fall back on the SBT, which generally requires that from the time the losses were incurred until the income year in which the Australian NOLs are sought to be used, the operations carried on substantially the same business and that during the same period the group did not enter into any new transactions of a kind it had previously not entered into. In the event that our Australian operations cannot satisfy either the COT or the SBT, although the NOLs are not technically canceled, the Australian NOLs cannot be used.
Peabody Energy Corporation | 2016 Form 10-K | 25 |
Risks Associated with Our Operations
Our profitability depends upon the prices we receive for our coal.
We operate in a competitive and highly regulated industry that for years has experienced strong headwinds. Decreased prices in the first three quarters of 2016 have reduced our revenues. For example, our revenues decreased during the year ended December 31, 2016 compared to the same period in 2015 by $893.9 million, primarily due to lower realized pricing and lower sales volumes driven by various demand and production factors. In the fourth quarter of 2016, the coal industry saw sharp upturns in seaborne metallurgical and thermal coal pricing primarily due to restrictive production policies in China. However, these recent industry events do not demonstrate that these prices will be sustainable in the future and the vast majority of third-party analysts project that prices are likely to decline. If coal prices decrease or return to depressed levels, our operating results and profitability and value of our coal reserves could be materially and adversely affected.
Coal prices are dependent upon factors beyond our control, including:
• | the demand for electricity; |
• | the strength of the global economy; |
• | the relative price of natural gas and other energy sources used to generate electricity; |
• | the demand for electricity and capacity utilization of electricity generating units (whether coal or non-coal); |
• | the demand for steel, which may lead to price fluctuations in the monthly and quarterly repricing of our metallurgical coal contracts; |
• | the global supply and production costs of thermal and metallurgical coal; |
• | changes in the fuel consumption and dispatch 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. |
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 we negotiate pricing for metallurgical coal contracts quarterly and seaborne thermal coal contracts annually, with a substantial portion sold on a shorter-term basis.
Thermal coal accounted for the majority of our coal sales during 2015 and 2016. The vast 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) utilization of all electricity generating units (whether using coal or not), including the relative cost of producing electricity from all fuels, including coal; (iv) increasingly stringent environmental and other governmental regulations; and (v) the coal inventories of utilities. Gas-fueled generation has displaced and is expected to continue 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 along with flat electricity demand 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 volume and price of coal that we mine and sell.
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% and 23% our coal sales revenue in 2015 and 2016, respectively. Deteriorating conditions in the steel industry, including the demand for steel and the continued financial condition of the industry, could 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.
Peabody Energy Corporation | 2016 Form 10-K | 26 |
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. The balance between coal demand and supply within the coal industry, factoring in demand and supply of closely related and competing segments such as natural gas, both domestically and internationally, could materially reduce coal prices and therefore materially reduce our revenues and profitability. We compete with producers of other low cost fuels used for electricity generation, such as natural gas and renewables. 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. Prices for coal vary by mining region and country. As a result, we cannot predict the future strength of the coal industry 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, 2016, we derived 28% of our total revenues from our five largest customers, similar to the prior year. Those five customers were supplied primarily from 24 coal supply agreements (excluding trading transactions) expiring at various times from 2017 to 2026. On an ongoing basis, we discuss the extension of existing agreements or entering into new long-term agreements with various customers, but these negotiations may not be successful and these customers may not continue to purchase coal from us under long-term 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.
Peabody Energy Corporation | 2016 Form 10-K | 27 |
One of our five largest customers is served by a single Peabody mine, included in our Western U.S. Mining operations, that has no other customers. Given the mine’s location, it is currently unable to economically market its coal to other utility customers. This mine has a contract to supply coal to the customer’s coal-fueled power plant through December 2019. The customer is owned by several private companies and one governmental entity. The non-governmental owners of the customer recently completed an evaluation of the plant and determined to continue operating the plant through December 2019, subject to certain conditions. Those non-governmental owners of the plant then issued a statement that they do not currently intend to be the operators the plant beyond December 2019; however, the United States Bureau of Reclamation -- also an owner of the customer -- has stated that it is investigating ways to continue operating the plant. The Company is currently discussing with the customer options to improve the plant’s economics. If the customer closes the plant, our Western U.S. Mining operations revenues, Adjusted EBITDA and cash flows would be materially reduced. We could also incur accelerated costs related to the mine’s closure and may be required to record asset impairment charges.
Our trading and hedging activities no longer cover certain risks, and may expose us to earnings volatility and other risks, including increasing requirements to post collateral.
We historically entered into hedging arrangements designed primarily to manage market price volatility of foreign currency (primarily the Australian dollar), diesel fuel and coal. Currently, we primarily enter into hedging arrangements designed to manage coal industry price through our trading and marketing functions; however, we may in the future enter into hedging arrangements to manage the volatility of foreign currency, diesel fuel, or other matters.
Some of these derivative trading instruments require us to post margin based on the value of those instruments and other credit factors. If the fair value of our hedge portfolio moves significantly, or if laws or regulations are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, we could be required to post additional margin. In addition, as a result of the Chapter 11 Cases and the volatility in global markets, we have increasingly been required to post margin under the requirements of these instruments. Further requirements to post margin could negatively impact our liquidity.
Through our trading and hedging activities, we are also exposed to 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.
We are currently subject to foreign currency exchange rate risk for non-U.S. dollar expenditures and balances and price risk on diesel fuel utilized in our mining operations. As noted above, we have historically used derivative financial instruments, including forward contracts, swaps and options, designated as cash flow hedges, to manage these risks. The Chapter 11 Cases constituted an event of default under these derivative financial instruments and the counterparties terminated the agreements shortly thereafter in accordance with contractual terms. As a result, we will be exposed to foreign currency exchange rate risk and the risk of fluctuations in the price of fuel.
Our operating results could be adversely affected by unfavorable economic and financial market conditions.
Our profits are affected, in large part, by industry conditions. Industry conditions are subject to a variety of factors beyond our control. 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. These conditions, among other factors, led to the filing of the Chapter 11 Cases. If any of these conditions return, if coal prices continue at or below levels experienced in 2015 and early 2016 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 will depend 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 if they fail to perform the terms of their contracts with us, our accounts receivable securitization program and our business could be adversely affected.
Peabody Energy Corporation | 2016 Form 10-K | 28 |
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.
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 $1.6 billion, with terms ranging up to 26 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 sometimes allow us to apply amounts paid for subsequent deliveries, but these provisions have limitations and we may not be able to apply all such amounts so paid in all cases. Also, we may not be able to utilize the amount of capacity for which we have 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.
Peabody Energy Corporation | 2016 Form 10-K | 29 |
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. We have completed several conversions to owner-operator status at certain of our Australian operations. Employee relations at mines that use contractors 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.
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. This may be mitigated by our application of fresh start reporting rules.
As described in Note 4. "Asset Impairment" to the accompanying consolidated financial statements, we recognized aggregate asset impairment costs of $247.9 million, $1,277.8 million and $154.4 million in 2016, 2015 and 2014, 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, 2016, we had approximately 6,700 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 5,100 hourly employees. Approximately 39% of our hourly employees were represented by organized labor unions and generated approximately 22% of 2016 coal production for the 12 months ended December 31, 2016. 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.
Peabody Energy Corporation | 2016 Form 10-K | 30 |
We could be adversely affected if we fail to appropriately provide financial assurances for our obligations.
U.S. federal and state laws and Australian laws require us to provide financial assurances related to requirements to reclaim lands used for mining, to pay federal and state workers’ compensation, to provide financial assurances for 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, 2016, we had $1,094.2 million of self-bonding in place for our U.S. coal mine reclamation obligations. As of December 31, 2016, we also had outstanding surety bonds with third parties, bank guarantees and letters of credit of $921.3 million, of which $607.5 million was for post-mining reclamation, $61.8 million related to workers’ compensation and other insurance obligations, $94.0 million was for coal lease obligations and $158.0 million was for other obligations, including road maintenance and performance guarantees. In addition, as of December 31, 2016, we had posted letters of credit and cash collateral in support of these financial instruments of $429.5 million. During 2015 and 2016, we were required to increase our total posted letters of credit to the issuing parties of certain of our surety bonds and bank guarantees, whereas we had not previously been required to do so. Surety bond issuers may demand additional collateral, which may in turn affect our available liquidity.
Our bonding obligations may increase due to a number of factors, and, upon our emergence from Chapter 11 or otherwise, we may not continue to qualify to self-bond or self-bonding programs may be terminated. Alternative forms of financial assurance such as surety bonds and letters of credit may not be available to us. Our failure to retain, or inability to obtain surety bonds, bank guarantees or letters of credit, or to provide a suitable alternative, could 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; and |
• | inability to provide or fund collateral for current and future third-party surety bond issuers. |
Our failure to maintain adequate bonding would invalidate our mining permits and prevent mining operations from continuing, which would cast substantial doubt on our ability to continue as a going concern.
Our mining operations are extensively regulated, which imposes 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, sediment and groundwater; |
• | air quality standards; |
• | water pollution; |
• | protection of human health, plant-life and wildlife, including endangered or threatened species and habitats; |
• | 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.
Peabody Energy Corporation | 2016 Form 10-K | 31 |
For additional information about the various regulations affecting us, see the sections entitled “Regulatory Matters —U.S.” and “Regulatory Matters — Australia”.
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.
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 permitting process, when we apply for permits and approvals, we are required to prepare and present to governmental authorities data pertaining to the potential impact or 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 (including modifications and renewals of certain 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 permitting requirements 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.
Peabody Energy Corporation | 2016 Form 10-K | 32 |
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.
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” involves 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, 2016, we leased a total of 59,626 acres from the federal government subject to those limitations. Many of these leases are in place for the next 20 years. On January 15, 2016, the Interior Department announced that it will perform a review of the federal coal leasing program. At that time, the Interior Department ordered a pause on issuing new coal leases which the Interior Department stated would continue for three years while the review of the federal coal leasing program occurs. 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. 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 and federal and state coal leases 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.
Peabody Energy Corporation | 2016 Form 10-K | 33 |
Our global operations increase our exposure to risks unique to international mining and trading operations.
Our international platform increases our exposure to country risks, international regulatory requirements 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 business and political risks, including political instability, heightened levels of corruption or fraud in certain markets, 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 perform due diligence, screening, training and auditing of internal and external business agents, vendors, partners and customers to mitigate these risks, our results of operations, financial position or cash flow could be adversely affected by these activities.
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.
We may undertake further repositioning plans that would require additional charges.
As a result of our continuing review of our business or changing demand, we may choose to further reduce our workforce in the future. These actions may result in further restructuring charges, 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.
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 $812.1 million as of December 31, 2016, of which $55.8 million was classified as a current liability. Certain of our U.S. subsidiaries also sponsor defined benefit pension plans. Net pension liabilities were $186.3 million as of December 31, 2016, of which none was classified a current liability.
Peabody Energy Corporation | 2016 Form 10-K | 34 |
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 Guaranty Corporation (PBGC) may terminate our plans under certain circumstances pursuant to ERISA, 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.
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 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.
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. 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 CCUS 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.
Peabody Energy Corporation | 2016 Form 10-K | 35 |
Risks Related to Our Indebtedness and Expected Post-Emergence Capital Structure under the Plan
If the Plan becomes effective, our common stock will be extinguished, canceled and discharged on the Plan Effective Date.
If the Plan becomes effective, our common stock will be extinguished, canceled and discharged on the Plan Effective Date. Under the Plan, holders of our common stock are not entitled to receive, and will not receive or retain, any property or interest in property on account of such equity interests. In the event of cancellation of our common stock, amounts invested by the holders will not be recoverable and the common stock will have no value. Trading prices for Peabody Energy's equity or other securities prior to the Plan Effective Date may bear little or no relationship to the actual recovery, if any, by the holders thereof on the Plan Effective Date. Our common stock may continue to trade even though it will be extinguished, canceled and discharged on the Plan Effective Date if the Plan becomes effective. Accordingly, Peabody Energy urges caution with respect to existing and future investments in its equity or other securities.
Following our expected emergence from our Chapter 11 Cases, we will continue to face a number of risks that could materially and adversely affect our business.
Following our expected emergence from our Chapter 11 Cases, we will continue to face a number of risks, including certain risks that are beyond our control, such as deterioration or other changes in economic conditions, changes in the industry, changes in customer demand for, and acceptance of, our coal, and increasing expenses. As a result of these risks and others, there is no guarantee that the Plan will achieve our stated goals.
Furthermore, even though our overall indebtedness will be reduced through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the Plan Effective Date. Adequate funds may not be available when needed or may not be available on favorable terms.
Following our expected emergence from our Chapter 11 Cases, there will not be an established market for shares of Reorganized PEC Common Stock or our Preferred Equity, which means there are uncertainties regarding the prices and terms on which holders could dispose of their shares, if at all.
No established market exists for the new common stock (Reorganized PEC Common Stock) or the preferred stock (Preferred Equity) to be issued pursuant to the Plan. We will use our reasonable best efforts to cause the Reorganized PEC Common Stock and Preferred Equity to be listed for trading on the New York Stock Exchange (NYSE) as soon as practicable following the Plan Effective Date. However, the Company cannot give assurances as to whether the NYSE will approve the Reorganized PEC Common Stock or Preferred Equity for listing or when any such listing will occur. There can be no assurance that the Reorganized PEC Common Stock or Preferred Equity will be listed on the NYSE or any other national exchange or interdealer quotation system or that we will continue to meet the requirements for listing once a listing has been approved. If the Reorganized PEC Common Stock or Preferred Equity is not listed on a national exchange or interdealer quotation system, we intend to cooperate with any registered broker-dealer who may seek to initiate price quotations for the Reorganized PEC Common Stock or Preferred Equity in the over-the-counter market. Again, however, no assurance can be given that such securities will be quoted on the over-the-counter market. We, therefore, cannot provide any assurance that the Reorganized PEC Common Stock or Preferred Equity will be publicly tradable at any time after the Plan Effective Date. If no public market for the Reorganized PEC Common Stock or Preferred Equity develops, holders of such securities may have difficulty selling or obtaining timely and accurate quotations with respect to such securities.
There cannot be any assurance as to the degree of price volatility in any market that develops for the Reorganized PEC Common Stock or Preferred Equity. Some holders who receive Reorganized PEC Common Stock or Preferred Equity pursuant to the Plan may not elect to hold equity on a long-term basis. Sales by future stockholders of a substantial number of shares after the Plan Effective Date could significantly reduce the market price of the Reorganized PEC Common Stock or Preferred Equity. Moreover, the perception that these stockholders might sell significant amounts of the Reorganized PEC Common Stock or Preferred Equity could depress the trading price of the shares for a considerable period. Under the terms of a registration rights agreement contemplated by the Plan, we will be required to file a shelf registration statement that will permit certain holders of Reorganized PEC Common Stock and/or Preferred Equity acquiring shares in connection with the Plan to sell their shares in the public markets. Sales of the Reorganized PEC Common Stock or Preferred Equity, and the possibility thereof, could make it more difficult for us to sell equity, or equity-related securities, in the future at a time and price that we consider appropriate.
Peabody Energy Corporation | 2016 Form 10-K | 36 |
Reorganized PEC Common Stock will be subject to dilution and may be subject to further dilution in the future.
Reorganized PEC Common Stock to be issued on the Plan Effective Date is subject to dilution from the long-term incentive plan (LTIP) contemplated by the Plan, the Preferred Equity, payment-in-kind dividends to be paid to holders of Preferred Equity and certain warrants expected to be issued on the Plan Effective Date. In addition, in the future, we may issue equity securities in connection with future investments, acquisitions or capital raising transactions. Such issuances or grants could constitute a significant portion of the then-outstanding common stock, which may result in significant dilution in ownership of common stock, including shares of Reorganized PEC Common Stock issued pursuant to the Plan. In addition, holders of Reorganized PEC Common Stock will be subordinated to the Preferred Equity to the extent of the Preferred Equity's liquidation preference.
Following our expected emergence from our Chapter 11 Cases, the potential payment of dividends on our stock or repurchases of our stock will be dependent on a number of factors, and future payments and repurchases cannot be assured.
It is uncertain whether we will pay cash dividends or other distributions with respect to our post-emergence stock in the foreseeable future. Restrictive covenants in certain debt instruments to which we or our subsidiaries will, or may, be a party, may limit our ability to pay dividends or for us to receive dividends from our subsidiaries, any of which may negatively impact the trading price of the Reorganized PEC Common Stock and Preferred Equity. In addition, holders of our post-emergence stock will only be entitled to receive such cash dividends as our Board of Directors may declare out of funds legally available for such payments, and our Board of Directors may only authorize us to repurchase shares of our post-emergence stock with funds legally available for such repurchases. The payment of future cash dividends and future repurchases will depend upon our earnings, economic conditions, liquidity and capital requirements, and other factors, including our debt leverage. In addition, the terms of the Preferred Equity will limit our ability to pay cash dividends on or purchase shares of Reorganized PEC Common Stock without the consent of holders representing at least a majority of the outstanding shares of the Preferred Equity. Accordingly, we cannot make any assurance that future dividends will be paid or future repurchases will be made.
Following our emergence from our Chapter 11 Cases under the Plan, we expect to have substantial indebtedness, and our financial performance could be adversely affected by our substantial indebtedness.
Our financial performance could be affected by our substantial indebtedness. As of December 31, 2016, we had approximately $7.8 billion of indebtedness outstanding on a consolidated basis. Upon emergence from our Chapter 11 Cases under the Plan, we expect to have $1.95 billion of indebtedness outstanding, excluding capital leases, on a consolidated basis.
The degree to which we are leveraged could have important consequences, including, but not limited to:
• | making it more difficult for us to pay interest and satisfy our debt obligations; |
• | increasing the cost of borrowing under our credit facilities; |
• | 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; |
• | making it more difficult to obtain surety bonds, letters of credit, bank guarantees 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; |
• | causing a decline in our credit ratings; and |
• | placing us at a competitive disadvantage compared to less leveraged competitors. |
In addition, our future indebtedness under the Plan is expected to subject us to certain 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.
Any downgrade in our credit ratings could result in, among other matters, additional required financial assurances related to our reclamation obligations, a requirement to post additional collateral on derivative trading instruments that we may enter into, 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.
Peabody Energy Corporation | 2016 Form 10-K | 37 |
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Under the Plan, we expect our future indebtedness will restrict our ability to sell assets outside of the ordinary course of business and will restrict the use of the proceeds from any such sales. We may not be able to complete those sales or obtain the proceeds which we could realize from them, and these proceeds may not be adequate to meet any debt service obligations then due. In addition, the terms of our future indebtedness under the Plan provide that if we cannot meet our debt service obligations, the lenders could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation.
Despite our and our subsidiaries’ expected level of indebtedness following the Plan Effective Date, we may still be able to incur substantially more debt, including secured debt. This could further increase the risks associated with our substantial indebtedness.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future, including additional secured debt. Although covenants under the indenture governing the senior secured notes to be outstanding following the Plan Effective Date (New Senior Secured Notes) and the agreements governing our other post-emergence indebtedness (Exit Financings) will limit our ability to incur additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, debt incurred in compliance with these restrictions can be substantial. In addition, the indenture governing the New Senior Secured Notes and the agreements governing our other Exit Financings will not limit us from incurring obligations that do not constitute indebtedness as defined therein.
After the Plan Effective Date, we expect that approximately $950.0 million will be outstanding under our new senior secured term loan facility (New Credit Facility) as of the Plan Effective Date. Additionally, prior to the final maturity date of our New Credit Facility, we may add one or more incremental term loan facilities or other first lien debt in an aggregate principal amount not to exceed (a) $300 million plus (b) an additional amount subject to compliance with a specified first lien leverage ratio, subject to certain other conditions.
We may not be able to generate sufficient cash to service all of our post-emergence indebtedness or other obligations.
Our ability to make scheduled payments on, or refinance our debt obligations, depends on our financial condition and operating performance, which are subject to prevailing economic, industry, and competitive conditions and to certain financial, business, legislative, regulatory, and other factors beyond our control. We may be unable to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
The covenants in our indenture governing the New Senior Secured Notes and the agreements and instruments governing our other post-emergence indebtedness, including the other Exit Financings, impose restrictions that may limit our operating and financial flexibility.
The indenture governing the New Senior Secured Notes and the agreements and instruments governing our other post-emergence indebtedness, including the other Exit Financings, will 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, which could adversely affect our ability to operate our business, as well as significantly affect our liquidity, and therefore could adversely affect our results of operations.
These covenants restrict, among other things, our ability to:
• | incur additional indebtedness; |
• | pay dividends on or make distributions in respect of stock or make certain other restricted payments or investments; |
• | enter into agreements that restrict distributions from certain subsidiaries; |
• | sell or otherwise dispose of assets; |
• | enter into transactions with affiliates; |
• | create or incur liens; |
• | merge, consolidate or sell all or substantially all of our assets; and |
• | place restrictions on the ability of subsidiaries to pay dividends or make other payments to us. |
Peabody Energy Corporation | 2016 Form 10-K | 38 |
Our ability to comply with these covenants may be affected by events beyond our control and we may need to refinance existing debt in the future. A breach of any of these covenants together with the expiration of any cure period, if applicable, could result in a default under the New Senior Secured Notes. If any such default occurs, subject to applicable grace periods, the holder of New Senior Secured Notes may elect to declare all outstanding New Senior Secured Notes, together with accrued interest and other amounts payable thereunder, to be immediately due and payable. If the obligations under the New Senior Secured Notes were to be accelerated, our financial resources may be insufficient to repay the notes and any other indebtedness becoming due in full.
In addition, if we breach the covenants in the indentures governing the New Senior Secured Notes and do not cure such breach within the applicable time periods specified therein, we would cause an event of default under the indenture governing the New Senior Secured Notes and a cross-default to certain of our other Exit Financings and the lenders or holders thereunder could accelerate their obligations. If our indebtedness is accelerated, we may not be able to repay our indebtedness 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 indebtedness 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 make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.
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, 2016, we had gross deferred income tax assets and liabilities of $4,978.0 million and $1,114.4 million, respectively, as described further in Note 12. “Income Taxes” to the accompanying consolidated financial statements. At that date, we also had recorded a valuation allowance of $3,881.2 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.
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, as in effect now, 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. The certificate of incorporation and by-laws that will govern us following the Plan Effective Date are expected to include similar provisions.
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.
Peabody Energy Corporation | 2016 Form 10-K | 39 |
Item 2. Properties.
Coal Reserves
We controlled an estimated 5.6 billion tons of proven and probable coal reserves as of December 31, 2016. An estimated 4.9 billion tons of our attributable proven and probable coal reserves are in the U.S., with the remainder in Australia. Approximately 63% of our Australian proven and probable coal reserves, or 448 million tons, are metallurgical coal, comprised of approximately 183 million and 265 million tons of coking coal and LV PCI coals, respectively. The remainder of our Australian coal reserves consists of thermal coal. We own approximately 28% of these reserves and leased property comprises the remaining 72%. Approximately 65% of our reserves, or 3.6 billion tons, are compliance coal and 35% are non-compliance coal (assuming application of the U.S. industry standard definition of compliance coal to all of our reserves). 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.
Below is a table summarizing the locations and proven and probable coal reserves of our major mining segments.
Proven and Probable Reserves as of December 31, 2016 (1) | |||||||||||
Owned Tons | Leased Tons | Total Tons | |||||||||
Mining Segment | Locations | ||||||||||
(Tons in millions) | |||||||||||
Powder River Basin Mining | Wyoming | — | 2,713 | 2,713 | |||||||
Midwestern U.S. Mining | Illinois, Indiana and Kentucky | 1,425 | 297 | 1,722 | |||||||
Western U.S. Mining | Arizona, New Mexico and Colorado | 171 | 325 | 496 | |||||||
Total United States | 1,596 | 3,335 | 4,931 | ||||||||
Australian Metallurgical Mining | Queensland and New South Wales | — | 418 | 418 | |||||||
Australian Thermal Mining | New South Wales | — | 294 | 294 | |||||||
Total Australia | — | 712 | 712 | ||||||||
Total Proven and Probable Coal Reserves | 1,596 | 4,047 | 5,643 | ||||||||
(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.
Peabody Energy Corporation | 2016 Form 10-K | 40 |
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 and engineers. 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.
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 market 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, 2016 reflected a net reduction compared to the prior year of 693 million 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 66 million production tons.
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, 2016, we leased 6,785 acres of federal land in Colorado, 640 acres in New Mexico and 52,201 acres in Wyoming, for a total of 59,626 nationwide subject to those limitations.
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.
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.
Peabody Energy Corporation | 2016 Form 10-K | 41 |
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 5.6 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 | 2016 Form 10-K | 42 |
The following charts provide a summary, by mining complex, of production (in descending order by mining segment) for the years ended December 31, 2016, 2015 and 2014, 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, 2016 (1) | ||||||||||||||||||||||
<1.2 lbs. | >1.2 to 2.5 lbs. | >2.5 lbs. | As | ||||||||||||||||||||
Sulfur | Sulfur | Sulfur | Received | ||||||||||||||||||||
Year Ended December 31, | Type of | Dioxide per | Dioxide per | Dioxide per | Btu per | ||||||||||||||||||
Segment/Mining Complex | 2016 | 2015 | 2014 | Coal | Million Btu | Million Btu | Million Btu | pound (2) | |||||||||||||||
Powder River Basin Mining: | |||||||||||||||||||||||
North Antelope Rochelle | 92.9 | 109.3 | 118.0 | T | 1,920 | — | — | 8,800 | |||||||||||||||
Caballo | 11.2 | 11.4 | 8.0 | T | 476 | 6 | 6 | 8,400 | |||||||||||||||
Rawhide | 8.1 | 15.2 | 15.4 | T | 248 | 56 | 1 | 8,300 | |||||||||||||||
Total | 112.2 | 135.9 | 141.4 | 2,644 | 62 | 7 | |||||||||||||||||
Midwestern U.S. Mining: | |||||||||||||||||||||||
Bear Run | 7.3 | 7.9 | 8.4 | T | 4 | 28 | 208 | 11,000 | |||||||||||||||
Wild Boar | 2.6 | 2.7 | 3.5 | T | — | — | 35 | 11,100 | |||||||||||||||
Somerville Central | 2.3 | 3.0 | 3.4 | T | — | — | 15 | 11,200 | |||||||||||||||
Francisco Underground | 2.1 | 2.9 | 3.1 | T | — | — | 28 | 11,500 | |||||||||||||||
Gateway North | 1.8 | 1.8 | 2.5 | T | — | — | 61 | 10,800 | |||||||||||||||
Wildcat Hills Underground | 1.5 | 1.7 | 2.0 | T | — | — | 29 | 12,100 | |||||||||||||||
Cottage Grove | 0.2 | 1.1 | 1.9 | T | — | — | 5 | 12,200 | |||||||||||||||
Viking - Corning Pit (Closed in 2014) | — | — | 0.1 | T | — | — | — | NA | |||||||||||||||
Total | 17.8 | 21.1 | 24.9 | 4 | 28 | 381 | |||||||||||||||||
Western U.S. Mining: | |||||||||||||||||||||||
Kayenta | 5.4 | 6.8 | 8.1 | T | 139 | 61 | 3 | 10,600 | |||||||||||||||
El Segundo | 4.9 | 7.5 | 8.4 | T | 14 | 34 | 34 | 9,000 | |||||||||||||||
Twentymile | 2.0 | 3.5 | 6.7 | T | 38 | — | — | 11,200 | |||||||||||||||
Lee Ranch | — | — | — | T | 14 | 66 | 9 | 9,400 | |||||||||||||||
Total | 12.3 | 17.8 | 23.2 | 205 | 161 | 46 | |||||||||||||||||
Australian Metallurgical Mining: | |||||||||||||||||||||||
Millennium | 3.5 | 4.4 | 3.9 | M/P | 4 | — | — | 12,600 | |||||||||||||||
Coppabella | 2.4 | 2.8 | 3.2 | P | 31 | — | — | 12,600 | |||||||||||||||
Moorvale | 1.9 | 2.2 | 2.4 | P | 9 | — | — | 12,300 | |||||||||||||||
Metropolitan (3) | 1.9 | 2.1 | 2.5 | M | 26 | — | — | 12,600 | |||||||||||||||
Burton | 1.5 | 1.3 | 1.9 | M/T | 7 | — | — | 12,700 | |||||||||||||||
North Goonyella | 1.3 | 2.6 | 2.9 | M | 87 | — | — | 12,700 | |||||||||||||||
Middlemount (4) | — | — | — | M/P | 28 | — | — | 12,300 | |||||||||||||||
Total | 12.5 | 15.4 | 16.8 | 192 | — | — | |||||||||||||||||
Australian Thermal Mining: | |||||||||||||||||||||||
Wilpinjong | 14.0 | 12.0 | 14.4 | T | 149 | — | — | 10,000 | |||||||||||||||
Wambo (5) | 6.8 | 6.5 | 6.5 | M/T | 145 | — | — | 11,800 | |||||||||||||||
Total | 20.8 | 18.5 | 20.9 | 294 | — | — | |||||||||||||||||
Total Assigned | 175.6 | 208.7 | 227.2 | 3,339 | 251 | 434 | |||||||||||||||||
T: Thermal
M: Metallurgical
P: Pulverized Coal Injection Metallurgical
Peabody Energy Corporation | 2016 Form 10-K | 43 |
ASSIGNED RESERVES (6) | ||||||||||||||||||||||||||||||||
AS OF DECEMBER 31, 2016 | ||||||||||||||||||||||||||||||||
Attributable Ownership | 100% Project Basis | |||||||||||||||||||||||||||||||
(Tons in Millions) | Proven and | Proven and | ||||||||||||||||||||||||||||||
Segment/Mining Complex | Interest | Probable Reserves | Owned | Leased | Surface | Underground | Probable Reserves | Owned | Leased | Surface | Underground | |||||||||||||||||||||
Powder River Basin Mining: | ||||||||||||||||||||||||||||||||
North Antelope Rochelle | 100% | 1,920 | — | 1,920 | 1,920 | — | 1,920 | — | 1,920 | 1,920 | — | |||||||||||||||||||||
Caballo | 100% | 488 | — | 488 | 488 | — | 488 | — | 488 | 488 | — | |||||||||||||||||||||
Rawhide | 100% | 305 | — | 305 | 305 | — | 305 | — | 305 | 305 | — | |||||||||||||||||||||
Total | 2,713 | — | 2,713 | 2,713 | — | |||||||||||||||||||||||||||
Midwestern U.S. Mining: | ||||||||||||||||||||||||||||||||
Bear Run | 100% | 240 | 104 | 136 | 240 | — | 240 | 104 | 136 | 240 | — | |||||||||||||||||||||
Wild Boar | 100% | 35 | 19 | 16 | 35 | — | 35 | 19 | 16 | 35 | — | |||||||||||||||||||||
Somerville Central | 100% | 15 | 14 | 1 | 15 | — | 15 | 14 | 1 | 15 | — | |||||||||||||||||||||
Francisco Underground | 100% | 28 | 5 | 23 | — | 28 | 28 | 5 | 23 | — | 28 | |||||||||||||||||||||
Gateway North | 100% | 61 | 59 | 2 | — | 61 | 61 | 59 | 2 | — | 61 | |||||||||||||||||||||
Wildcat Hills Underground | 100% | 29 | 11 | 18 | — | 29 | 29 | 11 | 18 | — | 29 | |||||||||||||||||||||
Cottage Grove | 100% | 5 | 3 | 2 | 5 | — | 5 | 3 | 2 | 5 | — | |||||||||||||||||||||
Total | 413 | 215 | 198 | 295 | 118 | |||||||||||||||||||||||||||
Western U.S. Mining: | ||||||||||||||||||||||||||||||||
Kayenta | 100% | 203 | — | 203 | 203 | — | 203 | — | 203 | 203 | — | |||||||||||||||||||||
El Segundo | 100% | 82 | 68 | 14 | 82 | — | 82 | 68 | 14 | 82 | — | |||||||||||||||||||||
Twentymile | 100% | 38 | 10 | 28 | — | 38 | 38 | 10 | 28 | — | 38 | |||||||||||||||||||||
Lee Ranch | 100% | 89 | 87 | 2 | 89 | — | 89 | 87 | 2 | 89 | — | |||||||||||||||||||||
Total | 412 | 165 | 247 | 374 | 38 | |||||||||||||||||||||||||||
Australian Metallurgical Mining: | ||||||||||||||||||||||||||||||||
Millennium | 100% | 4 | — | 4 | 4 | — | 4 | — | 4 | 4 | — | |||||||||||||||||||||
Coppabella | 73.3% | 31 | — | 31 | 31 | — | 42 | — | 42 | 42 | — | |||||||||||||||||||||
Moorvale | 73.3% | 9 | — | 9 | 9 | — | 12 | — | 12 | 12 | — | |||||||||||||||||||||
Metropolitan (3) | 100% | 26 | — | 26 | — | 26 | 26 | — | 26 | — | 26 | |||||||||||||||||||||
Burton | 100% | 7 | — | 7 | 7 | — | 7 | — | 7 | 7 | — | |||||||||||||||||||||
North Goonyella | 100% | 87 | — | 87 | — | 87 | 87 | — | 87 | — | 87 | |||||||||||||||||||||
Middlemount (4) | 50.0% | 28 | — | 28 | 28 | — | 56 | — | 56 | 56 | — | |||||||||||||||||||||
Total | 192 | — | 192 | 79 | 113 | |||||||||||||||||||||||||||
Australian Thermal Mining: | ||||||||||||||||||||||||||||||||
Wilpinjong | 100% | 149 | — | 149 | 149 | — | 149 | — | 149 | 149 | — | |||||||||||||||||||||
Wambo (5) | 100% | 145 | — | 145 | 34 | 111 | 145 | — | 145 | 34 | 111 | |||||||||||||||||||||
Total | 294 | — | 294 | 183 | 111 | |||||||||||||||||||||||||||
Total Assigned | 4,024 | 380 | 3,644 | 3,644 | 380 | |||||||||||||||||||||||||||
Peabody Energy Corporation | 2016 Form 10-K | 44 |
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES (6) | ||||||||||||||||||||||||||||||
AS OF DECEMBER 31, 2016 | ||||||||||||||||||||||||||||||
(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 | ||||||||||||||||||||
Powder River Basin Mining (Wyoming) | 2,713 | — | 2,713 | 2,587 | 126 | 2,713 | — | 2,713 | 2,587 | 126 | ||||||||||||||||||||
Midwestern U.S. Mining: | ||||||||||||||||||||||||||||||
Illinois | 95 | 1,156 | 1,251 | 554 | 697 | 95 | 1,156 | 1,251 | 554 | 697 | ||||||||||||||||||||
Indiana | 318 | 29 | 347 | 289 | 58 | 318 | 29 | 347 | 289 | 58 | ||||||||||||||||||||
Kentucky (7) | — | 124 | 124 | 54 | 70 | — | 124 | 124 | 54 | 70 | ||||||||||||||||||||
Total | 413 | 1,309 | 1,722 | 897 | 825 | |||||||||||||||||||||||||
Western U.S. Mining: | ||||||||||||||||||||||||||||||
Arizona | 203 | — | 203 | 203 | — | 203 | — | 203 | 203 | — | ||||||||||||||||||||
New Mexico | 171 | — | 171 | 171 | — | 171 | — | 171 | 171 | — | ||||||||||||||||||||
Colorado | 38 | 84 | 122 | 79 | 43 | 38 | 84 | 122 | 79 | 43 | ||||||||||||||||||||
Total | 412 | 84 | 496 | 453 | 43 | |||||||||||||||||||||||||
Australian Metallurgical Mining: | ||||||||||||||||||||||||||||||
New South Wales | 26 | — | 26 | 6 | 20 | 26 | — | 26 | 6 | 20 | ||||||||||||||||||||
Queensland | 166 | 226 | 392 | 223 | 169 | 208 | 289 | 497 | 277 | 220 | ||||||||||||||||||||
Total | 192 | 226 | 418 | 229 | 189 | |||||||||||||||||||||||||
Australian Thermal Mining (New South Wales) | 294 | — | 294 | 237 | 57 | 294 | — | 294 | 237 | 57 | ||||||||||||||||||||
Total Proven and Probable | 4,024 | 1,619 | 5,643 | 4,403 | 1,240 | |||||||||||||||||||||||||
Peabody Energy Corporation | 2016 Form 10-K | 45 |
ASSIGNED AND UNASSIGNED - RESERVE CONTROL AND MINING METHOD | ||||||||||||||||||||||||
AS OF DECEMBER 31, 2016 | ||||||||||||||||||||||||
(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 | ||||||||||||||||
Powder River Basin Mining (Wyoming) | — | 2,713 | 2,713 | — | — | 2,713 | 2,713 | — | ||||||||||||||||
Midwestern U.S. Mining: | ||||||||||||||||||||||||
Illinois | 1,217 | 34 | 9 | 1,242 | 1,217 | 34 | 9 | 1,242 | ||||||||||||||||
Indiana | 165 | 182 | 301 | 46 | 165 | 182 | 301 | 46 | ||||||||||||||||
Kentucky (7) | 43 | 81 | — | 124 | 43 | 81 | — | 124 | ||||||||||||||||
Total | 1,425 | 297 | 310 | 1,412 | ||||||||||||||||||||
Western U.S. Mining: | ||||||||||||||||||||||||
Arizona | — | 203 | 203 | — | — | 203 | 203 | — | ||||||||||||||||
New Mexico | 154 | 17 | 171 | — | 154 | 17 | 171 | — | ||||||||||||||||
Colorado | 17 | 105 | — | 122 | 17 | 105 | — | 122 | ||||||||||||||||
Total | 171 | 325 | 374 | 122 | ||||||||||||||||||||
Australia Metallurgical Mining: | ||||||||||||||||||||||||
New South Wales | — | 26 | — | 26 | — | 26 | — | 26 | ||||||||||||||||
Queensland | — | 392 | 179 | 213 | — | 497 | 249 | 248 | ||||||||||||||||
Total | — | 418 | 179 | 239 | ||||||||||||||||||||
Australian Thermal Mining (New South Wales) | — | 294 | 182 | 112 | — | 294 | 182 | 112 | ||||||||||||||||
Total Proven and Probable | 1,596 | 4,047 | 3,758 | 1,885 | ||||||||||||||||||||
Peabody Energy Corporation | 2016 Form 10-K | 46 |
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES - SULFUR CONTENT | |||||||||||||||||||||||
AS OF DECEMBER 31, 2016 | |||||||||||||||||||||||
(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) | |||||||||||||||
Powder River Basin Mining (Wyoming) | T | 2,644 | 62 | 7 | 2,644 | 62 | 7 | 8,700 | |||||||||||||||
Midwestern U.S. Mining: | |||||||||||||||||||||||
Illinois | T | — | — | 1,251 | — | — | 1,251 | 10,800 | |||||||||||||||
Indiana | T | 4 | 28 | 315 | 4 | 28 | 315 | 11,000 | |||||||||||||||
Kentucky (7) | T | — | — | 124 | — | — | 124 | 12,000 | |||||||||||||||
Total | 4 | 28 | 1,690 | ||||||||||||||||||||
Western U.S. Mining: | |||||||||||||||||||||||
Arizona | T | 139 | 61 | 3 | 139 | 61 | 3 | 10,600 | |||||||||||||||
New Mexico | T | 28 | 100 | 43 | 28 | 100 | 43 | 9,200 | |||||||||||||||
Colorado | T | 122 | — | — | 122 | — | — | 11,200 | |||||||||||||||
Total | 289 | 161 | 46 | ||||||||||||||||||||
Australia Metallurgical Mining: | |||||||||||||||||||||||
New South Wales | M | 26 | — | — | 26 | — | — | 12,600 | |||||||||||||||
Queensland | M/P/T | 392 | — | — | 497 | — | — | 12,400 | |||||||||||||||
Total | 418 | — | — | ||||||||||||||||||||
Australian Thermal Mining (New South Wales) | T/M | 294 | — | — | 294 | — | — | 10,800 | |||||||||||||||
Total Proven and Probable | 3,649 | 251 | 1,743 | ||||||||||||||||||||
T: Thermal
M: Metallurgical
P: Pulverized Coal Injection Metallurgical
Peabody Energy Corporation | 2016 Form 10-K | 47 |
(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 emission 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) | On November 3, 2016, Peabody Australia Mining Pty Ltd, one of the Company's Australian subsidiaries, entered into a definitive share sale and purchase agreement (SPA) for the sale of all of its equity interest in Metropolitan Collieries Pty Ltd to a subsidiary of South32 Limited (South32). The closing of the transaction is conditional upon receipt of approval from the Australian Competition and Consumer Commission (ACCC). On February 22, 2017, the ACCC issued a Statement of Issues (SOI) relating to the transaction, noting that the ACCC is continuing to review the transaction. On February 24, 2017, pursuant to its right under the SPA, South32 extended the CP End Date (as defined in the SPA) from March 3, 2017 to April 17, 2017.On March 21, 2017, the ACCC notified us that it has extended the date on which it intends to render its decision regarding the transaction to April 27, 2017, which extends beyond the CP End Date. As a result, we are assessing our options under the SPA. |
(4) | Represents our 50% 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, 2016, 2015 and 2014 tons produced by Middlemount have been excluded from the "Summary of Coal Production and Sulfur Content of Assigned Reserves" table. Middlemount produced 4.5 million tons of coal in 2016 (on a 100% basis). |
(5) | Includes the Wambo Open-Cut Mine and the Wambo Underground Mine areas. |
(6) | Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations as of December 31, 2016. 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 to third parties. |
Item 3. Legal Proceedings.
See Note 26. "Commitments and Contingencies" and Note 27. "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 was listed on the New York Stock Exchange, under the symbol “BTU,” until the Petition Date, when it was suspended from trading on the New York Stock Exchange. Our common stock began trading on the OTC Pink Sheets marketplace under the symbol “BTUUQ” on April 14, 2016. Following the Petition Date, the New York Stock Exchange formally de-listed our common stock. As of March 15, 2017 there were 809 holders of record of our common stock.
Peabody Energy Corporation | 2016 Form 10-K | 48 |
If the Plan becomes effective, our common stock will be extinguished, canceled and discharged on the Plan Effective Date. Under the Plan, holders of our common stock are not to be entitled to receive, and will not receive or retain, any property or interest in property on account of such equity interests. In the event of cancellation of our common stock, amounts invested by the holders will not be recoverable and the common stock will have no value. Trading prices for Peabody Energy's equity or other securities prior to the Plan Effective Date may bear little or no relationship to the actual recovery, if any, by the holders thereof on the Plan Effective Date. Our common stock may continue to trade even though it will be extinguished, canceled and discharged on the Plan Effective Date if the Plan becomes effective. Accordingly, Peabody Energy urges caution with respect to existing and future investments in its equity or other securities.
All share and per share data have been retroactively restated to reflect the September 30, 2015 1-for-15 reverse stock split.
The table below sets forth the range of quarterly high and low sales prices (including intraday prices) for our common stock as reported on the market on which it traded at the time and the amount of cash dividends paid per share of our common stock during the calendar quarters indicated.
Share Price | Dividends | ||||||||||
High | Low | Paid | |||||||||
2016 | |||||||||||
First Quarter | $ | 7.87 | $ | 2.00 | $ | — | |||||
Second Quarter | 2.43 | 0.55 | — | ||||||||
Third Quarter | 2.05 | 1.22 | — | ||||||||
Fourth Quarter | 18.75 | 1.43 | — | ||||||||
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 | — | ||||||||
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. As a result of the Chapter 11 Cases we are currently prohibited from paying dividends. Following the Plan Effective Date, our future indebtedness incurred under the Plan will include provisions that limit our ability to pay dividends. See Part I, Item 1A. "Risk Factors — Following our expected emergence from the Chapter 11 Cases, the potential payment of dividends on our stock and repurchases of our stock will be dependent on a number of factors, and future payments and repurchases cannot be assured."
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. From October 2008 through December 2012, we 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. No share repurchases were made under the Repurchase Program during the years ended December 31, 2016, 2015 or 2014. As a result of the Chapter 11 Cases we are currently prohibited from repurchasing shares. Following the Plan Effective Date, our future indebtedness incurred under the Plan will include provisions that limit our ability to repurchase shares. See Part I, Item 1A. "Risk Factors — Following our expected emergence from the Chapter 11 Cases, the potential payment of dividends on our stock and repurchases of our stock will be dependent on a number of factors, and future payments and repurchases cannot be assured."
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.
Peabody Energy Corporation | 2016 Form 10-K | 49 |
Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended December 31, 2016:
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, 2016 | 321 | $ | 1.55 | — | $ | 700.4 | ||||||||
November 1 through November 30, 2016 | 272 | 14.10 | — | 700.4 | ||||||||||
December 1 through December 31, 2016 | — | — | — | 700.4 | ||||||||||
Total | 593 | $ | 7.31 | — | ||||||||||
(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 2016, 2015 and 2014 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 which is a financial measure not recognized in accordance with U.S. generally accepted accounting principles (U.S. 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-U.S. 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 and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing the segments' operating performance, as displayed in the reconciliation. A reconciliation of income (loss) from continuing operations, net of income taxes to Adjusted EBITDA is included on page 52 of 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.
The selected financial data for all periods presented reflect the classification as discontinued operations of certain operations previously divested (by sale or otherwise).
We have derived the selected historical financial data as of and for the years ended December 31, 2016, 2015, 2014, 2013 and 2012 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.”
Peabody Energy Corporation | 2016 Form 10-K | 50 |
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, | |||||||||||||||||||
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
(In millions, except per share data) | |||||||||||||||||||
Results of Operations Data | |||||||||||||||||||
Total revenues | $ | 4,715.3 | $ | 5,609.2 | $ | 6,792.2 | $ | 7,013.7 | $ | 8,077.5 | |||||||||
Costs and expenses | 4,992.2 | 7,074.0 | 6,927.3 | 7,338.5 | 7,905.0 | ||||||||||||||
Operating (loss) profit | (276.9 | ) | (1,464.8 | ) | (135.1 | ) | (324.8 | ) | 172.5 | ||||||||||
Interest expense, net | 322.4 | 525.5 | 412.8 | 409.5 | 381.1 | ||||||||||||||
Reorganization items, net | 159.0 | — | — | — | — | ||||||||||||||
Loss from continuing operations before income taxes | (758.3 | ) | (1,990.3 | ) | (547.9 | ) | (734.3 | ) | (208.6 | ) | |||||||||
Income tax (benefit) provision | (84.0 | ) | (176.4 | ) | 201.2 | (448.3 | ) | 262.3 | |||||||||||
Loss from continuing operations, net of income taxes | (674.3 | ) | (1,813.9 | ) | (749.1 | ) | (286.0 | ) | (470.9 | ) | |||||||||
Loss from discontinued operations, net of income taxes | (57.6 | ) | (175.0 | ) | (28.2 | ) | (226.6 | ) | (104.2 | ) | |||||||||
Net loss | (731.9 | ) | (1,988.9 | ) | (777.3 | ) | (512.6 | ) | (575.1 | ) | |||||||||
Less: Net income attributable to noncontrolling interests | 7.9 | 7.1 | 9.7 | 12.3 | 10.6 | ||||||||||||||
Net loss attributable to common stockholders | $ | (739.8 | ) | $ | (1,996.0 | ) | $ | (787.0 | ) | $ | (524.9 | ) | $ | (585.7 | ) | ||||
Basic and diluted EPS - Loss from continuing operations | $ | (37.30 | ) | $ | (100.34 | ) | $ | (42.52 | ) | $ | (16.80 | ) | $ | (26.95 | ) | ||||
Weighted average shares used in calculating basic and diluted EPS | 18.3 | 18.1 | 17.9 | 17.8 | 17.9 | ||||||||||||||
Dividends declared per share | $ | — | $ | 0.075 | $ | 5.100 | $ | 5.100 | $ | 5.100 | |||||||||
Other Data | |||||||||||||||||||
Tons produced | 175.6 | 208.7 | 227.2 | 218.4 | 225.4 | ||||||||||||||
Tons sold | 186.8 | 228.8 | 249.8 | 251.7 | 248.5 | ||||||||||||||
Net cash provided by (used in) continuing operations: | |||||||||||||||||||
Operating activities | $ | (22.9 | ) | $ | 18.9 | $ | 441.0 | $ | 780.1 | $ | 1,599.8 | ||||||||
Investing activities | (244.1 | ) | (290.0 | ) | (314.5 | ) | (514.2 | ) | (1,070.1 | ) | |||||||||
Financing activities | 907.9 | 267.7 | (168.1 | ) | (321.5 | ) | (663.3 | ) | |||||||||||
Adjusted EBITDA | 492.2 | 434.6 | 814.0 | 1,047.2 | 1,836.5 | ||||||||||||||
Balance Sheet Data (at period end) | |||||||||||||||||||
Total assets | $ | 11,777.7 | $ | 10,946.9 | $ | 13,126.4 | $ | 14,069.5 | $ | 15,721.7 | |||||||||
Total long-term debt (including capital leases) | 7,791.4 | 6,241.2 | 5,922.1 | 5,938.5 | 6,156.6 | ||||||||||||||
Total stockholders’ equity | 337.8 | 918.5 | 2,726.5 | 3,947.9 | 4,938.8 | ||||||||||||||
Peabody Energy Corporation | 2016 Form 10-K | 51 |
Adjusted EBITDA is calculated as follows:
Year Ended December 31, | |||||||||||||||||||
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
(Dollars in millions) | |||||||||||||||||||
Loss from continuing operations, net of income taxes | $ | (674.3 | ) | $ | (1,813.9 | ) | $ | (749.1 | ) | $ | (286.0 | ) | $ | (470.9 | ) | ||||
Depreciation, depletion and amortization | 465.4 | 572.2 | 655.7 | 740.3 | 663.4 | ||||||||||||||
Asset retirement obligation expenses | 41.8 | 45.5 | 81.0 | 66.5 | 67.0 | ||||||||||||||
Asset impairment and mine closure costs | 247.9 | 1,277.8 | 154.4 | 528.3 | 929.0 | ||||||||||||||
Selling and administrative expenses related to debt restructuring | 21.5 | — | — | — | — | ||||||||||||||
Settlement charges related to the Patriot bankruptcy reorganization | — | — | — | 30.6 | — | ||||||||||||||
Change in deferred tax asset valuation allowance related to equity affiliates | (7.5 | ) | (1.0 | ) | 52.3 | — | — | ||||||||||||
Amortization of basis difference related to equity affiliates | — | 4.9 | 5.7 | 6.3 | 4.6 | ||||||||||||||
Interest expense, net | 322.4 | 525.5 | 412.8 | 409.5 | 381.1 | ||||||||||||||
Reorganization items, net | 159.0 | — | — | — | — | ||||||||||||||
Income tax (benefit) provision | (84.0 | ) | (176.4 | ) | 201.2 | (448.3 | ) | 262.3 | |||||||||||
Adjusted EBITDA | $ | 492.2 | $ | 434.6 | $ | 814.0 | $ | 1,047.2 | $ | 1,836.5 | |||||||||
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
In 2016, we produced and sold 175.6 million and 186.8 million tons of coal, respectively, from continuing operations. During that period, 76% of our total sales (by volume) were to U.S. electricity generators, 21% were to customers outside the U.S. and 3% were to the U.S. industrial sector, with approximately 86% of our worldwide sales (by volume) delivered under long-term contracts.
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 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 mid-range sulfur content and Btu. 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 U.S. Mining operations mine both bituminous and sub-bituminous coal deposits.
Peabody Energy Corporation | 2016 Form 10-K | 52 |
The business of our Australian operating platform is primarily export focused with customers spread across several countries, while a portion of our metallurgical and 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 coking 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, 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 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. 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, from time to time, cash flow hedging in support of our coal trading strategy.
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.
Filing Under Chapter 11 of the United States Bankruptcy Code
On April 13, 2016, Peabody and a majority of its wholly owned domestic subsidiaries as well as one international subsidiary in Gibraltar (the Filing Subsidiaries, and together with Peabody, the Debtors) filed voluntary petitions for reorganization (the Bankruptcy Petitions) under Chapter 11 of Title 11 of the U.S. Code (the Bankruptcy Code) in the United States Bankruptcy Court for the Eastern District of Missouri (the Bankruptcy Court). The Company's Australian operations and other international subsidiaries are not included in the filings. The Debtors continue to operate their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In general, as debtors-in-possession, the Debtors are authorized under Chapter 11 to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court.
The filings of the Bankruptcy Petitions constituted an event of default under our prepetition credit agreement as well as the indentures governing certain of our debt instruments, as further described in Note 14. "Current and Long-term Debt" to the accompanying consolidated financial statements, and all unpaid principal and accrued and unpaid interest due thereunder became immediately due and payable. Any efforts to enforce such payment obligations are automatically stayed as a result of the Bankruptcy Petitions and the creditors' rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.
In August 2016, we outlined a business plan intended to form the basis for our plan of reorganization, as further described below. As a result of our reorganization, we expect to emerge from the Chapter 11 Cases with the competitive cost structure necessary to improve our financial position and provide long-term stability for our stakeholders in the face of potentially volatile market conditions. Important aspects of our emergence business strategy include (i) a continued focus on safe, cost-disciplined mining operations and reclamation activities, (ii) maximization of the most profitable elements of our asset base and potential divestiture of non-strategic assets, (iii) investment return-driven capital discipline, and (iv) a reduction of overall debt and fixed charges.
Peabody Energy Corporation | 2016 Form 10-K | 53 |
In order to successfully emerge from our Chapter 11 Cases, the Debtors must propose and obtain confirmation from the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code. On January 27, 2017, the Debtors filed with the Bankruptcy Court the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, the Plan) and the Second Amended Disclosure Statement with Respect to Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (previous versions of the Plan and Disclosure Statement were filed with the Bankruptcy Court on December 22, 2016, January 25, 2017 and January 27, 2017). Subsequently, the Debtors solicited votes on the Plan. On March 15, 2017, the Debtors filed a revised version of the Plan. On March 16, 2017, the Bankruptcy Court held a hearing to determine whether the Plan should be confirmed. On March 17, 2017, the Bankruptcy Court entered an order confirming the Plan. The Plan provides for, among other things, (1) classification and treatment of various claims and equity interests, (2) a reduction of our debt upon emergence, and (3) recapitalization through a rights offering and private placement for equity securities of the reorganized company. For additional details regarding the Bankruptcy Petitions and the Debtors' plan of reorganization, refer to Note 1. "Summary of Significant Accounting Policies" to the accompanying consolidated financial statements.
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 and our ability to consummate the Plan pursuant to the Bankruptcy Code, the price of coal, cost of competing fuels, availability of transportation for coal shipments, labor relations, weather conditions, 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
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 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, which is a financial measure not recognized in accordance with U.S. GAAP. Adjusted EBITDA is used by management as the primary metric to measure our segments’ operating performance. We believe non-U.S. 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 and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing our segments' operating performance, as displayed in the reconciliation. 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.
A reconciliation of Adjusted EBITDA to its most comparable measure under U.S. GAAP is included in Note 29. "Segment and Geographic Information" of the consolidated financial statements, which information is incorporated herein by reference.
Peabody Energy Corporation | 2016 Form 10-K | 54 |
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Summary
Demand for seaborne metallurgical coal for the year ended December 31, 2016 increased compared to 2015, driven by stronger demand in China following policy measures reducing domestic coal production and on stronger China steel production. Worldwide steel production increased by 0.8% in 2016, according to data recently published by the World Steel Association (WSA), with China's crude steel production up 1.2% compared to 2015. International seaborne metallurgical and thermal coal prices increased sharply in the second half of 2016, reaching multi-year highs driven by tightening coal supply and improved coal import demand from China. Benchmark pricing for seaborne premium high quality hard coking coal (HQHCC) and premium LV PCI products for 2016 and 2015 were as follows (on a per tonne basis):
Contract Commencement Month: | HQHCC | Price (Decrease) Increase | LV PCI | Price (Decrease) Increase | ||||||||||||||||||
2016 | 2015 | % | 2016 | 2015 | % | |||||||||||||||||
January | $ | 81 | $ | 117 | (31 | )% | $ | 69 | $ | 99 | (30 | )% | ||||||||||
April | $ | 84 | $ | 110 | (24 | )% | $ | 73 | $ | 93 | (22 | )% | ||||||||||
July | $ | 93 | $ | 93 | — | % | $ | 75 | $ | 73 | 3 | % | ||||||||||
October | $ | 200 | $ | 89 | 125 | % | $ | 133 | $ | 71 | 87 | % | ||||||||||
During the year ended December 31, 2016, HQHCC and Newcastle index thermal coal realized the following spot pricing:
High | Low | Average | December 31, 2016 | |||||||||||||
High quality hard coking coal | $ | 310 | $ | 73 | $ | 143 | $ | 230 | ||||||||
Newcastle index thermal coal | $ | 115 | $ | 49 | $ | 66 | $ | 88 | ||||||||
In the U.S., electricity generation from coal decreased 9% during the year ended December 31, 2016 compared to 2015, 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 comparatively low natural gas prices during the first half of 2016, high coal stockpiles and lower heating-degree days due to mild weather. During the first half of 2016 coal and natural gas accounted for 28% and 33%, respectively, of the electricity generation mix. During the second half of 2016, coal increased its relative share of the generation mix, as coal and natural gas accounted for approximately 32% and 34%, respectively, of electricity generation.
Our revenues decreased during the year ended December 31, 2016 compared to the prior year ($893.9 million) primarily due to lower realized pricing in the U.S. and internationally 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 contributed to year-over-year decreases in our operating costs and expenses ($900.1 million) and selling and administrative expenses ($23.0 million). Also included in operating results for the year ended December 31, 2016 were aggregate restructuring charges of $15.5 million, recognized in connection with certain actions initiated to reduce headcount and costs across our operating segments and administrative functions, which are expected to better align our workforce with our near-term outlook and improve our cost position moving forward.
Net loss attributable to common stockholders was $739.8 million for the year ended December 31, 2016, a decrease of $1,256.2 million compared to the net loss attributable to common stockholders of $1,996.0 million in the prior year. Overall, Adjusted EBITDA of $492.2 million for the year ended December 31, 2016 reflected a year-over-year increase of $57.6 million. In addition to higher Adjusted EBITDA, the results were favorably impacted by lower asset impairment charges and decreased interest expense. These factors were partially offset by reorganization items recorded in connection with our Chapter 11 Cases.
As of December 31, 2016, our available liquidity was approximately $0.9 billion consisting of cash and cash equivalents. Refer to the "Liquidity and Capital Resources" section contained within this Item 7 for further discussion of factors affecting our available liquidity.
Peabody Energy Corporation | 2016 Form 10-K | 55 |
Tons Sold
The following table presents tons sold by operating segment for the years ended December 31, 2016 and 2015:
Year Ended December 31, | (Decrease) Increase to Tons Sold | ||||||||||
2016 | 2015 | Tons | % | ||||||||
(Tons in millions) | |||||||||||
Australian Metallurgical Mining | 13.4 | 15.7 | (2.3 | ) | (14.6 | )% | |||||
Australian Thermal Mining | 21.3 | 20.1 | 1.2 | 6.0 | % | ||||||
Powder River Basin Mining | 113.1 | 138.8 | (25.7 | ) | (18.5 | )% | |||||
Western U.S. Mining | 13.7 | 17.9 | (4.2 | ) | (23.5 | )% | |||||
Midwestern U.S. Mining | 18.3 | 21.2 | (2.9 | ) | (13.7 | )% | |||||
Total tons sold from mining segments | 179.8 | 213.7 | (33.9 | ) | (15.9 | )% | |||||
Trading and Brokerage | 7.0 | 15.1 | (8.1 | ) | (53.6 | )% | |||||
Total tons sold | 186.8 | 228.8 | (42.0 | ) | (18.4 | )% | |||||
Peabody Energy Corporation | 2016 Form 10-K | 56 |
Supplemental Financial Data
The following table presents supplemental financial data by operating segment for the years ended December 31, 2016 and 2015:
Year Ended December 31, | Increase (Decrease) | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
Revenues per Ton - Mining Operations | ||||||||||||||
Australian Metallurgical | $ | 81.41 | $ | 75.04 | $ | 6.37 | 8 | % | ||||||
Australian Thermal | 38.79 | 41.00 | (2.21 | ) | (5 | )% | ||||||||
Powder River Basin | 13.02 | 13.45 | (0.43 | ) | (3 | )% | ||||||||
Western U.S. | 38.30 | 38.09 | 0.21 | 1 | % | |||||||||
Midwestern U.S. | 43.39 | 46.18 | (2.79 | ) | (6 | )% | ||||||||
Operating Costs per Ton - Mining Operations (1) | ||||||||||||||
Australian Metallurgical | $ | 82.63 | $ | 76.20 | $ | 6.43 | 8 | % | ||||||
Australian Thermal | 28.56 | 31.36 | (2.80 | ) | (9 | )% | ||||||||
Powder River Basin | 9.66 | 9.97 | (0.31 | ) | (3 | )% | ||||||||
Western U.S. | 30.90 | 27.78 | 3.12 | 11 | % | |||||||||
Midwestern U.S. | 31.49 | 33.49 | (2.00 | ) | (6 | )% | ||||||||
Gross Margin per Ton - Mining Operations (1) | ||||||||||||||
Australian Metallurgical | $ | (1.22 | ) | $ | (1.16 | ) | $ | (0.06 | ) | (5 | )% | |||
Australian Thermal | 10.23 | 9.64 | 0.59 | 6 | % | |||||||||
Powder River Basin | 3.36 | 3.48 | (0.12 | ) | (3 | )% | ||||||||
Western U.S. | 7.40 | 10.31 | (2.91 | ) | (28 | )% | ||||||||
Midwestern U.S. | 11.90 | 12.69 | (0.79 | ) | (6 | )% | ||||||||
(1) | Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring and pension settlement charges; asset impairment; and certain other costs related to post-mining activities. Gross margin per ton is approximately equivalent to segment Adjusted EBITDA divided by segment tons sold. |
Revenues
The following table presents revenues by reporting segment for the years ended December 31, 2016 and 2015:
Year Ended December 31, | (Decrease) Increase to Revenues | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Australian Metallurgical Mining | $ | 1,090.4 | $ | 1,181.9 | $ | (91.5 | ) | (7.7 | )% | |||||
Australian Thermal Mining | 824.9 | 823.5 | 1.4 | 0.2 | % | |||||||||
Powder River Basin Mining | 1,473.3 | 1,865.9 | (392.6 | ) | (21.0 | )% | ||||||||
Western U.S. Mining | 526.0 | 682.3 | (156.3 | ) | (22.9 | )% | ||||||||
Midwestern U.S. Mining | 792.5 | 981.2 | (188.7 | ) | (19.2 | )% | ||||||||
Trading and Brokerage | (10.9 | ) | 42.8 | (53.7 | ) | (125.5 | )% | |||||||
Corporate and Other | 19.1 | 31.6 | (12.5 | ) | (39.6 | )% | ||||||||
Total revenues | $ | 4,715.3 | $ | 5,609.2 | $ | (893.9 | ) | (15.9 | )% | |||||
Australia Metallurgical Mining. The decrease in our Australian Metallurgical Mining segment revenues for the year ended December 31, 2016 compared to the prior year was driven by unfavorable volume and mix variances ($186.9 million), partially offset by higher realized coal prices ($95.4 million). The volume decrease reflected lower sales volumes from Queensland mines due to weather impacts and lower production at our North Goonyella Mine resulting from a longwall move and a significant geological event which resulted in the cessation of the current longwall top coal caving system.
Peabody Energy Corporation | 2016 Form 10-K | 57 |
Australia Thermal Mining. The slight increase in our Australian Thermal Mining segment revenues for the year ended December 31, 2016 compared to the prior year was primarily driven by higher volumes ($47.6 million) offset by lower realized coal prices ($46.2 million). The increase in tons sold was primarily driven by increased production at our Wilpinjong Mine as the result of receiving temporary approval during 2016 to ship tons in excess of its government mandated limit.
Powder River Basin Mining. The decrease in our Powder River Basin Mining segment revenues for the year ended December 31, 2016 compared to the prior year was largely driven by lower volume ($335.7 million) and lower realized coal prices ($56.9 million). The decline in volume across all mines in the segment reflected the impacts on customer demand of lower natural gas prices during the first half of 2016 and mild winter weather.
Western U.S. Mining. The decrease in our Western U.S. Mining segment revenues for the year ended December 31, 2016 compared to the prior year was primarily driven by an unfavorable volume and mix variance ($146.4 million). The volume decrease reflected lower sales volumes at our Twentymile Mine due to lower production resulting from longwall moves (including an extended move to a new seam) and geological issues. The volume decrease was also driven by the litigation with Arizona Public Service Company and PacifiCorp that is further described in Note 26. "Commitments and Contingencies" of our consolidated financial statements.
Midwestern U.S. Mining. Revenues from our Midwestern U.S. Mining segment decreased during the year ended December 31, 2016 compared to the prior year due to lower volume ($146.7 million) driven by the impacts on customer demand of lower natural gas prices. Revenues for the segment were also impacted by lower realized coal prices ($42.0 million) that resulted from the repricing of certain long-term supply contracts.
Trading and Brokerage. The decline in Trading and Brokerage segment revenues for the year ended December 31, 2016 compared to the prior year reflected lower physical volumes shipped due to the impact of depressed coal pricing and unfavorable mark-to-market earnings from financial contract trading activities. We expect a significant portion of the unfavorable mark-to-market earnings to be offset in future periods upon the delivery of physical shipments which economically hedge the financial positions that related to the losses.
Loss From Continuing Operations Before Income Taxes
The following table presents loss from continuing operations before income taxes for the years ended December 31, 2016 and 2015:
Year Ended December 31, | Increase (Decrease) to Income | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Loss from continuing operations before income taxes | $ | (758.3 | ) | $ | (1,990.3 | ) | $ | 1,232.0 | 61.9 | % | ||||
Depreciation, depletion and amortization | (465.4 | ) | (572.2 | ) | 106.8 | 18.7 | % | |||||||
Asset retirement obligation expenses | (41.8 | ) | (45.5 | ) | 3.7 | 8.1 | % | |||||||
Selling and administrative expenses related to debt restructuring | (21.5 | ) | — | (21.5 | ) | n.m. | ||||||||
Asset impairment | (247.9 | ) | (1,277.8 | ) | 1,029.9 | 80.6 | % | |||||||
Change in deferred tax asset valuation allowance related to equity affiliates | 7.5 | 1.0 | 6.5 | 650.0 | % | |||||||||
Amortization of basis difference related to equity affiliates | — | (4.9 | ) | 4.9 | 100.0 | % | ||||||||
Interest expense | (298.6 | ) | (465.4 | ) | 166.8 | 35.8 | % | |||||||
Loss on early debt extinguishment | (29.5 | ) | (67.8 | ) | 38.3 | 56.5 | % | |||||||
Interest income | 5.7 | 7.7 | (2.0 | ) | (26.0 | )% | ||||||||
Reorganization items, net | (159.0 | ) | — | (159.0 | ) | n.m. | ||||||||
Adjusted EBITDA | $ | 492.2 | $ | 434.6 | $ | 57.6 | 13.3 | % | ||||||
Results from continuing operations before income taxes for the year ended December 31, 2016 increased compared to the prior year primarily due to asset impairment charges recorded during the year ended December 31, 2015, improved Adjusted EBITDA, decreased interest expense and decreased depreciation, depletion and amortization expenses. Those factors were partially offset by reorganization items, net recorded during the year ended December 31, 2016.
Peabody Energy Corporation | 2016 Form 10-K | 58 |
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of our reporting segments for the years ended December 31, 2016 and 2015:
Year Ended December 31, | Increase (Decrease) to Adjusted EBITDA | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Australian Metallurgical Mining | $ | (16.3 | ) | $ | (18.2 | ) | $ | 1.9 | 10.4 | % | ||||
Australian Thermal Mining | 217.6 | 193.6 | 24.0 | 12.4 | % | |||||||||
Powder River Basin Mining | 379.9 | 482.9 | (103.0 | ) | (21.3 | )% | ||||||||
Western U.S. Mining | 101.6 | 184.6 | (83.0 | ) | (45.0 | )% | ||||||||
Midwestern U.S. Mining | 217.3 | 269.7 | (52.4 | ) | (19.4 | )% | ||||||||
Trading and Brokerage | (72.2 | ) | 27.0 | (99.2 | ) | (367.4 | )% | |||||||
Corporate and Other | (335.7 | ) | (705.0 | ) | 369.3 | 52.4 | % | |||||||
Adjusted EBITDA | $ | 492.2 | $ | 434.6 | $ | 57.6 | 13.3 | % | ||||||
Australian Metallurgical Mining. The improvement in Australian Metallurgical Mining segment Adjusted EBITDA during the year ended December 31, 2016 compared to the prior year reflected higher coal pricing (driven by fourth quarter price settlements), net of sales-related costs ($88.9 million), offset by lower volume across the segment caused by the impact of longwall moves and geological issues at our North Goonyella Mine and the impact of wet weather at certain mines ($79.7 million).
Australian Thermal Mining. The increase in Australian Thermal Mining segment Adjusted EBITDA during the year ended December 31, 2016 compared to the prior year reflected production efficiencies attributable to mine sequencing and lower port costs ($41.7 million), an increase in volume ($25.6 million), partially offset by lower coal pricing, net of sales-related costs ($42.6 million).
Powder River Basin Mining. The decrease in Powder River Basin Mining segment Adjusted EBITDA during the year ended December 31, 2016 compared to the prior year was due to lower volume driven by lower natural gas prices, particularly in the first half of 2016 ($87.4 million), lower coal pricing, net of sales-related costs ($38.5 million) and the impact of mine sequencing, primarily at our North Antelope Rochelle Mine ($21.6 million). These factors were partially offset by reductions in materials, services and repairs resulting from our ongoing cost containment initiatives ($32.4 million) and lower diesel fuel and explosives pricing ($11.1 million).
Western U.S. Mining. The decrease in Western U.S. Mining segment Adjusted EBITDA during the year ended December 31, 2016 compared to the prior year was driven by longwall move costs at our Twentymile Mine ($38.5 million), a decline in volume driven by the contract litigation with Arizona Public Service Company and PacifiCorp that is further described in Note 26. "Commitments and Contingencies" of our consolidated financial statements ($33.0 million) and the unfavorable impact of mine sequencing, primarily at our El Segundo Mine ($12.2 million).
Midwestern U.S. Mining. The decrease in Midwestern U.S. Mining segment Adjusted EBITDA for the year ended December 31, 2016 compared to the prior year was due to lower volume driven by lower natural gas prices, particularly in the first half of 2016 ($50.1 million) and lower coal pricing, net of sales-related costs ($38.6 million), partially offset by favorable materials, services and repairs costs ($15.2 million) and reductions in labor and overhead charges ($11.4 million) resulting from our ongoing cost containment initiatives and favorable pricing and usage of fuel and explosives ($9.5 million).
Trading and Brokerage. The decrease in Trading and Brokerage segment Adjusted EBITDA during the year ended December 31, 2016 compared to the prior year reflected the impact of decreased revenues described above and the impact of damages awarded in 2015 relating to the Eagle Mining, LLC (Eagle) arbitration and the settlement of the matter. Refer to Note 26. "Commitments and Contingencies" to the accompanying consolidated financial statements for additional information related to the Eagle matter.
Peabody Energy Corporation | 2016 Form 10-K | 59 |
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, 2016 and 2015:
Year Ended December 31, | (Decrease) Increase to Income | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Resource management activities (1) | $ | 19.0 | $ | 32.2 | $ | (13.2 | ) | (41.0 | )% | |||||
Selling and administrative expenses (excluding debt restructuring) | (131.9 | ) | (176.4 | ) | 44.5 | 25.2 | % | |||||||
Restructuring charges | (15.5 | ) | (23.5 | ) | 8.0 | 34.0 | % | |||||||
Corporate hedging | (241.0 | ) | (436.8 | ) | 195.8 | 44.8 | % | |||||||
UMWA VEBA Settlement | 68.1 | — | 68.1 | n.m. | ||||||||||
Other items, net (2) | (34.4 | ) | (100.5 | ) | 66.1 | 65.8 | % | |||||||
Corporate and Other Adjusted EBITDA | $ | (335.7 | ) | $ | (705.0 | ) | $ | 369.3 | 52.4 | % | ||||
(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, certain coal royalty expenses, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts and expenses related to our other commercial activities. |
The increase associated with corporate hedging results, which includes foreign currency and commodity hedging, was due to lower hedge realizations. During the year ended December 31, 2016, a gain of $68.1 million was recognized for the voluntary employee beneficiary association (VEBA) settlement with the United Mine Workers of America (UMWA) as further described in Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" of our consolidated financial statements. The significant reduction in selling and administrative expenses during the year ended December 31, 2016 compared to the prior year largely reflected the impact of our ongoing cost containment initiatives, including past restructuring activities. The increase associated with "Other items, net" is primarily attributable to lower charges on certain transportation-related contracts as compared to prior year and improved Middlemount results driven by favorable pricing in the fourth quarter of 2016. Restructuring charges decreased during the year ended December 31, 2016 compared to the prior year due to the larger staffing reductions at corporate and regional offices during the first half of 2015. Resource management results decreased during the year ended December 31, 2016 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. during 2015.
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment for the years ended December 31, 2016 and 2015:
Increase | ||||||||||||||
Year Ended December 31, | to Income | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Australian Metallurgical Mining | $ | (118.7 | ) | $ | (178.9 | ) | $ | 60.2 | 33.7 | % | ||||
Australian Thermal Mining | (102.5 | ) | (108.0 | ) | 5.5 | 5.1 | % | |||||||
Powder River Basin Mining | (123.4 | ) | (138.5 | ) | 15.1 | 10.9 | % | |||||||
Western U.S. Mining | (45.2 | ) | (55.3 | ) | 10.1 | 18.3 | % | |||||||
Midwestern U.S. Mining | (56.2 | ) | (69.0 | ) | 12.8 | 18.6 | % | |||||||
Trading and Brokerage | (0.2 | ) | (0.6 | ) | 0.4 | 66.7 | % | |||||||
Corporate and Other | (19.2 | ) | (21.9 | ) | 2.7 | 12.3 | % | |||||||
Total | $ | (465.4 | ) | $ | (572.2 | ) | $ | 106.8 | 18.7 | % | ||||
Peabody Energy Corporation | 2016 Form 10-K | 60 |
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, 2016 and 2015:
Year Ended December 31, | |||||||
2016 | 2015 | ||||||
Australian Metallurgical Mining | $ | 4.36 | $ | 5.27 | |||
Australian Thermal Mining | 2.53 | 2.51 | |||||
Powder River Basin Mining | 0.71 | 0.69 | |||||
Western U.S. Mining | 0.92 | 0.93 | |||||
Midwestern U.S. Mining | 0.53 | 0.45 | |||||
The decrease in depreciation, depletion and amortization expense during the year ended December 31, 2016 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 carrying value at certain of our Australian Metallurgical mines due to impairment charges recognized during 2015.
Selling and Administrative Expenses Related to Debt Restructuring. The general and administrative expenses related to debt restructuring recorded during the year ended December 31, 2016 related primarily to legal and other professional fees incurred in connection with debt restructuring initiatives prior to the Debtors' filing of the Bankruptcy Petitions.
Asset Impairment. We recognized $247.9 million and $1,277.8 million in aggregate asset impairment charges during the years ended December 31, 2016 and 2015, respectively. Refer to Note 4. "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.
Interest Expense. The decrease in interest expense for the year ended December 31, 2016 compared to the prior year is primarily due to the impact of our filing of the Bankruptcy Petitions, specifically only accruing adequate protection payments subsequent to the Petition Date to certain secured lenders and other parties in accordance with Section 502(b)(2) of the Bankruptcy Code, partially offset by increased interest recorded in connection with additional prepetition borrowings under the 2013 Revolver and increased expense related to additional letters of credit issued in support of various obligations.
Loss on Early Debt Extinguishment. The decrease in loss on early debt extinguishment charges for the year ended December 31, 2016 as compared to prior year was driven by higher charges recorded during the year ended December 31, 2015 related to the repurchase of $566.9 million aggregate principal amount of our 2016 Notes compared to the charges recorded during the year ended December 31, 2016 related to the repayment of our DIP Term Loan Facility.
Reorganization Items, Net. The reorganization items recorded during the year ended December 31, 2016 related to expenses in connection with our Chapter 11 Cases. Refer to Note 2. "Reorganization Items, Net" to the accompanying consolidated financial statements for further information regarding our reorganization items.
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, 2016 and 2015:
Year Ended December 31, | Increase (Decrease) to Income | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Loss from continuing operations before income taxes | $ | (758.3 | ) | $ | (1,990.3 | ) | $ | 1,232.0 | 61.9 | % | ||||
Income tax benefit | (84.0 | ) | (176.4 | ) | (92.4 | ) | (52.4 | )% | ||||||
Loss from continuing operations, net of income taxes | $ | (674.3 | ) | $ | (1,813.9 | ) | $ | 1,139.6 | 62.8 | % | ||||
Results from continuing operations, net of income taxes, increased for the year ended December 31, 2016 compared to the prior year due to the effect of higher before-tax earnings, partially offset by the unfavorable effect of income taxes.
Peabody Energy Corporation | 2016 Form 10-K | 61 |
Income Tax Benefit. The year-over-year unfavorable effect of income taxes was driven by higher benefits recorded in 2015 as compared to 2016 for the tax allocation to continuing operations related to the tax effects of items credited directly to "Accumulated other comprehensive loss", the release of reserves related to uncertain tax positions and the election to carry back specified liability losses ten years. These unfavorable factors were partially offset by lower expense in Australia due to reduced before-tax earnings in 2016 as compared to 2015. Refer to Note 12. "Income Taxes" to the accompanying consolidated financial statements for additional information.
Net Loss Attributable to Common Stockholders
The following table presents net loss attributable to common stockholders for the years ended December 31, 2016 and 2015:
Year Ended December 31, | Increase (Decrease) to Income | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Loss from continuing operations, net of income taxes | $ | (674.3 | ) | $ | (1,813.9 | ) | $ | 1,139.6 | 62.8 | % | ||||
Loss from discontinued operations, net of income taxes | (57.6 | ) | (175.0 | ) | 117.4 | 67.1 | % | |||||||
Net loss | (731.9 | ) | (1,988.9 | ) | 1,257.0 | 63.2 | % | |||||||
Net income attributable to noncontrolling interests | 7.9 | 7.1 | (0.8 | ) | (11.3 | )% | ||||||||
Net loss attributable to common stockholders | $ | (739.8 | ) | $ | (1,996.0 | ) | $ | 1,256.2 | 62.9 | % | ||||
Net results attributable to common stockholders increased during the year ended December 31, 2016 compared to the prior year largely due to the favorable change in results from continuing operations, net of income taxes, as discussed above, and the favorable impact of changes in results from discontinued operations.
Loss from Discontinued Operations, Net of Income Taxes. The improved results from discontinued operations for the year ended December 31, 2016 compared to the prior year was driven primarily by Patriot bankruptcy related charges associated with black lung liabilities and the UMWA Combined Benefit Fund totaling $132.5 million recognized during 2015. Results for the year ended December 31, 2015 also reflected a $34.7 million charge related to credit support that we provided to Patriot and a charge of $9.7 million associated with the Queensland Bulk Handling Pty Ltd. litigation. These costs were partially offset by charges of $54.3 million recorded during the year ended December 31, 2016 associated with the UMWA 1974 Pension Plan settlement. Those matters are discussed further in Note 26. "Commitments and Contingencies" and Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" to the accompanying consolidated financial statements.
Diluted EPS
The following table presents diluted EPS for the years ended December 31, 2016 and 2015:
Year Ended December 31, | Increase to EPS | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
Diluted EPS attributable to common stockholders: | ||||||||||||||
Loss from continuing operations | $ | (37.30 | ) | $ | (100.34 | ) | $ | 63.04 | 62.8 | % | ||||
Loss from discontinued operations | (3.15 | ) | (9.64 | ) | 6.49 | 67.3 | % | |||||||
Net loss | $ | (40.45 | ) | $ | (109.98 | ) | $ | 69.53 | 63.2 | % | ||||
Diluted EPS increased in the year ended December 31, 2016 compared to the prior year commensurate with the favorable change in results from continuing and discontinued operations between those periods.
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 published by the 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.
Peabody Energy Corporation | 2016 Form 10-K | 62 |
These adverse demand factors and the impact of excess metallurgical and thermal supply continued to weigh on international coal prices. Benchmark pricing for seaborne premium HQHCC and premium LV PCI for 2015 and 2014 were as follows (on a per tonne basis):
Contract Commencement Month: | HQHCC | Price Decrease | LV PCI | Price Decrease | ||||||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||||||||
January | $ | 117 | $ | 143 | (18 | )% | $ | 99 | $ | 116 | (15 | )% | ||||||||||
April | $ | 110 | $ | 120 | (8 | )% | $ | 93 | $ | 100 | (7 | )% | ||||||||||
July | $ | 93 | $ | 120 | (23 | )% | $ | 73 | $ | 100 | (27 | )% | ||||||||||
October | $ | 89 | $ | 119 | (25 | )% | $ | 71 | $ | 99 | (28 | )% | ||||||||||
During the year ended December 31, 2015, HQHCC and Newcastle index thermal coal realized the following spot pricing:
High | Low | Average | December 31, 2015 | |||||||||||||
High quality hard coking coal | $ | 110 | $ | 72 | $ | 87 | $ | 76 | ||||||||
Newcastle index thermal coal | $ | 71 | $ | 51 | $ | 59 | $ | 51 | ||||||||
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. 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 continued to drive operational efficiencies, optimize production across our mining platform and control expenses at all operational and administrative levels of the organization, which 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.
Net loss attributable to common stockholders was $1,996.0 million for the year ended December 31, 2015, an increase of $1,209.0 million compared to the net loss attributable to common stockholders of $787.0 million in the prior year. The increased loss reflected an adverse impact from asset impairment charges, a year-over-year decrease in Adjusted EBITDA 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 4. "Asset Impairment" to the accompanying consolidated financial statements.
Peabody Energy Corporation | 2016 Form 10-K | 63 |
Tons Sold
The following table presents tons sold by operating segment for the years ended December 31, 2015 and 2014:
Year Ended December 31, | Decrease to Tons Sold | ||||||||||
2015 | 2014 | Tons | % | ||||||||
(Tons in millions) | |||||||||||
Australian Metallurgical Mining | 15.7 | 17.2 | (1.5 | ) | (8.7 | )% | |||||
Australian Thermal Mining | 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 | )% | |||||
Peabody Energy Corporation | 2016 Form 10-K | 64 |
Supplemental Financial Data
The following table presents supplemental financial data by operating segment for the years ended December 31, 2015 and 2014:
Year Ended December 31, | (Decrease) Increase | |||||||||||||
2015 | 2014 | $ | % | |||||||||||
Revenues per Ton - Mining Operations | ||||||||||||||
Australian Metallurgical | $ | 75.04 | $ | 93.81 | $ | (18.77 | ) | (20 | )% | |||||
Australian Thermal | 41.00 | 50.46 | (9.46 | ) | (19 | )% | ||||||||
Powder River Basin | 13.45 | 13.49 | (0.04 | ) | — | % | ||||||||
Western U.S. | 38.09 | 37.90 | 0.19 | 1 | % | |||||||||
Midwestern U.S. | 46.18 | 47.99 | (1.81 | ) | (4 | )% | ||||||||
Operating Costs per Ton - Mining Operations (1) | ||||||||||||||
Australian Metallurgical | $ | 76.20 | $ | 102.60 | $ | (26.40 | ) | (26 | )% | |||||
Australian Thermal | 31.36 | 37.87 | (6.51 | ) | (17 | )% | ||||||||
Powder River Basin | 9.97 | 9.92 | 0.05 | 1 | % | |||||||||
Western U.S. | 27.78 | 26.69 | 1.09 | 4 | % | |||||||||
Midwestern U.S. | 33.49 | 35.70 | (2.21 | ) | (6 | )% | ||||||||
Gross Margin per Ton - Mining Operations (1) | ||||||||||||||
Australian Metallurgical | $ | (1.16 | ) | $ | (8.79 | ) | $ | 7.63 | 87 | % | ||||
Australian Thermal | 9.64 | 12.59 | (2.95 | ) | (23 | )% | ||||||||
Powder River Basin | 3.48 | 3.57 | (0.09 | ) | (3 | )% | ||||||||
Western U.S. | 10.31 | 11.21 | (0.90 | ) | (8 | )% | ||||||||
Midwestern U.S. | 12.69 | 12.29 | 0.40 | 3 | % | |||||||||
(1) | Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring and pension settlement charges; asset impairment; and certain other costs related to post-mining activities. Gross margin per ton is approximately equivalent to segment Adjusted EBITDA divided by segment tons sold. |
Revenues
The following table presents revenues by reporting segment for the years ended December 31, 2015 and 2014:
Year Ended December 31, | Decrease to Revenues | |||||||||||||
2015 | 2014 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Australian Metallurgical Mining | $ | 1,181.9 | $ | 1,613.8 | $ | (431.9 | ) | (26.8 | )% | |||||
Australian Thermal Mining | 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.
Peabody Energy Corporation | 2016 Form 10-K | 65 |
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 coal 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.
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 coal demand due to lower natural gas prices and transition of production from our Gateway Mine to our then 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 pricing, partially offset by improved mark-to-market earnings from financial contract trading.
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:
(Decrease) Increase | ||||||||||||||
Year Ended December 31, | to Income | |||||||||||||
2015 | 2014 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Loss from continuing operations before income taxes | $ | (1,990.3 | ) | $ | (547.9 | ) | $ | (1,442.4 | ) | (263.3 | )% | |||
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 | )% | ||||||||
Adjusted EBITDA | $ | 434.6 | $ | 814.0 | $ | (379.4 | ) | (46.6 | )% | |||||
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 Adjusted EBITDA (discussed below). Refer to Note 4. "Asset Impairment" to the accompanying consolidated financial statements for further information regarding the nature and composition of impairment charges.
Peabody Energy Corporation | 2016 Form 10-K | 66 |
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of our reporting segments for the years ended December 31, 2015 and 2014:
Increase (Decrease) to | ||||||||||||||
Year Ended December 31, | Adjusted EBITDA | |||||||||||||
2015 | 2014 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Australian Metallurgical Mining | $ | (18.2 | ) | $ | (151.1 | ) | $ | 132.9 | 88.0 | % | ||||
Australian Thermal Mining | 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 | % | |||||||||
Corporate and Other | (705.0 | ) | (396.7 | ) | (308.3 | ) | 77.7 | % | ||||||
Adjusted EBITDA | $ | 434.6 | $ | 814.0 | $ | (379.4 | ) | (46.6 | )% | |||||
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 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 26. "Commitments and Contingencies" to the accompanying consolidated financial statements for additional information related to the Eagle matter.
Peabody Energy Corporation | 2016 Form 10-K | 67 |
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 charges | (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, certain coal royalty expenses, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts and expenses related to our other commercial activities. |
Resource management results 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 cost containment efforts. The decrease in restructuring and pension settlement charges 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 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.
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 | ||||||||||||||
Year Ended December 31, | to Income | |||||||||||||
2015 | 2014 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Australian Metallurgical Mining | $ | (178.9 | ) | $ | (221.5 | ) | $ | 42.6 | 19.2 | % | ||||
Australian Thermal Mining | (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 Mining | $ | 5.27 | $ | 4.86 | |||
Australian Thermal Mining | 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 | |||||
Peabody Energy Corporation | 2016 Form 10-K | 68 |
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 4. "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 then 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 had 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 resulted 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 4. "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 were no longer considered more likely than not of being realized. That conclusion was driven by a then recent history of operating losses, as sustained weakness in seaborne metallurgical coal prices had more than offset a successful owner-operator conversion completed in 2013 and an ongoing series of operational efficiency initiatives conducted at the site that had improved the mine's cost structure.
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 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. litigation.
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 14. "Current and 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, | (Decrease) Increase 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.
Peabody Energy Corporation | 2016 Form 10-K | 69 |
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 "Accumulated other comprehensive loss", 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 12. "Income Taxes" to the accompanying consolidated financial statements for additional information.
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, | (Decrease) Increase 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 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" and Note 26. "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, | 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.
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
U.S. Thermal Coal. U.S. domestic electricity generation increased as a result of above-average cooling degree days, which along with increasing natural gas prices since March, positively impacted utility coal consumption and resulted in larger than normal stockpile drawdowns. U.S. coal prices have strengthened with prompt Powder River Basin (PRB) 8,800 Btu/Lb coal prices reaching $12.10 per ton as of December 31, 2016, up 17% year-to-date. As of March 16, 2017, the PRB 8,800 Btu/Lb coal prompt price was $11.35.
Peabody Energy Corporation | 2016 Form 10-K | 70 |
Peabody projects U.S. utility coal consumption to increase approximately 50 to 70 million tons in 2017 versus 2016, driven by higher natural gas prices and improved competitiveness of coal-fired electric generation. Peabody expects U.S. thermal coal supply and demand to continue to rebalance in 2017 as natural gas prices increase, coal consumption grows, exports stabilize and stockpile drawdowns continue. If natural gas prices are lower than projected in 2017, coal consumption will likely decrease relative to expectations.
Seaborne Thermal Coal. Seaborne thermal coal demand rose in the second half of 2016 resulting from increased import demand from China but has declined in recent months as China production increased following the government’s easing of production policy restrictions. Newcastle index thermal coal spot pricing reached its highest level since early 2012 at $114.75 in November, and was $88.40 per tonne as of December 31, 2016, up $37.80 per tonne (75%) year-over-year. Higher China import demand was primarily the result of stronger electricity generation, improved industrial demand and reduced domestic coal supply largely driven by restrictive policies. Seaborne demand growth outside of China has been relatively weak, as evidenced by reduced imports into India. As of March 16, 2017, the Newcastle index thermal coal spot price was $81.10.
Following the strong surge in prices, China relaxed production restrictions multiple times. In addition, recent price levels have incentivized exporting producers to increase production and export supply. A key driver for future seaborne thermal coal supply and demand balance is the outlook for China import demand, which remains uncertain and is expected to be dependent in part on the sustainability and enforcement of China’s domestic production policy.
Seaborne Metallurgical Coal. Supply tightness and increased seaborne import demand have resulted in sharply higher seaborne high quality hard coking coal prices in the second half of 2016. Domestic supply declines in China accelerated during the year largely due to policy restrictions, which along with reduced coal supplies from Australia and other key exporting countries drove spot pricing to $310 per tonne in November, its highest level since May 2011. Hard coking coal spot pricing was at $230 per tonne on December 31, 2016, up 201% year-to-date. Seaborne metallurgical coal prices for high quality hard coking coal and low-vol PCI settled at $285 and $180 per tonne, respectively, for quarterly contracts commencing in January 2017, increasing 43% and 35% percent, respectively, versus prior-quarter price levels. As of March 16, 2017, the hard coking coal and low-vol PCI coal spot prices were $159.75 and $107.75, respectively.
Similar to thermal, China’s domestic metallurgical coal production is expected to increase due to relaxed policy on production curtailments. While the impact remains uncertain, such policy changes could lead to reduced coal imports by China.
Long-Term Outlook
As part of its normal planning and forecasting process, Peabody utilizes a bottom-up approach to develop macroeconomic assumptions for key variables, including country level GDP, industrial production, fixed asset investment and third-party inputs, driving detailed supply and demand projections. This includes key demand centers for coal, generation and steel, while cost curves concentrate on major supply regions/countries that impact the regions in which the Company operates.
Our estimates involve risks and uncertainties and are subject to change based on various factors.
Seaborne Fundamentals
In 2016, seaborne coal prices rose from multi-year lows in the first half of the year to multi-year highs in later months as supply and demand fundamentals improved on strong import demand in China. During 2016, China thermal coal imports increased approximately 22% as compared to 2015, while metallurgical coal imports increased approximately 25% as compared to 2015, driven by domestic production policy restrictions and increased steel production.
Looking ahead, Peabody projects seaborne coal fundamentals to trend higher through 2021. In seaborne metallurgical coal, demand is forecast by Peabody to increase 30 to 35 million tonnes, or 10% – 15%, from 2016 to 2021. Growth in metallurgical coal demand is expected to be led by India, with an increase of approximately 25 million tonnes, which we expect could become the largest importer of seaborne metallurgical coal over this period. Longer-term metallurgical coal pricing is expected by Peabody to retreat to more stable levels, driven by expected China policies restricting supply and the response from seaborne suppliers.
In seaborne thermal coal, demand is expected by Peabody to rise modestly by 25 to 35 million tonnes from 2016 through 2021 as new generation capacity comes on line. Approximately 375 gigawatts of new gross coal capacity are expected by Peabody to be added by 2021. More than 85% of this projected increase is expected to be concentrated in the Asia-Pacific region as Association of Southeast Asian Nations capacity is forecasted by Peabody to surge approximately 75% over the period. Approximately 180 gigawatts are expected by Peabody to be added in China, 64 gigawatts added in India, 72 gigawatts added in other Asian countries and the remainder across the rest of the world. The majority of new capacity is projected by Peabody to be ultra or supercritical boiler types as part of a transition to a lower carbon-emitting coal fleet. Peabody expects a shift toward enhanced boilers to result in stronger demand for higher quality coal.
Peabody Energy Corporation | 2016 Form 10-K | 71 |
We believe Australia is well positioned to supply increased demand for both metallurgical and thermal coal, while Colombia is also positioned to grow thermal coal exports. Due to the cyclical nature of the coal industry, supply and demand fundamentals are subject to extreme fluctuations over time.
U.S. Fundamentals
In the U.S., coal demand rebounded in the second half of 2016 as natural gas prices rose sharply from the lowest levels in approximately 15 years. Peabody expects 2017 coal consumption to rebound from 2016 levels on higher natural gas prices. As a result, coal is projected by Peabody to fuel over 30% of U.S. electricity generation in 2017.
Longer term, Peabody forecasts U.S. coal consumption will decline 5 to 15 million tons between 2016 and 2021 as expected coal plant retirements are largely offset by higher capacity utilization at remaining plants. Approximately 50 gigawatts of plant retirements are expected by Peabody over the period, and competition for coal in electric generation from natural gas is expected to continue given low natural gas production costs and sufficient reserves.
By 2021, Peabody expects coal to supply an estimated 29% of U.S. electricity generation, down from approximately 30% in 2016. Coal from the PRB and Illinois Basin (ILB) is expected to remain most competitive on average against natural gas based on delivered fuel costs. By 2021, the PRB and ILB are projected by Peabody to supply nearly 55% of U.S. coal compared to approximately 51% in 2016. In addition, we believe PRB coal prices will improve over the period while ILB prices will stabilize. Key variables impacting stockpiles and prices included GDP, weather, renewables and gas exports. The economics of coal pricing and volume remain highly sensitive to natural gas prices.
Liquidity and Capital Resources
Overview
Our primary sources of cash are proceeds from the sale of our coal production to customers. We have also generated cash from the sale of non-strategic assets, including coal reserves and surface lands. Our primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, capital and operating lease payments, postretirement plans, take-or-pay obligations and post-mining retirement obligations. Historically, we have also generated cash from borrowings under our credit facilities and, from time to time, the issuance of securities.
Total Indebtedness. Our total indebtedness as of December 31, 2016 and 2015 consisted of the following:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
2013 Revolver | $ | 1,558.1 | $ | — | |||
2013 Term Loan Facility due September 2020 | 1,154.5 | 1,156.3 | |||||
6.00% Senior Notes due November 2018 | 1,509.9 | 1,508.9 | |||||
6.50% Senior Notes due September 2020 | 645.8 | 645.5 | |||||
6.25% Senior Notes due November 2021 | 1,327.7 | 1,327.0 | |||||
10.00% Senior Secured Second Lien Notes due March 2022 | 962.3 | 960.4 | |||||
7.875% Senior Notes due November 2026 | 245.9 | 245.8 | |||||
Convertible Junior Subordinated Debentures due December 2066 | 367.1 | 366.3 | |||||
Capital lease obligations | 19.7 | 30.3 | |||||
Other | 0.4 | 0.7 | |||||
7,791.4 | 6,241.2 | ||||||
Less: Current portion of long-term debt | 20.2 | 5,874.9 | |||||
Less: Liabilities subject to compromise | 7,771.2 | — | |||||
Long-term debt | $ | — | $ | 366.3 | |||
Refer to Note 14. "Current and Long-term Debt" to the accompanying consolidated financial statements for further information regarding our indebtedness.
Peabody Energy Corporation | 2016 Form 10-K | 72 |
Liquidity After Filing Under Chapter 11 of the United States Bankruptcy Code
As of December 31, 2016, our available liquidity was $872.3 million, which was comprised of cash and cash equivalents. Of the $872.3 million of liquidity, $394.5 million was held by Debtor entities. Peabody is limited in its ability to transfer funds between Debtor and non-debtor entities or between certain non-debtor entities by court order, and, in certain instances, Peabody must first seek the approval of the Bankruptcy Court to make such transfers.
During the first quarter of 2016, we borrowed $947.0 million under the $1.65 billion revolving credit facility (as amended, the 2013 Revolver) for general corporate purposes. As a result of filing the Bankruptcy Petitions on April 13, 2016, we are in default under the 2013 Credit Facility and as such the 2013 Revolver can no longer be utilized.
As of the Petition Date, we had approximately $675 million letters of credit outstanding under the 2013 Revolver. Subsequent to the Petition Date, certain counterparties drew on a portion of those letters of credit. The letters of credit were in place to support various types of obligations, though the most significant items related to bank guarantees in place for reclamation bonding requirements in Australia. The draws required the recording of previously off-balance sheet liabilities, except in certain instances where we had previously recorded a liability, and as such have been reflected as additional borrowings under the 2013 Revolver. The total of such letters of credit drawn was $611.1 million during the year ended December 31, 2016. "Investments and other assets" in the consolidated balance sheets as of December 31, 2016 includes $479.3 million of cash collateral in support of certain of these obligations.
Subject to certain exceptions under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the filing of the Bankruptcy Petitions. Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors' property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a prepetition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.
The Bankruptcy Court has approved payment of certain prepetition obligations, including payments for employee wages, salaries and certain other benefits, customer programs, taxes, utilities and certain payments of insurance, essential suppliers, possessory lien vendors and surety bond issuers. Despite the liquidity provided by our existing cash on hand and cash from operations, our ability to maintain normal credit terms with our suppliers may become impaired. We have been and may continue to be required to pay cash in advance to certain vendors and may experience restrictions on the availability of trade credit, which would further reduce our liquidity. Our suppliers could refuse to provide key products and services if we are unable to reach an agreement on credit terms. In addition, due to the public perception of our financial condition and results of operations, in particular with regard to our potential failure to meet our debt obligations, some customers could be reluctant to enter into long-term agreements with us or may seek to terminate or modify their contracts with us.
We have incurred and expect to continue to incur significant costs associated with the Chapter 11 Cases and our reorganization, but we cannot accurately predict the effect the Chapter 11 Cases will have on our operations, liquidity, financial position and results of operations. We believe that our cash on hand and cash generated from the results of our operations will be sufficient to fund anticipated cash requirements through the Chapter 11 Cases for minimum operating and capital expenditures and for working capital purposes. However, given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our mining operations, our liquidity needs could be significantly higher than we currently anticipate.
Our ability to maintain adequate liquidity through the reorganization process and beyond depends on our ability to successfully implement a plan of reorganization, operate our business, and manage our operating expenses and capital spending. Our anticipated liquidity needs are highly sensitive to changes in each of these and other factors. 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 liquidity after the filing of our Chapter 11 Cases.
Peabody Energy Corporation | 2016 Form 10-K | 73 |
Superpriority Secured Debtor-In-Possession Credit Agreement
On the Petition Date, the Debtors filed a motion (the DIP Motion) seeking authorization to use cash collateral and to approve financing (the DIP Financing) under that certain Superpriority Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) by and among Peabody as borrower, Peabody Global Funding, LLC, formerly known as the Global Center for Energy and Human Development and certain Debtors party thereto as guarantors (the Guarantors and together with the Company, the Loan Parties), the lenders party thereto (the DIP Lenders) and Citibank, N.A. as Administrative Agent (in such capacity, the DIP Agent) and L/C Issuer. The DIP Credit Agreement provided for (i) a term loan not to exceed $500 million (the DIP Term Loan Facility), of which $200 million was made available upon entry of an interim order, the remaining $300 million pending the entry of the final order approving the DIP Credit Agreement (the Final Order), secured by substantially all of the assets of the Loan Parties, subject to certain excluded assets and carve outs and guaranteed by the Loan Parties (other than the Company), which would be used for working capital and general corporate purposes, to cash collateralize letters of credit and to pay fees and expenses, (ii) a cash collateralized letter of credit facility in an amount up to $100 million (the L/C Facility), and (iii) a bonding accommodation facility in an amount up to $200 million consisting of (x) a carve-out from the collateral with superpriority claim status, subject only to the fees carve-out, entitling the authority making any bonding request to receive proceeds of collateral first in priority before distribution to any DIP Lender or other prepetition secured creditor, except for letters of credit issued under the DIP Credit Agreement and/or (y) a letter of credit facility (the Bonding L/C Facility). The aggregate face amount of all letters of credit issued under the L/C Facility and the Bonding L/C Facility could not at any time exceed $50 million without DIP Lender consent.
On April 15, 2016, the Bankruptcy Court issued an order approving the DIP Motion on an interim basis and authorizing the Loan Parties to, among other things, (i) enter into the DIP Credit Agreement and initially borrow up to $200 million, (ii) obtain a cash collateralized letter of credit facility in the aggregate amount of up to $100 million, and (iii) establish an accommodation facility for bonding requests in an aggregate stated amount of up to $200 million under the DIP Term Loan Facility. On April 18, 2016, we entered into the DIP Credit Agreement with the DIP Lenders and borrowed $200 million under the DIP Term Loan Facility. On May 17, 2016, the Bankruptcy Court approved the DIP Financing on a final basis and entered an order to that effect on May 18, 2016. On May 19, 2016, following entry of the Final Order, we borrowed the remaining $300 million available under the DIP Term Loan Facility. We paid aggregate debt issuance costs of $26.8 million during the year ended December 31, 2016 related to the DIP Term Loan Facility.
On December 14, 2016, the Bankruptcy Court entered an order authorizing the repayment of the DIP Term Loan Facility prior to its scheduled maturity date and on December 15, 2016, we repaid the DIP Term Loan Facility in full. Upon making this payment, our obligations under the DIP Credit Agreement were satisfied in full and it was terminated. In connection with the repayment and termination, we incurred a loss on the early debt extinguishment of $29.5 million, consisting of a $10.0 million early-termination fee and $19.5 million related to the write-off of unamortized deferred financing costs and an original issue discount.
Accounts Receivable Securitization Program
On March 25, 2016, we amended and restated our accounts receivable securitization program (securitization program) to, among other things, extend the term of the program by two years to March 23, 2018 and reduce the maximum availability under the facility from $275.0 million to $180.0 million. The accessible capacity of the program varies daily, dependent upon the actual amount of receivables available for contribution and various reserves and limits. As of December 31, 2016, $40.5 million was deposited in a collateral account to secure letters of credit.
With the approval of the Bankruptcy Court, we executed two additional amendments to the March 25, 2016 securitization agreement during the second quarter of 2016. These amendments permit the continuation of the securitization program through our Chapter 11 Cases, change the maturity date to the earlier of March 23, 2018 or the emergence of the Debtors from the Chapter 11 Cases, revise the associated fees and enter into an additional performance guarantee by our subsidiaries that are contributors under the securitization facility to fulfill the obligations of the other contributors.
On January 27, 2017, the Company and P&L Receivables Company, LLC (P&L Receivables) obtained a commitment letter (Commitment Letter) from PNC Bank, National Association (PNC), pursuant to which, in connection with the consummation of the proposed Plan, PNC has agreed to amend the existing securitization facility evidenced by the Fifth Amended and Restated Receivables Purchase Agreement, dated as of March 25, 2016 (as amended prior to the date hereof), among P&L Receivables, as the seller, the Company, as the servicer, the sub-servicers party thereto, the various purchasers and purchaser agents party thereto and PNC, as administrator, in order to, among other things, (i) increase the purchase limit to an amount not to exceed $250.0 million (the Purchase Limit), (ii) extend the facility termination date, and (iii) add certain Australian subsidiaries of the Company as originators (as so amended, the Sixth Amended Securitization Facility).
The commitment of PNC to provide 100% of the Purchase Limit under the Sixth Amended Securitization Facility is subject to certain conditions set forth in the Commitment Letter, including but not limited to the occurrence or waiver of all conditions precedent to the effectiveness of the Plan.
Peabody Energy Corporation | 2016 Form 10-K | 74 |
The Commitment Letter will terminate upon the occurrence of certain events described therein. The outside termination date for the Commitment Letter is May 1, 2017.
On January 27, 2017, the Debtors filed a motion with the Bankruptcy Court seeking authorization to enter into and perform under the Commitment Letter. On February 15, 2017, the Bankruptcy Court issued an order authorizing the Company’s entry into and performance under the Commitment Letter.
Exit Financing
On January 11, 2017, the Debtors obtained an exit facility commitment letter (Exit Facility Commitment Letter) from a consortium of lenders (Lenders), pursuant to which, in connection with the consummation of the Plan, the Lenders have agreed to provide a senior secured term loan facility (Term Loan Facility) in an aggregate amount of (a) $1.5 billion, less (b) the aggregate principal amount of privately placed debt securities (Notes) of the Company, or special purpose escrow issuer, issued on or prior to the closing date of the Term Loan Facility (Closing Date), plus (c) any amount of additional senior secured term loans funded on the Closing Date at the sole discretion of the Term Loan Facility's arranging Lenders and the Company.
The commitments of the Lenders to provide the Term Loan Facility are subject to the occurrence or waiver of all conditions precedent to the effectiveness of the Plan, other than the closing and funding of the Term Loan Facility (and the Notes issued in lieu thereof, if any). The Lenders’ commitments to provide and arrange the Term Loan Facility will terminate on a dollar-for-dollar basis to the extent of the issuance of the Notes.
On February 8, 2017, the Company announced the pricing of a $950.0 million senior secured term loan. The term loan will mature in 2022 and bear interest at a fluctuating rate of LIBOR plus 4.50% per annum, with a 1.00% LIBOR floor. The closing of the term loan is expected to occur in early April 2017, concurrent with the Plan Effective Date and subject to customary closing conditions and final documentation. The proceeds from the term loan will be used to fund a portion of the distributions to creditors provided for under the Plan.
Also on February 8, 2017, the Company announced that a special purpose wholly owned subsidiary of the Company priced an offering of $500.0 million aggregate principal amount of 6.000% senior secured notes due 2022 and $500.0 million aggregate principal amount of 6.375% senior secured notes due 2025, each exempt from the registration requirements of the Securities Act of 1933, as amended. The offering of the notes closed on February 15, 2017 at which time the net proceeds of the offering were funded into an escrow account pending the Plan Effective Date. The notes were offered by a special purpose wholly owned subsidiary of the Company. If certain conditions are satisfied on or before August 1, 2017, the net proceeds from the offering will be released from escrow to fund a portion of the distributions to creditors provided for under the Plan, and the Company will become the obligor under the notes.
Capital Requirements
Additions to Property, Plant, Equipment and Mine Development. Additions to property, plant, equipment and mine development during the year ended December 31, 2016 included expenditures associated with the extension of our Twentymile Mine in the U.S. and expenditures to sustain production across our operating platform.
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 2016, our additions to property, plant, equipment and mine development of $126.6 million were comparable to the prior year. For 2017, we are again targeting a tightly controlled capital expenditure level of $160 million to $190 million. We plan to defer significant growth and development projects across our global platform to time periods beyond 2017 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 Powder River Basin Mining and Western U.S. Mining segment operations, amounted to $249.0 million in 2016. The 2016 expenditures primarily consisted of our final required payments on our current leases in the Powder River Basin. We currently anticipate that our annual federal coal lease expenditures will total approximately $1 million in 2017. In January 2016, the Secretary of the Interior ordered a three-year pause on new leases for coal mined on federal land as part of a review of the federal coal leasing program.
Settlement Agreement with the UMWA 1974 Pension Plan (UMWA Plan). On January 25, 2017, the UMWA Plan and the Debtors agreed to a settlement of the UMWA Plan's claim whereby the UMWA Plan will be entitled to $75 million to be paid by the Company as follows: $5 million on the Plan Effective Date, $10 million paid 90 days subsequent to that date, $15 million paid one year later and $15 million per year for the following three years. On March 15, 2017, the Debtors filed with the Bankruptcy Court a notice of settlement between the Debtors and the UMWA Plan.
Refer to Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" to the accompanying consolidated financial statements for additional information surrounding the settlement agreement.
Peabody Energy Corporation | 2016 Form 10-K | 75 |
Pension Contributions. Annual contributions to qualified plans are made in accordance with minimum funding standards and our 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, 2016, we contributed $0.5 million and $0.6 million to our qualified and non-qualified pension plans, respectively. We expect to contribute approximately $5.9 million to our pension plans to meet minimum funding requirements for our qualified plans and benefit payments for our non-qualified plans in 2017. Contributions to non-qualified plans ceased subsequent to April 12, 2016 as a result of filing the Bankruptcy Petitions.
Historical Cash Flows
The following table summarizes our cash flows for the years ended December 31, 2016 and 2015, as reported in the accompanying consolidated financial statements:
Year Ended December 31, | Increase (Decrease) to Cash Flow | |||||||||||||
2016 | 2015 | $ | % | |||||||||||
(Dollars in millions) | ||||||||||||||
Net cash used in operating activities | $ | (52.8 | ) | $ | (14.4 | ) | $ | (38.4 | ) | (266.7 | )% | |||
Net cash used in investing activities | (244.1 | ) | (290.0 | ) | 45.9 | 15.8 | % | |||||||
Net cash provided by financing activities | 907.9 | 267.7 | 640.2 | 239.1 | % | |||||||||
Net change in cash and cash equivalents | 611.0 | (36.7 | ) | 647.7 | 1,764.9 | % | ||||||||
Cash and cash equivalents at beginning of period | 261.3 | 298.0 | (36.7 | ) | (12.3 | )% | ||||||||
Cash and cash equivalents at end of period | $ | 872.3 | $ | 261.3 | $ | 611.0 | 233.8 | % | ||||||
Operating Activities. The decrease in net cash used in operating activities for the year ended December 31, 2016 compared to the prior year was driven by the following:
• | A reduction in the amount drawn on our accounts receivable securitization program ($307.0 million); |
• | Funds that became restricted during the year as collateral for financial assurances associated with reclamation bonding requirements ($125.7 million); partially offset by |
• | A year-over-year increase in working capital ($253.3 million); and |
• | An increase associated with the reclassification from other comprehensive income for terminated hedge contracts that occurred in 2016 ($125.2 million). |
Investing Activities. The favorable change in cash results from investing activities for the year ended December 31, 2016 compared to the prior year was mainly due to:
• | Higher proceeds from disposals of assets ($74.0 million) primarily due to the sale of our 5.06% participation interest in the Prairie State Energy Campus, as well as our interest in undeveloped metallurgical reserve tenements in Queensland's Bowen Basin, which included the Olive Downs South, Olive Downs South Extended and Willunga tenements; and |
• | Lower federal coal lease expenditures ($28.2 million); partially offset by |
• | Lower net proceeds from debt and equity security investment transactions ($61.5 million) due primarily to 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. |
Financing Activities. The increase in net cash provided by financing activities for the year ended December 31, 2016 compared to the prior year was reflective of:
• | Higher proceeds from long-term debt ($454.1 million), primarily due to the proceeds received from our DIP Term Loan Facility during the second quarter of 2016 ($475.0 million, net of original issue discount) and the net draws on our 2013 Revolver during the first quarter of 2016 ($947.0 million), partially offset by proceeds received from our Senior Secured Second Lien Notes ($975.7 million, net of original issue discount) during the first quarter of 2015; and |
• | Lower repayments of long-term debt ($157.6 million), mainly due to the extinguishment of $650.0 million aggregate principal of our 2016 Senior Notes in the first quarter of 2015, offset by the repayment of the DIP Term Loan Facility ($500.0 million) in the fourth quarter of 2016. |
Peabody Energy Corporation | 2016 Form 10-K | 76 |
Contractual Obligations
The following is a summary of our contractual obligations as of December 31, 2016:
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) (1) | $ | 9,377.6 | $ | 490.2 | $ | 2,363.8 | $ | 2,343.9 | $ | 4,179.7 | |||||||||
Capital lease obligations (principal and interest) | 27.3 | 7.3 | 9.4 | 1.0 | 9.6 | ||||||||||||||
Operating lease obligations(2) | 372.9 | 148.7 | 160.6 | 37.0 | 26.6 | ||||||||||||||
Unconditional purchase obligations(3) | 7.4 | 7.4 | — | — | — | ||||||||||||||
Coal reserve lease and royalty obligations | 53.8 | 6.1 | 10.9 | 10.2 | 26.6 | ||||||||||||||
Take-or-pay obligations(4) | 1,596.9 | 209.9 | 379.7 | 234.7 | 772.6 | ||||||||||||||
Other long-term liabilities(5) | 3,240.6 | 239.1 | 339.7 | 437.2 | 2,224.6 | ||||||||||||||
Total contractual cash obligations | $ | 14,676.5 | $ | 1,108.7 | $ | 3,264.1 | $ | 3,064.0 | $ | 7,239.7 | |||||||||
(1) | Represents the original contractual maturities of our long-term debt obligations, although $7.8 billion of debt is classified as liabilities subject to compromise as a result of our Chapter 11 Cases. The related interest on long-term debt was calculated using rates in effect at December 31, 2016 for the remaining contractual term of the outstanding borrowings. The above table does not include indebtedness expected to be incurred in connection with the Plan. |
(2) | Excludes contingent rents. Refer to Note 15. "Leases" to the accompanying consolidated financial statements for additional discussion of contingent rental agreements. |
(3) | 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. |
(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. |
(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 $13 million of required payments to the VEBA established in connection with Patriot's bankruptcy, as well as $75 million related to the settlement of the UMWA 1974 Pension Plan Litigation described in Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" to the accompanying consolidated financial statements. |
We do not expect any of the $20.1 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 21, 2017, 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, 2016. However, we could experience a decline in our liquidity as financial assurances associated with reclamation bonding requirements, 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 25. "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.
Peabody Energy Corporation | 2016 Form 10-K | 77 |
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 as a triggering event for conducting impairment tests because of historic price volatility. However, we view a sustained trend of depressed coal 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).
Impairment of long-lived assets included in continuing operations was $247.9 million for the year ended December 31, 2016. 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 our 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 our operating costs, may result in the need for future adjustments to the carrying value of our long-lived mining assets. Our assets whose recoverability and values are most sensitive to near-term pricing include certain Australian metallurgical and thermal assets 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 $1,407.3 million as of December 31, 2016. We conducted a review of those assets for recoverability as of December 31, 2016 and determined that, other than the charges described above, no further impairment charge was necessary as of that date.
See Note 4. "Asset Impairment" to our consolidated financial statements for additional information regarding impairment charges.
Peabody Energy Corporation | 2016 Form 10-K | 78 |
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, 2016, we had valuation allowances for income taxes totaling $3,881.2 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, 2016, we had net unrecognized tax benefits of $20.1 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 12. "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, 2016 for postretirement benefit costs and pension liabilities totaled $79.8 million, while employer contributions were $49.5 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.
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, 2016 | |||||||
One-Percentage- Point Increase | One-Percentage- Point Decrease | ||||||
(Dollars in millions) | |||||||
Health care cost trend rate: | |||||||
Effect on total net periodic postretirement benefit cost | $ | 10.6 | $ | (9.3 | ) | ||
Effect on total postretirement benefit obligation | $ | 67.0 | $ | (61.9 | ) | ||
For Year Ended December 31, 2016 | |||||||
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 | ) | $ | 2.2 | ||
Effect on total postretirement benefit obligation | $ | (39.4 | ) | $ | 44.7 | ||
Peabody Energy Corporation | 2016 Form 10-K | 79 |
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, 2016 | |||||||
One-Half Percentage- Point Increase | One-Half Percentage- Point Decrease | ||||||
(Dollars in millions) | |||||||
Discount rate: | |||||||
Effect on total net periodic pension cost | $ | (6.9 | ) | $ | 7.4 | ||
Effect on defined benefit pension plans' funded status | $ | 48.0 | $ | (52.5 | ) | ||
Expected return on assets: | |||||||
Effect on total net periodic pension cost | $ | (3.8 | ) | $ | 3.8 | ||
See Note 17. "Postretirement Health Care and Life Insurance Benefits" and Note 18. "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, 2016 were $41.8 million, and payments totaled $28.7 million. See Note 16. "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.
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%, we consider 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, 2016 we had no Corporate Hedging Instruments and Contracts categorized as Level 3. See Note 8. "Derivatives and Fair Value Measurements" to our consolidated financial statements for additional information regarding fair value measurements of our net financial asset trading positions.
Peabody Energy Corporation | 2016 Form 10-K | 80 |
At December 31, 2016, we had liabilities of $1.1 million of Coal Trading Instruments and Contracts categorized as Level 3. See Note 9. "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. See Note 26. "Commitments and Contingencies" to our accompanying consolidated financial statements for further discussion of our contingent liabilities.
Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
See Note 1. "Summary of Significant Accounting Policies" to our accompanying 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.
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.
Peabody Energy Corporation | 2016 Form 10-K | 81 |
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, and options as of December 31, 2016. 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 15-day holding period 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, 2016, the actual low, high and average VaR was $0.6 million, $7.9 million and $2.9 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, 2016, the estimated future realization of the value of our trading portfolio is expected to be fully realized in 2017.
We also monitor other types of risk associated with our coal trading activities, including credit, market liquidity and counterparty nonperformance.
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.
Peabody Energy Corporation | 2016 Form 10-K | 82 |
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 have historically utilized currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. The accounting for these derivatives is discussed in Note 8. "Derivatives and Fair Value Measurements" to the accompanying consolidated financial statements. The Bankruptcy Petitions constituted an event of default under our derivative financial instrument contracts and the counterparties terminated the agreements shortly thereafter in accordance with contractual terms. As a result, we no longer have any foreign currency hedging instruments in place. Therefore, our exposure in operating costs and expenses due to a $0.05 change in the Australian dollar/U.S. dollar exchange rate is approximately $85 million for the next twelve months.
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 86%, 88% and 83% of our worldwide sales (by volume) for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016, approximately 95% of our projected 2017 U.S. coal production is priced at planned production levels of approximately 145 million to 155 million tons. We are estimating 2017 thermal coal sales volumes from our Australian business unit of approximately 21 million to 22 million tons. We expect near-term macroeconomic movements to dictate quarterly metallurgical coal pricing for the remainder of 2017 and are targeting full year 2017 metallurgical coal sales from our Australian business unit of approximately 10 million to 11 million tons.
Diesel Fuel Hedges. We have historically managed price risk of the diesel fuel used in our mining activities through the use of cost pass-through contracts and from time to time, derivatives, primarily swaps. The Bankruptcy Petitions constituted an event of default under our derivative financial instrument contracts and the counterparties terminated the agreements shortly thereafter in accordance with contractual terms. As a result, we no longer have any diesel fuel derivative instruments in place.
We expect to consume 125 million to 135 million gallons of diesel fuel in 2017. 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.
Interest Rate Risk
The Company’s current and long-term debt as of December 31, 2016 is subject to compromise in connection with the Company's plan of reorganization and as such we are unable to calculate the interest rate risk on the company's debt.
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.
Peabody Energy Corporation | 2016 Form 10-K | 83 |
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, 2016, 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, 2016, 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, procedures and control documentation requirements, 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, 2016 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.
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, 2016.
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 21, 2017
Peabody Energy Corporation | 2016 Form 10-K | 84 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of Peabody Energy Corporation and subsidiaries
We have audited Peabody Energy Corporation and subsidiaries’ (the Company’s) internal control over financial reporting as of December 31, 2016, 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 and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, 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 and subsidiaries as of December 31, 2016 and 2015, 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, 2016 of Peabody Energy Corporation and subsidiaries and our report dated March 21, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
St. Louis, Missouri
March 21, 2017
Peabody Energy Corporation | 2016 Form 10-K | 85 |
Item 9B. Other Information.
None.
PART III
Item 10.Directors, Executive Officers and Corporate Governance.
As set forth in the Plan, following the Plan Effective Date, the Company's Board of Directors will consist of nine directors, Mr. Kellow and eight independent directors. On March 6, 2017, the Company filed a supplement to the Plan setting forth the members of the Board of Directors assuming the plan becomes effective. The following provides information regarding the Company's Board of Directors as of December 31, 2016.
Directors of the Company | ||
WILLIAM A. COLEY Age: 73 Director Since: March 2004 | Board Committees: Compensation Health, Safety, Security and Environmental | Other Public Directorships: None Former Public Directorships: British Energy Group plc CT Communications, Inc. SouthTrust Bank Duke Energy |
From March 2005 to July 2009, Mr. Coley served as Chief Executive Officer and Director of British Energy Group plc, the United Kingdom’s largest electricity producer. He was previously a non-executive director of British Energy. Mr. Coley served as President of Duke Power, the U.S.-based global energy company, from 1997 until his retirement in February 2003. During his 37-year career at Duke Power, Mr. Coley held various officer-level positions in the engineering, operations and senior management areas, including Vice President, Operations (1984-1986), Vice President, Central Division (1986-1988), Senior Vice President, Power Delivery (1988-1990), Senior Vice President, Customer Operations (1990-1991), Executive Vice President, Customer Group (1991-1994) and President, Associated Enterprises Group (1994-1997). Mr. Coley was elected to the board of Duke Power in 1990 and was named President following Duke Power’s acquisition of PanEnergy in 1997. Mr. Coley earned his B.S. in electrical engineering from the Georgia Institute of Technology and is a registered professional engineer. He is also a director of two private companies, E. R. Jahna Enterprises and Ontario Power Generation.
WILLIAM E. JAMES Age: 71 Director Since: July 2001 | Board Committees: Compensation Nominating and Corporate Governance | Other Public Directorships: None Former Public Directorships: Ener1, Inc. |
In July 2000, Mr. James co-founded RockPort Capital Partners LLC, a venture capital fund specializing in energy and power, advanced materials, process and prevention technologies, transportation and green building technologies. From July 2000 to December 2013, he was Managing General Partner of the fund. In January 2014, he became a General Partner of the fund. Prior to joining RockPort, Mr. James co-founded and served as Chairman and Chief Executive Officer of Citizens Power LLC, the nation’s first and a leading power marketer. He also co-founded the nonprofit Citizens Energy Corporation and served as the Chairman and Chief Executive Officer of Citizens Corporation, its for-profit holding company, from 1987 to 1996. Mr. James is also a director of a private company, MicroSeismic, Inc.
Peabody Energy Corporation | 2016 Form 10-K | 86 |
ROBERT B. KARN, III Age: 75 Director Since: January 2003 | Board Committees: Audit Nominating and Corporate Governance | Other Public Directorships: Natural Resource Partners L.P. Numerous NYSE-listed closed-end, open-end mutual and exchange-traded funds under the Guggenheim Financial Family of Funds (about 100 funds) Investment Company Directorships: Kennedy Capital Management Former Investment Company Directorships: Fiduciary/Claymore Dynamic Equity Fund |
Mr. Karn is a financial consultant and former managing partner in financial and economic consulting with Arthur Andersen LLP in St. Louis. Before retiring from Arthur Andersen in 1998, Mr. Karn served in a variety of accounting, audit and financial roles over a 33-year career, including Managing Partner in charge of Arthur Andersen’s global coal mining practice from 1981 through 1998. He is a Certified Public Accountant and has served as a Panel Arbitrator with the American Arbitration Association.
GLENN L. KELLOW Age: 49 Director Since: January 2015 | Board Committees: Executive | Other Public Directorships: None |
Mr. 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 and 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.
Peabody Energy Corporation | 2016 Form 10-K | 87 |
HENRY E. LENTZ Age: 72 Director Since: February 1998 | Board Committees: Executive Health, Safety, Security and Environmental Nominating and Corporate Governance (Chair) | Other Public Directorships: CARBO Ceramics, Inc. Macquarie Infrastructure Company WPX Energy, Inc. Former Public Directorships: Rowan Companies, Inc. |
Mr. Lentz served as a Managing Director of Lazard Frères & Co. LLC, an investment banking firm, from June 2009 to May 2011. He was a Managing Director of Barclays Capital, an investment banking firm and successor to Lehman Brothers Inc., an investment banking firm, from September 2008 to June 2009. From January 2004 to September 2008 he was employed as an Advisory Director by Lehman Brothers. He joined Lehman Brothers in 1971 and became a Managing Director in 1976. He left the firm in 1988 to become Vice Chairman of Wasserstein Perella Group, Inc., an investment banking firm. In 1993, he returned to Lehman Brothers as a Managing Director and served as head of the firm’s worldwide energy practice. In 1996, he joined Lehman Brothers’ Merchant Banking Group as a Principal and in January 2003 became a consultant to the Merchant Banking Group.
ROBERT A. MALONE Age: 65 Director Since: July 2009 | Board Committees: Executive (Chair) Nominating and Corporate Governance Non-Executive Chairman | Other Public Directorships: Halliburton Company Teledyne Corporation |
Mr. Malone was elected Executive Chairman, President and CEO of First Sonora Bancshares, Inc., a financial services holding company, in October 2014. He also serves as Chairman, President and Chief Executive Officer of the First National Bank of Sonora, Texas, a position he held since October 2009. He is a retired Executive Vice President of BP plc and the retired Chairman of the Board and President of BP America Inc., at the time the largest producer of oil and natural gas and the second largest gasoline retailer in the U.S. He served in that position from 2006 to 2009. Mr. Malone previously served as Chief Executive Officer of BP Shipping Limited from 2002 to 2006, as Regional President Western United States, BP America Inc. from 2000 to 2002 and as President, Chief Executive Officer and Chief Operating Officer, Alyeska Pipeline Service Company from 1996 to 2000. Mr. Malone previously served in senior positions with Kennecott Copper Corporation. He is also a director of four private companies, First Sonora Bancshares, Inc., the First National Bank of Sonora, Texas, INTERA Incorporated and International City Mortgage, Inc.
WILLIAM C. RUSNACK Age: 72 Director Since: January 2002 | Board Committees: Audit Compensation (Chair) Executive | Other Public Directorships: Sempra Energy Company Flowserve Corporation Former Public Directorships: Solutia Inc. |
Mr. Rusnack served as the President and Chief Executive Officer of Premcor Inc., one of the largest independent oil refiners in the U.S. prior to its acquisition by Valero Energy Corporation in 2005. He served as President, Chief Executive Officer and Director of Premcor from 1998 to February 2002. Prior to joining Premcor, Mr. Rusnack was President of ARCO Products Company, the refining and marketing division of Atlantic Richfield Company. During a 31-year career at ARCO, he was also President of ARCO Transportation Company and Vice President of Corporate Planning.
MICHAEL W. SUTHERLIN Age: 70 Director Since: January 2014 | Board Committees: Compensation Health, Safety, Security and Environmental | Other Public Directorships: Tesco Corporation Schnitzer Steel Industries, Inc. Former Public Directorships: Joy Global Inc. |
Mr. Sutherlin served as the President and Chief Executive Officer of Joy Global Inc., a mining equipment and services provider from 2006 to 2013. From 2003 to 2006, he served as Executive Vice President of Joy Global Inc. and as President and Chief Operating Officer of its subsidiary, Joy Mining Machinery. Prior to joining Joy Global Inc., Mr. Sutherlin served as President and Chief Operating Officer of Varco International, Inc.
Peabody Energy Corporation | 2016 Form 10-K | 88 |
JOHN F. TURNER Age: 75 Director Since: July 2005 | Board Committees: Executive Health, Safety, Security and Environmental (Chair) Nominating and Corporate Governance | Other Public Directorships: None Former Public Directorships: American Electric Power Company, Inc. Ashland, Inc. International Paper Company |
Mr. Turner served as Assistant Secretary of State for the Bureau of Oceans and International Environmental and Scientific Affairs from November 2001 to July 2005. Mr. Turner was previously President and Chief Executive Officer of The Conservation Fund, a national nonprofit organization dedicated to public-private partnerships to protect land and water resources. He was director of the U.S. Fish and Wildlife Service from 1989 to 1993. Mr. Turner also served in the Wyoming state legislature for 19 years and is a past president of the Wyoming State Senate. He serves on the National Council of The Conservation Fund. Mr. Turner also serves as Chairman of the Board of Advisors to the Haub School of Environment and Natural Resources, the University of Wyoming.
SANDRA A. VAN TREASE Age: 56 Director Since: January 2003 | Board Committees: Audit (Chair) Executive Health, Safety, Security and Environmental | Other Public Directorships: Enterprise Financial Services Corporation |
Ms. Van Trease is Group President, BJC HealthCare, a position she has held since September 2004. BJC HealthCare is one of the nation’s largest nonprofit healthcare organizations, delivering services to residents in the greater St. Louis, southern Illinois and mid-Missouri regions. Prior to joining BJC HealthCare, Ms. Van Trease served as President and Chief Executive Officer of UNICARE, an operating affiliate of WellPoint Health Networks Inc., from 2002 to September 2004. Ms. Van Trease also served as President, Chief Financial Officer and Chief Operating Officer of RightCHOICE Managed Care, Inc. from 2000 to 2002 and as Executive Vice President, Chief Financial Officer and Chief Operating Officer from 1997 to 2000. Prior to joining RightCHOICE in 1994, she was a Senior Audit Manager with Price Waterhouse LLP. She is a Certified Public Accountant and Certified Management Accountant.
HEATHER A. WILSON Age: 56 Director Since: August 2013 | Board Committees: Audit Nominating and Corporate Governance | Other Public Directorships: Raven Industries, Inc. |
Dr. Wilson has served as President of the South Dakota School of Mines and Technology since June 2013. During 2011 and 2012, Dr. Wilson was a candidate for election to the U.S. Senate. From 2009 to 2011, she served as President of the consulting firm of Heather Wilson & Company. From 1998 to 2009, Dr. Wilson served as a member of the U.S. House of Representatives, where she served as a senior member of the House Energy and Commerce Committee and Chair of the House Intelligence Subcommittee on Technical and Tactical Intelligence. Prior to that time, Dr. Wilson served as Cabinet Secretary for the State of New Mexico Children, Youth and Families Department, as founder and President of Keystone International, Inc., a company dedicated to international business development, and as Staff Director of Defense Policy and Arms Control for the National Security Council. She is a former U.S. Air Force officer.
President Trump has nominated Dr. Wilson to serve as Secretary of the Air Force. On January 23, 2017, Dr. Wilson notified the Board that she will resign from the Board effective if and when she is confirmed as Secretary of the Air Force.
Executive Officers of the Company
Information concerning the executive officers of the Company is set forth in Part I, Item 1. “Business” under the caption “Executive Officers of the Company” of this Form 10-K.
Section 16(a) Beneficial Ownership Reporting Compliance
Our officers and directors and persons beneficially holding more than 10% of our common stock are required under the Securities Exchange Act of 1934, as amended, to file reports of ownership and changes in ownership of our common stock with the SEC and the New York Stock Exchange (NYSE). We file these reports of ownership and changes in ownership on behalf of our officers and directors.
Peabody Energy Corporation | 2016 Form 10-K | 89 |
To the best of our knowledge, based solely on our review of the copies of such reports furnished to us during the fiscal year ended December 31, 2016, filings with the SEC and written representations from certain reporting persons that no additional reports were required, all required reports were timely filed for such fiscal year.
Code of Business Conduct and Ethics
Our Code of Business Conduct and Ethics can be found on our website (www.peabodyenergy.com) by clicking on “Investors” and then “Corporate Governance.” Information on our website is not considered part of this Form 10-K. The Code of Business Conduct and Ethics applies to all of our directors, officers and salaried employees.
Director Nomination Process and Proxy Access
As of the date of this Form 10-K, there have been no material changes to the procedures by which security holders may recommend nominees to our Board as described in the Company’s Definitive Proxy Statement filed with the SEC on March 24, 2015.
Effective December 10, 2015, the Company modified its Amended and Restated Bylaws to implement “proxy access,” a means for stockholders to include stockholder-nominated director candidates in the Company’s proxy materials for annual meetings of stockholders. The proxy access process will first be available to stockholders in connection with the Company’s next annual meeting of stockholders.
The Audit Committee
The Company has a standing Audit Committee consisting of Ms. Van Trease, Mr. Karn, Mr. Rusnack and Dr. Wilson. The Board of Directors has affirmatively determined that, in its judgment, all members of the Audit Committee are independent under NYSE and SEC rules. The Board also has determined that each of Messrs. Rusnack and Karn and Ms. Van Trease is an “audit committee financial expert” under SEC rules.
Item 11.Executive Compensation.
COMPENSATION DISCUSSION AND ANALYSIS
Overview
On the Petition Date, the Debtors filed voluntary petitions for reorganization with the Bankruptcy Court (the Chapter 11 Filing). The Bankruptcy Code places restrictions on certain compensation paid to our employees, including our Named Executive Officers for 2016. As a result, our 2016 Named Executive Officer compensation program was significantly impacted by the Chapter 11 Filing, as described below.
This Compensation Discussion and Analysis (the CD&A) describes the material elements of compensation paid to each of the following named executive officers (collectively, the NEOs or Named Executive Officers) for the year ended December 31, 2016:
Current Officers | Title as of December 31, 2016 | |
Glenn L. Kellow | President and Chief Executive Officer | |
Amy B. Schwetz | Executive Vice President and Chief Financial Officer | |
Charles F. Meintjes | President - Australia(1) | |
Kemal Williamson | President - Americas | |
A. Verona Dorch | Executive Vice President and Chief Legal Officer, Government Affairs and Corporate Secretary | |
(1) On March 15, 2017 we announced that Mr. Meintjes will assume the role of Executive Vice President - Corporate Services and Chief Commercial Officer effective following our emergence from our Chapter 11 Cases and George J. Schuller, the current Chief Operations Officer in Australia, will fill the role of President - Australia.
Peabody Energy Corporation | 2016 Form 10-K | 90 |
The Compensation Committee, together with the independent members of the Board with respect to the compensation of our CEO (the independent directors of the Board comprising the Special Committee), have responsibility for overseeing our executive compensation framework. The Compensation Committee and the Special Committee (collectively, the Committees) working with external advisors and senior management, seek to align pay with performance and create incentives that reward operational excellence, safety and financial management and that ultimately are designed to create stockholder value. The information presented in this CD&A includes compensation decisions made by the Compensation Committee and the Special Committee both prior to and after the Petition Date. As a result of the Chapter 11 Filing, we were unable to continue some of our compensation programs for our NEOs and were required to seek Bankruptcy Court approval to provide our NEOs compensation beyond their base salaries. Our Named Executive Officers, like our employees generally and our stockholders and other stakeholders, have been significantly impacted by the Chapter 11 Cases.
As described in more detail below, the Committees made certain executive compensation decisions prior to the Petition Date that were impacted by the Chapter 11 Cases. The details of the compensation program established prior to the Petition Date are summarized below under the heading “2016 Compensation Program Prior to our Chapter 11 Filing.”
Key Elements of 2016 Named Executive Officer Compensation Program
For 2016, the principal components of NEO compensation were:
• | Base salary; |
• | Annual cash incentive; |
• | Long-term incentives; and |
• | Retirement and other benefits provided on the same basis as those provided to employees |
With the exception of base salary, each of the principal components of our NEOs’ compensation for 2016 was significantly impacted by the Chapter 11 Cases.
As a result of our Chapter 11 Filing, target total direct compensation (TDC) for our NEOs significantly decreased from levels set by the Committees in early 2016. Even after adopting and approving the 2016 ELT-STIP (as defined below) and KEIP (as defined below), target total direct compensation decreased from prepetition levels for each individual NEO with our CEO’s TDC decreasing by approximately 39% and our NEOs’ TDC, on average, decreasing approximately 17%. Following modifications to the NEOs 2016 compensation as a result of the Chapter 11 Cases, approximately 74% of our CEO’s TDC and 68% of our NEOs’ TDC, on average, was performance based and not guaranteed.
At the time the Committees approved the 2016 ELT-STIP and KEIP, they believed that these programs would motivate our NEOs to meet and exceed certain operational goals critical for the Debtors’ Chapter 11 restructuring and key to enhancing the value of the enterprise.
Performance Basis for Our 2016 Named Executive Officer Compensation Program
Decisions regarding executive compensation made by the Compensation Committee and the Special Committee during 2016 reflect our industry context, operating environment and results, as well as the impact of the Chapter 11 Cases.
As a result of our Chapter 11 Filing, we were unable to continue the 2016 annual cash incentive program in accordance with the terms established by the Compensation Committee in early 2016 without Bankruptcy Court approval. After the Petition Date, the Compensation Committee approved modifications to the short-term cash incentive programs for 2016 (the 2016 ELT-STIP), which modifications were approved by the Bankruptcy Court in August 2016. Upon approval by the Bankruptcy Court, our NEOs became eligible to earn an annual cash incentive for 2016 under the 2016 ELT-STIP. The 2016 ELT-STIP was designed to utilize information already known about our 2016 performance to set a high bar for achievement on various financial metrics before our NEOs would receive payment, if any, to incentivize our NEOs to maximize current year profitability while incentivizing management to continue to improve upon our excellent safety record. Under the 2016 ELT-STIP, our NEOs became eligible to earn an annual cash incentive for 2016 contingent on meeting certain financial and safety metrics, as described below. For 2016, our NEOs earned annual cash incentive payouts under the 2016 ELT-STIP equal to 129.5% of target.
Peabody Energy Corporation | 2016 Form 10-K | 91 |
Additionally, we are unable to continue the long-term incentive programs for the NEOs that were in place prior to the Petition Date without Bankruptcy Court approval. In order to establish long-term incentives to motivate our NEOs during the pendency of the Chapter 11 Cases, in August 2016, the Compensation Committee approved a key employee incentive plan (the KEIP). The KEIP is a performance-based long-term cash incentive plan designed to incentivize our NEOs to drive value for stakeholders during the Chapter 11 Cases, with the expectation that this performance will maximize value available to creditors and other stakeholders under our Plan. The KEIP is comprised of one performance period running from the Petition Date through the Plan Effective Date. Awards, if any, earned under the KEIP will be determined based on the Debtors’ level of achievement across financial and environmental performance metrics, as described below. The performance period for the long-term cash incentive opportunities under the KEIP has not yet concluded, but is expected to conclude on the Plan Effective Date.
The following discussion provides detail regarding our executive compensation program and the 2016 compensation arrangements for each of our NEOs.
What We Pay and Why: Elements of Compensation
We utilized three elements of total direct compensation for 2016: base salary, annual cash incentive and long-term incentives. Following the Petition Date and upon approval by the Bankruptcy Court of the 2016 ELT-STIP and KEIP, 74% of reported TDC for our CEO, and 68% of reported TDC, on average, for our other NEOs was performance-based and not guaranteed. This mix of compensation places the vast majority of the NEOs' total direct compensation at-risk and in direct alignment with our stakeholders’ interests. The following focuses on our post-petition compensation program. The details of the compensation program established prior to the Petition Date are summarized below under the heading “2016 Compensation Program Prior to our Chapter 11 Filing.”
2016 Base Salaries
We pay base salaries to attract and retain talented executives and to provide a fixed base of cash compensation. The base salary of our CEO was recommended by the Compensation Committee and approved by the Special Committee after review of peer information compiled by the Compensation Committee’s independent compensation consultant, F.W. Cook & Co., Inc. (F.W. Cook). The 2016 base salaries for the other NEOs were individually recommended by our CEO, and were approved by the Compensation Committee. In each case, base salaries were set after consideration of:
• | The breadth, scope and complexity of the NEO's role; |
• | Comparability with the external and internal marketplace (roles of similar responsibilities, experience and organizational impact) based on, among other things, peer information compiled by F.W. Cook; |
• | Current compensation levels; and |
• | Individual performance. |
After a review of the base salaries of our NEOs, the Compensation Committee and the Special Committee determined to make a 1% cost of living increase to the base salaries of each of the NEOs on March 1, 2016. This increase was consistent with our decision to make a 1% cost of living increase to the salaries of all salaried employees. In March 2016, the Committees approved an additional 5.0% salary increase for Mr. Kellow and the Compensation Committee approved additional salary increases for Ms. Schwetz and Ms. Dorch of 6.9% and 3.5%, respectively, to bring their base salaries closer to the median for our Compensation Peer Group and in recognition of their 2015 individual performance. Subsequently, in July 2016, the Committees approved a 5.3% salary increase for Ms. Schwetz (to become effective on August 1, 2016) in recognition of her individual performance and substantially increased duties resulting from the Chapter 11 Cases. The base salaries for our NEOs as of March 1, 2016 were $1,007,475, $475,000, $555,510, $505,000, and $460,000 for Mr. Kellow, Ms. Schwetz, Mr. Meintjes, Mr. Williamson and Ms. Dorch, respectively. The base salary for Ms. Schwetz increased to $500,000 on August 1, 2016.
2016 Annual Cash Incentives
Following the Petition Date, the Compensation Committee, in consultation with its independent advisors, adopted modifications to the 2016 annual cash incentive program. These program changes were approved by the Bankruptcy Court in August 2016. The 2016 ELT-STIP is a modified version of the 2016 annual cash incentive program that remained in place for the majority of employees other than our executive officers. The performance targets for the 2016 ELT-STIP were established in July 2016. The level of performance required under the 2016 ELT-STIP incentivizes our NEOs to produce superior results for the Debtors’ estates, and requires them to achieve results above and beyond achievements occurring in the first half of 2016.
Peabody Energy Corporation | 2016 Form 10-K | 92 |
Under the 2016 ELT-STIP, the NEOs were assigned threshold, target and maximum incentive opportunities. The target incentive opportunities for the NEOs under the 2016 ELT-STIP were the same as under the 2016 annual cash incentive program as a percentage of base salary set by the Committees in early 2016. However, the maximum payout under the 2016 ELT-STIP was set at 150% of target (rather than 200% of target under the 2016 annual cash incentive program) as a result of negotiations with the various stakeholders in the Chapter 11 Cases, including the Creditors’ Committee and the U.S. Trustee for the Eastern District of Missouri. The target awards, expressed as a percentage of base salary, for each of the NEOs were as follows: Mr. Kellow, 110%; Ms. Schwetz, 80%; Mr. Meintjes, 80%; Mr. Williamson, 80%; and Ms. Dorch, 80%. The Committees established these opportunities through an analysis of compensation for comparable positions in companies of similar size and complexity and were intended to provide a competitive level of compensation when performance objectives are achieved. In general, the payout percentages were designed to result in 100% payout for target performance, 150% payout for maximum performance (versus 200% under the prepetition annual cash incentive program), 40% payout for threshold performance, and 0% payout for performance below threshold levels.
Following the end of 2016, the Committees reviewed and approved the achievement and payouts for the NEOs under the 2016 ELT-STIP. Payments earned in respect of 2016 performance were paid on March 3, 2017.
2016 Performance Measures under the 2016 ELT-STIP
There are two performance metrics under the 2016 ELT-STIP: (1) adjusted earnings before interest, taxes, depreciation, amortization and restructuring costs (which we refer to as 2016 ELT-STIP Adjusted EBITDAR), which comprises 75% of the target award opportunity; and (2) safety metrics, which comprise 25% of the target award opportunity and is equally divided into two components (each of which accounts for 12.5% of the target award opportunity), consisting of the reduction in Global Total Recordable Injury Frequency Rates (or TRIFR) and adherence to the Safety, A Way of Life Management System (or SAWOL MS).
Given the price volatility endemic to the energy market and the cyclical nature of the global energy market, the 2016 ELT-STIP has a “price collar” feature to mitigate 50% of price swings (positive and negative) versus the assumed prices utilized in setting the applicable metrics, with a maximum impact to 2016 ELT-STIP Adjusted EBITDAR of plus or minus $100 million. Additionally, to address currency exchange fluctuations (positive and negative) related to our Australian operations, the 2016 ELT-STIP has a “foreign currency exchange collar” feature to mitigate 75% of foreign currency exchange fluctuations (positive or negative) versus our assumed exchange rate utilized in setting the applicable metrics. These collars are designed to eliminate potential windfalls and penalties arising from uncontrollable factors that can significantly affect 2016 ELT-STIP Adjusted EBITDAR. This allows the NEOs to focus on operational performance and take the necessary actions to benefit the Debtors’ estates on an annual basis and in the longer term. If coal prices decline significantly or foreign currency exchange rates increase significantly, these collars would increase 2016 ELT-STIP Adjusted EBITDAR. Conversely, if coal prices rise significantly or foreign currency exchange rates decrease significantly, these collars have the effect of decreasing 2016 ELT-STIP Adjusted EBITDAR.
2016 ELT-STIP Adjusted EBITDAR is a financial measure that is not recognized in accordance with U.S. generally accepted accounting principles (or GAAP). A definition of 2016 ELT-STIP Adjusted EBITDAR is provided below.
The table below shows the performance metrics established under the 2016 ELT-STIP and our actual performance against those metrics.
Metric | % of Total Award | Threshold | Target | Maximum | Actual Results | Achievement | ||||||||||||
2016 ELT-STIP Adjusted EBITDAR ($ millions) | 75.0 | % | 379 | 511 | 724 | 671 | 137.6 | % | ||||||||||
TRIFR | 12.5 | % | 1.53 | 1.12 | 0.79 | 1.22 | 87.8 | % | ||||||||||
SAWOL MS | 12.5 | % | 90 | % | 95 | % | 100 | % | 97 | % | 123.0 | % | ||||||
Peabody Energy Corporation | 2016 Form 10-K | 93 |
The table below provides a definition for each of the performance measures used in the 2016 ELT-STIP and describes the purpose of these measures.
2016 ELT-STIP Adjusted EBITDAR | This metric is based on 2016 ELT-STIP Adjusted EBITDAR (as defined below) of our consolidated enterprise, after excluding 50% of the impact of realized pricing versus budget and 75% of the impact of Australian Dollar Foreign Exchange movements versus budget, both capped at $100 million. In 2016 these adjustments impacted 2016 ELT-STIP Adjusted EBITDAR by reducing it by $100 million related to the pricing collar offset by an increase of $85 million related to the foreign exchange collar. 2016 ELT-STIP Adjusted EBITDAR is a non-GAAP financial metric and is defined as Adjusted EBITDA (as defined in Item 6 of this Form 10-K) further adjusted to exclude the impact of certain employee compensation programs related to the Chapter 11 Cases, restructuring charges, the UMWA VEBA Settlement, and corporate hedging. 2016 ELT-STIP Adjusted EBITDAR and Adjusted EBITDA are not recognized terms under GAAP and are not, and do not purport to be an alternative to operating income or net income as determined in accordance with GAAP as a measure of profitability. Because these measures are not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. | Measures the impact of cost savings programs and operational earnings across the global platform. The price and foreign exchange collars address the impact of extraordinary price and foreign exchange volatility, both positive and negative. | ||
Global Total Recordable Injury Frequency Rate (TRIFR) | Global TRIFR is the number of injuries that result in medical treatment, restricted work or lost time, divided by the number of hours worked (includes employees, contractors and visitors), multiplied by 200,000 hours. The rate includes the injuries and hours associated with office workers, as well as travel-related injuries when employees are traveling for work purposes. | Safety is a value that is integrated into our business. For 2016, our quantitative safety target was set at a 10% improvement over 2015’s actual results. | ||
Safety, A Way of Life (SAWOL) Management System (MS) Conformance | SAWOL MS sets the expectations relating to safety and health for the organization. SAWOL MS aligns with CORESafetyTM (a National Mining Association framework) and is centered on three key areas of leadership and organization, risk management and assurance. Embedded in this framework is a requirement to audit conformance. | Safety is a value that is integrated into our business. For 2016, our qualitative safety target was set as “90% of global mine sites complete SAWOL MS audit” and “95% compliance with SAWOL elements and approved standards.” | ||
2016 Annual Cash Incentive Awards Earned Under 2016 ELT-STIP
Based on our performance in 2016, our NEOs earned annual cash incentive payouts of 129.5% of target under the 2016 ELT-STIP. In summary, we achieved results equal to 137.6% of our target goal with respect to the 2016 ELT-STIP Adjusted EBITDAR metric (weighted 75%), results equal to 87.8% of our target goal with respect to the TRIFR metric (weighted 12.5%) and results equal to 123.0% of our target goal with respect to the SAWOL MS metric (weighted 12.5%).
The following table shows the 2016 annual cash incentive awards earned by each NEO as a result of this performance.
Name | Target Opportunity as a % of Base Salary | 2016 Cash Incentive Award Earned as a % of Target | 2016 Cash Incentive Award Achieved ($) | ||||||
Glenn L. Kellow | 110 | % | 129.5 | % | 1,435,370 | ||||
Amy B. Schwetz | 80 | % | 129.5 | % | 518,080 | ||||
Charles F. Meintjes | 80 | % | 129.5 | % | 575,587 | ||||
Kemal Williamson | 80 | % | 129.5 | % | 523,261 | ||||
A. Verona Dorch | 80 | % | 129.5 | % | 476,634 | ||||
Peabody Energy Corporation | 2016 Form 10-K | 94 |
2016 Long-Term Incentives
As a result of our Chapter 11 Filing, we are no longer permitted to vest or settle equity awards granted prior to the Petition Date under our long-term incentive programs to our NEOs. In order to appropriately incentivize our NEOs during the pendency of the Chapter 11 Cases, the Compensation Committee approved the adoption of (and, in August 2016, the Bankruptcy Court approved) the Key Employee Incentive Plan, or the KEIP. The KEIP is a long-term, performance-based cash incentive program intended to incentivize our Named Executive Officers to drive value for stakeholders during the Chapter 11 Cases, with the expectation that strong performance against these objectives will maximize value for creditors and other stakeholders. The KEIP is comprised of one performance period running from the Petition Date through the Plan Effective Date.
Awards, if any, earned under the KEIP will be determined based on the cumulative level of achievement in each of the following four performance metric categories (each, as defined below): (1) Consolidated EBITDAR (Excluding Australia), which comprises 30% of the target award opportunity; (2) Australian EBITDAR, which comprises 10% of the target award opportunity; (3) Consolidated Cash Flow (before Restructuring Costs), which comprises 40% of the target award opportunity; and (4) Environmental Reclamation, which comprises 20% of the target award opportunity. If performance falls below the minimum threshold amount for a particular metric, the Named Executive Officer will not be eligible to receive any payout related to that metric. The threshold, target, and maximum values for the KEIP metrics fluctuate based upon the quarter in which the Plan Effective Date falls. In the event that the Plan Effective Date falls between the close of two quarters, the targets for each metric will be prorated based upon the Plan Effective Date.
Peabody Energy Corporation | 2016 Form 10-K | 95 |
The following table provides a definition for each of the performance measures used in 2016 and describes the purpose of the metric.
Consolidated Adjusted EBITDAR (excluding Australia) | Consolidated Adjusted EBITDAR (Excluding Australia) is a non-GAAP financial metric and is defined as Adjusted EBITDA (as defined in Item 6 of this Form 10-K) of our consolidated enterprise, except for our Australian subsidiaries, further adjusted to exclude the impact of certain employee compensation programs related to the Chapter 11 Cases, restructuring charges, the UMWA VEBA Settlement, and corporate hedging. Consolidated Adjusted EBITDAR and Adjusted EBITDA are not recognized terms under GAAP and are not, and do not purport to be an alternative to operating income or net income as determined in accordance with GAAP as a measure of profitability. Because these measures are not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. | Designed to incentivize the NEOs to maximize the value of the Debtors’ non-Australian assets. | ||
Australian Adjusted EBITDAR | Australian Adjusted EBITDAR is a non-GAAP financial metric and is defined as Adjusted EBITDA (as defined in Item 6 of this Form 10-K) of our Australian subsidiaries further adjusted to exclude the impact of certain employee compensation programs related to the Chapter 11 Cases, restructuring charges, the UMWA VEBA Settlement, and corporate hedging. Australian Adjusted EBITDAR and Adjusted EBITDA are not recognized terms under GAAP and are not, and do not purport to be an alternative to operating income or net income as determined in accordance with GAAP as a measure of profitability. Because these measures are not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. | Designed to incentivize the NEOs to focus on improving the profitability of the Debtors’ Australian affiliates. | ||
Consolidated Cash Flow (before Restructuring Costs) | Consolidated Cash Flow (before Restructuring Costs) is a non-GAAP financial metric and is defined as net change in cash and cash equivalents, as set forth in the Consolidated Statement of Cash Flows on page F-5 of this Form 10-K, before deducting cash used for reorganization costs, restructuring, certain employee compensation programs related to the Chapter 11 Cases, adequate protection payments, and any proceeds, repayments, fees, interest, or other charges related to the DIP Financing. Consolidated Cash Flow (before Restructuring Costs) is not a recognized term under GAAP and is not, and does not purport to be an alternative to operating income or net income as determined in accordance with GAAP as a measure of profitability. Because Consolidated Cash Flow (before Restructuring Costs) is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. | Designed to incentivize the NEOs to focus on and increase cash flow from projections set forth in the Business Plan prepared by the Debtors in August 2016. | ||
Environmental Reclamation | Environmental Reclamation is tied to land reclamation and is defined as the ratio of reclaimed or graded land to disturbed land. Reclaimed or graded land means returning the land to the final contour grading prior to soil replacement. The term disturbed land means new acres impacted for mining purposes. | Designed to incentivize the NEOs to achieve the financial metrics while honoring the Debtors’ commitment to reclaim mined land in an environmentally responsible manner and in accordance with existing laws. | ||
Peabody Energy Corporation | 2016 Form 10-K | 96 |
The table below sets forth the applicable cumulative performance targets:
Performance Metric | Q2 2016 | Q3 2016 | Q4 2016 | Q1 2017 | Q2 2017 | Q3 2017 | Q4 2017 | |||||||||||||||||||||||
Consolidated Adjusted EBITDAR (Excluding Australia) (in millions) | Threshold | $ | 138 | $ | 234 | $ | 325 | $ | 414 | $ | 504 | $ | 605 | $ | 700 | |||||||||||||||
Target | $ | 172 | $ | 292 | $ | 406 | $ | 517 | $ | 627 | $ | 755 | $ | 875 | ||||||||||||||||
Maximum | $ | 206 | $ | 350 | $ | 487 | $ | 620 | $ | 752 | $ | 907 | $ | 1,050 | ||||||||||||||||
Australia Adjusted EBITDAR (in millions) | Threshold | $ | (64 | ) | $ | (124 | ) | $ | (132 | ) | $ | (179 | ) | $ | (209 | ) | $ | (236 | ) | $ | (268 | ) | ||||||||
Target | $ | (24 | ) | $ | (73 | ) | $ | (20 | ) | $ | (47 | ) | $ | (38 | ) | $ | (18 | ) | $ | (10 | ) | |||||||||
Maximum | $ | 16 | $ | (22 | ) | $ | 92 | $ | 85 | $ | 133 | $ | 200 | $ | 248 | |||||||||||||||
Consolidated Cash Flow (Before Restructuring Costs) (in millions) | Threshold | $ | 314 | $ | 291 | $ | 262 | $ | 323 | $ | 373 | $ | 429 | $ | 490 | |||||||||||||||
Target | $ | 627 | $ | 581 | $ | 524 | $ | 646 | $ | 745 | $ | 857 | $ | 979 | ||||||||||||||||
Maximum | $ | 941 | $ | 872 | $ | 786 | $ | 969 | $ | 1,118 | $ | 1,286 | $ | 1,469 | ||||||||||||||||
Environmental Reclamation | Threshold | 1 to 1 (25% of target): Grading the same amount of land as that which is disturbed | ||||||||||||||||||||||||||||
Target | 1.1 to 1 (100% of target): Grading the same amount of land as that which is disturbed | |||||||||||||||||||||||||||||
Maximum | 1.3 to 1 (150% of target): Grading the same amount of land as that which is disturbed | |||||||||||||||||||||||||||||
Performance against the applicable goals will result in payouts, expressed as a percentage of target opportunity, weighted per the applicable category, as follows:
Metric | % of Total Award | Threshold | Target | Maximum | ||||||||
Consolidated Adjusted EBITDAR (Excluding Australia) | 30.0 | % | 33.0 | % | 100.0 | % | 150.0 | % | ||||
Australian Adjusted EBITDAR | 10.0 | % | 50.0 | % | 100.0 | % | 150.0 | % | ||||
Consolidated Cash Flow (Before Restructuring Costs) | 40.0 | % | 50.0 | % | 100.0 | % | 150.0 | % | ||||
Environmental Reclamation | 20.0 | % | 25.0 | % | 100.0 | % | 150.0 | % | ||||
The target incentive opportunity was established through an analysis of target total direct compensation in the Compensation Peer Group, as well as other relevant data, including analogous compensation programs utilized by companies in the coal industry and companies that undertook a financial restructuring under the Bankruptcy Code. The opportunities were intended to provide an appropriate level of compensation when performance objectives are achieved. The target awards for the Named Executive Officers, expressed as a percentage of base salary, are as follows: Mr. Kellow, 175%; Ms. Schwetz, 150%; Mr. Meintjes, 125%; Mr. Williamson, 125%; and Ms. Dorch, 125%. In the event performance falls below the minimum threshold amount for a particular metric, the NEOs would not be eligible for an incentive award related to that metric. Because the Plan Effective Date did not occur in 2016, the NEOs have not yet earned any amounts under the KEIP in 2016. The determination of any amounts earned under the KEIP will be made following the Plan Effective Date.
In order to receive an earned award under the KEIP, if any, the NEO must be employed with the Debtors up to and including the Plan Effective Date, unless the NEO is involuntarily terminated without cause, including due to death or disability, in which case the NEO will receive a prorated payment of any earned award based on our performance against the applicable performance metrics.
Peabody Energy Corporation | 2016 Form 10-K | 97 |
Additional Compensation Elements
Benefits
NEOs are eligible to participate in benefit plans generally available to the broader employee group.
Previously, our NEOs generally participated in our supplemental employee retirement account program, which is a nonqualified excess defined contribution retirement plan (Excess Retirement Plan). The Excess Retirement Plan is designed to allow a select group of highly compensated management employees to make contributions in excess of certain limits imposed by the Internal Revenue Code that apply to our tax-qualified 401(k) plan, and to receive matching contributions on such employee contributions. The Excess Retirement Plan was suspended effective December 31, 2015 and participants, including our NEOs, were no longer able to contribute to the plan and we did not make any contributions on behalf of the NEOs for 2016. Under the Plan confirmed by the Bankruptcy Court, the liabilities relating to our current employees under the Excess Retirement Plan will be spun off and transferred to a new nonqualified supplemental employee retirement account plan.
Perquisites
We provide perquisites that the Committees believe are necessary to enable the NEOs to perform their responsibilities safely and efficiently. We believe the benefit we receive from providing these perquisites significantly outweighs the cost of providing them. The table below summarizes and provides the business rationale for each of the perquisites provided to the NEOs for 2016.
Perquisite | Description and Business Rationale | |
Aircraft Usage | The Board does not require our executives to travel on our corporate aircraft for business or personal travel. Further, generally only business travel is allowed on our corporate aircraft. We do not provide tax gross-ups for imputed income due to personal aircraft use. | |
From time to time, spouses accompany our executives on business travel. Reimbursement is provided for taxes incurred only when a spouse travels for business purposes. | ||
Security | We provide personal security to NEOs when circumstances warrant. A car and driver are also provided only when necessary for security reasons. | |
Other | We may provide tax gross ups to NEOs related to expatriate assignments to keep them tax neutral. We also provide relocation and temporary housing as discussed in the All Other Compensation table. | |
How We Make Compensation Decisions
Risk Considerations
The Compensation Committee periodically reviews our compensation programs for features that might encourage inappropriate risk-taking. The programs are designed with features that mitigate risk without diminishing the incentive nature of the compensation. We believe our compensation programs encourage and reward prudent business judgment without encouraging undue risk.
We conducted, and the Compensation Committee reviewed, a comprehensive global risk assessment. The risk assessment included a global inventory of incentive plans and programs and considered factors such as the plan metrics, number of participants, maximum payments and risk mitigation factors. Based on the review, we believe our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on the Company.
Responsibilities for Executive Compensation
Compensation decisions for the CEO role are determined by the Special Committee. Compensation decisions for the other NEOs are determined by the Compensation Committee and the CEO. The role of the CEO is to review the performance of the other NEOs and make recommendations on base salary, annual incentive and long-term incentives for the other NEOs. F.W. Cook and Mercer, independent consultants engaged by the Compensation Committee, and the compensation group in our Human Resources Department support the Committees’ efforts.
Peabody Energy Corporation | 2016 Form 10-K | 98 |
Compensation Peer Group
Talent for senior-level management positions and key roles in the organization can be acquired across a broad spectrum of companies. As such, we rely on compensation data for a group of publicly-held companies of similar size and/or complexity as us based on revenue, market capitalization and assets (the “Compensation Peer Group”):
• | As an input in developing base salary ranges, annual incentive targets and long-term equity award ranges; |
• | To evaluate share utilization by reviewing overhang levels and annual run rate; |
• | To evaluate the form and mix of equity awarded to NEOs; |
• | To evaluate share ownership guidelines; |
• | To assess the competitiveness of total direct compensation awarded to NEOs; |
• | To validate whether our executive compensation program is aligned with our performance; and |
• | As an input in designing compensation plans, benefits and perquisite programs. |
While the Compensation Committee examines executive compensation data for the Compensation Peer Group, compensation paid at those companies is not the sole factor in their decision-making process.
Each year, the Compensation Committee also commissions a compensation analysis conducted by its independent compensation consultant to determine whether our executive compensation program is appropriate compared to the Compensation Peer Group and revises it as circumstances warrant. As a result of our independent compensation consultant’s review, no changes were made to our Compensation Peer Group for 2016.
During the Chapter 11 Cases and in relation to the modifications to the 2016 compensation programs, the Committees worked with Mercer (US) Inc. to evaluate other relevant data including compensation programs utilized by companies in the coal industry and companies that undertook a financial restructuring under the Bankruptcy Code.
Peabody Energy Corporation | 2016 Form 10-K | 99 |
The Compensation Peer Group for 2016 consists of the 19 companies listed in the following chart, which sets forth the relative size measures considered by the Compensation Committee. Rows marked “N/A” below reflect the fact that the data was not publicly available at the time of this filing.
Company | Revenue (1) | Total Assets (2) | ||||
(Dollars in millions) | ||||||
Air Products & Chemicals, Inc. | 9,524 | 18,055 | ||||
AK Steel Corporation | 5,883 | 4,036 | ||||
Allegheny Technologies, Inc. | 3,135 | 5,170 | ||||
Alpha Natural Resources, Inc. | N/A | N/A | ||||
Arch Coal, Inc. | 1,927 | 2,137 | ||||
Barrick Gold Corporation | 8,558 | 25,264 | ||||
Cliffs Natural Resources, Inc. | 2,109 | 1,924 | ||||
CONSOL Energy, Inc. | 1,971 | 9,184 | ||||
Domtar Corporation | 5,098 | 5,680 | ||||
Eastman Chemical Company | 9,008 | 15,457 | ||||
Ecolab, Inc. | 13,153 | 18,330 | ||||
Freeport-McMoRan Copper & Gold Inc. | 14,830 | 37,317 | ||||
Joy Global, Inc. | 2,371 | 3,426 | ||||
Kinross Gold Corporation | 3,472 | 7,979 | ||||
Newmont Mining Corporation | 6,711 | 21,031 | ||||
Praxair, Inc. | 10,534 | 19,332 | ||||
Rockwell Automation, Inc. | 5,880 | 7,101 | ||||
SPX Corporation | 1,472 | 1,913 | ||||
Teck Resources, Inc. | 6,924 | 26,525 | ||||
75th Percentile | 8,896 | 19,082 | ||||
Median | 5,881 | 8,582 | ||||
25th Percentile | 2,562 | 4,320 | ||||
Peabody Energy Corporation | 4,715 | 11,778 | ||||
Peabody Energy Corporation Percentile Rank | 40 | % | 55 | % | ||
Data Source: S&P's Capital IQ; includes adjustments that may differ from US GAAP reporting made by Capital IQ to all companies
(1) Reflected as of the most recently reported four quarters at December 31, 2016.
(2) Reflected as of the most recently reported quarter at December 31, 2016.
Share Ownership Requirements
We have share ownership requirements for our executives, including the NEOs, which are designed to align their long-term financial interests with those of our stockholders.
The NEO share ownership requirements are as follows:
Role | Value of Common Stock to be Owned | |
CEO | 5 times base salary | |
Other NEOs | 3 times base salary | |
Peabody Energy Corporation | 2016 Form 10-K | 100 |
If at any time an NEO does not meet his ownership requirement, he or she must retain (1) any of our common stock owned by him or her (whether owned directly or indirectly) and (2) any net shares received as the result of the exercise, vesting or payment of any equity award until the ownership requirement is met, in each case unless otherwise approved by the Compensation Committee. For this purpose, “net shares” means the shares of stock that remain after shares are sold or withheld to (1) pay the exercise price for a stock option award or (2) satisfy any tax obligations, including withholding taxes, arising in connection with the exercise, vesting or payment of an equity award.
Compliance with these requirements is evaluated as of December 31 of each year. The value of an individual’s share ownership as of such date is determined by multiplying the number of shares of our stock or other eligible equity interests held by the individual by the closing price of our stock as of the business day immediately preceding the date of determination.
For purposes of determining executive stock ownership levels, only the following forms of our equity interests are included:
• | Stock owned directly (including stock or stock units held in any defined contribution plan or employee stock purchase plan); |
• | Stock held by immediate family members residing in the same household or through trusts for the benefit of the person or his or her immediate family members residing in the same household; and |
• | Unvested restricted stock or RSUs (provided that vesting is based solely on the passage of time and/or continued service with Peabody). |
Due to the continued decline in the market price per share of our stock, in addition to the short tenure of some of our NEOs, ownership requirements were not met by our NEOs as of December 31, 2016. All of our NEOs complied with the requirements that apply when their required stock ownership level is not met.
Prohibition on Hedging or Pledging of Company Stock
Our Insider Trading Policy prohibits our directors and all of our employees, including our officers, from entering into hedging transactions involving our stock, and from holding our stock in a margin account as collateral for a margin loan or otherwise pledging our stock as collateral for a loan.
Clawback Provisions
If we are required to prepare an accounting restatement due to fraudulent and/or intentional material misrepresentation, the Board may take action to recoup incentive awards and equity gains on awards granted to NEOs to the extent such awards exceeded the payment that would have been made based on the restated financial results. This right to recoup expires unless such determination is made by the Board within three years following the payment of the award. When final regulations for clawbacks are promulgated by the SEC and NYSE under the Dodd-Frank Wall Street Reform and Consumer Protection Act, we expect to modify our clawback policies and provisions accordingly to ensure compliance with such new regulations.
Employment Agreements and the 2015 Amended and Restated Executive Severance Plan
During 2015, all NEOs either transitioned from employment agreements or became participants in the 2015 Amended and Restated Executive Severance Plan (the Severance Plan), with the exception of our President and CEO, whose employment agreement expired in September 2016. The Severance Plan is intended to provide transitional assistance to certain senior executives whose employment is terminated for reasons other than cause, death or disability, or by the senior executive for good reason. The Severance Plan provides cash severance based upon a tiered severance multiple of annual base salary and average annual cash incentive paid over the preceding three years ranging from a 1.5x multiple for certain executives to a 2x multiple for NEOs (or a 2.5x multiple for the CEO if termination occurs within two years following a Change in Control as defined in the Severance Plan), as well as continuation of healthcare benefits. Terms used in the following table are defined in Mr. Kellow’s employment agreement and the Severance Plan, as applicable.
The Bankruptcy Code places limitations on payments made to insiders of a company for, among other things, severance payments. Accordingly, the severance payments described below will be subject to such limitations during the Chapter 11 Cases.
Peabody Energy Corporation | 2016 Form 10-K | 101 |
The following table highlights employment agreement provisions for Mr. Kellow, which applied through the expiration of his employment agreement on September 16, 2016, and Severance Plan provisions:
Employment Agreement Provisions | Severance Plan Provisions | |||
Position | President and CEO through September 2016 | NEOS other than the President and CEO | ||
Most recent employment agreement commencement date | September 16, 2013 | Not applicable | ||
Term of contract | Three-year employment agreement | ▪ Plan may be modified, amended or terminated at any time by the Board without notice to plan participants with certain exceptions▪ For a period of two years following a Change in Control, the Severance Plan may not be discontinued, terminated or amended in such a manner that decreases the Severance Payment payable to any Participant or that makes any provision less favorable for any Participant without the consent of the Participant▪ Plan may not be modified, amended or terminated in a manner adverse to Participants as of the date of the modification, amendment or termination without one year’s advance written notice of such modification, amendment or termination▪ Either Peabody or the executive may terminate employment at any time for any reason (other than for cause) by delivery of notice 90 days in advance of the termination date | ||
Severance Benefits | ▪ Upon termination other than for cause or upon resignation for good reason, severance is equal to a 2x multiple times (or in the event termination occurs within two years after a Change in Control, the severance multiplier changes to 2.5x):◦ Base salary◦ Average annual cash incentive award paid for the three years preceding the year of termination◦ 6% of base salary (to compensate for company contributions he or she otherwise would have earned under our 401(k) plan)▪ Upon termination other than for cause or resignation for good reason, executive is also entitled to medical and other benefits for 18 months▪ 1/4 of severance benefit total paid in lump sum on the earlier of executive’s death or first day after six-month anniversary of termination (or, in the event termination occurs within two years after a Change in Control, 1/5 of such severance benefit)▪ Remaining 3/4 of severance benefits paid in 18 equal monthly payments beginning on the first day of the month next following the initial lump sum payment (or, in the event termination occurs within two years after a Change in Control, 4/5 of such severance benefit)▪ We are not obligated to provide any benefits under tax qualified plans that are not permitted by plan terms or applicable laws | ▪ Upon termination other than for cause or upon resignation for good reason, severance is equal to a 2x multiple times (or in the event termination occurs within two years after a Change in Control for the CEO, the severance multiplier changes to 2.5x):◦ Base salary◦ Average annual cash incentive award paid for the three years preceding the year of termination◦ 6% of base salary (to compensate for company contributions he or she otherwise would have earned under our 401(k) plan)▪ Upon termination other than for cause or upon resignation for good reason, executive is also entitled to medical and other benefits for 18 months▪ We are not obligated to provide any benefits under tax qualified plans that are not permitted by plan terms or applicable laws | ||
Peabody Energy Corporation | 2016 Form 10-K | 102 |
Employment Agreement Provisions | Severance Plan Provisions | |||
Restrictive Covenants (post-termination) | ▪ Confidentiality (perpetual)▪ Non-compete (1 year)▪ Non-solicitation (1 year)▪ Breach will result in forfeiture of any unpaid amounts or benefits; executive will repay any portion of the severance payment previously paid to him or her | ▪ Confidentiality (perpetual)▪ Non-compete (1 year)▪ Non-solicitation (1 year)▪ Breach will result in forfeiture of any unpaid amounts or benefits; executive will repay any portion of the severance payment previously paid to him or her | ||
Tax Gross-Ups | Mr. Kellow is not entitled to any tax gross-up payment if excise tax is incurred. | None | ||
Deductibility of Compensation Expenses
Under Section 162(m) of the Internal Revenue Code, compensation paid to certain NEOs in excess of $1 million is not tax deductible, except to the extent it constitutes “performance-based compensation” for purposes of Section 162(m) of the Internal Revenue Code. The Committees generally consider the impact of Section 162(m) of the Internal Revenue Code when establishing incentive compensation plans. As a result, a significant portion of our executive compensation may be designed so that it may be able to qualify as “performance-based compensation” under Section 162(m) of the Internal Revenue Code depending upon facts and circumstances. At the same time, the Committees consider as their primary goal the design of compensation strategies that further our best interests and the best interests of our stockholders. In certain cases, for example, the Committees may determine that the amount of tax deductions lost is not significant when compared to the potential opportunity an executive compensation program provides for creating stockholder value. The Committees therefore retain the ability to evaluate our NEOs’ performance and to pay appropriate compensation, even if some of it may be non-deductible. Moreover, even if the Committees intend to grant compensation that qualifies as “performance-based compensation” for purposes of Section 162(m), the Committees cannot guarantee that such compensation will so qualify or ultimately will be deductible.
2015 Say-on-Pay Results
At our 2015 Annual Meeting of Stockholders (the last time we conducted an advisory vote to approve the compensation of its NEOs (which we refer to as Say-on-Pay)), 58.9% of the votes cast on the Say-on-Pay proposal were voted in favor of our NEOs’ compensation. The Compensation Committee considered the result of this 2015 Say-on-Pay vote at its meetings in 2015 following the 2015 Annual Meeting of Stockholders. While this voting result reflected majority support for our then-existing NEO compensation program, this result was less than desired. We thereafter contacted our 50 largest institutional stockholders as of April 2015. Ten stockholders (owning approximately 23% of our outstanding stock measured as of April 2015) agreed to have at least one telephonic meeting with us. The valuable feedback indicated that:
• | Stockholders wanted greater transparency around program structure and the linkage between pay and performance; |
• | Stockholders requested more information about the drivers behind compensation decisions, and requested expanded explanation on selected incentive metrics; |
• | Stockholders provided feedback regarding our CEO succession process and other aspects of our corporate governance, specifically the separation of the Chairman and CEO roles; and |
• | Stockholders suggested that we review our Compensation Peer Group. |
As a result of these discussions, in early 2016 we addressed stockholder comments for each topic in our compensation program design and throughout the CD&A included in Amendment No. 1 on Form 10-K/A to our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 which was filed with the SEC on April 29, 2016 (last year’s compensation disclosure). We also reviewed our Compensation Peer Group and made changes as described in last year’s compensation disclosure.
As a result of our Chapter 11 Filing, however, the results of the 2015 Say-on-Pay vote did not have a material impact on the key compensation programs that were in place for our NEOs for 2016 as the compensation programs put in place after our Chapter 11 Filing were negotiated with the various stakeholders in the Chapter 11 Cases, including the Creditors’ Committee and the U.S. Trustee for the Eastern District of Missouri, and were approved by the Bankruptcy Court.
Peabody Energy Corporation | 2016 Form 10-K | 103 |
2016 Compensation Program Prior to our Chapter 11 Filing
Our compensation philosophy and programs designed in early 2016 were based on the following core principles: competitive compensation opportunities and stockholder alignment through stock ownership and pay for performance. The Committees adopted the mix as a short term solution due to the distressed nature of the industry and coal stocks.
As determined by the Committees, the mix of target total direct compensation (TDC) (defined as base salary, annual cash incentive awards at target and long-term incentive awards at target) for our CEO and our NEOs, at the time their 2016 long-term incentive awards were granted in January 2016, resulted in 41% of our CEO’s TDC and 40% of our other NEOs’ TDC, on average, being performance based and not guaranteed. When the Committees determined this overall mix of target total direct compensation, they believed it:
▪ | Limits share utilization and reduces burn rate under our 2015 LTIP; |
▪ | Focuses on share conservation; and |
▪ | Adds a retentive element to our compensation program. |
In early 2016, the Compensation Committee, in conjunction with our independent advisors, reviewed our executive compensation program to determine whether it appropriately aligns pay and performance and links officer activities and performance with stockholder interests. The analysis indicated that our 2016 executive compensation program did align with our compensation philosophy and performance and the program appropriately links pay and performance.
For 2016, prior to the Petition Date, the performance-based portion of NEO compensation consisted of an annual cash incentive opportunity and performance-based restricted stock units (PRSUs) awarded under the Peabody Energy Corporation 2015 Long-Term Incentive Plan (2015 LTIP). Annual cash incentive plan payouts were contingent on meeting certain goals for Pre-Petition Price-collar Adjusted EBITDA, Safety and individual objectives, all as further described below. The PRSUs were designed to vest one-third per year subject to achievement of the performance metric in each year. For 2016, the performance metric for the PRSUs related to compliance with our Credit Agreement (as defined below).
After the Petition Date, we are not authorized to continue our long-term incentive programs for our NEOs without Bankruptcy Court approval. As a result, no payouts were provided to NEOs under our outstanding long-term incentive awards. As noted above, under the Plan, all of our equity securities will be canceled, including our common stock and any outstanding equity awards in respect to such equity securities.
2016 Annual Cash Incentive Program Prior to our Chapter 11 Filing
Prior to the Petition Date, our 2016 annual cash incentive program was designed to provide our NEOs the opportunity to earn annual cash incentive payments tied to the successful achievement of specified performance goals. For 2016, our 2016 annual incentive program for our NEOs involved a maximum performance metric based on achievement of positive Pre-Petition Adjusted EBITDA (as defined below) and was designed to qualify the annual cash incentive program as performance-based compensation under Section 162(m) of the Internal Revenue Code of 1986, as amended. Achievement of this performance metric established a maximum of 200% of the NEO’s target incentive that could be paid to each NEO for 2016. The Compensation Committee, using negative discretion, could then pay an annual incentive amount less than such maximum limitation to each such NEO guided by its review and consideration of our achievement of various underlying performance metrics. For 2016, the underlying performance metrics were Pre-Petition Price-collar Adjusted EBITDA, Safety metrics, and individual objectives established for each NEO that supported our business strategy for 2016.
Under the annual cash incentive plan, the NEOs were assigned threshold, target and maximum incentive opportunities. The target incentive opportunity was established through an analysis of compensation for comparable positions in companies of similar size and complexity and was intended to provide a competitive level of compensation when performance objectives are achieved. Maximum incentive payments could be awarded when target performance objectives were significantly exceeded. At threshold performance, the incentive that could be earned generally was equal to 50% of the target incentive and, at maximum performance, the incentive that could be earned was up to 200% of the target incentive. No incentive would be earned if actual performance did not meet the threshold level of performance. The target awards, expressed as a percentage of base salary, for each of the NEOs were as follows: Mr. Kellow, 110%; Ms. Schwetz, 80%; Mr. Meintjes, 80%; Mr. Williamson, 80%; and Ms. Dorch, 80%. No increases were made to target annual cash incentive award levels between 2015 and 2016.
In order to motivate our employees in a distressed environment and promote their retention, the Compensation Committee determined that the 2016 annual cash incentive award would be paid in two installments, with the first installment based on 2016 mid-year results and paid after the first six months of the year and the second installment based on 2016 full-year results and paid after the end of the year.
Peabody Energy Corporation | 2016 Form 10-K | 104 |
2016 Performance Measures under the Annual Cash Incentive Plan Prior to our Chapter 11 Filing
Based on input from management and information and advice from F.W. Cook, the Committees established performance metrics and weightings for determining the NEOs’ 2016 annual cash incentive payouts. For 2016, in line with our overall goal of focusing on line-of-sight metrics, we utilized metrics tied to measurable financial and safety goals over which the NEOs had direct control. We simplified the metrics from those used in 2015 to include Pre-Petition Price-collar Adjusted EBITDA, weighted at 50%, Safety, weighted at 25% (which in turn, was comprised of TRIFR, weighted at 12.5% and SAWOL MS Conformance, weighted at 12.5%), and individual objectives, weighted at 25%.
Given the price volatility endemic to the coal sector and the cyclical nature of the global coal markets, we retained a “price collar” feature to eliminate potential windfalls and penalties arising from uncontrollable factors that can significantly impact Pre-Petition Adjusted EBITDA, but with a maximum range at plus or minus $100 million, to limit the upside and downside related to significant price changes. We believe the “price collar” allowed our NEOs to focus on operational performance and take the necessary actions to benefit us and our stockholders on an annual basis and in the longer term. In years when coal prices decline significantly, the price collar has the effect of increasing Pre-Petition Adjusted EBITDA as used for the annual cash incentive compensation plan. Conversely, in years when coal prices might rise significantly, the price collar would have the effect of decreasing Pre-Petition Adjusted EBITDA as used for the annual cash incentive compensation plan.
Pre-Petition Adjusted EBITDA is a financial measure that is not recognized in accordance with GAAP. A definition of Pre-Petition Adjusted EBITDA is provided in the table below.
The following table shows the performance metrics originally established for 2016. However, as a result of our Chapter 11 Filing and the subsequent modifications to our annual cash incentive program, the Committee did not evaluate actual performance against the performance metrics originally established for 2016.
Metric | % of Total Award | Threshold | Target | Maximum | ||||||||
Pre-Petition Price-collar Adjusted EBITDA ($ millions) | 50.0 | % | 249 | 311 | 373 | |||||||
TRIFR | 12.5 | % | 1.53 | 1.12 | 0.79 | |||||||
SAWOL MS | 12.5 | % | 90 | % | 95 | % | 100 | % | ||||
Individual Goals | 25.0 | % | N/A | N/A | N/A | |||||||
Peabody Energy Corporation | 2016 Form 10-K | 105 |
The following table provides a definition for the performance measures originally established under the annual cash incentive program for 2016 and describes how we use these measures.
Pre-Petition Price-collar Adjusted EBITDA | This metric is based on Pre-Petition Adjusted EBITDA for the 2016 annual cash incentive (as defined below), after excluding 50% of the impact of realized pricing versus budget, with a maximum collar limit of $100 million for actual relative to target level performance. Pre-Petition Adjusted EBITDA for the 2016 annual cash incentive is equal to income or loss from continuing operations before deducting net interest expense (including gains and losses on early debt extinguishment or modification); income taxes; asset retirement obligation expenses; 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. | Management uses this metric to measure our performance, the impact of cost savings programs and operational earnings across the global platform. The price collar addresses the impact of extraordinary price volatility, both positive and negative. | ||
Global Total Recordable Injury Frequency Rate (TRIFR) | Global TRIFR is the number of injuries that result in medical treatment, restricted work or lost time, divided by the number of hours worked (includes employees, contractors and visitors), multiplied by 200,000 hours. The rate includes the injuries and hours associated with office workers, as well as travel-related injuries when employees are travelling for work purposes. | Safety is a value that is integrated into our business. For 2016, our quantitative safety target was set at a 10% improvement over 2015’s actual results. | ||
Safety, A Way of Life (SAWOL) Management System (MS) Conformance | SAWOL MS sets the expectations relating to safety and health for the organization. SAWOL MS aligns with CORESafety™ (a National Mining Association framework) and is centered on three key areas of leadership and organization, risk management and assurance. Embedded in this framework is a requirement to audit conformance. | Safety is a value that is integrated into our business. For 2016, our qualitative safety target was set as “no major non-conformances at year-end.” | ||
Individual Performance
In determining the amount of each NEO’s actual annual cash incentive award within the range determined by the payout formula, the annual incentive program for 2016 was designed so that the Committees would consider quantitative and qualitative factors relating to the individual accomplishments of the NEOs over the course of the calendar year. As a result of our Chapter 11 Filing and the modification to the annual cash incentive program for 2016, the Committee did not evaluate the individual performance of the NEOs for purposes of determining payouts under the annual cash incentive program.
2016 Long-Term Incentives Prior to our Chapter 11 Filing
In late 2015, the Compensation Committee adopted changes to our approach to delivering long-term equity compensation for NEOs in 2016. To limit share utilization and reduce the burn rate under our 2015 LTIP, we rebalanced our award vehicles mix by eliminating stock options and relative total stockholder return (TSR) performance units. We also focused on share conservation by awarding 50% of long-term incentive awards in the form of PRSUs with a maximum potential payout of 100% versus a 200% historic maximum potential payout, and 50% in the form of service based cash awards (Cash Awards). Additionally, we determined the number of PRSUs to grant by dividing the target dollar award for the relevant NEO by an assumed share price of $15 while the actual fair value of the award was based on the closing price per share of our common stock on the grant date, or $7.75 per share.
In approving the 2016 long-term incentive awards, the Committees considered the advice of F.W. Cook, as well as available comparative compensation data. The PRSUs were structured to provide competitive long-term equity incentive opportunities, with any amounts earned based on performance metrics relating to compliance with our Amended and Restated Credit Agreement, dated as of September 24, 2013, as amended from time to time (the Credit Agreement), in order to maintain access to the $1.65 billion revolving credit facility constituted under the Credit Agreement. The Cash Awards were designed to add a retentive element and limit share utilization.
Peabody Energy Corporation | 2016 Form 10-K | 106 |
For 2016, the target value of these awards was based on a mix of PRSUs and Cash Awards. The target opportunity for our CEO was set at $4.2 million and for each of the other NEOs at 200% of their base salary, with the maximum award set at 175% of target. The target incentive opportunity was established through an analysis of compensation for comparable positions in companies of similar size and complexity and was intended to provide a competitive level of compensation when performance objectives are achieved.
PRSUs
The PRSUs were designed to create a direct link between executive compensation and our ability to continue to access our revolving credit facility under the Credit Agreement. Our Board and the Compensation Committee granted PRSUs to each of the NEOs on January 4, 2016. As described above, in determining the number of units granted to each NEO, we modified the approach for granting PRSUs to conserve shares under our 2015 LTIP. The approach approved by the Board and the Compensation Committee utilized an assumed price per share of our common stock of $15 (in other words, to determine the number of target PSUs to grant to each NEO, we divided the applicable PRSU target award value by $15, rather than the significantly lower fair value of our common stock on the date of grant). The fair value of the award was based on the closing price per share of our stock as of January 4, 2016, or $7.75, resulting in a significantly lower grant value and further share conservation. Using this methodology, Mr. Kellow, Ms. Schwetz, Mr. Meintjes, Mr. Williamson and Ms. Dorch received awards of PRSUs of 140,000 units, 29,333 units, 36,677 units, 33,333 units and 29,333 units, respectively.
The PRSUs were designed to vest one-third per year and shares were to be delivered in settlement of earned awards after the end of the three-year performance period, subject to achievement of the performance metric in each year. The performance metric for the PRSUs related to compliance with the Credit Agreement in order to maintain access to the $1.65 billion revolving credit facility constituted under the Credit Agreement. The maximum payout for the PRSUs was capped at 100%, versus a 200% historic maximum. In order to receive the PRSUs, each NEO was required to execute a restrictive covenant agreement which contains customary confidentiality, non-competition and non-solicitation provisions.
As discussed above, during the course of the Chapter 11 Cases, we are prohibited from paying long-term incentive awards granted to the Named Executive Officers under our long-term equity incentive programs granted prior to the Petition Date. In addition, under the Plan confirmed by the Bankruptcy Court, all of our equity securities will be canceled, including our common stock and any outstanding equity awards in respect of such equity securities, such as the PRSUs, on the Plan Effective Date.
Cash Awards
The Cash Awards granted to our Named Executive Officers were intended to add a retentive element to our long-term incentive program, as well as to limit share utilization. The Board of Directors and Compensation Committee, in consultation with F.W. Cook, approved the grant of Cash Awards to Mr. Kellow, Ms. Schwetz, Mr. Meintjes, Mr. Williamson and Ms. Dorch in the amount of $2,100,000, $440,000, $550,000, $500,000 and $440,000, respectively. These amounts were approximately 50% of the target long-term incentive opportunity for each NEO. In order to receive the Cash Awards, each NEO was required to execute a restrictive covenant agreement which contains customary confidentiality, non-competition and non-solicitation provisions.
The Cash Awards were designed to vest in three substantially equal installments over three years and to be paid annually after each of the three anniversaries of the grant date. However, during the course of the Chapter 11 Cases, we are prohibited by the Bankruptcy Code from paying retention awards, such as the Cash Awards, to the Named Executive Officers absent the satisfaction of certain requirements under the Code and the approval of the Bankruptcy Court.
2014 and 2015 Performance Unit Awards
As discussed above, after the Petition Date, we are not authorized to continue our long-term incentive programs for our NEOs without Bankruptcy Court approval. As a result, we did not conduct a specific assessment of performance against the pre-established performance goals of relative TSR and Return on Mining Assets (ROMA) goals for the 2014 and 2015 performance unit programs covering the 2014-2016 and 2015-2017 performance periods, respectively. We did not provide any payouts to our NEOs in respect of the 2014 and 2015 performance unit programs.
Peabody Energy Corporation | 2016 Form 10-K | 107 |
Other Equity Awards
We are unable to continue our prepetition long-term incentive programs for the NEOs without Bankruptcy Court approval as a result of our Chapter 11 Filing. During the Chapter 11 Cases, we are prohibited from vesting or settling outstanding equity awards previously granted to the Named Executive Officers under those programs absent Bankruptcy Court approval. In July 2016, to comply with applicable bankruptcy law, we informed the Named Executive Officers that we would not vest or settle any of their outstanding equity awards, and that outstanding restricted stock awards that were due to vest before October 31, 2017 would be canceled. As a result, an aggregate of 1,994 restricted stock awards held by the NEOs were canceled on August 11, 2016. Under the terms of the Plan, all of our existing equity awards, plus our equity securities, will be canceled on the Plan Effective Date. Accordingly, our Named Executive Officers are not expected to receive any value from their equity awards that were outstanding during 2016 or other Peabody equity holdings, despite the values reflected in the CD&A and the related tabular or footnote disclosures below.
Peabody Energy Corporation | 2016 Form 10-K | 108 |
EXECUTIVE COMPENSATION
2016 Summary Compensation Table
The following table summarizes the compensation of our Named Executive Officers for their performance during the years ended December 31, 2016, 2015 and 2014, as applicable.
Name and Principal Position | Year | Salary ($) | Bonus ($) | Stock Awards ($) (1) | Option Awards ($) (1) | Non-Equity Incentive Plan Compensation ($) (2) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (3) | All Other Compensation ($) (4) | Total ($) | |||||||||||||||||
Glenn L. Kellow (5) President and Chief Executive Officer | 2016 | 997,896 | — | 1,085,000 | — | 1,435,370 | — | 17,610 | 3,535,876 | |||||||||||||||||
2015 | 874,167 | (6) | — | 2,573,358 | 749,747 | 519,730 | (7) | — | 94,220 | 4,811,222 | ||||||||||||||||
2014 | 800,000 | — | 1,771,919 | 1,499,933 | 955,365 | — | 552,299 | 5,579,516 | ||||||||||||||||||
Amy B. Schwetz Executive Vice President and Chief Financial Officer | 2016 | 479,583 | — | 227,331 | — | 518,080 | — | 34,887 | 1,259,881 | |||||||||||||||||
2015 | 341,837 | (8) | — | 180,071 | — | 174,108 | (7) | — | 188,912 | 884,928 | ||||||||||||||||
Charles F. Meintjes President - Australia (9) | 2016 | 554,583 | — | 284,169 | — | 575,587 | — | 72,869 | 1,487,208 | |||||||||||||||||
2015 | 550,000 | — | 1,218,471 | — | 243,638 | (7) | — | 188,912 | 2,201,021 | |||||||||||||||||
2014 | 550,000 | 1,497,585 | — | 537,368 | — | 352,644 | 2,937,597 | |||||||||||||||||||
Kemal Williamson President - Americas | 2016 | 504,167 | — | 258,331 | — | 523,261 | 980 | 50,938 | 1,337,677 | |||||||||||||||||
2015 | 500,000 | — | 857,800 | 249,916 | 205,489 | (7) | — | 51,960 | 1,865,165 | |||||||||||||||||
2014 | 500,000 | 738,299 | 624,970 | 462,683 | 1,434 | 76,438 | 2,403,824 | |||||||||||||||||||
A. Verona Dorch Executive Vice President and Chief Legal Officer, Government Affairs and Corporate Securities | 2016 | 456,667 | — | 227,331 | — | 476,634 | — | 136,063 | 1,296,695 | |||||||||||||||||
(1) | Amounts in the Stock Awards and Option Awards columns reported for 2016 represent the aggregate grant date fair value computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, Compensation - Stock Compensation (“FASB ASC Topic 718”). A discussion of the relevant fair value assumptions is set forth in Note 20 to our consolidated financial statements included in this Form 10-K. For 2016 PRSU award opportunities included in the Stock Awards column, the maximum potential payout was equal to the grant date fair value of the awards. As discussed above, as a result of our Chapter 11 Filing, we are unable to continue the long-term incentive programs for the NEOs that were in place prior to the filing of such petitions without Bankruptcy Court approval. In addition, under the Plan of Reorganization confirmed by the Bankruptcy Court, all of our equity securities will be canceled, including our common stock and any outstanding equity awards in respect of such equity securities, such as the PRSUs. Accordingly, the NEOs are not expected to realize any value in respect of the 2016 PRSUs. |
(2) | Amounts in this column reported for 2016 represent awards earned under the 2016 ELT-STIP based on actual performance. The material terms of the 2016 ELT-STIP awards are described under the heading “2016 Annual Cash Incentives” above. |
(3) | Amounts in this column reported for 2016 reflect only changes in the actuarial present value of Mr. Williamson’s accumulated benefit under the Peabody Investments Corp. (or PIC) Retirement Plan. See below for more discussion about this plan. |
(4) | Amounts included in this column are described in the All Other Compensation table below. |
(5) | Mr. Kellow served as our President and Chief Operating Officer prior to being named President and Chief Executive Officer effective May 1, 2015. The 2015 salary amounts for Mr. Kellow represents a blend of (1) amounts paid prior to his promotion to President and CEO for the applicable time period, and (2) amounts paid following his promotion. |
(6) | During the period beginning on May 1, 2015 and ending on December 31, 2015, Mr. Kellow requested a voluntary 10% reduction to his annual base salary in response to market conditions and to align with our cash conservation initiatives. |
(7) | Award payouts earned based on actual performance under the 2015 annual cash incentive plan were reduced by 50%. |
(8) | The 2015 salary amounts for Ms. Schwetz represents a blend of (1) amounts paid prior to her promotion to Executive Vice President and Chief Financial Officer for the applicable time period, and (2) amounts paid following her promotion. |
(9) | On March 15, 2017, we announced that Mr. Meintjes will assume the role of Executive Vice President - Corporate Services and Chief Commercial Officer effective following our emergence from our Chapter 11 Cases and George J. Schuller, the current Chief Operations Officer in Australia, will fill the role of President - Australia. |
Peabody Energy Corporation | 2016 Form 10-K | 109 |
All Other Compensation
The following table sets forth detailed information regarding the 2016 amounts reported in the All Other Compensation column of the 2016 Summary Compensation Table above.
Name | Group Term Life Insurance ($) | Registrant Contributions for Defined Contribution Plans ($) (1) | Tax Gross-Ups ($) (2) | Perquisites ($) (3) | Total ($) | ||||||||||
Glenn L. Kellow | 1,710 | 15,900 | — | — | 17,610 | ||||||||||
Amy B. Schwetz | 804 | 15,900 | 18,183 | — | 34,887 | ||||||||||
Charles F. Meintjes | 2,160 | 23,850 | 46,859 | — | 72,869 | ||||||||||
Kemal Williamson | 3,646 | 46,793 | 499 | — | 50,938 | ||||||||||
A. Verona Dorch | 1,143 | 15,900 | 24,896 | 94,124 | 136,063 | ||||||||||
(1) | Represents employee and employer contributions to the Company’s qualified 401(k) plan. There were no employee or employer contributions to the Company’s Excess Retirement Plan. |
(2) | For Ms. Schwetz, represents tax gross-ups consisting of $17,301 related to her expatriate assignment in Australia and $882 tax gross-up for tax return preparation costs. For Mr. Meintjes, represents tax gross-up related to his expatriate assignment in Australia. For Mr. Williamson, represents tax gross-ups related to tax return preparation costs. For Ms. Dorch, represents tax gross-ups related to her temporary housing expenses. |
(3) | For Ms. Dorch, includes $45,000 for travel expenses incurred for travel between her principal residence to the Company’s headquarters in St. Louis, Missouri, $47,580 for temporary housing and $1,544 for use of our corporate aircraft. In the course of business travel, Ms. Dorch occasionally embarked or disembarked the corporate aircraft at an airport (commiserate with her principal residence) along the route between the origin and destination of the business travel. The aggregate incremental cost of use of our corporate aircraft was determined on a per flight basis, including, as applicable, the cost of fuel, landing fees, in-flight meals, sales tax, crew expenses, the hourly cost of aircraft maintenance for the applicable number of flight hours, and other variable costs specifically incurred. |
Peabody Energy Corporation | 2016 Form 10-K | 110 |
2016 Grants of Plan-Based Awards
The following table sets forth information concerning grants to the NEOs of plan-based awards during the year ended December 31, 2016. The table includes prepetition PRSUs and annual cash incentive awards which, as described above, we are unable to continue without Bankruptcy Court approval as a result of our Chapter 11 Filing. The table also reflects awards under the 2016 ELT-STIP as approved by the Bankruptcy Court.
Estimated Future Payouts Under Non-Equity Incentive Plan Awards | Estimated Future Payouts Under Equity Incentive Plan Awards (4) | Grant Date Fair Value of Stock and Option Awards ($) (5) | |||||||||||||||||||||||||
Grant Date | Approval Date | Threshold ($) | Target ($) | Maximum ($) | Threshold (#) | Target (#) | Maximum (#) | ||||||||||||||||||||
Glenn L. Kellow | — | — | 69,264 | (1) | 1,108,223 | (1) | 2,216,445 | (1) | — | — | — | — | |||||||||||||||
— | — | 55,411 | (2) | 1,108,223 | (2) | 1,662,334 | (2) | — | — | — | — | ||||||||||||||||
— | — | 88,154 | (3) | 1,763,081 | (3) | 2,644,622 | (3) | — | — | — | — | ||||||||||||||||
1/4/2016 | 12/10/2015 | — | — | — | — | 140,000 | — | 1,085,000 | |||||||||||||||||||
Amy B. Schwetz | — | — | 25,000 | (1) | 400,000 | (1) | 800,000 | (1) | — | — | — | — | |||||||||||||||
— | — | 20,000 | (2) | 400,000 | (2) | 600,000 | (2) | — | — | — | — | ||||||||||||||||
— | — | 37,500 | (3) | 750,000 | (3) | 1,125,000 | (3) | — | — | — | — | ||||||||||||||||
1/4/2016 | 12/10/2015 | — | — | — | — | 29,333 | — | 227,331 | |||||||||||||||||||
Charles F. Meintjes | — | — | 27,775 | (1) | 444,400 | (1) | 888,800 | (1) | — | — | — | — | |||||||||||||||
— | — | 22,220 | (2) | 444,400 | (2) | 666,600 | (2) | — | — | — | — | ||||||||||||||||
— | — | 34,719 | (3) | 694,375 | (3) | 1,041,563 | (3) | — | — | — | — | ||||||||||||||||
1/4/2016 | 12/10/2015 | — | — | — | — | 36,667 | — | 284,169 | |||||||||||||||||||
Kemal Williamson | — | — | 25,250 | (1) | 404,000 | (1) | 808,000 | (1) | — | — | — | — | |||||||||||||||
— | — | 20,200 | (2) | 404,000 | (2) | 606,000 | (2) | — | — | — | — | ||||||||||||||||
— | — | 31,562 | (3) | 631,250 | (3) | 946,875 | (3) | — | — | — | — | ||||||||||||||||
1/4/2016 | 12/10/2015 | — | — | — | — | 33,333 | — | 258,331 | |||||||||||||||||||
A. Verona Dorch | — | — | 23,000 | (1) | 368,000 | (1) | 736,000 | (1) | — | — | — | — | |||||||||||||||
— | — | 18,400 | (2) | 368,000 | (2) | 552,000 | (2) | — | — | — | — | ||||||||||||||||
— | — | 28,750 | (3) | 575,000 | (3) | 862,500 | (3) | — | — | — | — | ||||||||||||||||
1/4/2016 | 12/10/2015 | — | — | — | — | 29,333 | — | 227,331 | |||||||||||||||||||
Peabody Energy Corporation | 2016 Form 10-K | 111 |
(1) | Represents the estimated payouts under the 2016 annual cash incentive program award opportunities prior to the Petition Date. The target award represented 100% of the maximum award value payable upon the achievement of the performance measures (Pre-Petition Price-collar Adjusted EBITDA, Safety and individual goals) described above under the subheading “2016 Performance Measures under the Annual Cash Incentive Plan Prior to our Chapter 11 Filing” at 100% of the specified performance measures. The maximum award represents 200% of the target award value and the threshold award represents 6.3% of the target award value, assuming that only the lowest weighted metric met the threshold. As a result of our Chapter 11 Filing and the modification to the annual cash incentive program, as discussed above, the Committee did not evaluate performance under the 2016 annual cash incentive program and the NEOs did not receive any payments under the 2016 annual cash incentive program. |
(2) | Represents the payouts under the 2016 ELT-STIP. The target award represents the maximum award payable upon achievement of the performance measures (2016 ELT-STIP Adjusted EBITDAR, TRIFR and SAWOL MS) described above under the subheading “2016 Performance Measures under the 2016 ELT-STIP” at 100% of the specified performance measures. The maximum award represents 150% of the target award value and the threshold award represents 5% of the target award value, assuming that only the lowest weighted metric met the threshold. Actual payouts under the 2016 ELT-STIP are included in the Summary Compensation Table. |
(3) | Represents the payouts under the KEIP. The target award represents the maximum award payable upon achievement of the performance measures (Consolidated Adjusted EBITDAR (Excluding Australia), Australia Adjusted EBITDAR, Consolidated Cash Flow (Before Restructuring Costs)), and Environmental Reclamation) at 100% of the specified performance measures. The maximum award represents 150% of the target award value and the threshold award represents 5% of the target award value, assuming that only the lowest weighted metric met the threshold. As noted above, because the Plan Effective Date did not occur in 2016, none of the NEOs earned any amounts under the KEIP in 2016. The determination of any amounts to be earned under the KEIP will be made following the Plan Effective Date. |
(4) | Represents the number of shares of our common stock underlying PRSU award opportunities granted in 2016. The PRSUs were designed to vest over a three-year performance period ending on December 31, 2018 at a rate of one-third per year based on performance during that applicable year. Payout was designed to be subject to the compliance with the Credit Agreement, which, as disclosed above, for 2016 we did not achieve. The material terms of these awards, including payout formulas, are described under the subheading “PRSUs”. As discussed above, as a result of our Chapter 11 Filing, we are unable to continue the long-term incentive programs for the NEOs that were in place prior to the filing of such petitions without Bankruptcy Court approval. In addition, under the Plan confirmed by the Bankruptcy Court, all of our equity securities will be canceled, including our common stock and any outstanding equity awards in respect of such equity securities, such as the PRSUs. |
(5) | Represents the grant date fair value of stock awards determined in accordance with FASB ASC Topic 718. A discussion of the relevant fair value assumptions is set forth in Note 20 to our consolidated financial statements included in this Form 10-K. As discussed above, as a result of our Chapter 11 Filing, we are unable to continue the long-term incentive programs for the NEOs that were in place prior to the filing of such petitions without Bankruptcy Court approval. In addition, under the Plan confirmed by the Bankruptcy Court, all of our equity securities will be canceled, including our common stock and any outstanding equity awards in respect of such equity securities, such as the PRSUs. |
Peabody Energy Corporation | 2016 Form 10-K | 112 |
Outstanding Equity Awards at 2016 Fiscal Year-End
The table below sets forth details about the outstanding equity awards for each of the NEOs as of December 31, 2016. We generally note that the amount ultimately realized from outstanding equity awards typically varies based on a number of factors, including our actual operating performance, stock price fluctuations and the timing of exercises (for options and SARs only) and stock sales. However, as discussed above, as a result of our Chapter 11 Filing, we are unable to continue the long-term incentive programs for the NEOs that were in place prior to the filing of such petitions without Bankruptcy Court approval. In addition, under the Plan confirmed by the Bankruptcy Court, all of our equity securities will be canceled, including our common stock and any outstanding equity awards in respect of such equity securities, including all of the awards described in the table below.
Option Awards | Stock Awards | ||||||||||||||||||||||
Name | Number of Securities Underlying Unexercised Options (#) (1) Exercisable | Number of Securities Underlying Unexercised Options (#) (1) Unexercisable | Option Exercise Price ($) (1) | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested (1) | Market Value of Shares or Units of Stock That Have Not Vested ($) (2) | Equity Incentive Plan Awards; Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (1)(3) | Equity Incentives Plan Awards; Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (4) | |||||||||||||||
Glenn L. Kellow | 3,954 | (14) | — | 270.750 | 9/16/2023 | 6,459 | (7) | 32,295 | 2,248 | (5) | 11,242 | ||||||||||||
8,972 | (15) | 4,486 | (15) | 293.100 | 1/2/2024 | — | — | 5,952 | (6) | 29,760 | |||||||||||||
6,335 | (16) | 12,670 | (16) | 116.100 | 1/2/2025 | — | — | — | — | ||||||||||||||
Total | 19,261 | 17,156 | 6,459 | 32,295 | 8,200 | 41,002 | |||||||||||||||||
Amy B. Schwetz | — | — | — | 1,551 | (7) | 7,755 | — | — | |||||||||||||||
Total | — | — | — | 1,551 | 7,755 | — | — | ||||||||||||||||
Charles F. Meintjes | 358 | (11) | — | 967.800 | 1/3/2021 | 3,158 | 15,792 | 1,030 | (5) | 5,152 | |||||||||||||
680 | (12) | — | 544.050 | 1/3/2022 | — | — | 2,182 | (6) | 10,912 | ||||||||||||||
Total | 1,038 | — | 3,158 | 15,792 | 3,212 | 16,064 | |||||||||||||||||
Kemal Williamson | 1,050 | (8) | — | 940.800 | 1/2/2018 | 2,153 | (7) | 10,765 | 936 | (5) | 4,682 | ||||||||||||
2,154 | (9) | — | 402.600 | 1/5/2019 | — | — | 1,984 | (6) | 9,920 | ||||||||||||||
1,090 | (10) | — | 718.050 | 1/4/2020 | — | — | — | — | |||||||||||||||
425 | (11) | — | 967.800 | 1/3/2021 | — | — | — | — | |||||||||||||||
425 | (11) | — | 967.800 | 1/3/2021 | — | — | — | — | |||||||||||||||
799 | (12) | — | 544.050 | 1/3/2022 | — | — | — | — | |||||||||||||||
4,643 | (13) | — | 387.600 | 1/2/2023 | — | — | — | — | |||||||||||||||
3,738 | (15) | 1,869 | (15) | 116.100 | 1/2/2024 | — | — | — | — | ||||||||||||||
2,122 | (16) | 4,223 | (16) | 116.100 | 1/2/2025 | — | — | — | — | ||||||||||||||
Total | 16,446 | 6,092 | 2,153 | 10,765 | 2,920 | 14,602 | |||||||||||||||||
A. Verona Dorch | — | — | 10,714 | (7) | 53,570 | — | — | ||||||||||||||||
Total | — | — | 10,714 | 53,570 | — | — | |||||||||||||||||
Peabody Energy Corporation | 2016 Form 10-K | 113 |
(1) | The number of stock options/SARs/shares/units and the exercise prices of options have been adjusted, where applicable, to reflect: our 2-for-1 stock splits in March 2005 and February 2006; the spin-off of Patriot Coal Corporation on October 31, 2007; and the 1-for-15 stock split in September 2015. |
(2) | The market value was calculated based on the closing market price per share of our common stock on the last trading day of 2016 ($5.00 per share). |
(3) | The number of performance units disclosed is based on the assumption that target performance goals will be achieved. |
(4) | The market value was calculated based on the closing market price per share of our common stock on the last trading day of 2016 ($5.00 per share). As of December 31, 2016, we are not authorized to pay out our 2014 and 2015 grants of performance units, regardless of award achievement. |
(5) | The performance units were granted on January 2, 2014, and were intended to vest over a three-year performance period (ended December 31, 2016). Payout in early 2017 was to be subject to the achievement of the following goals: (i) our three-year TSR performance relative to the applicable Performance Unit Peer Group and the S&P 500 Index Group and (ii) a three-year ROMA target. |
(6) | The performance units were granted on January 2, 2015, and were intended to vest over a three-year performance period (ending December 31, 2017). Payout in early 2018 was to be subject to the achievement of the following goals: (i) our three-year TSR performance relative to the applicable Performance Unit Peer Group and the S&P 400 Midcap Index Group and (ii) a three-year ROMA target. A portion of the performance units granted to Mr. Kellow were intended to be payable, if earned, in cash based on the plan limitation previously discussed. |
(7) | The restricted shares were granted on January 2, 2015 and were intended to vest on the third anniversary of the grant date (January 2, 2018). For Ms. Dorch, the restricted shares were granted on August 19, 2015 and were intended to vest on the third anniversary of the grant date (August 19, 2018). Two-thirds of the number of restricted shares that were granted to Mr. Meintjes have vested or were intended to vest in three equal annual installments beginning on the first anniversary of the grant date; the remaining restricted shares were intended to vest on the third anniversary of the grant date. |
(8) | The options were granted on January 2, 2008 and vested in three equal installments beginning January 2, 2009. |
(9) | The options were granted on January 5, 2009 and vested in three equal installments beginning January 5, 2010. |
(10) | The options were granted on January 4, 2010 and vested in three equal installments beginning January 4, 2011. |
(11) | The options were granted on January 3, 2011 and vested in three equal installments beginning January 3, 2012. |
(12) | The options were granted on January 3, 2012 and vested in three equal installments beginning January 3, 2013. |
(13) | The options were granted on January 2, 2013 and vested in three equal installments beginning January 2, 2014. |
(14) | The options were granted on September 16, 2013 and were intended to vest in three equal installments beginning September 16, 2014. |
(15) The options were granted on January 2, 2014 and were intended to vest in three equal installments beginning January 2, 2015.
(16) The options were granted on January 2, 2015 and were intended to vest in three equal installments beginning January 2, 2016.
2016 Option Exercises and Stock Vested
The following table sets forth detail about stock awards that vested during 2016 for each of the NEOs prior to the Petition Date. The stock awards below included only common stock delivered in connection with the lapse of restrictions on restricted stock vesting prior to the Petition Date. There were no stock option exercises in 2016. As described above, as a result of our Chapter 11 Filing, we are unable to continue the long-term incentive programs for the NEOs that were in place prior to the filing of such petitions without Bankruptcy Court approval. In addition, under the Plan confirmed by the Bankruptcy Court, all of our equity securities will be canceled, including our common stock and any outstanding equity awards in respect of such equity securities.
Stock Awards (1) | ||||||
Name | Number of Shares Acquired on Vesting | Value Realized on Vesting ($) | ||||
Glenn L. Kellow | — | — | ||||
Amy B. Schwetz | 644 | 4,946 | ||||
Charles F. Meintjes | 2,182 | 16,758 | ||||
Kemal Williamson | — | — | ||||
A. Verona Dorch | — | — | ||||
(1) Includes shares of common stock that were delivered in connection with the lapse of restrictions on restricted stock vesting prior to the Petition Date.
Peabody Energy Corporation | 2016 Form 10-K | 114 |
Performance Unit Program
As discussed above, after the Petition Date, we are not authorized to continue our long-term incentive programs for our NEOs without Bankruptcy Court approval. As a result, we did not conduct a specific assessment of performance against the pre-established performance goals of relative TSR and Return on Mining Assets (ROMA) goals for the 2014 and 2015 performance unit programs covering the 2014-2016 and 2015-2017 performance periods, respectively. We did not provide any payouts to our NEOs in respect of the 2014 and 2015 performance unit programs.
2016 Pension Benefits
Our Retirement Plan for Salaried Employees, or pension plan, is a qualified “defined benefit” pension plan. The pension plan provides a monthly annuity to eligible salaried employees when they retire. An employee must have at least five years of service to be vested in his or her benefit under the pension plan. A full benefit is available to a retiree at age 62. A retiree can begin receiving a benefit as early as age 55; however, a 4% reduction factor applies for each year a retiree receives a benefit prior to age 62.
The pension plan was phased out beginning January 1, 2001. Certain transition benefits were introduced based on the age and service of affected employees at December 31, 2000. Each of the participants in the pension plan has had his or her pension benefits frozen. In all cases, final average earnings for retirement purposes are capped at December 31, 2000 levels.
A participant’s retirement benefit under the pension plan is equal to the sum of (1) 1.112% of the highest average monthly earnings over 60 consecutive months up to the “covered compensation limit” multiplied by the employee’s years of service, not to exceed 35 years, and (2) 1.5% of the average monthly earnings over 60 consecutive months over the “covered compensation limit” multiplied by the employee’s years of service, not to exceed 35 years. Under the pension plan, “earnings” include compensation earned as base salary and up to five annual incentive awards.
Listed below is the actuarial present value of the current accumulated pension benefit under the pension plan as of December 31, 2016 for the NEOs. Due to the phase out of the pension plan in 2001, Mr. Williamson is the only NEO who is eligible to receive a benefit under the pension plan. The estimated present value was determined assuming Mr. Williamson retired at age 62, the normal retirement age under the plan, using a discount rate of 4.15% and the RP 2014 Blue Collar Sex-Distinct Annuitant Mortality projected back to 2007 with MP 2014, and projected forward using generational Scale BB-2D. Other material assumptions used in making the calculations are discussed in Note 20. "Share-Based Compensation" to our consolidated financial statements included in this Form 10-K. The disclosed amounts are estimates only and do not necessarily reflect the actual amounts that will be paid to an NEO. Such amounts will be known only at the time the NEO becomes eligible for payment.
Name | Plan Name | Number of Years Credited Service (#) (1) | Present Value of Accumulated Benefit ($) | Payments During Last Fiscal Year | |||||||
Glenn L. Kellow | (2) | Peabody Investments Corp. Retirement Plan | — | Not a plan participant | — | ||||||
Amy B. Schwetz | (2) | Peabody Investments Corp. Retirement Plan | — | Not a plan participant | — | ||||||
Charles F. Meintjes | (2) | Peabody Investments Corp. Retirement Plan | — | Not a plan participant | — | ||||||
Kemal Williamson | (3) | Peabody Investments Corp. Retirement Plan | 0.4 | 9,651 | — | ||||||
A. Verona Dorch | (2) | Peabody Investments Corp. Retirement Plan | — | Not a plan participant | — | ||||||
(1) | Due to the phase-out of our pension plan as described above, years of credited service are less than years of actual service. The actual years of service number for Mr. Williamson is 16.4. |
(2) | Messrs. Kellow and Meintjes and Ms. Schwetz and Ms. Dorch are not eligible to receive benefits under our pension plan because their employment with us began after the pension plan was phased out. |
(3) | Under the terms of the phase-out, pension benefits for Mr. Williamson were frozen as of December 31, 2000, and years of credited service, for the purposes of the pension plan, ceased to accrue. |
2016 Nonqualified Deferred Compensation
The following table sets forth detail about activity for the NEOs in our nonqualified excess defined contribution retirement plan (or Excess Retirement Plan).
Peabody Energy Corporation | 2016 Form 10-K | 115 |
Historically, our executives also participated in the Excess Retirement Plan, which is designed to allow highly compensated management employees to make contributions in excess of certain limits imposed by the Internal Revenue Code that apply to our tax-qualified 401(k) plan. The Excess Retirement Plan is designed to restore the benefits, including matching contributions, not permitted due to certain limits imposed by the Internal Revenue Code on the 401(k) plan. Investment options under the Excess Retirement Plan are identical to those under the 401(k) plan, except that historically the 401(k) plan also included the Peabody Energy Stock Fund as an investment option. The Excess Retirement Plan was suspended effective December 31, 2015 and participants were no longer able to contribute to the plan and the Company did not make any contributions on behalf of participants.
Under the Plan confirmed by the Bankruptcy Court, the liabilities relating to our current employees under the Excess Retirement Plan will be spun off and transferred to a new nonqualified supplemental employee retirement account plan. The liabilities of former employees will remain under the Excess Retirement Plan, which will be frozen and will not be assumed by us.
Name | Plan Name | Executive Contributions in Last Fiscal Year ($) | Registrant Contributions in Last Fiscal Year ($) | Aggregate Earnings in Last Fiscal Year ($) | Aggregate Withdrawals/Distributions ($) | Aggregate Balance at Last Fiscal Year End ($) (1) | |||||||||||
Glenn L. Kellow | (2) | Excess Retirement Plan | — | — | 13,236 | — | 180,110 | ||||||||||
Amy B. Schwetz | (2) | Excess Retirement Plan | — | — | 871 | — | 10,772 | ||||||||||
Charles F. Meintjes | (2) | Excess Retirement Plan | — | — | 6,721 | — | 339,291 | ||||||||||
Kemal Williamson | (3) | Excess Retirement Plan | — | — | 74,332 | — | 1,016,699 | ||||||||||
A. Verona Dorch | (2) | Excess Retirement Plan | — | — | — | — | — | ||||||||||
(1) Of the totals in this column, the following amounts represent Registrant Contributions to the Excess Retirement Plan that are reported in the 2016 Summary Compensation Table for the years 2007-2016:
Name | Excess Defined Contribution Retirement Plan Registrant Contributions Included in the 2016 Summary Compensation Table ($) | Excess Defined Contribution Retirement Plan Registrant Contributions Included in the 2007 - 2015 Summary Compensation Tables ($) | Total ($) | ||||||
Glenn L. Kellow | — | 99,730 | 99,730 | ||||||
Amy B. Schwetz | — | 4,610 | 4,610 | ||||||
Charles F. Meintjes | — | 113,258 | 113,258 | ||||||
Kemal Williamson | — | 64,396 | 64,396 | ||||||
A. Verona Dorch | — | — | — | ||||||
Peabody Energy Corporation | 2016 Form 10-K | 116 |
Potential Payments Upon Termination or Change in Control
In 2015, all NEOs had either transitioned from employment agreements or became participants in the Severance Plan, with the exception of Mr. Kellow, whose employment agreement expired in September 2016. Due to the pendency of our Chapter 11 Cases, Mr. Kellow did not sign an agreement to participate in the Severance Plan after the expiration of his employment agreement.
The Severance Plan was adopted to provide transitional assistance to certain senior executives whose employment is terminated by us (for reasons other than cause, death or disability) or by the senior executive for good reason. Mr. Kellow’s employment agreement provided, and the Severance Plan provides, cash severance based upon a 2x severance multiple of the sum of annual base salary and average annual cash incentive paid over the preceding three years (or a 2.5x multiple for the CEO if termination occurs within two years following a Change in Control), as well as continuing healthcare benefits. The table set forth on the next page reflects the amount of compensation that would have been payable to the NEOs in the event of termination of employment, including certain benefits upon an involuntary termination related to a Change in Control, under the terms of the Severance Plan and long-term incentive award agreements, as applicable. Terms used in the chart are defined in the applicable Severance Plan or award agreement. The amounts shown assume a termination effective as of December 30, 2016. The actual amounts that would be payable can be determined only at the time of the NEO’s termination. The amount of compensation payable to each NEO upon retirement is not included in the table, as none of the NEOs were eligible for retirement (age 60, with 10 years of service) as of December 30, 2016.
Mr. Kellow’s employment agreement expired in September 2016. Due to the pendency of our Chapter 11 Cases, Mr. Kellow did not sign an agreement to participate in the Severance Plan after the expiration of his employment agreement. We have provided in the chart below a description of the severance benefits that Mr. Kellow would have received as of December 30, 2016 assuming he had been a participant in the Severance Plan on that date. Outside of the terms of the Severance Plan, as of December 30, 2016, Mr. Kellow was entitled to $560,692 in accelerated and/or continued vesting or earnout of his unvested equity awards under our applicable equity award arrangements with him on terms similar to those described below for our other NEOs.
The Bankruptcy Code places limitations on payments made to insiders of a company for, among other things, severance payments. Accordingly, during the Chapter 11 Cases, if any of our NEOs were to incur a termination of employment that would entitle the NEO to severance under the Severance Plan, any severance payments would be limited. Specifically, section 503(c)(2) of the Bankruptcy Code prohibits severance payments to insiders unless (i) the payment is part of a program that is generally applicable to all full-time employees and (ii) the amount of the payment is not greater than 10 times the amount of the mean severance pay given to non-management employees during the calendar year in which the payment is made.
Peabody Energy Corporation | 2016 Form 10-K | 117 |
Cash Severance ($) | Continued Benefits and Perquisites ($) | Other Cash Payment ($) | Accelerated and/or Continued Vesting/Earnout of Unvested Equity Compensation ($)(1) | Excise Tax Gross-up or Cut-back ($) | Total ($) | |||||||||||||
Glenn L. Kellow | ||||||||||||||||||
"For Cause" Termination or Voluntary Termination (2) | — | — | — | — | — | — | ||||||||||||
Death or Disability (3) | 1,435,370 | — | — | 560,692 | — | 1,996,062 | ||||||||||||
Involuntary Termination "Without Cause" or "For Good Reason" (4) | 5,119,691 | 24,172 | — | — | — | 5,143,863 | ||||||||||||
Involuntary Termination Related to a Change in Control (6) | 6,040,771 | 24,172 | — | 560,692 | — | 6,625,635 | ||||||||||||
Amy B. Schwetz | ||||||||||||||||||
"For Cause" Termination or Voluntary Termination (2) | — | — | — | — | — | — | ||||||||||||
Death or Disability (3) | 518,080 | — | — | 7,755 | — | 525,835 | ||||||||||||
Involuntary Termination "Without Cause" or "For Good Reason" (4) | 1,896,875 | 24,715 | — | — | — | 1,921,590 | ||||||||||||
Involuntary Termination Related to a Change in Control (5) | 1,896,875 | 24,715 | — | 7,755 | — | 1,929,345 | ||||||||||||
Charles F. Meintjes | ||||||||||||||||||
"For Cause" Termination or Voluntary Termination (2) | — | — | — | — | — | — | ||||||||||||
Death or Disability (3) | 575,587 | — | — | 147,109 | — | 722,696 | ||||||||||||
Involuntary Termination "Without Cause" or "For Good Reason" (4) | 2,568,554 | 34,592 | — | 11,735 | — | 2,614,881 | ||||||||||||
Involuntary Termination Related to a Change in Control (5) | 2,568,554 | 34,592 | — | 147,109 | — | 2,750,255 | ||||||||||||
Kemal Williamson | ||||||||||||||||||
"For Cause" Termination or Voluntary Termination (2) | — | — | — | — | — | — | ||||||||||||
Death or Disability (3) | 523,261 | — | — | 130,142 | — | 653,403 | ||||||||||||
Involuntary Termination "Without Cause" or "For Good Reason" (4) | 2,313,159 | 24,715 | — | — | — | 2,337,874 | ||||||||||||
Involuntary Termination Related to a Change in Control (5) | 2,313,159 | 24,715 | — | 130,142 | — | 2,468,016 | ||||||||||||
A. Verona Dorch | ||||||||||||||||||
"For Cause" Termination or Voluntary Termination (2) | — | — | — | — | — | — | ||||||||||||
Death or Disability (3) | 476,634 | — | — | 151,347 | — | 627,981 | ||||||||||||
Involuntary Termination "Without Cause" or "For Good Reason" (4) | 1,932,437 | 24,172 | — | — | — | 1,956,609 | ||||||||||||
Involuntary Termination Related to a Change in Control (5) | 1,932,437 | 24,172 | — | 151,347 | — | 2,107,956 | ||||||||||||
Peabody Energy Corporation | 2016 Form 10-K | 118 |
(1) | Reflects the value the NEO could realize as a result of the accelerated and/or continued vesting of any unvested performance units, restricted stock, restricted stock units and stock option awards. Value attributed to restricted stock and restricted stock units is based on the December 30, 2016 closing stock price of $5.00. There is no value assigned to outstanding stock options, as all outstanding stock options have exercise prices that are greater than the December 30, 2016 closing stock price of $5.00. |
(2) | “For Cause,” as defined for all NEOs includes: (1) any material and uncorrected breach by the NEO of the terms of his employment agreement, including but not limited to, engaging in disclosure of secret or confidential information; (2) any willful fraud or dishonesty of the NEO involving our property or business; (3) a deliberate or willful refusal or failure to comply with any major corporate policies which are communicated in writing; or (4) the NEO’s conviction of, or plea of no contest to any felony if such conviction shall result in imprisonment or if such conviction has a material detrimental effect on our reputation or business. |
(3) | For all NEOs, compensation payable upon death or disability would include (1) accrued but unused vacation; (2) earned but unpaid annual incentive for the year of termination; (3) 100% payout of outstanding performance units based on actual performance to the date of termination; and (4) the value the NEO could realize as a result of the accelerated and/or continued vesting of any unvested restricted stock, restricted stock units, and stock option awards, as applicable. For 2016, the earned but unpaid annual incentive was equal to 100% of the sum of the non-equity incentive plan compensation, as shown in the Summary Compensation Table. Amounts do not include life insurance payments in the case of death. |
(4) | For all NEOs, compensation payable would include: (1) severance payments of two times base salary; (2) a payment equal to two times the average of the actual annual incentives paid in the three prior years; (3) a payment equal to two times 6% of base salary to compensate the NEO for Company contributions the NEO otherwise might have received under our 401(k) plan; (4) any earned but unpaid annual incentive for the year of termination; (5) continuation of benefits for 18 months; (6) the value that could be realized based on a portion of the continued vesting of outstanding stock option awards; and (7) a prorated payout of outstanding performance units based on performance through the end of the performance period. |
(5) | The amounts the NEOs would receive in the event of an involuntary termination in connection with a Change in Control, as defined in the applicable employment agreement, Severance Plan, or award agreement, are similar to those described in footnote 4 above. |
(6) | For the CEO, compensation payable would include: (1) severance payments of two and one half times base salary; (2) a payment equal to two and one half times the average of the actual annual incentives paid in the three prior years; (3) a payment equal to two and one half times 6% of base salary to compensate the CEO for Company contributions the CEO otherwise might have received under our 401(k) plan; (4) any earned but unpaid annual incentive for the year of termination; (5) continuation of benefits for 18 months; (6) the value that could be realized based on a portion of the continued vesting of outstanding stock option awards; and (7) a prorated payout of outstanding performance units based on performance through the end of the performance period. |
Peabody Energy Corporation | 2016 Form 10-K | 119 |
DIRECTOR COMPENSATION
Compensation of non-employee directors for 2016 consisted of cash compensation, specifically annual board and committee retainers, and equity compensation. Each of these components is described below in more detail. Any director who is also our employee receives no additional compensation for serving as a director.
Annual Board and Committee Retainers
Prior to the Petition Date, for 2016, each non-employee director was eligible to receive an annual cash retainer of $110,000, payable quarterly in advance, a deferred cash award of $65,000, that was to vest monthly and would be payable in January 2017, and equity with a value of $65,000, that was designed to vest monthly, awarded in deferred stock units. The Chairs of the Audit Committee and Compensation Committee each were to receive an additional annual $15,000 cash retainer, and the Chairs of the Health, Safety, Security and Environmental Committee and the Nominating and Corporate Governance Committee each received an additional annual $10,000 cash retainer. The Non-Executive Chairman of the Board was to receive an additional annual $150,000 cash retainer. Because the annual cash retainers and the Chair retainers are paid quarterly in advance, as of the Petition Date, no amounts were due under the retainers. As a result of the Chapter 11 Filing, the deferred stock units were not distributed and the deferred cash awards were not paid to the non-employee directors. As noted above, under the Plan, all of our equity securities will be canceled, including our common stock and any outstanding equity awards in respect of such equity securities, including the deferred stock units.
After the Petition Date, we sought authorization and approval for certain changes to the compensation of our non-employee directors. As described above, we traditionally compensated our non-employee directors with both cash payments and equity awards. As a result of the Chapter 11 Cases, we determined that modifying the compensation of the non-employee directors to eliminate the equity award altogether (with no replacement of its value) and to combine all cash compensation into the cash retainer was beneficial to the enterprise and appropriate under the facts and circumstances of the Chapter 11 Cases. Therefore, we sought approval of a combined annual retainer of $175,000, plus applicable Chair retainers, during the pendency of the Chapter 11 Cases. The Bankruptcy Court subsequently approved such modifications.
We pay travel and accommodation expenses of our non-employee directors to attend meetings and other corporate functions. Non-employee directors do not receive meeting attendance fees. Non-employee directors may be accompanied by a spouse/partner when traveling on company business on our aircraft or charter aircraft. Non-employee directors also have the opportunity to participate in our charitable contribution matching gifts program at the same level and based on the same guidelines applicable to our full-time employees.
Annual Equity Compensation
Prior to the modifications to our non-employee director compensation described above, for 2016, non-employee directors received equity compensation valued at $65,000, awarded in deferred stock units (based on the fair market value of our Common Stock on the grant date). The deferred stock units were to vest ratably over 12 months (such that they fully vest on the first anniversary of the grant date) and would be converted into shares of our Common Stock on the specified distribution date elected by each non-employee director. In the event of a change in control (as defined in the 2015 LTIP), any unvested deferred stock units would vest on an accelerated basis. The deferred stock units also provided for accelerated vesting in the event of the non-employee director’s death or disability or separation from service due to the non-employee director reaching the end of his or her elected term and either (1) being ineligible to run for an additional term on the Board as a result of reaching age 75 or (2) having completed three years of service as a non-employee director and the current Board term for which he or she was elected.
Peabody Energy Corporation | 2016 Form 10-K | 120 |
The total 2016 compensation of our non-employee directors is shown in the table below.
Fees Earned or Paid in Cash ($) (1) | Stock Awards ($) (2) | All Other Compensation ($) (3) | Total ($) | Undistributed Deferred Stock Units (#) | Outstanding Stock Options (#) (4) | |||||||||||||
William A. Coley | 156,583 | 33,581 | 2,500 | 192,664 | 5,895 | — | ||||||||||||
William E. James | 156,583 | 33,581 | — | 190,164 | 5,895 | — | ||||||||||||
Robert B. Karn III | 156,583 | 33,581 | — | 190,164 | 6,122 | — | ||||||||||||
Henry E. Lentz * | 166,583 | 33,581 | — | 200,164 | 5,895 | — | ||||||||||||
Robert A. Malone ^ | 306,583 | 33,581 | 8,292 | 348,456 | 5,895 | — | ||||||||||||
William C. Rusnack * | 171,583 | 33,581 | 2,500 | 207,664 | 5,895 | — | ||||||||||||
Michael W. Sutherlin | 156,583 | 33,581 | — | 190,164 | 5,944 | — | ||||||||||||
John F. Turner * | 166,583 | 33,581 | — | 200,164 | 5,895 | — | ||||||||||||
Sandra Van Trease * | 171,583 | 33,581 | — | 205,164 | 5,895 | — | ||||||||||||
Heather A. Wilson | 156,583 | 33,581 | 2,500 | 192,664 | 6,140 | — | ||||||||||||
* Committee Chair
^ Non-Executive Chairman
(1) | Fees Earned include the annual retainer and any committee chair or non-executive chair premiums. In August 2016, the Bankruptcy Court approved an increase to the annual retainer from $110,000 to $175,000 effective for the pendency of the Chapter 11 Cases. |
(2) | On January 4, 2016, each Director was granted 4,333 deferred stock units at a grant date fair value of $7.75 per share. As noted above, as a result of our Chapter 11 Filing, we are not authorized to continue our long-term incentive programs for insiders (as defined under the Bankruptcy Code), including for our non-executive directors. As a result, the deferred stock units have not been distributed. Also, under the Plan, all of our equity securities will be canceled, including the deferred stock units. |
(3) | All Other Compensation for Messrs. Coley, Rusnack and Dr. Wilson consists of charitable contributions in accordance with our matching gifts program. All Other Compensation for Mr. Malone consists of the aggregate incremental cost to us for use of our corporate aircraft when his spouse accompanied him on business travel. The aggregate incremental cost to us for use of our corporate aircraft was determined on a per flight basis, including the cost of fuel, landing fees, in-flight meals, sales tax, crew expenses, the hourly cost of aircraft maintenance for the applicable number of flight hours, and other variable costs specifically incurred. |
(4) | There were no stock options granted in 2016. |
Share Ownership Requirements
Under our share ownership requirements for directors, each non-employee director is required to acquire and retain Common Stock having a value equal to at least five times his or her annual cash retainer.
If at any time a non-employee director does not meet his or her ownership requirement, the director must retain (1) any Common Stock owned by the director (whether owned directly or indirectly) and (2) any net shares received as the result of the exercise, vesting or payment of any equity award until the ownership requirement is met, in each case unless otherwise approved in writing by the Compensation Committee. For this purpose, “net shares” means the shares of Common Stock that remain after shares are sold or withheld, as the case may be, to (1) pay the exercise price for a stock option award or (2) satisfy any tax obligations, including withholding taxes, arising in connection with the exercise, vesting or payment of an equity award.
Compliance with these requirements is evaluated as of December 31 of each year. The value of an individual’s share ownership as of such date is determined by multiplying the number of shares of our Common Stock or other eligible equity interests held by the individual by the closing price of our stock as of the business day immediately preceding the date of determination.
Peabody Energy Corporation | 2016 Form 10-K | 121 |
For purposes of determining stock ownership levels, only the following forms of equity interests are included:
▪ | Stock owned directly (including stock or stock units held in any defined contribution plan or employee stock purchase plan and shares of restricted stock); |
▪ | Stock held by immediate family members residing in the same household or through trusts for the benefit of the person or his or her immediate family members residing in the same household; |
▪ | Unvested restricted stock or RSUs (provided that vesting is based solely on the passage of time and/or continued service with Peabody); and |
▪ | Vested and undistributed deferred stock units. |
Due to the continued decline in the market price per share of our stock, ownership requirements were not met for any of our directors as of December 31, 2016. All of our directors complied with the requirements that apply when their required stock ownership level is not met.
Compensation Committee Interlocks and Insider Participation
Messrs. Coley, James, Rusnack, and Sutherlin served on our Compensation Committee during 2016. None of these committee members is a current or former Peabody officer or employee. In addition, none of our executive officers served during 2016 as a member of the board of directors or compensation committee of any entity which has one or more executive officers serving as a member of our Board of Directors or Compensation Committee.
Compensation Committee Report
The Compensation Committee has reviewed and discussed the above section of this report entitled “Compensation Discussion and Analysis” with management. Based on such review and discussion, the Compensation Committee has recommended to the Board of Directors that the “Compensation Discussion and Analysis” be included in this report for filing with the Securities and Exchange Commission.
MEMBERS OF THE COMPENSATION COMMITTEE:
WILLIAM C. RUSNACK, CHAIR
WILLIAM A. COLEY
WILLIAM E. JAMES
MICHAEL W. SUTHERLIN
Peabody Energy Corporation | 2016 Form 10-K | 122 |
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Ownership of Company Securities
The following table sets forth information as of March 15, 2017 with respect to persons or entities who are known by the Company to beneficially own more than 5% of our outstanding Common Stock, each current director, each executive officer named in the Summary Compensation Table, and all directors and executive officers as a group.
Under the plan confirmed by the Bankruptcy Court, all of our equity securities will be canceled, including our common stock and any outstanding equity awards in respect of such equity securities, including holdings referenced in the table below, on the Plan Effective Date.
Beneficial Owners of More Than Five Percent, Directors and Management
Name and Address of Beneficial Owner(1) | Amount and Nature of Beneficial Ownership(2)(3)(4) | Percent of Class(5) | |||
William A. Coley | 2,305 | * | |||
A. Verona Dorch | 10,714 | * | |||
William E. James | 2,336 | * | |||
Robert B. Karn III | 2,612 | * | |||
Glenn L. Kellow | 7,921 | * | |||
Henry E. Lentz | 1,548 | * | |||
Robert A. Malone | 2,379 | * | |||
Charles F. Meintjes | 9,525 | * | |||
William C. Rusnack | 2,077 | * | |||
Amy B. Schwetz | 2,442 | * | |||
Michael W. Sutherlin | 333 | * | |||
John F. Turner | 1,403 | * | |||
Sandra A. Van Trease | 2,286 | * | |||
Kemal Williamson | 7,140 | * | |||
Heather A. Wilson | — | * | |||
All directors and executive officers as a group (16 people) | 61,876 | 0.33% | |||
(1) | The address for all officers and directors listed is c/o Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St. Louis, Missouri 63101. |
(2) | Beneficial ownership is determined in accordance with SEC rules and includes voting and investment power with respect to shares. Unless otherwise indicated, the persons and entities named in the table have sole voting and dispositive power with respect to all shares beneficially owned. |
(3) | Includes restricted stock that remains unvested as of March 15, 2017 as follows: Mr. Kellow, 6,459; Mr. Meintjes, 3,158; Ms. Schwetz, 1,551; Mr. Williamson, 2,153; Ms. Dorch 10,714; and all directors and executive officers as a group, 24,980. |
(4) | Excludes deferred stock units held by our non-employee directors as of March 15, 2017 as follows: Mr. Coley, 5,895; Mr. James, 5,895; Mr. Karn, 6,122; Mr. Lentz, 5,895; Mr. Malone, 5,895; Mr. Rusnack, 5,895; Mr. Sutherlin, 5,944; Mr. Turner, 5,895; Ms. Van Trease, 5,895; Dr. Wilson, 6,140; and all directors and executive officers as a group, 59,471. Excludes unvested performance units as of March 15, 2017 as follows: Mr. Kellow, 22,266; Mr. Meintjes, 5,456; Mr. Williamson, 4,960; and all directors and executive officers as a group, 32,682. Also excludes performance-based restricted stock units as of March 15, 2017 as follows: Mr. Kellow, 93,334; Mr. Meintjes, 24,445; Ms. Schwetz, 19,556; Mr. Williamson, 22,222; Ms. Dorch, 19,556; and all directors and executive officers as a group, 179,113. |
(5) | Applicable percentage ownership is based on 18,491,188 shares of common stock outstanding at March 15, 2017. An asterisk (*) indicates that the applicable person beneficially owns less than one percent of the outstanding shares. |
Peabody Energy Corporation | 2016 Form 10-K | 123 |
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, 2016:
(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 | 243,105 | (1) | $ | 451.88 | (2) | 981,573 | |||||
Equity compensation plans not approved by security holders | — | — | — | ||||||||
Total | 243,105 | $ | 451.88 | 981,573 | |||||||
(1) | Includes 55,851 shares issuable pursuant to outstanding deferred stock units and no 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 20. "Share-Based Compensation" to the accompanying consolidated financial statements for additional information regarding the material features of our current equity compensation plans.
Item 13.Certain Relationships and Related Transactions, and Director Independence.
Policy for Approval of Related Person Transactions
Under a written policy adopted by the Board of Directors, the Nominating and Corporate Governance Committee is responsible for reviewing and approving all transactions between us and certain “related persons,” such as our executive officers, directors and owners of more than 5% of our voting securities. In reviewing a transaction, the Committee considers the relevant facts and circumstances, including the benefits to us, any impact on director independence and whether the terms are consistent with a transaction available on an arms-length basis. Only those related person transactions that are determined to be in (or not inconsistent with) our best interests and the best interests of our stockholders are permitted to be approved. No committee member may participate in any review of a transaction in which the member or any of his or her family members is the related person. A copy of the policy can be found on our website (www.peabodyenergy.com) by clicking on “Investors,” then “Corporate Governance,” and then “Board of Directors Committee Charters” and is available in print to any stockholder who requests it. Information on our website is not considered part of this Form 10-K. During 2016, there were no such transactions requiring consideration by the committee.
Director Independence
As required by NYSE rules, the Board of Directors evaluates the independence of its members at least annually, and at other appropriate times when a change in circumstances could potentially impact the independence or effectiveness of one or more directors (such as in connection with a change in employment status or other significant status changes). This process is administered by the Nominating and Corporate Governance Committee, which consists entirely of directors who are independent under applicable NYSE rules. After carefully considering all relevant relationships with us, the Nominating and Corporate Governance Committee submits its recommendations regarding independence to the full Board, which then makes a determination with respect to each director.
In making independence determinations, the Nominating and Corporate Governance Committee and the Board consider all relevant facts and circumstances, including (1) the nature of any relationships with us, (2) the significance of the relationship to us, the other organization and the individual director, (3) whether or not the relationship is solely a business relationship in the ordinary course of our and the other organization’s businesses and does not afford the director any special benefits, and (4) any commercial, industrial, banking, consulting, legal, accounting, charitable and familial relationships. For purposes of this determination, the Board generally deems any relationships that have expired for more than three years to be immaterial.
After considering NYSE standards for independence and various other factors as described herein, the Board has determined that all directors other than Mr. Kellow are independent. None of the directors other than Mr. Kellow receives any compensation from us other than customary director and committee fees.
Peabody Energy Corporation | 2016 Form 10-K | 124 |
Ms. Van Trease serves as a director of a charitable organization to which we made a contribution in the normal course of our charitable contributions program. After careful consideration, the Board has determined that the contribution does not impair, or appear to impair, her independent judgment.
Item 14.Principal Accountant Fees and Services.
Fees Paid to Independent Registered Public Accounting Firm
Ernst & Young LLP served as our independent registered public accounting firm for the fiscal years ended December 31, 2016 and 2015. The following fees were paid to Ernst & Young LLP for services rendered during our last two fiscal years:
• | Audit Fees: $5,250,376 (for the fiscal year ended December 31, 2016) and $5,835,761 (for the fiscal year ended December 31, 2015) for fees associated with the annual audit of our consolidated financial statements, including the audit of internal control over financial reporting, the reviews of our quarterly reports on Form 10-Q, services provided in connection with statutory and regulatory filings or transactional requirements, assistance with and review of documents filed with the SEC and accounting and financial reporting consultations. |
• | Audit-Related Fees: $45,166, (for the fiscal year ended December 31, 2016) and $32,572 (for the fiscal year ended December 31, 2015) for assurance-related services for internal control reviews, and other attest services not required by statute. |
• | Tax Fees: $243,622 (for the fiscal year ended December 31, 2016) and $149,975 (for the fiscal year ended December 31, 2015) for tax compliance, tax advice and tax planning services. |
• | All Other Fees: $1,995 (for the fiscal year ended December 31, 2016) and $1,995 (for the fiscal year ended December 31, 2015) for fees related to an online research tool. |
Under the Board’s established procedures, the Audit Committee is required to pre-approve all audit and non-audit services performed by our independent registered public accounting firm to ensure that the provisions of such services do not impair such firm’s independence. The Audit Committee may delegate its pre-approval authority to one or more of its members, but not to management. The member or members to whom such authority is delegated must report any pre-approval decisions to the Audit Committee at its next scheduled meeting.
Each fiscal year, the Audit Committee reviews with management and the independent registered public accounting firm the types of services that are likely to be required throughout the year. Those services are comprised of four categories, including audit services, audit-related services, tax services and all other permissible services. At that time, the Audit Committee pre-approves a list of specific services that may be provided within each of these categories, and sets fee limits for each specific service or project. Management is then authorized to engage the independent registered public accounting firm to perform the pre-approved services as needed throughout the year, subject to providing the Audit Committee with regular updates. The Audit Committee regularly reviews the amount of all billings submitted by the independent registered public accounting firm to ensure their services do not exceed pre-defined limits. The Audit Committee must review and approve in advance, on a case-by-case basis, all other projects, services and fees to be performed by or paid to the independent registered public accounting firm. The Audit Committee also must approve in advance any fees for pre-approved services that exceed the pre-established limits, as described above.
Under our policy and/or applicable rules and regulations, our independent registered public accounting firm is prohibited from providing the following types of services to us: (1) bookkeeping or other services related to our accounting records or financial statements, (2) financial information systems design and implementation, (3) appraisal or valuation services, fairness opinions or contribution-in-kind reports, (4) actuarial services, (5) internal audit outsourcing services, (6) management functions, (7) human resources, (8) broker-dealer, investment advisor or investment banking services, (9) legal services, (10) expert services unrelated to audit, (11) any services entailing a contingent fee or commission (not including fees awarded by a bankruptcy court) and (12) tax services to any of our officers whose role is in a financial reporting oversight capacity (regardless of whether we or the officer pays the fee for the services).
During the fiscal years ended December 31, 2016 and 2015, all of the services described under the headings “Audit Fees,” “Audit-Related Fees,” “Tax Fees” and “All Other Fees” were approved by the Audit Committee in accordance with the procedures described above.
Peabody Energy Corporation | 2016 Form 10-K | 125 |
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 | |
F-1 | |
Consolidated Statements of Operations — Years Ended December 31, 2016, 2015 and 2014 | F-2 |
F-3 | |
F-4 | |
F-5 | |
F-7 | |
F-8 | |
(2) Financial Statement Schedules.
The following financial statement schedule of Peabody Energy Corporation is at the page indicated:
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.
Peabody Energy Corporation | 2016 Form 10-K | 126 |
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 21, 2017
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 21, 2017 | ||||
Glenn L. Kellow | ||||||
/s/ AMY B. SCHWETZ | Executive Vice President and Chief Financial Officer (principal financial and accounting officer) | March 21, 2017 | ||||
Amy B. Schwetz | ||||||
/s/ WILLIAM A. COLEY | Director | March 21, 2017 | ||||
William A. Coley | ||||||
/s/ WILLIAM E. JAMES | Director | March 21, 2017 | ||||
William E. James | ||||||
/s/ ROBERT B. KARN III | Director | March 21, 2017 | ||||
Robert B. Karn III | ||||||
/s/ HENRY E. LENTZ | Director | March 21, 2017 | ||||
Henry E. Lentz | ||||||
/s/ ROBERT A. MALONE | Chairman | March 21, 2017 | ||||
Robert A. Malone | ||||||
/s/ WILLIAM C. RUSNACK | Director | March 21, 2017 | ||||
William C. Rusnack | ||||||
/s/ MICHAEL W. SUTHERLIN | Director | March 21, 2017 | ||||
Michael W. Sutherlin | ||||||
/s/ JOHN F. TURNER | Director | March 21, 2017 | ||||
John F. Turner | ||||||
/s/ SANDRA A. VAN TREASE | Director | March 21, 2017 | ||||
Sandra A. Van Trease | ||||||
/s/ HEATHER A. WILSON | Director | March 21, 2017 | ||||
Heather A. Wilson | ||||||
Peabody Energy Corporation | 2016 Form 10-K | 127 |
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 and subsidiaries (the Company) as of December 31, 2016 and 2015, 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, 2016. 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 and subsidiaries at December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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.
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, 2016, 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 21, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
St. Louis, Missouri
March 21, 2017
Peabody Energy Corporation | 2016 Form 10-K | F- 1 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions, except per share data) | |||||||||||
Revenues | |||||||||||
Sales | $ | 4,117.9 | $ | 5,138.3 | $ | 6,132.7 | |||||
Other revenues | 597.4 | 470.9 | 659.5 | ||||||||
Total revenues | 4,715.3 | 5,609.2 | 6,792.2 | ||||||||
Costs and expenses | |||||||||||
Operating costs and expenses (exclusive of items shown separately below) | 4,107.6 | 5,007.7 | 5,716.9 | ||||||||
Depreciation, depletion and amortization | 465.4 | 572.2 | 655.7 | ||||||||
Asset retirement obligation expenses | 41.8 | 45.5 | 81.0 | ||||||||
Selling and administrative expenses | 153.4 | 176.4 | 227.1 | ||||||||
Restructuring and pension settlement charges | 15.5 | 23.5 | 26.0 | ||||||||
Other operating (income) loss: | |||||||||||
Net gain on disposal of assets | (23.2 | ) | (45.0 | ) | (41.4 | ) | |||||
Asset impairment | 247.9 | 1,277.8 | 154.4 | ||||||||
(Gain) loss from equity affiliates | (16.2 | ) | 15.9 | 107.6 | |||||||
Operating loss | (276.9 | ) | (1,464.8 | ) | (135.1 | ) | |||||
Interest expense | 298.6 | 465.4 | 426.6 | ||||||||
Loss on early debt extinguishment | 29.5 | 67.8 | 1.6 | ||||||||
Interest income | (5.7 | ) | (7.7 | ) | (15.4 | ) | |||||
Reorganization items, net | 159.0 | — | — | ||||||||
Loss from continuing operations before income taxes | (758.3 | ) | (1,990.3 | ) | (547.9 | ) | |||||
Income tax (benefit) provision | (84.0 | ) | (176.4 | ) | 201.2 | ||||||
Loss from continuing operations, net of income taxes | (674.3 | ) | (1,813.9 | ) | (749.1 | ) | |||||
Loss from discontinued operations, net of income taxes | (57.6 | ) | (175.0 | ) | (28.2 | ) | |||||
Net loss | (731.9 | ) | (1,988.9 | ) | (777.3 | ) | |||||
Less: Net income attributable to noncontrolling interests | 7.9 | 7.1 | 9.7 | ||||||||
Net loss attributable to common stockholders | $ | (739.8 | ) | $ | (1,996.0 | ) | $ | (787.0 | ) | ||
Loss from continuing operations | |||||||||||
Basic loss per share | $ | (37.30 | ) | $ | (100.34 | ) | $ | (42.52 | ) | ||
Diluted loss per share | $ | (37.30 | ) | $ | (100.34 | ) | $ | (42.52 | ) | ||
Net loss attributable to common stockholders | |||||||||||
Basic loss per share | $ | (40.45 | ) | $ | (109.98 | ) | $ | (44.09 | ) | ||
Diluted loss per share | $ | (40.45 | ) | $ | (109.98 | ) | $ | (44.09 | ) | ||
Dividends declared per share | $ | — | $ | 0.075 | $ | 5.100 | |||||
See accompanying notes to consolidated financial statements
Peabody Energy Corporation | 2016 Form 10-K | F- 2 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Net loss | $ | (731.9 | ) | $ | (1,988.9 | ) | $ | (777.3 | ) | ||
Other comprehensive income (loss), net of income taxes: | |||||||||||
Net change in unrealized losses on available-for-sale securities (net of respective tax benefit of $0.0, $0.1 and $0.5) | |||||||||||
Unrealized holding losses on available-for-sale securities | — | — | (3.7 | ) | |||||||
Reclassification for realized losses included in net loss | — | — | 2.9 | ||||||||
Net change in unrealized losses on available-for-sale securities | — | — | (0.8 | ) | |||||||
Net unrealized gains (losses) on cash flow hedges (net of respective tax provision (benefit) of $85.9, $72.2 and ($54.6)) | |||||||||||
Decrease in fair value of cash flow hedges | — | (131.3 | ) | (195.0 | ) | ||||||
Reclassification for realized losses (gains) included in net loss | 146.3 | 251.7 | (10.2 | ) | |||||||
Net unrealized gains (losses) on cash flow hedges | 146.3 | 120.4 | (205.2 | ) | |||||||
Postretirement plans and workers' compensation obligations (net of respective tax (benefit) provision of ($1.5), $36.2 and ($10.3)) | |||||||||||
Prior service (cost) credit for the period | (4.5 | ) | 10.4 | 11.4 | |||||||
Net actuarial (loss) gain for the period | (13.5 | ) | 18.1 | (142.7 | ) | ||||||
Amortization of actuarial loss and prior service cost included in net loss | 15.4 | 31.9 | 32.7 | ||||||||
Postretirement plans and workers' compensation obligations | (2.6 | ) | 60.4 | (98.6 | ) | ||||||
Foreign currency translation adjustment | (1.8 | ) | (34.9 | ) | (41.0 | ) | |||||
Other comprehensive income (loss), net of income taxes | 141.9 | 145.9 | (345.6 | ) | |||||||
Comprehensive loss | (590.0 | ) | (1,843.0 | ) | (1,122.9 | ) | |||||
Less: Comprehensive income attributable to noncontrolling interests | 7.9 | 7.1 | 9.7 | ||||||||
Comprehensive loss attributable to common stockholders | $ | (597.9 | ) | $ | (1,850.1 | ) | $ | (1,132.6 | ) | ||
See accompanying notes to consolidated financial statements
Peabody Energy Corporation | 2016 Form 10-K | F- 3 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
CONSOLIDATED BALANCE SHEETS
December 31, | |||||||
2016 | 2015 | ||||||
(Amounts in millions, except per share data) | |||||||
ASSETS | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 872.3 | $ | 261.3 | |||
Restricted cash | 54.3 | — | |||||
Accounts receivable, net of allowance for doubtful accounts of $13.1 at December 31, 2016 and $6.6 at December 31, 2015 | 473.0 | 228.8 | |||||
Inventories | 203.7 | 307.8 | |||||
Assets from coal trading activities, net | 0.7 | 23.5 | |||||
Deferred income taxes | — | 53.5 | |||||
Other current assets | 486.6 | 447.6 | |||||
Total current assets | 2,090.6 | 1,322.5 | |||||
Property, plant, equipment and mine development, net | 8,776.7 | 9,258.5 | |||||
Deferred income taxes | — | 2.2 | |||||
Investments and other assets | 910.4 | 363.7 | |||||
Total assets | $ | 11,777.7 | $ | 10,946.9 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current liabilities | |||||||
Current portion of long-term debt | $ | 20.2 | $ | 5,874.9 | |||
Liabilities from coal trading activities, net | 1.2 | 15.6 | |||||
Accounts payable and accrued expenses | 990.4 | 1,446.3 | |||||
Total current liabilities | 1,011.8 | 7,336.8 | |||||
Long-term debt, less current portion | — | 366.3 | |||||
Deferred income taxes | 17.6 | 69.1 | |||||
Asset retirement obligations | 717.8 | 686.6 | |||||
Accrued postretirement benefit costs | 756.3 | 722.9 | |||||
Other noncurrent liabilities | 496.2 | 846.7 | |||||
Total liabilities not subject to compromise | 2,999.7 | 10,028.4 | |||||
Liabilities subject to compromise | 8,440.2 | — | |||||
Total liabilities | 11,439.9 | 10,028.4 | |||||
Stockholders’ equity | |||||||
Preferred Stock — $0.01 per share par value; 10.0 shares authorized, no shares issued or outstanding as of December 31, 2016 or December 31, 2015 | — | — | |||||
Perpetual Preferred Stock — 0.8 shares authorized, no shares issued or outstanding as of December 31, 2016 or December 31, 2015 | — | — | |||||
Series Common Stock — $0.01 per share par value; 40.0 shares authorized, no shares issued or outstanding as of December 31, 2016 or December 31, 2015 | — | — | |||||
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, 2016 and December 31, 2015 | 0.2 | 0.2 | |||||
Additional paid-in capital | 2,422.0 | 2,410.7 | |||||
Treasury stock, at cost — 0.8 shares as of December 31, 2016 and December 31, 2015 | (371.8 | ) | (371.7 | ) | |||
Accumulated deficit | (1,243.2 | ) | (503.4 | ) | |||
Accumulated other comprehensive loss | (477.0 | ) | (618.9 | ) | |||
Peabody Energy Corporation stockholders’ equity | 330.2 | 916.9 | |||||
Noncontrolling interests | 7.6 | 1.6 | |||||
Total stockholders’ equity | 337.8 | 918.5 | |||||
Total liabilities and stockholders’ equity | $ | 11,777.7 | $ | 10,946.9 | |||
See accompanying notes to consolidated financial statements
Peabody Energy Corporation | 2016 Form 10-K | F- 4 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Cash Flows From Operating Activities | |||||||||||
Net loss | $ | (731.9 | ) | $ | (1,988.9 | ) | $ | (777.3 | ) | ||
Loss from discontinued operations, net of income taxes | 57.6 | 175.0 | 28.2 | ||||||||
Loss from continuing operations, net of income taxes | (674.3 | ) | (1,813.9 | ) | (749.1 | ) | |||||
Adjustments to reconcile loss from continuing operations, net of income taxes to net cash (used in) provided by operating activities: | |||||||||||
Depreciation, depletion and amortization | 465.4 | 572.2 | 655.7 | ||||||||
Noncash interest expense | 61.3 | 30.6 | 23.6 | ||||||||
Deferred income taxes | (86.5 | ) | (107.6 | ) | 231.9 | ||||||
Noncash share-based compensation | 12.8 | 28.2 | 46.8 | ||||||||
Asset impairment | 247.9 | 1,277.8 | 154.4 | ||||||||
Net gain on disposal of assets | (23.2 | ) | (45.0 | ) | (41.4 | ) | |||||
(Gain) loss from equity affiliates | (16.2 | ) | 15.9 | 107.6 | |||||||
Gain on voluntary employee beneficiary association settlement | (68.1 | ) | — | — | |||||||
Settlement of hedge positions | (25.0 | ) | (14.9 | ) | (136.9 | ) | |||||
Reclassification from other comprehensive earnings for terminated hedge contracts | 125.2 | — | — | ||||||||
Noncash reorganization items, net | 90.9 | — | — | ||||||||
Changes in current assets and liabilities: | |||||||||||
Accounts receivable | (101.3 | ) | 188.0 | 55.4 | |||||||
Change in receivable from accounts receivable securitization program | (168.5 | ) | 138.5 | (70.0 | ) | ||||||
Inventories | 104.0 | 96.2 | 104.9 | ||||||||
Net assets from coal trading activities | 8.5 | (27.3 | ) | (10.1 | ) | ||||||
Other current assets | (24.4 | ) | 14.8 | 7.7 | |||||||
Accounts payable and accrued expenses | 156.5 | (381.7 | ) | (29.2 | ) | ||||||
Restricted cash | (125.7 | ) | — | — | |||||||
Asset retirement obligations | 13.1 | 23.9 | 60.3 | ||||||||
Workers’ compensation obligations | (0.4 | ) | (4.2 | ) | 2.2 | ||||||
Accrued postretirement benefit costs | 6.3 | 18.7 | 9.6 | ||||||||
Accrued pension costs | 21.7 | 29.6 | 28.3 | ||||||||
Take-or-pay obligation settlement | (15.5 | ) | — | — | |||||||
Other, net | (7.4 | ) | (20.9 | ) | (10.7 | ) | |||||
Net cash (used in) provided by continuing operations | (22.9 | ) | 18.9 | 441.0 | |||||||
Net cash used in discontinued operations | (29.9 | ) | (33.3 | ) | (104.4 | ) | |||||
Net cash (used in) provided by operating activities | (52.8 | ) | (14.4 | ) | 336.6 | ||||||
Cash Flows From Investing Activities | |||||||||||
Additions to property, plant, equipment and mine development | (126.6 | ) | (126.8 | ) | (194.4 | ) | |||||
Changes in accrued expenses related to capital expenditures | (6.1 | ) | (9.2 | ) | (16.6 | ) | |||||
Federal coal lease expenditures | (249.0 | ) | (277.2 | ) | (276.7 | ) | |||||
Proceeds from disposal of assets, net of notes receivable | 144.4 | 70.4 | 203.7 | ||||||||
Purchases of debt and equity securities | — | (28.8 | ) | (15.1 | ) | ||||||
Proceeds from sales and maturities of debt and equity securities | — | 90.3 | 13.5 | ||||||||
Contributions to joint ventures | (309.5 | ) | (425.4 | ) | (529.8 | ) | |||||
Distributions from joint ventures | 312.4 | 422.6 | 534.2 | ||||||||
Advances to related parties | (40.4 | ) | (3.7 | ) | (33.7 | ) | |||||
Repayment of loans from related parties | 40.6 | 0.9 | 5.4 | ||||||||
Other, net | (9.9 | ) | (3.1 | ) | (5.0 | ) | |||||
Net cash used in investing activities | (244.1 | ) | (290.0 | ) | (314.5 | ) | |||||
See accompanying notes to consolidated financial statements
Peabody Energy Corporation | 2016 Form 10-K | F- 5 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Cash Flows From Financing Activities | |||||||||||
Proceeds from long-term debt | $ | 1,458.4 | $ | 975.7 | $ | 1.1 | |||||
Repayments of long-term debt | (513.7 | ) | (671.3 | ) | (21.0 | ) | |||||
Payment of deferred financing costs | (31.0 | ) | (28.7 | ) | (10.1 | ) | |||||
Dividends paid | — | (1.4 | ) | (92.3 | ) | ||||||
Restricted cash for distributions to noncontrolling interests | — | — | (42.5 | ) | |||||||
Other, net | (5.8 | ) | (6.6 | ) | (3.3 | ) | |||||
Net cash provided by (used in) financing activities | 907.9 | 267.7 | (168.1 | ) | |||||||
Net change in cash and cash equivalents | 611.0 | (36.7 | ) | (146.0 | ) | ||||||
Cash and cash equivalents at beginning of year | 261.3 | 298.0 | 444.0 | ||||||||
Cash and cash equivalents at end of year | $ | 872.3 | $ | 261.3 | $ | 298.0 | |||||
See accompanying notes to consolidated financial statements
Peabody Energy Corporation | 2016 Form 10-K | F- 6 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 Loss | Noncontrolling Interests | Total Stockholders’ Equity | |||||||||||||||||||||
(Dollars in millions) | |||||||||||||||||||||||||||
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 | ||||||||||||||||||||
Defined contribution plan share contribution | — | (1.4 | ) | 97.5 | (76.5 | ) | — | — | 19.6 | ||||||||||||||||||
Purchase of interest of noncontrolling stockholders | — | (3.5 | ) | — | — | — | (0.5 | ) | (4.0 | ) | |||||||||||||||||
Repurchase of employee common stock relinquished for tax withholding | — | — | (2.1 | ) | — | — | — | (2.1 | ) | ||||||||||||||||||
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 | ||||||||||
Net (loss) income | — | — | — | (739.8 | ) | — | 7.9 | (731.9 | ) | ||||||||||||||||||
Net unrealized gains on cash flow hedges (net of $85.9 tax provision) | — | — | — | — | 146.3 | — | 146.3 | ||||||||||||||||||||
Postretirement plans and workers' compensation obligations (net of $1.5 tax benefit) | — | — | — | — | (2.6 | ) | — | (2.6 | ) | ||||||||||||||||||
Foreign currency translation adjustment | — | — | — | — | (1.8 | ) | — | (1.8 | ) | ||||||||||||||||||
Share-based compensation for equity-classified awards | — | 11.3 | — | — | — | — | 11.3 | ||||||||||||||||||||
Repurchase of employee common stock relinquished for tax withholding | — | — | (0.1 | ) | — | — | — | (0.1 | ) | ||||||||||||||||||
Distributions to noncontrolling interests | — | — | — | — | — | (1.9 | ) | (1.9 | ) | ||||||||||||||||||
December 31, 2016 | $ | 0.2 | $ | 2,422.0 | $ | (371.8 | ) | $ | (1,243.2 | ) | $ | (477.0 | ) | $ | 7.6 | $ | 337.8 | ||||||||||
See accompanying notes to consolidated financial statements
Peabody Energy Corporation | 2016 Form 10-K | F- 7 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 and its affiliates. The Company, or Peabody, are used interchangeably to refer to Peabody Energy Corporation, to Peabody Energy Corporation and its subsidiaries, or to such subsidiaries, as appropriate to the context. Interests in subsidiaries controlled by the Company are consolidated with any outside stockholder 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. As discussed below in "Newly Adopted Accounting Standards," prior year amounts of deferred financing costs have been reclassified to conform with the new standard.
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 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 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, the United Kingdom and the U.S. (listed alphabetically). The Company’s other energy-related commercial activities include managing its coal reserve and real estate holdings and supporting the development of clean coal technologies.
Filing Under Chapter 11 of the United States Bankruptcy Code
On April 13, 2016 (the Petition Date), Peabody and a majority of its wholly owned domestic subsidiaries as well as one international subsidiary in Gibraltar (the Filing Subsidiaries, and together with Peabody, the Debtors) filed voluntary petitions for reorganization (the petitions collectively, the Bankruptcy Petitions) under Chapter 11 of Title 11 of the U.S. Code (the Bankruptcy Code) in the United States Bankruptcy Court for the Eastern District of Missouri (the Bankruptcy Court). The Company’s Australian operations and other international subsidiaries are not included in the filings. The Debtors' Chapter 11 cases (collectively, the Chapter 11 Cases) are being jointly administered under the caption In re Peabody Energy Corporation, et al., Case No. 16-42529 (Bankr. E.D. Mo.). The Debtors continue to operate their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In general, as debtors-in-possession, the Debtors are authorized under Chapter 11 to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court.
Peabody Energy Corporation | 2016 Form 10-K | F- 8 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The filings of the Bankruptcy Petitions constituted an event of default under the Company’s prepretition credit agreement as well as the indentures governing certain of the Company’s debt instruments, as further described in Note 14. "Current and Long-term Debt" to the consolidated financial statements, and all unpaid principal and accrued and unpaid interest due thereunder became immediately due and payable. Any efforts to enforce such payment obligations are automatically stayed as a result of the Bankruptcy Petitions and the creditors' rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.
Additionally, on the Petition Date, the New York Stock Exchange (NYSE) determined that Peabody’s common stock was no longer suitable for listing pursuant to NYSE regulations, and trading in the Company’s common stock was suspended. The Company's common stock began trading on the OTC Pink Sheets marketplace under the symbol BTUUQ on April 14, 2016. Following the Petition Date, the NYSE formally de-listed the Company's common stock.
In August 2016, the Company outlined a business plan intended to form the basis for its plan of reorganization, as further described below. As a result of its reorganization, the Company expects to emerge from its Chapter 11 Cases with the competitive cost structure necessary to improve its financial position and provide long-term stability for its stakeholders in the face of potentially volatile supply and demand conditions. Important aspects of the Company’s emergence business strategy include (i) a continued focus on safe, cost-disciplined mining operations and reclamation activities, (ii) maximization of the most profitable elements of its asset base and potential divesture of non-strategic assets, (iii) investment return-driven capital discipline, and (iv) a reduction of overall debt and fixed charges.
Filing of Plan of Reorganization with the Bankruptcy Court. In order to successfully emerge from the Chapter 11 Cases, the Debtors must propose and obtain confirmation from the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code. The Debtors retain the exclusive right to file a plan of reorganization until May 1, 2017, and have the exclusive right until June 30, 2017 to obtain the necessary acceptances to a plan. These periods may be extended by the Bankruptcy Court for cause. If the Debtors’ exclusivity period were to lapse, any party in interest may file a plan of reorganization for any of the Debtors.
On January 27, 2017, the Debtors filed with the Bankruptcy Court their Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, the Plan) and a related Second Amended Disclosure Statement with Respect to Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (Disclosure Statement). The Plan provides for, among other things, (1) classification and treatment of various claims and equity interests, (2) a reduction of the Company’s debt upon emergence, and (3) the recapitalization of the Company through a rights offering and private placement for equity securities of the Company. The Bankruptcy Court approved the Disclosure Statement by order entered on January 27, 2017.
The reorganization contemplated by the Plan will reduce the Debtors' debt burden by over $6.6 billion, but does not compromise existing coal mining reclamation obligations. The Plan will provide creditors with recoveries, funded in large part by a $1.95 billion first lien exit facility, a $750 million rights offering available to holders of second lien and general unsecured claims, and a $750 million private placement offering of new mandatory convertible preferred stock of the Company. Under the Plan, current holders of the Company’s equity interests will not receive any distributions, and their equity interests will be canceled once the Plan becomes effective.
The Company and various creditor constituencies entered into an agreement which serves as the cornerstone of the Plan (the Global Settlement). The Global Settlement is premised upon a consensual resolution of a number of complex issues that have been the subject of extensive and vigorous negotiations post-petition among the Debtors and holders of certain second lien notes. Under the Global Settlement, certain lenders will backstop the first lien exit facility by agreeing to take up to $1.5 billion in take-back paper in the event the Debtors are unable to raise the exit facility, subject to certain restrictions as set forth in the Plan. Similarly, holders of certain second lien notes have agreed that, at the Company's sole discretion, in partial satisfaction of their claims, they may receive $450 million in cash, $450 million of first lien debt on the same terms as the exit facility or $450 million of new second lien notes at terms and conditions set forth in the Plan. A third group of lenders and other parties have agreed to backstop the $750 million rights offering and invest through the $750 million private placement offering in order to ensure that the Company raises the $1.5 billion equity investment that will be necessary to consummate the Plan.
On January 11, 2017, the Debtors obtained an exit facility commitment letter (Exit Facility Commitment Letter) from a consortium of lenders (Lenders), pursuant to which, in connection with the consummation of the Plan, the Lenders have agreed to provide a senior secured term loan facility (Term Loan Facility) in an aggregate amount of (a) $1.5 billion, less (b) the aggregate principal amount of privately placed debt securities (Notes) of the Company, or special purpose escrow issuer, issued on or prior to the closing date of the Term Loan Facility (Closing Date), plus (c) any amount of additional senior secured term loans funded on the Closing Date at the sole discretion of the Term Loan Facility's arranging Lenders and the Company.
Peabody Energy Corporation | 2016 Form 10-K | F- 9 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The commitments of the Lenders to provide the Term Loan Facility are subject to the occurrence or waiver of all conditions precedent to the effectiveness of the Plan, other than the closing and funding of the Term Loan Facility (and the Notes issued in lieu thereof, if any). The Lenders’ commitments to provide and arrange the Term Loan Facility will terminate on a dollar-for-dollar basis to the extent of the issuance of the Notes.
On February 8, 2017, the Company announced the pricing of a $950.0 million senior secured term loan. The term loan will mature in 2022 and bears interest at a fluctuating rate of LIBOR plus 4.50% per annum, with a 1.00% LIBOR floor. The closing of the term loan is expected to occur in early April 2017, concurrently with the anticipated effective date of the Plan and subject to customary closing conditions and final documentation. The proceeds from the term loan will be used to fund a portion of the distributions to creditors provided for under the Plan.
Also on February 8, 2017, the Company announced that a special purpose wholly owned subsidiary of the Company priced an offering of $500.0 million aggregate principal amount of 6.000% senior secured notes due 2022 and $500.0 million aggregate principal amount of 6.375% senior secured notes due 2025, each exempt from the registration requirements of the Securities Act of 1933, as amended. The offering of the notes closed on February 15, 2017 at which time the net proceeds of the offering were funded into an escrow account pending the Plan Effective Date. The notes are being offered by a special purpose wholly owned subsidiary of the Company. If certain conditions are satisfied on or before August 1, 2017, the net proceeds from the offering will be released from escrow to fund a portion of the distributions to creditors provided for under the Plan, and the Company will become the obligor under the notes.
Pursuant to the Plan, the Company will use reasonable best efforts to cause the Company's common stock (Reorganized PEC Common Stock) and Preferred Equity (as defined below) to be listed on the New York Stock Exchange as soon as practicable after the Plan Effective Date.
The Plan also provides for a long-term incentive plan (the LTIP) for directors, management and other employees of the Company, including reservation of an amount of Reorganized PEC Common Stock for the LTIP.
In addition, in accordance with the Plan, a nine member Board of Directors of the Company was established (the Reorganized PEC Board). The Reorganized PEC Board is comprised of the Company’s Chief Executive Officer and eight independent directors.
On January 26, 2017, the Bankruptcy Court approved the amended Disclosure Statement, and authorized the Debtors to begin soliciting votes from creditors to approve the Plan. Subsequently, the Debtors solicited votes on the Plan. On March 15, 2017, the Debtors filed a revised version of the Plan. On March 16, 2017, the Bankruptcy Court held a hearing to determine whether the Plan should be confirmed. On March 17, 2017, the Bankruptcy Court entered an order confirming the Plan.
Although the Bankruptcy Court has confirmed the Plan, the Debtors have not yet consummated all of the transactions that are contemplated by the Plan. Rather, the Debtors intend to consummate these transactions in the near future, on or before the Plan Effective Date. As set forth in Section V.B of the Plan, there are certain conditions precedent to the occurrence of the Plan Effective Date, which must be satisfied or waived in accordance with the Plan in order for the Plan to become effective and the Debtors to emerge from the Chapter 11 Cases. The Debtors anticipate that each of these conditions will be either satisfied or waived by early April 2017, which is the target for the Debtors' emergence from the Chapter 11 Cases. On the Plan Effective Date, the Debtors will, generally, no longer be governed by the Bankruptcy Court's oversight.
Under the provisions set forth in Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court confirmed the Plan even though the Plan was not accepted by all impaired classes of claims and equity interests. The classes of claims or equity interests that will not receive or retain any property under the Plan on account of such claims or interests were deemed to have voted to reject the Plan. The precise requirements and evidentiary showing for confirming a plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests in the rejecting class (e.g., secured claims or unsecured claims, subordinated or senior claims, preferred or common stock). Generally, the Bankruptcy Court confirmed the Plan and allowed it to be “crammed down” on owners of the Company's common stock, even though the shareowners will receive no recovery under the Plan, because the Debtors demonstrated that (1) no class junior to the common stock is receiving or retaining property under the Plan and (2) no class of claims or interests senior to the common stock is being paid more than in full.
Peabody Energy Corporation | 2016 Form 10-K | F- 10 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Notices to Creditors; Effect of Automatic Stay. Shortly after the Petition Date, the Debtors began notifying all known current or potential creditors of the Chapter 11 filing. Pursuant to Section 362 of the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically stayed most actions against the Debtors, including actions to collect indebtedness incurred prior to the Petition Date or to exercise control over the Debtors’ property. Subject to certain exceptions under the Bankruptcy Code, the filing of the Debtors’ Chapter 11 Cases also automatically stayed the continuation of most legal proceedings, including certain of the third party litigation matters described in Note 26. "Commitments and Contingencies" and Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" of this report or the filing of other actions against or on behalf of the Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date or to exercise control over property of the Debtors’ bankruptcy estates, unless and until the Bankruptcy Court modifies or lifts the automatic stay as to any such claim. Notwithstanding the general application of the automatic stay described above, governmental authorities may determine to continue actions brought under their police and regulatory powers.
The automatic stay remains in place pending the occurrence of the Plan Effective Date. After the Plan Effective Date, subject to certain limited exceptions, holders of claims against the Debtors and interests in the Debtors will be bound by the discharge, release and exculpation provisions set forth in Sections V.E.2, V.E.4 and V.E.5 of the Plan and will be enjoined from taking any action against the reorganized Debtors pursuant to the injunction provisions set forth in Section V.E.3 of the Plan and paragraphs 16 through 31 of the order confirming the Plan.
Appointment of Creditors' Committee. As required by the Bankruptcy Code, the United States Trustee for the Eastern District of Missouri appointed an official committee of unsecured creditors (the Creditors' Committee) on April 29, 2016. On January 4, 2017, the United States Trustee for the Eastern District of Missouri filed a document with the Bankruptcy Court indicating that additional members had been added to the Creditors' Committee. The Creditors' Committee represents all unsecured creditors of the Debtors and has a right to be heard on all matters that come before the Bankruptcy Court. The Creditors' Committee has been generally supportive of the Debtors’ positions on various matters. After negotiations between the Creditors' Committee and the Debtors, the Debtors agreed to include the following provisions in the Plan in exchange for the Creditors' Committee's support for the Plan: (a) holders of Class 5B Claims (as defined in the Plan) will have the option to elect to receive, in lieu of receiving other distributions on such claims, their pro rata share of $75 million in cash (with recoveries capped at 50%) and (b) the cash distributable to Class 5A Claims (as defined in the Plan) will be set at $5 million. In exchange for these, and certain other, provisions, the Creditors' Committee agreed to support the Plan.
Rejection of Executory Contracts. Under Section 365 and other relevant sections of the Bankruptcy Code, the Debtors may assume, assume and assign, or reject certain executory contracts and unexpired leases, including leases of real property and mining equipment, subject to the approval of the Bankruptcy Court and certain other conditions. In general, rejection of an executory contract or unexpired lease is treated as a prepetition breach of the executory contract or unexpired lease in question and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a prepetition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases can file claims against the Debtors for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing defaults under such executory contract or unexpired lease.
Under the terms of the Plan, the Debtors will reject all of their executory contracts and unexpired leases unless the Debtors expressly provide for the assumption of any such executory contract or unexpired lease, or any such executory contract or unexpired lease is otherwise assumed pursuant to the terms of the Plan. With limited exceptions, the assumptions and rejections of the executory contracts and unexpired leases pursuant to the Plan will occur as of the Plan Effective Date.
Liabilities subject to compromise and resolution in the Chapter 11 proceedings will likely arise in the future as a result of damage claims created by the Debtors’ rejection of various executory contracts and unexpired leases. Such claims may be material (see “Magnitude of Potential Claims” below).
Impact of the Chapter 11 Cases on Certain Leases. The Company leases equipment and facilities under various noncancelable lease agreements. Certain lease agreements were subject to the restrictive covenants of the 2013 Credit Facility 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. In relation to the Company's non-debtor subsidiaries, the Company is in various stages of negotiating stand-still arrangements with some lessors confirming the lessor will not exercise those rights. The Company does not currently believe it is probable the lessors will exercise those rights for the non-debtor subsidiaries. The lessors' rights related to the Debtor subsidiaries were automatically stayed as a result of the filing of the Chapter 11 Cases. As of December 31, 2016, the Company had approximately $189 million of remaining commitments under these non-debtor lease arrangements.
Peabody Energy Corporation | 2016 Form 10-K | F- 11 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Adequate Protection. The Debtors were required to make adequate protection payments subsequent to the Petition Date to certain secured lenders and other parties in accordance with Section 502(b)(2) of the Bankruptcy Code in order to continue using the assets comprising collateral under the Debtors’ first lien debt and because of the priming liens granted to the DIP Lenders, as defined in Note 14. "Current and Long-term Debt". Such payments are included in interest expense in the accompanying consolidated statements of operations.
Magnitude of Potential Claims. The Debtors filed with the Bankruptcy Court schedules and statements of financial affairs setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules were not prepared in accordance with generally accepted accounting principles and are subject to amendment or modification.
Bankruptcy Rule 3003(c)(3) requires the Bankruptcy Court to set the time within which proofs of claim must be filed in a Chapter 11 case. The Bankruptcy Court established August 19, 2016 (the Bar Date) as the last date and time for each person or entity to file a proof of claim against the Debtors. The Bankruptcy Court also established October 11, 2016, as the last date for governmental units to file a proof of claim against the Debtors. Subject to certain exceptions, the Bar Date applies to all claims against the Debtors that arose prior to the Petition Date.
As of March 20, 2017, nearly 7,000 claims had been filed with the Bankruptcy Court against the Debtors, and new and amended claims are expected to be filed in the future, including claims amended to assign values to claims originally filed with no designated value. Management has identified, and expects to continue to identify, many claims that it believes should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. The Bankruptcy Court has disallowed certain claims and has not yet ruled on other objections to claims. Management expects to continue to file objections in the future. Because the process of analyzing and objecting to claims will be ongoing, the number of disallowed claims may increase significantly in the future.
Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In light of the substantial number and amount of claims filed, the claims resolution process may take considerable time to complete, and management expects that it will continue after emergence from Chapter 11. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor is the exact recovery with respect to allowed claims presently known.
Costs of Reorganization. The Company has incurred and will continue to incur significant costs associated with reorganization. The amount of these costs, which are being expensed as incurred, are expected to significantly affect the Company’s results of operations. For additional information, see Note 2. “Reorganization Items, Net".
Effect of Filing on Creditors and Equity Holders. Under the priority structure established by the Bankruptcy Code, unless creditors agree otherwise, prepetition claims and post-petition claims must be satisfied in full before equity holders are entitled to receive any distribution or retain any property under a plan of reorganization. Under the Plan, current holders of Peabody common stock will not retain or receive any property, and the common stock, and other Peabody equity interests, will be canceled upon the Plan Effective Date. As discussed above (see “Filing of Plan of Reorganization with the Bankruptcy Court”), because the Plan satisfied the requirements of Section 1129(b) of the Bankruptcy Code, the Plan was confirmed notwithstanding its rejection by the holders of Peabody common stock and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan.
Newly Adopted Accounting Standards
Going Concern. In August 2014, the Financial Accounting Standards Board (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 is 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 12 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company is currently operating its business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, has incurred net losses for the years ended 2016, 2015 and 2014, and had an accumulated deficit as of December 31, 2016 and 2015. These conditions raise substantial doubt about the Company's ability to continue for one year from the date these financial statements are issued. However, the Bankruptcy Court entered an order confirming the Plan on March 17, 2017 and the Company's current projections, based on the confirmed Plan, indicate that it is probable the Company will have sufficient liquidity to meet its obligations as they become due within one year after the date of this report. The confirmed Plan provides for the elimination of the Company's existing debt outstanding at December 31, 2016, which is discussed in Note 14. "Current and Long-term Debt." The Company's projections include the debt issued and planned equity issuance as part of its restructuring which are discussed above in “Filing of Plan of Reorganization with the Bankruptcy Court." Given the Plan confirmation on March 17, 2017, management believes it is probable the Plan will become effective and consummated in early April 2017, and emergence from the Chapter 11 Cases will occur at that time. There are certain substantial conditions precedent for the confirmed Plan to become effective and legally binding. Management believes it is probable these conditions precedent to the Plan effective date will be satisfied or waived by the Company’s targeted emergence date in early April 2017. Based on the confirmation of the Plan and the Company's financial projections, management believes it is probable the conditions that raise substantial doubt about its ability to continue as a going concern have been alleviated.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business, the likelihood of which has been increased by the Bankruptcy Court’s confirmation of the Company’s Plan and the Company's ability to obtain exit financing, but is contingent on the Company’s ability to successfully consummate the Plan and maintain sufficient liquidity, among other factors. As a result of the Bankruptcy Petitions, the realization of assets and the satisfaction of liabilities are subject to uncertainty. If the Plan were not to become effective and the Company continued to operate as debtors-in-possession under Chapter 11, the Company may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Plan is expected to materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should the Company be unable to continue as a going concern or as a consequence of the Bankruptcy Petitions.
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. 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 became effective retrospectively for interim and annual periods beginning after December 15, 2015 (January 1, 2016 for the Company). There was no material impact to the Company's results of operations or cash flows in connection with the adoption of the guidance.
The impact to the Company's consolidated balance sheets as of December 31, 2015 was as follows:
Before Application of Accounting Guidance | Adjustment | After Application of Accounting Guidance | ||||||||||
(Dollars in millions) | ||||||||||||
Other current assets | $ | 503.1 | $ | (55.5 | ) | $ | 447.6 | |||||
Investments and other assets | 382.6 | (18.9 | ) | 363.7 | ||||||||
Total assets | 11,021.3 | (74.4 | ) | 10,946.9 | ||||||||
Current portion of long-term debt | 5,930.4 | (55.5 | ) | 5,874.9 | ||||||||
Long-term debt, less current portion | 385.2 | (18.9 | ) | 366.3 | ||||||||
Total liabilities | 10,102.8 | (74.4 | ) | 10,028.4 | ||||||||
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 elected early adoption of this guidance effective December 31, 2016 on a prospective basis. There was no material impact to the Company's results of operations, financial condition, cash flows or financial statement presentation in connection with the adoption of the guidance.
Peabody Energy Corporation | 2016 Form 10-K | F- 13 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Compensation - Stock Compensation. In March 2016, the FASB issued accounting guidance which identifies areas for simplification involving several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, an option to recognize gross stock compensation expense with actual forfeitures recognized as they occur, as well as certain classifications on the statement of cash flows. The new guidance will be effective prospectively for annual periods beginning after December 15, 2016 and interim periods therein, with early adoption permitted. The Company elected early adoption of this guidance effective December 31, 2016. There was no material impact to the Company's results of operations, financial condition, cash flows or financial statement presentation in connection with the adoption of the guidance.
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 would have been effective for interim and annual periods beginning after December 15, 2016 (January 1, 2017 for the Company). On July 9, 2015, the FASB delayed the effective date of the new revenue recognition standard by one year (January 1, 2018 for the Company) 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. While the Company is in the process of evaluating the impact that the adoption of this guidance will have on its financial statement presentation, its preliminary assessment is that it will not have a material impact on its results of operations, financial condition or cash flows.
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. While the Company is finalizing its evaluation of the impact that the adoption of this guidance will have, it does not expect a material impact to its results of operations, financial condition, cash flows and financial statement presentation.
Lease Accounting. In February 2016, the FASB issued accounting guidance that will require a lessee to recognize in its 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 December 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.
Financial Instruments - Credit Losses. In June 2016, the FASB issued accounting guidance related to the measurement of credit losses on financial instruments. The pronouncement replaces the incurred loss methodology to record credit losses with a methodology that reflects the expected credit losses for financial assets not accounted for at fair value with gains and losses recognized through net income. This standard is effective for fiscal years beginning after December 15, 2019 (January 1, 2020 for the Company) and interim periods therein,with early adoption permitted for fiscal years, and interim periods therein, beginning after December 15, 2018. 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 14 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued accounting guidance to amend the classification of certain cash receipts and cash payments in the statement of cash flows to reduce diversity in practice. The new guidance will be effective for fiscal years beginning after December 15, 2017 (January 1, 2018 for the Company) and interim periods therein, with early adoption permitted. The amendments in this update should be applied retrospectively to all periods presented, unless deemed impracticable, in which case, prospective application is permitted. The Company is currently evaluating this guidance and its impact on classification of certain cash receipts and cash payments in the Company's statements of cash flows.
Restricted Cash. In November 2016, the FASB issued accounting guidance which will reduce diversity in the presentation of restricted cash and restricted cash equivalents in the statement of cash flows. The new guidance will be effective retrospectively for fiscal years beginning after December 15, 2017 (January 1, 2018 for the Company) and interim periods therein, with early adoption permitted. The Company is currently evaluating this guidance and its impact, if any, on the Company's statements of cash flows.
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 9. "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 5. "Discontinued Operations" for additional details related to discontinued operations.
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.
Peabody Energy Corporation | 2016 Form 10-K | F- 15 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 impairment losses were recorded during the years ended December 31, 2016 and 2015. Refer to Note 4. "Asset Impairment" for details regarding other-than-temporary impairment losses of $4.7 million recognized during the year ended December 31, 2014 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 2016, 2015 and 2014 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.
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 | 3 to 34 | ||
Machinery and equipment | 3 to 34 | ||
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 “(Gain) 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 16 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 4. "Asset Impairment" and Note 7. "Investments" for details regarding other-than-temporary impairment losses of $276.5 million recorded during the year ended December 31, 2015 related to certain of the Company's equity and cost method investments. No such impairment losses were recorded during the years ended December 31, 2016 or 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 and regulations 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.
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.
Peabody Energy Corporation | 2016 Form 10-K | F- 17 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 17. "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 18. "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 market 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 Company's consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014 were aggregate restructuring charges of $15.5 million, $23.5 million and $26.0 million, respectively, primarily associated with voluntary and involuntary workforce reductions. The majority of the cash expenditures associated with the charges recognized in 2016 were paid in 2016.
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 8. "Derivatives and Fair Value Measurements" and Note 9. "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.
Peabody Energy Corporation | 2016 Form 10-K | F- 18 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 as a triggering event for conducting impairment tests because of historic price volatility. However, the Company generally does view a sustained trend of depressed coal 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.
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 4. "Asset Impairment" for details regarding impairment charges related to long-lived assets of $247.9 million, $1,001.3 million and $149.7 million recognized during the years ended December 31, 2016, 2015 and 2014, 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 19 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 $7.4 million, $6.4 million and $1.3 million for the years ended December 31, 2016, 2015 and 2014, respectively.
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 stockholder 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 $1.8 million, $34.9 million and $41.0 million for the years ended December 31, 2016, 2015 and 2014, 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 20. "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.
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
These consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP). In doing so, estimates and assumptions are made that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates are based on historical experience and on various other assumptions deemed reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The Company's actual results may differ materially from these estimates. Significant estimates inherent in the preparation of these consolidated financial statements include, but are not limited to, accounting for sales and cost recognition, postretirement benefit plans, environmental receivables and liabilities, asset retirement obligations, evaluation of long-lived assets for impairment, income taxes including deferred tax assets, fair value measurements and contingencies.
Peabody Energy Corporation | 2016 Form 10-K | F- 20 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(2) Reorganization Items, Net
In accordance with Accounting Standards Codification 852, "Reorganizations," the statement of operations shall portray the results of operations of the reporting entity during the pendency of the Chapter 11 Cases. Revenues, expenses (including professional fees), realized gains and losses, and provisions for losses resulting from reorganization and restructuring of the business shall be reported separately as "reorganization items".
The Company's reorganization items for the year ended December 31, 2016 consisted of the following:
Year Ended | ||||
December 31, 2016 | ||||
(Dollars in millions) | ||||
Professional fees | $ | 88.4 | ||
Loss on termination of derivative contracts | 75.2 | |||
Accounts payable settlement gains | (1.8 | ) | ||
Interest income | (1.8 | ) | ||
Other | (1.0 | ) | ||
Reorganization items, net | $ | 159.0 | ||
As a result of filing the Bankruptcy Petitions, counterparties to certain derivative contracts terminated the agreements shortly thereafter in accordance with their contractual terms and the Company adjusted the corresponding liabilities to be equivalent to the termination value and allowed claim amount of each contract. Such liabilities are considered first lien debt and are included within "Liabilities subject to compromise" in the accompanying consolidated balance sheet at December 31, 2016.
Professional fees are only those that are directly related to the reorganization including, but not limited to, fees associated with advisors to the Debtors, the Creditors' Committee and certain secured and unsecured creditors.
Interest income reflects interest earned due to the preservation of cash as a result of the automatic stay pursuant to Section 362 of the Bankruptcy Code.
During the year ended December 31, 2016, $68.1 million of cash payments were made for "Reorganization items, net".
(3) Liabilities Subject to Compromise
Liabilities subject to compromise include unsecured or under-secured liabilities incurred prior to the Petition Date. These liabilities represent the amounts expected to be allowed on known or potential claims to be resolved through the Chapter 11 Cases and remain subject to future adjustments based on negotiated settlements with claimants, actions of the Bankruptcy Court, rejection of executory contracts, proofs of claims or other events. Additionally, liabilities subject to compromise also include certain items that may be assumed under a plan of reorganization, and as such, may be subsequently reclassified to liabilities not subject to compromise. Generally, actions to enforce or otherwise effect payment of prepetition liabilities are subject to the automatic stay or an approved motion of the Bankruptcy Court, as discussed in Note 1. "Summary of Significant Accounting Policies".
Peabody Energy Corporation | 2016 Form 10-K | F- 21 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Liabilities subject to compromise consisted of the following:
Previously Reported Balance Sheet Line | December 31, 2016 | |||
(Dollars in millions) | ||||
Debt (1) | $ | 8,080.3 | ||
Interest payable | 172.6 | |||
Environmental liabilities | 61.9 | |||
Trade payables | 58.4 | |||
Postretirement benefit obligations (2) | 34.6 | |||
Other accrued liabilities | 32.4 | |||
Liabilities subject to compromise | $ | 8,440.2 | ||
(1) | Includes $7,771.2 million of first lien, second lien and unsecured debt, $257.3 million of derivative contract terminations, and $51.8 million of liabilities secured by prepetition letters of credit. |
(2) | Includes liabilities for unfunded non-qualified pension plans, all the participants of which are former employees. |
(4) | Asset Impairment |
Year Ended December 31, 2016
The following costs are reflected in "Asset impairment" in the consolidated statement of operations for the year ended December 31, 2016:
Reportable Segment | ||||||||||||
Australian Metallurgical Mining | Corporate and Other | Consolidated | ||||||||||
(Dollars in millions) | ||||||||||||
Asset impairment charges | $ | 193.2 | $ | 54.7 | $ | 247.9 | ||||||
Australian Metallurgical Mining
On November 3, 2016, Peabody Australia Mining Pty Ltd, one of the Company’s Australian subsidiaries, entered into a definitive share sale and purchase agreement (SPA) for the sale of all of its equity interest in Metropolitan Collieries Pty Ltd, the entity that owns the Metropolitan mine in New South Wales, Australia and the associated interest in the Port Kembla Coal Terminal, to a subsidiary of South32 Limited (South32). Pursuant to the SPA, the Company will receive cash consideration of $200 million, subject to a customary working capital adjustment. The transaction also includes contingent consideration that enables the Company to share equally with South32 in any revenue above an agreed metallurgical coal price forward curve, after taxes, royalties and appropriate discounts, on all coal sold for the 12 months following completion of the transaction, subject to extension if a minimum amount of coal is not sold during that period. The closing of the transaction is conditional on receipt of approval from the Australian Competition and Consumer Commission (the ACCC). On February 22, 2017, the ACCC issued a Statement of Issues relating to the transaction, noting that the ACCC is continuing to review the transaction. On February 24, 2017, pursuant to its right under the SPA, South32 extended the CP End Date (as defined in the SPA) from March 3, 2017 to April 17, 2017. On March 21, 2017, the ACCC notified the Company that it has extended the date on which it intends to render its decision regarding the transaction to April 27, 2017, which date extends beyond the CP End Date. As a result, the Company is assessing its options under the SPA.
The Company determined that, as a result of entering into the transaction, and the approval of the Company’s Board of Directors of such a transaction in October 2016, the Metropolitan mine was deemed to meet held-for-sale accounting criteria in the fourth quarter of 2016. Accordingly, the Company recorded an after-tax impairment charge of $193.2 million to write down the assets to their estimated selling price, which is the best estimate of fair value under a held-for-sale accounting model.
Peabody Energy Corporation | 2016 Form 10-K | F- 22 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Corporate and Other
During a 2016 review of its asset portfolio and prepetition leases, the Company identified certain non-strategic Midwestern coal reserves held under lease that were determined to be uneconomical to be mined in the future. As a result, the Company rejected certain leases and recognized an aggregate impairment charge of $37.5 million. The Company also recognized a $17.2 million impairment charge to record at fair value certain non-strategic Australian metallurgical assets classified as held for sale. For additional information regarding those divested assets, refer to Note 22. "Resource Management, Acquisitions and Other Commercial Events".
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 as an indicator of impairment. However, the Company generally views a sustained trend (for example, over periods exceeding one year) of adverse coal pricing or unfavorable changes thereto as a potential indicator of impairment. Because of the volatile and cyclical nature of coal prices and demand, it is reasonably possible that coal prices 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.
The Company's assets whose recoverability and values are most sensitive to near-term pricing include certain Australian metallurgical and thermal assets 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. These assets had an aggregate carrying value of $1,407.3 million as of December 31, 2016. The Company conducted a review of those assets for recoverability as of December 31, 2016 and determined that, other than the charges described above, no further impairment charge was necessary as of that date.
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
Due to the severity of the decline in seaborne metallurgical and thermal coal pricing observed during 2015 and other adverse supply and demand conditions noted during the year that drove an unfavorable change in the expected timing of eventual seaborne supply and demand 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 | 2016 Form 10-K | F- 23 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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.
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 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 stockholders’ 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 to Middlemount which have seniority over the fully impaired Subordinated Loans. The Priority Loans amounted to $84.8 million and $65.2 million at December 31, 2016 and 2015, respectively, and were not impaired as of December 31, 2016 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.
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 | ||||||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 24 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.
(5) Discontinued Operations
Discontinued operations include certain 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).
Summarized Results of Discontinued Operations
Results from discontinued operations were as follows during the years ended December 31, 2016, 2015 and 2014:
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(Dollars in millions) | ||||||||||||
Loss from discontinued operations before income taxes | $ | (57.6 | ) | $ | (182.2 | ) | $ | (23.8 | ) | |||
Income tax benefit (provision) | — | 7.2 | (4.4 | ) | ||||||||
Loss from discontinued operations, net of income taxes | $ | (57.6 | ) | $ | (175.0 | ) | $ | (28.2 | ) | |||
There were no significant revenues from discontinued operations during the years ended December 31, 2016, 2015 and 2014.
Peabody Energy Corporation | 2016 Form 10-K | F- 25 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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, | ||||||||
2016 | 2015 | |||||||
(Dollars in millions) | ||||||||
Assets: | ||||||||
Other current assets | $ | 0.2 | $ | 3.1 | ||||
Investments and other assets | 15.9 | 13.2 | ||||||
Total assets classified as discontinued operations | $ | 16.1 | $ | 16.3 | ||||
Liabilities: | ||||||||
Accounts payable and accrued expenses | $ | 55.9 | $ | 60.0 | ||||
Other noncurrent liabilities | 198.5 | 203.7 | ||||||
Liabilities subject to compromise | 20.9 | — | ||||||
Total liabilities classified as discontinued operations | $ | 275.3 | $ | 263.7 | ||||
Patriot-Related Matters. Included in "Loss from discontinued operations, net of income taxes" for the year ended December 31, 2016, is a charge of $54.3 million for the UMWA 1974 Pension Plan related to the settlement of litigation. Refer to Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" for information surrounding charges recorded during the years ended December 31, 2016 and 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 from discontinued operations, net of income taxes" for the year ended December 31, 2015 is a $9.7 million charge related to the settlement of that litigation. In September 2016, a settlement was reached under which the Company agreed to pay $13.0 million Australian dollars ($9.9 million USD) to QBH in a full and final settlement of all claims each party had against the other in relation to the CPSA litigation. Refer to Note 26. "Commitments and Contingencies" for additional information surrounding the QBH matter.
(6) | Inventories |
Inventories as of December 31, 2016 and December 31, 2015 consisted of the following:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
Materials and supplies | $ | 104.5 | $ | 115.9 | |||
Raw coal | 29.6 | 75.9 | |||||
Saleable coal | 69.6 | 116.0 | |||||
Total | $ | 203.7 | $ | 307.8 | |||
Materials and supplies inventories presented above have been shown net of reserves of $5.6 million and $4.7 million as of December 31, 2016 and 2015, respectively.
Peabody Energy Corporation | 2016 Form 10-K | F- 26 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(7) | Investments |
Investments in Marketable Securities
Investments in available-for-sale securities were liquidated prior to December 31, 2015. Proceeds from sales and maturities of available-for-sale debt securities amounted to $90.3 million and $13.5 million for the years ended December 31, 2015 and 2014, respectively. The Company realized zero net gains associated with those sales and maturities during the years ended December 31, 2015 and 2014.
Equity Method Investments
The Company’s equity method investments include its joint venture interest in Middlemount 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 (income) loss from equity affiliates:
Book Value at December 31, | (Income) Loss from Equity Affiliates for the Year Ended December 31, | ||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2014 | |||||||||||||||
(Dollars in millions) | |||||||||||||||||||
Equity interest in Middlemount Coal Pty Ltd | $ | — | $ | — | $ | (22.6 | ) | $ | 7.0 | $ | 98.5 | ||||||||
Other equity method investments | 0.5 | 1.5 | 6.4 | 8.9 | 9.1 | ||||||||||||||
Total equity method investments | $ | 0.5 | $ | 1.5 | $ | (16.2 | ) | $ | 15.9 | $ | 107.6 | ||||||||
During the years ended December 31, 2016, 2015 and 2014, Middlemount generated revenues of approximately $183 million, $160 million and $165 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 the year ended December 31, 2015. Refer to Note 4. "Asset Impairment" for additional background surrounding the impairment charge recognized in 2015. At December 31, 2016, the Company had priority loans related to Middlemount with a carrying value of $84.8 million reflected in "Investments and other assets". Refer to Note 10. "Financing Receivables" for additional background on the Company's loans with Middlemount as of December 31, 2016.
In 2014, the Company recorded to "(Gain) 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, 2016 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 $47.3 million, $263.4 million, $363.5 million and $50.3 million, respectively, as of December 31, 2016 and $31.7 million, $348.0 million, $362.2 million and $10.5 million, respectively, as of December 31, 2015 (on a 50% basis).
In addition to its equity method investment, the Company periodically makes loans to Middlemount pursuant to the related stockholders' agreement. Refer to Note 10. "Financing Receivables" for additional details surrounding those loans.
Peabody Energy Corporation | 2016 Form 10-K | F- 27 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(8) | Derivatives and Fair Value Measurements |
Risk Management — Corporate Hedging 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 coal produced by, and diesel fuel 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 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 have historically been used to manage the Company's risk exposure to foreign currency exchange rate risk, primarily on Australian dollar expenditures made in its Australian mining platform. This risk was historically 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 has also used derivative instruments to manage its exposure to the variability of diesel fuel prices used in production in the U.S. and Australia with swaps or options, which it has also designated as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted diesel fuel purchases. These risk management activities are collectively referred to as "Corporate Hedging" and are actively monitored for compliance with the Company's risk management policies.
During the fourth quarter of 2015, the Company performed an assessment of its risk of nonperformance with respect to derivative financial instruments designated as cash flow hedges in light of 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 conclude, as of December 31, 2015, that its hedging relationships were expected to be "highly effective" at offsetting the changes in the anticipated exposure of the hedged item. Therefore, the Company discontinued the application of cash flow hedge accounting subsequent to December 31, 2015 and changes in the fair value of derivative instruments have been recorded as operating costs and expenses in the accompanying consolidated statements of operations after that date. Previous fair value adjustments recorded in "Accumulated other comprehensive loss" were frozen until the underlying transactions impact the Company's earnings.
The Company's Bankruptcy Petitions constituted an event of default under the Company's derivative financial instrument contracts and the counterparties terminated the agreements shortly thereafter in accordance with contractual terms. The terminated positions are first-lien obligations under the Company's secured credit agreement dated September 24, 2013 (as amended, the 2013 Credit Facility). The resulting net settlement liability of $257.3 million was accounted for as a prepetition liability subject to compromise without credit valuation adjustments. As of December 31, 2016, the Company had no derivative financial instruments in place in relation to diesel fuel or foreign currency exchange rate. The Company is reevaluating its future Corporate Hedging activities and programs.
Based on the previous fair value adjustments of the Company's foreign currency and diesel fuel hedge contracts recorded in "Accumulated other comprehensive loss", the net loss expected to be reclassified from comprehensive income to earnings over the next 12 months is approximately $93 million (which excludes the impact of fresh start reporting rules in connection with emergence from the Chapter 11 Cases).
Peabody Energy Corporation | 2016 Form 10-K | F- 28 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 Corporate Hedging derivatives during the years ended December 31, 2016, 2015 and 2014:
Year Ended December 31, 2016 | ||||||||||||||
Income Statement Classification Losses - Realized | Total realized loss recognized in income | Loss reclassified from other comprehensive income into income (1) | (Loss) gain recognized in income on derivatives | |||||||||||
Financial Instrument | ||||||||||||||
(Dollars in millions) | ||||||||||||||
Commodity swap contracts | Operating costs and expenses | $ | (98.0 | ) | $ | (86.1 | ) | $ | (11.9 | ) | ||||
Commodity swap contracts | Reorganization items, net | (38.8 | ) | — | (38.8 | ) | ||||||||
Foreign currency forward contracts | Operating costs and expenses | (142.9 | ) | (145.6 | ) | 2.7 | ||||||||
Foreign currency forward contracts | Reorganization items, net | (36.4 | ) | — | (36.4 | ) | ||||||||
Total | $ | (316.1 | ) | $ | (231.7 | ) | $ | (84.4 | ) | |||||
(1) | Includes the reclassification from "Accumulated other comprehensive loss" into earnings of $13.6 million and $9.0 million of previously unrecognized losses on foreign currency and fuel contracts, respectivley, monetized in first quarter of 2016. |
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) | Loss reclassified from other comprehensive income into income (ineffective portion) | |||||||||||
Financial Instrument | ||||||||||||||
(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 | ||||||||||||||
(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. |
Cash Flow Presentation. The Company classifies the cash effects of its Corporate Hedging derivatives within the "Cash Flows From Operating Activities" section of the consolidated statements of cash flows.
Peabody Energy Corporation | 2016 Form 10-K | F- 29 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Offsetting and Balance Sheet Presentation
The Company's previous Corporate Hedging derivative financial instruments were 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 offset its Corporate Hedging asset and liability derivative positions on a counterparty-by-counterparty basis in the 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 Corporate Hedging derivatives existed at the overall counterparty level across its foreign currency and diesel fuel hedging strategy derivative contract portfolios, the Company's accounting policy is to apply counterparty offsetting separately within those derivative contract portfolios for presentation in the consolidated balance sheets because that application is more consistent with the fact that the Company generally net settled its Corporate Hedging derivatives with each counterparty by derivative contract portfolio on a routine basis.
The classification and amount of Corporate Hedging derivative financial instruments presented on a gross and net basis as of December 31, 2015 are presented in the table that follows.
Fair Value of Liabilities Presented in the Consolidated Balance Sheet as of December 31, 2015 (1) | |||
Financial Instrument | |||
(Dollars in millions) | |||
Current Liabilities: | |||
Commodity swap contracts | $ | 86.1 | |
Foreign currency forward contracts | 145.6 | ||
Total | $ | 231.7 | |
Noncurrent Liabilities: | |||
Commodity swap contracts | $ | 37.6 | |
Foreign currency forward contracts | 55.1 | ||
Total | $ | 92.7 | |
(1) | All commodity swap contracts and foreign currency forward contracts were in a liability position as of December 31, 2015. |
See Note 9. "Coal Trading" for information on balance sheet offsetting related to the Company’s coal trading activities.
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 | ) | |||||
Peabody Energy Corporation | 2016 Form 10-K | F- 30 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As of December 31, 2016, the Company no longer had any outstanding financial positions.
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:
• | Commodity swap contracts: 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, then the Company classifies such contracts as Level 3. |
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, 2016 | ||||||||||||
Commodity Contracts | Foreign Currency Contracts | Total | ||||||||||
(Dollars in millions) | ||||||||||||
Beginning of period | $ | 123.7 | $ | 200.7 | $ | 324.4 | ||||||
Total net losses realized/unrealized: | ||||||||||||
Included in earnings | 15.7 | (48.0 | ) | (32.3 | ) | |||||||
Settlements / terminations | (139.4 | ) | (152.7 | ) | (292.1 | ) | ||||||
End of period | $ | — | $ | — | $ | — | ||||||
The Company had no transfers between Levels 1, 2 and 3 during the years ended December 31, 2016 or 2015. 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.
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, 2016 and 2015:
• | Cash and cash equivalents, restricted cash, 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 estimated fair value of the Company’s current and long-term debt as of December 31, 2016 is subject to compromise in connection with the Company's Plan and as such has been excluded from the table below. The carrying amount and estimated fair value of the Company's current and long-term debt as of December 31, 2015 are summarized as follows:
December 31, 2015 | |||||||
Carrying Amount | Estimated Fair Value | ||||||
(Dollars in millions) | |||||||
Current and Long-term debt | $ | 6,241.2 | $ | 1,373.7 | |||
(9) | 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 31 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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, 2016, 2015 and 2014 were as follows:
Year Ended December 31, | ||||||||||||
Trading Revenues by Type of Instrument | 2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | ||||||||||||
Commodity futures, swaps and options | $ | (96.5 | ) | $ | 107.3 | $ | 92.3 | |||||
Physical commodity purchase/sale contracts | 85.6 | (64.5 | ) | (33.9 | ) | |||||||
Total trading revenues | $ | (10.9 | ) | $ | 42.8 | $ | 58.4 | |||||
Risk Management
Hedge Ineffectiveness. In some instances prior to 2016, the Company 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 as of December 31, 2016 and 2015.
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 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."
Peabody Energy Corporation | 2016 Form 10-K | F- 32 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The fair value of assets and liabilities from coal trading activities presented on a gross and net basis as of December 31, 2016 and 2015 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, 2016 | ||||||||||||||||
Assets from coal trading activities, net | $ | 191.2 | $ | (190.5 | ) | $ | — | $ | 0.7 | |||||||
Liabilities from coal trading activities, net | (249.1 | ) | 190.5 | 57.4 | (1.2 | ) | ||||||||||
Total, net | $ | (57.9 | ) | $ | — | $ | 57.4 | $ | (0.5 | ) | ||||||
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 | |||||||
(1) | None of the net variation margin (held) posted at December 31, 2016 and 2015, respectively, related to cash flow hedges. |
See Note 8. "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, 2016 and 2015:
December 31, 2016 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(Dollars in millions) | |||||||||||||||
Commodity futures, swaps and options | $ | — | $ | (0.1 | ) | $ | — | $ | (0.1 | ) | |||||
Physical commodity purchase/sale contracts | — | 0.7 | (1.1 | ) | (0.4 | ) | |||||||||
Total net financial assets (liabilities) | $ | — | $ | 0.6 | $ | (1.1 | ) | $ | (0.5 | ) | |||||
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 assets (liabilities) | $ | — | $ | 23.5 | $ | (15.6 | ) | $ | 7.9 | ||||||
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:
• | 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) 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 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. |
Peabody Energy Corporation | 2016 Form 10-K | F- 33 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Physical 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 2016 and 2015, the credit valuation adjustments as of December 31, 2016 and 2015 are considered to be significant unobservable inputs in the valuation of the contracts resulting in Level 3 classification.
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. Decreases in the number of third-party brokers or market liquidity could erode the quality of market information and therefore the valuation of the Company's 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 purchase/sale contracts classified as Level 3 as of December 31, 2016:
Range | Weighted | ||||||||
Input | Low | High | Average | ||||||
Quality adjustments | 2 | % | 2 | % | 2 | % | |||
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.
The following table summarizes the changes in the Company’s recurring Level 3 net financial assets:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Beginning of period | $ | (15.6 | ) | $ | 2.1 | $ | 2.1 | ||||
Transfers into Level 3 | 5.3 | (4.4 | ) | — | |||||||
Transfers out of Level 3 | (0.4 | ) | — | — | |||||||
Total gains realized/unrealized: | |||||||||||
Included in earnings | (2.4 | ) | (10.1 | ) | 6.7 | ||||||
Purchases | — | (0.5 | ) | — | |||||||
Sales | — | (0.1 | ) | — | |||||||
Settlements | 12.0 | (2.6 | ) | (6.7 | ) | ||||||
End of period | $ | (1.1 | ) | $ | (15.6 | ) | $ | 2.1 | |||
The Company had no transfers between Levels 1 and 2 during the years ended December 31, 2016, 2015 or 2014, Transfers of liabilities into/out of Level 3 from/to Level 2 during the years ended December 31, 2016 and 2015 were due to the relative value of unobservable inputs to the total fair value measurement of certain derivative contracts falling below, or in the case of transfers in, rising above, the 10% threshold. There were no transfers of liabilities into/out of Level 3 from/to Level 2 during the year ended December 31, 2014. The Company’s policy is to value all transfers between levels using the beginning of period valuation.
Peabody Energy Corporation | 2016 Form 10-K | F- 34 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Changes in unrealized (losses) gains (1) | $ | — | $ | (6.2 | ) | $ | 2.1 | ||||
(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, 2016, the estimated future realization of the value of the Company’s trading portfolio is expected to all be realized in 2017.
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, 2016, 22% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties, while 7% was with non-investment grade counterparties and 71% was with counterparties that are not rated.
Performance Assurances and Collateral
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, 2016 the Company had posted $57.4 million of net variation margin. At December 31, 2015 the Company held net variation margin of $10.7 million.
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, 2016 and 2015, the Company had posted initial margin of $16.2 million and $9.2 million, respectively, which is reflected in “Other current assets” in the consolidated balance sheets. As of December 31, 2016 the Company was in receipt of $2.0 million of the required variation and initial margin, compared to December 31, 2015 when the Company had posted $0.7 million of margin in excess of the required variation and initial margin.
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, 2016 and 2015, would have amounted to collateral postings to counterparties of approximately $2 million and $21 million, respectively. As of December 31, 2016, the Company was required to post approximately $1 million in collateral to counterparties for such positions. No collateral was required to be posted to counterparties as of December 31, 2015.
Peabody Energy Corporation | 2016 Form 10-K | F- 35 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 2016, each of the three rating agencies downgraded the Company's corporate credit rating due to the Bankruptcy Petitions. Despite the rating agencies downgrades, the Company’s additional collateral requirement owed to its counterparties for these ratings based derivative trading instruments would have been zero at December 31, 2016 and 2015 based on the aggregate fair value of all derivative trading instruments with such features. As of December 31, 2016 and 2015, no collateral was posted to counterparties to support such derivative trading instruments.
(10) | Financing Receivables |
The Company's total financing receivables as of December 31, 2016 and 2015 consisted of the following:
December 31, | ||||||||
Balance Sheet Classification | 2016 | 2015 | ||||||
(Dollars in millions) | ||||||||
Other current assets | $ | — | $ | 20.0 | ||||
Investments and other assets | 84.8 | 65.2 | ||||||
Total financing receivables | $ | 84.8 | $ | 85.2 | ||||
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, 2016 and 2015.
Codrilla Mine Project. In 2011, a wholly-owned subsidiary of Peabody Energy Australia PCI Pty Ltd, 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 was 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 with the remaining balance being received during 2016. At December 31, 2015, the balance associated with these receivables totaled $20 million and was recorded in "Other current assets" in the consolidated balance sheets.
Middlemount Mine. The Company periodically makes loans to Middlemount, in which the Company owns a 50% equity interest, pursuant to the related stockholders' agreement for purposes of funding capital expenditures and working capital requirements. The Priority Loans bear interest at a rate equal to the monthly average 30-day Australian Bank Bill Swap Reference Rate plus 3.5%. They were due to expire on December 31, 2016, but have been extended to June 30, 2017 in conjunction with a commercial agreement with the stockholders concerning the distribution of available cash against outstanding payables and the loans. That agreement requires the distribution of available cash at least twice each month. Available cash is defined as the amount in Middlemount’s bank accounts that will not be required to pay known bills within the next 35 days. The available cash is distributed to the stockholders in a 50/50 ratio, unless there is no marketing royalty payment overdue. In that situation, 100% of the available cash is distributed to the Company until its priority repayment loans are repaid in full. Based on the existence of letters of support from related entities of the stockholders, the expected timing of repayment of these loans is projected to extend beyond the stated expiration date and so the Company considers these loans to be of a long-term nature. As a result, (i) the foreign currency impact related to the stockholder loans is included in foreign currency translation adjustment in the consolidated balance sheets and the consolidated statements of comprehensive income and (ii) interest income on the Priority Loans is recognized when cash is received. Refer to Note 4. "Asset Impairment" for background surrounding the impairment charge recognized in 2015 related to Middlemount. The carrying value of the loans of $84.8 million and $65.2 million was reflected in "Investments and other assets" in the consolidated balance sheets as of December 31, 2016 and 2015, respectively.
On August 8, 2016, one of the Company's Australian subsidiaries and the other stockholder of Middlemount entered into an agreement to provide a revolving loan (Revolving Loans) to Middlemount not to exceed $60.0 million Australian dollars (Revolving Loan Limit). The Company’s participation in the Revolving Loans will not, at any time, exceed its 50% equity interest of the Revolving Loan Limit. The Revolving Loans bear interest at 15% per annum and expire on December 31, 2017. As of December 31, 2016, the carrying value of the Revolving Loans due to the Company's Australian subsidiary was zero.
Peabody Energy Corporation | 2016 Form 10-K | F- 36 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(11) Property, Plant, Equipment and Mine Development
Property, plant, equipment and mine development, net, as of December 31, 2016 and December 31, 2015 consisted of the following:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
Land and coal interests | $ | 10,330.8 | $ | 10,503.7 | |||
Buildings and improvements | 1,507.6 | 1,506.0 | |||||
Machinery and equipment | 2,130.2 | 2,280.4 | |||||
Less: Accumulated depreciation, depletion and amortization | (5,191.9 | ) | (5,031.6 | ) | |||
Total, net | $ | 8,776.7 | $ | 9,258.5 | |||
The net book value of coal reserves totaled $5.5 billion as of December 31, 2016 and $5.7 billion as of December 31, 2015, which excludes the carrying value of acquired interests in mineral rights at certain Australian exploration properties of $1.2 billion for both years, respectively. The coal reserves include mineral rights for leased coal interests and advance royalties that had a net book value of $4.4 billion as of December 31, 2016 and $4.6 billion as of December 31, 2015. The remaining net book value of coal reserves of $1.1 billion at December 31, 2016 and December 31, 2015 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 $1.6 billion as of December 31, 2016 and $1.7 billion as of December 31, 2015.
(12) | Income Taxes |
Loss from continuing operations before income taxes for the years ended December 31, 2016, 2015 and 2014 consisted of the following:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
U.S. | $ | (49.7 | ) | $ | (515.9 | ) | $ | 268.9 | |||
Non-U.S. | (708.6 | ) | (1,474.4 | ) | (816.8 | ) | |||||
Total | $ | (758.3 | ) | $ | (1,990.3 | ) | $ | (547.9 | ) | ||
Total income tax (benefit) provision for the years ended December 31, 2016, 2015 and 2014 consisted of the following:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Current: | |||||||||||
U.S. federal | $ | (12.4 | ) | $ | (71.9 | ) | $ | 27.1 | |||
Non-U.S. | 14.4 | 3.7 | (61.1 | ) | |||||||
State | 0.5 | (0.6 | ) | 3.3 | |||||||
Total current | 2.5 | (68.8 | ) | (30.7 | ) | ||||||
Deferred: | |||||||||||
U.S. federal | (82.1 | ) | (117.4 | ) | 111.0 | ||||||
Non-U.S. | (2.3 | ) | 15.7 | 122.3 | |||||||
State | (2.1 | ) | (5.9 | ) | (1.4 | ) | |||||
Total deferred | (86.5 | ) | (107.6 | ) | 231.9 | ||||||
Total income tax (benefit) provision | $ | (84.0 | ) | $ | (176.4 | ) | $ | 201.2 | |||
Peabody Energy Corporation | 2016 Form 10-K | F- 37 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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, 2016, 2015 and 2014:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Expected income tax benefit at U.S. federal statutory rate | $ | (265.4 | ) | $ | (696.6 | ) | $ | (191.7 | ) | ||
Changes in valuation allowance, income tax | 2,462.8 | 462.0 | 569.4 | ||||||||
Worthless partnership | (2,204.4 | ) | — | — | |||||||
Changes in tax reserves | 2.3 | (21.4 | ) | (81.5 | ) | ||||||
Excess depletion | (37.2 | ) | (53.7 | ) | (65.3 | ) | |||||
Foreign earnings repatriation | — | — | (71.4 | ) | |||||||
Foreign earnings provision differential | 27.5 | 146.5 | 28.8 | ||||||||
General business tax credits | (14.2 | ) | (15.7 | ) | (19.2 | ) | |||||
Minerals resource rent tax, net of federal tax | — | — | 16.1 | ||||||||
Remeasurement of foreign income tax accounts | (0.4 | ) | (0.5 | ) | (2.7 | ) | |||||
State income taxes, net of federal tax benefit | (90.2 | ) | (20.1 | ) | (2.3 | ) | |||||
Reorganization costs | 29.6 | — | — | ||||||||
Other, net | 5.6 | 23.1 | 21.0 | ||||||||
Total income tax (benefit) provision | $ | (84.0 | ) | $ | (176.4 | ) | $ | 201.2 | |||
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 | 2016 Form 10-K | F- 38 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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, 2016 and 2015 consisted of the following:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
Deferred tax assets: | |||||||
Tax loss carryforwards and credits | $ | 4,284.4 | $ | 1,817.4 | |||
Accrued postretirement benefit obligations | 364.5 | 372.4 | |||||
Asset retirement obligations | 163.6 | 160.9 | |||||
Financial guarantees | 77.9 | 16.9 | |||||
Employee benefits | 57.0 | 69.6 | |||||
Payable to voluntary employee beneficiary association for certain Patriot retirees (1) | — | 52.9 | |||||
Hedge activities | 21.0 | 26.6 | |||||
Workers’ compensation obligations | 7.5 | 13.7 | |||||
Other | 2.1 | 66.7 | |||||
Total gross deferred tax assets | 4,978.0 | 2,597.1 | |||||
Deferred tax liabilities: | |||||||
Property, plant, equipment and mine development, principally due to differences in depreciation, depletion and asset impairments | 900.4 | 966.6 | |||||
Unamortized discount on Convertible Junior Subordinated Debentures | 127.7 | 130.3 | |||||
Investments and other assets | 86.3 | 70.1 | |||||
Total gross deferred tax liabilities | 1,114.4 | 1,167.0 | |||||
Valuation allowance, income tax | (3,881.2 | ) | (1,447.3 | ) | |||
Net deferred tax liability | $ | (17.6 | ) | $ | (17.2 | ) | |
Deferred taxes are classified as follows: | |||||||
Current deferred income taxes | $ | — | $ | 49.7 | |||
Noncurrent deferred income taxes | (17.6 | ) | (66.9 | ) | |||
Net deferred tax liability | $ | (17.6 | ) | $ | (17.2 | ) | |
(1) | Refer to Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" herein for additional details related to this transaction. |
During 2016, the Company determined that a foreign holding company was insolvent, resulting in a worthlessness deduction which increased the Company's federal net operating losses (NOL) by $6.3 billion. The Company's tax loss carryforwards and credits included federal NOL carryforwards of $2,340.4 million, state NOL carryforwards of $127.9 million, foreign tax credits of $267.9 million, U.S. alternative minimum tax (AMT) credits of $264.3 million, tax general business credits of $119.4 million, U.S. capital losses of $60.8 million, charitable contribution carryforwards of $1.3 million and foreign NOL carryforwards of $1,102.2 million as of December 31, 2016. 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, 2016, the Company continued to record valuation allowance against net deferred tax asset positions in the U.S. and Australia of $2,342.9 million and $91.0 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. The $2,342.9 million recorded in U.S. valuation allowance during the year ended December 31, 2016, was reflected in "Income tax (benefit) provision".
Peabody Energy Corporation | 2016 Form 10-K | F- 39 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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, 2016 and 2015:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
Deferred income taxes | $ | 8.9 | $ | 7.9 | |||
Other noncurrent liabilities | 11.2 | 11.7 | |||||
Net unrecognized tax benefits | $ | 20.1 | $ | 19.6 | |||
Gross unrecognized tax benefits | $ | 20.1 | $ | 22.9 | |||
The amount of the Company's gross unrecognized tax benefits decreased by $2.8 million since January 1, 2016 due to the finalization settlement of state audits, 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 $20.1 million and $19.6 million at December 31, 2016 and 2015, respectively. A reconciliation of the beginning and ending amount of gross unrecognized tax benefits for the years ended December 31, 2016, 2015 and 2014 is as follows:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Balance at beginning of period | $ | 22.9 | $ | 44.5 | $ | 143.9 | |||||
Additions for current year tax positions | 1.5 | 2.3 | 12.0 | ||||||||
Reductions for prior year tax positions | (2.8 | ) | (23.5 | ) | — | ||||||
Reductions for settlements with tax authorities | (1.5 | ) | (0.4 | ) | (111.4 | ) | |||||
Balance at end of period | $ | 20.1 | $ | 22.9 | $ | 44.5 | |||||
The Company recognizes interest and penalties related to unrecognized tax benefits in its income tax provision. The Company reversed gross interest and penalties of $0.4 million, $2.1 million and $8.0 million for the years ended December 31, 2016, 2015 and 2014, respectively. The Company had $2.4 million and $0.4 million of accrued gross interest and penalties related to unrecognized tax benefits at December 31, 2016 and 2015, 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 Company's federal income tax returns for the 2014 and 2015 tax years are subject to potential examinations by the Internal Revenue Service (IRS). 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. Australian income tax returns for tax years 2010 through 2013 continue to be subject to potential examinations by the Australian Taxation Office (ATO).
Foreign Earnings
As of December 31, 2016, the Company has a consolidated earnings deficit outside the U.S. but with some immaterial unremitted earnings in certain jurisdictions. The Company continues to be permanently reinvested with respect to its current and historical earnings. However, when appropriate, the Company has the ability to access foreign cash without incurring a residual tax.
Peabody Energy Corporation | 2016 Form 10-K | F- 40 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Tax Payments and Refunds
The following table summarizes the Company’s income tax refunds, net for the years ended December 31, 2016, 2015 and 2014:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
U.S. — federal | $ | (56.5 | ) | $ | (38.1 | ) | $ | (7.7 | ) | ||
U.S. — state and local | 1.4 | 0.4 | (6.8 | ) | |||||||
Non-U.S. | 15.0 | 11.9 | (2.2 | ) | |||||||
Total income tax refunds, net | $ | (40.1 | ) | $ | (25.8 | ) | $ | (16.7 | ) | ||
(13) | Accounts Payable and Accrued Expenses |
Accounts payable and accrued expenses consisted of the following:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
Trade accounts payable | $ | 288.6 | $ | 333.3 | |||
Accrued payroll and related benefits | 201.2 | 191.9 | |||||
Other accrued expenses | 190.1 | 225.8 | |||||
Accrued taxes other than income | 119.6 | 135.9 | |||||
Accrued royalties | 62.8 | 41.0 | |||||
Asset retirement obligations | 41.0 | 25.5 | |||||
Accrued health care insurance | 16.0 | 15.8 | |||||
Workers’ compensation obligations | 7.8 | 8.6 | |||||
Income taxes payable | 6.2 | 6.8 | |||||
Accrued interest | 1.2 | 68.8 | |||||
Accrued environmental cleanup-related costs | — | 23.9 | |||||
Other | — | 2.3 | |||||
Payable to voluntary employee beneficiary associated for certain Patriot retirees (1) | — | 75.0 | |||||
Commodity and foreign currency hedge contracts | — | 231.7 | |||||
Liabilities associated with discontinued operations | 55.9 | 60.0 | |||||
Total accounts payable and accrued expenses | $ | 990.4 | $ | 1,446.3 | |||
(1) | Refer to Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" herein for additional details related to this transaction. |
Peabody Energy Corporation | 2016 Form 10-K | F- 41 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(14) | Current and Long-term Debt |
The Company’s total indebtedness as of December 31, 2016 and 2015 consisted of the following:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
2013 Revolver | $ | 1,558.1 | $ | — | |||
2013 Term Loan Facility due September 2020 | 1,154.5 | 1,156.3 | |||||
6.00% Senior Notes due November 2018 | 1,509.9 | 1,508.9 | |||||
6.50% Senior Notes due September 2020 | 645.8 | 645.5 | |||||
6.25% Senior Notes due November 2021 | 1,327.7 | 1,327.0 | |||||
10.00% Senior Secured Second Lien Notes due March 2022 | 962.3 | 960.4 | |||||
7.875% Senior Notes due November 2026 | 245.9 | 245.8 | |||||
Convertible Junior Subordinated Debentures due December 2066 | 367.1 | 366.3 | |||||
Capital lease obligations | 19.7 | 30.3 | |||||
Other | 0.4 | 0.7 | |||||
7,791.4 | 6,241.2 | ||||||
Less: Current portion of long-term debt | 20.2 | 5,874.9 | |||||
Less: Liabilities subject to compromise | 7,771.2 | — | |||||
Long-term debt | $ | — | $ | 366.3 | |||
The carrying amounts of the 2013 Term Loan Facility due September 2020, the 6.00% Senior Notes due November 2018, the 6.50% Senior Notes due September 2020, the 6.25% Senior Notes due November 2021, 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 debt issuance costs and original issue discounts, as applicable.
Prior to the issuance of the Company's 2015 consolidated financial statements, the Company believed it would not comply with the financial covenants of its 2013 Credit Facility (as defined below), and as such, all of its long-term debt with the exception of the Debentures was classified as current at December 31, 2015. As of December 31, 2016, substantially all of the Company's long-term debt was recorded in “Liabilities subject to compromise” in the consolidated balance sheets. Refer to Note 3. "Liabilities Subject to Compromise" for additional information.
Peabody Energy Corporation | 2016 Form 10-K | F- 42 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The filing of the Bankruptcy Petitions constituted an event of default that accelerated Peabody’s obligations under the following debt instruments (collectively, the Debt Instruments):
• | Indenture governing $1,000.0 million outstanding aggregate principal amount of the Company’s 10.00% Senior Secured Second Lien Notes due 2022, dated as of March 16, 2015, among the Company, U.S. Bank National Association (U.S. Bank), as trustee and collateral agent, and the guarantors named therein, as supplemented; |
• | Indenture governing $650.0 million outstanding aggregate principal amount of the Company’s 6.50% Senior Notes due 2020, dated as of March 19, 2004, among the Company, U.S. Bank and the guarantors named therein, as supplemented; |
• | Indenture governing $1,518.8 million outstanding aggregate principal amount of the Company’s 6.00% Senior Notes due 2018, dated as of November 15, 2011, among the Company, U.S. Bank and the guarantors named therein, as supplemented; |
• | Indenture governing $1,339.6 million outstanding aggregate principal amount of the Company’s 6.25% Senior Notes due 2021, dated as of November 15, 2011, by and among the Company, U.S. Bank and the guarantors named therein, as supplemented; |
• | Indenture governing $250.0 million outstanding aggregate principal amount of the Company’s 7.875% Senior Notes due 2026, dated as of March 19, 2004, among the Company, U.S. Bank and the guarantors named therein, as supplemented; |
• | Subordinated Indenture governing $732.5 million outstanding aggregate principal amount of the Company’s Convertible Junior Subordinated Debentures due 2066, dated as of December 20, 2006, among the Company and U.S. Bank, as supplemented; and |
• | Amended and Restated Credit Agreement, as amended and restated as of September 24, 2013 (the 2013 Credit Facility), related to $1,170.0 million outstanding aggregate principal amount of term loans under the 2013 Term Loan Facility and $1,650.0 million in the 2013 Revolver which includes approximately $675 million of posted but undrawn letters of credit and approximately $947 million in outstanding borrowings, by and among the Company, Citibank, N.A., as administrative agent, swing line lender and letter of credit (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 lender parties thereto, as amended by that certain Omnibus Credit Agreement, dated as of February 5, 2015. |
During March 2016, the Company 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 Senior Secured Second Lien Notes. The Company filed the Bankruptcy Petitions before the grace period lapsed, which stayed the related interest payments.
As a result of the filing of the Bankruptcy Petitions, all unpaid principal and accrued and unpaid interest related to the Company's Debt Instruments due thereunder became immediately due and payable. Any efforts to enforce such payment obligations under the Debt Instruments are automatically stayed as a result of the Bankruptcy Petitions, and the creditors’ rights of enforcement in respect of the Debt Instruments are subject to the applicable provisions of the Bankruptcy Code.
The Company was also required to pay monthly adequate protection payments to the First Lien Secured Parties in accordance with the rates defined in the 2013 Credit Facility. The adequate protection payments were recorded as "Interest expense" in the consolidated statement of operations, which totaled $121.4 million for the year ended December 31, 2016.
The Company has not recorded interest expense on the 6.00% Senior Notes due November 2018, the 6.50% Senior Notes due September 2020, the 6.25% Senior Notes due November 2021, the Debentures, the Senior Secured Second Lien Notes or the 7.875% Senior Notes due November 2026 since the filing of the Bankruptcy Petitions on the Petition Date. The Company's contractual interest obligation was $564.9 million for the year ended December 31, 2016; however, in accordance with Section 502(b)(2) of the Bankruptcy Code, $266.3 million of that amount was automatically stayed.
Interest paid on debt was $132.3 million, $414.2 million and $404.4 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Financing costs incurred with the issuance of the Company’s debt (excluding DIP financing costs) were being amortized to interest expense over the remaining term of the associated debt prior to the Bankruptcy Petitions. The remaining balance at December 31, 2016 was $89.0 million.
Peabody Energy Corporation | 2016 Form 10-K | F- 43 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
DIP Financing
On the Petition Date, the Debtors filed a motion (the DIP Motion) seeking authorization to use cash collateral and to approve financing (the DIP Financing) under that certain Superpriority Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) by and among the Company as borrower, Peabody Global Funding, LLC, formerly known as the Global Center for Energy and Human Development and certain Debtors party thereto as guarantors (the Guarantors and together with the Company, the Loan Parties), the lenders party thereto (the DIP Lenders) and Citibank, N.A. as Administrative Agent (in such capacity, the DIP Agent) and L/C Issuer. The DIP Credit Agreement provided for (i) a term loan not to exceed $500 million (the DIP Term Loan Facility), of which $200 million was made available upon entry of an interim order, the remaining $300 million pending the entry of the final order approving the DIP Credit Agreement (the Final Order), secured by substantially all of the assets of the Loan Parties, subject to certain excluded assets and carve outs and guaranteed by the Loan Parties (other than the Company), which would be used for working capital and general corporate purposes, to cash collateralize letters of credit and to pay fees and expenses, (ii) a cash collateralized letter of credit facility in an amount up to $100 million (the L/C Facility), and (iii) a bonding accommodation facility in an amount up to $200 million consisting of (x) a carve-out from the collateral with superpriority claim status, subject only to the fees carve-out, entitling the authority making any bonding request to receive proceeds of collateral first in priority before distribution to any DIP Lender or other prepetition secured creditor, except for letters of credit issued under the DIP Credit Agreement and/or (y) a letter of credit facility (the Bonding L/C Facility). The aggregate face amount of all letters of credit issued under the L/C Facility and the Bonding L/C Facility could not at any time exceed $50 million without DIP Lender consent.
On April 15, 2016, the Bankruptcy Court issued an order approving the DIP Motion on an interim basis and authorizing the Loan Parties to, among other things, (i) enter into the DIP Credit Agreement and initially borrow up to $200 million, (ii) obtain a cash collateralized letter of credit facility in the aggregate amount of up to $100 million, and (iii) establish an accommodation facility for bonding requests in an aggregate stated amount of up to $200 million. On April 18, 2016, the Company entered into the DIP Credit Agreement with the DIP Lenders and borrowed $200 million under the DIP Term Loan Facility. On May 17, 2016, the Bankruptcy Court approved the DIP Financing on a final basis and entered an order to that effect on May 18, 2016. On May 19, 2016, following entry of the Final Order, the Company borrowed the remaining $300 million available under the DIP Term Loan Facility. The Company paid aggregate debt issuance costs of $26.8 million during the year ended December 31, 2016 related to the DIP Term Loan Facility.
On December 14, 2016, the Bankruptcy Court entered an order authorizing the repayment of the DIP Term Loan Facility prior to its scheduled maturity date and on December 15, 2016, the Company repaid the DIP Term Loan Facility in full. Upon making this payment, the Company’s obligations under the DIP Credit Agreement were satisfied in full and it was terminated. In connection with the repayment and termination, the Company incurred a loss on the early debt extinguishment of $29.5 million, consisting of a $10.0 million early-termination fee and $19.5 million related to the write-off of unamortized deferred financing costs and an original issue discount.
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).
During the first quarter of 2016, the Company borrowed $947.0 million under the 2013 Revolver for general corporate purposes. As of the Petition Date, the Company had approximately $675 million letters of credit outstanding on the 2013 Revolver. Subsequent to the Petition Date, certain counterparties drew on a portion of those letters of credit. The letters of credit were in place to support various types of obligations, though the most significant items related to bank guarantees in place for certain reclamation bonding requirements in Australia. The draws required the recording of previously off-balance sheet liabilities, except in certain instances where the Company had previously recorded a liability, and as such have been reflected as additional borrowings under the 2013 Revolver. The total of such letters of credit was $611.1 million as of December 31, 2016. "Investments and other assets" in the consolidated balance sheets as of December 31, 2016 includes $479.3 million of collateral in support of certain of these obligations.
As a result of filing the Bankruptcy Petitions on April 13, 2016, as discussed in Note 1. "Summary of Significant Accounting Policies", the Company is in default under the 2013 Credit Facility and as such the 2013 Revolver can no longer be utilized.
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.
Peabody Energy Corporation | 2016 Form 10-K | F- 44 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.
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.
Exit Financing
On February 8, 2017, the Company announced the pricing of a $950.0 million senior secured term loan. The term loan will mature in 2022 and bear interest at a fluctuating rate of LIBOR plus 4.50% per annum, with a 1.00% LIBOR floor. The closing of the term loan is expected to occur in early April 2017, concurrent with the anticipated effective date of the Plan and subject to confirmation of the Plan and customary closing conditions and final documentation. The proceeds from the term loan will be used to fund a portion of the distributions to creditors provided for under the Plan.
Also on February 8, 2017, the Company announced that a special purpose wholly owned subsidiary of the Company priced an offering of $500.0 million aggregate principal amount of 6.000% senior secured notes due 2022 and $500.0 million aggregate principal amount of 6.375% senior secured notes due 2025, each exempt from the registration requirements of the Securities Act of 1933, as amended. The offering of the notes closed on February 15, 2017 at which time the net proceeds of the offering were funded into an escrow account pending the Plan Effective Date. The notes were offered by a special purpose wholly owned subsidiary of the Company and if the Plan is confirmed and certain other conditions are satisfied on or before August 1, 2017, the net proceeds from the offering will be released from escrow to fund a portion of the distributions to creditors provided for under the Plan, and the Company will become the obligor under the notes.
Capital Lease Obligations
Refer to Note 15. "Leases" for additional information associated with the Company's capital leases, which pertain to the financing of mining equipment used in operations.
(15) | Leases |
The Company leases equipment and facilities under various noncancellable 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 $264.7 million, $290.1 million and $306.0 million for the years ended December 31, 2016, 2015 and 2014, 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, 2016, 2015 and 2014. The gross value of property, plant, and equipment under capital leases was $77.9 million and $77.5 million as of December 31, 2016 and 2015, respectively, related primarily to the leasing of mining equipment. The accumulated depreciation for these items was $48.6 million and $32.2 million at December 31, 2016 and 2015, 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 $389.7 million, $444.5 million and $507.8 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Peabody Energy Corporation | 2016 Form 10-K | F- 45 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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, 2016 are as follows:
Capital Leases | Operating Leases | Coal Lease and Royalty Obligations | ||||||||||
Year Ending December 31, | ||||||||||||
(Dollars in millions) | ||||||||||||
2017 | $ | 7.3 | $ | 148.7 | $ | 6.1 | ||||||
2018 | 8.9 | 100.4 | 5.7 | |||||||||
2019 | 0.5 | 60.2 | 5.2 | |||||||||
2020 | 0.5 | 26.4 | 4.9 | |||||||||
2021 | 0.5 | 10.6 | 5.3 | |||||||||
2022 and thereafter | 9.6 | 26.6 | 26.6 | |||||||||
Total minimum lease payments | 27.3 | $ | 372.9 | $ | 53.8 | |||||||
Less interest | 7.6 | |||||||||||
Present value of minimum capital lease payments | $ | 19.7 | ||||||||||
As of December 31, 2016, certain of the Company’s coal lease obligations were secured by outstanding surety bonds totaling $94.0 million.
Peabody Energy Corporation | 2016 Form 10-K | F- 46 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(16) | Asset Retirement Obligations |
Reconciliations of the Company’s asset retirement obligations are as follows:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
Balance at beginning of year | $ | 712.1 | $ | 752.5 | |||
Liabilities incurred or acquired | — | 1.3 | |||||
Liabilities settled or disposed | (41.5 | ) | (53.3 | ) | |||
Accretion expense | 45.7 | 42.7 | |||||
Revisions to estimates | 42.5 | (31.1 | ) | ||||
Balance at end of year | $ | 758.8 | $ | 712.1 | |||
Less: Current portion (included in "Accounts payable and accrued expenses") | 41.0 | 25.5 | |||||
Noncurrent obligation (included in "Asset retirement obligations") | $ | 717.8 | $ | 686.6 | |||
Balance at end of year — active locations | $ | 651.1 | $ | 656.8 | |||
Balance at end of year — closed or inactive locations | $ | 107.7 | $ | 55.3 | |||
The credit-adjusted, risk-free interest rates utilized to estimate the Company's asset retirement obligations were 13.45% for its U.S. reclamation obligations and 4.92% for its Australia reclamation obligations at December 31, 2016 and 50.83% and 6.82% at December 31, 2015 and 2014, respectively. For 2016, a distinct rate was developed for Australia due to the amount of cash collateral held in support of the related obligations as of December 31, 2016.
As of December 31, 2016 and 2015, the Company had $374.3 million and $609.4 million, respectively, in surety bonds and bank guarantees outstanding to secure reclamation obligations. The amount of reclamation self-bonding in certain U.S. states in which the Company qualifies was $1,094.2 million and $1,430.8 million as of December 31, 2016 and 2015, respectively. Additionally, the Company had $80.0 million and $126.6 million, respectively, of letters of credit in support of reclamation obligations as of December 31, 2016 and 2015. During 2016, the Company replaced certain bank guarantees with cash collateral of $233.2 million as of December 31, 2016.
(17) | Postretirement Health Care and Life Insurance Benefits |
The Company currently provides health care and life insurance benefits to qualifying salaried and hourly retirees of its current and certain former subsidiaries 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, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Service cost for benefits earned | $ | 10.4 | $ | 11.2 | $ | 12.2 | |||||
Interest cost on accumulated postretirement benefit obligation | 34.5 | 33.8 | 36.4 | ||||||||
Amortization of prior service (credit) cost | (9.2 | ) | (6.8 | ) | 1.3 | ||||||
Amortization of actuarial loss | 20.4 | 24.9 | 14.5 | ||||||||
Special termination benefits (1) | — | — | 1.6 | ||||||||
Net periodic postretirement benefit cost | $ | 56.1 | $ | 63.1 | $ | 66.0 | |||||
(1) | Reflected in "Restructuring and pension settlement charges" in the consolidated statement of operations for the year ended December 31, 2014. |
Peabody Energy Corporation | 2016 Form 10-K | F- 47 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following includes pre-tax amounts recorded in "Accumulated other comprehensive loss":
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Net actuarial loss (gain) arising during year | $ | 32.3 | $ | (35.1 | ) | $ | 115.8 | ||||
Prior service credit arising during year | — | — | (18.0 | ) | |||||||
Amortization: | |||||||||||
Actuarial loss | (20.4 | ) | (24.9 | ) | (14.5 | ) | |||||
Prior service credit (cost) | 9.2 | 6.8 | (1.3 | ) | |||||||
Settlement related to the Patriot bankruptcy: (1) | |||||||||||
Prior service cost | 7.2 | (16.6 | ) | — | |||||||
Total recorded in "Accumulated other comprehensive loss" | $ | 28.3 | $ | (69.8 | ) | $ | 82.0 | ||||
(1) | Refer to Note 27. "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 (10.31 years and 10.49 years at January 1, 2017 and 2016, respectively). The estimated net actuarial loss and prior service credit that will be amortized from accumulated other comprehensive loss into net periodic postretirement benefit cost during the year ending December 31, 2017 are $22.0 million and $9.2 million, respectively.
The following table sets forth the plans' funded status reconciled with the amounts shown in the consolidated balance sheets:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
Change in benefit obligation: | |||||||
Accumulated postretirement benefit obligation at beginning of period | $ | 776.1 | $ | 839.1 | |||
Service cost | 10.4 | 11.2 | |||||
Interest cost | 34.5 | 33.8 | |||||
Participant contributions | 0.6 | 1.7 | |||||
Plan changes(1) | 7.2 | (16.6 | ) | ||||
Benefits paid | (49.0 | ) | (46.5 | ) | |||
Actuarial loss (gain) | 32.3 | (35.1 | ) | ||||
Settlement related to the Patriot bankruptcy (1) | — | (15.2 | ) | ||||
Other | — | 3.7 | |||||
Accumulated postretirement benefit obligation at end of period | 812.1 | 776.1 | |||||
Change in plan assets: | |||||||
Fair value of plan assets at beginning of period | — | — | |||||
Employer contributions | 48.4 | 44.8 | |||||
Participant contributions | 0.6 | 1.7 | |||||
Benefits paid and administrative fees (net of Medicare Part D reimbursements) | (49.0 | ) | (46.5 | ) | |||
Fair value of plan assets at end of period | — | — | |||||
Funded status at end of year | (812.1 | ) | (776.1 | ) | |||
Less: Current portion (included in "Accounts payable and accrued expenses") | 55.8 | 53.2 | |||||
Noncurrent obligation (included in "Accrued postretirement benefit costs") | $ | (756.3 | ) | $ | (722.9 | ) | |
(1) | Refer to Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation" herein for additional details related to the changes in the benefit obligation. |
Peabody Energy Corporation | 2016 Form 10-K | F- 48 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:
December 31, | |||||
2016 | 2015 | ||||
Discount rate | 4.15 | % | 4.50 | % | |
Measurement date | December 31, 2016 | December 31, 2015 | |||
The weighted-average assumptions used to determine net periodic benefit cost during each year were as follows:
Year Ended December 31, | ||||||||
2016 | 2015 | 2014 | ||||||
Discount rate | 4.50 | % | 4.10 | % | 4.90 | % | ||
Measurement date | December 31, 2015 | December 31, 2014 | December 31, 2013 | |||||
The following presents information about the assumed health care cost trend rate:
Year Ended December 31, | |||||
2016 | 2015 | ||||
Pre-Medicare: | |||||
Health care cost trend rate assumed for next year | 6.20 | % | 6.60 | % | |
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 | 5.60 | % | 5.80 | % | |
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) | $ | 3.6 | $ | (3.2 | ) | ||
Effect on total postretirement benefit obligation (1) | $ | 67.0 | $ | (61.9 | ) | ||
(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 10.31 years at January 1, 2017. |
Peabody Energy Corporation | 2016 Form 10-K | F- 49 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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) | |||
2017 | $ | 55.0 | |
2018 | 56.2 | ||
2019 | 57.0 | ||
2020 | 57.5 | ||
2021 | 61.3 | ||
Years 2022-2026 | 290.3 | ||
(18) | 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 Pension 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, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Service cost for benefits earned | $ | 2.5 | $ | 2.7 | $ | 2.1 | |||||
Interest cost on projected benefit obligation | 41.5 | 40.4 | 45.4 | ||||||||
Expected return on plan assets | (45.3 | ) | (48.2 | ) | (54.3 | ) | |||||
Amortization of prior service cost | 0.3 | 1.0 | 1.3 | ||||||||
Amortization of net actuarial losses | 24.7 | 39.6 | 30.2 | ||||||||
Settlement charge | — | — | 8.7 | ||||||||
Net periodic pension cost | $ | 23.7 | $ | 35.5 | $ | 33.4 | |||||
Peabody Energy Corporation | 2016 Form 10-K | F- 50 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following includes pre-tax amounts recorded in "Accumulated other comprehensive loss":
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Net actuarial loss arising during year | $ | 6.6 | $ | 30.6 | $ | 79.2 | |||||
Amortization: | |||||||||||
Net actuarial loss | (24.7 | ) | (39.6 | ) | (30.2 | ) | |||||
Prior service cost | (0.3 | ) | (1.0 | ) | (1.3 | ) | |||||
Settlement charge | — | — | (8.7 | ) | |||||||
Total recorded in "Accumulated other comprehensive loss" | $ | (18.4 | ) | $ | (10.0 | ) | $ | 39.0 | |||
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, 2017 are $25.4 million and $0.3 million, respectively.
The following summarizes the change in benefit obligation, change in plan assets and funded status of the Pension Plans:
December 31, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
Change in benefit obligation: | |||||||
Projected benefit obligation at beginning of period | $ | 939.3 | $ | 1,002.5 | |||
Service cost | 2.5 | 2.7 | |||||
Interest cost | 41.5 | 40.4 | |||||
Benefits paid | (61.1 | ) | (62.6 | ) | |||
Actuarial loss (gain) | 37.1 | (43.7 | ) | ||||
Projected benefit obligation at end of period | 959.3 | 939.3 | |||||
Change in plan assets: | |||||||
Fair value of plan assets at beginning of period | 757.3 | 839.8 | |||||
Actual return (loss) on plan assets | 75.7 | (26.1 | ) | ||||
Employer contributions | 1.1 | 6.2 | |||||
Benefits paid | (61.1 | ) | (62.6 | ) | |||
Fair value of plan assets at end of period | 773.0 | 757.3 | |||||
Funded status at end of year | $ | (186.3 | ) | $ | (182.0 | ) | |
Amounts recognized in the consolidated balance sheets: | |||||||
Current obligation (included in "Accounts payable and accrued expenses") | $ | — | $ | (1.6 | ) | ||
Noncurrent obligation (included in "Other noncurrent liabilities") | (163.5 | ) | (180.4 | ) | |||
Liabilities subject to compromise | (22.8 | ) | — | ||||
Net amount recognized | $ | (186.3 | ) | $ | (182.0 | ) | |
The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:
December 31, | |||||
2016 | 2015 | ||||
Discount rate | 4.15 | % | 4.55 | % | |
Measurement date | December 31, 2016 | December 31, 2015 | |||
Peabody Energy Corporation | 2016 Form 10-K | F- 51 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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, | ||||||||
2016 | 2015 | 2014 | ||||||
Discount rate | 4.55 | % | 4.15 | % | 4.95 | % | ||
Expected long-term return on plan assets | 6.00 | % | 6.25 | % | 6.85 | % | ||
Measurement date | December 31, 2015 | December 31, 2014 | December 31, 2013 | |||||
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, 2017, the Company lowered its expected rate of return on plan assets from 6.00% to 5.90% reflecting the impact of the Company's asset allocation and capital market expectations.
The projected benefit obligation and the accumulated benefit obligation exceeded plan assets for all plans as of December 31, 2016 and 2015. The accumulated benefit obligation for all plans was $959.3 million and $939.3 million as of December 31, 2016 and 2015, respectively.
Assets of the Pension 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 Pension Plan's expected liabilities. To determine the appropriate target asset allocations, the Retirement Committees consider the demographics of each Pension Plan's participants, the funded status of each Pension 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 Pension 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 Pension Plans reach certain funded status thresholds. As of December 31, 2016 and 2015, the Master Trust investment portfolio reflected the Company's target asset mix of 31% equity securities and 69% fixed income investments. Master Trust assets also include funds invested in various real estate properties representing approximately 2% and 3% of total Master Trust assets as of December 31, 2016 and 2015, 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 52 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Mutual funds. The Master Trust invests in mutual funds for growth and diversification. Investment vehicles include a fund (benchmarked against the performance of the S&P 500 Index) that invests in large-cap publicly traded common stocks (Large-Cap Fund), an institutional fund that holds a diversified portfolio of long-duration corporate fixed income investments (Corporate Bond Fund), and an institutional fund that consists of a diversified portfolio of liquid, short-term instruments of varying maturities (Short-Term Fund). The Large-Cap 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 Corporate Bond Fund and the Short-Term Fund are not traded on a national securities exchange and are valued at NAV, the practical expedient to estimate fair value.
Corporate bonds. The Master Trust invests in corporate bonds for diversification, volatility reduction of equity securities and to provide a hedge to interest rate movements affecting liabilities. Investment vehicles include investment-grade corporate bonds. 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. Corporate bonds are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the bonds are not traded on a national securities exchange.
U.S. government securities. The Master Trust invests in U.S. government 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 bonds, agency securities and municipal bonds. 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, U.S. government securities are classified within the Level 1 valuation hierarchy; otherwise, U.S. government securities are classified within the Level 2 valuation hierarchy.
International government securities. The Master Trust invests in international government securities for diversification, volatility reduction of equity securities and to provide a hedge to interest rate movements affecting liabilities. Investment vehicles include non-U.S. government bonds. 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. International government securities are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the bonds are not traded on a national securities exchange.
Common/collective trusts. The Master Trust invests in common/collective trusts (CCT) for growth and diversification. Investment vehicles include a CCT (benchmarked against the performance of the Russell 2000 Index) that invests in small-cap publicly traded common stocks (the Small-Cap CCT), a CCT that invests in publicly traded non-U.S. equity securities (the Equity CCT) and a 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). The Equity CCT and the Equity Index CCT 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. All CCTs are not traded on a national securities exchange and are valued at NAV, the practical expedient to estimate fair value.
Cash funds. The Master Trust invests in cash funds to manage liquidity resulting from payment of participant benefits and certain administrative fees. Investment vehicles primarily include a non-interest bearing cash fund with an earnings credit allowance feature 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. 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.
Real estate investment trusts. 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 Pension Plans invest elsewhere within the Master Trust.
Peabody Energy Corporation | 2016 Form 10-K | F- 53 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.
The following tables present the fair value of assets in the Master Trust by asset category and by fair value hierarchy:
December 31, 2016 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(Dollars in millions) | |||||||||||||||
Mutual funds | $ | 119.9 | $ | — | $ | — | $ | 119.9 | |||||||
Corporate bonds | — | 265.7 | — | 265.7 | |||||||||||
U.S. government securities | 25.1 | 22.7 | — | 47.8 | |||||||||||
International government securities | — | 12.6 | — | 12.6 | |||||||||||
Cash funds | 17.8 | — | — | 17.8 | |||||||||||
Real estate investment trusts | — | — | 14.1 | 14.1 | |||||||||||
Total assets at fair value | $ | 162.8 | $ | 301.0 | $ | 14.1 | 477.9 | ||||||||
Assets measured at net asset value practical expedient (1) | |||||||||||||||
Private mutual funds | 186.1 | ||||||||||||||
Common collective trusts | 109.0 | ||||||||||||||
295.1 | |||||||||||||||
Total plan assets | $ | 773.0 | |||||||||||||
December 31, 2015 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(Dollars in millions) | |||||||||||||||
Mutual funds | $ | 107.1 | $ | — | $ | — | $ | 107.1 | |||||||
Corporate bonds | — | 259.4 | — | 259.4 | |||||||||||
U.S. government securities | 26.8 | 26.6 | — | 53.4 | |||||||||||
International government securities | — | 15.0 | — | 15.0 | |||||||||||
Cash funds | 18.2 | — | — | 18.2 | |||||||||||
Real estate investment trusts | — | — | 23.0 | 23.0 | |||||||||||
Total assets at fair value | $ | 152.1 | $ | 301.0 | $ | 23.0 | 476.1 | ||||||||
Assets measured at net asset value practical expedient (1) | |||||||||||||||
Private mutual funds | 183.9 | ||||||||||||||
Common collective trusts | 97.3 | ||||||||||||||
281.2 | |||||||||||||||
Total plan assets | $ | 757.3 | |||||||||||||
(1) In accordance with Accounting Standards Update 2015-07, investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value of assets of the plans.
Peabody Energy Corporation | 2016 Form 10-K | F- 54 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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, | |||||||
2016 | 2015 | ||||||
(Dollars in millions) | |||||||
Balance, beginning of year | $ | 23.0 | $ | 30.2 | |||
Realized gains | 1.8 | 3.2 | |||||
Unrealized gains relating to investments still held at the reporting date | 0.2 | 0.2 | |||||
Purchases, sales and settlements, net | (10.9 | ) | (10.6 | ) | |||
Balance, end of year | $ | 14.1 | $ | 23.0 | |||
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, 2016, the Company contributed $0.5 million and $0.6 million, respectively, to its qualified and non-qualified pension plans. As of December 31, 2016, the Company's qualified plans are expected to be at or above the Pension Protection Act thresholds. However, during the Chapter 11 Cases, certain forms of payment from the Pension Plans are restricted. 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 21st 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 $5.9 million to its pension plans to meet minimum funding requirements for its qualified plans and benefit payments for its non-qualified plans in 2017. Contributions to non-qualified plans ceased subsequent to April 12, 2016 as a result of filing the Bankruptcy Petitions.
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) | |||
2017 | $ | 61.7 | |
2018 | 62.3 | ||
2019 | 62.2 | ||
2020 | 64.0 | ||
2021 | 65.1 | ||
Years 2022-2026 | 312.4 | ||
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 $19.2 million, $22.0 million and $44.7 million for the years ended December 31, 2016, 2015 and 2014, respectively. A performance contribution feature in one of the plans allows for additional contributions from the Company based upon meeting specified Company performance targets. There was no performance contribution for the year ended December 31, 2016. Performance contributions paid during the years ended December 31, 2015 and 2014 were $19.5 million and $18.3 million, respectively. The performance contribution was paid in Peabody Energy Corporation common stock for the year ended December 31, 2015 and cash for the year ended December 31, 2014.
Peabody Energy Corporation | 2016 Form 10-K | F- 55 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(19) | Stockholders’ Equity |
If the Plan becomes effective, the Company's common stock will be extinguished, canceled and discharged on the Plan Effective Date. Under the Plan, holders of common stock are not entitled to receive, and will not receive or retain, any property or interest in property on account of such equity interests. In the event of cancellation of the Company's common stock, amounts invested by the holders will not be recoverable and the common stock will have no value.
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 the Company. There are no redemption or sinking fund provisions applicable to the common stock.
The following table summarizes common stock activity from January 1, 2014 to December 31, 2016:
2016 | 2015 | 2014 | ||||||
(In millions) | ||||||||
Shares outstanding at the beginning of the year | 18.5 | 18.1 | 18.0 | |||||
Stock grants to employees | — | 0.2 | 0.1 | |||||
Performance share contribution 401k | — | 0.2 | — | |||||
Shares outstanding at the end of the year | 18.5 | 18.5 | 18.1 | |||||
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, 2016.
Peabody Energy Corporation | 2016 Form 10-K | F- 56 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Perpetual Preferred Stock
The Company had $732.5 million aggregate principal amount of the Debentures outstanding as of December 31, 2016. 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, 2016.
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. From October 2008 through December 2013, the Company 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, 2016, 2015 and 2014. As a result of filing the Bankruptcy Petition, the Company is currently prohibited from repurchasing shares. The payment of future cash dividends and future repurchases will depend upon the Company's earnings, economic conditions, liquidity and capital requirements, and other factors, including the Company's debt leverage. In addition, the terms of the Preferred Equity will limit the Company's ability to pay cash dividends on or purchase shares of Reorganized PEC Common Stock without the consent of holders representing at least a majority of the outstanding shares of the Preferred Equity.
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, 2016, 2015 and 2014, respectively. The value of the common stock tendered by employees was based upon the closing price on the dates of the respective transactions.
Peabody Energy Corporation | 2016 Form 10-K | F- 57 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(20) | 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, 2016, there are approximately 1.0 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. On the Plan Effective Date, equity holders' interests will be canceled and all unrecognized share-based compensation expense will be charged to reorganization items, net.
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, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Share-based compensation expense - equity classified awards | $ | 11.3 | $ | 26.2 | $ | 46.1 | |||||
Share-based compensation expense - liability classified awards | 1.5 | 2.0 | 0.7 | ||||||||
Total share-based compensation expense | 12.8 | 28.2 | 46.8 | ||||||||
Tax benefit | — | — | 17.3 | ||||||||
Share-based compensation expense, net of tax benefit | $ | 12.8 | $ | 28.2 | $ | 29.5 | |||||
Cash received upon the exercise of stock options and from employee stock purchases | — | 3.4 | 5.5 | ||||||||
Write-off tax benefits related to share-based compensation | — | — | (8.3 | ) | |||||||
As of December 31, 2016, the total unrecognized compensation cost related to nonvested awards was $4.9 million, net of taxes, which is expected to be recognized over one year with a weighted-average period of 0.5 years.
Deferred Stock Units
In 2016, 2015 and 2014, 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 58 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Restricted Stock Awards
Prior to 2016, the primary share-based compensation tool used by the Company for its employees was 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, 2016 | Weighted Average Grant-Date Fair Value | |||||
Nonvested at December 31, 2015 | 306,931 | $ | 184.09 | |||
Granted | 7,847 | 7.75 | ||||
Vested | (76,663 | ) | 277.28 | |||
Forfeited | (30,076 | ) | 167.68 | |||
Canceled | (11,295 | ) | 82.49 | |||
Nonvested at December 31, 2016 | 196,744 | $ | 151.72 | |||
The total fair value at grant date of restricted stock awards granted during the year ended December 31, 2016 was less than $0.1 million. The total fair value at grant date of restricted stock awards granted during the years ended December 31, 2015 and 2014 was $26.0 million and $25.5 million, respectively. The total fair value of restricted stock awards vested during the years ended December 31, 2016, 2015 and 2014, was $21.3 million, $35.7 million and $24.5 million, respectively.
Restricted Stock Units
The Company grants restricted stock units to certain senior management and non-senior management employees. 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 2016 and 2014 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.
A summary of restricted stock unit activity is as follows:
Year Ended December 31, 2016 | Weighted Average Grant-Date Fair Value | |||||
Nonvested at December 31, 2015 | 48,780 | $ | 170.42 | |||
Granted | 342,627 | 7.75 | ||||
Vested | (23,220 | ) | 149.84 | |||
Forfeited | (59,629 | ) | 22.41 | |||
Nonvested at December 31, 2016 | 308,558 | $ | 16.98 | |||
The total fair value at grant date of restricted stock units granted during the years ended December 31, 2016, 2015 and 2014 was $2.7 million, $5.5 million and $4.2 million, respectively. The total fair value of restricted stock units vested was $3.5 million and $2.1 million during the years ended December 31, 2016 and 2015, respectively. The total fair value was less than $0.1 million during the year ended December 31, 2014.
Peabody Energy Corporation | 2016 Form 10-K | F- 59 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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. There were no stock options granted in 2016. 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. All awards granted in 2014 will be settled in 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, 2016 | Weighted Average Exercise Price | Weighted Average Remaining Contractual Life | Aggregate Intrinsic Value (in millions) | |||||||||
Options Outstanding at December 31, 2015 | 240,428 | $ | 388.16 | 6.28 | $ | — | ||||||
Forfeited | (22,182 | ) | 419.40 | |||||||||
Options Outstanding at December 31, 2016 | 218,246 | $ | 379.17 | 5.56 | $ | — | ||||||
Vested and Exercisable | 162,402 | $ | 451.88 | 4.86 | $ | — | ||||||
There were no stock options exercised during the years ended December 31, 2016 and 2015. During the year ended December 31, 2014, 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. 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 | ||||||
Weighted-average fair value | $ | 43.66 | $ | 110.70 | |||
Risk-free interest rate | 1.7 | % | 1.7 | % | |||
Expected option life | 5 years | 5 years | |||||
Expected volatility | 45.2 | % | 48.4 | % | |||
Dividend yield | 2.4 | % | 1.7 | % | |||
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. There were no performance units granted in 2016. 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. 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 60 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
A summary of performance unit activity is as follows:
Year Ended December 31, 2016 | Weighted Average Remaining Contractual Life | |||
Nonvested at December 31, 2015 | 81,812 | 1.7 | ||
Forfeited | (5,916 | ) | ||
Vested | (24,474 | ) | ||
Nonvested at December 31, 2016 | 51,422 | 1.0 | ||
As of December 31, 2016, there were 24,474 performance units vested. As a result of the Chapter 11 Cases, these units will not be paid out.
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 | ||||
Risk-free interest rate | 1.1 | % | 0.8 | % | |
Expected volatility | 45.0 | % | 45.3 | % | |
Dividend yield | 2.4 | % | 1.7 | % | |
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 and 2014.
Peabody Energy Corporation | 2016 Form 10-K | F- 61 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(21) | Accumulated Other Comprehensive Loss |
The following table sets forth the after-tax components of comprehensive loss:
Foreign Currency Translation Adjustment | Net Actuarial Loss Associated with Postretirement Plans and Workers’ Compensation Obligations | Prior Service Credit (Cost) Associated with Postretirement Plans | Cash Flow Hedges | Available-For-Sale Securities | Total Accumulated Other Comprehensive Loss | ||||||||||||||||||
(Dollars in millions) | |||||||||||||||||||||||
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 | ) | |||||||||||||
Net change in fair value | — | — | — | — | — | — | |||||||||||||||||
Reclassification from other comprehensive income to earnings | — | 21.0 | (5.6 | ) | 146.3 | — | 161.7 | ||||||||||||||||
Current period change | (1.8 | ) | (13.5 | ) | (4.5 | ) | — | — | (19.8 | ) | |||||||||||||
December 31, 2016 | $ | (148.2 | ) | $ | (256.3 | ) | $ | 21.7 | $ | (94.2 | ) | $ | — | $ | (477.0 | ) | |||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 62 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 years ended December 31, 2016 and 2015:
Amount reclassified from accumulated other comprehensive loss (1) | ||||||||||
Year Ended December 31 | ||||||||||
Details about accumulated other comprehensive loss components | 2016 | 2015 | Affected line item in the consolidated statement of operations | |||||||
(Dollars in millions) | ||||||||||
Net actuarial loss associated with postretirement plans and workers' compensation obligations: | ||||||||||
Postretirement health care and life insurance benefits | $ | (20.4 | ) | $ | (24.9 | ) | Operating costs and expenses | |||
Defined benefit pension plans | (20.5 | ) | (32.9 | ) | Operating costs and expenses | |||||
Defined benefit pension plans | (4.2 | ) | (6.7 | ) | Selling and administrative expenses | |||||
Workers' compensation amortization | 11.7 | 8.0 | Operating costs and expenses | |||||||
(33.4 | ) | (56.5 | ) | Total before income taxes | ||||||
12.4 | 20.9 | Income tax benefit | ||||||||
$ | (21.0 | ) | $ | (35.6 | ) | Total after income taxes | ||||
Prior service credit (cost) associated with postretirement plans: | ||||||||||
Postretirement health care and life insurance benefits | $ | 9.2 | $ | 6.8 | Operating costs and expenses | |||||
Defined benefit pension plans | (0.3 | ) | (1.0 | ) | Operating costs and expenses | |||||
8.9 | 5.8 | Total before income taxes | ||||||||
(3.3 | ) | (2.1 | ) | Income tax benefit | ||||||
$ | 5.6 | $ | 3.7 | Total after income taxes | ||||||
Cash flow hedges: | ||||||||||
Foreign currency forward contracts | $ | (145.6 | ) | $ | (316.4 | ) | Operating costs and expenses | |||
Fuel and explosives commodity swaps | (86.1 | ) | (120.4 | ) | Operating costs and expenses | |||||
Coal trading commodity futures, swaps and options | — | 51.8 | Other revenues | |||||||
Insignificant items | (0.5 | ) | (0.7 | ) | ||||||
(232.2 | ) | (385.7 | ) | Total before income taxes | ||||||
85.9 | 134.0 | Income tax provision | ||||||||
$ | (146.3 | ) | $ | (251.7 | ) | Total after income taxes | ||||
(1) Presented as gains (losses) in the consolidated statements of operations.
Comprehensive loss 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 8. "Derivatives and Fair Value Measurements" and Note 9. "Coal Trading" for information related to the Company’s cash flow hedges), changes in the fair value of available-for-sale securities (see Note 7. "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 17. "Postretirement Health Care and Life Insurance Benefits," Note 18. "Pension and Savings Plans" and Note 27. "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.
Peabody Energy Corporation | 2016 Form 10-K | F- 63 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(22) | Resource Management, Acquisitions and Other Commercial Events |
Organizational Realignment
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.
In 2016, the Company has continued to drive operational efficiencies, optimize production across its mining platform and control operational and administrative expenses. Included in the Company's consolidated statement of operations were aggregate restructuring charges, primarily comprised of cash severance costs, of $15.5 million for the year ended December 31, 2016. These costs were primarily incurred in the first half of 2016.
Divestitures
On January 30, 2017, the Bankruptcy Court issued an order authorizing certain subsidiaries of the Company to enter into a stalking horse purchase agreement and approved bidding procedures for the sale of its 37.5% interest in Dominion Terminal Associates, a partnership that operates a coal export terminal in Newport News, Virginia. Pursuant to that order, the deadline to submit qualified bids for the purchase of this interest was set for March 2, 2017 at 4:00 p.m. (Central) and the related auction was scheduled to begin on March 6, 2017 at 10:00 a.m. (Central). On February 10, 2017, Contura Terminal and Ashland Terminal, Inc., both of which are partners of the Dominion Terminal Associates partnership, filed an appeal of the January 30, 2017 order. On March 6, 2017, the Company held the auction relating to the sale of this interest. At the auction, Contura Terminal, LLC and Ashland Terminal, Inc., who bid at the auction together, were declared the successful bidder. On March 7, 2017, the Company filed a notice with the Bankruptcy Court indicating the identity of the successful bidder. On March 9, 2017, the Bankruptcy Court entered an order approving the sale of the Company's interest in Dominion Terminal Associates to Contura Terminal, LLC and Ashland Terminal, Inc. On March 14, 2017, the Bankruptcy Appellate Panel for the Eighth Circuit entered an order dismissing the appeal of Contura Terminal, LLC and Ashland Terminal, Inc. to the Bankruptcy Court's January 26, 2017 order. The sale of the Company's interest in Dominion Terminal Associates is expected to close prior to the Plan Effective Date.
On November 3, 2016, Peabody Australia Mining Pty Ltd, one of the Company’s Australian subsidiaries, entered into a definitive share sale and purchase agreement for the sale of all of its equity interest in Metropolitan Collieries Pty Ltd, the entity that owns the Metropolitan mine in New South Wales, Australia and the associated interest in the Port Kembla Coal Terminal, to a subsidiary of South32 Limited (South32), which is conditional on receipt of approval from the ACCC. Refer to Note 4. "Asset Impairment" for additional details related to the transaction.
In May 2016, the Company completed the sale of its 5.06% participation interest in the Prairie State Energy Campus to the Wabash Valley Power Association for $57.1 million. The Company recognized a gain on sale of $6.2 million related to the transaction, which was classified in "Net gain on disposal of assets" in the consolidated statement of operations for the year ended December 31, 2016.
In May 2016, the Company entered into sale and purchase agreements with Australia-based Pembroke Resources to sell its interest in undeveloped metallurgical reserve tenements in Queensland's Bowen Basin for $64.1 million in cash plus a royalty stream. The transaction included Olive Downs South, Olive Downs South Extended and Willunga tenements. The Company recognized a gain on sale of $2.8 million related to the transaction, which was classified in "Net gain on disposal of assets" in the consolidated statement of operations for the year ended December 31, 2016.
In November 2015, the Company entered into a definitive agreement to sell its New Mexico and Colorado assets to a subsidiary of Bowie Resource Partners, LLC (Bowie) in exchange for cash proceeds of $358 million and the assumption of certain liabilities. Bowie agreed to pay the Company a termination fee of $20 million (Termination Fee) in the event the Company terminated the agreement because Bowie failed to obtain financing and close the transaction. On April 12, 2016, Peabody terminated the agreement and demanded payment of the Termination Fee, which Bowie has not done. The Company brought action against Bowie to recover the Termination Fee, interest and certain costs. On February 7, 2017, the United States Bankruptcy Court issued a memorandum opinion stating that it would grant summary judgment in favor of the Company and award it the Termination Fee, interest and attorney’s fees and costs incurred in collecting the Termination Fee. On March 9, 2017, after a hearing on the attorneys’ fees and costs that the Company incurred in collecting the Termination Fee, the United States Bankruptcy Court entered judgment in favor of the Company. The Company will not record income related to this judgment until collection from Bowie.
Peabody Energy Corporation | 2016 Form 10-K | F- 64 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 that 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 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 of assets" in the consolidated statement of operations for the year ended December 31, 2014.
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. Accordingly, there was no gain or loss recognized on the disposal during the year ended December 31, 2014.
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 2018, 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.
Customer Contract Amendment
During the second quarter of 2016, the Company amended its arrangements concerning its long-term supply contract with the largest customer of its Australian Thermal Mining segment as a result of the Debtors' Bankruptcy Petitions. Coal under the supply contract is sourced from the Company's Wilpinjong Mine. The Bankruptcy Petitions enabled the customer to exercise their contractual step-in rights to appoint a receiver to operate the mine within the parameters of the agreement; however, the customer has not exercised this right. Under the new arrangements, the Company's subsidiary agreed to post cash collateral of $50.0 million Australian dollars, all of which was posted and is included in "Investments and other assets" in the consolidated balance sheet at December 31, 2016. The subsidiary also agreed to maintain compliance with additional covenants and restrictions, including achieving minimum quarterly cash flow and production volumes in relation to specific forecasted amounts. If these conditions are met, the customer will not exercise their step-in rights to appoint a receiver. The arrangements provide for remedial action where certain covenants are not met; but noncompliance could result in termination of the amended arrangements and enable the customer to exercise step-in rights to appoint a receiver to operate the Wilpinjong Mine. As of March 20, 2017, the Company was in compliance with the covenants and restrictions under the new arrangements.
(23) | 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 20. "Share-Based Compensation."
Peabody Energy Corporation | 2016 Form 10-K | F- 65 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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. 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 0.4 million, 0.6 million and 0.2 million for the years ended December 31, 2016, 2015 and 2014, 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.
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, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In millions, except per share amounts) | |||||||||||
EPS numerator: | |||||||||||
Loss from continuing operations, net of income taxes | $ | (674.3 | ) | $ | (1,813.9 | ) | $ | (749.1 | ) | ||
Less: Net income attributable to noncontrolling interests | 7.9 | 7.1 | 9.7 | ||||||||
Loss from continuing operations attributable to common stockholders, before allocation of earnings to participating securities | (682.2 | ) | (1,821.0 | ) | (758.8 | ) | |||||
Less: Earnings allocated to participating securities | — | — | 1.0 | ||||||||
Loss from continuing operations attributable to common stockholders, after allocation of earnings to participating securities | (682.2 | ) | (1,821.0 | ) | (759.8 | ) | |||||
Loss from discontinued operations attributable to common stockholders, after allocation of earnings to participating securities | (57.6 | ) | (175.0 | ) | (28.2 | ) | |||||
Net loss attributable to common stockholders, after earnings allocated to participating securities | $ | (739.8 | ) | $ | (1,996.0 | ) | $ | (788.0 | ) | ||
EPS denominator: | |||||||||||
Weighted average shares outstanding — basic and diluted | 18.3 | 18.1 | 17.9 | ||||||||
Basic and diluted EPS attributable to common stockholders: | |||||||||||
Loss from continuing operations | $ | (37.30 | ) | $ | (100.34 | ) | $ | (42.52 | ) | ||
Loss from discontinued operations | (3.15 | ) | (9.64 | ) | (1.57 | ) | |||||
Net loss attributable to common stockholders | $ | (40.45 | ) | $ | (109.98 | ) | $ | (44.09 | ) | ||
(24) Management — Labor Relations
On December 31, 2016, the Company had approximately 6,700 employees worldwide, including approximately 5,100 hourly employees; the employee amounts exclude employees that were employed at operations classified as discontinued operations. Approximately 39% of those hourly employees were represented by organized labor unions and were employed by mines that generated 22% of the Company's 2016 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 | 2016 Form 10-K | F- 66 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table presents the Company's active mining operations as of December 31, 2016 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 | |
Wambo Underground (2) | April 2017 | |
North Goonyella | December 2018 | |
Metropolitan (3) | December 2016 | |
Millennium (4) | October 2015 | |
Wilpinjong (5) | May 2016 | |
Coppabella (6) | December 2016 | |
Moorvale (6) | October 2019 | |
(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, 2016. |
(2) | Employees of the Company's Wambo Underground Mine operate under a separate labor agreement. That agreement expired in April 2015. The parties agreed to an initial rollover for 12 months through April 2016 and agreed to a further rollover for another 12 months through April 2017. There were no wage increases for the two rollover periods and there have been no disruptions to the operation of the site as a result of the expiration of the agreement. Hourly employees of this mine comprise approximately 8% of the Company's Australian subsidiaries hourly employees, who generated approximately 10% of the Company's Australian production during the year ended December 31, 2016. |
(3) | Employees of the Company's Metropolitan mine operate under a separate labor agreement, which expired in September 2015. Negotiations progressed to a vote on the Company’s best offer in November 2015, which was rejected by the employees. The parties agreed to hold off on any further negotiations until the Company's emergence from the Chapter 11 Cases, expected to occur in early April 2017. There were no wage increases during this period and there have been no disruptions to the operation of the site as a result of the expiration of the agreement. There is also a Deputy labor agreement which expired in September 2015. The parties agreed to a rollover for 18 months through to December 2016. Negotiations resumed in January 2017 for a new labor agreement. There have been no disruptions to the operations of the site as a result of the expiration of the agreement. Hourly employees of this mine comprise approximately 11% of the Company's Australian subsidiaries hourly employees, who generated approximately 6% of the Company's Australian production during the year ended December 31, 2016. |
(4) | Employees of the Company's Millennium mine operate under a separate labor agreement. Negotiations have been ongoing for an extended period of time, where employees rejected the Company's offers in July 2016 and again in November 2016. After the second unsuccessful vote the Company informed employees it was in the process of applying for the agreement to be terminated. Employees requested the Company to vote again on the second rejected agreement with the intent to accept the offer, 70% of employees voted and accepted the offer late January 2017. The agreement was approved by the Fair Work Commission in early March 2017. Hourly employees of this mine comprise approximately 16% of the Company's Australian subsidiaries hourly employees, who generated approximately 11% of the Company's Australian production during the year ended December 31, 2016. |
(5) | Employees of the Company's Wilpinjong Mine operate under an enterprise agreement. Negotiations to replace the enterprise agreement that nominally expired in May 2016 commenced in April 2016. In January 2017 the workforce formally rejected Wilpinjong’s proposed replacement agreement and good faith negotiations are now continuing. Hourly employees of this mine comprise approximately 18% of the Company's Australian subsidiaries hourly employees, who generated approximately 42% of the Company's Australian production during the year ended December 31, 2016. |
(6) | Employees of the Company's Coppabella/Moorvale Coal Handling and Preparation Plant facility previously operated under a separate enterprise agreement. As a result of the latest negotiation process the Company was successful in its application to terminate the agreement. The negotiations resulted in the Coppabella employees requesting to be employed on individual salaried contracts (rather than a labor agreement) and the Moorvale employees accepted the Company's final offer. The Moorevale agreement expires in October 2019. Hourly employees of this mine comprise approximately 28% of the Company's Australian subsidiaries hourly employees, who generated approximately 13% of the Company's Australian production during the year ended December 31, 2016. |
Peabody Energy Corporation | 2016 Form 10-K | F- 67 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(25) | 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 21, 2017, 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, 2016.
Financial Instruments with Off-Balance Sheet Risk
As of December 31, 2016, the Company had the following financial instruments with off-balance-sheet risk:
Reclamation Bonding Requirements | Coal Lease Obligations | Workers’ Compensation Obligations | Other(1) | Total (2) | Cash Collateral in Support of Financial Instruments | ||||||||||||||||||
(Dollars in millions) | |||||||||||||||||||||||
Self bonding | $ | 1,094.2 | $ | — | $ | — | $ | — | $ | 1,094.2 | $ | — | |||||||||||
Surety bonds (3) | 319.6 | 94.0 | 19.1 | 15.5 | 448.2 | 64.5 | |||||||||||||||||
Bank guarantees | 54.7 | — | — | 24.5 | 79.2 | 83.8 | |||||||||||||||||
Other (4) | 233.2 | — | 42.7 | 118.0 | 393.9 | 233.2 | |||||||||||||||||
Total | $ | 1,701.7 | $ | 94.0 | $ | 61.8 | $ | 158.0 | $ | 2,015.5 | $ | 381.5 | |||||||||||
(1) | Other includes the $37.0 million in letters of credit related to the PBGC, as described below, and an additional $121.0 million in bank guarantees, letters of credit and surety bonds related to road maintenance, performance guarantees and other operations. |
(2) | Letters of credit held as collateral in support of surety bonds at December 31, 2016 were $48.0 million and are not reflected in the table above. |
(3) | A total of $72.6 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 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation". |
(4) | Other under the "Reclamation Bonding Requirements" header represents the amount of reclamation bonding requirements for our Australian Mining operations that were not otherwise supported by bank guarantees. Such amounts were supported by cash collateral held by the applicable state agency. |
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, and which are supported by letters of credit from a commercial bank. On July 1, 2016, $39.9 million of the total $42.7 million of letters of credit supporting the reimbursement obligation to the commercial bank were drawn down to repay the outstanding bonds. As a result, the bonds were retired with the balance of the letters of credit canceled. Refer to Note 22. "Resource Management, Acquisitions and Other Commercial Events" for details related to the Company's divestiture of Dominion Terminal Associates.
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, 2016. 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 68 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Reclamation Bonding
The Company bonds its reclamation requirements using three categories of bonds: surety bonds, collateral bonds or self-bonds. A surety bond is an indemnity agreement in a sum certain payable to the regulatory authority, executed by the permittee as principal and which is supported by the performance guarantee of a surety corporation. A collateral bond can take several forms, including cash, letters of credit, first lien security interest in property or other qualifying investment securities. A self-bond is an indemnity agreement in a sum certain executed by the permittee or by the permittee and any corporate guarantor made payable to the regulatory authority.
Our total reclamation bonding requirements in the U.S. were $1,413.8 million as of December 31, 2016. The bond requirements represent the calculated cost to reclaim the current operations of a mine if it ceased to operate in the current period. The cost calculation for each bond must be completed according to the regulatory authority of each state. Our asset retirement obligations calculated in accordance with GAAP for our U.S. operations was $471.1 million as of December 31, 2016. The bond requirement amount for our U.S. operations significantly exceeds the financial liability for final mine reclamation because the financial liability is discounted from the end of the mine’s economic life to the balance sheet date in recognition of the economic reality that the final reclamation obligation is a number of years (and in some cases decades) away. The bond amount, in contrast with the asset retirement obligation, presumes reclamation begins immediately. In Australia, we generally used bank guarantees to satisfy our financial assurance requirements related to reclamation. Those bank guarantees allowed the issuer to request collateral, which was provided in the forms of letters of credit. Subsequent to the petition date, some of the bank guarantee issuers drew on a portion of those letters of credit and subsequently canceled the bank guarantees, which resulted in the cash collateral being transferred to the applicable state agency. The total cash collateral held in relation to the Company's Australian reclamation obligations was $233.2 million at December 31, 2016 and was included in "Investments and other assets" due to the long-term nature of the underlying obligations. The Company's asset retirement obligations calculated in accordance with GAAP for its Australian operations was $287.7 million as of December 31, 2016.
During August and September 2016, the Bankruptcy Court approved four motions for Stipulations and Orders (collectively, the Stipulations) regarding settlement agreements with the states of Wyoming, New Mexico, Indiana, and Illinois. The Stipulations provide the relevant state authorities with additional financial assurance for the Company’s performance of its reclamation bonding requirements by entitling them to (i) claims in the Chapter 11 Cases that have priority over all administrative expenses of the kind specified in section 503(b) of the Bankruptcy Code for the specified values set forth in the Stipulations and (ii) in the cases of Wyoming, Indiana and Illinois, $0.8 million, $7.5 million and $3.2 million, respectively, in letters of credit or surety bonds related to closed mining operations, together not to exceed the full amount of the $200 million bonding accommodation facility provided for in the DIP Credit Agreement. Each state received financial assurances equal to approximately 17.5% of the Company's prepetition reclamation bond amount with the relevant state. In addition to providing supplemental financial assurances to these states, the Company has agreed to, among other things, quarterly reclamation activity status meetings as well as targeting reductions in the amount of bonds outstanding with these states. Pursuant to the Stipulations, the states will effectively deem the Company’s bonding requirements satisfied for the pendency of the Chapter 11 Cases.
As previously disclosed, the Company's ability to self-bond reduces the Company's costs of securing reclamation bonding requirements and enhances liquidity to the extent alternate forms of bonding would require the Company to post collateral. To the extent the Company is unable to maintain its current level of self-bonding following the conclusion of the Chapter 11 Cases for any reason, the Company would be required to obtain replacement financial assurances or security. Further, self-bonding is permitted at the discretion of each state. As of December 31, 2016, the Company was self-bonded in Illinois, Indiana, New Mexico and Wyoming. As a condition precedent to the occurrence of the Effective Date of the Plan, the Company was required to put in place mutually acceptable forms of bonding for coal mine reclamation requirements in those states subsequent to the Effective Date. On March 6, 2017, the Debtors notified the Bankruptcy Court that the Company had determined to secure all of its coal mine reclamation obligations, including those in Illinois, Indiana, New Mexico and Wyoming, by arranging for approximately $1.3 billion in surety bonds.
Accounts Receivable Securitization
On March 25, 2016, the Company amended and restated its accounts receivable securitization program (securitization program) to, among other things, extend the term of the program by two years to March 23, 2018 and reduce the maximum availability under the facility from $275.0 million to $180.0 million. The accessible capacity of the program varies daily, dependent upon the actual amount of receivables available for contribution and various reserves and limits. As of December 31, 2016, $40.5 million was deposited in a collateral account to secure obligations under the facility.
Peabody Energy Corporation | 2016 Form 10-K | F- 69 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Under the securitization program, the Company contributes the trade receivables of most of its U.S. subsidiaries on a revolving basis to its wholly-owned, bankruptcy-remote subsidiary (Seller), which then sells the receivables in their entirety to 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 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, 2016, the Company received total consideration of $2,859.9 million related to accounts receivable sold under the securitization program, including $1,541.7 million of cash up front from the sale of the receivables, an additional $1,155.3 million of cash upon the collection of the underlying receivables and $162.9 million that had not been collected at December 31, 2016 and was recorded at carrying value, which approximates fair value. There was no reduction in accounts receivable as a result of securitization activity with the Conduits at December 31, 2016 and a $168.5 million reduction at December 31, 2015.
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 $8.2 million, $1.8 million and $1.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.
With the approval of the Bankruptcy Court, the Company executed two additional amendments to the March 25, 2016 agreement during the second quarter of 2016. These amendments permit the continuation of the securitization program through the Company’s Chapter 11 Cases, change the maturity date to the earlier of March 23, 2018 or the emergence of the Company from the Chapter 11 Cases, revise the associated fees, and enter into an additional performance guarantee by the Company’s subsidiaries that are contributors under the securitization facility to fulfill the obligations of the other contributors.
On January 27, 2017, the Company and P&L Receivables Company, LLC (P&L Receivables) obtained a commitment letter (Commitment Letter) from PNC Bank, National Association (PNC), pursuant to which, in connection with the consummation of the Plan, PNC has agreed to amend the existing securitization facility evidenced by the Fifth Amended and Restated Receivables Purchase Agreement, dated as of March 25, 2016 (as amended prior to the date hereof), among P&L Receivables, as the seller, the Company, as the servicer, the sub-servicers party thereto, the various purchasers and purchaser agents party thereto and PNC, as administrator, in order to, among other things, (i) increase the purchase limit to an amount not to exceed $250,000,000 (the Purchase Limit), (ii) extend the facility termination date, and (iii) consider adding certain Australian subsidiaries of the Company as originators (as so amended, the Sixth Amended Securitization Facility).
The commitment of PNC to provide 100% of the Purchase Limit under the Sixth Amended Securitization Facility is subject to certain conditions set forth in the Commitment Letter, including but not limited to the occurrence or waiver of all conditions precedent to the effectiveness of the Plan.
The Commitment Letter will terminate upon the occurrence of certain events described therein. The outside termination date for the Commitment Letter is May 1, 2017.
On January 27, 2017, the Debtors filed a motion with the Bankruptcy Court seeking authorization to enter into and perform under the Commitment Letter. On February 15, 2017, the Bankruptcy Court issued an order authorizing the Company’s entry into and performance under the Commitment Letter
Restricted Cash
As of December 31, 2016, the Company had balance sheet-reflected restricted cash of $54.3 million, primarily related to the collateral under its securitization program and various other obligations. The company also had restricted cash held as collateral for financial assurances associated with reclamation and other obligations of $71.4 million as of December 31, 2016 included in "Investments and other assets" due to the long-term nature of the underlying obligations.
Peabody Energy Corporation | 2016 Form 10-K | F- 70 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other
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.
(26) | Commitments and Contingencies |
Commitments
Unconditional Purchase Obligations
As of December 31, 2016, purchase commitments for capital expenditures were $7.4 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 26 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, 2016, these Australian and U.S. commitments under take-or-pay arrangements totaled $1.6 billion, of which approximately $210 million is obligated within the next year.
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, 2016, 2015 and 2014 pursuant to the two associated federal coal leases. The payments for these leases are now complete.
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 a true-up payment during the year ended December 31, 2014 and the cash receipt was 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 the final true up payment was not received. On February 19, 2016 the Company filed a claim in Alpha’s bankruptcy. Additionally, on April 15, 2016 the Company filed an objection to the potential assumption and assignment of the lease exchange agreement and to the cure amount. On October 16, 2016 the Company entered into a settlement agreement with Alpha and Contura Wyoming Land, LLC allowing the claim in the full amount of the true-up payment and resolving other issues between the parties. The settlement agreement was approved by the Bankruptcy Court on December 14, 2016.
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.
Peabody Energy Corporation | 2016 Form 10-K | F- 71 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.
Effect of Automatic Stay. The Debtors filed voluntary petitions for relief under the Bankruptcy Code on the Petition Date in the Bankruptcy Court. Each of the Debtors continues to operate its business and manage its property as a debtor-in-possession pursuant to Sections 1107 and 1108 of the Bankruptcy Code. Subject to certain exceptions under the Bankruptcy Code, the filing of the Debtors’ Chapter 11 Cases, pursuant to Section 362(a) of the Bankruptcy Code, automatically enjoined, or stayed, among other things, the continuation of most judicial or administrative proceedings or the filing of other actions against or on behalf of the Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date or to exercise control over property of the Debtors’ bankruptcy estates, unless and until the Bankruptcy Court modifies or lifts the automatic stay as to any such claim. Notwithstanding the general application of the automatic stay described above, governmental authorities may determine to continue actions brought under their police and regulatory powers.
The Debtors have filed notices of the bankruptcy filings and suggestions of stay in the applicable matters involving one or more of the Debtors as discussed below and in Note 27. "Matters Related to the Bankruptcy of Patriot Coal Corporation". The Company expects that the Chapter 11 Cases will impact the liabilities of the Debtors described below and in Note 27, as well as certain other contingent liabilities the Debtors may have. For example, if a contingent litigation liability of the Debtors is ultimately allowed as a prepetition "claim" under the Bankruptcy Code, that claim would be subject to the applicable treatment set forth in the Plan and be discharged pursuant to the terms of the Plan. However, until the Plan becomes effective, there can be no certainty as to how such liabilities will be impacted.
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.
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.
Peabody Energy Corporation | 2016 Form 10-K | F- 72 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.
In September 2016, a settlement was reached under which the Company agreed to pay $13.0 million Australian dollars ($9.9 million USD) to QBH in a full and final settlement of all claims each party had against the other in relation to the CPSA litigation. A deed of settlement was executed by the parties and the settlement amount was paid to QBH on September 30, 2016. This matter has concluded.
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 Peabody Energy Corporation (PEC), 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 and seeks monetary damages 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 relevant boards of directors 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.
Plaintiffs filed a second amended complaint on March 11, 2016 that included 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 second amended complaint also added the three committees responsible for administering the three 401(k) retirement plans at issue and dropped several individual defendants, including current directors of PEC's board of directors. As a result of filing the Chapter 11 Cases, the plaintiffs voluntarily dismissed the three Debtor defendants (PEC, PIC and PHC) and elected to proceed against the individual defendants and the three named committees with the second amended complaint. On November 17, 2016, the parties presented arguments on the defendants’ motion to dismiss. A ruling has not yet been issued.
CNTA Dispute. On May 20, 2016, the Company filed a complaint and a request for declaratory judgment in the Bankruptcy Court against Citibank, N.A. (in its capacity as Administrative Agent under the Company’s 2013 Credit Facility), among others, regarding the extent of certain collateral and secured claims of certain prepetition creditors. On June 13, 2016, Citibank, N.A. filed an answer and counter-claim for declaratory judgment. On June 14, 2016, two motions to intervene were filed, one from the Creditors' Committee and another from a group of creditors holding $1.65 billion in face value of the Company's Senior Notes (as indicated in their motion). On June 20, 2016, the Bankruptcy Court entered an order granting the Debtors' motion requesting that the Bankruptcy Court direct all parties to the proceeding to participate in non-binding mediation. The intervention motions were granted on July 7, 2016. On October 7, 2016, a group of creditors holding approximately $287.4 million in face value of the Company’s Senior Secured Second Lien Notes (as indicated in their motion) filed a motion to intervene. The Bankruptcy Court heard oral arguments related to the parties’ motions for summary judgment on September 12, 2016 and subsequently vacated the previously scheduled trial dates and deferred ruling on the matter while the parties continued with mediation. Mediation and negotiation with certain creditors resulted in a settlement of the CNTA Dispute, which is reflected in the economic terms of the Plan, including the treatment of the holders of allowed secured and unsecured claims.
APS/PacifiCorp Litigation. The Arizona Public Service Company (APS) and PacifiCorp filed a motion in the Bankruptcy Court seeking authorization to allow it to terminate a coal supply agreement, which accounts for approximately half of the Company's El Segundo Mine sales volume. The Company filed a complaint for APS’s and PacifiCorp’s violation of the automatic stay applicable to the Chapter 11 Cases and breach of the coal supply agreement. In September 2016, the parties engaged in a court-ordered mediation. The parties continued to engage in mediation in December 2016 and January 2017. On January 8, 2017 the parties entered into a Settlement Term Sheet outlining a settlement in principle (Settlement Term Sheet). On January 17, 2017, the Company filed a Motion Of The Debtors And Debtors In Possession, Pursuant To Bankruptcy Rule 9019 And Section 365 Of The Bankruptcy Code, For Entry Of An Order (I) Approving A Settlement Agreement With APS and PacifiCorp, (II) Authorizing The Assumption Of The Coal Supply Agreement, As Amended and (III) Granting Related Relief. On January 27, 2017 the Bankruptcy Court entered its order approving the Settlement Term Sheet and authorizing the parties to enter into a settlement agreement and amendment to the coal supply agreement. The parties entered into a settlement agreement and an amendment to the coal supply agreement on February 3, 2017.
Peabody Energy Corporation | 2016 Form 10-K | F- 73 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Berenergy Corporation. The Company has been in a legal dispute with Berenergy Corporation (Berenergy) regarding Berenergy’s access to certain of its underground oil deposits beneath the Company's North Antelope Rochelle Mine and contiguous undisturbed areas. The Company believes that any claims related to this matter constitute prepetition claims. On October 13, 2016, the Sixth Judicial Court in the state of Wyoming (Wyoming Court) entered an order (Wyoming Court Decision) allowing the Company the right to mine through certain wells owned by Berenergy but required the Company to compensate Berenergy for damages of $0.9 million, which the Company has accrued as of December 31, 2016. Further, the Wyoming Court ruled that should Berenergy obtain approval from the Wyoming Oil and Gas Conservation Commission (the Commission) to recover certain secondary deposits beneath the mine’s contiguous undisturbed areas, the Company would be liable to Berenergy for the cost of certain special procedures and equipment required to access the secondary deposits remotely from outside the Company's mine area, which has been estimated as $13.1 million by Berenergy. The Company believes it is not probable that the Commission will approve access to the secondary deposits based on the Company's view of a lack of economic feasibility and certain restrictions on Berenergy's legal claim to the deposits. Based upon these factors, the Company has not accrued a liability related to the secondary deposits as of December 31, 2016. On November 22, 2016, the Bankruptcy Court entered an order granting Berenergy limited relief from the automatic stay to pursue an appeal of the Wyoming Court Decision with the Wyoming Supreme Court. On December 21, 2016, Berenergy filed a Notice of Appeal with the Wyoming Supreme Court of the Wyoming Court Decision. On January 5, 2017, Peabody filed a Notice of Cross-Appeal with the Wyoming Supreme Court of the Wyoming Court Decision.
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 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 PEC despite the fact that Gold Fields had no ongoing operations and PEC had no prior involvement in the past operations of Gold Fields. Gold Fields is currently one of PEC's subsidiaries. As part of separate transactions, both PEC and Gold Fields also agreed to indemnify Blue Tee with respect to certain claims relating to the historical operations of a predecessor of Blue Tee, which is a former affiliate of Gold Fields. Neither PEC nor Gold Fields had any involvement with the past operations of the Blue Tee predecessor.
Pursuant to the indemnity, Blue Tee has tendered its environmental claims for remediation, past cost and future costs and/or natural resource damages (Blue Tee Liabilities) to Gold Fields. Although Gold Fields has paid remediation costs as a result of the indemnification obligations, Blue Tee has been identified as a potentially responsible party (PRP) at various designated national priority list (NPL) sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and similar statutes. Of these sites where Blue Tee has been identified as a PRP, neither Gold Fields nor PEC is a party to any cleanup orders relating to the operations of Blue Tee’s predecessor. In addition to the NPL sites, Blue Tee has been named a PRP at multiple other sites, where Gold Fields has either paid remediation costs or settled the environmental claims on behalf of Blue Tee. As a result of filing the Chapter 11 Cases, Gold Fields has now stopped paying these remediation costs.
Environmental assessments for remediation, past and future costs and/or natural resource damages also have been asserted by the EPA and natural resources trustees against Gold Fields related to historical activities of Gold Fields’ predecessor. Gold Fields has been identified as a PRP at four NPL sites and has been conducting response actions or working with the EPA to resolve past cost recovery claims at these sites pursuant to cleanup orders or other negotiations. As a result of filing the Chapter 11 Cases, Gold Fields has ceased its response actions and other engagements with the EPA at these sites.
Undiscounted liabilities for environmental cleanup-related costs relating to (i) the contractual indemnification obligations owed to Blue Tee and (ii) for the sites noted above for which Gold Fields has been identified as a PRP as a result of the operations of its predecessor, are collectively estimated to be $62.8 million and $66.9 million as of December 31, 2016 and 2015, respectively, in the consolidated balance sheets. The majority of these estimated costs relate to Blue Tee site liabilities.
Prior to the August 19, 2016 bar date for filing claims in the Chapter 11 Cases, Blue Tee filed an unliquidated, general unsecured claim in the amount of $65.6 million against Gold Fields regarding the Blue Tee Liabilities, additional unliquidated claims in an unknown amount in excess of $150 million at known sites, and further contingent claims at known and unknown sites, including natural resources damages (NRDs) claims alleged, without explanation, to be in the range of $500 million. On November 17, 2016 Blue Tee amended its claim to increase the amount of the claim to $1.2 billion. PEC and Gold Fields believe that these claims significantly overstate any liabilities that may exist for remediation costs or potential NRDs.
Peabody Energy Corporation | 2016 Form 10-K | F- 74 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Prior to the October 11, 2016 government bar date for filing claims in the Chapter 11 Cases, several governmental entities including the EPA, the Department of the Interior and several states filed unliquidated, secured and general unsecured claims against PEC and Gold Fields. These claims total in excess of $2.7 billion and allege damages for past and future remediation costs as well as for alleged NRDs at several sites. As noted in the claims, many of the claims are duplicative as they overlap with each other as well as with claims made by Blue Tee. Additionally, PEC and Gold Fields believe the claims significantly overstate any liabilities that may exist for remediation costs or potential NRDs.
On January 27, 2017, PEC filed objections to claims filed by the U.S. Department of Interior, the U.S. Department of Justice and the EPA (collectively the PEC Objections). The PEC Objections dispute that Peabody Energy Corporation has liability to the claimant under applicable federal environmental statutes for the Blue Tee sites listed in the claims based on the fact that Peabody Energy Corporation never owned any of the sites or disposed or arranged for the disposal of hazardous substances at any of the sites.
On February 2, 2017, Gold Fields filed objections to claims filed by the State of Oklahoma, the State of Missouri, the Kansas Department of Health and Environment and the U.S. Department of Interior, the EPA, the Kansas Department of Health and Environment, the Illinois Department of Natural Resources and the Missouri Department of Natural Resources (collectively the Gold Fields Objections). The Gold Fields Objections dispute that Gold Fields has liability to the claimant under applicable federal and state environmental statutes for the Blue Tee sites listed in the claims based on the fact that Gold Fields never owned any of the sites or disposed or arranged for the disposal of hazardous substances at any of the sites.
On March 16, 2017, the Debtors agreed to settle the objections to the Plan filed by Blue Tee and several government entities in the Chapter 11 Cases. Under the settlements, the Debtors will (1) not seek to recover federal tax refunds owed to Debtors in the amount of approximately $11 million; (2) transfer $12 million of insurance settlement proceeds from Century and Pacific Employers Insurance Company relating to environmental liabilities to the Gold Fields Liquidating Trust (as described in the Plan); and (3) pay $20 million to the Gold Fields Liquidating Trust on or around the Plan Effective Date. On March 16 and 17, 2017, the Bankruptcy Court entered orders approving these settlements. The Debtors and government entities intend to enter into settlement agreements to reflect the above.
Other
At times the Company becomes a party to other disputes, including those related to contract miner performance, claims, lawsuits, arbitration proceedings, regulatory investigations 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.
(27) | 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 provided certain credit support to Patriot. The Company has recorded $20.9 million of credit support provided to Patriot as a liability on the Company's consolidated balance sheet as of December 31, 2016, of which $15.7 million was supported by letters of credit.
Due to Patriot’s May 2015 bankruptcy filing, the Company recorded a net charge during the year ended December 31, 2015 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 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 considered 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.
Peabody Energy Corporation | 2016 Form 10-K | F- 75 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.
By statute, the Company had secondary liability 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 amount of the liability at December 31, 2016 was $123.3 million. While the Company has recorded a liability, it intends to review each claim on a case-by-case basis and contest liability estimates as appropriate. 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. 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 paid $0.7 million related to these liabilities during 2016.
The Company's accounting for the black lung liabilities related to Patriot is based on an interpretation of applicable statutes. Management believes that there exist inconsistencies among the applicable statutes, regulations promulgated under those statutes and the Department of Labor’s interpretative guidance. The Company may seek clarification from the Department of Labor regarding these inconsistencies and the accounting for these liabilities could change in the future depending on the Department of Labor’s responses to inquiries.
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 to the Combined Fund for the approximately $40 million of its subsidiaries' obligations 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. During the year ended December 31, 2016, the Company recorded an additional charge of $1.2 million. The Company paid $2.6 million into the fund during 2016 and 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. The liability related to the fund was $22.7 million at December 31, 2016.
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.
Peabody Energy Corporation | 2016 Form 10-K | F- 76 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The parties agreed to a subsequent settlement of the Company’s obligations for payment of the remaining VEBA payments (2016 Settlement Agreement), 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 were due at the beginning of each successive month ending October 2016, and the obligations were supported in full by a letter of credit. As a result of the Company’s Chapter 11 Cases, the Company’s remaining obligations to the VEBA under the 2016 Settlement Agreement were being satisfied by monthly draws on the letter of credit by the VEBA trustees. As part of the settlement, the Company recognized a gain of $68.1 million during the year ended December 31, 2016, which was classified in "Operating costs and expenses" in the consolidated statements of operations and is included in the Company's Corporate and Other segment results.
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 (UMWA Plan) Litigation
On July 16, 2015, a lawsuit was filed by the UMWA Plan, the UMWA 1974 Pension Trust (Trust) and the Trustees of the UMWA Plan and Trust (Trustees) in the United States District Court for the District of Columbia, against PEC, PHC, a subsidiary of the Company, and Arch Coal, Inc. (Arch). The plaintiffs sought, pursuant to ERISA and the Multiemployer Pension Plan Amendments Act of 1980 (MPPAA), a declaratory judgment that the defendants were 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' lawsuit claimed that the defendants' withdrawal liability would result in at least $767 million owed to the UMWA Plan. After a comprehensive legal and arbitration process and with the approval of the Bankruptcy Court, on January 25, 2017, the UMWA Plan and the Debtors agreed to a settlement of the claim whereby the UMWA Plan will be entitled to $75 million to be paid by the Company as follows: $5 million upon the Plan Effective Date, $10 million paid 90 days after the Plan Effective Date, $15 million paid one year after the previous payment and $15 million per year for the following 3 years. In exchange, the UMWA Plan will release PEC and all members of the PEC control group (as defined under ERISA) from any cause of action regarding withdrawal liability. In connection with the settlement, the Company recorded a liability representing the present value of the installments of $54.3 million at December 31, 2016 and recognized an equivalent charge to "Loss from discontinued operations, net of income taxes" in the consolidated statement of operations for the year ended December 31, 2016.
Peabody Energy Corporation | 2016 Form 10-K | F- 77 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(28) | Summary of Quarterly Financial Information (Unaudited) |
A summary of the unaudited quarterly results of operations for the years ended December 31, 2016 and 2015 is presented below.
Year Ended December 31, 2016 | |||||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
(In millions, except per share data) | |||||||||||||||
Revenues | $ | 1,027.2 | $ | 1,040.2 | $ | 1,207.1 | $ | 1,440.8 | |||||||
Operating loss | (102.7 | ) | (107.7 | ) | (21.6 | ) | (44.9 | ) | |||||||
Loss from continuing operations, net of income taxes | (161.7 | ) | (230.8 | ) | (95.6 | ) | (186.2 | ) | |||||||
Net loss | (165.1 | ) | (233.8 | ) | (133.7 | ) | (199.3 | ) | |||||||
Net loss attributable to common stockholders | (165.1 | ) | (235.5 | ) | (135.5 | ) | (203.7 | ) | |||||||
Basic and diluted EPS — continuing operations(1) | $ | (8.85 | ) | $ | (12.71 | ) | $ | (5.32 | ) | $ | (10.42 | ) | |||
Weighted average shares used in calculating basic and diluted EPS | 18.3 | 18.3 | 18.3 | 18.3 | |||||||||||
(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 first quarter and second quarter of 2016 reflected $26.4 million and $10.3 million of debt restructuring costs, respectively. Operating loss for the first and fourth quarters of 2016 included $17.2 million and $230.7 million of asset impairment costs, respectively, primarily driven by the impairment of Metropolitan Mine to reflect estimated selling price. The operating loss for the second quarter of 2016 included net gain on disposal of assets of $13.7 million, primarily driven by net gains on sale of the Olive Downs South tenements and participation interest in Prairie State Energy Campus of $2.8 million and $6.2 million, respectively. Operating loss for the fourth quarter of 2016 included income from equity affiliates of $28.8 million, due to favorable coal pricing at Middlemount. Loss from continuing operations, net of income taxes for the first quarter included $126.2 million of interest expense, while the following three quarters experienced significant decreases in interest expense due to bankruptcy filing and stay of interest payments. Loss from continuing operations, net of income taxes for the second, third and fourth quarters of 2016 reflected $95.4 million, $29.7 million and $33.9 million of reorganization items, net due to bankruptcy filing and ongoing chapter 11 cases, respectively. Loss from continuing operations, net of income taxes for the fourth quarter of 2016 included a loss on debt extinguishment of $29.5 million resulting from the repayment of debtor-in-possession term loan. Loss from discontinued operations, net of income for the third and fourth quarters reflected $38.1 million and $13.1 million of Patriot bankruptcy related charges associated with black lung liabilities and the UMWA Combined Benefit fund, respectively.
Peabody Energy Corporation | 2016 Form 10-K | F- 78 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.
(29) | Segment and Geographic Information |
The Company 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.
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 include 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 mid-range sulfur content and Btu. 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 U.S. Mining operations mine both bituminous and sub-bituminous coal deposits.
Peabody Energy Corporation | 2016 Form 10-K | F- 79 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 metallurgical and 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. The Company’s 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 coking coal and low-volatile pulverized coal injection coal. The Company's 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. 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 its 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 chief operating decision maker 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 and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items, which are reflected in the reconciliation below, that management excluded in analyzing the segments' operating performance. 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, 2016 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 | $ | 1,473.3 | $ | 792.5 | $ | 526.0 | $ | 1,090.4 | $ | 824.9 | $ | (10.9 | ) | $ | 19.1 | $ | 4,715.3 | ||||||||||||||
Adjusted EBITDA | 379.9 | 217.3 | 101.6 | (16.3 | ) | 217.6 | (72.2 | ) | (335.7 | ) | 492.2 | ||||||||||||||||||||
Additions to property, plant, equipment and mine development | 33.0 | 18.7 | 20.8 | 29.9 | 22.1 | — | 2.1 | 126.6 | |||||||||||||||||||||||
Federal coal lease expenditures | 248.4 | — | 0.6 | — | — | — | — | 249.0 | |||||||||||||||||||||||
Income from equity affiliates | — | — | — | — | — | — | (16.2 | ) | (16.2 | ) | |||||||||||||||||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 80 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 | |||||||||||||||||||||||
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 | |||||||||||||||||||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 81 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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, 2016 were as follows:
U.S. Mining | Australian Mining | Trading and Brokerage | Corporate and Other | Consolidated | |||||||||||||||
(Dollars in millions) | |||||||||||||||||||
Total assets | $ | 4,255.9 | $ | 5,402.2 | $ | 128.7 | $ | 1,990.9 | $ | 11,777.7 | |||||||||
Property, plant, equipment and mine development, net | 3,970.6 | 3,905.8 | 0.2 | 900.1 | 8,776.7 | ||||||||||||||
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 | $ | 4,105.8 | $ | 5,319.9 | $ | 217.2 | $ | 1,304.0 | $ | 10,946.9 | |||||||||
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 | ||||||||||||||
A reconciliation of consolidated loss from continuing operations, net of income taxes to Adjusted EBITDA follows:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(Dollars in millions) | |||||||||||
Loss from continuing operations, net of income taxes | $ | (674.3 | ) | $ | (1,813.9 | ) | $ | (749.1 | ) | ||
Depreciation, depletion and amortization | 465.4 | 572.2 | 655.7 | ||||||||
Asset retirement obligation expenses | 41.8 | 45.5 | 81.0 | ||||||||
Selling and administrative expenses related to debt restructuring | 21.5 | — | — | ||||||||
Asset impairment | 247.9 | 1,277.8 | 154.4 | ||||||||
Change in deferred tax asset valuation allowance related to equity affiliates | (7.5 | ) | (1.0 | ) | 52.3 | ||||||
Amortization of basis difference related to equity affiliates | — | 4.9 | 5.7 | ||||||||
Interest expense | 298.6 | 465.4 | 426.6 | ||||||||
Loss on early debt extinguishment | 29.5 | 67.8 | 1.6 | ||||||||
Interest income | (5.7 | ) | (7.7 | ) | (15.4 | ) | |||||
Reorganization items, net | 159.0 | — | — | ||||||||
Income tax (benefit) provision | (84.0 | ) | (176.4 | ) | 201.2 | ||||||
Total Adjusted EBITDA | $ | 492.2 | $ | 434.6 | $ | 814.0 | |||||
Peabody Energy Corporation | 2016 Form 10-K | F- 82 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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, | ||||||||
2016 | 2015 | 2014 | ||||||
U.S. | 54.7 | % | 57.4 | % | 59.5 | % | ||
Japan | 6.9 | % | 8.1 | % | 9.5 | % | ||
China | 5.4 | % | 7.1 | % | 6.1 | % | ||
South Korea | 1.5 | % | 4.1 | % | 5.2 | % | ||
Other | 31.5 | % | 23.3 | % | 19.7 | % | ||
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.
(30) | 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 | 2016 Form 10-K | F- 83 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Year Ended December 31, 2016 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(Dollars in millions) | |||||||||||||||||||
Total revenues | $ | — | $ | 2,830.0 | $ | 2,189.8 | $ | (304.5 | ) | $ | 4,715.3 | ||||||||
Costs and expenses | |||||||||||||||||||
Operating costs and expenses (exclusive of items shown separately below) | 172.9 | 2,172.4 | 2,066.8 | (304.5 | ) | 4,107.6 | |||||||||||||
Depreciation, depletion and amortization | — | 217.4 | 248.0 | — | 465.4 | ||||||||||||||
Asset retirement obligation expenses | — | 15.8 | 26.0 | — | 41.8 | ||||||||||||||
Selling and administrative expenses | 12.8 | 126.5 | 14.1 | — | 153.4 | ||||||||||||||
Restructuring charges | — | 11.9 | 3.6 | — | 15.5 | ||||||||||||||
Other operating (income) loss: | |||||||||||||||||||
Net gain on disposal of assets | — | (21.4 | ) | (1.8 | ) | — | (23.2 | ) | |||||||||||
Asset impairment | — | 37.5 | 210.4 | — | 247.9 | ||||||||||||||
Loss from equity affiliates and investment in subsidiaries | 185.0 | 4.5 | (20.7 | ) | (185.0 | ) | (16.2 | ) | |||||||||||
Interest expense | 288.6 | 19.6 | 24.4 | (34.0 | ) | 298.6 | |||||||||||||
Loss on early debt extinguishment | 29.5 | — | — | — | 29.5 | ||||||||||||||
Interest income | (0.2 | ) | (4.8 | ) | (34.7 | ) | 34.0 | (5.7 | ) | ||||||||||
Reorganization items, net | 73.4 | 82.1 | 3.5 | — | 159.0 | ||||||||||||||
(Loss) income from continuing operations before income taxes | (762.0 | ) | 168.5 | (349.8 | ) | 185.0 | (758.3 | ) | |||||||||||
Income tax (benefit) provision | (84.6 | ) | (11.0 | ) | 11.6 | — | (84.0 | ) | |||||||||||
(Loss) income from continuing operations, net of income taxes | (677.4 | ) | 179.5 | (361.4 | ) | 185.0 | (674.3 | ) | |||||||||||
(Loss) income from discontinued operations, net of income taxes | (62.4 | ) | (0.1 | ) | 4.9 | — | (57.6 | ) | |||||||||||
Net (loss) income | (739.8 | ) | 179.4 | (356.5 | ) | 185.0 | (731.9 | ) | |||||||||||
Less: Net income attributable to noncontrolling interests | — | — | 7.9 | — | 7.9 | ||||||||||||||
Net (loss) income attributable to common stockholders | $ | (739.8 | ) | $ | 179.4 | $ | (364.4 | ) | $ | 185.0 | $ | (739.8 | ) | ||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 84 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 | $ | — | $ | 3,535.3 | $ | 2,535.3 | $ | (461.4 | ) | $ | 5,609.2 | ||||||||
Costs and expenses | |||||||||||||||||||
Operating costs and expenses (exclusive of items shown separately below) | 436.6 | 2,782.6 | 2,249.9 | (461.4 | ) | 5,007.7 | |||||||||||||
Depreciation, depletion and amortization | — | 249.7 | 322.5 | — | 572.2 | ||||||||||||||
Asset retirement obligation expenses | — | 13.2 | 32.3 | — | 45.5 | ||||||||||||||
Selling and administrative expenses | 32.1 | 132.6 | 11.7 | — | 176.4 | ||||||||||||||
Restructuring charges | (3.9 | ) | 11.4 | 16.0 | — | 23.5 | |||||||||||||
Other operating (income) loss: | |||||||||||||||||||
Net gain on disposal of assets | (2.3 | ) | (29.8 | ) | (12.9 | ) | — | (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 | 19.6 | 24.7 | (47.3 | ) | 465.4 | |||||||||||||
Loss on early debt extinguishment | 67.8 | — | — | — | 67.8 | ||||||||||||||
Interest income | (14.0 | ) | (2.4 | ) | (38.6 | ) | 47.3 | (7.7 | ) | ||||||||||
(Loss) income from continuing operations before income taxes | (1,918.6 | ) | 42.9 | (1,048.5 | ) | 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 | ) | 151.1 | (1,067.7 | ) | 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 | ) | 152.7 | (1,079.5 | ) | 933.9 | (1,988.9 | ) | |||||||||||
Less: Net income attributable to noncontrolling interests | — | 0.8 | 6.3 | — | 7.1 | ||||||||||||||
Net (loss) income attributable to common stockholders | $ | (1,996.0 | ) | $ | 151.9 | $ | (1,085.8 | ) | $ | 933.9 | $ | (1,996.0 | ) | ||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 85 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 | $ | — | $ | 4,063.8 | $ | 3,311.7 | $ | (583.3 | ) | $ | 6,792.2 | ||||||||
Costs and expenses | |||||||||||||||||||
Operating costs and expenses (exclusive of items shown separately below) | 49.6 | 3,121.9 | 3,128.7 | (583.3 | ) | 5,716.9 | |||||||||||||
Depreciation, depletion and amortization | — | 271.0 | 384.7 | — | 655.7 | ||||||||||||||
Asset retirement obligation expenses | — | 23.2 | 57.8 | — | 81.0 | ||||||||||||||
Selling and administrative expenses | 46.8 | 161.1 | 19.2 | — | 227.1 | ||||||||||||||
Restructuring and pension settlement charges | — | 26.0 | — | — | 26.0 | ||||||||||||||
Other operating (income) loss: | |||||||||||||||||||
Net gain on disposal of assets | — | (17.7 | ) | (23.7 | ) | — | (41.4 | ) | |||||||||||
Asset impairment | 4.7 | 63.3 | 86.4 | — | 154.4 | ||||||||||||||
Loss from equity affiliates and investment in subsidiaries | 128.5 | 7.6 | 100.0 | (128.5 | ) | 107.6 | |||||||||||||
Interest expense | 423.1 | 19.5 | 34.3 | (50.3 | ) | 426.6 | |||||||||||||
Loss on early debt extinguishment | 1.6 | — | — | — | 1.6 | ||||||||||||||
Interest income | (15.3 | ) | (2.9 | ) | (47.5 | ) | 50.3 | (15.4 | ) | ||||||||||
(Loss) income from continuing operations before income taxes | (639.0 | ) | 390.8 | (428.2 | ) | 128.5 | (547.9 | ) | |||||||||||
Income tax provision | 116.4 | 23.7 | 61.1 | — | 201.2 | ||||||||||||||
(Loss) income from continuing operations, net of income taxes | (755.4 | ) | 367.1 | (489.3 | ) | 128.5 | (749.1 | ) | |||||||||||
(Loss) income from discontinued operations, net of income taxes | (31.6 | ) | (7.2 | ) | 10.6 | — | (28.2 | ) | |||||||||||
Net (loss) income | (787.0 | ) | 359.9 | (478.7 | ) | 128.5 | (777.3 | ) | |||||||||||
Less: Net income attributable to noncontrolling interests | — | 5.2 | 4.5 | — | 9.7 | ||||||||||||||
Net (loss) income attributable to common stockholders | $ | (787.0 | ) | $ | 354.7 | $ | (483.2 | ) | $ | 128.5 | $ | (787.0 | ) | ||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 86 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31, 2016 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(Dollars in millions) | |||||||||||||||||||
Net (loss) income | $ | (739.8 | ) | $ | 179.4 | $ | (356.5 | ) | $ | 185.0 | $ | (731.9 | ) | ||||||
Other comprehensive income (loss), net of income taxes: | |||||||||||||||||||
Net unrealized gains on cash flow hedges (net of $85.9 tax provision) | |||||||||||||||||||
(Decrease) increase in fair value of cash flow hedges | — | — | — | — | — | ||||||||||||||
Reclassification for realized losses included in net (loss) income | 146.3 | — | — | — | 146.3 | ||||||||||||||
Net unrealized gains on cash flow hedges | 146.3 | — | — | — | 146.3 | ||||||||||||||
Postretirement plans and workers' compensation obligations (net of $1.5 tax benefit) | |||||||||||||||||||
Prior service cost for the period | — | (4.5 | ) | — | — | (4.5 | ) | ||||||||||||
Net actuarial gain (loss) for the period | 8.9 | (22.4 | ) | — | — | (13.5 | ) | ||||||||||||
Amortization of actuarial (loss) gain and prior service cost included in net (loss) income | (6.1 | ) | 21.5 | — | — | 15.4 | |||||||||||||
Postretirement plans and workers' compensation obligations | 2.8 | (5.4 | ) | — | — | (2.6 | ) | ||||||||||||
Foreign currency translation adjustment | — | — | (1.8 | ) | — | (1.8 | ) | ||||||||||||
Other comprehensive loss from investment in subsidiaries | (7.2 | ) | — | — | 7.2 | — | |||||||||||||
Other comprehensive income (loss), net of income taxes | 141.9 | (5.4 | ) | (1.8 | ) | 7.2 | 141.9 | ||||||||||||
Comprehensive (loss) income | (597.9 | ) | 174.0 | (358.3 | ) | 192.2 | (590.0 | ) | |||||||||||
Less: Comprehensive income attributable to noncontrolling interests | — | — | 7.9 | — | 7.9 | ||||||||||||||
Comprehensive (loss) income attributable to common stockholders | $ | (597.9 | ) | $ | 174.0 | $ | (366.2 | ) | $ | 192.2 | $ | (597.9 | ) | ||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 87 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 | ) | $ | 152.7 | $ | (1,079.5 | ) | $ | 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 | 37.3 | (12.6 | ) | — | 31.9 | |||||||||||||
Postretirement plans and workers' compensation obligations | 12.7 | 60.3 | (12.6 | ) | — | 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 | 60.3 | (82.1 | ) | 21.8 | 145.9 | |||||||||||||
Comprehensive (loss) income | (1,850.1 | ) | 213.0 | (1,161.6 | ) | 955.7 | (1,843.0 | ) | |||||||||||
Less: Comprehensive income attributable to noncontrolling interests | — | 0.8 | 6.3 | — | 7.1 | ||||||||||||||
Comprehensive (loss) income attributable to common stockholders | $ | (1,850.1 | ) | $ | 212.2 | $ | (1,167.9 | ) | $ | 955.7 | $ | (1,850.1 | ) | ||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 88 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 | ) | $ | 359.9 | $ | (478.7 | ) | $ | 128.5 | $ | (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 | — | (152.6 | ) | 9.9 | — | (142.7 | ) | ||||||||||||
Amortization of actuarial loss (gain) and prior service cost included in net (loss) income | — | 41.4 | (8.7 | ) | — | 32.7 | |||||||||||||
Postretirement plans and workers' compensation obligations | — | (99.8 | ) | 1.2 | — | (98.6 | ) | ||||||||||||
Foreign currency translation adjustment | — | — | (41.0 | ) | — | (41.0 | ) | ||||||||||||
Other comprehensive income from investment in subsidiaries | (150.2 | ) | — | — | 150.2 | — | |||||||||||||
Other comprehensive loss, net of income taxes | (345.6 | ) | (99.8 | ) | (50.4 | ) | 150.2 | (345.6 | ) | ||||||||||
Comprehensive (loss) income | (1,132.6 | ) | 260.1 | (529.1 | ) | 278.7 | (1,122.9 | ) | |||||||||||
Less: Comprehensive income attributable to noncontrolling interests | — | 5.2 | 4.5 | — | 9.7 | ||||||||||||||
Comprehensive (loss) income attributable to common stockholders | $ | (1,132.6 | ) | $ | 254.9 | $ | (533.6 | ) | $ | 278.7 | $ | (1,132.6 | ) | ||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 89 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2016 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications/ Eliminations | Consolidated | |||||||||||||||
(Dollars in millions) | |||||||||||||||||||
Assets | |||||||||||||||||||
Current assets | |||||||||||||||||||
Cash and cash equivalents | $ | 266.6 | $ | 107.0 | $ | 498.7 | $ | — | $ | 872.3 | |||||||||
Restricted cash | 13.8 | — | 40.5 | — | 54.3 | ||||||||||||||
Accounts receivable, net | — | 5.1 | 467.9 | — | 473.0 | ||||||||||||||
Receivables from affiliates, net | 899.9 | — | 783.0 | (1,682.9 | ) | — | |||||||||||||
Inventories | — | 76.8 | 126.9 | — | 203.7 | ||||||||||||||
Assets from coal trading activities, net | — | 0.9 | — | (0.2 | ) | 0.7 | |||||||||||||
Other current assets | 19.1 | 51.2 | 416.3 | — | 486.6 | ||||||||||||||
Total current assets | 1,199.4 | 241.0 | 2,333.3 | (1,683.1 | ) | 2,090.6 | |||||||||||||
Property, plant, equipment and mine development, net | — | 4,381.6 | 4,395.1 | — | 8,776.7 | ||||||||||||||
Deferred income taxes | — | 15.8 | — | (15.8 | ) | — | |||||||||||||
Investments and other assets | 8,652.0 | 3.8 | 626.5 | (8,371.9 | ) | 910.4 | |||||||||||||
Notes receivable from affiliates, net | — | 1,036.3 | — | (1,036.3 | ) | — | |||||||||||||
Total assets | $ | 9,851.4 | $ | 5,678.5 | $ | 7,354.9 | $ | (11,107.1 | ) | $ | 11,777.7 | ||||||||
Liabilities and Stockholders’ Equity | |||||||||||||||||||
Current liabilities | |||||||||||||||||||
Current portion of long-term debt | $ | — | $ | 19.3 | $ | 0.9 | $ | — | $ | 20.2 | |||||||||
Payables to affiliates, net | — | 1,682.9 | — | (1,682.9 | ) | — | |||||||||||||
Liabilities from coal trading activities, net | — | — | 1.4 | (0.2 | ) | 1.2 | |||||||||||||
Accounts payable and accrued expenses | 58.9 | 439.3 | 492.2 | — | 990.4 | ||||||||||||||
Total current liabilities | 58.9 | 2,141.5 | 494.5 | (1,683.1 | ) | 1,011.8 | |||||||||||||
Deferred income taxes | 28.0 | — | 5.4 | (15.8 | ) | 17.6 | |||||||||||||
Notes payable to affiliates, net | 1,032.5 | — | 3.8 | (1,036.3 | ) | — | |||||||||||||
Other noncurrent liabilities | 160.4 | 1,330.3 | 479.6 | — | 1,970.3 | ||||||||||||||
Total liabilities not subject to compromise | 1,279.8 | 3,471.8 | 983.3 | (2,735.2 | ) | 2,999.7 | |||||||||||||
Liabilities subject to compromise | 8,241.4 | 184.2 | 14.6 | — | 8,440.2 | ||||||||||||||
Total liabilities | 9,521.2 | 3,656.0 | 997.9 | (2,735.2 | ) | 11,439.9 | |||||||||||||
Peabody Energy Corporation stockholders’ equity | 330.2 | 2,022.5 | 6,349.4 | (8,371.9 | ) | 330.2 | |||||||||||||
Noncontrolling interests | — | — | 7.6 | — | 7.6 | ||||||||||||||
Total stockholders’ equity | 330.2 | 2,022.5 | 6,357.0 | (8,371.9 | ) | 337.8 | |||||||||||||
Total liabilities and stockholders’ equity | $ | 9,851.4 | $ | 5,678.5 | $ | 7,354.9 | $ | (11,107.1 | ) | $ | 11,777.7 | ||||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 90 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 | $ | 4.7 | $ | 249.4 | $ | — | $ | 261.3 | |||||||||
Accounts receivable, net | — | 12.1 | 216.7 | — | 228.8 | ||||||||||||||
Receivables from affiliates, net | 582.1 | — | 948.1 | (1,530.2 | ) | — | |||||||||||||
Inventories | — | 109.4 | 198.4 | — | 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 | 23.1 | 128.1 | 296.4 | — | 447.6 | ||||||||||||||
Total current assets | 612.4 | 322.8 | 1,929.3 | (1,542.0 | ) | 1,322.5 | |||||||||||||
Property, plant, equipment and mine development, net | — | 4,304.8 | 4,953.7 | — | 9,258.5 | ||||||||||||||
Deferred income taxes | — | 33.1 | — | (30.9 | ) | 2.2 | |||||||||||||
Investments and other assets | 8,476.2 | 3.6 | 185.5 | (8,301.6 | ) | 363.7 | |||||||||||||
Notes receivable from affiliates, net | — | 632.7 | 399.9 | (1,032.6 | ) | — | |||||||||||||
Total assets | $ | 9,088.6 | $ | 5,297.0 | $ | 7,468.4 | $ | (10,907.1 | ) | $ | 10,946.9 | ||||||||
Liabilities and Stockholders’ Equity | |||||||||||||||||||
Current liabilities | |||||||||||||||||||
Current portion of long-term debt | $ | 5,844.0 | $ | 23.8 | $ | 7.1 | $ | — | $ | 5,874.9 | |||||||||
Payables to affiliates, net | — | 1,530.2 | — | (1,530.2 | ) | — | |||||||||||||
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 | 479.8 | 467.9 | — | 1,442.5 | ||||||||||||||
Total current liabilities | 6,350.6 | 2,038.6 | 489.6 | (1,542.0 | ) | 7,336.8 | |||||||||||||
Long-term debt, less current portion | 366.3 | — | — | — | 366.3 | ||||||||||||||
Deferred income taxes | 98.6 | — | 1.4 | (30.9 | ) | 69.1 | |||||||||||||
Notes payable to affiliates, net | 1,032.6 | — | — | (1,032.6 | ) | — | |||||||||||||
Other noncurrent liabilities | 323.6 | 1,454.9 | 477.7 | — | 2,256.2 | ||||||||||||||
Total liabilities | 8,171.7 | 3,493.5 | 968.7 | (2,605.5 | ) | 10,028.4 | |||||||||||||
Peabody Energy Corporation stockholders’ equity | 916.9 | 1,803.5 | 6,498.1 | (8,301.6 | ) | 916.9 | |||||||||||||
Noncontrolling interests | — | — | 1.6 | — | 1.6 | ||||||||||||||
Total stockholders’ equity | 916.9 | 1,803.5 | 6,499.7 | (8,301.6 | ) | 918.5 | |||||||||||||
Total liabilities and stockholders’ equity | $ | 9,088.6 | $ | 5,297.0 | $ | 7,468.4 | $ | (10,907.1 | ) | $ | 10,946.9 | ||||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 91 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2016 | |||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidated | ||||||||||||
(Dollars in millions) | |||||||||||||||
Cash Flows From Operating Activities | |||||||||||||||
Net cash (used in) provided by continuing operations | $ | (167.3 | ) | $ | 78.5 | $ | 65.9 | $ | (22.9 | ) | |||||
Net cash used in discontinued operations | (16.2 | ) | (1.9 | ) | (11.8 | ) | (29.9 | ) | |||||||
Net cash (used in) provided by operating activities | (183.5 | ) | 76.6 | 54.1 | (52.8 | ) | |||||||||
Cash Flows From Investing Activities | |||||||||||||||
Additions to property, plant, equipment and mine development | — | (55.5 | ) | (71.1 | ) | (126.6 | ) | ||||||||
Changes in accrued expenses related to capital expenditures | — | (0.6 | ) | (5.5 | ) | (6.1 | ) | ||||||||
Federal coal lease expenditures | — | (249.0 | ) | — | (249.0 | ) | |||||||||
Proceeds from disposal of assets, net of notes receivable | — | 77.7 | 66.7 | 144.4 | |||||||||||
Contributions to joint ventures | — | — | (309.5 | ) | (309.5 | ) | |||||||||
Distributions from joint ventures | — | — | 312.4 | 312.4 | |||||||||||
Advances to related parties | — | — | (40.4 | ) | (40.4 | ) | |||||||||
Repayment of loans from related parties | — | — | 40.6 | 40.6 | |||||||||||
Other, net | — | (5.1 | ) | (4.8 | ) | (9.9 | ) | ||||||||
Net cash used in by investing activities | — | (232.5 | ) | (11.6 | ) | (244.1 | ) | ||||||||
Cash Flows From Financing Activities | |||||||||||||||
Proceeds from long-term debt | 1,450.6 | — | 7.8 | 1,458.4 | |||||||||||
Repayments of long-term debt | (503.0 | ) | (4.4 | ) | (6.3 | ) | (513.7 | ) | |||||||
Payment of deferred financing costs | (26.8 | ) | — | (4.2 | ) | (31.0 | ) | ||||||||
Other, net | — | (5.8 | ) | — | (5.8 | ) | |||||||||
Transactions with affiliates, net | (477.9 | ) | 268.4 | 209.5 | — | ||||||||||
Net cash provided by financing activities | 442.9 | 258.2 | 206.8 | 907.9 | |||||||||||
Net change in cash and cash equivalents | $ | 259.4 | $ | 102.3 | $ | 249.3 | $ | 611.0 | |||||||
Cash and cash equivalents at beginning of year | 7.2 | 4.7 | 249.4 | 261.3 | |||||||||||
Cash and cash equivalents at end of year | $ | 266.6 | $ | 107.0 | $ | 498.7 | $ | 872.3 | |||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 92 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 | ) | $ | 615.3 | $ | 96.5 | $ | 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 | ) | 612.4 | 93.5 | (14.4 | ) | |||||||||
Cash Flows From Investing Activities | |||||||||||||||
Additions to property, plant, equipment and mine development | — | (70.6 | ) | (56.2 | ) | (126.8 | ) | ||||||||
Changes in accrued expenses related to capital expenditures | — | (2.3 | ) | (6.9 | ) | (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 loan from related parties | — | — | 0.9 | 0.9 | |||||||||||
Other, net | — | (2.7 | ) | (0.4 | ) | (3.1 | ) | ||||||||
Net cash (used in) provided by investing activities | — | (316.5 | ) | 26.5 | (290.0 | ) | |||||||||
Cash Flows From Financing Activities | |||||||||||||||
Proceeds from long-term debt | 975.7 | — | — | 975.7 | |||||||||||
Repayments of long-term debt | (662.0 | ) | (0.7 | ) | (8.6 | ) | (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 | (289.9 | ) | 36.1 | — | ||||||||||
Net cash provided by (used in) financing activities | 538.8 | (292.4 | ) | 21.3 | 267.7 | ||||||||||
Net change in cash and cash equivalents | $ | (181.5 | ) | $ | 3.5 | $ | 141.3 | $ | (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 | $ | 4.7 | $ | 249.4 | $ | 261.3 | |||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 93 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
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 | ) | $ | 764.7 | $ | 45.3 | $ | 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 | ) | 760.1 | 18.8 | 336.6 | ||||||||||
Cash Flows From Investing Activities | |||||||||||||||
Additions to property, plant, equipment and mine development | — | (95.8 | ) | (98.6 | ) | (194.4 | ) | ||||||||
Changes in accrued expenses related to capital expenditures | — | 2.2 | (18.8 | ) | (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 loans from related parties | — | — | 5.4 | 5.4 | |||||||||||
Other, net | — | (4.2 | ) | (0.8 | ) | (5.0 | ) | ||||||||
Net cash used in investing activities | — | (268.6 | ) | (45.9 | ) | (314.5 | ) | ||||||||
Cash Flows From Financing Activities | |||||||||||||||
Proceeds from long-term debt | — | — | 1.1 | 1.1 | |||||||||||
Repayments of long-term debt | (12.0 | ) | (0.7 | ) | (8.3 | ) | (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 | (488.2 | ) | 46.6 | — | ||||||||||
Net cash provided by (used in) financing activities | 330.3 | (490.6 | ) | (7.8 | ) | (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 | 2016 Form 10-K | F- 94 |
Debtor / Non-Debtor
The activity and balances included in the tables below represent the Debtors' and non-debtors' financial information covering the period ended December 31, 2016 and the period from the Petition Date to the end of the current fiscal month.
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
The Period April 13 through December 31, 2016 | |||||||||||||||
Debtors | Non-Debtors | Eliminations | Consolidated | ||||||||||||
(Dollars in millions) | |||||||||||||||
Total revenues | $ | 2,074.0 | $ | 1,494.7 | $ | (4.0 | ) | $ | 3,564.7 | ||||||
Costs and expenses | |||||||||||||||
Operating costs and expenses (exclusive of items shown separately below) | 1,692.9 | 1,347.0 | (4.0 | ) | 3,035.9 | ||||||||||
Depreciation, depletion and amortization | 177.6 | 159.1 | — | 336.7 | |||||||||||
Asset retirement obligation expenses | 11.6 | 15.3 | — | 26.9 | |||||||||||
Selling and administrative expenses | 81.4 | 9.3 | — | 90.7 | |||||||||||
Restructuring charges | 2.2 | 0.6 | — | 2.8 | |||||||||||
Other operating (income) loss: | |||||||||||||||
Net gain on disposal of assets | (19.7 | ) | (1.7 | ) | — | (21.4 | ) | ||||||||
Asset impairment | 37.5 | 193.2 | — | 230.7 | |||||||||||
Loss (income) from equity affiliates and investment in subsidiaries | 229.1 | (29.2 | ) | (226.1 | ) | (26.2 | ) | ||||||||
Loss on early debt extinguishment | 29.5 | — | — | 29.5 | |||||||||||
Interest expense | 143.2 | 16.9 | (9.7 | ) | 150.4 | ||||||||||
Interest income | (3.7 | ) | (10.0 | ) | 9.7 | (4.0 | ) | ||||||||
Reorganization items, net | 155.1 | 3.9 | — | 159.0 | |||||||||||
Loss from continuing operations before income taxes | (462.7 | ) | (209.7 | ) | 226.1 | (446.3 | ) | ||||||||
Income tax (benefit) provision | (20.6 | ) | 14.4 | — | (6.2 | ) | |||||||||
Loss from continuing operations, net of income taxes | (442.1 | ) | (224.1 | ) | 226.1 | (440.1 | ) | ||||||||
(Loss) gain from discontinued operations, net of income taxes | (59.5 | ) | 5.9 | — | (53.6 | ) | |||||||||
Net loss | (501.6 | ) | (218.2 | ) | 226.1 | (493.7 | ) | ||||||||
Less: Net income attributable to noncontrolling interests | — | 7.9 | — | 7.9 | |||||||||||
Net loss attributable to common stockholders | $ | (501.6 | ) | $ | (226.1 | ) | $ | 226.1 | $ | (501.6 | ) | ||||
Peabody Energy Corporation | 2016 Form 10-K | F- 95 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2016 | |||||||||||||||
Debtors | Non-Debtors | Reclassifications/Eliminations | Consolidated | ||||||||||||
(Dollars in millions) | |||||||||||||||
Assets | |||||||||||||||
Current assets | |||||||||||||||
Cash and cash equivalents | $ | 394.5 | $ | 477.8 | $ | — | $ | 872.3 | |||||||
Restricted cash | 13.8 | 40.5 | — | 54.3 | |||||||||||
Accounts receivable, net | 5.2 | 467.8 | — | 473.0 | |||||||||||
Receivables from affiliates, net | 226.9 | — | (226.9 | ) | — | ||||||||||
Inventories | 96.3 | 107.4 | — | 203.7 | |||||||||||
Assets from coal trading activities, net | 0.9 | — | (0.2 | ) | 0.7 | ||||||||||
Deferred income taxes | — | — | — | — | |||||||||||
Other current assets | 72.0 | 416.2 | (1.6 | ) | 486.6 | ||||||||||
Total current assets | 809.6 | 1,509.7 | (228.7 | ) | 2,090.6 | ||||||||||
Property, plant, equipment and mine development, net | 4,870.2 | 3,906.5 | — | 8,776.7 | |||||||||||
Deferred income taxes | — | — | — | — | |||||||||||
Investments and other assets | 4,282.2 | 596.7 | (3,968.5 | ) | 910.4 | ||||||||||
Notes receivable from affiliates, net | 1,036.3 | — | (1,036.3 | ) | — | ||||||||||
Total assets | $ | 10,998.3 | $ | 6,012.9 | $ | (5,233.5 | ) | $ | 11,777.7 | ||||||
Liabilities and Stockholders’ Equity | |||||||||||||||
Current liabilities | |||||||||||||||
Current portion of long-term debt | $ | 19.3 | $ | 0.9 | $ | — | $ | 20.2 | |||||||
Payables to affiliates, net | — | 226.9 | (226.9 | ) | — | ||||||||||
Income taxes payable | — | 7.8 | (1.6 | ) | 6.2 | ||||||||||
Liabilities from coal trading activities, net | 0.1 | 1.3 | (0.2 | ) | 1.2 | ||||||||||
Accounts payable and accrued expenses | 541.7 | 442.5 | — | 984.2 | |||||||||||
Total current liabilities | 561.1 | 679.4 | (228.7 | ) | 1,011.8 | ||||||||||
Deferred income taxes | 12.1 | 5.5 | — | 17.6 | |||||||||||
Notes payable to affiliates, net | — | 1,036.3 | (1,036.3 | ) | — | ||||||||||
Other noncurrent liabilities | 1,648.8 | 321.5 | — | 1,970.3 | |||||||||||
Total liabilities not subject to compromise | 2,222.0 | 2,042.7 | (1,265.0 | ) | 2,999.7 | ||||||||||
Liabilities subject to compromise | 8,440.2 | — | — | 8,440.2 | |||||||||||
Total liabilities | 10,662.2 | 2,042.7 | (1,265.0 | ) | 11,439.9 | ||||||||||
Peabody Energy Corporation stockholders’ equity | 336.1 | 3,962.6 | (3,968.5 | ) | 330.2 | ||||||||||
Noncontrolling interests | — | 7.6 | — | 7.6 | |||||||||||
Total stockholders’ equity | 336.1 | 3,970.2 | (3,968.5 | ) | 337.8 | ||||||||||
Total liabilities and stockholders’ equity | $ | 10,998.3 | $ | 6,012.9 | $ | (5,233.5 | ) | $ | 11,777.7 | ||||||
Peabody Energy Corporation | 2016 Form 10-K | F- 96 |
PEABODY ENERGY CORPORATION
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
The Period April 13 through December 31, 2016 | |||||||||||
Debtors | Non-Debtors | Consolidated | |||||||||
(Dollars in millions) | |||||||||||
Cash Flows From Operating Activities | |||||||||||
Net cash provided by continuing operations | $ | 435.8 | $ | 54.2 | $ | 490.0 | |||||
Net cash used in discontinued operations | (18.3 | ) | (10.9 | ) | (29.2 | ) | |||||
Net cash provided by operating activities | 417.5 | 43.3 | 460.8 | ||||||||
Cash Flows From Investing Activities | |||||||||||
Additions to property, plant, equipment and mine development | (62.6 | ) | (44.1 | ) | (106.7 | ) | |||||
Changes in accrued expenses related to capital expenditures | 0.9 | (3.0 | ) | (2.1 | ) | ||||||
Federal coal lease expenditures | (248.5 | ) | — | (248.5 | ) | ||||||
Proceeds from disposal of assets, net of notes receivable | 75.6 | 66.6 | 142.2 | ||||||||
Contributions to joint ventures | — | (208.3 | ) | (208.3 | ) | ||||||
Distributions from joint ventures | — | 215.4 | 215.4 | ||||||||
Advances to related parties | — | (39.8 | ) | (39.8 | ) | ||||||
Repayments of loans from related parties | — | 39.3 | 39.3 | ||||||||
Other, net | (2.0 | ) | (2.6 | ) | (4.6 | ) | |||||
Net cash (used in) provided by investing activities | (236.6 | ) | 23.5 | (213.1 | ) | ||||||
Cash Flows From Financing Activities | |||||||||||
Proceeds from long-term debt | 503.6 | 7.8 | 511.4 | ||||||||
Repayments of long-term debt | (502.9 | ) | (3.7 | ) | (506.6 | ) | |||||
Payment of deferred financing costs | (26.8 | ) | (1.4 | ) | (28.2 | ) | |||||
Distributions to noncontrolling interests | — | (4.0 | ) | (4.0 | ) | ||||||
Other, net | (0.1 | ) | — | (0.1 | ) | ||||||
Transactions with affiliates, net | 131.3 | (131.3 | ) | — | |||||||
Net cash provided by (used in) financing activities | 105.1 | (132.6 | ) | (27.5 | ) | ||||||
Net change in cash and cash equivalents | 286.0 | (65.8 | ) | 220.2 | |||||||
Cash and cash equivalents at beginning of period | 108.5 | 543.6 | 652.1 | ||||||||
Cash and cash equivalents at end of period | $ | 394.5 | $ | 477.8 | $ | 872.3 | |||||
Peabody Energy Corporation | 2016 Form 10-K | F- 97 |
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, 2016 | ||||||||||||||||||||
Reserves deducted from asset accounts: | ||||||||||||||||||||
Advance royalty recoupment reserve | $ | 8.3 | $ | 0.5 | $ | (1.0 | ) | (2) | $ | — | $ | 7.8 | ||||||||
Reserve for materials and supplies | 4.7 | 4.3 | (3.4 | ) | — | 5.6 | ||||||||||||||
Allowance for doubtful accounts | 6.6 | 7.9 | (1.4 | ) | — | 13.1 | ||||||||||||||
Tax valuation allowances | 1,447.3 | 2,462.8 | — | (28.9 | ) | (3) | 3,881.2 | |||||||||||||
Year Ended December 31, 2015 | ||||||||||||||||||||
Reserves deducted from asset accounts: | ||||||||||||||||||||
Advance royalty recoupment reserve | $ | 7.6 | $ | — | $ | (0.9 | ) | (2) | $ | 1.6 | (4) | $ | 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 | ) | (3) | 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 | |||||||||||||
(1) | Reserves utilized, unless otherwise indicated. |
(2) | Deductions to advance royalty recoupment reserve represents the termination of federal and state leases. |
(3) | Includes the impact of the decrease in Australian dollar exchange rates. |
(4) | Balances transferred from other accounts. |
(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. |
Peabody Energy Corporation | 2016 Form 10-K | F- 98 |
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 | |
2.1 | Debtors’ Second Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code as revised March 15, 2017 (Incorporated by reference to Exhibit 2.2 of the Registrant’s Current Report on Form 8-K, filed March 20, 2017). | |
2.2 | Order Confirming Debtors’ Second Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code on March 17, 2017 (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed March 20, 2017). | |
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. | |
4.6 | Indenture, dated as of February 15, 2017, between Peabody Securities Finance Corporation and Wilmington Trust, National Association, as Trustee, governing 6.000% Senior Secured Notes due 2022 and 6.375% Senior Secured Notes due 2025 (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed February 15, 2017). | |
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). | |
Exhibit No. | Description of Exhibit | |
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). | |
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). | |
Exhibit No. | Description of Exhibit | |
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). | |
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 (Incorporated by reference to Exhibit 10.28 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015). | |
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). | |
Exhibit No. | Description of Exhibit | |
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). | |
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). | |
Exhibit No. | Description of Exhibit | |
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). | |
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 (Incorporated by reference to Exhibit 10.69 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015). | |
10.70* | Form of Performance-Based Restricted Stock Unit Agreement under the Registrant's 2015 Long-Term Incentive Plan (effective for Australia) (Incorporated by reference to Exhibit 10.70 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015). | |
10.71* | Form of Service-Based Cash Award Agreement under the Registrant's 2015 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.71 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015). | |
10.72* | Form of Service-Based Cash Award Agreement under the Registrant’s 2015 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.72 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015). | |
10.73* | Form of Service-Based Cash Award Agreement for Non-Employee Directors under the Registrant's 2015 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.73 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015). | |
10.74* | Form of Deferred Stock Unit Agreement under the Registrant's 2015 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.74 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015). | |
10.75* | Form of Restrictive Covenant Agreement under the Registrant's 2015 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.75 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015). | |
10.76* | Form of Restrictive Covenant Agreement under the Registrant's 2015 Long-Term Incentive Plan (Australia) (Incorporated by reference to Exhibit 10.76 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015). | |
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). | |
Exhibit No. | Description of Exhibit | |
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). | |
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). | |
Exhibit No. | Description of Exhibit | |
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). | |
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). | |
10.109 | Limited Waiver to Purchase and Sale Agreement by and between Four Star Holdings, LLC and Western Megawatt Resources, LLC dated March 30, 2016 (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed March 31, 2016). | |
10.110 | Fifth Amended and Restated Receivables Purchase Agreement, dated as of March 25, 2016, 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 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 of the Registrant's Current Report on Form 8-K filed March 31, 2016). | |
10.111 | First Amendment to the Fifth Amended and Restated Receivables Purchase Agreement, dated as of April 12, 2016, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as the Sole Purchaser, Committed Purchaser, LC Bank and LC Participant (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 13, 2016). | |
10.112 | Second Amendment to the Fifth Amended and Restated Receivables Purchase Agreement, dated as of April 18, 2016, by and among Peabody Energy Corporation, P&L Receivables Company, LLC, the various Sub-Servicers listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as the Sole Purchaser, Committed Purchaser, LC Bank and LC Participant (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 22, 2016). | |
10.113 | Superpriority Secured Debtor-In-Possession Credit Agreement, dated as of April 18, 2016, by and among Peabody Energy Corporation, the guarantors party thereto, the lenders party thereto and Citibank, N.A. as Administrative Agent and L/C Issuer (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed April 22, 2016). | |
10.114 | Amendment No. 1 to Superpriority Secured Debtor-in-Possession Credit Agreement, dated as of May 9, 2016, by and among Peabody Energy Corporation, the guarantors party thereto, the lenders party thereto and Citibank, N.A. as Administrative Agent (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed May 24, 2016). | |
Exhibit No. | Description of Exhibit | |
10.115 | Amendment No. 2 to Superpriority Secured Debtor-in-Possession Credit Agreement, dated as of May 18, 2016, by and among Peabody Energy Corporation, the guarantors party thereto, the lenders party thereto, the issuing bank party thereto, and Citibank, N.A. as Administrative Agent (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed May 24, 2016). | |
10.116 | Amendment No. 4 to the Superpriority Secured Debtor-In-Possession Credit Agreement, dated as of October 11, 2016, by and among Peabody Energy Corporation, Peabody Global Funding, LLC (f/k/a Global Center for Energy and Human Development, LLC) and certain Debtors parties thereto as guarantors, the lenders party thereto and Citibank, N.A., as administrative agent (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed October 14, 2016). | |
10.117 | Amendment No. 5 to Superpriority Secured Debtor-In-Possession Credit Agreement, by and among Peabody Energy Corporation, Peabody Global Funding, LLC (f/k/a Global Center for Energy and Human Development, LLC) and certain Debtors parties thereto as guarantors, the lenders party thereto and Citibank, N.A., as administrative agent (Incorporated by reference to the Registrant’s Current Report on Form 8-K filed November 23, 2016). | |
10.118 | Amendment No. 6 to Superpriority Secured Debtor-In-Possession Credit Agreement, by and among Peabody Energy Corporation, Peabody Global Funding, LLC and certain Debtors parties thereto as guarantors, the lenders party thereto and Citibank, N.A., as administrative agent (Incorporated by reference to the Registrant’s Current Report on Form 8-K filed December 14, 2016). | |
10.119 | Plan Support Agreement entered into as of December 22, 2016 by and among the Registrant and certain other parties thereto (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed December 23, 2016). | |
10.120 | Private Placement Agreement entered into as of December 22, 2016 by and among the Registrant and certain of its creditors party thereto (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed December 23, 2016). | |
10.121 | Amendment to Private Placement Agreement entered into as of December 28, 2016 by and among the Registrant and certain of its creditors party thereto (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed December 30, 2016). | |
10.122 | Backstop Commitment Agreement entered into as of December 23, 2016 by and among the Registrant and certain of its creditors party thereto (Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed December 23, 2016). | |
10.123 | Amendment to Backstop Commitment Agreement entered into as of December 28, 2016 by and among the Registrant and certain of its creditors party thereto (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed December 30, 2016). | |
10.124† | Share Sale and Purchase Agreement entered into as of November 3, 2016 by and among Peabody Australia Mining Pty Ltd, Peabody Energy Australia Pty Ltd, South32 Aluminium (Holdings) Pty Ltd, and South32 Treasury Limited. | |
10.125 | Exit Facility Commitment Letter entered into as of January 11, 2017, by and among the Registrant, Goldman Sachs Bank USA, JPMorgan Chase Bank, N.A., Credit Suisse AG, Credit Suisse Securities (USA) LLC, Macquarie Capital Funding LLC and Macquarie Capital (USA) Inc. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 12, 2017). | |
10.126 | Receivables Purchase Facility Commitment Letter entered into as of January 27, 2017, by and among the Registrant, P&L Receivables Company, LLC and PNC Bank, National Association (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 27, 2017). | |
10.127† | Amendment to Private Placement Agreement entered into as of February 8, 2017 by and among the Registrant and certain of its creditors party thereto. | |
10.128† | Notice Letter and Term Sheet dated as of February 15, 2017, for Amendments to the Receivables Purchase Facility Commitment Letter entered into as of January 27, 2017, by and among the Registrant, P&L Receivables Company, LLC and PNC Bank, National Association. | |
10.129 | Settlement Agreement dated as of March 13, 2017 by and among the Registrant, certain subsidiaries of the Registrant, and the United Mine Workers of America 1974 Pension Plan and Trust (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on March 17, 2017). | |
21† | List of Subsidiaries. | |
23† | Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm. | |
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. | |
Exhibit No. | Description of Exhibit | |
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, 2016 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. |