424b3 Prospectus Supplement 9.30.17 10Q Combined Document


Filed Pursuant to Rule 424(b)(3)
Registration No. 333-217242

PROSPECTUS SUPPLEMENT NO. 6
(to prospectus dated July 14, 2017)

logo.jpg
PEABODY ENERGY CORPORATION

Shares of Series A Convertible Preferred Stock

Shares of Common Stock

Shares of Common Stock initially issuable upon the conversion of
Series A Convertible Preferred Stock

This prospectus supplement no. 6 supplements the prospectus, dated July 14, 2017, relating to the above-referenced securities (the “Securities”), which may be offered for sale by the selling stockholders identified in “Principal and Selling Stockholders” in the prospectus. This prospectus supplement no. 6 is not complete without, and may not be delivered or utilized except in connection with, the prospectus, including any amendments or supplements thereto. If there is any inconsistency between the information in the prospectus and this prospectus supplement no. 6, you should rely on the information in this prospectus supplement no. 6.

Investing in the Securities involves risks. See “Risk Factors” beginning on page 3 of the prospectus.

This prospectus supplement no. 6 is filed for the purpose of including in the prospectus information contained in the attached Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017, which was filed with the Securities and Exchange Commission on November 3, 2017.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus supplement no. 6 is November 3, 2017.



 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-Q
 
(Mark One)
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission File Number: 1-16463
____________________________________________
peabodylogoa09.jpg
PEABODY ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
 
13-4004153
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
701 Market Street, St. Louis, Missouri
 
63101-1826
(Address of principal executive offices)
 
(Zip Code)
(314) 342-3400
(Registrant’s telephone number, including area code)
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 ¨
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 ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934. (Check one):
Large accelerated filer ¨
 
 
 
 
 
Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)
 
Smaller reporting company þ
 
 
 
 
 
 
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Exchange Act subsequent to the distribution of securities under a plan confirmed by a court. Yes þ No ¨
There were 104.5 million shares of the registrant’s common stock (par value of $0.01 per share) outstanding at October 30, 2017.
There were 14.3 million shares of the registrant’s Series A convertible preferred stock (par value of $0.01 per share) outstanding at October 30, 2017.



TABLE OF CONTENTS
 
Page
 
 


Table of Contents



PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
Successor
Predecessor
 
Successor
Predecessor
 
Three Months Ended September 30, 2017
Three Months Ended September 30, 2016

April 2 through September 30, 2017
January 1 through April 1, 2017

Nine Months Ended September 30, 2016
 
(Dollars in millions, except per share data)
Revenues
 

 
 
 
 
 
 
Sales
$
1,264.2

$
1,064.0

 
$
2,323.8

$
1,081.4

 
$
2,835.9

Other revenues
213.0

143.1

 
411.7

244.8

 
438.6

Total revenues
1,477.2

1,207.1

 
2,735.5

1,326.2

 
3,274.5

Costs and expenses
 
 
 

 
 
 
Operating costs and expenses (exclusive of items shown separately below)
1,044.9

1,064.8

 
1,979.7

963.7

 
2,981.2

Depreciation, depletion and amortization
194.5

117.8

 
342.8

119.9

 
345.5

Asset retirement obligation expenses
11.3

12.7

 
22.3

14.6

 
37.3

Selling and administrative expenses
33.4

32.1

 
67.8

37.2

 
114.6

Restructuring charges
1.1

0.3

 
1.1

—

 
15.5

Other operating (income) loss:
 
 
 
 
 
 
 
Net gain on disposal of assets
(0.4
)
(1.9
)
 
(0.9
)
(22.8
)
 
(17.4
)
Asset impairment
—

—

 
—

30.5

 
17.2

(Income) loss from equity affiliates
(10.5
)
2.9

 
(26.2
)
(15.0
)
 
12.6

Operating profit (loss)
202.9

(21.6
)

348.9

198.1

 
(232.0
)
Interest expense
42.4

58.5

 
83.8

32.9

 
243.7

Loss on early debt extinguishment
12.9

—

 
12.9

—

 
—

Interest income
(2.0
)
(1.3
)
 
(3.5
)
(2.7
)
 
(4.0
)
Reorganization items, net
—

29.7

 
—

627.2

 
125.1

Income (loss) from continuing operations before income taxes
149.6

(108.5
)
 
255.7

(459.3
)
 
(596.8
)
Income tax benefit
(84.1
)
(10.8
)
 
(79.4
)
(263.8
)
 
(108.2
)
Income (loss) from continuing operations, net of income taxes
233.7

(97.7
)
 
335.1

(195.5
)
 
(488.6
)
Loss from discontinued operations, net of income taxes
(3.7
)
(38.1
)
 
(6.4
)
(16.2
)
 
(44.5
)
Net income (loss)
230.0

(135.8
)
 
328.7

(211.7
)
 
(533.1
)
Less: Series A Convertible Preferred Stock dividends
23.5

—

 
138.6

—

 
—

Less: Net income attributable to noncontrolling interests
5.1

1.8

 
8.9

4.8

 
3.5

Net income (loss) attributable to common stockholders
$
201.4

$
(137.6
)
 
$
181.2

$
(216.5
)
 
$
(536.6
)
 
 
 
 
 
 
 
 
Income (loss) from continuing operations:
 
 
 
 
 
 
 
Basic income (loss) per share
$
1.51

$
(5.44
)
 
$
1.38

$
(10.93
)
 
$
(26.91
)
Diluted income (loss) per share
$
1.49

$
(5.44
)
 
$
1.37

$
(10.93
)
 
$
(26.91
)
 
 
 
 
 
 
 
 
Net income (loss) attributable to common stockholders:
 
 
 
 
 
 
 
Basic income (loss) per share
$
1.48

$
(7.53
)
 
$
1.33

$
(11.81
)
 
$
(29.34
)
Diluted income (loss) per share
$
1.47

$
(7.53
)
 
$
1.32

$
(11.81
)
 
$
(29.34
)
 
 
 
 
 
 
 
 
Dividends declared per share
$
—

$
—

 
$
—

$
—

 
$
—

See accompanying notes to unaudited condensed consolidated financial statements.


1

Table of Contents



PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
Successor
Predecessor
 
Successor
Predecessor
 
Three Months Ended September 30, 2017
Three Months Ended September 30, 2016
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2016
 
(Dollars in millions)
Net income (loss)
$
230.0

$
(135.8
)
 
$
328.7

$
(211.7
)
 
$
(533.1
)
Reclassification for realized losses on cash flow hedges (net of respective net tax provision of $0.0, $17.6, $0.0, $9.1 and $69.9) included in net income (loss)
—

29.9

 
—

18.6

 
119.0

Postretirement plans and workers’ compensation obligations (net of respective net tax provision of $0.0, $2.1, $0.0, $2.5 and $6.3)
—

3.6

 
—

4.4

 
10.8

Foreign currency translation adjustment
1.3

1.5

 
1.8

5.5

 
2.4

Other comprehensive income, net of income taxes
1.3

35.0

 
1.8

28.5

 
132.2

Comprehensive income (loss)
231.3

(100.8
)
 
330.5

(183.2
)
 
(400.9
)
Less: Series A Convertible Preferred Stock dividends
23.5

—

 
138.6

—

 
—

Less: Comprehensive income attributable to noncontrolling interests
5.1

1.8

 
8.9

4.8

 
3.5

Comprehensive income (loss) attributable to common stockholders
$
202.7

$
(102.6
)
 
$
183.0

$
(188.0
)
 
$
(404.4
)

See accompanying notes to unaudited condensed consolidated financial statements.


2

Table of Contents



PEABODY ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
 
 
(Unaudited)
 
 
 
Successor
Predecessor
 
 
September 30, 2017
December 31, 2016
 
 
(Amounts in millions, except per share data)
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
 
$
925.0

$
872.3

Restricted cash
 
7.8

54.3

Accounts receivable, net of allowance for doubtful accounts of $4.6 at September 30, 2017 and $13.1 at December 31, 2016
 
431.0

473.0

Inventories
 
307.7

203.7

Assets from coal trading activities, net
 
2.5

0.7

Other current assets
 
268.6

486.6

Total current assets
 
1,942.6

2,090.6

Property, plant, equipment and mine development, net
 
5,082.6

8,776.7

Restricted cash collateral
 
530.3

529.3

Investments and other assets
 
517.9

381.1

Total assets
 
$
8,073.4

$
11,777.7

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
 
$
47.1

$
20.2

Liabilities from coal trading activities, net
 
1.0

1.2

Accounts payable and accrued expenses
 
1,065.0

990.4

Total current liabilities
 
1,113.1

1,011.8

Long-term debt, less current portion
 
1,612.0

—

Deferred income taxes
 
2.2

173.9

Asset retirement obligations
 
636.0

717.8

Accrued postretirement benefit costs
 
745.8

756.3

Other noncurrent liabilities
 
573.7

496.2

Total liabilities not subject to compromise
 
4,682.8

3,156.0

Liabilities subject to compromise
 
—

8,440.2

Total liabilities
 
4,682.8

11,596.2

Stockholders’ equity
 
 
 
Predecessor Preferred Stock — $0.01 per share par value; 10.0 shares authorized, no shares issued or outstanding as December 31, 2016
 
—

—

Predecessor Perpetual Preferred Stock — 0.8 shares authorized, no shares issued or outstanding as of December 31, 2016
 
—

—

Predecessor Series Common Stock — $0.01 per share par value; 40.0 shares authorized, no shares issued or outstanding as of December 31, 2016
 
—

—

Predecessor 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
 
—

0.2

Successor Series A Convertible Preferred Stock — $0.01 per share par value; 50.0 shares authorized, 30.0 shares issued and 15.9 shares outstanding as of September 30, 2017
 
691.7

—

Successor Preferred Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of September 30, 2017
 
—

—

Successor Series Common Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of September 30, 2017
 
—

—

Successor Common Stock — $0.01 per share par value; 450.0 shares authorized, 106.0 shares issued and 102.7 shares outstanding as of September 30, 2017
 
1.0

—

Additional paid-in capital
 
2,425.9

2,422.0

Treasury stock, at cost — 2.5 Successor common shares as of September 30, 2017 and 0.8 Predecessor common shares as of December 31, 2016
 
(69.2
)
(371.8
)
Retained earnings (accumulated deficit)
 
296.3

(1,399.5
)
Accumulated other comprehensive income (loss)
 
1.8

(477.0
)
Peabody Energy Corporation stockholders’ equity
 
3,347.5

173.9

Noncontrolling interests
 
43.1

7.6

Total stockholders’ equity
 
3,390.6

181.5

Total liabilities and stockholders’ equity
 
$
8,073.4

$
11,777.7

See accompanying notes to unaudited condensed consolidated financial statements.


3

Table of Contents



PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Successor
Predecessor
 
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2016
 
 
(Dollars in millions)
Cash Flows From Operating Activities
 
 
 
 
 
Net income (loss)
 
$
328.7

$
(211.7
)
 
$
(533.1
)
Loss from discontinued operations, net of income taxes
 
6.4

16.2

 
44.5

Income (loss) from continuing operations, net of income taxes
 
335.1

(195.5
)
 
(488.6
)
Adjustments to reconcile income (loss) from continuing operations, net of income taxes to net cash provided by (used in) operating activities:
 
 
 
 
 
Depreciation, depletion and amortization
 
342.8

119.9

 
345.5

Noncash coal inventory revaluation
 
67.3

—

 
—

Noncash interest expense including loss on early debt extinguishment
 
21.8

0.5

 
30.0

Deferred income taxes
 
1.6

(252.2
)
 
(39.4
)
Noncash share-based compensation
 
14.1

1.9

 
8.9

Asset impairment
 
—

30.5

 
17.2

Net gain on disposal of assets
 
(0.9
)
(22.8
)
 
(17.4
)
(Income) loss from equity affiliates
 
(26.2
)
(15.0
)
 
12.6

Gain on voluntary employee beneficiary association settlement
 
—

—

 
(68.1
)
Foreign currency option contracts
 
(5.1
)
—

 
—

Reclassification from other comprehensive earnings for terminated hedge contracts
 
—

27.6

 
82.0

Settlement of hedge positions
 
—

—

 
(25.0
)
Noncash reorganization items, net
 
—

569.3

 
96.5

Changes in current assets and liabilities:
 
 
 
 
 
Accounts receivable
 
(118.9
)
159.3

 
24.4

Change in receivable from accounts receivable securitization program
 
—

—

 
(168.5
)
Inventories
 
(54.1
)
(47.2
)
 
47.8

Net assets from coal trading activities
 
(1.6
)
(0.5
)
 
7.5

Other current assets
 
(23.4
)
0.1

 
(28.6
)
Accounts payable and accrued expenses
 
(261.0
)
(64.9
)
 
5.2

Restricted cash
 
99.4

(94.1
)
 
(94.8
)
Asset retirement obligations
 
7.6

10.2

 
19.0

Workers’ compensation obligations
 
(1.1
)
(3.1
)
 
(8.7
)
Accrued postretirement benefit costs
 
(1.2
)
0.8

 
(0.6
)
Accrued pension costs
 
(32.7
)
5.4

 
16.4

Take-or-pay obligation settlement
 
—

(5.5
)
 
(15.5
)
Other, net
 
(18.8
)
(2.5
)
 
(15.7
)
Net cash provided by (used in) continuing operations
 
344.7

222.2

 
(257.9
)
Net cash used in discontinued operations
 
(14.4
)
(8.2
)
 
(18.9
)
Net cash provided by (used in) operating activities
 
330.3

214.0

 
(276.8
)
Cash Flows From Investing Activities
 
 
 
 
 
Additions to property, plant, equipment and mine development
 
(68.6
)
(32.8
)
 
(56.6
)
Changes in accrued expenses related to capital expenditures
 
1.8

(1.4
)
 
(5.5
)
Federal coal lease expenditures
 
—

(0.5
)
 
(249.0
)
Proceeds from disposal of assets
 
5.2

24.3

 
134.7

Contributions to joint ventures
 
(210.0
)
(95.4
)
 
(241.7
)
Distributions from joint ventures
 
208.0

90.5

 
236.7

Advances to related parties
 
(4.1
)
(0.4
)
 
(23.3
)
Repayments of loans from related parties
 
35.2

31.1

 
13.2

Other, net
 
(2.4
)
(0.3
)
 
(8.2
)
Net cash (used in) provided by investing activities
 
(34.9
)
15.1

 
(199.7
)
Cash Flows From Financing Activities
 
 
 
 
 
Proceeds from long-term debt
 
—

1,000.0

 
1,429.8

Successor Notes issuance proceeds into escrow
 
—

(1,000.0
)
 
—

Repayments of long-term debt
 
(332.1
)
(2.1
)
 
(11.2
)
Payment of deferred financing costs
 
(6.1
)
(45.4
)
 
(29.8
)
Common stock repurchases
 
(69.2
)
—

 
—

Distributions to noncontrolling interests
 
(16.7
)
(0.1
)
 
(3.9
)
Other, net
 
—

(0.1
)
 
(1.9
)
Net cash (used in) provided by financing activities
 
(424.1
)
(47.7
)
 
1,383.0

Net change in cash and cash equivalents
 
(128.7
)
181.4

 
906.5

Cash and cash equivalents at beginning of period
 
1,053.7

872.3

 
261.3

Cash and cash equivalents at end of period
 
$
925.0

$
1,053.7

 
$
1,167.8


See accompanying notes to unaudited condensed consolidated financial statements.


4

Table of Contents



PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

 
 
 
Peabody Energy Corporation Stockholders’ Equity
 
 
 
 
 
Series A Convertible Preferred Stock
 
Common Stock
 
Additional
Paid-in
Capital
 
Treasury Stock
 
(Accumulated Deficit) Retained Earnings
 
Accumulated
Other Comprehensive
(Loss) Income
 
Noncontrolling
Interests
 
Total
Stockholders’
Equity
 
 
 
(Dollars in millions)
December 31, 2016 - Predecessor
$
—


$
0.2


$
2,422.0


$
(371.8
)

$
(1,399.5
)

$
(477.0
)

$
7.6


$
181.5

Net (loss) income
—


—


—


—


(216.5
)

—


4.8


(211.7
)
Net realized losses on cash flow hedges (net of $9.1 net tax provision)
—


—


—


—


—


18.6


—


18.6

Postretirement plans and workers’ compensation obligations (net of $2.5 net tax provision)
—


—


—


—


—


4.4


—


4.4

Foreign currency translation adjustment
—


—


—


—


—


5.5


—


5.5

Share-based compensation for equity-classified awards
—


—


1.9


—


—


—


—


1.9

Repurchase of employee common stock relinquished for tax withholding
—


—


—


(0.1
)

—


—


—


(0.1
)
Distributions to noncontrolling interests
—


—


—


—


—


—


(0.1
)

(0.1
)
Elimination of Predecessor equity
—


(0.2
)

(2,423.9
)

371.9


1,616.0


448.5


(12.3
)

—

April 1, 2017 - Predecessor
$
—


$
—


$
—


$
—


$
—


$
—


$
—


$
—

Issuance of Successor equity
1,305.4


0.7


1,774.9


—


—


—


50.9


3,131.9

April 2, 2017 - Successor
$
1,305.4


$
0.7


$
1,774.9


$
—


$
—


$
—


$
50.9


$
3,131.9

Net income
—


—


—


—


319.8


—


8.9


328.7

Foreign currency translation adjustment
—


—


—


—


—


1.8


—


1.8

Warrant conversions
—

 
0.1


(0.1
)

—


—


—


—


—

Series A Convertible Preferred Stock conversions
(616.7
)

0.2


640.0


—


(23.5
)

—


—


—

Series A Convertible Preferred Stock dividends
3.0


—


(3.0
)

—


—


—


—


—

Share-based compensation for equity-classified awards
—


—


14.1


—


—


—


—


14.1

Common stock repurchases
—


—


—


(69.2
)

—


—


—


(69.2
)
Distributions to noncontrolling interests
—


—


—


—


—


—


(16.7
)

(16.7
)
September 30, 2017 - Successor
$
691.7


$
1.0


$
2,425.9


$
(69.2
)

$
296.3


$
1.8


$
43.1


$
3,390.6


See accompanying notes to unaudited condensed consolidated financial statements.



5

Table of Contents



PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(1) Basis of Presentation
The condensed consolidated financial statements include the accounts of Peabody Energy Corporation (PEC) and its consolidated subsidiaries and affiliates (along with PEC, the Company or Peabody). 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 unaudited condensed consolidated financial statements. All intercompany transactions, profits and balances have been eliminated in consolidation.
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements and should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017. In the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation and certain prior year amounts have been reclassified for consistency with the current period presentation. Balance sheet information presented herein as of December 31, 2016 has been derived from the Company’s audited consolidated balance sheet at that date. The Company’s results of operations for the three months ended September 30, 2017 and the period April 2, 2017 through September 30, 2017 are not necessarily indicative of the results that may be expected for future quarters.
The Company has classified items within discontinued operations in the unaudited condensed 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.
Plan of Reorganization and Emergence from Chapter 11 Cases
On April 13, 2016, (the Petition Date), PEC and a majority of its wholly owned domestic subsidiaries, as well as one international subsidiary in Gibraltar (collectively with PEC, the Debtors), filed voluntary petitions (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 Debtors’ Chapter 11 cases (the Chapter 11 Cases) were jointly administered under the caption In re Peabody Energy Corporation, et al., Case No. 16-42529.
For periods subsequent to filing the Bankruptcy Petitions, the Company applied the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, “Reorganizations”, in preparing its consolidated financial statements. ASC 852 requires that financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that were realized or incurred in the bankruptcy proceedings were recorded in “Reorganization items, net” in the unaudited condensed consolidated statements of operations. In addition, the pre-petition obligations that were impacted by the bankruptcy reorganization process were classified as “Liabilities subject to compromise” in the accompanying condensed consolidated balance sheet at December 31, 2016.
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 the 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 and 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, Docket No. 2763 (the Confirmation Order), confirming the Plan. On April 3, 2017, (the Effective Date), the Debtors satisfied the conditions to effectiveness set forth in the Plan, the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On the Effective Date, in accordance with ASC 852, the Company applied fresh start reporting which requires the Company to allocate its reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. The Company was permitted to use fresh start reporting because (i) the holders of existing voting shares of the Predecessor (as defined below) company received less than 50% of the voting shares of the emerging entity upon reorganization and (ii) the reorganization value of the Company’s assets immediately prior to Plan confirmation was less than the total of all postpetition liabilities and allowed claims.
Upon adoption of fresh start reporting, the Company became a new entity for financial reporting purposes, reflecting the Successor (as defined below) capital structure. As a result, a new accounting basis in the identifiable assets and liabilities assumed was established with no retained earnings or accumulated other comprehensive income (loss) (OCI) for financial reporting purposes. The Company selected an accounting convenience date of April 1, 2017 for purposes of applying fresh start reporting as the activity between the convenience date and the Effective Date does not result in a material difference in the results. References to “Successor” in the financial statements and accompanying footnotes are in reference to reporting dates on or after April 2, 2017; references to “Predecessor” in the financial statements and accompanying footnotes are in reference to reporting dates through April 1, 2017 which includes the impact of the Plan provisions and the application of fresh start reporting. As such, the Company’s financial statements for the Successor will not be comparable in many respects to its financial statements for periods prior to the adoption of fresh start reporting and prior to the accounting for the effects of the Plan. For further information on the Plan and fresh start reporting, see Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting.”
In connection with fresh start reporting, the Company made certain accounting policy elections that impact the Successor periods presented herein and will impact prospective periods. The Company will classify the amortization associated with its asset retirement obligation assets within “Depreciation, depletion and amortization” in its consolidated statements of operations, rather than within “Asset retirement obligation expenses”, as in Predecessor periods. With respect to its accrued postretirement benefit and pension obligations, the Company will prospectively record amounts attributable to prior service cost and actuarial valuation changes, as applicable, currently in earnings rather than recording such amounts within accumulated other comprehensive income and amortizing to expense over applicable time periods.
(2)    Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
Newly Adopted Accounting Standards
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 became effective prospectively for annual periods beginning after December 15, 2016 (January 1, 2017 for the Company). 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.
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 was 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.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The new standard will be effective for interim and annual periods beginning after December 15, 2017 (January 1, 2018 for the Company), with early adoption permitted. The standard allows for either a full retrospective adoption or a modified retrospective adoption. The Company’s primary source of revenue is from the sale of coal through both short-term and long-term contracts with utilities, industrial customers and steel producers whereby revenue is currently recognized when risk of loss has passed to the customer. Upon adoption of this new standard, the Company believes that the timing of revenue recognition related to its coal sales will remain consistent with its current practice. The Company has reviewed its portfolio of coal sales contracts and the various terms and clauses within each contract and believes it is unlikely that its revenue recognition policies for such contracts will be materially impacted by the standard. The Company is also evaluating other revenue streams to determine the potential impact related to the adoption of the standard, as well as potential disclosures required by the standard. The Company plans to adopt the standard under the modified retrospective approach.
Lease Accounting. In February 2016, the FASB issued accounting guidance that will require a lessee to recognize on 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.
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 the classification 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 on the Company’s statements of cash flows.
Compensation - Retirement Benefits. In March 2017, the FASB issued accounting guidance which requires employers that sponsor defined benefit pension and other postretirement plans to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. 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 the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivatives and Hedging. In August 2017, the FASB issued accounting guidance to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirement to separately measure and report hedge ineffectiveness, as well as eases certain hedge effectiveness assessment requirements. The new guidance will be effective for fiscal years beginning after December 15, 2018 (January 1, 2019 for the Company) and interim periods therein, with early adoption permitted. The amendments to cash flow and net investment hedge relationships that exist on the date of adoption will be applied using a modified retrospective approach. The presentation and disclosure requirements will be applied prospectively. The Company is currently evaluating the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.
(3)    Emergence from the Chapter 11 Cases and Fresh Start Reporting
The following is a summary of certain provisions of the Plan, as confirmed by the Bankruptcy Court pursuant to the Confirmation Order, and is not intended to be a complete description of the Plan, which is included in its entirety as Exhibit 2.2 of the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission (SEC) on March 20, 2017.
The consummation of the Plan resulted in the following capital structure on the Effective Date:
•Successor Notes - $1,000.0 million first lien senior secured notes
•Successor Credit Facility - a first lien credit facility of $950.0 million
•
Series A Convertible Preferred Stock - $750.0 million for 30.0 million shares of Series A Convertible Preferred Stock
•
Common Stock and Warrants - $750.0 million for common stock and warrants issued in connection with a Rights Offering (as defined below), resulting in, together with other issuances of common stock, the issuance of 70.9 million shares of a single class of common stock and warrants to purchase 6.2 million shares of common stock
The new debt and equity instruments comprising the Successor Company’s capital structure are further described below.
Treatment of Classified Claims and Interests
The following summarizes the various classes of claimants’ recoveries under the Plan. Undefined capitalized terms used in this section, Treatment of Classified Claims and Interests, are defined in the Plan.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

First Lien Lender Claims (Classes 1A - 1D)
 
Paid in full in cash.
 
 
 
Second Lien Notes Claims (Classes 2A - 2D)
 
A combination of (1) $450 million of cash, first lien debt and/or new second lien notes and (2)(a) new common stock, par value $0.01 per share, of the Reorganized Peabody (Common Stock) and (b) subscription rights in the Rights Offering.
 
 
 
Other Secured Claims (Classes 3A - 3E)
 
At the election of the Debtors, (1) reinstatement, (2) payment in full in cash, (3) receipt of the applicable collateral or (4) such other treatment consistent with section 1129(b) of the Bankruptcy Code.
 
 
 
Other Priority Claims (Classes 4A - 4E)
 
Paid in full in cash.
 
 
 
General Unsecured Claims
 
Class 5A: Against Peabody Energy: a pro rata share of $5 million in cash plus an amount of additional cash (up to $2 million) not otherwise paid to holders of Convenience Claims.
 
 
Class 5B: Against the Encumbered Guarantor Debtors: (1) Common Stock and subscription rights in the Rights Offering or (2) at the election of the claim holder, cash from a pool of $75 million in cash to be paid by the Debtors and the Reorganized Debtors into a segregated account in accordance with the terms set forth in the Plan.
 
 
Class 5C: Against the Gold Fields Debtors: units in the Gold Fields Liquidating Trust.
 
 
Class 5D: Against Peabody Holdings (Gibraltar) Limited: no recoveries.
 
 
Class 5E: Against the Unencumbered Debtors: cash in the amount of such holder’s allowed claim, less any amounts attributable to late fees, postpetition interest or penalties.
 
 
 
Convenience Claims
 
Class 6A: Against Peabody Energy: up to 72.5% of such claim in cash, provided that total payments to Convenience Claims may not exceed $2 million.
 
 
Class 6B: Against the Encumbered Guarantor Debtors: up to 72.5% of such claim in cash, provided that total payments to Convenience Claims may not exceed $18 million.
 
 
 
United Mine Workers of America 1974 Pension Plan Claim
(Classes 7A - 7E)
 
$75 million in cash paid over five years. See Note 5. “Discontinued Operations,” for additional details.
Unsecured Subordinated Debentures Claims
(Class 8A)
 
(1) Payment of the reasonable and documented fees and expenses of the trustee under the 2066 subordinated indenture up to $350,000; and (2) because this class voted in favor of the Plan and in connection with the settlement of certain potential intercreditor disputes as part of the global settlement embodied therein, and because the trustee under the 2066 subordinated indenture did not object to, and affirmatively supported, the Plan, holders of allowed Unsecured Subordinated Debenture Claims received from specified noteholder co-proponents their pro rata share of penny warrants exercisable for 1.0% of the fully diluted Reorganized Peabody common stock from the pool of penny warrants issued to the noteholder co-proponents under the Rights Offering and/or the terms of the Backstop Commitment Agreement (as defined below).
 
 
 
Section 510(b) Claims
(Class 10A)
 
No recovery.
 
 
 
Peabody Energy Equity Interests
(Class 11A)
 
No recovery, as further described under Cancellation of Prior Common Stock below.
 
 
 



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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Cancellation of Prior Common Stock
In accordance with the Plan and as previously disclosed, each share of the Company’s common stock outstanding prior to the Effective Date, including all options and warrants to purchase such stock, were extinguished, canceled and discharged, and each such share, option or warrant has no further force or effect as of the Effective Date. Furthermore, all of the Company’s equity award agreements under prior incentive plans, and the awards granted pursuant thereto, were extinguished, canceled and discharged and have no further force or effect as of the Effective Date.
Issuance of Equity Securities
Section 1145 Securities
On the Effective Date and simultaneous with the cancellation of the prior common stock discussed above, in connection with the Company’s emergence from the Chapter 11 Cases and in reliance on the exemption from registration requirements of the Securities Act of 1933 (the Securities Act) provided by Section 1145 of the Bankruptcy Code, the Company issued:
•
11.6 million shares of Common Stock to holders of Allowed Claims (as defined in the Plan) in Classes 2A, 2B, 2C, 2D and 5B on account of such claims as provided in the Plan; and
•
51.2 million shares of Common Stock and 2.9 million Warrants (the 1145 Warrants) pursuant to the completed Rights Offering to certain holders of the Company’s prepetition indebtedness for total consideration of $704.4 million.
Any shares of Common Stock issued pursuant to the exercise of such 1145 Warrants were similarly issued pursuant to the exemption from registration provided by Section 1145 of the Bankruptcy Code.
Section 4(a)(2) Securities
In addition, on the Effective Date, in connection with the Company’s emergence from the Chapter 11 Cases and in reliance on the exemption from registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act, the Company issued:
•
30.0 million shares of Series A Convertible Preferred Stock (the Preferred Stock) to parties to the Private Placement Agreement, dated as of December 22, 2016 (as amended, the Private Placement Agreement), among the Company and the other parties thereto, for total consideration of $750.0 million;
•
3.3 million shares of Common Stock and 0.2 million Warrants (the Private Warrants, and together with the 1145 Warrants, the Warrants) to parties to the Backstop Commitment Agreement, dated as of December 22, 2016 (as amended, the Backstop Commitment Agreement), among the Company and the other parties thereto, on account of their commitments under that agreement, for total consideration of $45.6 million; and
•
4.8 million shares of Common Stock and 3.1 million additional Private Warrants to specified parties to the Private Placement Agreement and Backstop Commitment Agreement on account of commitment premiums contemplated by those agreements.
Any shares of Common Stock issued pursuant to the conversion of the Preferred Stock or the exercise of such Private Warrants have been or will be issued pursuant to the exemption from registration provided by Section 3(a)(9) and/or Section  4(a)(2) of the Securities Act. The securities issued in reliance on Section 4(a)(2) of the Securities Act were subject to restrictions on transfer; however, substantially all such shares were registered with the SEC on a resale Form S-1 effective July 14, 2017.
Current Equity Structure
During the three months ended September 30, 2017, the Company made repurchases of approximately 2.5 million shares of its Common Stock pursuant to its share repurchase program, as described in Note 16. “Other Events”. As of September 30, 2017, the Company would have approximately 134.8 million shares of Common Stock outstanding, assuming full conversion of the Preferred Stock (including make-whole shares issuable upon conversion of the Preferred Stock). This amount excludes approximately 3.5 million shares of Common Stock which underlie unvested equity awards granted under the 2017 Incentive Plan (as defined below).


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other Forms of Equity Authorized under the Company’s Certificate of Incorporation
As noted on the accompanying condensed consolidated balance sheets, the Company’s Fourth Amended and Restated Certificate of Incorporation authorizes the issuances of additional series of preferred stock, as well as series common stock. Other than the Series A Convertible Preferred Stock, no other series of preferred stock is outstanding as of September 30, 2017. Additionally, as of September 30, 2017, no series common stock is outstanding. A copy of the Company’s Fourth Amended and Restated Certificate of Incorporation is included as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.
Preferred Stock
The Preferred Stock accrues dividends at a rate of 8.5% per year, payable in-kind semi-annually on April 30 and October 31 of each year as additional shares of Series A Convertible Preferred Stock, and may be converted into a number of shares of Common Stock as described below. The Preferred Stock will also participate on an as-converted basis (giving effect to any accrued and unpaid dividends) in any dividend, distribution or payments to holders of Common Stock. Upon the Company’s liquidation, dissolution or wind up, whether voluntarily or involuntarily, the holders of Preferred Stock are granted a liquidation preference of $25.00 per share of Preferred Stock, plus any accrued but unpaid dividends through the date of liquidation. The Preferred Stock may also participate on an as-converted basis in any payments upon liquidation payable to the holders of Common Stock.
The Preferred Stock shall be convertible into Common Stock at any time, at the option of the holders at an initial conversion price of $16.25, representing a discount of 35% to the equity value assigned to the Common Stock by the Plan (subject to customary anti-dilution adjustments, the Conversion Price). If at any time following the Effective Date, less than 7,500,000 shares of Preferred Stock remain outstanding, then the Company shall have the right, but not the obligation, to redeem all (but not less than all) of the remaining shares of Preferred Stock, following thirty days’ notice, and on no more than 60 days’ notice, at a redemption price equal to $25.00 per share of Preferred Stock, payable in cash or shares of Common Stock at the Company’s election, subject to certain adjustments; provided that the Company shall not redeem any shares of Preferred Stock for cash during any time that any obligations under the Successor Credit Agreement (as defined below) remain outstanding. At any time following the Effective Date, if holders of at least 66 2/3% of the outstanding Preferred Stock elect to convert, then all remaining outstanding Preferred Stock will automatically convert at the same time and on the same terms.
In addition, beginning on the Effective Date, each outstanding share of Preferred Stock shall automatically convert into a number of shares of Common Stock at the Conversion Price (such conversion, the Mandatory Conversion) if the volume weighted average price of the Common Stock exceeds $32.50 (the Conversion Threshold) for at least 45 trading days in a 60 consecutive trading day period, including each of the last 20 days in such 60 consecutive trading day period (such period, the Mandatory Conversion Period).
Finally, the Preferred Stock shall automatically convert into shares of Common Stock immediately prior to the consummation of a Fundamental Change (generally defined as significant business combinations, as fully defined in the Certificate of Designation of Series A Convertible Preferred Stock included as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on April 3, 2017) if either (1) at consummation of the Fundamental Change, the price of the Common Stock exceeds the Conversion Threshold, or (2) the consideration payable in the Fundamental Change per share of Common Stock exceeds the Conversion Threshold and is payable in cash.
Upon any optional or mandatory conversion of the Preferred Stock that occurs on or prior to the three year anniversary of its initial issuance, holders of the Preferred Stock will be deemed to have (1) received dividends through the last payment of dividends prior to the conversion, including dividends received on prior dividends, to the extent accrued and not previously paid; and (2) dividends on the shares of Preferred Stock then outstanding and any shares deemed issued pursuant to the preceding clause accruing from the last dividend date preceding the date of the conversion through, but not including, the three year anniversary of their initial issuance, and all dividends on prior dividends. In respect of an optional or mandatory conversion occurring after the three year anniversary of its initial issuance, there shall be deemed to have been issued in respect of all shares of Preferred Stock at the time outstanding (1) dividends through the date of payment of the dividend immediately preceding the date of the conversion, including dividends on such dividends, to the extent accrued and not previously paid, and (2) dividends on (a) the shares of Preferred Stock at the time outstanding and (b) any shares of Preferred Stock deemed issued pursuant to the preceding clause (1) accruing from the date of payment of the dividend immediately preceding the conversion, through, but not including, the date of conversion and all dividends on such dividends.
There are no restrictions on the repurchase or redemption of the Preferred Stock while there is any arrearage in the payment of dividends.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Preferred Stock votes with the Common Stock as a single class on an as-converted basis on all matters submitted to a vote of the holders of Common Stock with the exception of certain matters, as outlined in the Certificate of Designation of Series A Convertible Preferred Stock, in which the holders of Preferred Stock are entitled to vote as a separate class with a majority vote required for approval. Such matters include any Fundamental Change requiring approval of the holders of Common Stock and authorization of cash dividends on Common Stock in excess of $100 million payable in any 12-month period.
Rights Offering
Pursuant to the Plan and Rights Offering, holders of Allowed Claims in Classes 2A, 2B, 2C, 2D and 5B were offered the opportunity to purchase up to 54.5 million units, each unit being comprised of (1) one share of Common Stock and (2) a fraction of a Warrant. The purchase price for the units offered in the Rights Offering was $13.75 per unit. A total of 51.2 million units were purchased in the Rights Offering. Pursuant to the Backstop Commitment Agreement, the remaining 3.3 million units that were not purchased in the Rights Offering were purchased by the parties to the Backstop Commitment Agreement at the same per-unit price.
Registration Rights Agreement
On the Effective Date, the Company entered into a registration rights agreement (Registration Rights Agreement) with certain parties (together with any person or entity that becomes a party to the Registration Rights Agreement, the Holders) that received shares of the Company’s Common Stock and Preferred Stock in the Company on the Effective Date, as provided in the Plan. The Registration Rights Agreement provides Holders with registration rights for the Holders’ Registrable Securities (as defined in the Registration Rights Agreement). Substantially all of the Holders’ Registrable Securities were registered with the SEC on Form S-1 effective July 14, 2017.
The registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in an underwritten offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. A copy of the Registration Rights Agreement is included as Exhibit 10.1 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.
Warrant Agreement
On the Effective Date, the Company entered into a warrant agreement (the Warrant Agreement) with American Stock Transfer and Trust Company, LLC. In accordance with the Plan, the Company issued 6.2 million warrants to purchase one share of Common Stock each at an exercise price of $0.01 per share to all Noteholder Co-Proponents (as defined in the Plan) and subscribers in the Rights Offering (as defined in the Plan) and related backstop commitment. All Warrants described above under the heading Issuance of Equity Securities were issued under the Warrant Agreement. All unexercised Warrants expired, and the rights of the holders of such Warrants to purchase Common Stock terminated on July 3, 2017, with less than 0.1% of the Warrants unexercised.
A copy of the Warrant Agreement is included as Exhibit 4.1 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.
6.000% and 6.375% Senior Secured Notes (collectively, the Successor Notes)
On February 15, 2017, one of PEC’s subsidiaries entered into an indenture with Wilmington Trust, National Association, as trustee, relating to the issuance by PEC’s subsidiary of $500.0 million aggregate principal amount of 6.000% senior secured notes due 2022 (the 2022 Notes) and $500.0 million aggregate principal amount of 6.375% senior secured notes due 2025 (together with the 2022 Notes, the Successor Notes). The Successor Notes were sold on February 15, 2017 in a private transaction exempt from the registration requirements of the Securities Act.
Prior to the Effective Date, PEC’s subsidiary deposited the proceeds of the offering of the Successor Notes into an escrow account pending confirmation of the Plan and certain other conditions being satisfied. On the Effective Date, the proceeds from the Successor Notes were used to repay the predecessor first lien obligations.
The Successor Notes are further described in Note 13. “Long-term Debt” and copies of the indenture documents underlying the Successor Notes are incorporated as Exhibit 4.3 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Successor Credit Agreement
In connection with an exit facility commitment letter, on the Effective Date, the Company entered into a credit agreement, dated as of April 3, 2017, among the Company, as Borrower, Goldman Sachs Bank USA, as Administrative Agent, and other lenders party thereto (the Successor Credit Agreement). The Successor Credit Agreement originally provided for a $950.0 million senior secured term loan, which matures in 2022 and prior to the amendment described in Note 13. “Long-term Debt,” bore interest at LIBOR plus 4.50% per annum with a 1.00% LIBOR floor. Following the amendment the loan bears interest at LIBOR plus 3.50% per annum with a 1.00% LIBOR floor. On the Effective Date, the proceeds from the Successor Credit Agreement were used to repay the predecessor first lien obligations.
The Successor Credit Agreement and the amendment are further described in Note 13. “Long-term Debt.” A copy of the Successor Credit Agreement is included as Exhibit 10.3 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017 and a copy of the amendment is included as Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on September 18, 2017.
Securitization Facility
In connection with a receivables securitization program commitment letter, on the Effective Date, the Company entered into the Sixth Amended and Restated Receivables Purchase Agreement, as amended, dated as of April 3, 2017 (Receivables Purchase Agreement), among P&L Receivables Company, LLC (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 Bank, National Association (PNC), as administrator. The Receivables Purchase Agreement extends the receivables securitization facility previously in place and expands that facility to include certain receivables from the Company’s Australian operations.
The Receivables Purchase Agreement is further described in Note 18. “Financial Instruments and Other Guarantees” and a copy of the Receivables Purchase Agreement is included as Exhibit 10.4 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.


14

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Cancellation of Prepetition Obligations
In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the following debt instruments were canceled:
•
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, as trustee, 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, as trustee, 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, as trustee, 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, as trustee, 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 trustee, 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 a term loan facility (the 2013 Term Loan Facility) and $1,650.0 million under a revolving credit facility (the 2013 Revolver), which includes approximately $675.0 million of posted but undrawn letters of credit and approximately $947.0 million in outstanding borrowings, by and among the Company, Citibank, N.A., as administrative agent, swing line lender and letter of credit 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 Amendment Agreement, dated as of February 5, 2015.
2017 Incentive Compensation Plan
In accordance with the Plan, the Peabody Energy Corporation 2017 Incentive Plan (the 2017 Incentive Plan) became effective as of the Effective Date. The 2017 Incentive Plan is intended to, among other things, help attract and retain employees and directors upon whom, in large measure, the Company depends for sustained progress, growth and profitability. The 2017 Incentive Plan also permits awards to consultants.
Unless otherwise determined by the Board, the compensation committee of the Board will administer the 2017 Incentive Plan. The 2017 Incentive Plan generally provides for the following types of awards:
•
options (including non-qualified stock options and incentive stock options);
•
stock appreciation rights;
•
restricted stock;
•
restricted stock units;
•
deferred stock;
•
performance units;
•
dividend equivalents; and
•
cash incentive awards.
The aggregate number of shares of Common Stock reserved for issuance pursuant to the 2017 Incentive Plan is 14.1 million. The 2017 Incentive Plan will remain in effect, subject to the right of the Board to terminate the 2017 Incentive Plan at any time, subject to certain restrictions, until the earlier to occur of (a) the date all shares of Common Stock subject to the 2017 Incentive Plan are purchased or acquired and the restrictions on all restricted stock granted under the 2017 Incentive Plan have lapsed, according to the 2017 Incentive Plan’s provisions, and (b) ten years from the Effective Date.


15

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Reorganization Value
Fresh start reporting provides, among other things, for a determination of the value to be assigned to the equity of the emerging company as of a date selected for financial reporting purposes. In conjunction with the bankruptcy proceedings, a third-party financial advisor provided an enterprise value of the Company of approximately $4.2 billion to $4.9 billion. The final equity value of $3,081.0 million was based upon the approximate low end of the enterprise value established by the third-party valuation and cash held by the Successor company in connection with the emergence from the Chapter 11 Cases, less the fair value of Successor debt issued on the Effective Date as described above. The final equity value equated to a per share value of $22.03 per equivalent common share issued in accordance with the Plan.
The enterprise value of the Company was estimated using two primary valuation methods: a comparable public company analysis and a discounted cash flow (DCF) analysis. The comparable public company analysis is based on the enterprise value of selected publicly traded companies that have operating and financial characteristics comparable in certain respects to the Company, for example, operational requirements and risk and profitability characteristics. Selected companies were comprised of coal mining companies with primary operations in the United States. Under this methodology, certain financial multiples and ratios that measure financial performance and value were calculated for each selected company and then applied to the Company’s financials to imply an enterprise value for the Company.
The DCF analysis is a forward-looking enterprise valuation methodology that estimates the value of an asset or business by calculating the present value of expected future cash flows by that asset or business. The basis of the DCF analysis was the Company’s prepared projections which included a variety of estimates and assumptions, such as pricing and demand for coal. The Company’s pricing was based on its view of the market taking into account third-party forward pricing curves adjusted for the quality of products sold by the Company. While the Company considers such estimates and assumptions reasonable, they are inherently subject to significant business, economic and competitive uncertainties, many of which are beyond the Company’s control and, therefore, may not be realized. Changes in these estimates and assumptions may have a significant effect on the determination of the Company’s enterprise value. The assumptions used in the calculations for the DCF analysis included projected revenue, cost and cash flows for the nine months ending December 31, 2017 through each respective mine life and represented the Company’s best estimates at the time the analysis was prepared. The DCF analysis was completed using discount rates ranging from 11% to 14%. The DCF analysis involves complex considerations and judgments concerning appropriate discount rates. Due to the unobservable inputs to the valuation, the fair value would be considered Level 3 in the fair value hierarchy.
Grant of Emergence Awards
On the Effective Date, the Company granted restricted stock units under the 2017 Incentive Plan and the terms of the relevant restricted stock unit agreement to all employees, including its executive officers (the Emergence Awards). The fair value of the Emergence Awards on the Effective Date was $80.0 million. The Emergence Awards granted to the Company’s executive officers generally will vest ratably on each of the first three anniversaries of the Effective Date, subject to, among other things, each such executive officer’s continued employment with the Company. The Emergence Awards will become fully vested upon each such executive officer’s termination of employment by the Company and its subsidiaries without Cause or by the executive for Good Reason (each, as defined in the 2017 Incentive Plan or award agreement) or due to a termination of employment with the Company and its subsidiaries by reason of death or Disability (as defined in the 2017 Incentive Plan or award agreement). In order to receive the Emergence Awards, the executive officers were required to execute restrictive covenant agreements protecting the Company’s interests.
Copies of the 2017 Incentive Plan and related documents are included as Exhibits 10.7 and 10.8 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.


16

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Plan and Fresh Start Reporting Adjustments
The following balance sheet illustrates the impacts of the implementation of the Plan and the application of fresh start reporting, which results in the opening balance sheet of the Successor company.
As of April 1, 2017
Predecessor (a)
 
Effect of Plan
(b)
 
Fresh Start Adjustments (c)
 
Successor
 
(Dollars in millions)
ASSETS
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
Cash and cash equivalents
$
1,068.1

 
$
(14.4
)
(d)
$
—

 
$
1,053.7

Restricted cash
80.7

 
(54.7
)
(d)
—

 
26.0

Successor Notes issuance proceeds - restricted cash
1,000.0

 
(1,000.0
)
(d)
—

 
—

Accounts receivable, net
312.1

 
—

 
—

 
312.1

Inventories
250.8

 
—

 
70.1

(k)
320.9

Assets from coal trading activities, net
0.6

 
—

 
—

 
0.6

Other current assets
493.9

 
(18.1
)
(e)
(333.0
)
(l)
142.8

Total current assets
3,206.2

 
(1,087.2
)
 
(262.9
)
 
1,856.1

Property, plant, equipment and mine development, net
8,653.9

 
—

 
(3,461.4
)
(m)
5,192.5

Investments and other assets
976.4

 
3.9

(f)
238.0

(n)
1,218.3

Total assets
$
12,836.5

 
$
(1,083.3
)
 
$
(3,486.3
)
 
$
8,266.9

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
Current portion of long-term debt
$
18.2

 
$
9.5

(g)
$
—

 
$
27.7

Liabilities from coal trading activities, net
0.7

 
—

 
—

 
0.7

Accounts payable and accrued expenses
967.3

 
257.6

(h)
14.8

(o)
1,239.7

Total current liabilities
986.2

 
267.1

 
14.8

 
1,268.1

Long-term debt, less current portion
950.5

 
903.2

(g)
—

 
1,853.7

Deferred income taxes
179.2

 
—

 
(177.8
)
(p)
1.4

Asset retirement obligations
707.0

 
—

 
(73.9
)
(q)
633.1

Accrued postretirement benefit costs
753.9

 
—

 
(6.9
)
(r)
747.0

Other noncurrent liabilities
511.1

 
—

 
120.6

(s)
631.7

Total liabilities not subject to compromise
4,087.9

 
1,170.3

 
(123.2
)
 
5,135.0

Liabilities subject to compromise
8,416.7

 
(8,416.7
)
(i)
—

 
—

Total liabilities
12,504.6

 
(7,246.4
)
 
(123.2
)
 
5,135.0

Stockholders’ equity
 
 
 
 
 
 
 
Common Stock (Predecessor)
0.2

 
(0.2
)
(j)
—

 
—

Common Stock (Successor)
—

 
0.7

(b)
—

 
0.7

Series A Preferred Stock (Successor)
—

 
1,305.4

(b)
—

 
1,305.4

Additional paid-in capital (Predecessor)
2,423.9

 
(2,423.9
)
(j)
—

 
—

Additional paid-in capital (Successor)
—

 
1,774.9

(b)
—

 
1,774.9

Treasury stock, at cost
(371.9
)
 
371.9

(j)
—

 
—

Accumulated deficit
(1,284.1
)
 
5,134.3

(j)
(3,850.2
)
(t)
—

Accumulated other comprehensive loss
(448.5
)
 
—

 
448.5

(t)
—

Peabody Energy Corporation stockholders’ equity
319.6

 
6,163.1

 
(3,401.7
)
 
3,081.0

Noncontrolling interests
12.3

 
—

 
38.6

(u)
50.9

Total stockholders’ equity
331.9

 
6,163.1

 
(3,363.1
)
 
3,131.9

Total liabilities and stockholders’ equity
$
12,836.5

 
$
(1,083.3
)
 
$
(3,486.3
)
 
$
8,266.9






17

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(a)
Represents the Predecessor consolidated balance sheet at April 1, 2017.
(b)
Represents amounts recorded for the implementation of the Plan on the Effective Date. This includes the settlement of liabilities subject to compromise through a combination of cash payments, the issuance of new common stock and warrants and the issuance of new debt. The following is the calculation of the total pre-tax gain on the settlement of the liabilities subject to compromise.
 
 
(Dollars in millions)
Liabilities subject to compromise
 
$
8,416.7

Less amounts issued to settle claims:
 
 
Successor Common Stock (at par)
 
(0.7
)
Successor Series A Convertible Preferred Stock
 
(1,305.4
)
Successor Additional paid-in capital
 
(1,774.9
)
Issuance of Successor Notes
 
(1,000.0
)
Issuance of Successor Term Loan
 
(950.0
)
Cash payments and accruals for claims and professional fees
 
(336.4
)
Other:
 
 
Write-off of Predecessor debt issuance costs, see also (e) below
 
(18.1
)
Total pre-tax gain on plan effects, see also (j) below
 
$
3,031.2

At the Effective Date, 70.9 million shares of Common Stock were issued and outstanding at a par value of $0.01 per share.
Preferred Stock was recorded at fair value and is based upon the $750.0 million cash raised upon emergence from bankruptcy through the Private Placement Agreement, plus a premium to account for the fair value of the Preferred Stocks’ conversion and dividend features. Each share of Preferred Stock is convertible, at the holder’s election or upon the occurrence of certain triggering events, into shares of Common Stock at a 35% discount relative to the initial per share purchase price of $25.00 and provides for three years of guaranteed paid-in-kind dividends, payable semiannually, at a rate of 8.5% per annum. The 46.2 million shares of Common Stock issuable upon conversion of the Preferred Stock issued under the Plan and an additional 13.1 million shares of Common Stock attributable to such Preferred Stocks’ guaranteed paid-in-kind dividend feature constitute approximately 42% ownership of the Plan Equity Value (as defined in the Plan) of $3,105.0 million in the reorganized Company, and thus have a fair value of $1,305.4 million.
Successor Additional paid-in capital was recorded at the Plan Equity Value less the amounts recorded for par value of the Common Stock, the fair value of the Preferred Stock, and certain fees incurred associated with the Registration Rights Agreement.
(c)
Represents the fresh start reporting adjustments required to record the assets and liabilities of the Company at fair value.
(d)
The following table reflects the sources and uses of cash and restricted cash at emergence:
 
 
(Dollars in millions)
Sources:
 
 
Private placement and rights offering
 
$
1,500.0

Net proceeds from Senior Secured Term Loan
 
912.7

Escrowed interest from Successor Notes offering
 
8.0

Net impact on collateral requirements
 
11.6

Uses:
 
 
Payments to secured lenders
 
(3,489.2
)
Professional fees
 
(8.3
)
Securitization facility deferred financing costs
 
(3.9
)
Total cash outflow at emergence
 
$
(1,069.1
)


18

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(e)
Primarily represents the write off of deferred financing costs associated with the cancellation and discharge of Predecessor revolving debt obligations.
(f)
Represents the payment of deferred financing costs associated with the Receivables Purchase Agreement.
(g)
Represents a new $950 million Senior Secured Term Loan, net of an original issue discount and deferred financing costs of $37.3 million, as contemplated by the Plan. Under the Plan, the Company also issued $1.0 billion of Successor Notes, net of $49.5 million of deferred financing costs. The Successor Notes and the related proceeds held in escrow were included on the Company’s unaudited condensed consolidated balance sheet at March 31, 2017. The new debt instruments issued in accordance with the Plan are further described in Note 13. “Long-term Debt.”
(h)
Represents an accrual to account for amounts paid subsequent to the Effective Date for professional fees and certain unsecured claims and settlements set forth in the Plan.
(i)
Liabilities subject to compromise include secured and unsecured 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 were assumed under the Plan, and as such, were subsequently reclassified to liabilities not subject to compromise. Generally, actions to enforce or otherwise effect payment of prepetition liabilities are subject to the injunction provisions set forth in the Plan, as discussed in Note 19. “Commitments and Contingencies”. Liabilities subject to compromise consisted of the following immediately prior to emergence and at December 31, 2016:
 
Predecessor
 
April 1, 2017
December 31, 2016
 
(Dollars in millions)
Debt (1)
$
8,077.4

$
8,080.3

Interest payable
172.6

172.6

Environmental liabilities
61.9

61.9

Trade payables
55.2

58.4

Postretirement benefit obligations (2)
23.0

34.6

Other accrued liabilities
26.6

32.4

Liabilities subject to compromise
$
8,416.7

$
8,440.2

(1) 
Includes $7,768.3 million and $7,771.2 million of first lien, second lien and unsecured debt at April 1, 2017 and December 31, 2016, respectively, and $257.3 million of derivative contract terminations, and $51.8 million of liabilities secured by prepetition letters of credit at April 1, 2017 and December 31, 2016.
(2) 
Includes liabilities for unfunded non-qualified pension plans, all the participants of which are former employees.
(j)
Reflects the impacts of the reorganization adjustments:
 
 
(Dollars in millions)
Total pre-tax gain on plan effects, see also (b) above
 
$
3,031.2

Cancellation of Predecessor Common Stock
 
0.2

Cancellation of Predecessor Additional paid-in capital
 
2,423.9

Cancellation of Predecessor Treasury stock
 
(371.9
)
Successor debt issuance costs and other items, see also (f) and (g) above
 
50.9

Net impact on accumulated deficit
 
$
5,134.3

(k)
Represents adjustment to increase the book value of coal inventories to their estimated fair value, less costs to sell the inventories.
(l)
Represents adjustments comprising $228.5 million related to assets classified as held-for-sale at March 31, 2017 which were reclassified as held-for-use and considered in connection with the valuations described in (m) below, $89.5 million to write off certain existing short-term mine development costs, and $15.0 million of various prepaid assets deemed to have no future utility subsequent to the Effective Date.


19

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(m)
Represents a $3,461.4 million reduction in property, plant and equipment to estimated fair value as discussed below:
 
 
Predecessor
 
Fresh Start Adjustments
 
Successor
 
 
(Dollars in millions)
Land and coal interests
 
$
10,297.7

 
$
(6,511.8
)
 
$
3,785.9

Buildings and improvements
 
1,479.3

 
(1,013.2
)
 
466.1

Machinery and equipment
 
2,143.8

 
(1,203.3
)
 
940.5

Less: Accumulated depreciation, depletion and amortization
 
(5,266.9
)
 
5,266.9

 
—

Net impact on accumulated deficit
 
$
8,653.9

 
$
(3,461.4
)
 
$
5,192.5

The fair value of land and coal interests, excluding the asset related to the Company’s asset retirement obligations described below, was established at $3,504.7 million utilizing a DCF model and the market approach. The market approach was used to provide a starting value of the coal mineral reserves without consideration for economic obsolescence. The DCF model was based on assumptions market participants would use in the pricing of these assets as well as projections of revenues and expenditures that would be incurred to mine or maintain these coal reserves through the life of mine. The basis of the DCF analysis was the Company’s prepared projections which included a variety of estimates and assumptions, such as pricing and demand for coal. The Company’s pricing was based on its view of the market taking into account third-party forward pricing curves adjusted for the quality of products sold by the Company. The fair value of land and coal interests also includes $281.2 million corresponding to the asset retirement obligation discussed in item (q) below.
The fair value of buildings and improvements and machinery and equipment were set at $466.1 million and $940.5 million, respectively, utilizing both market and cost approaches. The market approach was used to estimate the value of assets where detailed information for the asset was available and an active market was identified with a sufficient number of sales of comparable property that could be independently verified through reliable sources. The cost approach was utilized where there were limitations in the secondary equipment market to derive values from. The first step in the cost approach is the estimation of the cost required to replace the asset via construction or purchasing a new asset with similar utility adjusting for depreciation due to physical deterioration, functional obsolescence due to technology changes and economic obsolescence due to external factors such as regulatory changes. Useful lives were assigned to all assets based on remaining future economic benefit of each asset.
(n)
Primarily to recognize fair value of $314.9 million inherent in certain U.S. coal supply agreements as a result of favorable differences between contract terms and estimated market terms for the same coal products, partially offset by a reduction in the fair value of certain equity method investments. The intangible asset related to coal supply agreements will be amortized on a per ton shipped basis through 2025, predominately over the next three years. See also Note 9. “Intangible Contract Assets and Liabilities.”
(o)
Represents $32.6 million to account for the short-term portion of the value of certain contract-based intangibles primarily consisting of unutilized capacity of certain port and rail take-or-pay contracts, partially offset by $15.7 million related to liabilities classified as held-for-sale at March 31, 2017 which were reclassified as held-for-use and considered in connection with the valuations described in (m) above, and various other fair value adjustments. The intangible liabilities related to port and rail take-or-pay contracts will be amortized ratably over the terms of each contact, which vary in duration through 2043.
(p)
Represents the tax impact of fresh start reporting. See also Note 12. “Income Taxes.”
(q)
Represents the fair value adjustment related to the Company’s asset retirement obligations which was calculated using DCF models based on current mine plans. The credit-adjusted, risk-free interest rates utilized to estimate the Company’s asset retirement obligations were 9.36% for its U.S. reclamation obligations and 4.36% for its Australia reclamation obligations.
(r)
Represents the remeasurement of liabilities associated with the Company’s postretirement benefits obligations as of the Effective Date as the reorganization of the Company pursuant to the Plan represented a remeasurement event under ASC 715 “Compensation - Retirement Benefits.” The relevant discount rate was adjusted to 4.1% from 4.15% used in the Company’s most recent year-end remeasurement process.


20

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(s)
Represents $83.6 million to account for the long-term portion of the value of contract-based intangibles related to unutilized capacity of port and rail take-or-pay contracts as described in (o) above and $58.7 million to account for the fair value inherent in certain U.S. coal supply agreements as a result of unfavorable differences between contract terms and estimated market terms for the same coal products as described in (n) above, partially offset by a remeasurement reduction of $9.2 million of the Company’s pension liabilities in accordance with ASC 715 as described in (r) above, as the relevant discount rate was adjusted to 4.1% from 4.15% used in the Company’s most recent year-end remeasurement process, and certain other valuation adjustments.
(t)
Represents the elimination of remaining equity balances in accordance with fresh start reporting requirements.
(u)
Represents adjustment to increase the book value of noncontrolling interests to fair value based on an estimate of the rights of the noncontrolling interests.
Reorganization Items, Net
The Company’s reorganization items for the period January 1 through April 1, 2017, and the three and nine months ended September 30, 2016 consisted of the following:
 
Predecessor
 
 
Three Months Ended September 30, 2016
 
January 1 through
April 1, 2017
 
Nine Months Ended September 30, 2016
 
(Dollars in millions)
Gain on settlement of claims (per above)
 
$
—

 
$
(3,031.2
)
 
$
—

Fresh start adjustments, net (per above)
 
—

 
3,363.1

 
—

Fresh start income tax adjustments, net
 
—

 
253.9

 
—

Loss on termination of derivative contracts
 
—

 
—

 
75.2

Professional fees
 
31.1

 
42.5

 
52.7

Accounts payable settlement gains
 
(0.5
)
 
(0.7
)
 
(0.7
)
Interest income
 
(0.9
)
 
(0.4
)
 
(1.1
)
Other
 
—

 
—

 
(1.0
)
Reorganization items, net
 
$
29.7

 
$
627.2

 
$
125.1

 
 
 
 
 
 
 
Cash paid for “Reorganization items, net”
 
$
30.7

 
$
45.8

 
$
30.7

The fresh start income tax adjustments included in the above table are comprised of tax benefits related to Predecessor deferred tax liabilities of $177.8 million, accumulated other comprehensive income of $81.5 million and unrecognized tax benefits of $6.7 million, partially offset by $12.1 million of tax expense related to the deferred tax assets of Predecessor discontinued operations.
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 unsecured creditors’ committee and certain other secured and unsecured creditors.
During the Successor period April 2, 2017 through September 30, 2017, the Company paid approximately $250 million related to professional fees and certain unsecured claims and settlements set forth in the Plan.
(4)    Asset Impairment
The Company’s mining and exploration assets and mining-related investments may be adversely affected by numerous factors that may cause the Company to be unable to recover all or a portion of the carrying value of those assets. As a result of various unfavorable conditions, including but not limited to sustained trends of weakness in U.S. and international seaborne coal market pricing and certain asset-specific factors, the Company recognized aggregate impairment charges of $247.9 million during the year ended December 31, 2016, which included $17.2 million during the first nine months of 2016 to write down certain targeted divestiture assets in Queensland, Australia. For additional information surrounding those charges, refer to Note 4. “Asset Impairment” to the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.


21

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company generally does not view short-term declines subsequent to previous impairment assessments in thermal and metallurgical coal prices in the markets in which it sells its products as an indicator of impairment. However, the Company generally views a sustained trend (for example, over periods exceeding one year) of adverse coal market pricing or unfavorable changes thereto as a potential indicator of impairment. Because of the volatile and cyclical nature of U.S. and international seaborne coal markets, it is reasonably possible that prices in those market segments may decrease and/or fail to improve in the near term, which, absent sufficient mitigation such as an offsetting reduction in the Company’s operating costs, may result in the need for future adjustments to the carrying value of the Company’s long-lived mining assets and mining-related investments.
During the period January 1 through April 1, 2017, the Company recognized impairment charges of $30.5 million related to terminated coal lease contracts in the Midwestern United States.
(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 periods April 2 through September 30, 2017, January 1 through April 1, 2017, and the three and nine months ended September 30, 2016:
 
 
Successor
Predecessor
 
Successor
Predecessor
 
 
Three Months Ended September 30, 2017
Three Months Ended September 30, 2016
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2016
 
 
(Dollars in millions)
Loss from discontinued operations, net of income taxes
 
$
(3.7
)
$
(38.1
)
 
$
(6.4
)
$
(16.2
)
 
$
(44.5
)


22

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Assets and Liabilities of Discontinued Operations
Assets and liabilities classified as discontinued operations included in the Company’s condensed consolidated balance sheets were as follows:
 
 
Successor
Predecessor
 
 
September 30, 2017
December 31, 2016
 
 
(Dollars in millions)
Assets:
 
 
 
Other current assets
 
$
0.2

$
0.2

Investments and other assets
 
—

15.9

Total assets classified as discontinued operations
 
$
0.2

$
16.1

 
 
 
 
Liabilities:
 
 
 
Accounts payable and accrued expenses
 
$
46.2

$
55.9

Other noncurrent liabilities
 
185.5

198.5

Liabilities subject to compromise
 
—

20.9

Total liabilities classified as discontinued operations
 
$
231.7

$
275.3

Patriot-Related Matters
A significant portion of the liabilities in the table above relate to a former subsidiary, 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 United Mine Workers of America (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 the Bankruptcy Code in the Eastern District of Virginia and subsequently initiated a process to sell some or all of its assets to qualified bidders. On October 9, 2015, Patriot’s bankruptcy court entered an order confirming Patriot’s plan of reorganization, which provided, among other things, for the sale of substantially all of Patriot’s assets to two different buyers.
Black Lung Occupational Disease Liabilities. Patriot has 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 2013 Agreement included Patriot’s affirmance of indemnities provided in the spin-off agreements, including the indemnity relating to such black lung liabilities; however, Patriot rejected this indemnity in its May 2015 bankruptcy.
By statute, the Company remains secondarily liable for the black lung liabilities related to Patriot’s workers employed by former subsidiaries of the Company. Whether the Company will ultimately be required to fund certain of those obligations in the future as a result of Patriot’s May 2015 bankruptcy remains uncertain. The amount of the liability, which was determined on an actuarial basis, was $125.4 million at September 30, 2017. While the Company has recorded this liability, it intends to review each claim on a case-by-case basis and contest liability 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’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 be reduced in the future depending on the Department of Labor’s responses to inquiries.


23

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UMWA VEBA. 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. After making scheduled payments to Patriot and the VEBA amounting to $165 million through 2015, the parties agreed to a settlement of the Company’s remaining VEBA payment obligations for $75 million. As a result of the settlement, the Company recognized a gain of $68.1 million during the nine months ended September 30, 2016, which was classified in “Operating costs and expenses” in the unaudited condensed consolidated statement of operations and is included in the Company’s Corporate and Other segment results. The Company’s obligation has been satisfied and the matter has concluded.
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, Peabody Holding Company, LLC (PHC), a subsidiary of the Company, and Arch Coal, Inc. (Arch). The plaintiffs sought, pursuant to the Employee Retirement Income Security Act of 1974 (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. After a 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 in increments through 2021. In connection with the settlement, the Company recorded a liability representing the present value of the installments of $54.3 million and recognized an equivalent charge to “Loss from discontinued operations, net of income taxes” during 2016. The balance of the liability was $44.3 million at September 30, 2017.
(6)     Inventories
Inventories as of September 30, 2017 and December 31, 2016 consisted of the following:
 
Successor
Predecessor
 
September 30, 2017
December 31, 2016
 
(Dollars in millions)
Materials and supplies
$
104.0

$
104.5

Raw coal
58.0

29.6

Saleable coal
145.7

69.6

Total
$
307.7

$
203.7

Materials and supplies inventories presented above have been shown net of reserves of $5.6 million as of December 31, 2016. At September 30, 2017, the amount of such reserves was immaterial due to the application of fresh start reporting at the Effective Date.
(7)     Derivatives and Fair Value Measurements
Risk Management — Non-Coal Trading Activities
The Company is exposed to several risks in the normal course of business, including (1) foreign currency exchange rate risk for non-U.S. dollar expenditures and balances, (2) price risk on 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 has historically been managed using forward contracts and options designated as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted foreign currency expenditures. The Company 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 and/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.


24

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of September 30, 2017, the Company had no diesel fuel derivatives in place. Subsequent to the Effective Date, the Company entered into a series of currency options and, as of September 30, 2017, had currency options outstanding with aggregate notional amounts of $450.0 million and $675.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the remainder of 2017 and the first half of 2018, respectively. The instruments are average rate options whereby the Company is entitled to receive payment on the notional amount should the average Australian dollar-to-U.S. dollar exchange rate exceed approximately $0.78 over the fourth quarter of 2017 and $0.85 over the first half of 2018. The currency options are not expected to receive cash flow hedge accounting treatment and changes in fair value will be reflected in current earnings. At September 30, 2017, the currency options’ fair value of $8.6 million was included in “Other current assets” in the accompanying unaudited condensed consolidated balance sheet.
The tables below show the classification and amounts of pre-tax gains and losses related to the Company’s Corporate Hedging derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
 
 
 
Three Months Ended September 30, 2017
Financial Instrument
 
Income Statement
Classification of (Losses) Gains
 
Total gain recognized in income
 
Gain realized in income on derivatives
 
Unrealized loss recognized in income on non- designated derivatives
 
 
 
(Dollars in millions)
Foreign currency option contracts
 
Operating costs and expenses
 
$
5.6

 
$
7.3

 
$
(1.7
)
Total
 
 
 
$
5.6

 
$
7.3

 
$
(1.7
)

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Predecessor
 
 
 
 
Three Months Ended September 30, 2016
Financial Instrument
 
Income Statement
Classification of (Losses) Gains
 
Total loss recognized in income
 
Loss reclassified from other comprehensive income into income
 
(Loss) gain realized in income on derivatives
 
Unrealized gain (loss) recognized in income on non- designated derivatives
 
 
 
(Dollars in millions)
Commodity swap contracts
 
Operating costs and expenses
 
$
(19.4
)
 
$
(19.4
)
 
$
—

 
$
—

Foreign currency forward contracts
 
Operating costs and expenses
 
(28.0
)
 
(28.0
)
 
—

 
—

Total
 
 
 
$
(47.4
)
 
$
(47.4
)
 
$
—

 
$
—


 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
 
 
 
April 2 through September 30, 2017
Financial Instrument
 
Income Statement
Classification of (Losses) Gains
 
Total gain recognized in income
 
Gain realized in income on derivatives
 
Unrealized gain recognized in income on non- designated derivatives
 
 
 
(Dollars in millions)
Foreign currency option contracts
 
Operating costs and expenses
 
$
8.5

 
$
7.0

 
$
1.5

Total
 
 
 
$
8.5

 
$
7.0

 
$
1.5



25

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Predecessor
 
 
 
 
January 1 through April 1, 2017
Financial Instrument
 
Income Statement
Classification of (Losses) Gains
 
Total loss recognized in income
 
Loss reclassified from other comprehensive loss into income
 
(Loss) gain realized in income on derivatives
 
Unrealized gain (loss) recognized in income on non- designated derivatives
 
 
 
(Dollars in millions)
Commodity swap contracts
 
Operating costs and expenses
 
$
(11.0
)
 
$
(11.0
)
 
$
—

 
$
—

Foreign currency forward contracts
 
Operating costs and expenses
 
(16.6
)
 
(16.6
)
 
—

 
—

Total
 
 
 
$
(27.6
)
 
$
(27.6
)
 
$
—

 
$
—


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Predecessor
 
 
 
 
Nine Months Ended September 30, 2016
Financial Instrument
 
Income Statement
Classification of (Losses) Gains
 
Total loss recognized in income
 
Loss reclassified from other comprehensive income into income (1)
 
(Loss) gain realized in income on derivatives
 
Unrealized gain (loss) recognized in income on non- designated derivatives
 
 
 
(Dollars in millions)
Commodity swap contracts
 
Operating costs and expenses
 
$
(78.3
)
 
$
(66.4
)
 
$
(11.9
)
 
$
—

Commodity swap contracts
 
Reorganization items, net
 
(38.8
)
 
—

 
(38.8
)
 
—

Foreign currency forward contracts
 
Operating costs and expenses
 
(119.4
)
 
(122.1
)
 
2.7

 
—

Foreign currency forward contracts
 
Reorganization items, net
 
(36.4
)
 
—

 
(36.4
)
 
—

Total
 
 
 
$
(272.9
)
 
$
(188.5
)
 
$
(84.4
)
 
$
—

(1)  
Includes the reclassification from “Accumulated other comprehensive income (loss)” into earnings of $13.6 million and $9.0 million of previously unrecognized losses on foreign currency and fuel contracts, respectively, monetized in the first quarter of 2016.
Cash Flow Presentation. The Company classifies the cash effects of its Corporate Hedging derivatives within the “Cash Flows From Operating Activities” section of the unaudited condensed consolidated statements of cash flows.
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 asset positions for which fair value is measured on a recurring basis:
 
Successor
 
September 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Dollars in millions)
Foreign currency contracts
$
—

 
$
8.6

 
$
—

 
$
8.6

Total net financial assets
$
—

 
$
8.6

 
$
—

 
$
8.6

The Company had no transfers between fair value hierarchy levels subsequent to the Effective Date. As of December 31, 2016, the Company did not have any outstanding financial positions.


26

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including interest rate yield curves, exchange indices, broker/dealer quotes, published indices, issuer spreads, benchmark securities and other market quotes. In the case of certain debt securities, fair value is provided by a third-party pricing service. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:
•
Investments in debt and equity securities: U.S. government securities and marketable equity securities are valued based on quoted prices in active markets (Level 1) and investment-grade corporate bonds and U.S. government agency securities are valued based on the various inputs listed above that may preclude the security from being measured using an identical asset in an active market (Level 2).
•
Commodity swap contracts — diesel fuel and explosives: valued based on a valuation that is corroborated by the use of market-based pricing (Level 2) except when credit and non-performance risk is considered to be a significant input, then the Company classifies such contracts as Level 3.
•
Foreign currency forward and option contracts: valued utilizing inputs obtained in quoted public markets (Level 2) except when credit and non-performance risk is considered to be a significant input, then the Company classifies such contracts as Level 3.
Other Financial Instruments. The Company used the following methods and assumptions in estimating fair values for other financial instruments as of September 30, 2017 and December 31, 2016:
•
Cash and cash equivalents, accounts receivable, including those within the Company’s accounts receivable securitization program, notes receivable and accounts payable have carrying values which approximate fair value due to the short maturity or the liquid nature of these instruments.
•
Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available (Level 2), and otherwise on estimated borrowing rates to discount the cash flows to their present value (Level 3).
The estimated fair value of the Company’s current and long-term debt as of December 31, 2016 is unable to be determined given it was subject to compromise in connection with the Plan. The carrying amounts and estimated fair values of the Company’s long-term debt as of September 30, 2017 are summarized as follows:
 
Successor
 
September 30, 2017
 
Carrying
Amount
 
Estimated
Fair Value
 
(Dollars in millions)
Long-term debt
$
1,659.1

 
$
1,744.3


(8)     Coal Trading
The Company engages in the direct and brokered trading of coal and freight-related contracts (coal trading). Except those contracts for which the Company has elected to apply a normal purchases and normal sales exception, all derivative coal trading contracts are accounted for at fair value.
The Company includes instruments associated with coal trading transactions as a part of its trading book. Trading revenues from such transactions are recorded in “Other revenues” in the unaudited condensed 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.


27

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Trading revenues (losses) recognized during the periods presented below were as follows:
 
 
Successor
Predecessor
 
Successor
Predecessor
Trading Revenues (Losses) by Type of Instrument
 
Three Months Ended September 30, 2017
Three Months Ended September 30, 2016
 
April 2 through September 30, 2017
January 1 through April 1, 2017
Nine Months Ended September 30, 2016
 
 
(Dollars in millions)
Futures, swaps and options
 
$
(17.1
)
$
(19.6
)
 
$
(24.4
)
$
(10.2
)
$
(42.7
)
Physical purchase/sale contracts
 
36.5

22.3

 
49.0

25.2

59.2

Total trading revenues
 
$
19.4

$
2.7

 
$
24.6

$
15.0

$
16.5

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 open positions. The Company must post cash collateral in the form of initial margin, in addition to 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 over-the-counter (OTC) markets with financial institutions and other non-financial trading entities under International Swaps and Derivatives Association (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, 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 condensed consolidated balance sheets, with the fair values of those respective derivatives reflected in “Assets from coal trading activities, net” and “Liabilities from coal trading activities, net.”
The fair value of assets and liabilities from coal trading activities presented on a gross and net basis as of September 30, 2017 and December 31, 2016 is set forth below:
Affected Line Item in the Condensed Consolidated Balance Sheets
 
Gross Amounts of Recognized Assets (Liabilities)
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Variation Margin Posted (1)
 
Net Amounts of Assets (Liabilities) Presented in the Condensed Consolidated Balance Sheets
 
 
(Dollars in millions)
 
 
Successor
 
 
Fair Value as of September 30, 2017
Assets from coal trading activities, net
 
$
127.1

 
$
(124.6
)
 
$
—

 
$
2.5

Liabilities from coal trading activities, net
 
(157.5
)
 
124.6

 
31.9

 
(1.0
)
Total, net
 
$
(30.4
)
 
$
—

 
$
31.9

 
$
1.5

 
 
 
 
 
 
 
 
 
 
 
Predecessor
 
 
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
)
(1) 
None of the net variation margin posted at September 30, 2017 and December 31, 2016, respectively, related to cash flow hedges.
See Note 7. “Derivatives and Fair Value Measurements” for information on balance sheet offsetting related to the Company’s Corporate Hedging activities.


28

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 30, 2017 and December 31, 2016:
 
Successor
 
September 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Dollars in millions)
Futures, swaps and options
$
—

 
$
0.5

 
$
—

 
$
0.5

Physical purchase/sale contracts
—

 
1.0

 
—

 
1.0

Total net financial assets
$
—

 
$
1.5

 
$
—

 
$
1.5

 
Predecessor
 
December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Dollars in millions)
Futures, swaps and options
$
—

 
$
(0.1
)
 
$
—

 
$
(0.1
)
Physical purchase/sale contracts
—

 
0.7

 
(1.1
)
 
(0.4
)
Total net financial assets (liabilities)
$
—

 
$
0.6

 
$
(1.1
)
 
$
(0.5
)
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), Baltic Exchange 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.
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, the credit valuation adjustment as of December 31, 2016 is considered to be a significant unobservable input in the valuation of the contracts resulting in Level 3 classification. During the second quarter of 2017, two of the major rating agencies upgraded the Company’s corporate credit rating upon emergence from the Chapter 11 proceedings. With the credit rating upgrade, the credit valuation adjustment as of September 30, 2017 no longer has a material impact on the valuation of contracts and is in line with the Company’s historical range.
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 DCF 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 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.


29

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 liabilities:
 
Predecessor
 
Successor
Predecessor
 
Three Months Ended September 30, 2016
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2016
 
(Dollars in millions)
Beginning of period
$
(1.1
)
 
$
(0.7
)
$
(1.1
)
 
$
(15.6
)
Transfers into Level 3
4.6

 
—

—

 
5.0

Transfers out of Level 3
(11.1
)
 
0.7

0.2

 
(0.4
)
Total gains realized/unrealized:
 
 
 
 
 
 
Included in earnings
2.6

 
—

0.2

 
1.2

Sales
0.1

 
—

—

 
—

Settlements
4.2

 
—

—

 
9.1

End of period
$
(0.7
)
 
$
—

$
(0.7
)
 
$
(0.7
)
The Company had no transfers between Levels 1 and 2 during any of the periods presented. Transfers of liabilities into/out of Level 3 from/to Level 2 during the Successor period April 2 through September 30, 2017, and the Predecessor periods January 1 through April 1, 2017, and the three and nine months ended September 30, 2016 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. The Company’s policy is to value all transfers between levels using the beginning of period valuation.
The following table summarizes the changes in net unrealized gains (losses) relating to Level 3 net financial assets held both as of the beginning and the end of the period:
 
Predecessor
 
Successor
Predecessor
 
Three Months Ended September 30, 2016
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2016
 
(Dollars in millions)
Changes in unrealized gains (losses) (1)
$
0.1

 
$
—

$
0.3

 
$
(0.1
)
(1) 
Within the unaudited condensed consolidated statements of operations and unaudited condensed 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.


30

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of September 30, 2017, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:
 
 
Percentage of
Year of Expiration
 
Portfolio Total
2017
 
15
%
2018
 
82
%
2019
 
3
%
 
 
100
%
Credit and Non-performance 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 non-performance risk, if present, on a case-by-case basis.
At September 30, 2017, 33% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties, while 67% 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 September 30, 2017 and December 31, 2016, the Company posted a net variation margin of $31.9 million and $57.4 million, respectively.
In addition to the requirements surrounding variation margin, the Company is required by the exchanges upon which it transacts 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. The Company posted initial margin of $14.6 million as of September 30, 2017, compared to $16.2 million as of December 31, 2016, which is reflected in “Other current assets” in the condensed consolidated balance sheets.
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 September 30, 2017 and December 31, 2016, would have amounted to collateral postings to counterparties of approximately $0.4 million and $2.0 million, respectively. As of September 30, 2017, the Company was required to post no collateral to counterparties for such positions. Approximately $1.0 million collateral was required to be posted to counterparties as of December 31, 2016.
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 the second quarter of 2017, two of the major rating agencies upgraded the Company’s corporate credit rating upon emergence from the Chapter 11 proceedings. The Company’s collateral requirement owed to its counterparties for these ratings based derivative trading instruments for September 30, 2017 remained at zero, consistent with December 31, 2016. As of September 30, 2017 and December 31, 2016, no collateral was posted to counterparties to support such derivative trading instruments.


31

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(9)     Intangible Contract Assets and Liabilities
As described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting,” at the Effective Date, the Company recorded intangible assets of $314.9 million and liabilities of $58.7 million to reflect the inherent fair value of certain U.S. coal supply agreements as a result of favorable and unfavorable differences between contract terms and estimated market terms for the same coal products, and also recorded intangible liabilities of $116.2 million related to unutilized capacity under its port and rail take-or-pay contracts. The balances and respective balance sheet classifications of such assets and liabilities at September 30, 2017, net of accumulated amortization, are set forth in the following table:
 
Successor
 
September 30, 2017
 
(Dollars in millions)
 
Assets
 
Liabilities
 
Net Total
Coal supply agreements
$
231.6

 
$
(46.9
)
 
$
184.7

Take-or-pay contracts
—

 
(108.4
)
 
(108.4
)
Total
$
231.6

 
$
(155.3
)
 
$
76.3

 
 
 
 
 
 
Balance sheet classification:
 
 
 
 
 
Investments and other assets
$
231.6

 
$
—

 
$
231.6

Accounts payable and accrued expenses
—

 
(35.7
)
 
(35.7
)
Other noncurrent liabilities
—

 
(119.6
)
 
(119.6
)
Total
$
231.6

 
$
(155.3
)
 
$
76.3

Amortization of the intangible assets and liabilities related to coal supply agreements occurs ratably based upon coal volumes shipped per contract and is recorded as a component of “Depreciation, depletion and amortization” in the accompanying condensed consolidated statements of operations. Such amortization amounted to $41.5 million and $71.2 million during the Successor three months ended September 30, 2017 and the Successor period April 2, 2017 through September 30, 2017, respectively. The Company anticipates net amortization of sales contracts, based upon expected shipments in the next five years, to be an expense of approximately $40 million during the three months ended December 31, 2017, and for the years 2018 through 2021, expense of approximately $80 million, $40 million, $10 million, and $10 million, respectively.
Future unutilized capacity and the amortization periods related to the take-or-pay contract intangible liabilities are based upon estimates of forecasted usage. Such amortization, which is classified as a reduction to “Operating costs and expenses” in the accompanying condensed consolidated statements of operations, amounted to $6.5 million and $16.4 million during the Successor three months ended September 30, 2017 and the Successor period April 2, 2017 through September 30, 2017, respectively. The Company anticipates net amortization of take-or-pay contract intangible liabilities to be approximately $6 million during the three months ended December 31, 2017, and for the years 2018 through 2021, approximately $30 million, $20 million, $10 million, and $5 million, respectively.
(10) Equity Method Investments and Financing Receivables
The Company had total equity method investments and financing receivables of $75.0 million and $84.8 million reflected in “Investments and other assets” in the condensed consolidated balance sheets as of September 30, 2017 and December 31, 2016, respectively, related to Middlemount Coal Pty Ltd (Middlemount). As noted in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting,” the carrying value of the equity method investments and financing receivables was adjusted to fair value in connection with fresh start reporting based on the net present value of future cash flows associated with the Company’s 50% equity interest in Middlemount.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company periodically makes loans to Middlemount pursuant to the related shareholders’ agreement for purposes of funding capital expenditures and working capital requirements. The Priority Loans (the amount loaned by the Company in excess of the amount loaned by the other shareholder) 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 June 30, 2017, but have been extended to December 31, 2018 in conjunction with a commercial agreement with the stockholders concerning the distribution of available cash against outstanding payables and the loans. The 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 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 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 and in-substance equity. As a result, (i) the foreign currency impact related to the shareholder loans is included in foreign currency translation adjustment in the condensed consolidated balance sheets and the unaudited condensed consolidated statements of comprehensive income and (ii) interest income on the Priority Loans is recognized when cash is received. The Company received loan repayments and other cash payments from Middlemount of approximately $35.2 million during the Successor period April 2 through September 30, 2017 and approximately $31.1 million and $13.2 million during the Predecessor period January 1 through April 1, 2017 and the nine months ended September 30, 2016, respectively.
One of the Company’s Australian subsidiaries and the other shareholder of Middlemount are parties to an agreement, as amended from time to time, to provide a revolving loan (Revolving Loans) to Middlemount not to exceed $50.0 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, 2018. As of September 30, 2017 and December 31, 2016, the carrying value of the Revolving Loans due to the Company’s Australian subsidiary was zero.
(11) Property, Plant, Equipment and Mine Development
The composition of property, plant, equipment and mine development, net, as of September 30, 2017 and December 31, 2016 is set forth in the table below. Refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” for details regarding the impact of fresh start reporting on property, plant, equipment and mine development.
 
Successor
Predecessor
 
September 30, 2017
December 31, 2016
 
(Dollars in millions)
Land and coal interests
$
3,819.7

$
10,330.8

Buildings and improvements
457.3

1,507.6

Machinery and equipment
1,077.4

2,130.2

Less: Accumulated depreciation, depletion and amortization
(271.8
)
(5,191.9
)
Total, net
$
5,082.6

$
8,776.7

(12)  Income Taxes
The Company’s income tax benefit of $84.1 million and $10.8 million for the three months ended September 30, 2017 and 2016, respectively, included tax provisions of $0.9 million and $5.0 million related to the remeasurement of foreign income tax accounts. The Company’s income tax benefit of $79.4 million and $108.2 million for the Successor period of April 2 through September 30, 2017 and the nine months ended September 30, 2016, respectively, included tax provisions of $1.0 million and $7.4 million, respectively, related to the remeasurement of foreign income tax accounts. The Company recorded an income tax benefit of $266.0 million on April 1, 2017 that was primarily comprised of benefits related to Predecessor deferred tax liabilities and accumulated comprehensive income. The Company’s income tax benefit of $263.8 million for the period of January 1 through April 1, 2017 included a tax provision of $9.4 million related to the remeasurement of foreign income tax accounts and was calculated using a discrete period method.
The Company’s effective tax rate for the three month period ended September 30, 2017 and the period of April 2 through September 30, 2017 is comprised of the expected statutory tax expense offset by foreign rate differential and changes in valuation allowance, plus tax benefits for expected refunds for U.S. net operating loss carrybacks.


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Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting,” the Plan provided that the Company’s pre-petition equity and certain obligations were canceled and extinguished and a significant portion of its long-term debt was discharged in exchange for new Common Stock and other consideration. Generally, absent an exception, for U.S. tax purposes a debtor recognizes cancellation of debt income (CODI) upon discharge of its outstanding indebtedness for an amount of consideration less than the adjusted issue price of such indebtedness. The Company excluded CODI with respect to the Plan from its taxable income in accordance with U.S. Internal Revenue Code (IRC) Section 108, which allows a taxpayer that is a debtor in a reorganization case to exclude CODI from taxable income if the discharge is granted by a bankruptcy court or pursuant to a plan of reorganization approved by a bankruptcy court. However, in such event, Section 108 requires a reduction in certain income tax attributes otherwise available to the taxpayer, in most cases by the amount of such CODI. Generally, the amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued, and (iii) the fair market value of any consideration, including equity, issued to the creditors. The actual reduction in tax attributes does not occur until the first day of the Company’s taxable year subsequent to the date of emergence, or January 1, 2018. The Company estimates that it will be able to retain approximately $3.3 billion of gross U.S. federal net operating losses (NOLs) after giving effect to such required deductions.
In connection with the Company’s emergence from bankruptcy, the Company experienced an “ownership change” as defined in U.S. IRC Section 382. As a result, the Company’s ability to use pre-ownership change NOLs, general business credits, U.S. alternative minimum tax credits, foreign tax credits (FTCs) and other tax attributes to offset future taxable income or taxes owed is limited. Under U.S. IRC Section 382 and Section 383, an entity that experiences an ownership change in bankruptcy generally is subject to an annual limitation (the 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 entity immediately after implementation of the plan of reorganization (reflecting the increase, if any, in value resulting from the surrender or cancellation of any claims against the Company thereunder), multiplied by the long-term tax exempt rate posted by the Internal Revenue Service, subject to certain adjustments. A significant portion of the Company’s retained NOLs (stated above) are not subject to the Annual Limitation because they are deemed attributable to the period after the ownership change. The Company also had a net unrealized built-in gain at the time of the ownership change; therefore, certain built-in gains recognized within five years after the ownership change will increase the Annual Limitation for the five-year recognition period beginning April 3, 2017 through April 2, 2022. There is significant uncertainty surrounding which assets with built-in gains will be realized within this period which otherwise would allow the Company to realize the incremental NOLs and other attributes in excess of the Annual Limitation. The estimated Annual Limitation will not prevent the usage of NOLs, provided there is sufficient income in the carryforward period. The Company maintains a full valuation allowance against its U.S. net deferred tax assets. The Company has reduced the deferred tax assets and corresponding valuation allowance related to general business credits and FTCs as a result of the Annual Limitation.


34

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(13)     Long-term Debt 
The Company’s total indebtedness as of September 30, 2017 and December 31, 2016 is set forth in the table below. As of December 31, 2016, substantially all of the Company’s long-term debt, with the exception of capital lease obligations, was recorded in “Liabilities subject to compromise” in the consolidated balance sheets. Refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” for additional information.
 
Successor
Predecessor
 
September 30, 2017
December 31, 2016
 
(Dollars in millions)
6.00% Senior Secured Notes due March 2022
$
500.0

$
—

6.375% Senior Secured Notes due March 2025
500.0

—

Senior Secured Term Loan due 2022
645.0

—

2013 Revolver
—

1,558.1

2013 Term Loan Facility due September 2020
—

1,162.3

6.00% Senior Notes due November 2018
—

1,518.8

6.50% Senior Notes due September 2020
—

650.0

6.25% Senior Notes due November 2021
—

1,339.6

10.00% Senior Secured Second Lien Notes due March 2022
—

979.4

7.875% Senior Notes due November 2026
—

247.8

Convertible Junior Subordinated Debentures due December 2066
—

386.1

Capital lease and other obligations
84.0

20.1

Less: Debt issuance costs
(69.9
)
(70.8
)
 
1,659.1

7,791.4

Less: Current portion of long-term debt
47.1

20.2

Less: Liabilities subject to compromise
—

7,771.2

Long-term debt
$
1,612.0

$
—

As more fully described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting”, on the Effective Date, all of the debt instruments associated with the Predecessor indebtedness included in the above table, with the exception of “Capital lease and other obligations”, were canceled and the debt obligations discharged. In accordance with the Plan, the Company was concurrently recapitalized with new debt and equity instruments, including the 6.000% Senior Notes due March 2022, the 6.375% Senior Notes due March 2025, and the Senior Secured Term Loan due 2022, included with the Successor obligations in the above table.
In connection with the Chapter 11 Cases, the Company was required to pay monthly adequate protection payments to certain first lien creditors in accordance with the rates defined in its existing prepetition credit facility which included the 2013 Revolver and the 2013 Term Loan Facility due September 2020. The adequate protection payments were recorded as “Interest expense” in the consolidated statement of operations, which totaled $29.8 million during the Predecessor period January 1, 2017 through April 1, 2017.
For the remaining non-first lien Predecessor indebtedness included in the table above, with the exception of capital lease and other obligations, the Company did not record interest expense subsequent to the filing of the Bankruptcy Petitions. The amount of contractual interest for such obligations which was automatically stayed in accordance with Section 502(b)(2) of the Bankruptcy Code was $92.9 million for the period January 1, 2017 through the Effective Date.
6.00% and 6.375% Senior Secured Notes (collectively, the Successor Notes)
The Successor Notes were issued at par value. The Company paid aggregate debt issuance costs of $49.5 million related to the offering, which will be amortized over the respective terms of the Successor Notes.
Interest payments on the Successor Notes are scheduled to occur each year on March 31st and September 30th until maturity. During the Successor three months ended September 30, 2017 and the Successor period April 2, 2017 through September 30, 2017, the Company recorded interest expense of $15.5 million and $30.6 million related to the Successor Notes, respectively.


35

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company may redeem the 6.00% Senior Secured Notes due March 2022, in whole or in part, beginning in 2019 at 103.0% of par, in 2020 at 101.5% of par, and in 2021 and thereafter at par. The 6.375% Senior Secured Notes due March 2025 may be redeemed, in whole or in part, beginning in 2020 at 104.8% of par, in 2021 at 103.2% of par, in 2022 at 101.6% of par, and in 2023 and thereafter at par.
The indenture underlying the Successor Notes (Indenture) contains customary conditions of default and imposes certain restrictions on the Company’s activities, including its ability to incur liens, incur debt, make investments, engage in fundamental changes such as mergers and dissolutions, dispose of assets, enter into transactions with affiliates, and make certain restricted payments, such as cash dividends and share repurchases.
The Successor Notes rank senior in right of payment to any subordinated indebtedness and equally in right of payment with any senior indebtedness to the extent of the collateral securing that indebtedness. The Successor Notes are jointly and severally and fully and unconditionally guaranteed on a senior secured basis by substantially all of the Company’s material domestic subsidiaries and secured by first priority liens over (1) substantially all of the assets of the Company and the guarantors, except for certain excluded assets, (2) 100% of the capital stock of each domestic restricted subsidiary of the Company, (3) 100% of the non-voting capital stock of each first tier foreign subsidiary of the Company or a foreign subsidiary holding company and no more than 65% of the voting capital stock of each first tier foreign subsidiary of the Company or a foreign subsidiary holding company, (4) a legal charge of 65% of the voting capital stock and 100% of the non-voting capital stock of Peabody Investments (Gibraltar) Limited and (5) all intercompany debt owed to the Company or any guarantor, in each case, subject to certain exceptions. The obligations under the Successor Notes are secured on a pari passu basis by the same collateral securing the Successor Credit Agreement, subject to certain exceptions.
Successor Credit Agreement
Following the amendment described below, the Successor Credit Agreement provides for a $650.0 million first lien senior secured term loan (the Senior Secured Term Loan), which bears interest at LIBOR plus 3.50% per annum with a 1.00% LIBOR floor. During the Successor three months ended September 30, 2017 and the Successor period April 2, 2017 through September 30, 2017, the Company recorded interest expense of $13.8 million and $26.9 million related to the Senior Secured Term Loan, respectively.
Proceeds from the Senior Secured Term Loan were received net of an original issue discount and deferred financing costs of $37.3 million that will be amortized over its five-year term. The loan principal is payable in quarterly installments of $1.6 million plus accrued interest through December 2021 with the remaining balance due in March 2022. The loan principal is voluntarily prepayable at 101% of the principal amount repaid if voluntarily prepaid prior to March 18, 2018 (subject to certain exceptions, including prepayments made with internally generated cash) and is voluntarily prepayable at any time thereafter without premium or penalty. The Senior Secured Term Loan may require mandatory principal prepayments of 75% of Excess Cash Flow (as defined in the Successor Credit Agreement) for any fiscal year (commencing with the fiscal year ended December 31, 2018). The mandatory principal prepayment requirement changes to (i) 50% of Excess Cash Flow if the Company’s Total Leverage Ratio (as defined in the Successor Credit Agreement and calculated as of December 31) is less than or equal to 2.00:1.00 and greater than 1.50:1.00, (ii) 25% of Excess Cash Flow if the Company’s Total Leverage Ratio is less than or equal to 1.50:1.00 and greater than 1.00:1.00, or (iii) zero if the Company’s Total Leverage Ratio is less than or equal to 1.00:1.00. If required, mandatory prepayments resulting from Excess Cash Flows are payable within 100 days after the end of each fiscal year. In certain circumstances, the Senior Secured Term Loan also requires that Excess Proceeds (as defined in the Successor Credit Agreement) of $10.0 million or greater from sales of Company assets be applied against the loan principal, unless such proceeds are reinvested within one year.
Under the Successor Credit Agreement, the Company’s annual capital expenditures are limited to $220.0 million, $220.0 million, $250.0 million, $250.0 million, and $300.0 million from 2017 through 2021, respectively, subject to certain adjustments. The agreement contains customary conditions of default and imposes certain restrictions on the Company’s activities, including its ability to incur liens, incur debt, make investments, engage in fundamental changes such as mergers and dissolutions, dispose of assets, enter into transactions with affiliates, and make certain restricted payments, such as cash dividends and share repurchases.
Obligations under the Successor Credit Agreement are secured on a pari passu basis by the same collateral securing the Successor Notes.


36

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company voluntarily prepaid $300.0 million of the original $950.0 loan principal amount on the Senior Secured Term Loan in $150.0 million installments on July 31, 2017 and September 11, 2017. On September 18, 2017, the Company entered into an amendment to the Successor Credit Agreement (the Amendment) which lowered the interest rate from LIBOR plus 4.50% per annum with a 1.00% LIBOR floor to LIBOR plus 3.50% with a 1.00% LIBOR floor. The Amendment permits the Company to add an incremental revolving credit facility in addition to the Company’s ability to add one or more incremental term loan facilities under the Successor Credit Agreement. The incremental revolving credit facility and/or incremental term loan facilities, which remain unutilized, can be in an aggregate principal amount of up to $300.0 million plus additional amounts so long as the Company is below Total Leverage Ratio requirements as set forth in the Successor Credit Agreement. The Amendment also made available an additional restricted payment basket that permits additional repurchases, dividends or other distributions with respect to the Company’s Common and Preferred Stock in an aggregate amount up to $450.0 million so long as the Company’s Fixed Charge Coverage Ratio (as defined in the Successor Credit Agreement) would not exceed 2.00:1.00 on a pro forma basis.
The voluntary prepayments of $300.0 million made prior to the Amendment were accounted for as a partial debt extinguishment and accordingly, a pro rata portion of debt issuance costs and original issue discount of $11.0 million was charged to loss on early debt extinguishment in the accompanying condensed consolidated statements of operations during the Successor three months ended September 30, 2017. The Amendment was accounted for partially as a debt modification and partially as an extinguishment, the latter of which relating to certain lenders no longer participating in the Senior Secured Term Loan syndicate subsequent to the Amendment. As a result, the Company charged an additional pro rata portion of debt issuance costs and original issue discount of $1.9 million to “Loss on early debt extinguishment” in the accompanying condensed consolidated statements of operations during the Successor three months ended September 30, 2017 and the Successor period of April 2 through September 30, 2017. The Company also recorded $6.1 million of deferred financing costs paid to the remaining lenders and expensed $2.0 million of other fees associated with the Amendment to “Interest expense” in the accompanying condensed consolidated statements of operations during the Successor three months ended September 30, 2017 and the Successor period of April 2 through September 30, 2017.
Restricted Payments Under the Successor Notes and Successor Credit Agreement
In addition to the $450.0 million restricted payment basket provided for under the Amendment, the Indenture and the Successor Credit Agreement allow for $50.0 million of otherwise restricted payments. Additive to this general limit are certain “builder basket” provisions that may increase the amount of allowable restricted payments, as calculated periodically based upon the Company’s operating performance. Beginning on January 1, 2018, the payment of dividends and purchases of the Company’s Common Stock are permitted under additional provisions in the Indenture and the Successor Credit Agreement in an aggregate amount in any calendar year not to exceed $25.0 million, so long as the Company’s Total Leverage Ratio would not exceed 1.25:1.00 on a pro forma basis. During the three months ended September 30, 2017, the Company made repurchases of its Common Stock, as described in Note 16. “Other Events”.
Capital Lease Obligations
The Company leases equipment and facilities under various noncancelable lease agreements and historically, the majority of the Company's leases have been accounted for as operating leases. Certain lease agreements were subject to the restrictive covenants of the 2013 Credit Facility which was canceled upon emergence from the Chapter 11 Cases and included 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. During the Chapter 11 Cases, the Debtors amended and assumed certain leases and made lump sum payments to terminate certain other leases. In relation to the Company's non-Debtor subsidiaries, the Company successfully negotiated standstill agreements during the Chapter 11 Cases and successfully amended the leases, with those amendments becoming effective upon emergence from the Chapter 11 Cases. Certain of these amendments resulted in new lease agreements which are being accounted for as capital leases with an initial aggregate obligation of approximately $79.9 million.


37

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(14) Pension and Postretirement Benefit Costs
Net periodic pension (income) cost included the following components:
 
 
Successor
Predecessor
 
Successor
Predecessor
 
 
Three Months Ended September 30, 2017
Three Months Ended September 30, 2016
 
April 2 through September 30, 2017
January 1 through April 1, 2017

Nine Months Ended September 30, 2016
 
 
(Dollars in millions)
Service cost for benefits earned
 
$
0.5

$
0.7

 
$
1.1

$
0.6

 
$
2.0

Interest cost on projected benefit obligation
 
9.4

10.3

 
18.7

9.7

 
31.0

Expected return on plan assets
 
(11.2
)
(11.3
)
 
(22.4
)
(11.0
)
 
(33.9
)
Amortization of prior service cost and net actuarial loss
 
—

6.3

 
—

6.4

 
18.8

Net periodic pension (income) cost
 
$
(1.3
)
$
6.0

 
$
(2.6
)
$
5.7

 
$
17.9

Annual contributions to the qualified plans are made in accordance with minimum funding standards and the Company’s agreement with the Pension Benefit Guaranty Corporation. Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006 (generally 80%). As of September 30, 2017, the Company’s qualified plans were expected to be at or above the Pension Protection Act thresholds. Prior to emergence from the Chapter 11 Cases, the Company incurred pension costs for two non-qualified pension plans which it no longer sponsors. Minimum funding standards are legislated by ERISA and are modified by pension funding stabilization provisions included in the Moving Ahead for Progress in the 21st Century Act of 2012, the Highway and Transportation Funding Act of 2014 and the Bipartisan Budget Act of 2015. During the Successor period April 2 through September 30, 2017, the Company contributed $30.1 million to its qualified pension plans including a discretionary contribution of $25.0 million.
Net periodic postretirement benefit cost included the following components:
 
 
Successor
Predecessor
 
Successor
Predecessor
 
 
Three Months Ended September 30, 2017
Three Months Ended September 30, 2016
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2016
 
 
(Dollars in millions)
Service cost for benefits earned
 
$
2.3

$
2.6

 
$
4.6

$
2.3

 
$
7.8

Interest cost on accumulated postretirement benefit obligation
 
8.2

8.8

 
16.5

8.4

 
26.4

Amortization of prior service cost and net actuarial loss
 
—

2.4

 
—

3.2

 
7.1

Net periodic postretirement benefit cost
 
$
10.5

$
13.8

 
$
21.1

$
13.9

 
$
41.3



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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(15) Accumulated Other Comprehensive Income (Loss)
The following table sets forth the after-tax components of accumulated other comprehensive income (loss) and changes thereto recorded during the Predecessor period January 1 through April 1, 2017 and the Successor period April 2 through September 30, 2017:
 
 
Foreign
Currency
Translation
Adjustment
 
Net
Actuarial Loss
Associated with
Postretirement
Plans and
Workers’
Compensation
Obligations
 
Prior Service
Cost Associated
with
Postretirement
Plans
 
Cash Flow
Hedges
 
Total
Accumulated
Other
Comprehensive
Income (Loss)
 
 
(Dollars in millions)
Predecessor Company
 
 
 
 
 
 
 
 
 
 
December 31, 2016
$
(148.2
)
 
$
(256.3
)
 
$
21.7

 
$
(94.2
)
 
$
(477.0
)
 
Reclassification from other comprehensive income to earnings
—

 
5.8

 
(1.4
)
 
18.6

 
23.0

 
Current period change
5.5

 
—

 
—

 
—

 
5.5

 
Fresh start reporting adjustment
142.7

 
250.5

 
(20.3
)
 
75.6

 
448.5

 
April 1, 2017
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Successor Company
 
 
 
 
 
 
 
 
 
 
Current period change
1.8

 
—

 
—

 
—

 
1.8

 
September 30, 2017
$
1.8

 
$
—

 
$
—

 
$
—

 
$
1.8



39

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The components of accumulated other comprehensive income (loss) related to postretirement plans and workers’ compensation obligations and cash flow hedges related to Predecessor periods were eliminated in accordance with fresh start reporting as described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting.” The following table provides additional information regarding items reclassified out of “Accumulated other comprehensive income (loss)” into earnings during the Predecessor periods January 1 through April 1, 2017 and the three and nine months ended September 30, 2016:
 
 
Amount reclassified from accumulated other comprehensive income (loss) (1)
 
 
 
 
Predecessor
 
 
Details about accumulated other comprehensive income (loss) components

 
Three Months Ended September 30, 2016
January 1 through April 1, 2017
Nine Months Ended September 30, 2016
 
Affected line item in the unaudited condensed 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
 
$
(5.2
)
$
(5.5
)
$
(15.4
)
 
Operating costs and expenses
Defined benefit pension plans
 
(5.1
)
(5.3
)
(15.3
)
 
Operating costs and expenses
Defined benefit pension plans
 
(1.1
)
(1.0
)
(3.2
)
 
Selling and administrative expenses
Insignificant items
 
3.0

2.7

8.8

 
 
 
 
(8.4
)
(9.1
)
(25.1
)
 
Total before income taxes
 
 
3.1

3.3

9.3

 
Income tax benefit
 
 
$
(5.3
)
$
(5.8
)
$
(15.8
)
 
Total after income taxes
 
 
 
 
 
 
 
Prior service credit associated with postretirement plans:
 
 
 
 
 
 
Postretirement health care and life insurance benefits
 
$
2.8

$
2.3

$
8.3

 
Operating costs and expenses
Defined benefit pension plans
 
(0.1
)
(0.1
)
(0.3
)
 
Operating costs and expenses
 
 
2.7

2.2

8.0

 
Total before income taxes
 
 
(1.0
)
(0.8
)
(3.0
)
 
Income tax provision
 
 
$
1.7

$
1.4

$
5.0

 
Total after income taxes
 
 
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
 
Foreign currency cash flow hedge contracts
 
$
(28.0
)
$
(16.6
)
$
(122.1
)
 
Operating costs and expenses
Fuel and explosives commodity swaps
 
(19.4
)
(11.0
)
(66.4
)
 
Operating costs and expenses
Insignificant items
 
(0.1
)
(0.1
)
(0.4
)
 
 
 
 
(47.5
)
(27.7
)
(188.9
)
 
Total before income taxes
 
 
17.6

9.1

69.9

 
Income tax benefit
 
 
$
(29.9
)
$
(18.6
)
$
(119.0
)
 
Total after income taxes
(1)  
Presented as gains (losses) in the unaudited condensed consolidated statements of operations.


40

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(16) Other Events
Divestitures
On September 5, 2017, the Company entered into an agreement to sell the majority of its Burton Mine and related infrastructure to the Lenton Joint Venture for approximately $11.0 million. The transaction is conditional on a number of regulatory and other requirements and completion is expected to take place by March 31, 2018. The Lenton Joint Venture will assume the reclamation obligations associated with the assets being acquired by the Lenton Joint Venture. If completed, the transaction is expected to reduce the Company’s asset retirement obligation by approximately $53.0 million and reduce the amount of restricted cash held in support of such obligations by approximately $30.0 million. The Burton Mine, located in Queensland's Bowen Basin, entered a care, maintenance and rehabilitation phase in December 2016. At September 30, 2017, the Company’s assets associated with the pending transaction had no carrying value.
On August 29, 2017, the Company entered into an agreement to sell its 50% interest in the Red Mountain Joint Venture (RMJV) with BHP Billiton Mitsui Coal Pty Ltd (BMC) for $20.0 million. RMJV operates the coal handling and preparation plant utilized by the Company’s Millennium Mine. The transaction is conditional on a number of regulatory and other requirements and completion is expected to take place in the fourth quarter of 2017. BMC will assume the reclamation obligations and other commitments associated with the assets of RMJV. The agreement contains provisions allowing the Millennium Mine continued usage of the coal handling and preparation plant and the associated rail loading facility until the end of 2019.
The Company had 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 March 31, 2017, the Company completed a sale of its interest in Dominion Terminal Associates to Contura Terminal, LLC and Ashland Terminal, Inc., both of which are partners of the Dominion Terminal Associates. The Company collected $20.5 million in proceeds and recorded $19.7 million of gain on the sale, which was classified in “Net gain on disposal of assets” in the accompanying unaudited condensed consolidated statement of operations during the Predecessor period January 1, 2017 through April 1, 2017.
In November 2016, the Company entered into a definitive share sale and purchase agreement (SPA) for the sale of all of the equity interests in Metropolitan Collieries Pty Ltd, the entity that owns Metropolitan Mine in New South Wales, Australia, and the associated interest in the Port Kembla Coal Terminal, to South32 Limited (South32). The SPA provided for a cash purchase price of $200.0 million and certain contingent consideration, subject to a customary working capital adjustment. South32 terminated the agreement in April 2017 after it was unable to obtain necessary approvals from the Australian Competition and Consumer Commission within the timeframe required under the SPA. As a result of the termination, the Company retained an earnest deposit posted by South32 which was recorded in “Other revenues” in the accompanying unaudited condensed consolidated statements of operations during the Successor period April 2, 2017 through September 30, 2017.
In November 2015, the Company entered into a definitive agreement to sell its New Mexico and Colorado assets to Bowie Resource Partners, LLC (Bowie) in exchange for cash proceeds of $358.0 million and the assumption of certain liabilities. Bowie agreed to pay the Company a termination fee of $20.0 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. Following a favorable judgment by the Bankruptcy Court, the Company collected the Termination Fee from Bowie. The Termination Fee is included in “Other revenues” in the accompanying unaudited condensed consolidated statements of operations during the Successor period April 2, 2017 through September 30, 2017.
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 unaudited condensed consolidated statement of operations for the Predecessor nine months ended September 30, 2016.
In April 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. The transaction included Olive Downs South, Olive Downs South Extended and Willunga tenements, which were sold for $64.1 million in cash plus a royalty stream. The Company recognized a gain on sale of $2.8 million related to those tenements, which was classified in “Net gain on disposal of assets” in the unaudited condensed consolidated statement of operations for the Predecessor nine months ended September 30, 2016. The sale and purchase agreement for the remaining tenements, namely the Olive Downs North tenements, terminated in October 2017 as certain closing conditions were not satisfied within the prescribed time period.


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Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Share Repurchase Program
On August 1, 2017, the Board authorized a $500.0 million share repurchase program. Repurchases may be made from time to time at the Company’s discretion. The specific timing, price and size of purchases will depend on the share price, general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time. No expiration date has been set for the repurchase program, and the program may be suspended or discontinued at any time. On August 23, 2017, the Company repurchased approximately 1.5 million shares of its Common Stock for $40.0 million in connection with an underwritten secondary offering. During September 2017, the Company made additional open-market purchases of approximately 1.0 million shares of its Common Stock for $29.2 million. Subsequent to September 30, 2017 and through October 30, 2017, the Company purchased an additional approximately 1.3 million shares of Common Stock for $37.7 million.
(17) 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 convertible preferred stock is considered a participating security because holders are entitled to receive dividends on an if-converted basis. The Predecessor Company’s restricted stock awards were considered participating securities because holders were entitled to receive non-forfeitable dividends during the vesting term. Diluted EPS includes securities that could potentially dilute basic EPS during a reporting period and assumes that participating securities are not executed or converted. As such, the Company includes the share-based compensation awards in its potentially dilutive securities. Diluted EPS for the Predecessor Company also included the Debentures. 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 Predecessor Company’s performance units, which are further described in Note 20. “Share-Based Compensation” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017, 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 Predecessor Company’s performance units, their contingent features resulted 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.
A conversion of the Debentures could have resulted, up to the time of the cancellation, in payment for any conversion value in excess of the principal amount of the Debentures in the Predecessor Company’s common stock. For diluted EPS purposes, potential common stock was calculated based on whether the market price of the Predecessor Company’s common stock at the end of each reporting period was 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 for the Successor Company excluded aggregate share-based compensation awards of less than 0.1 million for three months ended September 30, 2017 and the period of April 2 through September 30, 2017, respectively. The computation of diluted EPS for the Predecessor Company excluded aggregate share-based compensation awards of approximately 0.2 million for the period January 1 through April 1, 2017 and 0.4 million for the three and nine months ended September 30, 2016, 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.


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Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.
 
 
Successor
Predecessor
 
Successor
Predecessor
 
 
Three Months Ended September 30, 2017
Three Months Ended September 30, 2016
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2016
 
 
 
 
 
 
(In millions, except per share data)
EPS numerator:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations, net of income taxes
 
$
233.7

$
(97.7
)
 
$
335.1

$
(195.5
)
 
$
(488.6
)
Less: Series A Convertible Preferred Stock dividends
 
23.5

—

 
138.6

—

 
—

Less: Net income attributable to noncontrolling interests
 
5.1

1.8

 
8.9

4.8

 
3.5

Income (loss) from continuing operations attributable to common stockholders, before allocation of earnings to participating securities
 
205.1

(99.5
)
 
187.6

(200.3
)

(492.1
)
Less: Earnings allocated to participating securities
 
51.6

—

 
50.6

—

 
—

Income (loss) from continuing operations attributable to common stockholders, after allocation of earnings to participating securities (1)
 
153.5

(99.5
)
 
137.0

(200.3
)
 
(492.1
)
Loss from discontinued operations, net of income taxes
 
(3.7
)
(38.1
)
 
(6.4
)
(16.2
)
 
(44.5
)
Less: Loss from discontinued operations allocated to participating securities
 
(0.9
)
—

 
(1.7
)
—

 
—

Loss from discontinued operations attributable to common stockholders, after allocation of earnings to participating securities
 
(2.8
)
(38.1
)
 
(4.7
)
(16.2
)
 
(44.5
)
Net income (loss) attributable to common stockholders, after allocation of earnings to participating securities (1)
 
$
150.7

$
(137.6
)
 
$
132.3

$
(216.5
)
 
$
(536.6
)
 
 
 
 
 
 
 
 
 
EPS denominator:
 
 
 
 
 
 
 
 
Weighted average shares outstanding — basic
 
101.6

18.3

 
99.2

18.3

 
18.3

Impact of dilutive securities
 
1.5

—

 
1.0

—

 
—

Weighted average shares
   outstanding — diluted (2)
 
103.1

18.3

 
100.2

18.3

 
18.3

 
 
 
 
 
 
 
 
 
Basic EPS attributable to common stockholders:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
1.51

$
(5.44
)
 
$
1.38

$
(10.93
)
 
$
(26.91
)
Loss from discontinued operations
 
(0.03
)
(2.09
)
 
(0.05
)
(0.88
)
 
(2.43
)
Net income (loss) attributable to common stockholders
 
$
1.48

$
(7.53
)
 
$
1.33

$
(11.81
)
 
$
(29.34
)
 
 
 
 
 
 
 
 
 
Diluted EPS attributable to common stockholders:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
1.49

$
(5.44
)
 
$
1.37

$
(10.93
)
 
$
(26.91
)
Loss from discontinued operations
 
(0.02
)
(2.09
)
 
(0.05
)
(0.88
)
 
(2.43
)
Net income (loss) attributable to common stockholders
 
$
1.47

$
(7.53
)
 
$
1.32

$
(11.81
)
 
$
(29.34
)
(1) 
The reallocation adjustment for participating securities to arrive at the numerator to calculate diluted EPS was $0.6 million for the Successor three months ended September 30, 2017 and $0.4 million for the Successor period April 2 through September 30, 2017.
(2) 
The two-class method assumes that participating securities are not exercised or converted. As such, weighted average diluted shares outstanding excluded 34.2 million shares and 36.7 million shares related to the participating securities for the Successor three months ended September 30, 2017 and the Successor period April 2 through September 30, 2017, respectively.


43

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In accordance with the Plan, each share of the Predecessor Company’s common stock outstanding prior to the Effective Date, including all options and warrants to purchase such stock, were extinguished, canceled and discharged, and each such share, option or warrant has no further force or effect after the Effective Date. Furthermore, all of the Predecessor Company’s equity award agreements under prior incentive plans, and the equity awards granted pursuant thereto, were extinguished, canceled and discharged and have no further force or effect after the Effective Date.
As of September 30, 2017, approximately 14.2 million shares of Preferred Stock had been converted and no Warrants remained unexercised, which together resulted in the issuance of an additional 34.2 million shares of Common Stock. As discussed in Note 13. “Long-term Debt” and Note 16. “Other Events,” approximately 2.5 million shares of Common Stock had been repurchased as of September 30, 2017.
(18) Financial Instruments and Other Guarantees
In the normal course of business, the Company is a party to guarantees and financial instruments, some of which carry off-balance-sheet risk and are not reflected in the accompanying unaudited condensed consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and the likelihood of required performance.
Reclamation Bonding
The Company is required to provide various forms of financial assurance in support of its mining reclamation obligations in the jurisdictions in which it operates. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees, letters of credit, cash collateral held in restricted accounts, and self-bonding arrangements in the U.S. In connection with its emergence from the Chapter 11 Cases, the Company elected to utilize primarily a portfolio of surety bonds to support its U.S. obligations.
At September 30, 2017, the Company’s asset retirement obligations for its U.S. operations were $377.0 million and had total corresponding reclamation bonding requirements of $1,147.7 million, which were predominately supported by surety bonds. In limited cases, the Company has also issued of letters of credit in favor of the related surety providers.
At September 30, 2017, the Company’s asset retirement obligations for its Australia operations of $259.0 million were supported by a combination of bank guarantees and cash collateral.
The financial instruments in support of the Company’s asset retirement obligations may also be backed by varying levels of restricted cash collateral from time to time, as further described below.
Accounts Receivable Securitization
As described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting,” the Company entered into the Receivables Purchase Agreement to extend the receivables securitization facility previously in place and expand that facility to include certain receivables from the Company’s Australian operations. The term of the receivables securitization program (Securitization Program) ends on April 3, 2020, subject to certain liquidity requirements and other customary events of default set forth in the Receivables Purchase Agreement. The Securitization Program provides for up to $250.0 million in funding accounted for as a secured borrowing, limited to the availability of eligible receivables, and may be secured by a combination of cash collateral and the trade receivables underlying the program, from time to time. Funding capacity under the Securitization Program may also be drawn upon for letters of credit in support of other obligations. On June 30, 2017, the Company entered into an amendment to the Securitization Program to include the receivables of additional Australian operations and reduce the associated fees payable.
Under the terms of the Securitization Program, the Company contributes the trade receivables of its participating subsidiaries on a revolving basis to P&L Receivables, its wholly-owned, bankruptcy-remote subsidiary, which then sells the receivables to unaffiliated asset-backed commercial paper conduits and banks. P&L Receivables retains the ability to repurchase the receivables in certain circumstances. The assets and liabilities of P&L Receivables are consolidated with Peabody, and the Securitization Program is treated as a secured borrowing for accounting purposes, but the assets of P&L Receivables will be used first to satisfy the creditors of P&L Receivables, not Peabody’s creditors. The borrowings under the Securitization Program remain outstanding throughout the term of the agreement, subject to the Company maintaining sufficient eligible receivables, by continuing to contribute trade receivables to P&L Receivables, unless an event of default occurs.


44

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

At September 30, 2017, the Company had no outstanding borrowings and $179.5 million of letters of credit drawn under the Securitization Program. The letters of credit were primarily in support of portions of the Company’s obligations for reclamation, workers’ compensation and postretirement benefits. The Company had no cash collateral requirement under the Securitization Program at September 30, 2017 and $40.5 million required under its former receivables securitization facility in place prior to the Effective Date at December 31, 2016. The Company incurred fees associated with the Securitization Program of $3.9 million during the Successor period April 2, 2017 through September 30, 2017, which have been recorded as interest expense in the accompanying unaudited statements of operations. As it relates to the former receivables securitization facility in place prior to the Effective Date, the Company incurred interest expense of $2.0 million during the Predecessor period January 1, 2017 through April 1, 2017, $2.4 million during the three months ended September 30, 2016 and $5.6 million during the nine months ended September 30, 2016.
Restricted Cash Collateral
The Company has restricted cash held as collateral for financial assurances associated with a variety of long-term obligations and commitments surrounding the mining, reclamation and shipping of its production. At September 30, 2017 and December 31, 2016, the Company had $530.3 million and $529.3 million, respectively, related to such obligations. The Company also had $7.8 million and $13.8 million of restricted cash at September 30, 2017 and December 31, 2016, respectively, related to various short-term obligations.
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.
(19) Commitments and Contingencies
Commitments
Unconditional Purchase Obligations
As of September 30, 2017, purchase commitments for capital expenditures were $56.3 million, all of which is obligated within the next 12 months.
There were no other material changes to the Company’s commitments from the information provided in Note 26 to the consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.
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. During the pendency of the Chapter 11 Cases, each of the Debtors continued 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.


45

Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The automatic stay was lifted when the Plan became effective on April 3, 2017 and was replaced by the injunction provisions under the Debtors’ confirmed Plan. The Plan’s injunction provisions provide that all holders of prepetition claims or interests are enjoined, or stayed, from, among other things, (a) commencing, conducting or continuing any suit, action or other proceeding against the Debtors, their estates or the reorganized Debtors, (b) enforcing, levying, attaching, collecting or otherwise recovering an award against the Debtors, their property or the assets or property of the reorganized Debtors, (c) creating, perfecting or otherwise enforcing a lien against the Debtors, their estates or the reorganized Debtors, and (d) asserting any setoff, right of subrogation or recoupment against any obligation due a Debtor or a reorganized Debtor.
The Chapter 11 Cases impacted the liabilities of the Debtors described below and in Note 5. “Discontinued Operations,” 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 will be subject to the applicable treatment set forth in the Plan and be discharged pursuant to the terms of the Plan.
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, that was then known as 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. Orders have been made by the court relating to trial preparation steps, with the steps expected to be completed by the end of February 2018. A trial date is expected in the second half of 2018 (at the earliest) or in 2019. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss currently cannot be reasonably estimated.
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 Peabody Energy Corporation (PEC), 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 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 then 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 the then 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. On March 30, 2017, the United States District Court granted the motion to dismiss. On May 1, 2017, the plaintiffs filed a notice of appeal regarding the March 30th order granting the motion to dismiss.
On July 7, 2017 the Bankruptcy Court entered an order on the agreed stipulation of the Debtors and plaintiffs such that the claim of the plaintiffs was estimated to have no value for purposes of any distribution under the Plan, except that plaintiffs are not precluded from pursuing recovery from applicable insurance, and that plaintiffs will limit their recovery solely to applicable insurance.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On September 28 2017, plaintiffs unilaterally filed a notice of dismissal of the appeal with the Eighth Circuit Court of Appeals. On September 29, 2017, the Eighth Circuit Court of Appeals granted the motion to dismiss the appeal. The March 30, 2017 United States District Court’s order granting the motion to dismiss is now a final judgment.
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 recognized during 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. Berenergy so far has not applied to the Commission for approval and the Company believes it is not probable that the Commission would approve access to the secondary deposits if Berenergy applied 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 September 30, 2017. 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. Both parties filed appellate briefs on April 17, 2017. The matter before the Wyoming Supreme Court has been fully briefed by the parties and oral arguments were held on August 16, 2017. On June 22, 2017, the Bankruptcy Court entered an order disallowing Berenergy’s proof of claim for the amounts awarded in the Wyoming Court Decision, which the Company believes discharged its obligation to pay these amounts.
County of San Mateo, County of Marin, City of Imperial Beach. The Company was named as a defendant, along with numerous other companies, in three nearly identical lawsuits. The lawsuits seek to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions attributable to those fuels. The lawsuits primarily assert that the companies’ products have caused a sea level rise that is damaging the plaintiffs. The complaints specifically alleged that the defendants’ activities from 1965 to 2015 caused such damage. The Company filed a motion to enforce the Confirmation Order in the Bankruptcy Court because the Confirmation Order enjoins claims that arose before the effective date of the Plan. The motion to enforce was heard on October 5, 2017 and granted on October 24, 2017. The Bankruptcy Court ordered the plaintiffs to dismiss their lawsuits against the Company.
10th Circuit U.S. Bureau of Land Management (BLM) Appeal. On September 15, 2017, the Tenth Circuit Court of Appeals reversed the District Court of Wyoming’s decision upholding BLM’s approval of four coal leases in the Powder River Basin. Two of the four leases relate to the Company’s North Antelope Rochelle Mine in Wyoming. There is no immediate impact on the Company’s leases as the Court of Appeals did not vacate the leases as part of its ruling. Rather, the Court of Appeals remanded the case back to the District Court with directions to order BLM to revise its environmental analysis. The Company’s operations will continue in the normal course during this period since the decision has no impact on mining at this time. The Company currently believes that its operations are unlikely to be materially impacted by this case, but the timing and magnitude of any impact on the Company’s future operations is not certain. 
Wilpinjong Extension Project (WEP). Wollar Progress Association has applied to the Land & Environment Court for a judicial review of the New South Wales Planning Assessment Commission’s (PAC) decision to approve the WEP. In the interim, the Company’s Wilpinjong Mine can continue to mine in accordance with its approvals. The Company intends to fully defend the validity of the PAC’s 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 and many of its subsidiaries had no ongoing operations and PEC had no prior involvement in the past operations of Gold Fields and its subsidiaries. Prior to the Effective Date, Gold Fields was one of PEC’s subsidiaries. As part of separate transactions, both PEC and Gold Fields 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.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Pursuant to the indemnity, Blue Tee tendered its environmental claims for remediation, past 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 stopped paying these remediation costs.
Environmental assessments for remediation, past and future costs, and/or natural resource damages were also asserted by the United States Environmental Protection Agency (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 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, were collectively estimated to be $62.8 million as of December 31, 2016 in the condensed consolidated balance sheets. The majority of these estimated costs related 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 it claim to increase the amount of the claim to $1.2 billion.
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 totaled in excess of $2.7 billion and alleged 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 were duplicative as they overlapped with each other as well as with claims made by Blue Tee.
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 PEC has liability to the claimant under applicable federal environmental statutes for the Blue Tee sites listed in the claims based on the fact that PEC 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 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 March 16 and 17, 2017, the Bankruptcy Court entered orders approving these settlements. On July 13, 2017, the Debtors and government entities entered into a settlement agreement to reflect the above settlement.  Notice of the settlement agreement was given in the Federal Register on July 20, 2017. On September 5, 2017, the Bankruptcy Court gave final approval of the settlement agreement after the notice and comment period expired. As of the Effective Date, all Gold Fields assets and liabilities have been transferred to the Gold Fields Liquidating Trust and Reorganized Debtors have no further obligations with respect to Gold Fields.


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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.
(20) Segment Information
The Company reports its results of operations 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 Company’s chief operating decision maker (CODM) uses Adjusted EBITDA as the primary metric to measure each of the segment’s operating performance.
Adjusted EBITDA is a non-U.S. GAAP measure defined as income (loss) from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses, depreciation, depletion and amortization and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of the segment’s operating performance, as displayed in the reconciliation below. Management believes non-U.S. GAAP performance measures are used by investors to measure the Company’s operating performance and lenders to measure the Company’s ability to incur and service debt. 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.
Reportable segment results were as follows:
 
 
Successor
Predecessor
 
Successor
Predecessor
 
 
Three Months Ended September 30, 2017
Three Months Ended September 30, 2016
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2016
 
 
 
Revenues:
 
 
 
 
 
 
 
 
Powder River Basin Mining
 
$
420.9

$
419.6

 
$
786.3

$
394.3

 
$
1,062.2

Midwestern U.S. Mining
 
207.7

211.0

 
402.6

193.2

 
599.6

Western U.S. Mining
 
155.7

162.4

 
281.1

149.7

 
387.0

Australian Metallurgical Mining
 
415.9

232.5

 
703.7

328.9

 
682.8

Australian Thermal Mining
 
265.8

197.9

 
505.0

224.8

 
561.4

Trading and Brokerage
 
19.4

2.7

 
24.6

15.0

 
16.5

Corporate and Other
 
(8.2
)
(19.0
)
 
32.2

20.3

 
(35.0
)
Total
 
$
1,477.2

$
1,207.1

 
$
2,735.5

$
1,326.2

 
$
3,274.5

 
 
 
 
 
 
 
 
 
Adjusted EBITDA:
 
 
 
 
 
 
 
 
Powder River Basin Mining
 
$
112.7

$
123.9

 
$
197.5

$
91.7

 
$
278.3

Midwestern U.S. Mining
 
49.5

59.1

 
96.0

50.0

 
172.4

Western U.S. Mining
 
34.5

34.3

 
79.4

50.0

 
83.2

Australian Metallurgical Mining
 
143.1

(34.5
)
 
215.0

109.6

 
(121.0
)
Australian Thermal Mining
 
97.8

48.9

 
203.7

75.6

 
137.2

Trading and Brokerage
 
2.7

(9.4
)
 
(2.4
)
8.8

 
(41.3
)
Corporate and Other (1)
 
(29.0
)
(92.1
)
 
(60.1
)
(44.4
)
 
(270.8
)
Total
 
$
411.3

$
130.2

 
$
729.1

$
341.3

 
$
238.0

(1)  
Includes a gain of $19.7 million related to the sale of Dominion Terminal Associates during the predecessor period January 1 through April 1, 2017 and a gain of $68.1 million related to the 2016 Settlement Agreement described in Note 5. “Discontinued Operations” during the predecessor nine months ended September 30, 2016.


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Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A reconciliation of consolidated income (loss) from continuing operations, net of income taxes to Adjusted EBITDA follows:
 
 
Successor
Predecessor
 
Successor
Predecessor


Three Months Ended September 30, 2017
Three Months Ended September 30, 2016

April 2 through September 30, 2017
January 1 through April 1, 2017

Nine Months Ended September 30, 2016
 

(Dollars in millions)
  Income (loss) from continuing operations, net of income taxes

$
233.7

$
(97.7
)

$
335.1

$
(195.5
)

$
(488.6
)
Depreciation, depletion and amortization

194.5

117.8


342.8

119.9


345.5

Asset retirement obligation expenses

11.3

12.7


22.3

14.6


37.3

Selling and administrative expenses related to debt restructuring

—

—


—

—


21.5

Asset impairment

—

—


—

30.5


17.2

Change in deferred tax asset valuation allowance related to equity affiliates

(3.4
)
(0.6
)

(7.7
)
(5.2
)

(0.6
)
Interest expense

42.4

58.5


83.8

32.9


243.7

Loss on early debt extinguishment
 
12.9

—

 
12.9

—

 
—

Interest income

(2.0
)
(1.3
)

(3.5
)
(2.7
)

(4.0
)
Break fees related to terminated asset sales

—

—


(28.0
)
—


—

Unrealized losses (gains) on non-coal trading derivative contracts

1.7

—


(1.5
)
—


—

Unrealized losses (gains) on economic hedges

10.8

21.9


1.4

(16.6
)

49.1

Coal inventory revaluation

—

—


67.3

—


—

Take-or-pay contract-based intangible recognition

(6.5
)
—


(16.4
)
—


—

Reorganization items, net

—

29.7


—

627.2


125.1

Income tax benefit

(84.1
)
(10.8
)

(79.4
)
(263.8
)

(108.2
)
Total Adjusted EBITDA

$
411.3

$
130.2


$
729.1

$
341.3


$
238.0



Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.
As used in this report, the terms “we,” “us,” “our,” and the “Company” refer to Peabody Energy Corporation and its consolidated subsidiaries and affiliates, collectively, unless the context indicates otherwise. The term “Peabody” refers to Peabody Energy Corporation and not its consolidated subsidiaries and affiliates.
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, as amended, 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 this Item 2. 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.


50


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:
•
the impact of assumptions and analyses developed by us which formed, in large part, the basis of the Plan could be incorrect, also persisting or worsening adverse market conditions could affect our ability to successfully implement the Plan;
•
certain claims that may not ultimately be discharged in the Plan could have a material adverse effect on our financial condition and results of operation;
•
adjustments to our historical financial information, which as a result of our emergence from our Chapter 11 Cases, will not be indicative of our future financial performance and realization of assets and liquidation of liabilities are subject to uncertainty;
•
the impairment of certain of the tax assets of our Australian operations as a result of the consummation of the Plan;
•
our dependence on the prices we receive for our coal, which are dependent on 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 the 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 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 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;
•
our ability to find alternate buyers willing to purchase our coal on comparable terms in the event that a substantial number of our long-term coal supply agreements terminate, which could cause our revenues and operating profits to suffer;
•
the loss of, or significant reduction in, purchases by our largest customers, which could adversely affect our revenues;
•
our trading and hedging activities that no longer cover certain risks, and which could expose us to earnings volatility and other risks, including increasing requirements to post collateral;
•
unfavorable economic and financial market conditions, which could adversely affect our operating results;
•
our ability to collect payments from our customers could be impaired if their creditworthiness or contractual performance deteriorates;
•
risks inherent to mining, such as 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, could increase the cost of operating our business;
•
any substantial increase in the price or the unavailability of transportation of our coal for our customers, in which case our ability to sell coal could suffer;
•
any decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires, which could decrease our anticipated profitability;
•
impacts of any unfavorable take-or-pay arrangements within the coal industry on our profitability;
•
inability of trading, brokerage, mining or freight counterparties to fulfill the terms of their contracts with us, which could reduce our profitability;
•
impairment charges that may result from any failure to recover our investments in our mining, exploration and other assets;
•
loss of key personnel or failure to attract qualified personnel may impact our ability to operate our company effectively;
•
our ability to maintain satisfactory labor relations;


51


•
our ability to appropriately provide financial assurances for our obligations, including land reclamation, federal and state workers’ compensation, coal leases and other obligations related to our operations;
•
the extensive regulation of our mining operations, which imposes significant costs, and future regulations and developments, which could impose significant costs on us and limit our ability to produce coal;
•
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 ability to obtain and renew permits necessary for our operations, which would reduce our production, cash flows and profitability;
•
the extensive forms of taxation of our mining operations, which imposes significant costs on us, and future regulations and developments which could increase those costs or limit our ability to produce coal competitively;
•
accuracy of our assumptions underlying our asset retirement obligations for reclamation and mine closures, which could raise our costs significantly greater than anticipated if the assumptions are materially inaccurate;
•
our ability to continue to acquire and develop coal reserves that are economically recoverable;
•
uncertainties in estimating our economically recoverable coal reserves, where inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability;
•
increased exposure to risks unique to international mining and trading operations, such as country risks, international regulatory requirements and the effects of changes in currency exchange rates;
•
the success or failure of joint ventures, partnerships or non-managed operations in which we participate, and the limited control over compliance with our operational standards that we may exercise over such non-managed operations;
•
further repositioning plans that we may undertake, and associated additional charges;
•
significant liability, reputational harm, loss of revenue, increased costs or other risks that we may sustain as a result of 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;
•
accuracy of our assumptions underlying our predicted expenditures for postretirement benefit and pension obligations;
•
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;
•
risks that could materially and adversely affect our business, including deterioration or other changes in economic conditions, changes in the industry, changes in customer demand for, and acceptance of, our coal, and increasing expenses;
•
dilution of our Common Stock;
•
our ability to pay dividends on our stock or to repurchase our stock, and our inability to assure future payments and repurchases;
•
our substantial indebtedness, which could adversely affect our financial performance. The degree to which we are leveraged could have important consequences, including, but not limited to, make it more difficult for us to pay interest and satisfy our debt obligations, increase the cost of borrowing under our credit facilities, increase our vulnerability to general economic and industry conditions, require 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, limit our ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements, limit our flexibility in planning for and reacting to changes in our business and in the coal industry, cause a decline in our credit ratings and place us at a competitive disadvantage to less leveraged competitors;
•
our and our subsidiaries’ ability to incur substantially more debt despite our and our subsidiaries’ level of indebtedness following the Plan Effective Date, including secured debt, which could further increase the risks associated with our substantial indebtedness;
•
any failure to generate sufficient cash to service all of our post-emergence indebtedness or other obligations;
•
restrictions imposed by the terms of our indenture governing the Senior Secured Notes and the agreements and instruments governing our other post-emergence indebtedness, which may impose restrictions that may limit our operating and financial flexibility;


52


•
our ability to fully utilize our deferred tax assets;
•
provisions in our Certificate of Incorporation and By-laws that may discourage a takeover attempt;
•
diversity in interpretation and application of accounting literature in the mining industry that may impact our reported financial results;
•
volatility in the price of our securities;
•
conflicts of interest among our significant stockholders and other holders of our securities;
•
reports and projections published by analysts, including projections in those reports that exceed our actual results, which could adversely affect the price and trading volume of our securities;
•
sales of our common stock that could exert downward pressure on the market price of our common stock, and could encourage short selling that could exert further downward pressure; and
•
other risks and factors detailed in this report, including, but not limited to, those discussed in “Legal Proceedings,” set forth in Part II, Item 1 and in “Risk Factors,” set forth in Part II, Item 1A of this Quarterly Report on Form 10-Q.
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, including, but not limited to, the more detailed discussion of these factors and other factors that could affect our results contained in Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” of our Annual Report on Form 10-K for the year ended December 31, 2016, Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on April 11, 2017, and in Amendment No. 1 to our Annual Report on Form 10-K/A for the year ended December 31, 2016 filed with the SEC on July 10, 2017. 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 federal securities laws.
Overview
We are the world’s largest private-sector coal company by volume. As of September 30, 2017, we owned interests in 23 coal mining operations located in the United States (U.S.) and Australia. 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.
In 2016, we produced 175.6 million tons of coal and sold 186.8 million tons of coal 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.
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. Refer to Note 20. “Segment Information” to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of our Corporate and Other segment.
Filing Under Chapter 11 of the United States Bankruptcy Code
On April 13, 2016 (the Petition Date), Peabody Energy Corporation 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 were not included in the filings. The Debtors’ Chapter 11 cases (collectively, the Chapter 11 Cases) were jointly administered under the caption In re Peabody Energy Corporation, et al., Case No. 16-42529 (Bankr. E.D. Mo.). During the Chapter 11 Cases, the Debtors continued 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 were authorized under Chapter 11 to continue to operate as an ongoing business, but could not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court.


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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 the 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 and 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, Docket No. 2763 (the Confirmation Order), confirming the Plan. On April 3, 2017 (the Effective Date), the Debtors satisfied the conditions to effectiveness set forth in the Plan, the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases.
Upon emergence, in accordance with Accounting Standards Codification (ASC) 852, we applied fresh start reporting to our consolidated financial statements as of April 1, 2017 and became a new entity for financial reporting purposes reflecting the Successor (as defined below) capital structure. As a new entity, a new accounting basis in the identifiable assets and liabilities assumed was established with no retained earnings or accumulated other comprehensive income (loss) (OCI). For additional details, refer to Note 1. “Basis of Presentation” and Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” to the unaudited condensed consolidated financial statements.
In connection with our emergence from the Chapter 11 Cases and the adoption of fresh start reporting, the results of operations for 2017 separately present a Successor period (for the period April 2, 2017 through September 30, 2017) and a Predecessor period (for the period January 1, 2017 through April 1, 2017). The results of operations for 2016 include Predecessor periods for the three and nine months ended September 30, 2016. References to “Successor” are in reference to reporting dates on or after April 2, 2017; references to “Predecessor” are in reference to reporting dates through April 1, 2017, which include the impact of the Plan provisions and the application of fresh start reporting. Although the 2017 Successor period and the 2017 Predecessor period are distinct reporting periods, the effects of emergence and fresh start reporting did not have a material impact on the comparability of our results of operations between the periods, unless otherwise noted below. Accordingly, references to 2017 results of operations for the nine months ended September 30, 2017 combine the two periods to enhance the comparability of such information to the prior year.
Results of Operations
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. generally accepted accounting principles (GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of our segment’s 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 income (loss) from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses, depreciation, depletion and amortization and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of our segment’s operating performance, as displayed in the reconciliation below. 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 20. “Segment Information” of the accompanying unaudited condensed consolidated financial statements.
Also included in the following discussion of our results of operations are references to Revenues per Ton, Operating Costs per Ton and Gross Margin per Ton for each reporting segment which are all non-U.S. GAAP measures. Revenues per Ton and Gross Margin per Ton are approximately equal to revenues by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Operating Costs per Ton is equal to Revenues per Ton less Gross Margin per Ton.
Three and Nine Months Ended September 30, 2017 Compared to the Three and Nine Months Ended September 30, 2016
Summary
Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal and Newcastle index thermal coal, and prompt month pricing for Powder River Basin (PRB) 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended September 30, 2017 is set forth in the table below. Pricing for our Western U.S. Mining segment is not included as there is no similar spot or prompt pricing data available.


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In the U.S., the pricing included in the table below is not necessarily indicative of the pricing we realized during the three months ended September 30, 2017 since we generally sell coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may 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. Competition from alternative fuels such as natural gas and other coal producers may also impact our realized pricing.
The seaborne pricing included in the table below is also not necessarily indicative of the pricing we realized during the three months ended September 30, 2017 due to price discounts based on coal qualities and properties.
 
 
High
 
Low
 
Average
 
September 30, 2017
Premium HCC
 
$
211.00

 
$
151.50

 
$
188.78

 
$
187.25

Premium PCI coal
 
$
128.55

 
$
102.35

 
$
116.75

 
$
124.80

Newcastle index thermal coal
 
$
100.30

 
$
79.45

 
$
93.23

 
$
97.25

PRB 8,800 Btu/Lb coal
 
$
11.90

 
$
11.20

 
$
11.62

 
$
11.50

Illinois Basin 11,500 Btu/Lb coal
 
$
35.00

 
$
33.25

 
$
34.45

 
$
35.00

Seaborne thermal and metallurgical coal pricing remained well above prior-year levels on continued strength in China and overall supply constraints.
With respect to seaborne metallurgical coal, global steel production has risen approximately 5% during the nine months ended September 30, 2017 as compared to the prior year period, led by record Chinese steel production. In addition, Chinese steel exports are down 30% year-to-date through September. Through the nine months ended September 30, 2017 metallurgical coal imports in China rose 9 million tonnes as compared to the prior year period on strong demand and curtailed domestic production.
Seaborne thermal coal demand and pricing continue to be supported by robust Asian demand primarily in China and South Korea. Chinese thermal coal imports are up approximately 15 million tonnes year-to-date through September compared to the prior year period on strong electricity generation that exceeded domestic production growth. In addition, South Korean imports have strengthened approximately 15 million tonnes through September, a 23% increase year-over-year, as nuclear generation has been curtailed. While import demand from India has been sluggish on increased domestic coal usage, stockpiles are currently at multi-year lows, which is supportive of additional imports in the fourth quarter.
In the United States, demand was impacted by mild weather and weaker gas pricing in the third quarter of 2017. Even as overall electricity demand weakened year-over-year through September, utility consumption of Powder River Basin coal rose approximately 8% with natural gas consumption decreasing 12% compared to the prior year period (on 30% higher average natural gas prices year-over-year through September).
Net results of $230.0 million for the Successor three months ended September 30, 2017 included revenues of $1,477.2 million, a tax benefit of $84.1 million and income from equity affiliates of $10.5 million. These were offset by operating costs of $1,044.9 million, depreciation, depletion and amortization of $194.5 million and interest expense of $42.4 million related to the new debt instruments for the Successor Company. Net income attributable to common stockholders of $201.4 million included dividends of $23.5 million related to the Series A Convertible Preferred Stock (Preferred Stock) issued by the Successor Company. Adjusted EBITDA for the three months ended September 30, 2017 was $411.3 million.
Net results of $328.7 million for the Successor period April 2 through September 30, 2017 included revenues of $2,735.5 million, a tax benefit of $79.4 million and income from equity affiliates of $26.2 million. These were offset by operating costs of $1,979.7 million, depreciation, depletion and amortization of $342.8 million and interest expense of $83.8 million. Net income attributable to common stockholders of $181.2 million for the Successor period April 2 through September 30, 2017 was impacted by Preferred Stock dividends of $138.6 million. Adjusted EBITDA for the Successor period April 2 through September 30, 2017 was $729.1 million.
For the Predecessor period January 1 through April 1, 2017, net loss attributable to common stockholders of $216.5 million included revenues of $1,326.2 million, a tax benefit of $263.8 million and income from equity affiliates of $15.0 million. These were offset by operating costs of $963.7 million, depreciation, depletion and amortization of $119.9 million, interest expense of $32.9 million and reorganization items, net of $627.2 million which included the impact of the Plan provisions and the application of fresh start reporting. Adjusted EBITDA for the Predecessor period January 1 through April 1, 2017 was $341.3 million.


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During the three and nine months ended September 30, 2016, the Predecessor Company had net loss attributable to common stockholders of $137.6 million and $536.6 million, respectively. The three months ended September 30, 2016 had revenues of $1,207.1 million which were offset by operating costs of $1,064.8 million, depreciation, depletion and amortization of $117.8 million, selling and administrative expenses of $32.1 million, interest expense of $58.5 million, and reorganization items, net of $29.7 million. The nine months ended September 30, 2016 had revenues of $3,274.5 million, which were offset by operating costs of $2,981.2 million, depreciation, depletion and amortization of $345.5 million, selling and administrative expenses of $114.6 million, interest expense of $243.7 million and reorganization items, net of $125.1 million. The Adjusted EBITDA for the three and nine months ended September 30, 2016 was $130.2 million and $238.0 million, respectively.
As of September 30, 2017, our available liquidity was approximately $942.7 million. Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of factors affecting our available liquidity.
Tons Sold
The following tables present tons sold by operating segment:
Three Month Comparison
2017
 
 
2016
 
 
 
 
 
Successor
 
 
Predecessor
 
Increase (Decrease)
 
Three Months Ended
 
to Volumes
 
September 30
 
Tons
 
%
 
(Tons in millions)
 
 
Powder River Basin Mining
33.7

 
 
33.0

 
0.7

 
2
 %
Midwestern U.S. Mining
4.9

 
 
4.9

 
—

 
—
 %
Western U.S. Mining
4.0

 
 
4.3

 
(0.3
)
 
(7
)%
Australian Metallurgical Mining
3.5

 
 
3.2

 
0.3

 
9
 %
Australian Thermal Mining
5.2

 
 
5.4

 
(0.2
)
 
(4
)%
Total tons sold from mining segments
51.3

 
 
50.8

 
0.5

 
1
 %
Trading and Brokerage
0.7

 
 
2.0

 
(1.3
)
 
(65
)%
Total tons sold
52.0

 
 
52.8

 
(0.8
)
 
(2
)%
Nine Month Comparison
2017
 
2016
 
 
 
 
 
Successor
 
 
Predecessor
 
Combined
 
Predecessor
 
Increase (Decrease)
 
April 2 through September 30
 
 
January 1 through April 1
 
Nine Months Ended
 
to Volumes
 
 
 
 
September 30
 
Tons
 
%
 
(Tons in millions)
 
 
Powder River Basin Mining
62.2

 
 
31.0

 
93.2

 
80.0

 
13.2

 
17
 %
Midwestern U.S. Mining
9.5

 
 
4.5

 
14.0

 
13.8

 
0.2

 
1
 %
Western U.S. Mining
7.2

 
 
3.4

 
10.6

 
10.0

 
0.6

 
6
 %
Australian Metallurgical Mining
5.5

 
 
2.2

 
7.7

 
10.1

 
(2.4
)
 
(24
)%
Australian Thermal Mining
9.8

 
 
4.6

 
14.4

 
15.8

 
(1.4
)
 
(9
)%
Total tons sold from mining segments
94.2

 
 
45.7

 
139.9

 
129.7

 
10.2

 
8
 %
Trading and Brokerage
1.4

 
 
0.4

 
1.8

 
5.4

 
(3.6
)
 
(67
)%
Total tons sold
95.6

 
 
46.1

 
141.7

 
135.1

 
6.6

 
5
 %


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Supplemental Financial Data
The following tables present supplemental financial data by operating segment:
Three Month Comparison
2017
 
 
2016
 
 
 
 
 
Successor
 
 
Predecessor
 
 
 
Three Months Ended
 
(Decrease) Increase
 
September 30
 
$
 
%
 
 
 
 
 
 
 
 
 
Revenues per Ton - Mining Operations
 
 
 
 
 
 
 
 
Powder River Basin
$
12.48

 
 
$
12.73

 
$
(0.25
)
 
(2
)%
Midwestern U.S.
42.52

 
 
43.02

 
(0.50
)
 
(1
)%
Western U.S.
38.25

 
 
38.03

 
0.22

 
1
 %
Australian Metallurgical
119.55

 
 
71.34

 
48.21

 
68
 %
Australian Thermal
51.78

 
 
36.53

 
15.25

 
42
 %
Operating Costs per Ton - Mining Operations (1)
 
 
 
 
 
 
 
 
Powder River Basin
$
9.13

 
 
$
8.97

 
$
0.16

 
2
 %
Midwestern U.S.
32.39

 
 
30.96

 
1.43

 
5
 %
Western U.S.
29.77

 
 
30.00

 
(0.23
)
 
(1
)%
Australian Metallurgical
78.42

 
 
81.93

 
(3.51
)
 
(4
)%
Australian Thermal
32.72

 
 
27.50

 
5.22

 
19
 %
Gross Margin per Ton - Mining Operations (1)
 
 
 
 
 
 
 
 
Powder River Basin
$
3.35

 
 
$
3.76

 
$
(0.41
)
 
(11
)%
Midwestern U.S.
10.13

 
 
12.06

 
(1.93
)
 
(16
)%
Western U.S.
8.48

 
 
8.03

 
0.45

 
6
 %
Australian Metallurgical
41.13

 
 
(10.59
)
 
51.72

 
488
 %
Australian Thermal
19.06

 
 
9.03

 
10.03

 
111
 %
(1)
Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; coal inventory revaluation; take-or-pay contract-based intangible recognition; and certain other costs related to post-mining activities.


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Nine Month Comparison
2017
 
2016
 
 
 
 
 
Successor
 
 
Predecessor
 
Combined
 
Predecessor
 
 
 
April 2 through September 30


January 1 through April 1
 
Nine Months Ended
 
(Decrease) Increase
 


 
September 30
 
$
 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues per Ton - Mining Operations
 
 
 
 
 
 
 
 
 
 
 
 
Powder River Basin
$
12.65

 
 
$
12.70

 
$
12.67

 
$
13.28

 
$
(0.61
)
 
(5
)%
Midwestern U.S.
42.57

 
 
42.96

 
42.69

 
43.45

 
(0.76
)
 
(2
)%
Western U.S.
38.54

 
 
44.68

 
40.47

 
38.72

 
1.75

 
5
 %
Australian Metallurgical
128.89

 
 
150.22

 
135.03

 
67.39

 
67.64

 
100
 %
Australian Thermal
51.65

 
 
48.65

 
50.69

 
35.60

 
15.09

 
42
 %
Operating Costs per Ton - Mining Operations (1)
 
 
 
 
 
 
 
 
 
 
 
 
Powder River Basin
$
9.47

 
 
$
9.75

 
$
9.57

 
$
9.80

 
$
(0.23
)
 
(2
)%
Midwestern U.S.
32.42

 
 
31.84

 
32.23

 
30.96

 
1.27

 
4
 %
Western U.S.
27.65

 
 
29.76

 
28.31

 
30.39

 
(2.08
)
 
(7
)%
Australian Metallurgical
89.53

 
 
100.16

 
92.57

 
79.34

 
13.23

 
17
 %
Australian Thermal
30.79

 
 
32.27

 
31.29

 
26.90

 
4.39

 
16
 %
Gross Margin per Ton - Mining Operations (1)
 
 
 
 
 
 
 
 
 
 
 
 
Powder River Basin
$
3.18

 
 
$
2.95

 
$
3.10

 
$
3.48

 
$
(0.38
)
 
(11
)%
Midwestern U.S.
10.15

 
 
11.12

 
10.46

 
12.49

 
(2.03
)
 
(16
)%
Western U.S.
10.89

 
 
14.92

 
12.16

 
8.33

 
3.83

 
46
 %
Australian Metallurgical
39.36

 
 
50.06

 
42.46

 
(11.95
)
 
54.41

 
455
 %
Australian Thermal
20.86

 
 
16.38

 
19.40

 
8.70

 
10.70

 
123
 %
(1)
Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; coal inventory revaluation; take-or-pay contract-based intangible recognition; and certain other costs related to post-mining activities.
Revenues
The following tables present revenues by reporting segment:
Three Month Comparison
2017
 
 
2016
 
 
 
 
 
Successor
 
 
Predecessor
 
Increase (Decrease)
 
Three Months Ended
 
to Revenues
 
September 30
 
$
 
%
 
(Dollars in millions)
 
 
Powder River Basin Mining
$
420.9

 
 
$
419.6

 
$
1.3

 
—
 %
Midwestern U.S. Mining
207.7

 
 
211.0

 
(3.3
)
 
(2
)%
Western U.S. Mining
155.7

 
 
162.4

 
(6.7
)
 
(4
)%
Australian Metallurgical Mining
415.9

 
 
232.5

 
183.4

 
79
 %
Australian Thermal Mining
265.8

 
 
197.9

 
67.9

 
34
 %
Trading and Brokerage
19.4

 
 
2.7

 
16.7

 
619
 %
Corporate and Other
(8.2
)
 
 
(19.0
)
 
10.8

 
57
 %
Total revenues
$
1,477.2

 
 
$
1,207.1

 
$
270.1

 
22
 %


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Nine Month Comparison
2017
 
2016
 
 
 
 
 
Successor
 
 
Predecessor
 
Combined
 
Predecessor
 
Increase (Decrease)
 
April 2 through September 30
 
 
January 1 through April 1
 
Nine Months Ended
 
to Revenues
 
 
 
 
September 30
 
$
 
%
 
(Dollars in millions)
 
 
Powder River Basin Mining
$
786.3

 
 
$
394.3

 
$
1,180.6

 
$
1,062.2

 
$
118.4

 
11
 %
Midwestern U.S. Mining
402.6

 
 
193.2

 
595.8

 
599.6

 
(3.8
)
 
(1
)%
Western U.S. Mining
281.1

 
 
149.7

 
430.8

 
387.0

 
43.8

 
11
 %
Australian Metallurgical Mining
703.7

 
 
328.9

 
1,032.6

 
682.8

 
349.8

 
51
 %
Australian Thermal Mining
505.0

 
 
224.8

 
729.8

 
561.4

 
168.4

 
30
 %
Trading and Brokerage
24.6

 
 
15.0

 
39.6

 
16.5

 
23.1

 
140
 %
Corporate and Other
32.2

 
 
20.3

 
52.5

 
(35.0
)
 
87.5

 
250
 %
Total revenues
$
2,735.5

 
 
$
1,326.2

 
$
4,061.7

 
$
3,274.5

 
$
787.2

 
24
 %
Powder River Basin Mining. Segment revenues increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year due to demand-based volume increases across the entire region as the result of increased natural gas pricing (three months, 0.7 million tons, $13.4 million; nine months, 13.2 million tons, $176.7 million) which drove a switch from natural gas to coal by customers, partially offset by lower realized coal pricing (three months, $12.1 million; nine months, $58.3 million).
Midwestern U.S. Mining. Segment revenues decreased during the three months ended September 30, 2017 compared to the same period in the prior year due to unfavorable volume and mix variances ($2.0 million) and lower realized coal pricing ($1.3 million). Segment revenues decreased during the nine months ended September 30, 2017 compared to the same period in the prior year primarily due to lower realized coal pricing ($5.0 million) which was slightly offset by favorable volume and mix variances ($1.2 million).
Western U.S. Mining. Segment revenues decreased during the three months ended September 30, 2017 compared to the same period in the prior year due to lower realized coal pricing ($3.4 million) and unfavorable volume and mix variances ($3.3 million). Segment revenues increased during the nine months ended September 30, 2017 compared to the same period in the prior year predominately due to favorable volume and mix variances from higher margin operations ($35.0 million) and the liquidated damages settlement collected from Arizona Public Service Company and PacifiCorp ($13.0 million).
Australian Metallurgical Mining. Segment revenues increased during the three months ended September 30, 2017 compared to the same period in the prior year primarily as the result of significantly improved realized coal pricing ($166.4 million) and a favorable volume and mix variance ($17.0 million) driven by improved production at our North Goonyella Mine due to a longwall move in the prior year period. Segment revenues increased during the nine months ended September 30, 2017 compared to the same period in the prior year primarily due to significantly improved realized coal pricing ($513.3 million) which was partially offset by an unfavorable volume and mix variance ($163.5 million). The volume decrease reflected lower sales volumes due to the cessation of mining activities at our Burton Mine during the fourth quarter of 2016, the impact of Cyclone Debbie and an extended longwall move at the Metropolitan Mine during the first half of 2017.
Australian Thermal Mining. Segment revenues increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to significantly improved realized coal pricing (three months, $75.8 million; nine months, $214.2 million), partially offset by an unfavorable volume and mix variance (three months, $7.9 million; nine months, $45.8 million) which was attributable to lower sales volumes from our Wambo Mine as the result of temporary geological issues associated with a longwall move.
Trading and Brokerage. Segment revenues increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year due to deliveries hedged in 2016.
Corporate and Other. Segment revenues increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year due to improved results on economic hedges (three months, $11.1 million; nine months, $64.3 million) and the receipt of break fees (nine months, $28.0 million) related to terminated asset sales which are further described in Note 16. “Other Events” of the accompanying unaudited condensed consolidated financial statements.


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Income (Loss) From Continuing Operations Before Income Taxes
The following table presents income (loss) from continuing operations before income taxes:
 
2017
 
 
2016
 
2017
 
2016
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
 
Combined
 
Predecessor
 
Three Months Ended
 
April 2 through September 30
 
 
January 1 through April 1
 
Nine Months Ended
 
September 30
 
 
 
 
September 30
 
(Dollars in millions)
Income (loss) from continuing operations before income taxes
$
149.6

 
 
$
(108.5
)
 
$
255.7

 
 
$
(459.3
)
 
$
(203.6
)
 
$
(596.8
)
Depreciation, depletion and amortization
(194.5
)
 
 
(117.8
)
 
(342.8
)
 
 
(119.9
)
 
(462.7
)
 
(345.5
)
Asset retirement obligation expenses
(11.3
)
 
 
(12.7
)
 
(22.3
)
 
 
(14.6
)
 
(36.9
)
 
(37.3
)
Selling and administrative expenses related to debt restructuring
—

 
 
—

 
—

 
 
—

 
—

 
(21.5
)
Asset impairment
—

 
 
—

 
—

 
 
(30.5
)
 
(30.5
)
 
(17.2
)
Change in deferred tax asset valuation allowance related to equity affiliates
3.4

 
 
0.6

 
7.7

 
 
5.2

 
12.9

 
0.6

Interest expense
(42.4
)
 
 
(58.5
)
 
(83.8
)
 
 
(32.9
)
 
(116.7
)
 
(243.7
)
Loss on early debt extinguishment
(12.9
)
 
 
—

 
(12.9
)
 
 
—

 
(12.9
)
 
—

Interest income
2.0

 
 
1.3

 
3.5

 
 
2.7

 
6.2

 
4.0

Break fees related to terminated asset sales
—

 
 
—

 
28.0

 
 
—

 
28.0

 
—

Unrealized (losses) gains on non-coal trading derivative contracts
(1.7
)
 
 
—

 
1.5

 
 
—

 
1.5

 
—

Unrealized (losses) gains on economic hedges
(10.8
)
 
 
(21.9
)
 
(1.4
)
 
 
16.6

 
15.2

 
(49.1
)
Coal inventory revaluation
—

 
 
—

 
(67.3
)
 
 
—

 
(67.3
)
 
—

Take-or-pay contract-based intangible recognition
6.5

 
 
—

 
16.4

 
 
—

 
16.4

 
—

Reorganization items, net
—

 
 
(29.7
)
 
—

 
 
(627.2
)
 
(627.2
)
 
(125.1
)
Adjusted EBITDA
$
411.3

 
 
$
130.2

 
$
729.1

 
 
$
341.3

 
$
1,070.4

 
$
238.0

Results from continuing operations before income taxes for the Successor three months ended September 30, 2017 resulted in Adjusted EBITDA of $411.3 million which was partially offset by depreciation, depletion and amortization, interest expense. and loss on early debt extinguishment. Results from continuing operations before income taxes for the Successor period April 2 through September 30, 2017 included Adjusted EBITDA of $729.1 million and break fees related to terminated asset sales, which were partially decreased by depreciation, depletion and amortization, fresh start reporting fair value adjustments, interest expense and loss on early debt extinguishment.
Results from continuing operations before income taxes for the Predecessor period January 1 through April 1, 2017 were impacted by reorganization items, net, depreciation, depletion and amortization and interest expense. These results were partially offset by Adjusted EBITDA of $341.3 million.
During the three and nine months ended September 30, 2016, the Predecessor Company’s results from continuing operations before income taxes included Adjusted EBITDA of $130.2 million and $238.0 million, respectively. These results were offset by depreciation, depletion and amortization, interest expense and reorganization items, net.


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Adjusted EBITDA
The following tables present Adjusted EBITDA for each of our reporting segments:
Three Month Comparison
2017
 
 
2016
 
(Decrease) Increase
 
Successor
 
 
Predecessor
 
to Segment Adjusted
 
Three Months Ended
 
EBITDA
 
September 30
 
$
 
%
 
(Dollars in millions)
 
 
Powder River Basin Mining
$
112.7

 
 
$
123.9

 
$
(11.2
)
 
(9
)%
Midwestern U.S. Mining
49.5

 
 
59.1

 
(9.6
)
 
(16
)%
Western U.S. Mining
34.5

 
 
34.3

 
0.2

 
1
 %
Australian Metallurgical Mining
143.1

 
 
(34.5
)
 
177.6

 
515
 %
Australian Thermal Mining
97.8

 
 
48.9

 
48.9

 
100
 %
Trading and Brokerage
2.7

 
 
(9.4
)
 
12.1

 
129
 %
Corporate and Other
(29.0
)
 
 
(92.1
)
 
63.1

 
69
 %
Adjusted EBITDA
$
411.3

 
 
$
130.2

 
$
281.1

 
216
 %
Nine Month Comparison
2017
 
2016
 
Increase (Decrease)
 
Successor
 
 
Predecessor
 
Combined
 
Predecessor
 
to Segment Adjusted
 
April 2 through September 30


January 1 through April 1
 
Nine Months Ended
 
EBITDA
 


 
September 30
 
$
 
%
 
(Dollars in millions)
 
 
Powder River Basin Mining
$
197.5

 
 
$
91.7

 
$
289.2

 
$
278.3

 
$
10.9

 
4
 %
Midwestern U.S. Mining
96.0

 
 
50.0

 
146.0

 
172.4

 
(26.4
)
 
(15
)%
Western U.S. Mining
79.4

 
 
50.0

 
129.4

 
83.2

 
46.2

 
56
 %
Australian Metallurgical Mining
215.0

 
 
109.6

 
324.6

 
(121.0
)
 
445.6

 
368
 %
Australian Thermal Mining
203.7

 
 
75.6

 
279.3

 
137.2

 
142.1

 
104
 %
Trading and Brokerage
(2.4
)
 
 
8.8

 
6.4

 
(41.3
)
 
47.7

 
115
 %
Corporate and Other
(60.1
)
 
 
(44.4
)
 
(104.5
)
 
(270.8
)
 
166.3

 
61
 %
Adjusted EBITDA
$
729.1

 
 
$
341.3

 
$
1,070.4

 
$
238.0

 
$
832.4

 
350
 %
Powder River Basin Mining. Segment Adjusted EBITDA decreased during the three months ended September 30, 2017 compared to the same period in the prior year due to lower realized coal pricing, net of sales-related costs ($9.7 million), higher materials, services and repairs costs ($3.7 million) and increased pricing for fuel and explosives ($2.9 million), partially offset by reduced lease expenses resulting from early lease buyouts ($6.0 million). Segment Adjusted EBITDA increased during the nine months ended September 30, 2017 compared to the same period in the prior year due to higher volume driven by increased natural gas pricing ($50.6 million) and reduced expenses for leases ($16.5 million) and labor ($12.3 million), partially offset by lower realized coal pricing, net of sales-related costs ($59.0 million) and increased pricing for fuel and explosives ($11.4 million).
Midwestern U.S. Mining. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to higher materials, services and repairs costs (three months, $4.4 million; nine months, $13.3 million), increased pricing for fuel and explosives (three months, $1.5 million; nine months, $8.2 million) and lower realized coal pricing, net of sales-related costs (three months, $2.7 million; nine months, $7.4 million).
Western U.S. Mining. Segment Adjusted EBITDA increased during the nine months ended September 30, 2017 compared to the same period in the prior year primarily due to improved sales volumes from higher margin operations ($27.3 million), the liquidated damages settlement collected from Arizona Public Service Company and PacifiCorp ($13.0 million) and decreased spending for materials, services and repairs costs ($12.7 million), partially offset by lower realized coal pricing, net of sales-related costs ($5.5 million).


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Australian Metallurgical Mining. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily driven by improved realized coal pricing, net of sales-related costs (three months, $155.2 million; nine months, $478.2 million), improved volumes at our North Goonyella Mine (three months, $23.5 million; nine months, $14.9 million) resulting from longwall moves in the prior year, improved production volumes at our Coppabella Mine (three months, $14.8 million; nine months, $19.2 million) and lower contractor and rail costs due to the cessation of mining activities at our Burton Mine during the fourth quarter of 2016 (nine months, $14.8 million). The increases were offset by the impact of Cyclone Debbie, unfavorable foreign exchange rate movements (three months, $9.4 million; nine months, $16.1 million) and cost escalations (three months, $6.0 million; nine months, $17.5 million).
Australian Thermal Mining. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to improved realized coal pricing, net of sales-related costs (three months, $69.9 million; nine months, $197.5 million) and improved production and leasing costs at our Wilpinjong Mine (three months, $6.8 million), offset by lower sales volume caused by geological issues at our Wambo Mine (three months, $26.8 million; nine months, $28.2 million) and higher fuel pricing and other cost escalations (three months, $3.5 million; nine months, $13.3 million).
Trading and Brokerage. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to market and business opportunities recognized.
Corporate and Other Adjusted EBITDA. The following tables present a summary of the components of Corporate and Other Adjusted EBITDA:
Three Month Comparison
2017
 
 
2016
 
 
 
 
 
Successor
 
 
Predecessor
 
(Decrease) Increase
 
Three Months Ended
 
to Income
 
September 30
 
Tons
 
$
 
(Dollars in millions)
 
 
Resource management activities (1)
$
0.4

 
 
$
1.3

 
$
(0.9
)
 
(69
)%
Selling and administrative expenses (excluding debt restructuring)
(33.4
)
 
 
(32.1
)
 
(1.3
)
 
(4
)%
Restructuring charges
(1.1
)
 
 
(0.3
)
 
(0.8
)
 
(267
)%
Corporate hedging
7.3

 
 
(47.4
)
 
54.7

 
115
 %
Other items, net (2)
(2.2
)
 
 
(13.6
)
 
11.4

 
84
 %
Corporate and Other Adjusted EBITDA
$
(29.0
)
 
 
$
(92.1
)
 
$
63.1

 
69
 %
(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.


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Nine Month Comparison
2017
 
2016
 
 
 
 
 
Successor
 
 
Predecessor
 
Combined
 
Predecessor
 
(Decrease) Increase
 
April 2 through September 30
 
 
January 1 through April 1
 
Nine Months Ended
 
to Income
 
 
 
 
September 30
 
$
 
%
 
(Dollars in millions)
 
 
Resource management activities (1)
$
1.6

 
 
$
2.9

 
$
4.5

 
$
11.3

 
$
(6.8
)
 
(60
)%
Selling and administrative expenses (excluding debt restructuring)
(67.8
)
 
 
(37.2
)
 
(105.0
)
 
(93.1
)
 
(11.9
)
 
(13
)%
Restructuring charges
(1.1
)
 
 
—

 
(1.1
)
 
(15.5
)
 
14.4

 
93
 %
Corporate hedging
6.9

 
 
(27.6
)
 
(20.7
)
 
(197.8
)
 
177.1

 
90
 %
UMWA voluntary employee beneficiary association settlement
—

 
 
—

 
—

 
68.1

 
(68.1
)
 
(100
)%
Gain on sale of interest in Dominion Terminal Associates
—

 
 
19.7

 
19.7

 
—

 
19.7

 
n.m.

Other items, net (2)
0.3

 
 
(2.2
)
 
(1.9
)
 
(43.8
)
 
41.9

 
96
 %
Corporate and Other Adjusted EBITDA
$
(60.1
)
 
 
$
(44.4
)
 
$
(104.5
)
 
$
(270.8
)
 
$
166.3

 
61
 %
(1) 
Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues.
(2) 
Includes results from equity affiliates (before the impact of related changes in deferred tax asset valuation allowance and amortization of basis difference), costs associated with past mining activities, certain coal royalty expenses, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts and expenses related to our other commercial activities.
The increases associated with corporate hedging results, which includes foreign currency and commodity hedging, were due to a decrease in realized losses as compared to the same period in the prior year. The increases associated with “Other items, net” were primarily attributable to improved Middlemount results as compared to the prior year driven by higher pricing. During the first quarter of 2017, a $19.7 million gain was recorded in connection with the sale of our interest in Dominion Terminal Associates. Restructuring charges for the nine months ended September 30, 2017 decreased as workforce reductions were made during 2016 at multiple mines in our Power River Basin Mining and Midwestern U.S. Mining segments. During 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 5. “Discontinued Operations” of the accompanying unaudited condensed consolidated financial statements. The increases in selling and administrative expenses were driven by charges for shared-based compensation expense.
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment:
 
2017
 
 
2016
 
2017
 
2016
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
 
Predecessor
 
Three Months Ended September 30
 
April 2 through September 30
 
 
January 1 through April 1
 
Nine Months Ended
September 30
 
(Dollars in millions)
Powder River Basin Mining
$
(57.4
)
 
 
$
(33.5
)
 
$
(95.6
)
 
 
$
(32.0
)
 
$
(90.2
)
Midwestern U.S. Mining
(38.1
)
 
 
(12.9
)
 
(73.4
)
 
 
(13.3
)
 
(40.1
)
Western U.S. Mining
(32.9
)
 
 
(11.2
)
 
(57.7
)
 
 
(23.6
)
 
(34.3
)
Australian Metallurgical Mining
(37.1
)
 
 
(30.9
)
 
(64.3
)
 
 
(20.6
)
 
(90.3
)
Australian Thermal Mining
(25.7
)
 
 
(26.2
)
 
(45.5
)
 
 
(24.0
)
 
(77.2
)
Trading and Brokerage
(0.1
)
 
 
—

 
(0.1
)
 
 
—

 
(0.1
)
Corporate and Other
(3.2
)
 
 
(3.1
)
 
(6.2
)
 
 
(6.4
)
 
(13.3
)
Total
$
(194.5
)
 
 
$
(117.8
)
 
$
(342.8
)
 
 
$
(119.9
)
 
$
(345.5
)


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Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments:
 
2017
 
 
2016
 
2017
 
2016
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
 
Predecessor
 
Three Months Ended
September 30
 
April 2 through September 30
 
 
January 1 through April 1
 
Nine Months Ended September 30
Powder River Basin Mining
$
0.84

 
 
$
0.69

 
$
0.83

 
 
$
0.69

 
$
0.73

Midwestern U.S. Mining
0.83

 
 
0.54

 
0.78

 
 
0.61

 
0.52

Western U.S. Mining
1.06

 
 
0.91

 
1.06

 
 
4.30

 
0.91

Australian Metallurgical Mining
0.66

 
 
4.29

 
0.68

 
 
4.72

 
4.24

Australian Thermal Mining
1.73

 
 
2.59

 
1.72

 
 
2.62

 
2.61

Depreciation, depletion and amortization expense for the Successor three months ended September 30, 2017 includes depletion expense ($50.3 million), amortization of the fair value of certain U.S. coal supply agreements ($41.5 million), amortization associated with our asset retirement obligation assets ($14.8 million) and depreciation expense ($87.9 million). Depreciation, depletion and amortization expense was higher for the Successor three months ended September 30, 2017 as compared to the Successor period April 2 through June 30, 2017 as the result of volume increases in the period which impacted the portion of our depreciation, depletion and amortization expense that is recorded on a units-of-production method.
Depreciation, depletion and amortization expense for the Predecessor period January 1 through April 1, 2017 reflected additional expense at some of our mines due to changes in the estimated life of mine and at Corporate and Other for leasehold improvements that were vacated in 2017. The additional expense was offset by a decrease at our Metropolitan Mine as the assets were classified as held for sale during the period and depreciation, depletion and amortization was therefore not recorded. The share sale and purchase agreement related to our Metropolitan Mine was terminated in April 2017, as discussed in Note. 16. “Other Events” to the accompanying unaudited condensed consolidated financial statements. Depreciation, depletion and amortization expense for the three and nine months ended September 30, 2016 was impacted by a reduction in the asset bases at several of our mines due to impairment charges that had been recognized during 2015.
Selling and Administrative Expenses Related to Debt Restructuring. The general and administrative expenses related to debt restructuring recorded during 2016 related to legal and other expenditures made in connection with debt restructuring initiatives prior to the Debtors’ filing of the Bankruptcy Petitions.
Asset Impairment. Refer to Note 4. “Asset Impairment” in the accompanying unaudited condensed consolidated financial statements for information surrounding the impairment charges recorded during the Predecessor period January 1 through April 1, 2017 and the nine months ended September 30, 2016.
Interest Expense. Interest expense for the Successor Company primarily related to the 6.000% Senior Secured Notes due March 2022, the 6.375% Senior Secured Notes due March 2025 and the Senior Secured Term Loan due 2022. For additional details on debt, refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” and Note. 13. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements.
Interest expense for the Predecessor period January 1 through April 1, 2017 and the three and nine months ended September 30, 2016, was impacted by our filing of the Bankruptcy Petitions, which resulted in 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.
Loss on Early Debt Extinguishment. The loss on early debt extinguishment recorded on the Successor Company, related to the amendment of the Senior Secured Term Loan due 2022 as described in Note 13. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements.
Break Fees Related to Terminated Asset Sales. The Successor Company received break fees of $28.0 million during the period April 2 through September 30, 2017 related to terminated asset sales which are further described in Note 16. “Other Events” of the accompanying unaudited condensed consolidated financial statements.
Unrealized (Losses) Gains on Economic Hedges. Unrealized (losses) gains primarily relate to mark-to-market activity from financial contract trading activities.


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Coal Inventory Revaluation. As a part of the fresh start reporting adjustments, the book value of coal inventories was increased to reflect the estimated fair value, less costs to sell the inventories. During the Successor period April 2 through September 30, 2017, this adjustment was fully amortized as the inventory was sold. For additional details, refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” to the accompanying unaudited condensed consolidated financial statements.
Take-or-Pay Contract-Based Intangible Recognition. Included in the fresh start reporting adjustments were contract-based intangible liabilities for port and rail take-or-pay contracts. During the Successor three months ended September 30, 2017 and the period April 2 through September 30, 2017, the Company has ratably recognized these contract-based intangible liabilities. For additional details, refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” to the accompanying unaudited condensed consolidated financial statements.
Reorganization Items, Net. The reorganization items recorded during the Predecessor period January 1 through April 1, 2017 reflected the impact of the Plan provisions and the application of fresh start reporting. Expense recorded during the three and nine months ended September 30, 2016 related to expenses recorded in connection with our Chapter 11 Cases. Refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” to the accompanying unaudited condensed consolidated financial statements for further information regarding our reorganization items.
Income (Loss) from Continuing Operations, Net of Income Taxes
The following tables present income (loss) from continuing operations, net of income taxes:
 
2017
 
 
2016
 
2017
 
2016
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
 
Predecessor
 
Three Months Ended September 30
 
April 2 through September 30
 
 
January 1 through April 1
 
Nine Months Ended
September 30
 
 
 
 
 
 
(Dollars in millions)
Income (loss) from continuing operations before income taxes
$
149.6

 
 
$
(108.5
)
 
$
255.7

 
 
$
(459.3
)
 
$
(596.8
)
Income tax benefit
(84.1
)
 
 
(10.8
)
 
(79.4
)
 
 
(263.8
)
 
(108.2
)
Income (loss) from continuing operations, net of income taxes
$
233.7

 
 
$
(97.7
)
 
$
335.1

 
 
$
(195.5
)
 
$
(488.6
)
Income Tax Benefit. The income tax benefit recorded for the Successor periods presented primarily related to expected refunds for U.S. net operating loss carrybacks.
The income tax benefit recorded for the Predecessor period January 1 through April 1, 2017, was primarily comprised of benefits related to Predecessor deferred tax liabilities ($177.8 million), accumulated other comprehensive income ($81.5 million) and unrecognized tax benefits ($6.7 million). Refer to Note 12. “Income Taxes” in the accompanying unaudited condensed consolidated financial statements for additional information.


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Net Income (Loss) Attributable to Common Stockholders
The following tables present net loss attributable to common stockholders:
 
2017
 
 
2016
 
2017
 
2016
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
 
Predecessor
 
Three Months Ended September 30
 
April 2 through September 30
 
 
January 1 through April 1
 
Nine Months Ended
September 30
 
 
 
 
 
 
(Dollars in millions)
Income (loss) from continuing operations, net of income taxes
$
233.7

 
 
$
(97.7
)
 
$
335.1

 
 
$
(195.5
)
 
$
(488.6
)
Loss from discontinued operations, net of income taxes
(3.7
)
 
 
(38.1
)
 
(6.4
)
 
 
(16.2
)
 
(44.5
)
Net income (loss)
230.0

 
 
(135.8
)
 
328.7

 
 
(211.7
)
 
(533.1
)
Less: Series A Convertible Preferred Stock dividends
23.5

 
 
—

 
138.6

 
 
—

 
—

Less: Net income attributable to noncontrolling interests
5.1

 
 
1.8

 
8.9

 
 
4.8

 
3.5

Net income (loss) attributable to common stockholders
$
201.4

 
 
$
(137.6
)
 
$
181.2

 
 
$
(216.5
)
 
$
(536.6
)
Loss from Discontinued Operations, Net of Income Taxes. The loss from discontinued operations for the Predecessor three and nine months ended September 30, 2016 was primarily comprised of a charge of $35.0 million for the UMWA 1974 Pension Plan. For additional details, refer to Note 5. “Discontinued Operations” to the accompanying unaudited condensed consolidated financial statements.
Series A Convertible Preferred Stock Dividends. The Series A Convertible Preferred Stock dividends for the Successor three months ended September 30, 2017 and the period April 2 through September 30, 2017 were comprised of the deemed dividends (three months, $23.5 million; nine months, $135.5 million) granted for the Preferred Stock shares that were converted during the respective periods and the first semi-annual payment of preferred dividends (nine months, $3.1 million) which was pro-rated for the period of April 3 through April 30, 2017.
Diluted EPS
The following table presents diluted EPS:
 
2017
 
 
2016
 
2017
 
2016
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
 
Predecessor
 
Three Months Ended September 30
 
April 2 through September 30
 
 
January 1 through April 1
 
Nine Months Ended
September 30
 
 
 
 
 
Diluted EPS attributable to common stockholders:
 
 
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
1.49

 
 
$
(5.44
)
 
$
1.37

 
 
$
(10.93
)
 
$
(26.91
)
Loss from discontinued operations
(0.02
)
 
 
(2.09
)
 
(0.05
)
 
 
(0.88
)
 
(2.43
)
Net income (loss)
$
1.47

 
 
$
(7.53
)
 
$
1.32

 
 
$
(11.81
)
 
$
(29.34
)
Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS for the Successor Company reflects weighted average diluted common shares outstanding of 103.1 million for the three months ended September 30, 2017 and 100.2 million for the period April 2 through September 30, 2017. Diluted EPS for the Predecessor periods January 1 through April 1, 2017 and the three and nine months ended September 30, 2016 reflect weighted average diluted common shares outstanding of 18.3 million, respectively.


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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 gross domestic product, industrial production, fixed asset investment and third-party inputs, driving detailed supply and demand projections. This includes demand for coal, electricity 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 as described more fully in the “Cautionary Notice Regarding Forward-Looking Statements” section contained within this Item 2.
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 decreased 2% in the nine months ended September 30, 2017 compared to the prior year as a result of mild weather. Even as overall electricity demand weakened year-over-year through September, utility consumption of Powder River Basin coal rose approximately 8% with natural gas consumption decreasing 12% compared to the prior year period (on 30% higher average natural gas prices year-over-year through September).
Cooling degree days in June, July and August 2017 were down approximately 16% from the prior year in coal-heavy regions. As a result, Peabody now expects U.S. coal consumption from electricity generation to be largely flat for full-year 2017 compared to 2016 levels.
Seaborne Thermal Coal. Seaborne thermal coal demand and pricing continue to be supported by robust Asian demand primarily in China and South Korea. Chinese thermal coal imports are up approximately 15 million tonnes year-to-date through September compared to the prior year period on strong electricity generation that exceeded domestic production growth. In addition, South Korean imports have strengthened approximately 15 million tonnes through September, a 23% increase year-over-year, as nuclear generation has been curtailed. While import demand from India has been sluggish on increased domestic coal usage, stockpiles are currently at multi-year lows, which is supportive of additional imports in the fourth quarter. For full-year 2017, Peabody now projects seaborne thermal coal demand to increase approximately 10 to 15 million tonnes from 2016 levels.
Seaborne Metallurgical Coal. With respect to seaborne metallurgical coal, global steel production has risen approximately 5% during the nine months ended September 30, 2017 as compared to the prior year period, led by record Chinese steel production. In addition, Chinese steel exports are down 30% year-to-date through September. Through the nine months ended September 30, 2017 metallurgical coal imports in China rose 9 million tonnes as compared to the prior year period on strong demand and curtailed domestic production on geologic issues. For full-year 2017, Peabody now expects global seaborne metallurgical coal demand to increase approximately 10 million tonnes from 2016 levels.
Seaborne metallurgical coal prompt prices averaged $189 per tonne in the third quarter of 2017, up over $50 per tonne from the prior year, with the index-based settlement price for hard coking coal set at approximately $170 per tonne. In addition, Peabody set third quarter low-vol PCI pricing at $115 per tonne with an additional settlement later in the quarter of $127.50 per tonne. The Company also negotiated a fourth quarter low-vol PCI settlement of $127.50 per tonne.
Long-Term Outlook
There were no significant changes to our Long-term Outlook subsequent to December 31, 2016. Information regarding our Long-term Outlook is outlined in Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.
Regulatory Update
Other than as described in the following section, there were no significant changes to our regulatory matters subsequent to December 31, 2016. Information regarding our regulatory matters is outlined in Part I, Item 1. “Business” in our Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.


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Regulatory Matters - U.S.
Grid Resiliency Pricing Rule. On October 10, 2017, the Secretary of Energy (the Secretary) published a Notice of Proposed Rulemaking entitled the Grid Resiliency Pricing Rule (the Proposed Rule). The Proposed Rule was issued by the Secretary pursuant to section 403 of the Department of Energy Organization Act. 42 U.S.C. § 7173. In the Proposed Rule, the Secretary instructed the Federal Energy Regulatory Commission (FERC) to impose rules to ensure that reliability and resiliency attributes of certain electric generation units with a 90-day on-site fuel supply are fully compensated for the benefits and services they provide to grid operations. The Secretary directed FERC to take final action on the Proposed Rule within 60 days of publication or, in the alternative, to issue the rule as an interim final rule immediately, with provision for later modifications after consideration of public comments. The Proposed Rule cites the retirements of coal and nuclear plants as a potential threat to grid reliability and resilience, and provides for the creation of a “reliability and resiliency rate” that would compensate certain eligible resources for the benefits and services they provide to grid operations, allowing such eligible resources to recover their fully allocated costs and a fair return on equity. The “reliability and resiliency rate” would be available to eligible resources operating within FERC-approved independent system operators or regional transmission organizations with energy and capacity markets. The rate would apply only to generators that are not currently subject to cost-of-service regulation by a state or other authority.
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 and may result in additional capital and operating costs.
Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to national ambient air quality standards (NAAQS) for particulate matter (PM), sulfur dioxide and ozone. It is possible that modifications to current NAAQS could 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/engine emission standards for vehicles/equipment utilized in our operations, or through the adoption of additional local control measures that could be required 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 2015, the EPA promulgated a more stringent NAAQS for ozone (80 Fed. Reg. 65,292, (Oct. 25, 2015)). This NAAQS for ozone rule was challenged in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit). Although the rule is not stayed during litigation, on April 7, 2017, the Department of Justice, on behalf of the EPA, filed a motion asking that the case be removed from the argument calendar so that the EPA can consider whether it “should reconsider the rule or some part of it.” On April 14, 2017, the D.C. Circuit granted the EPA’s motion and stayed the litigation indefinitely with regular 90 day status reports due to the court. More stringent ozone standards require that states develop and submit new state implementation plans to the EPA. Depending on the need for further emission reductions necessary to meet the standard, such plans could include additional control technology requirements for mining equipment or result in additional permitting requirements affecting operations 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 (78 Fed. Reg. 3,085 (Jan. 15, 2013). 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. Regulations regarding reporting requirements for underground coal mines were updated in 2016 and now include the ability to cease reporting if mines are abandoned and sealed.
The CAA also indirectly, but significantly affects the U.S. coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other substances emitted by coal-fueled electricity generating plants. Other CAA programs may require further emission reductions and may affect our operations, directly or indirectly. These 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.
NSPS for Fossil Fuel-Fired Electricity Utility Generating Units (EGUs). On April 13, 2012, pursuant to section 111(b) of the CAA, the EPA published for comment in the Federal Register a proposed NSPS for emissions of carbon dioxide for new, modified and reconstructed fossil fuel-fired EGUs (proposed NSPS). On January 8, 2014, however, the EPA withdrew the proposed NSPS and issued a new proposed NSPS for the same sources. The EPA then issued a Notice of Data Availability (NODA) and technical support document in support of the proposed NSPS on February 26, 2014. 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 the rule was published in the Federal Register on October 23, 2015 (80 Fed. Reg. 64,510).


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The final NSPS requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb. carbon dioxide per megawatt-hour gross output (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).
Sixteen separate petitions for review of the NSPS were filed in the D.C. Circuit, and the challengers included 25 states, utilities, mining companies (including Peabody Energy), labor unions, trade organizations and other groups. The cases were consolidated under a petition filed by North Dakota. States and other organizations intervened in the litigation on behalf of the Respondent EPA.
Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions that were submitted to the EPA regarding the final rule. This denial was published as a final action in the May 6, 2016 Federal Register (81 Fed. Reg. 27,442). States and other organizations also intervened on behalf of the EPA. Upon petitioners’ request, the D.C. Circuit suspended the briefing schedule in this case 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 were scheduled for April 17, 2017.
On March 28, 2017, however, the EPA moved to hold the case in abeyance pending its reconsideration of the NSPS pursuant to the terms of President Trump’s Executive Order on Promoting Energy Independence and Economic Growth (EI Order), which was signed the same day. On April 28, 2017, the court granted the motion to hold the case in abeyance for 60 days and required the EPA to file regular status reports. The court also ordered that parties file supplemental briefs on whether the cases should be remanded to the EPA, rather than held in abeyance. The EPA filed a supplemental brief on May 15, 2017 and, at the present time, the case remains in abeyance and the NSPS remains in effect.
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 established emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs. These guidelines require that the states individually or collectively create systems that would reduce carbon emissions from steam electric and natural gas-fired power plants 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 would have until September 6, 2018 to submit those plans. The rule also set emission performance rates for affected sources to be phased in over the period from 2022 through 2030. State plans were required to impose these rates on existing plants or implement other measures (such as emission caps, increased use of renewable energy or energy efficiency measures) that would yield the same result. Overall, the rule was intended to reduce carbon dioxide emissions from steam electric and natural gas-fired power plants by 28% in 2025 and 32% in 2030 compared with 2005 baseline emission rates.  
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 reflected challenges by 27 states and governmental entities, as well as challenges by utilities, industry groups, trade associations, coal companies, and other entities. The lawsuits were consolidated with the case filed by West Virginia and Texas (which other States 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 were also allowed to intervene in support of the EPA.


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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. Oral arguments in the case were heard en banc by ten active D.C. Circuit judges on September 27, 2016 but, to date, the D.C. Court has not yet issued an opinion.
On March 28, 2017, the EPA moved to hold the case in abeyance pending its reconsideration of the final rule pursuant to the EI Order. On April 4, 2017 the EPA published a Federal Register notice announcing that the Agency would review the rule and that it may act to suspend, revise or rescind the rule (82 Fed. Reg. 16,329).
The EI Order included a directive to reexamine the CAA 111(d) rule and, if appropriate, suspend, revise or rescind the rule. On April 28, 2017, the court granted the motion to hold the case in abeyance for 60 days and required the EPA to file regular status reports; the court also ordered that parties file supplemental briefs on whether the cases should be remanded to the EPA, rather than held in abeyance. The EPA filed a supplemental brief on May 15, 2017 and, at the present time, the case remains in abeyance. On October 10, 2017, the EPA reported to the D.C. Circuit Court of Appeals that it signed a Federal Register notice proposing to repeal the Clean Power Plan. The EPA further reported that it is considering the scope of any potential replacement rule.
Federal Coal Leasing Moratorium. The EI Order also lifted the Department of Interior’s federal coal leasing moratorium and rescinded guidance on the inclusion of social cost of carbon in federal rulemaking. Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium.
Stream Protection Rule. On December 20, 2016, the Office of Surface Mining Reclamation and Enforcement (OSM) issued its final Stream Protection Rule (SPR). The final 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 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 OSM from promulgating any substantially similar rule. As a result of this repeal, longstanding regulations implementing requirements under the Surface Mining Control and Reclamation Act will continue to govern operations.
Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.
The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain Corps permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.
States are empowered to develop and apply “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the CWA section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.


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A 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. 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 requested that both the Supreme Court and the Sixth Circuit stay all litigation proceedings. The Supreme Court denied that stay request and merits briefing is complete, and oral arguments were held on October 11, 2017. The Sixth Circuit, however, granted the stay request and litigation in that Court is 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 is expected to take until late 2017 or early 2018. If CWA authority is eventually expanded, it may impact our operations in some areas by way of additional requirements. On July 27, 2017, the EPA and the Corps published their proposed rule to rescind the 2015 WOTUS Rule and re-codify the prior definition of “waters of the U.S.” The agencies took public comment on that proposal through September 27, 2017 and could issue a final rule in late 2017 or early 2018.
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 PM 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 in the Federal Register a proposed supplemental finding 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.
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. On April 27, 2017, the D.C. Circuit issued an order which removed the previously scheduled oral argument from the court’s calendar and held the consolidated cases challenging the supplemental finding in abeyance. The order further directed the EPA to file status reports on the agency’s review of the supplemental finding every 90 days. The EPA’s most recent status report indicates that the EPA is continuing to review the Supplemental Finding “to determine whether the rule should be maintained, modified or otherwise reconsidered” (D.C. Cir. No. 16-1127; July 26, 2017).
Regulatory Matters - Australia
Occupational Health and Safety. State legislation requires us to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision. In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry. There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation.


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A small number of coal mine workers in Queensland and New South Wales have been diagnosed with coal workers’ pneumoconiosis (CWP, also known as black lung) following decades of assumed eradication of the disease. This has led the Queensland government to sponsor a review of the system for 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 held a Parliamentary inquiry into the re-emergence of CWP in the State which included public hearings with appearances by representatives of the coal mining industry, including Peabody, coal mine workers, the Department of Natural Resources and others. The Queensland Parliamentary Committee conducting the inquiry issued an interim report on March 22, 2017 and its final report on May 29, 2017. In finding that it is highly unlikely CWP was ever eradicated in Queensland, the Committee has made 68 recommendations to ensure the safety and health of mine workers. These include an immediate reduction to the occupational exposure limit for respirable coal dust equivalent to 1.5mg/m3 for coal dust and 0.05mg/m3 for silica and the establishment of a new and independent Mine Safety Authority to be funded by a dedicated proportion of coal and mineral royalties and overseeing the Mines Safety Inspectorate.
On August 23, 2017, the Queensland Parliament passed the Workers' Compensation and Rehabilitation (Coal Workers' Pneumoconiosis) and Other Legislation Amendment Act 2017, which amends the Workers' Compensation and Rehabilitation Act 2003 by:
•establishing a medical examination process for retired or former coal workers with suspected CWP;
•introducing an additional lump sum compensation for workers with CWP; and
•
clarifying that a worker with CWP can access further workers’ compensation entitlements if they experience disease progression.
On August 24, 2017, the Queensland Parliamentary Committee released a report containing a draft of the Mine Safety and Health Authority Bill 2017, which proposes to establish the Mine Safety Authority foreshadowed in the Committee’s recommendations released in May 2017. The draft bill has been referred to the relevant Parliamentary Portfolio Committee for review.
On September 7, 2017, the Queensland Parliament introduced proposed amendments to legislation which, if passed, will increase civil penalties for mining companies breaching their obligations under the Coal Mining Safety and Health Act 1999. The proposed amendments would also give the Chief Executive of the Department of Natural Resources and Mining new powers to suspend or cancel an individual’s statutory certificate of competency and issue site senior executives (SSEs) notices if they fail to meet their safety and health obligations. Higher levels of competency for the statutory position of ventilation officer at underground mines will also be required if the legislation is passed.
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 which 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 the extent of disturbance during the PO period.
In May 2017, the Queensland government announced broad policy reform proposals in relation to financial assurance (FA) and rehabilitation for the mining and petroleum sector. The proposed regime represents a new approach to managing Queensland’s existing rehabilitation risk management.  


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On October 25, 2017, the Queensland Parliament introduced the Mineral and Energy Resources (Financial Provisioning) Bill 2017 (MERFP Bill), which contained proposed legislation to give effect to some of the policy reforms, including:
•
a remodeled FA framework that takes into account the financial strength of the EA holder and the risk level of the mine;
•a state-wide pooled FA fund covering most mines and most of the total industry liability;
•discontinuation of prior discounting of FA requirements;
•
other options for providing FA for those mines that are not part of the pooled FA fund (for example, allowing insurance bonds or cash);
•updated rehabilitation calculations; and
•regular monitoring and reporting measures for progressive mine rehabilitation.
However, the MERFP Bill lapsed on October 29, 2017 when a Queensland state election was called. The nature of the FA and rehabilitation policy reforms, and the timing for the reintroduction into Parliament of the MERFP Bill or other proposed legislation for implementing those reforms, is dependent on the outcome of the election.
Federal Reclamation. In February 2017, the Australian Senate established a Committee of Inquiry into the rehabilitation of mining and resources projects as it relates to Commonwealth responsibilities, for example, under the Environment Protection and Biodiversity Conservation Act 1999. The Committee is holding public hearings and is currently due to report in during the second quarter of 2018.
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, post-mining retirement obligations, and selling and administrative expenses. Historically, we have also generated cash from borrowings under our credit facilities and, from time to time, the issuance of securities. We believe that our reorganized capital structure subsequent to the Effective Date will allow us to satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations and cash on hand.
Any future determinations to return capital to stockholders, such as dividends or share repurchases, will be at the discretion of our Board of Directors and will depend on a variety of factors, including the restrictions set forth under our Successor Notes and Successor Credit Agreement, our net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. Our ability to declare dividends or repurchase shares in the future will depend on our future financial performance, which in turn depends on the successful implementation of our strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to our industry, many of which are beyond our control. See also, Debt Reduction and Shareholder Return Initiatives, below.


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Total Indebtedness. Our total indebtedness as of September 30, 2017 and December 31, 2016 consisted of the following:
 
Successor
Predecessor
 
September 30, 2017
December 31, 2016
 
(Dollars in millions)
6.00% Senior Secured Notes due March 2022
$
500.0

$
—

6.375% Senior Secured Notes due March 2025
500.0

—

Senior Secured Term Loan due 2022
645.0

—

2013 Revolver
—

1,558.1

2013 Term Loan Facility due September 2020
—

1,162.3

6.00% Senior Notes due November 2018
—

1,518.8

6.50% Senior Notes due September 2020
—

650.0

6.25% Senior Notes due November 2021
—

1,339.6

10.00% Senior Secured Second Lien Notes due March 2022
—

979.4

7.875% Senior Notes due November 2026
—

247.8

Convertible Junior Subordinated Debentures due December 2066
—

386.1

Capital lease and other obligations
84.0

20.1

Less: Debt issuance costs
(69.9
)
(70.8
)
 
1,659.1

7,791.4

Less: Current portion of long-term debt
47.1

20.2

Less: Liabilities subject to compromise
—

7,771.2

Long-term debt
$
1,612.0

$
—

Refer to Note 1. “Basis of Presentation” and Note 13. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements for further information regarding our indebtedness, including our capital structure subsequent to the Effective Date.
Liquidity
As of September 30, 2017, our available liquidity was $942.7 million which was comprised of cash and cash equivalents and availability under our receivables securitization program described below. As of September 30, 2017, our cash balances totaled $925.0 million, including approximately $708.0 million held by U.S. entities, with the remaining balance held by foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by our foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia and the foreign operations of our Trading and Brokerage segment. We do not expect restrictions or potential taxes on the repatriation of amounts held by our foreign subsidiaries to have a material effect on our overall liquidity, financial condition or results of operations.
Subsequent to our emergence from the Chapter 11 Cases our liquidity primarily consists of cash and cash equivalents and the available balances from our accounts receivable securitization program. Our ability to maintain adequate liquidity depends on the successful operation of our business and appropriate management of operating expenses and capital spending. Our anticipated liquidity needs are highly sensitive to changes in each of these and other factors.
The Successor Notes and Successor Credit Agreement
As described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” and Note 13. “Long-term Debt” of the accompanying unaudited condensed consolidated financial statements, on the Effective Date, the proceeds from the 6.00% Senior Secured Notes due March 2022 and the 6.375% Senior Secured Notes due March 2025 (collectively, the Successor Notes) and the Senior Secured Term Loan under the Successor Credit Agreement were used to repay the predecessor first lien obligations. The proceeds from the Successor Notes and the Senior Secured Term Loan, net of debt issuance costs and an original issue discount, as applicable, were $950.5 million and $912.7 million, respectively.


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We voluntarily prepaid $300.0 million of the original $950.0 million loan principal on the Senior Secured Term Loan in $150.0 million installments on July 31, 2017 and September 11, 2017. On September 18, 2017, we entered into an amendment to the Successor Credit Agreement which lowered the interest rate from LIBOR plus 4.50% per annum with a 1.00% LIBOR floor to LIBOR plus 3.50% per annum with a 1.00% LIBOR floor. The amendment permits us to add an incremental revolving credit facility in addition to our ability to add one or more incremental term loan facilities under the Successor Credit Agreement. The incremental revolving credit facility and/or incremental term loan facilities, which remain unutilized, can be in an aggregate principal amount of up to $300.0 million plus additional amounts so long as the Company maintains compliance with the Total Leverage Ratio, as defined in the agreement.The amendment also made available an additional restricted payment basket that permits additional repurchases, dividends or other distributions with respect to our Common and Preferred Stock in an aggregate amount up to $450.0 million so long as our Fixed Charge Coverage Ratio, as defined in the agreement, would not exceed 2.00:1.00 on a pro forma basis.
Interest payments on the Successor Notes are scheduled to occur each year on March 31 and September 30 until maturity. We may redeem the 6.00% Senior Secured Notes beginning in 2019 and the 6.375% Senior Secured Notes beginning in 2020, in whole or in part, and subject to periodically decreasing redemption premiums, through maturity.
The Senior Secured Term Loan principal is payable in quarterly installments plus accrued interest through December 2021 with the remaining balance due in March 2022. The loan principal is voluntarily prepayable at 101% of the principal amount repaid if voluntarily prepaid prior to March 18, 2018 (subject to certain exceptions, including prepayments made with internally generated cash) and is voluntarily prepayable at any time thereafter without premium or penalty. The Senior Secured Term Loan may require mandatory principal prepayments of 75% of Excess Cash Flow (as defined in the Successor Credit Agreement) for any fiscal year (commencing with the fiscal year ending December 31, 2018). The mandatory principal prepayment requirement changes to (i) 50% of Excess Cash Flow if our Total Leverage Ratio (as defined in the Successor Credit Agreement and calculated as of December 31) is less than or equal to 2.00:1.00 and greater than 1.50:1.00, (ii) 25% of Excess Cash Flow if our Total Leverage Ratio is less than or equal to 1.50:1.00 and greater than 1.00:1.00, or (iii) zero if the our Total Leverage Ratio is less than or equal to 1.00:1.00. If required, mandatory prepayments resulting from Excess Cash Flows are payable within 100 days after the end of each fiscal year. In certain circumstances, the Senior Secured Term Loan also requires that Excess Proceeds (as defined in the Successor Credit Agreement) of $10 million or greater from sales of our assets be applied against the loan principal, unless such proceeds are reinvested within one year.
Under the Successor Credit Agreement, our annual capital expenditures are limited to $220.0 million, $220.0 million, $250.0 million, $250.0 million, and $300.0 million from 2017 through 2021, respectively, subject to certain adjustments.
In addition to the $450.0 million restricted payment basket provided for under the amendment, the Successor Credit Agreement and Successor Notes allow for $50 million of otherwise restricted payments. Additive to this general limit are certain “builder basket” provisions that may increase the amount of allowable restricted payments, as calculated periodically based upon our operating performance. Beginning on January 1, 2018, the payment of dividends and purchases of our own common stock are permitted under additional provisions of the Successor Notes and the Successor Credit Agreement in an aggregate amount in any calendar year not to exceed $25 million, so long as our Total Leverage Ratio would not exceed 1.25:1.00 on a pro forma basis.
Accounts Receivable Securitization
As described in Note 18. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, on the Effective Date, we entered into an amended Receivables Purchase Agreement to extend the receivables securitization facility previously in place and expand that facility to include certain receivables from the Company’s Australian operations. The term of the receivables securitization program (Securitization Program) ends on April 3, 2020, subject to certain liquidity requirements and other customary events of default set forth in the Receivables Purchase Agreement. The Securitization Program provides for up to $250 million in funding accounted for as a secured borrowing, limited to the availability of eligible receivables, and may be secured by a combination of cash collateral and the trade receivables underlying the program, from time to time. Funding capacity under the Securitization Program may also be drawn upon for letters of credit in support of other obligations. On June 30, 2017, we entered into an amendment to the Securitization Program to include the receivables of additional Australian operations and reduce the associated fees payable.
At September 30, 2017, we had no outstanding borrowings and $179.5 million of letters of credit drawn under the Securitization Program. The letters of credit were primarily in support of portions of our obligations for reclamation, workers’ compensation and postretirement benefits. There was no cash collateral requirement under the Securitization Program at September 30, 2017.


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Reclamation Bonding
As described in Note 18. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, we are required to provide various forms of financial assurance in support of our mining reclamation obligations in the jurisdictions in which we operate. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees, and letters of credit, as well as self-bonding arrangements in the U.S. In connection with our emergence from the Chapter 11 Cases, we shifted away from extensive self-bonding in the U.S. in favor of increased usage of surety bonds and similar third-party instruments, but have retained the ability to utilize self-bonding in the future, dependent upon state-by-state approval and internal cost-benefit considerations. This divergence in practice may impact our liquidity in the future due to increased cash collateral requirements and surety and related fees.
At September 30, 2017, we had total asset retirement obligations of $636.0 million which were backed by a combination of surety bonds, bank guarantees, letters of credit and restricted cash collateral. Cash collateral balances related to reclamation and other obligations are maintained on our balance sheets within “Investments and other assets,” but are excluded from our available liquidity. Such cash collateral amounted to $530.3 million at September 30, 2017, of which $160.1 million was held in the U.S. and $370.2 million in Australia.
Bonding requirement amounts may differ significantly from the related asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas our accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date.
Capital Requirements
There were no material changes to our capital requirements from the information provided in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.
Contractual Obligations
The consummation of the Plan and related reorganization activities resulted in significant changes to our future contractual obligations with respect to our long-term debt and capital and operating lease obligations which were disclosed in Item 2 of our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017. Our future contractual obligations with respect to our long-term debt have further changed as a result of the principal repayments on our Senior Secured Term Loan and the amendment to our Successor Credit Facility as more fully described in Note 13. “Long-term Debt” to the accompanying unaudited financial statements. Our resulting future long-term debt obligations for periods subsequent to September 30, 2017 are set forth in the table below. The related interest on long-term obligations was calculated using rates in effect at September 30, 2017 for the remaining contractual term of the outstanding borrowings. There were no other material changes to our contractual obligations from the information previously provided in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017, and Item 2 of our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017.
 
Payments Due By Period
 
Total
 
Three Months Ending December 31, 2017
 
2018-2019
 
2020-2021
 
2022-2023
 
Subsequent to 2023
 
(Dollars in millions)
Long-term debt obligations (principal and interest)
$
2,176.4

 
$
25.1

 
$
204.5

 
$
208.3

 
$
1,198.7

 
$
539.8




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Debt Reduction and Shareholder Return Initiatives
In the second quarter of 2017, we outlined our debt reduction and shareholder return initiatives. The details of these initiatives are as follows:
•
Liquidity Targets. Peabody is targeting liquidity of approximately $800 million. This target takes into account variability of pricing and cash flows and the ability to sustain cyclical downdrafts.
•
Debt Targets. Peabody is targeting gross debt of $1.2 billion to $1.4 billion over time to enhance the sustainability of its capital structure across all cycles.  Peabody is targeting $500 million of debt reduction by December 2018 and made $300 million in voluntary payments of its term loan under the Successor Credit Agreement during the three months ended September 30, 2017.
•
Return of Capital to Shareholders. Peabody’s board of directors authorized a $500 million share repurchase program. Repurchases may be made from time to time at our discretion. The specific timing, price and size of purchases will depend on the share price, general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time. No expiration date has been set for the repurchase program, and the program may be suspended or discontinued at any time. During the three months ended September 30, 2017, we repurchased approximately 1.5 million shares of our Common Stock for $40.0 million in connection with an underwritten secondary offering and made additional open-market purchases of approximately 1.0 million shares of our Common Stock for $29.2 million. Subsequent to September 30, 2017 and through October 30, 2017, we have purchased an additional 1.3 million shares of our Common Stock for $37.7 million. The purchases were made in compliance with our debt provisions that limit our ability to repurchase shares following the Plan Effective Date.
•
Dividends. Peabody’s board of directors will regularly evaluate a sustainable dividend program, targeting commencement in the first quarter of 2018. The timing and amount of dividends under such a program will depend on general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time.
Historical Cash Flows
The following table summarizes our cash flows for the period April 2 through September 30, 2017, January 1 through April 1, 2017, and the three and nine months ended September 30, 2016, as reported in the accompanying unaudited condensed consolidated financial statements:
 
Successor
Predecessor
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2016
 
 
 
(Dollars in millions)
Net cash provided by (used in) operating activities
330.3

214.0

 
(276.8
)
Net cash (used in) provided by investing activities
(34.9
)
15.1

 
(199.7
)
Net cash (used in) provided by financing activities
(424.1
)
(47.7
)
 
1,383.0

Net change in cash and cash equivalents
(128.7
)
181.4

 
906.5

Cash and cash equivalents at beginning of period
1,053.7

872.3

 
261.3

Cash and cash equivalents at end of period
$
925.0

$
1,053.7

 
$
1,167.8

Cash Flow - Successor
Cash provided by operating activities in the Successor period April 2, 2017 through September 30, 2017 resulted from improved supply and demand conditions leading to increased cash from our mining operations. In addition, $99.4 million of restricted cash collateral became unrestricted. These factors were partially offset by the greater use of working capital related to coal stockpile increases and the payment of claims and professional fees related to the Chapter 11 Cases.
Cash used in investing activities in the Successor period April 2, 2017 through September 30, 2017 resulted from additions to property, plant, equipment and mine development, which was partially offset by repayments of loans from related parties.
Cash used in financing activities in the Successor period April 2, 2017 through September 30, 2017 resulted primarily from $300.0 million of repayments on the Senior Secured Term Loan and $69.2 million of repurchases of Common Stock in accordance with our debt reduction and shareholder return initiatives.


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Cash Flow - Predecessor
Cash provided by operating activities in the Predecessor period January 1, 2017 through April 1, 2017 resulted from year-over-year increase in cash from our operations from improved supply and demand conditions.
Cash used in operating activities during the nine months ended September 30, 2016 resulted from unfavorable supply and demand conditions leading to decreased cash from our mining operations, greater use of working capital, and cash restrictions brought about by increased collateral demands on various obligations.
Cash provided by investing activities in the Predecessor period January 1, 2017 through April 1, 2017 resulted from repayments of loans from related parties and proceeds from disposals of assets driven by the sale of Dominion Terminal Associates, which was offset by payments for additions to property, plant and equipment.
Cash used in investing activities during the nine months ended September 30, 2016 resulted primarily from federal coal lease and other capital expenditures of approximately $305 million, partially offset by proceeds from the disposal of our 5.06% participation interest in the Prairie State Energy Campus, as well as our disposal of interests in undeveloped metallurgical reserve tenements in Queensland’s Bowen Basin, which included the Olive Downs South, Olive Downs South Extended and Willunga tenements.
Cash used in financing activities in the Predecessor period January 1, 2017 through April 1, 2017 resulted from payments of Predecessor deferred financing costs associated with the new Successor debt entered into upon our emergence from the Chapter 11 Cases.
Cash provided by financing activities during the nine months ended September 30, 2016 resulted from proceeds from long-term debt, primarily due to the proceeds received from our Predecessor interim financing facility during the second quarter of 2016 and the net draws on our 2013 Predecessor Revolver during the first quarter of 2016.
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 unaudited condensed consolidated balance sheets. 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 18. “Financial Instruments and Other Guarantees” to our unaudited condensed consolidated financial statements for a discussion of our accounts receivable securitization program and guarantees and other financial instruments with off-balance sheet risk.
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.
Our critical accounting policies are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017. Our critical accounting policies remain unchanged at September 30, 2017, with the exception of the accounting policy elections described in the following paragraph that we made in connection with fresh start reporting. These elections impact the Successor period presented in the accompanying condensed consolidated financial statements and will impact prospective periods.
We will classify the amortization associated with our asset retirement obligation assets within “Depreciation, depletion and amortization” in our consolidated statements of operations, rather than within “Asset retirement obligation expenses”, as in Predecessor periods. With respect to our accrued postretirement benefit and pension obligations, we will prospectively record amounts attributable to prior service cost and actuarial valuation changes, as applicable, currently in earnings rather than recording such amounts within accumulated other comprehensive income and amortizing to expense over applicable time periods.


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Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
See Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” to our unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
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 7. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. Subsequent to the Effective Date, we entered into a series of currency options and, as of September 30, 2017, had currency options outstanding with an aggregate notional amount of approximately $450 million and $675 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the remainder of 2017 and the first half of 2018, respectively. Assuming we had no foreign currency hedging instruments in place, our exposure in operating costs and expenses due to a $0.05 change in the Australian dollar/U.S. dollar exchange rate is approximately $95 to $105 million for the next twelve months. Taking into consideration the currency option contracts put into place subsequent to the Effective Date, our net exposure to unfavorable rate changes for the next twelve months is approximately $70 to $80 million.
Other Non-Coal Trading Activities — Diesel Fuel Price Risk
Diesel Fuel and Explosives Hedges. We have historically managed price risk of the diesel fuel and explosives used in our mining activities through the use of cost pass-through contracts and from time to time, derivatives, primarily swaps. As of September 30, 2017, we no longer have any diesel fuel derivative instruments in place.
We expect to consume 125 to 135 million gallons of diesel fuel during the next twelve months. 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 $31 million based on our expected usage.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) of the Securities Exchange Act of 1934, as amended) as of September 30, 2017. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were not effective as of September 30, 2017 because of the material weaknesses in our internal control over financial reporting described below.
All systems of internal control, no matter how well designed, have inherent limitations. Therefore, even those systems deemed to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim consolidated financial statements will not be prevented or detected on a timely basis.
Evaluation of the Internal Control over Financial Reporting
Management determined that the internal control around the reconciliation of tax basis balance sheets to deferred tax balances was not designed effectively and did not operate at a sufficient level of precision to prevent or detect a material misstatement on a timely basis.  Specifically, an immaterial misstatement related to deferred tax liabilities of a single taxpayer outside of the consolidated Australian tax paying group was identified, which resulted in the understatement of the income tax valuation allowance required to reduce the carrying value of its deferred tax assets. The Company has subsequently revised its financial statements and related disclosures to correct these errors.
This control deficiency created a reasonable possibility that a material misstatement to the annual consolidated financial statements would not be prevented or detected on a timely basis. Accordingly, management concluded that this control deficiency represents a material weakness.


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Management’s Plans for Remediation
Management has been engaged and will continue to advance remedial activities to address the material weakness described above. We believe the risk of a material weakness in subsequent periods will be mitigated by the implementation of an improved general ledger structure and a comprehensive analysis of all deferred tax positions. Additionally we have revised and enhanced the design of existing controls and procedures to properly apply accounting principles in this area, which includes strengthening our income tax controls with improved documentation standards, training and technical oversight.
The material weakness will not be considered fully remediated until the applicable remedial controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. We expect that the remediation of this material weakness will be completed prior to the end of fiscal year 2017.
Changes in Internal Control Over Financial Reporting
Other than as discussed above, there have been no changes in internal control over financial reporting during the three months ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
We are subject to various legal and regulatory proceedings. For a description of our significant legal proceedings refer to Note 1. “Basis of Presentation,” Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting,” Note 5. “Discontinued Operations,” and Note 19. “Commitments and Contingencies” to the unaudited condensed consolidated financial statements included in Part I, Item 1. “Financial Statements” of this Quarterly Report, which information is incorporated by reference herein.
Item 1A. Risk Factors.
In the third quarter of 2017, there were no significant changes to our risk factors from those disclosed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on March 22, 2017, in Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on April 11, 2017 and in our Annual Report on Form 10-K/A (Amendment No. 1) for the year ended December 31, 2016 filed with the SEC on July 10, 2017. The Risk Factors described in such Forms 8-K and 10-K/A restate certain Risk Factors included in our Annual Report on Form 10-K and are incorporated by reference herein. In addition to the other information set forth in this Quarterly Report, including the information presented in Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” you should carefully consider those risk factors disclosed in the aforementioned filings, which could materially affect the Company’s results of operations, financial condition and liquidity.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Share Repurchase Programs
On August 1, 2017, we announced that our Board of Directors authorized a share repurchase program to allow repurchases of up to $500 million of the then outstanding shares of our common stock and/or preferred stock (Repurchase Program). Repurchases may be made from time to time at the Company’s discretion. The specific timing, price and size of purchases will depend on the share price, general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time. The Repurchase Program does not have an expiration date and may be discontinued at any time. During the three months ended September 30, 2017, we repurchased approximately 1.5 million shares of our Common Stock for $40.0 million in connection with an underwritten secondary offering and made additional open-market purchases of approximately 1.0 million shares of our Common Stock for $29.2 million. Subsequent to September 30, 2017 and through October 30, 2017, we have purchased an additional 1.3 million shares of our Common Stock for $37.7 million. The purchases were made in compliance with our debt provisions that limit our ability to repurchase shares following the Plan Effective Date. See “Risk Factors — The potential payment of dividends on our stock or repurchases of our stock is dependent on a number of factors, and future payments and repurchases cannot be assured” in Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on April 11, 2017.


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Share Relinquishments
We routinely allow employees to relinquish common stock to pay estimated taxes upon the vesting of equity awards and upon the issuance of common stock related to 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.
Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended September 30, 2017:
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)
July 1 through July 31, 2017
 
215

 
$
27.09

 
—

 
$
500.0

August 1 through August 31, 2017
 
1,476,086

 
27.10

 
1,476,014

 
460.0

September 1 through September 30, 2017
 
989,306

 
29.53

 
987,977

 
430.8

Total
 
2,465,607

 
$
28.08

 
2,463,991

 
 
(1) 
Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not part of the Repurchase Program.
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 with 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. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Quarterly Report on Form 10-Q.
Item 6. Exhibits.
See Exhibit Index at page 82 of this report.


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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
 
 
 
 
2.2
 
 
 
 
3.1
 
 
 
 
3.2
 
 
 
 
3.3
 
 
 
 
4.1
 
 
 
 
4.2
 
 
 
 
4.3
 
 
 
 
4.4
 
 
 
 
4.5
 
 
 
 
10.1
 
 
 
 
10.2
 
 
 
 
12.1*
 
Computation of Ratio of Earnings to Combined Fixed Charges and Preference Security Dividends for the five year period ended December 31, 2016 and the nine-month period ended September 30, 2017
 
 
 
31.1*
 
Certification of periodic financial report by the Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
31.2*
 
Certification of periodic financial report by the Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
32.1*
 
Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Executive Officer
 
 
 
32.2*
 
Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Financial Officer
 
 
 


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95*
 
Mine Safety Disclosure required by Item 104 of Regulation S-K
 
 
 
101*
 
Interactive Data File (Form 10-Q for the quarterly period ended September, 30, 2017 filed in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed”
 
 
 
*
 
Filed herewith.


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SIGNATURE

Pursuant to the requirements 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
Date:
November 3, 2017
By:  
/s/ AMY B. SCHWETZ
 
 
 
 
Amy B. Schwetz
 
 
 
 
Executive Vice President and Chief Financial Officer
(On behalf of the registrant and as Principal Financial Officer) 




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