10-Q 1 btu_20180930-10q.htm 10-Q Document

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, 2018
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
____________________________________________
peabodylogoa15.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 every Interactive Data File required to be submitted 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 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 þ
 
 
 
 
 
Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)
 
Smaller reporting company ¨
 
 
 
 
 
 
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 Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes þ No ¨
There were 114.5 million shares of the registrant’s common stock (par value of $0.01 per share) outstanding at October 29, 2018.



TABLE OF CONTENTS
 
Page
 
 



PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
Successor
 
Successor
Predecessor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017

Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
(Dollars in millions, except per share data)
Revenues
 

 
 
 
 
 
 
 
Sales
$
1,194.5

 
$
1,264.2

 
$
3,600.9

 
$
2,323.8

$
1,081.4

Other revenues
218.1

 
213.0

 
583.8

 
411.7

244.8

Total revenues
1,412.6

 
1,477.2

 
4,184.7

 
2,735.5

1,326.2

Costs and expenses
 
 
 
 
 
 
 
 
Operating costs and expenses (exclusive of items shown separately below)
1,047.9

 
1,039.1

 
3,051.6

 
1,967.0

950.2

Depreciation, depletion and amortization
169.6

 
194.5

 
503.1

 
342.8

119.9

Asset retirement obligation expenses
12.4

 
11.3

 
37.9

 
22.3

14.6

Selling and administrative expenses
38.6

 
33.7

 
119.7

 
68.4

36.3

Acquisition costs related to Shoal Creek
2.5

 
—

 
2.5

 
—

—

Other operating (income) loss:
 
 

 
 
 
 
 
Net gain on disposals
(20.8
)
 
(0.4
)
 
(49.8
)
 
(0.9
)
(22.8
)
Asset impairment
—

 
—

 
—

 
—

30.5

Provision for North Goonyella equipment loss
49.3

 
—

 
49.3

 
—

—

Income from equity affiliates
(17.2
)
 
(10.5
)
 
(64.4
)
 
(26.2
)
(15.0
)
Operating profit
130.3

 
209.5


534.8

 
362.1

212.5

Interest expense
38.2

 
42.4

 
112.8

 
83.8

32.9

Loss on early debt extinguishment
—

 
12.9

 
2.0

 
12.9

—

Interest income
(10.1
)
 
(2.0
)
 
(24.3
)
 
(3.5
)
(2.7
)
Net periodic benefit costs, excluding service cost
4.5

 
6.6

 
13.6

 
13.2

14.4

Reorganization items, net
—

 
—

 
(12.8
)
 
—

627.2

Income (loss) from continuing operations before income taxes
97.7

 
149.6

 
443.5

 
255.7

(459.3
)
Income tax provision (benefit)
13.8

 
(84.1
)
 
31.3

 
(79.4
)
(263.8
)
Income (loss) from continuing operations, net of income taxes
83.9

 
233.7

 
412.2

 
335.1

(195.5
)
Loss from discontinued operations, net of income taxes
(4.1
)
 
(3.7
)
 
(9.0
)
 
(6.4
)
(16.2
)
Net income (loss)
79.8

 
230.0

 
403.2

 
328.7

(211.7
)
Less: Series A Convertible Preferred Stock dividends
—

 
23.5

 
102.5

 
138.6

—

Less: Net income attributable to noncontrolling interests
8.3

 
5.1

 
8.9

 
8.9

4.8

Net income (loss) attributable to common stockholders
$
71.5

 
$
201.4

 
$
291.8

 
$
181.2

$
(216.5
)
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations:
 
 
 
 
 
 
 
 
Basic income (loss) per share
$
0.64

 
$
1.51

 
$
2.43

 
$
1.38

$
(10.93
)
Diluted income (loss) per share
$
0.63

 
$
1.49

 
$
2.40

 
$
1.37

$
(10.93
)
 
 
 
 
 
 
 
 
 
Net income (loss) attributable to common stockholders:
 
 
 
 
 
 
 
 
Basic income (loss) per share
$
0.60

 
$
1.48

 
$
2.36

 
$
1.33

$
(11.81
)
Diluted income (loss) per share
$
0.59

 
$
1.47

 
$
2.33

 
$
1.32

$
(11.81
)
 
 
 
 
 
 
 
 
 
Dividends declared per share
$
0.125

 
$
—

 
$
0.355

 
$
—

$
—

See accompanying notes to unaudited condensed consolidated financial statements.


1


PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
Successor
 
Successor
Predecessor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
(Dollars in millions)
Net income (loss)
$
79.8

 
$
230.0

 
$
403.2

 
$
328.7

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

 
—

 
—

 
—

18.6

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

 
—

 
—

 
—

4.4

Foreign currency translation adjustment
(1.5
)
 
1.3

 
(4.5
)
 
1.8

5.5

Other comprehensive (loss) income, net of income taxes
(1.5
)
 
1.3

 
(4.5
)
 
1.8

28.5

Comprehensive income (loss)
78.3

 
231.3

 
398.7

 
330.5

(183.2
)
Less: Series A Convertible Preferred Stock dividends
—

 
23.5

 
102.5

 
138.6

—

Less: Net income attributable to noncontrolling interests
8.3

 
5.1

 
8.9

 
8.9

4.8

Comprehensive income (loss) attributable to common stockholders
$
70.0

 
$
202.7

 
$
287.3

 
$
183.0

$
(188.0
)

See accompanying notes to unaudited condensed consolidated financial statements.


2


PEABODY ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
 
 
September 30, 2018
 
December 31, 2017
 
(Amounts in millions, except per share data)
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
1,371.0

 
$
1,012.1

Restricted cash
—

 
40.1

Accounts receivable, net of allowance for doubtful accounts of $4.4 at September 30, 2018 and $4.6 at December 31, 2017
444.9

 
552.1

Inventories
277.1

 
291.3

Other current assets
213.9

 
294.4

Total current assets
2,306.9

 
2,190.0

Property, plant, equipment and mine development, net
4,851.9

 
5,111.9

Collateral arrangements
—

 
323.1

Investments and other assets
276.4

 
470.6

Deferred income taxes
85.5

 
85.6

Total assets
$
7,520.7

 
$
8,181.2

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
42.0

 
$
42.1

Accounts payable and accrued expenses
1,082.2

 
1,202.8

Total current liabilities
1,124.2

 
1,244.9

Long-term debt, less current portion
1,334.2

 
1,418.7

Deferred income taxes
4.8

 
5.4

Asset retirement obligations
670.7

 
657.0

Accrued postretirement benefit costs
723.4

 
730.0

Other noncurrent liabilities
374.8

 
469.4

Total liabilities
4,232.1

 
4,525.4

Stockholders’ equity
 
 
 
Series A Convertible Preferred Stock — $0.01 per share par value; no shares authorized, issued or outstanding as of September 30, 2018 and 50.0 shares authorized, 30.0 shares issued and 13.5 shares outstanding as of December 31, 2017
—

 
576.0

Preferred Stock — $0.01 per share par value; 100.0 shares authorized, no shares issued or outstanding as of September 30, 2018 and 50.0 shares authorized, no shares issued or outstanding as of December 31, 2017
—

 
—

Series Common Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of September 30, 2018 or December 31, 2017
—

 
—

Common Stock — $0.01 per share par value; 450.0 shares authorized, 137.7 shares issued and 114.5 shares outstanding as of September 30, 2018 and 111.8 shares issued and 105.2 shares outstanding as of December 31, 2017
1.4

 
1.0

Additional paid-in capital
3,295.1

 
2,590.3

Treasury stock, at cost — 23.2 and 5.8 common shares as of September 30, 2018 and December 31, 2017
(890.0
)
 
(175.9
)
Retained earnings
837.2

 
613.6

Accumulated other comprehensive (loss) income
(3.1
)
 
1.4

Peabody Energy Corporation stockholders’ equity
3,240.6

 
3,606.4

Noncontrolling interests
48.0

 
49.4

Total stockholders’ equity
3,288.6

 
3,655.8

Total liabilities and stockholders’ equity
$
7,520.7

 
$
8,181.2


See accompanying notes to unaudited condensed consolidated financial statements.


3


PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Successor
Predecessor
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
(Dollars in millions)
Cash Flows From Operating Activities
 
 
 
 
Net income (loss)
$
403.2

 
$
328.7

$
(211.7
)
Loss from discontinued operations, net of income taxes
9.0

 
6.4

16.2

Income (loss) from continuing operations, net of income taxes
412.2

 
335.1

(195.5
)
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
503.1

 
342.8

119.9

Noncash coal inventory revaluation
—

 
67.3

—

Noncash interest expense, net
11.3

 
21.8

0.5

Deferred income taxes
17.5

 
1.6

(252.2
)
Noncash share-based compensation
25.6

 
14.1

1.9

Asset impairment
—

 
—

30.5

Net gain on disposals
(49.8
)
 
(0.9
)
(22.8
)
Income from equity affiliates
(64.4
)
 
(26.2
)
(15.0
)
Provision for North Goonyella equipment loss
49.3

 
—

—

Foreign currency option contracts
7.9

 
(8.4
)
—

Reclassification from other comprehensive earnings for terminated hedge contracts
—

 
—

27.6

Noncash reorganization items, net
(12.8
)
 
—

(485.4
)
Changes in current assets and liabilities:
 
 
 
 
Accounts receivable
177.3

 
(118.9
)
159.3

Inventories
14.4

 
(54.1
)
(47.2
)
Other current assets
(36.2
)
 
(22.1
)
0.2

Accounts payable and accrued expenses
(39.0
)
 
(260.7
)
(65.5
)
Collateral arrangements
323.1

 
81.2

(66.4
)
Asset retirement obligations
9.5

 
7.6

10.2

Workers’ compensation obligations
(0.4
)
 
(1.1
)
(3.1
)
Postretirement benefit obligations
(6.6
)
 
(1.2
)
0.8

Pension obligations
(68.8
)
 
(32.7
)
5.4

Other, net
10.6

 
(17.1
)
(8.0
)
Net cash provided by (used in) continuing operations
1,283.8

 
328.1

(804.8
)
Net cash used in discontinued operations
(23.0
)
 
(14.4
)
(8.2
)
Net cash provided by (used in) operating activities
1,260.8

 
313.7

(813.0
)
Cash Flows From Investing Activities
 
 
 
 
Additions to property, plant, equipment and mine development
(186.5
)
 
(68.6
)
(32.8
)
Changes in accrued expenses related to capital expenditures
(7.0
)
 
1.8

(1.4
)
Federal coal lease expenditures
(0.5
)
 
—

(0.5
)
Proceeds from disposal of assets
69.0

 
5.2

24.3

Contributions to joint ventures
(358.2
)
 
(210.0
)
(95.4
)
Distributions from joint ventures
355.0

 
208.0

90.5

Advances to related parties
(5.6
)
 
(4.1
)
(0.4
)
Cash receipts from Middlemount Coal Pty Ltd
81.1

 
35.2

31.1

Investment in equity securities
(10.0
)
 
—

—

Other, net
(2.8
)
 
(2.4
)
(0.3
)
Net cash (used in) provided by investing activities
(65.5
)
 
(34.9
)
15.1



4


PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
 
Successor
Predecessor
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
(Dollars in millions)
Cash Flows From Financing Activities
 
 
 
 
Proceeds from long-term debt
—

 
—

1,000.0

Repayments of long-term debt
(73.0
)
 
(332.1
)
(2.1
)
Payment of deferred financing costs
(21.2
)
 
(6.1
)
(45.4
)
Common stock repurchases
(699.6
)
 
(69.2
)
—

Repurchases of employee common stock relinquished for tax withholding
(14.5
)
 
—

(0.1
)
Dividends paid
(44.6
)
 
—

—

Distributions to noncontrolling interests
(10.3
)
 
(16.7
)
(0.1
)
Other, net
0.1

 
—

—

Net cash (used in) provided by financing activities
(863.1
)
 
(424.1
)
952.3

Net change in cash, cash equivalents and restricted cash
332.2

 
(145.3
)
154.4

Cash, cash equivalents and restricted cash at beginning of period (1)
1,070.2

 
1,095.6

941.2

Cash, cash equivalents and restricted cash at end of period (2)
$
1,402.4

 
$
950.3

$
1,095.6

 
 
 
 
 
 
 
 
 
 
(1) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at beginning of period”:
Cash and cash equivalents
$
1,012.1

 
 
 
Restricted cash
40.1

 
 
 
Restricted cash included in “Investments and other assets”
18.0

 
 
 
Cash, cash equivalents and restricted cash at beginning of period
$
1,070.2

 
 
 
 
 
 
 
 
(2) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at end of period”:
Cash and cash equivalents
$
1,371.0

 
 
 
Restricted cash included in “Investments and other assets”
31.4

 
 
 
Cash, cash equivalents and restricted cash at end of period
$
1,402.4

 
 
 

See accompanying notes to unaudited condensed consolidated financial statements.


5


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
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Noncontrolling
Interests
 
Total
Stockholders’
Equity
 
(Dollars in millions)
December 31, 2017
$
576.0

 
$
1.0

 
$
2,590.3

 
$
(175.9
)
 
$
613.6

 
$
1.4

 
$
49.4

 
$
3,655.8

Impact of adoption of Accounting Standards Update 2014-09
—


—


—


—


(22.5
)

—


—


(22.5
)
Net income
—


—


—


—


394.3


—


8.9


403.2

Dividends declared
—


—


1.1


—


(45.7
)

—


—


(44.6
)
Foreign currency translation adjustment
—


—


—


—


—


(4.5
)

—


(4.5
)
Series A Convertible Preferred Stock conversions
(576.0
)

0.4


678.1


—


(102.5
)

—


—


—

Share-based compensation for equity-classified awards
—


—


25.6


—


—


—


—


25.6

Common stock repurchases
—


—


—


(699.6
)

—


—


—


(699.6
)
Repurchase of employee common stock relinquished for tax withholding
—


—


—


(14.5
)

—


—


—


(14.5
)
Distributions to noncontrolling interests
—


—


—


—


—


—


(10.3
)

(10.3
)
September 30, 2018
$
—


$
1.4


$
3,295.1


$
(890.0
)

$
837.2


$
(3.1
)

$
48.0


$
3,288.6


See accompanying notes to unaudited condensed consolidated financial statements.



6


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, 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. As discussed below in Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented,” prior year amounts of net periodic benefit costs, excluding the service cost for benefits earned have been reclassified to conform with the new standard. Balance sheet information presented herein as of December 31, 2017 has been derived from the Company’s audited consolidated balance sheet at that date. The Company’s results of operations for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for future quarters or for the year ending December 31, 2018.
Plan of Reorganization and Emergence from Chapter 11 Cases
On April 13, 2016, 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.


7

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

The Company's reorganization items consisted of the following for the periods presented below:
 
Successor
 
 
Predecessor
 
Nine Months Ended September 30, 2018
 
 
January 1 through April 1, 2017
 
(Dollars in millions)
Gain on settlement of claims (1)
$
(12.8
)
 
 
$
(3,031.2
)
Fresh start adjustments, net (1)
—

 
 
3,363.1

Fresh start income tax adjustments, net (1)
—

 
 
253.9

Professional fees (2)
—

 
 
42.5

Accounts payable settlement gains
—

 
 
(0.7
)
Interest income
—

 
 
(0.4
)
Reorganization items, net
$
(12.8
)
 
 
$
627.2

 
 
 
 
 
Cash paid for "Reorganization items, net"
$
—

 
 
$
45.8

(1) 
Refer to Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 for further information related to the adjustments recorded in the period January 1 through April 1, 2017.
(2) 
Professional fees are only those that were 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.
On March 17, 2017, the Bankruptcy Court entered an order, Docket No. 2763 (the Confirmation Order), confirming the Debtors’ Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, 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.
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) 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 did 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 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.
In connection with fresh start reporting, the Company made certain prospective accounting policy elections that impact the Successor periods presented herein. The Company now classifies 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 now records 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 the applicable time periods.


8

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

(2)    Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
Newly Adopted Accounting Standards
Revenue Recognition. In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers (Topic 606),” that requires recognition of revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which a company expects to be entitled in exchange for those goods or services. The FASB has also issued several updates to ASU 2014-09. On January 1, 2018, the Company adopted ASU 2014-09 using the modified retrospective method. 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. The Company recognized the cumulative effect of initially applying ASU 2014-09 as an adjustment to the opening balance of retained earnings. Revenue previously recognized under contracts completed prior to January 1, 2018 was not impacted by adoption and comparative information has not been restated. The impact of the adoption of ASU 2014-09 was immaterial to the Company’s results of operations, financial condition and cash flows.
The majority of the Company’s coal sales revenue will continue to be recognized as title and risk of loss transfer to the customer at mines and ports when coal is loaded to the transportation source, as further described in Note 3. “Revenue Recognition.” The impact of the adoption of ASU 2014-09 was limited to a long-term contract in which consideration related to the reimbursement of certain post-mining costs was recognized as costs were incurred, which differs in timing compared to the five-step model described above. The cumulative effects to the Company’s consolidated January 1, 2018 balance sheet were to reduce retained earnings for the amount of revenue that would have been deferred and to reduce long-term customer receivables, as noted in the table below:
 
Balance at
December 31, 2017
 
Adjustments due to ASU 2014-09
 
Balance at
January 1, 2018
 
(Dollars in millions)
ASSETS
 
 
 
 
 
Investments and other assets
$
470.6

 
$
(22.5
)
 
$
448.1

 
 
 
 
 
 
STOCKHOLDERS’ EQUITY
 
 
 
 
 
Retained earnings
613.6

 
(22.5
)
 
591.1

ASU 2014-09 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. Such disclosures are included in Note 3. “Revenue Recognition.”
Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued ASU 2016-15 to amend the classification of certain cash receipts and cash payments in the statement of cash flows to reduce diversity in practice. The Company retrospectively adopted all the provisions of this new standard in the first quarter of 2018. The classification requirements under the new guidance are either consistent with the Company’s current practices or are not applicable to its activities, and as such, did not have a material impact on classification of cash receipts and cash payments in the Company’s unaudited condensed consolidated statements of cash flows.
Restricted Cash. In November 2016, the FASB issued ASU 2016-18, which reduces diversity in the presentation of restricted cash and restricted cash equivalents in the statement of cash flows. The Company retrospectively adopted all the provisions of this new accounting standard in the first quarter of 2018 and as a result of the new guidance, the Company combines restricted cash with unrestricted cash and cash equivalents when reconciling the beginning and end of period balances on its statements of cash flows. The amendments also require a company to disclose information about the nature of the restrictions and amounts described as restricted cash and restricted cash equivalents. Such disclosures are included in Note 17. “Financial Instruments and Other Guarantees.” Further, as cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the Company reconciled these amounts to the total shown in the statement of cash flows in a tabular format within the Company’s unaudited condensed consolidated statements of cash flows.


9

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

Compensation - Retirement Benefits. In March 2017, the FASB issued ASU 2017-07, which requires employers that sponsor defined benefit pension and other postretirement plans 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 on a retrospective basis. The guidance limiting the capitalization of net periodic benefit cost in assets to the service cost component will be applied prospectively. The Company adopted all the provisions of this new accounting standard in the first quarter of 2018. While adoption of this guidance did impact financial statement presentation, it did not materially impact the Company’s results of operations, financial condition or cash flows. The retrospective impacts to the unaudited condensed consolidated statements of operations were as follows:
 
Successor
 
Three Months Ended September 30, 2017
 
Before Application of Accounting Guidance
 
Adjustment
 
After Application of Accounting Guidance
 
(Dollars in millions)
Results of Operations Amounts
 
 
 
 
 
Operating costs and expenses
$
1,046.0

 
$
(6.9
)
 
$
1,039.1

Selling and administrative expenses
33.4

 
0.3

 
33.7

Operating profit
202.9

 
6.6

 
209.5

Net periodic benefit costs, excluding service cost
—

 
6.6

 
6.6

Income from continuing operations before income taxes
149.6

 
—

 
149.6

 
Successor
 
April 2 through September 30, 2017
 
Before Application of Accounting Guidance
 
Adjustment
 
After Application of Accounting Guidance
 
(Dollars in millions)
Results of Operations Amounts
 
 
 
 
 
Operating costs and expenses
$
1,980.8

 
$
(13.8
)
 
$
1,967.0

Selling and administrative expenses
67.8

 
0.6

 
68.4

Operating profit
348.9

 
13.2

 
362.1

Net periodic benefit costs, excluding service cost
—

 
13.2

 
13.2

Income from continuing operations before income taxes
255.7

 
—

 
255.7

 
Predecessor
 
January 1 through April 1, 2017
 
Before Application of Accounting Guidance
 
Adjustment
 
After Application of Accounting Guidance
 
(Dollars in millions)
Results of Operations Amounts
 
 
 
 
 
Operating costs and expenses
$
963.7

 
$
(13.5
)
 
$
950.2

Selling and administrative expenses
37.2

 
(0.9
)
 
36.3

Operating profit
198.1

 
14.4

 
212.5

Net periodic benefit costs, excluding service cost
—

 
14.4

 
14.4

Loss from continuing operations before income taxes
(459.3
)
 
—

 
(459.3
)


10

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

Compensation - Stock Compensation. In May 2017, the FASB issued ASU 2017-09 to clarify when to account for a change to the terms or conditions of a share-based payment award as a modification. Under the new guidance, modification accounting is required only if the fair value, the vesting conditions or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The Company prospectively applied all the provisions of this new accounting standard on January 1, 2018, and there was no material impact to the Company’s results of operations, financial condition or cash flows.
Cloud Computing Arrangements. In August 2018, the FASB issued ASU 2018-15 to provide new guidance on a customer’s accounting for implementation, set-up, and other upfront costs incurred in a cloud computing arrangement that is hosted by the vendor. Under the new guidance, customers will apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The new guidance also prescribes the balance sheet, income statement, and cash flow classification of the capitalized implementation costs and related amortization expense, and requires additional quantitative and qualitative disclosures. The Company retrospectively adopted all the provisions of this new accounting standard pertaining to multiple ongoing cloud implementation projects. The adoption of this guidance did not materially impact the Company’s results of operations, financial condition or cash flows.
Accounting Standards Not Yet Implemented
Leases. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which will require a lessee to recognize on its balance sheet a liability to make lease payments and a right-of-use (“ROU”) 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). In July 2018, the FASB issued the new transition method and practical expedient to simplify the application of the new leasing standard. Under the new transition method, comparative periods presented in the financial statements in the period of adoption will not need to be restated. Instead, a Company would initially apply the new lease requirements at the effective date, and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company would continue to report comparative periods presented in the financial statements in the period of adoption under current U.S. GAAP and provide the applicable required disclosures for such periods. The new practical expedient allows lessors to avoid separating lease and associated nonlease components within a contract if certain criteria are met. If elected, lessors will be able to aggregate nonlease components that otherwise would be accounted for under the new revenue standard with the associated lease component if the following conditions are met: (1) the timing and pattern of transfer for the nonlease component and the associated lease component are the same and (2) the stand-alone lease component would be classified as an operating lease if accounted for separately. The Company intends to elect some of the available practical expedients on adoption.
The Company is in the process of implementing key systems functionality and internal control processes in order to comply with the new reporting requirements of ASU 2016-02 and estimates that adoption of the standard will result in the recognition of additional ROU assets and corresponding lease liabilities on January 1, 2019 of approximately $200 million to $300 million (dependent upon various factors at the adoption date, including leases outstanding and prevailing interest and foreign exchange rates). The adoption of ASU 2016-02 is not expected to have a material impact on the Company’s results of operations or its cash flows, or to affect the Company’s compliance with the terms of its existing debt agreements.
Derivatives and Hedging. In August 2017, the FASB issued ASU 2017-12 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.


11

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

Leases - Land Easements. In January 2018, the FASB issued ASU 2018-01 to provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under current leasing guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. An entity that does not elect this practical expedient should evaluate all existing or expired land easements in connection with the adoption of the new leases requirements in Topic 842 to assess whether they meet the definition of a lease. The amendments in this update affect the amendments in ASU 2016-02. The effective date and transition requirements for the amendments are the same as the effective date and transition requirements in ASU 2016-02. The Company plans to adopt the expedient effective January 1, 2019 and 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.
Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13, which amended the fair value measurement guidance by removing and modifying certain disclosure requirements, while also adding new disclosure requirements. The amendments on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty should be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. All other amendments should be applied retrospectively to all periods presented upon their effective date. The amendments are effective for all companies for fiscal years, and interim periods within those years, beginning after December 15, 2019. Early adoption is permitted for all amendments. Further, a company may elect to early adopt the removal or modification of disclosures immediately and delay adoption of the new disclosure requirements until the effective date. The Company plans to adopt all disclosure requirements effective January 1, 2020.
Compensation - Retirement Benefits. In August 2018, the FASB issued ASU 2018-14 to add, remove, and clarify disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. ASU 2018-14 is effective for fiscal years ending after December 15, 2020 for public companies and early adoption is permitted. The Company plans to adopt the disclosure requirements effective January 1, 2021.
(3)    Revenue Recognition
The Company accounts for revenue in accordance with ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606), which the Company adopted on January 1, 2018, using the modified retrospective approach. See Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” for further discussion of the adoption, including the impact on the Company’s opening balance sheet.
Sales
The majority of the Company’s revenue is derived from the sale of coal under long-term coal supply agreements (those with initial terms of one year or longer and which often include price reopener and/or extension provisions) and contracts with terms of less than one year, including sales made on a spot basis. The Company’s revenue from coal sales is realized and earned when risk of loss passes to the customer. Under the typical terms of the Company’s coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the transportation source(s) that serves each of the Company’s mines. The Company incurs certain “add-on” taxes and fees on coal sales. Reported coal sales include taxes and fees charged by various federal and state governmental bodies and the freight charged on destination customer contracts.
The Company’s U.S. operating platform primarily sells thermal coal to electric utilities in the U.S. under long-term contracts, with a portion sold into the seaborne markets as conditions warrant. A significant portion of the coal production from the U.S. mining segments is sold under long-term supply agreements, and customers of those segments continue to pursue long-term sales agreements in recognition of the importance of reliability, service and predictable coal prices to their operations. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of those agreements may vary 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.


12

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

The Company's Australian operating platform is primarily export focused with customers spread across several countries, while a portion of the metallurgical and thermal coal is sold within Australia. Generally, revenues from individual countries vary year by year based on electricity and steel demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. A majority of these sales are executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Industry commercial practice, and the Company’s typical practice, is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis. The portion of volume priced on a shorter-term basis and index-linked basis has increased in recent years. In the case of periodically negotiated pricing, the Company may deliver coal under provisional pricing until a final agreed-upon price is determined. The resulting make-whole settlements are recognized when reasonably estimable.
Contract pricing is set forth on a per ton basis, and revenue is generally recorded as the product of price and volume delivered. Many of the Company’s coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. These contract prices may be adjusted based on inflation or deflation and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. The Company sometimes experiences a reduction in coal prices in new long-term coal supply agreements replacing some of its expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by the Company or the customer during the duration of specified events beyond the control of the affected party. Most of the coal supply agreements contain provisions requiring the Company to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements allow the Company’s customers to terminate their contracts in the event of changes in regulations affecting the industry that restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.
Other Revenues
"Other revenues" may include net revenues from coal trading activities as discussed in Note 7. “Coal Trading,” as well as coal sales revenues that were derived from the Company’s mining operations and sold through the Company’s coal trading business. Also included are revenues from customer contract-related payments, royalties related to coal lease agreements, sales agency commissions, farm income and property and facility rentals. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced.
Accounts Receivable
The timing of revenue recognition, billings and cash collections results in accounts receivable from customers. Customers are invoiced as coal is shipped or at periodic intervals in accordance with contractual terms. Invoices typically include customary adjustments for the resolution of price variability related to prior shipments, such as coal quality thresholds. Payments are generally received within thirty days of invoicing. “Accounts receivable, net” at September 30, 2018 and December 31, 2017 consisted of the following:
 
September 30, 2018
 
December 31, 2017
 
(Dollars in millions)
Trade receivables, net
$
345.9

 
$
504.2

Miscellaneous receivables, net
99.0

 
47.9

Accounts receivable, net
$
444.9

 
$
552.1

Trade receivables, net presented above have been shown net of reserves of $0.1 million and $0.3 million as of September 30, 2018 and December 31, 2017, respectively. Miscellaneous receivables, net presented above have been shown net of reserves of $4.3 million as of both September 30, 2018 and December 31, 2017. Included in “Operating costs and expenses” in the unaudited condensed consolidated statements of operations was a credit of $0.4 million, $0.1 million and $0.2 million for the three months ended September 30, 2018 and 2017, and the nine months ended September 30, 2018, respectively. A charge for doubtful trade receivables of $4.4 million was included for the period April 2 through September 30, 2017. No charges for doubtful accounts were recognized during the period January 1 through April 1, 2017.


13

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

The Company also records long-term customer receivables related to the reimbursement of certain post-mining costs which are included within “Investments and other assets” in the accompanying condensed consolidated balance sheets. The balance of such receivables was $35.8 million and $139.3 million as of September 30, 2018 and December 31, 2017, respectively. The balance was adjusted in connection with the adoption of ASC 606, as described in Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented.” Also in connection with the adoption of ASC 606, the Company prospectively records a portion of the consideration received as “Interest income” rather than “Other revenues” in the accompanying unaudited condensed consolidated statements of operations, due to the embedded financing element within the related contract. Interest income related to these arrangements amounted to $2.1 million and $6.3 million during the three and nine months ended September 30, 2018, respectively.
Disaggregation of Revenues
Revenue by product type and market is set forth in the following tables. With respect to its Australian Mining segments, the Company classifies as “Export” certain revenue from domestically-delivered coal under contracts in which the price is derived on a basis similar to export contracts.
 
Successor
 
Three Months Ended September 30, 2018
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
Thermal coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
$
373.7

 
$
208.4

 
$
149.5

 
$
—

 
$
37.4

 
$
—

 
$
—

 
$
769.0

Export
—

 
—

 
3.1

 
—

 
267.7

 
—

 
—

 
270.8

Total thermal
373.7

 
208.4

 
152.6

 
—

 
305.1

 
—

 
—

 
1,039.8

Metallurgical coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Export
—

 
—

 
—

 
369.4

 
—

 
—

 
—

 
369.4

Total metallurgical
—

 
—

 
—

 
369.4

 
—

 
—

 
—

 
369.4

Other
—

 
0.1

 
3.5

 
0.9

 
—

 
22.6

 
(23.7
)
 
3.4

Total revenues
$
373.7

 
$
208.5

 
$
156.1

 
$
370.3

 
$
305.1

 
$
22.6

 
$
(23.7
)
 
$
1,412.6

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
Three Months Ended September 30, 2017
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
Thermal coal
 
 
 
 
 
 
 
 
 
 
 
 

 
 
Domestic
$
420.9

 
$
207.1

 
$
147.1

 
$
—

 
$
31.6

 
$
—

 
$
—

 
$
806.7

Export
—

 
0.4

 
11.2

 
—

 
234.1

 
—

 
—

 
245.7

Total thermal
420.9

 
207.5

 
158.3

 
—

 
265.7

 
—

 
—

 
1,052.4

Metallurgical coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Export
—

 
—

 
—

 
414.1

 
—

 
—

 
—

 
414.1

Total metallurgical
—

 
—

 
—

 
414.1

 
—

 
—

 
—

 
414.1

Other
—

 
0.2

 
(2.6
)
 
1.8

 
0.1

 
19.4

 
(8.2
)
 
10.7

Total revenues
$
420.9

 
$
207.7

 
$
155.7

 
$
415.9

 
$
265.8

 
$
19.4

 
$
(8.2
)
 
$
1,477.2



14

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

 
Successor
 
Nine Months Ended September 30, 2018
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
Thermal coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
$
1,084.4

 
$
606.2

 
$
410.9

 
$
—

 
$
112.0

 
$
—

 
$
—

 
$
2,213.5

Export
—

 
1.3

 
15.4

 
—

 
661.3

 
—

 
—

 
678.0

Total thermal
1,084.4

 
607.5

 
426.3

 
—

 
773.3

 
—

 
—

 
2,891.5

Metallurgical coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Export
—

 
—

 
—

 
1,251.9

 
—

 
—

 
—

 
1,251.9

Total metallurgical
—

 
—

 
—

 
1,251.9

 
—

 
—

 
—

 
1,251.9

Other
0.1

 
0.2

 
13.1

 
2.1

 
0.6

 
52.7

 
(27.5
)
 
41.3

Total revenues
$
1,084.5

 
$
607.7

 
$
439.4

 
$
1,254.0

 
$
773.9

 
$
52.7

 
$
(27.5
)
 
$
4,184.7

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
April 2 through September 30, 2017
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
Thermal coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
$
782.0

 
$
401.9

 
$
270.9

 
$
—

 
$
59.7

 
$
—

 
$
—

 
$
1,514.5

Export
—

 
0.4

 
11.2

 
—

 
445.0

 
—

 
—

 
456.6

Total thermal
782.0

 
402.3

 
282.1

 
—

 
504.7

 
—

 
—

 
1,971.1

Metallurgical coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Export
—

 
—

 
—

 
701.9

 
—

 
—

 
—

 
701.9

Total metallurgical
—

 
—

 
—

 
701.9

 
—

 
—

 
—

 
701.9

Other
4.3

 
0.3

 
(1.0
)
 
1.8

 
0.3

 
24.6

 
32.2

 
62.5

Total revenues
$
786.3

 
$
402.6

 
$
281.1

 
$
703.7

 
$
505.0

 
$
24.6

 
$
32.2

 
$
2,735.5

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Predecessor
 
January 1 through April 1, 2017
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
Thermal coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
$
394.3

 
$
193.2

 
$
133.5

 
$
—

 
$
27.3

 
$
—

 
$
—

 
$
748.3

Export
—

 
—

 
—

 
—

 
197.2

 
—

 
—

 
197.2

Total thermal
394.3

 
193.2

 
133.5

 
—

 
224.5

 
—

 
—

 
945.5

Metallurgical coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Export
—

 
—

 
—

 
324.6

 
—

 
—

 
—

 
324.6

Total metallurgical
—

 
—

 
—

 
324.6

 
—

 
—

 
—

 
324.6

Other
—

 
—

 
16.2

 
4.3

 
0.3

 
15.0

 
20.3

 
56.1

Total revenues
$
394.3

 
$
193.2

 
$
149.7

 
$
328.9

 
$
224.8

 
$
15.0

 
$
20.3

 
$
1,326.2



15

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

Revenue by contract duration was as follows:
 
Successor
 
Three Months Ended September 30, 2018
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
One year or longer
$
330.2

 
$
205.3

 
$
146.6

 
$
199.5

 
$
235.3

 
$
—

 
$
—

 
$
1,116.9

Less than one year
43.5

 
3.1

 
6.0

 
169.9

 
69.8

 
—

 
—

 
292.3

Other (2)
—

 
0.1

 
3.5

 
0.9

 
—

 
22.6

 
(23.7
)
 
3.4

Total revenues
$
373.7

 
$
208.5

 
$
156.1

 
$
370.3

 
$
305.1

 
$
22.6

 
$
(23.7
)
 
$
1,412.6

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
Three Months Ended September 30, 2017
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
One year or longer
$
373.3

 
$
199.0

 
$
144.2

 
$
270.9

 
$
164.7

 
$
—

 
$
—

 
$
1,152.1

Less than one year
47.6

 
8.5

 
14.1

 
143.2

 
101.0

 
—

 
—

 
314.4

Other (2)
—

 
0.2

 
(2.6
)
 
1.8

 
0.1

 
19.4

 
(8.2
)
 
10.7

Total revenues
$
420.9

 
$
207.7

 
$
155.7

 
$
415.9

 
$
265.8

 
$
19.4

 
$
(8.2
)
 
$
1,477.2



16

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

 
Successor
 
Nine Months Ended September 30, 2018
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
One year or longer
$
984.4

 
$
587.0

 
$
400.4

 
$
852.1

 
$
585.8

 
$
—

 
$
—

 
$
3,409.7

Less than one year
100.0

 
20.5

 
25.9

 
399.8

 
187.5

 
—

 
—

 
733.7

Other (2)
0.1

 
0.2

 
13.1

 
2.1

 
0.6

 
52.7

 
(27.5
)
 
41.3

Total revenues
$
1,084.5

 
$
607.7

 
$
439.4

 
$
1,254.0

 
$
773.9

 
$
52.7

 
$
(27.5
)
 
$
4,184.7

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
April 2 through September 30, 2017
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
One year or longer
$
700.0

 
$
386.3

 
$
266.9

 
$
524.3

 
$
300.3

 
$
—

 
$
—

 
$
2,177.8

Less than one year
82.0

 
16.0

 
15.2

 
177.6

 
204.4

 
—

 
—

 
495.2

Other (2)
4.3

 
0.3

 
(1.0
)
 
1.8

 
0.3

 
24.6

 
32.2

 
62.5

Total revenues
$
786.3

 
$
402.6

 
$
281.1

 
$
703.7

 
$
505.0

 
$
24.6

 
$
32.2

 
$
2,735.5

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Predecessor
 
January 1 through April 1, 2017
 
Powder River Basin Mining
 
Midwestern U.S. Mining
 
Western U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
Trading and Brokerage
 
Corporate and Other (1)
 
Consolidated
 
(Dollars in millions)
One year or longer
$
357.7

 
$
193.2

 
$
129.3

 
$
240.6

 
$
134.1

 
$
—

 
$
—

 
$
1,054.9

Less than one year
36.6

 
—

 
4.2

 
84.0

 
90.4

 
—

 
—

 
215.2

Other (2)
—

 
—

 
16.2

 
4.3

 
0.3

 
15.0

 
20.3

 
56.1

Total revenues
$
394.3

 
$
193.2

 
$
149.7

 
$
328.9

 
$
224.8

 
$
15.0

 
$
20.3

 
$
1,326.2

(1) 
Corporate and Other revenue includes unrealized gains and losses related to mark-to-market activity from economic hedge activities intended to hedge future coal sales. Such net unrealized losses were $26.8 million and $10.8 million during the three months ended September 30, 2018 and 2017, respectively, and $36.3 million and $1.4 million during the nine months ended September 30, 2018 and the period April 2 through September 30, 2017, respectively. During the period January 1 through April 1, 2017, such net unrealized gains were $16.6 million. When such gains and losses are realized in connection with recognition of the underlying transaction, they are reclassified to realized gains and losses and are then reflected in Trading and Brokerage revenue (realized losses of $11.6 million and $12.3 million during the three months ended September 30, 2018 and 2017, respectively, and $41.1 million, $20.0 million and $11.1 million during the nine months ended September 30, 2018 and the periods April 2 through September 30, 2017 and January 1 through April 1, 2017, respectively). At September 30, 2018 and December 31, 2017, the financial contracts’ fair values resulted in net liabilities, excluding margin, of $75.2 million and $38.9 million, respectively.
(2) 
Other includes revenues from arrangements such as customer contract-related payments, royalties related to coal lease agreements, sales agency commissions, farm income and property and facility rentals, for which contract duration is not meaningful.
Committed Revenue from Contracts with Customers
The Company expects to recognize revenue subsequent to September 30, 2018 of approximately $5.8 billion related to contracts with customers in which volumes and prices per ton were fixed or reasonably estimable at September 30, 2018. Approximately 47% of such amount is expected to be recognized over the next twelve months and the remainder thereafter. Actual revenue related to such contracts may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events. This estimate of future revenue does not include any revenue related to contracts with variable prices per ton that cannot be reasonably estimated, such as the majority of Australian metallurgical and seaborne thermal coal contracts where pricing is negotiated or settled quarterly or annually.


17

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

(4)    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 presented below:
 
 
Successor
 
Successor
Predecessor
 
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
 
(Dollars in millions)
Loss from discontinued operations, net of income taxes
 
$
(4.1
)
 
$
(3.7
)
 
$
(9.0
)
 
$
(6.4
)
$
(16.2
)
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:
 
September 30, 2018
 
December 31, 2017
 
(Dollars in millions)
Assets:
 
 
 
Other current assets
$
0.5

 
$
0.3

Total assets classified as discontinued operations
$
0.5

 
$
0.3

 
 
 
 
Liabilities:
 
 
 
Accounts payable and accrued expenses
$
70.8

 
$
70.6

Other noncurrent liabilities
156.0

 
170.0

Total liabilities classified as discontinued operations
$
226.8

 
$
240.6

Patriot-Related Matters
A significant portion of the liabilities in the table above relate to Patriot. In 2012, Patriot filed voluntary petitions for relief under the Bankruptcy 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 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 had federal and state black lung occupational disease liabilities related to workers employed in periods prior to Patriot’s spin-off from the Company in 2007. Upon spin-off, Patriot indemnified the Company against any claim relating to these liabilities, which amounted to approximately $150 million at that time. The indemnification included any claim made by the U.S. Department of Labor (DOL) against the Company with respect to these obligations as a potentially liable operator under the Federal Coal Mine Health and Safety Act of 1969. The 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.


18

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

By statute, the Company had secondary liability for the black lung liabilities related to Patriot’s workers employed by former subsidiaries of the Company. The Company’s accounting for the black lung liabilities related to Patriot is based on an interpretation of applicable statutes. Management believes that inconsistencies exist among the applicable statutes, regulations promulgated under those statutes and the DOL’s interpretative guidance. The Company has sought clarification from the DOL regarding these inconsistencies and the accounting for these liabilities could be reduced in the future depending on the DOL’s responses. 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 was $135.9 million at September 30, 2018, which was determined on an actuarial basis based on the best information available to the Company. While the Company has recorded a liability, it intends to review each claim on a case-by-case basis and contest liability estimates as appropriate. The amount of the Company’s recorded liability reflects only Patriot workers employed by former subsidiaries of the Company that are presently retired, disabled or otherwise not actively employed. The Company cannot reliably estimate the potential liabilities for Patriot’s workers employed by former subsidiaries of the Company that are presently active in the workforce because of the potential for such workers to continue to work for another coal operator that is a going concern.
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, a subsidiary of the Company, and Arch Coal, Inc. The plaintiffs sought, pursuant to the Employee Retirement Income Security Act of 1974 (ERISA) and the Multiemployer Pension Plan Amendments Act of 1980, 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. The balance of the liability, on a discounted basis, was $35.3 million at September 30, 2018.
(5)     Inventories
Inventories as of September 30, 2018 and December 31, 2017 consisted of the following:
 
September 30, 2018
 
December 31, 2017
 
(Dollars in millions)
Materials and supplies
$
104.3

 
$
101.5

Raw coal
57.5

 
78.1

Saleable coal
115.3

 
111.7

Total
$
277.1

 
$
291.3

Materials and supplies inventories presented above have been shown net of reserves of $0.2 million and $0.6 million as of September 30, 2018 and December 31, 2017, respectively.
(6)     Derivatives and Fair Value Measurements
Risk Management — Corporate Hedging Activities
The Company is exposed to several risks in the normal course of business, including (1) foreign currency exchange rate risk for non-U.S. dollar expenditures and balances, (2) price risk on coal produced by and diesel fuel utilized in the Company’s mining operations and (3) interest rate risk that has been partially mitigated by fixed rates on long-term debt. The Company manages a portion of its price risk related to the sale of coal (excluding coal trading activities) using long-term coal supply agreements. Derivative financial instruments have historically been used to manage the Company’s exposure to foreign currency exchange rate risk, primarily on Australian dollar expenditures made in its Australian mining platform. This risk was historically managed using forward contracts and options designated as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted foreign currency expenditures. The Company previously used derivative instruments to manage its exposure to the variability of diesel fuel prices used in production in the U.S. and Australia with swaps or options, which it 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.


19

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

The Company had no diesel fuel derivatives in place as of September 30, 2018 or December 31, 2017. As of September 30, 2018, the Company had currency options outstanding with an aggregate notional amount of $675.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the remainder of 2018 and over the first three months of 2019. The instruments are quarterly average rate options whereby the Company is entitled to receive payment on the notional amount should the quarterly average Australian dollar-to-U.S. dollar exchange rate exceed amounts ranging from $0.79 to $0.82over the remainder of 2018 and the first three months of 2019. The Company does not seek cash flow hedge accounting treatment for the currency options and thus changes in fair value are reflected in current earnings. The currency options’ fair value of $0.2 million and $4.2 million was included in “Other current assets” in the accompanying condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017, respectively.
Subsequent to September 30, 2018, the Company purchased additional quarterly average rate options with an aggregate notional amount of $275.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the first half of 2019 should the quarterly average Australian dollar-to-U.S. dollar exchange rate exceed approximately $0.76 over that period. The Company incurred premium costs of approximately $0.8 million for these options.
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, 2018
Financial Instrument
 
Income Statement Classification
 
Total loss recognized in income
 
Loss 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
 
$
(1.5
)
 
$
(1.8
)
 
$
0.3

Total
 
 
 
$
(1.5
)
 
$
(1.8
)
 
$
0.3

 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
 
 
 
Three Months Ended September 30, 2017
Financial Instrument
 
Income Statement Classification
 
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
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
 
 
 
Nine Months Ended September 30, 2018
Financial Instrument
 
Income Statement Classification
 
Total loss recognized in income
 
Loss 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
 
$
(7.9
)
 
$
(6.5
)
 
$
(1.4
)
Total
 
 
 
$
(7.9
)
 
$
(6.5
)
 
$
(1.4
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
 
 
 
April 2 through September 30, 2017
Financial Instrument
 
Income Statement Classification
 
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



20

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

 
 
 
 
 
 
 
 
 
 
 
Predecessor
 
 
 
 
January 1 through April 1, 2017
Financial Instrument
 
Income Statement Classification
 
Total loss recognized in income
 
Loss reclassified from other comprehensive loss into income
 
 
 
(Dollars in millions)
Commodity swap contracts
 
Operating costs and expenses
 
$
(11.0
)
 
$
(11.0
)
Foreign currency option contracts
 
Operating costs and expenses
 
(16.6
)
 
(16.6
)
Total
 
 
 
$
(27.6
)
 
$
(27.6
)
Cash Flow Presentation. The Company classifies the cash effects of its Corporate Hedging derivatives within the “Cash Flows From Operating Activities” section of the accompanying 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:
 
September 30, 2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Dollars in millions)
Equity securities
$
—

 
$
—

 
$
10.0

 
$
10.0

Foreign currency contracts
—

 
0.2

 
—

 
0.2

Total net financial assets
$
—

 
$
0.2

 
$
10.0

 
$
10.2

 
 
 
 
 
 
 
 
 
December 31, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Dollars in millions)
Foreign currency contracts
$
—

 
$
4.2

 
$
—

 
$
4.2

Total net financial assets
$
—

 
$
4.2

 
$
—

 
$
4.2

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:
•
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, 2018 and December 31, 2017:
•
Cash and cash equivalents, restricted cash, accounts receivable, including those within the Company’s accounts receivable securitization program, notes receivable and accounts payable have carrying values which approximate fair value due to the short maturity or the liquid nature of these instruments.
•
Investments in equity securities are based on observed prices in an inactive market (Level 3).
•
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).


21

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

The carrying amounts and estimated fair values of the Company’s current and long-term debt as of September 30, 2018 and December 31, 2017 are summarized as follows:
 
September 30, 2018
 
December 31, 2017
 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
 
(Dollars in millions)
Current and Long-term debt
$
1,376.2

 
$
1,451.0

 
$
1,460.8

 
$
1,547.4

The Company had no transfers between fair value hierarchy levels for either financial instruments measured on a recurring basis or other financial instruments during the three and nine months ended September 30, 2018, the three months ended September 30, 2017, the period April 2 through September 30, 2017 or the period January 1 through April 1, 2017. The Company’s policy is to value all transfers between levels using the beginning of period valuation.
(7)     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. Coal brokering is conducted both as principal and agent in support of various coal production-related activities that may involve coal produced from the Company's mines, coal sourcing arrangements with third-party mining companies or offtake agreements with other coal producers. The Company’s Trading and Brokerage segment also provides transportation-related services, which involve both financial derivative contracts and physical contracts. Collectively, coal and freight-related hedging activities include both economic hedging and, from time to time, cash flow hedging in support of the Company's coal trading strategy.
The Company 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.
Trading revenues (losses) recognized during the periods presented below were as follows:
 
 
Successor
 
Successor
Predecessor
Trading Revenues (Losses) by Type of Instrument
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
 
(Dollars in millions)
Futures, swaps and options
 
$
(12.1
)
 
$
(17.1
)
 
$
(44.3
)
 
$
(24.4
)
$
(10.2
)
Physical purchase/sale contracts
 
34.7

 
36.5

 
97.0

 
49.0

25.2

Total trading revenues
 
$
22.6

 
$
19.4

 
$
52.7

 
$
24.6

$
15.0

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 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 “Other current assets” and “Accounts payable and accrued expenses.”


22

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

The fair value of assets and liabilities from coal trading activities presented on a gross and net basis as of September 30, 2018 and December 31, 2017 is set forth below:
Affected Line Item in the Condensed Consolidated Balance Sheets
 
Gross Amounts of Recognized Assets (Liabilities) (1)
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Variation Margin Posted
 
Net Amounts of Assets (Liabilities) Presented in the Condensed Consolidated Balance Sheets
 
 
(Dollars in millions)
 
 
Fair Value as of September 30, 2018
Other current assets
 
$
81.8

 
$
(81.5
)
 
$
—

 
$
0.3

Accounts payable and accrued expenses
 
(160.4
)
 
81.5

 
69.3

 
(9.6
)
Total, net
 
$
(78.6
)
 
$
—

 
$
69.3

 
$
(9.3
)
 
 
 
 
 
 
 
 
 
 
 
Fair Value as of December 31, 2017
Other current assets
 
$
77.1

 
$
(74.5
)
 
$
—

 
$
2.6

Accounts payable and accrued expenses
 
(122.0
)
 
74.5

 
35.8

 
(11.7
)
Total, net
 
$
(44.9
)
 
$
—

 
$
35.8

 
$
(9.1
)
(1) 
Amounts include net liabilities of $75.2 million and $38.9 million at September 30, 2018 and December 31, 2017, respectively, representing the fair value of financial contracts used to hedge future coal sales, as further described in Note 3. “Revenue Recognition.”
The Company is exposed to the risk of changes in coal prices on the value of its coal trading portfolio. At September 30, 2018, the estimated future realization of the value of the trading portfolio was $12.0 million of gains during the remainder of 2018, $10.9 million of losses during 2019, $5.3 million of losses during 2020, and $0.2 million of gains during 2021.
Fair Value Measurements
The following tables set forth the hierarchy of the Company’s net financial liability coal trading positions for which fair value is measured on a recurring basis as of September 30, 2018 and December 31, 2017:
 
September 30, 2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Dollars in millions)
Futures, swaps and options
$
—

 
$
(2.1
)
 
$
—

 
$
(2.1
)
Physical purchase/sale contracts
—

 
(5.5
)
 
(1.7
)
 
(7.2
)
Total net financial liabilities
$
—

 
$
(7.6
)
 
$
(1.7
)
 
$
(9.3
)
 
December 31, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Dollars in millions)
Futures, swaps and options
$
(3.0
)
 
$
(4.2
)
 
$
—

 
$
(7.2
)
Physical purchase/sale contracts
—

 
(1.9
)
 
—

 
(1.9
)
Total net financial liabilities
$
(3.0
)
 
$
(6.1
)
 
$
—

 
$
(9.1
)
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 Group, Intercontinental Exchange, Baltic Exchange and Singapore Exchange 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.


23

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

The Company’s risk management function, which is independent of the Company's coal trading function, is responsible for valuation policies and procedures, with oversight from executive management. Generally, the Company's Level 3 instruments or contracts are valued using bid/ask price quotations and other market assessments obtained from multiple, independent third-party brokers or other transactional data incorporated into internally-generated discounted cash flow models. Decreases in the number of third-party brokers or market liquidity could erode the quality of market information and therefore the valuation of the Company's market positions. The Company's valuation techniques include basis adjustments to the foregoing price inputs for quality, such as sulfur and ash content, location differentials, expressed as port and freight costs, and credit risk. The Company's risk management function independently validates the Company's valuation inputs, including unobservable inputs, with third-party information and settlement prices from other sources where available. A daily process is performed to analyze market price changes and changes to the portfolio. Further periodic validation occurs at the time contracts are settled with the counterparty. These valuation techniques have been consistently applied in all periods presented, and the Company believes it has obtained the most accurate information available for the types of derivative contracts held.
The following table summarizes the quantitative unobservable inputs utilized in the Company's internally-developed valuation models for physical purchase/sale contracts classified as Level 3 as of September 30, 2018:
 
 
Range
 
Weighted
Input
 
Low
 
High
 
Average
Quality
 
(35.6
)%
 
(36.0
)%
 
(35.8
)%
Significant increases or decreases in the inputs in isolation could result in a significantly higher or lower fair value measurement. The unobservable inputs do not have a direct interrelationship; therefore, a change in one unobservable input would not necessarily correspond with a change in another unobservable input.
The following table summarizes the changes in the Company’s recurring Level 3 net financial assets:
 
 
Successor
 
Successor
Predecessor
 
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
 
(Dollars in millions)
Beginning of period
 
$
—

 
$
—

 
$
—

 
$
(0.7
)
$
(1.1
)
Transfers out of Level 3
 
—

 
—

 
—

 
0.7

0.2

Total (losses) gains realized/unrealized included in earnings
 
(1.7
)
 
—

 
(1.7
)
 
—

0.2

End of period
 
$
(1.7
)
 
$
—

 
$
(1.7
)
 
$
—

$
(0.7
)
The Company had no transfers between Levels 1 and 2 during the periods presented in the table above. Transfers of liabilities into/out of Level 3 from/to Level 2 during the periods April 2 through September 30, 2017 and January 1 through April 1, 2017 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 (losses) gains relating to Level 3 net financial assets held both as of the beginning and the end of the period:
 
 
Successor
 
Successor
Predecessor
 
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
 
(Dollars in millions)
Changes in unrealized (losses) gains (1)
 
$
(1.7
)
 
$
—

 
$
(1.7
)
 
$
—

$
0.3

(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.


24

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

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, 2018, 93% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties, while 0% was with non-investment grade counterparties and 7% 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, 2018 and December 31, 2017, the Company posted a net variation margin of $69.3 million and $35.8 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 $19.4 million as of September 30, 2018, compared to $18.8 million as of December 31, 2017, which is reflected in “Other current assets” in the condensed consolidated balance sheets. As of September 30, 2018 and December 31, 2017, the Company was in receipt of $0.2 million and $1.8 million, respectively, of the required variation and initial margin.
Certain of the Company’s derivative trading instruments require the parties to provide additional performance assurances whenever a material adverse event jeopardizes one party’s ability to perform under the instrument. If the Company was to sustain a material adverse event (using commercially reasonable standards), its counterparties could request collateralization on derivative trading instruments in net liability positions which, based on an aggregate fair value at September 30, 2018 and December 31, 2017, would have amounted to collateral postings to counterparties of approximately $9.7 million and $7.0 million, respectively. As of September 30, 2018, the Company was not required to post collateral, whereas on December 31, 2017, the Company was required to post approximately $0.4 million in collateral to counterparties for such positions.


25

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

(8)     Intangible Contract Assets and Liabilities
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, 2018 and December 31, 2017, net of accumulated amortization, are set forth in the following tables:
 
September 30, 2018
 
(Dollars in millions)
 
Assets
 
Liabilities
 
Net Total
Coal supply agreements
$
88.5

 
$
(32.4
)
 
$
56.1

Take-or-pay contracts
—

 
(63.6
)
 
(63.6
)
Total
$
88.5

 
$
(96.0
)
 
$
(7.5
)
 
 
 
 
 
 
Balance sheet classification:
 
 
 
 
 
Investments and other assets
$
88.5

 
$
—

 
$
88.5

Accounts payable and accrued expenses
—

 
(19.5
)
 
(19.5
)
Other noncurrent liabilities
—

 
(76.5
)
 
(76.5
)
Total
$
88.5

 
$
(96.0
)
 
$
(7.5
)
 
 
 
 
 
 
 
December 31, 2017
 
(Dollars in millions)
 
Assets
 
Liabilities
 
Net Total
Coal supply agreements
$
177.2

 
$
(42.7
)
 
$
134.5

Take-or-pay contracts
—

 
(90.7
)
 
(90.7
)
Total
$
177.2

 
$
(133.4
)
 
$
43.8

 
 
 
 
 
 
Balance sheet classification:
 
 
 
 
 
Investments and other assets
$
177.2

 
$
—

 
$
177.2

Accounts payable and accrued expenses
—

 
(27.6
)
 
(27.6
)
Other noncurrent liabilities
—

 
(105.8
)
 
(105.8
)
Total
$
177.2

 
$
(133.4
)
 
$
43.8

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 unaudited condensed consolidated statements of operations. Such amortization amounted to $24.0 million and $78.4 million during the three and nine months ended September 30, 2018, respectively, and $41.5 million and $71.2 million during the three months ended September 30, 2017 and the period April 2 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 $19 million during the three months ended December 31, 2018, and for the years 2019 through 2022, expense of approximately $26 million, $8 million, $3 million and $1 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 unaudited condensed consolidated statements of operations, amounted to $5.4 million and $21.5 million during the three and nine months ended September 30, 2018, respectively, and $6.5 million and $16.4 million during the three months ended September 30, 2017 and the period April 2 through September 30, 2017, respectively. The Company anticipates net amortization of take-or-pay contract intangible liabilities to be approximately $5 million during the three months ended December 31, 2018, and for the years 2019 through 2022, approximately $17 million, $9 million, $4 million and $3 million, respectively, and $26 million thereafter.


26

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

(9) Equity Method Investments
The Company had total equity method investments of $66.4 million and $82.1 million reflected in “Investments and other assets” in the condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017, respectively, related to Middlemount Coal Pty Ltd (Middlemount). As noted in Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, the carrying value of the equity method investments 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.
The Company received cash payments from Middlemount of $81.1 million during the nine months ended September 30, 2018, and $35.2 million and $31.1 million during the periods April 2 through September 30, 2017 and January 1 through April 1, 2017, respectively.
(10) Property, Plant, Equipment and Mine Development
The composition of property, plant, equipment and mine development, net, as of September 30, 2018 and December 31, 2017 is set forth in the table below. Refer to Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 for details regarding the impact of fresh start reporting on property, plant, equipment and mine development.
 
September 30, 2018
 
December 31, 2017
 
(Dollars in millions)
Land and coal interests
$
3,900.4

 
$
3,890.5

Buildings and improvements
457.0

 
470.6

Machinery and equipment
1,304.1

 
1,149.3

Less: Accumulated depreciation, depletion and amortization
(809.6
)
 
(398.5
)
Property, plant, equipment and mine development, net
$
4,851.9

 
$
5,111.9

(11)  Income Taxes
The Company’s income tax provision of $13.8 million and $31.3 million for the three and nine months ended September 30, 2018, respectively, included tax benefits of $0.3 million and $0.2 million, respectively, related to the remeasurement of foreign income tax accounts. The Company’s income tax benefit of $84.1 million, $79.4 million and $263.8 million for the three months ended September 30, 2017, the period April 2 through September 30, 2017 and the period January 1 through April 1, 2017, respectively, included tax provisions of $0.9 million, $1.0 million and $9.4 million, respectively, related to the remeasurement of foreign income tax accounts. The Company’s effective tax rate before remeasurement for the nine months ended September 30, 2018 is based on the Company’s estimated full year effective tax rate, comprised of expected statutory tax provision, offset by foreign rate differential and changes in valuation allowances.
On December 22, 2017, the Tax Cuts and Jobs Act (the Act) was signed into law making significant changes to the Internal Revenue Code. Certain provisions of the Act applied to taxable years beginning after December 31, 2017 and therefore have an impact on the nine months ended September 30, 2018. The Company has determined that a significant portion of the provisions will not have a material impact. The Company is continuing to gather additional information and anticipates completing the accounting for the following item by December 22, 2018:
•
Global Intangible Low-Taxed Income (GILTI): The Act subjects a U.S. shareholder to current tax on GILTI of its controlled foreign corporations (CFCs) for taxable years beginning after December 31, 2017. GILTI is calculated as the excess of a U.S. shareholder’s pro-rata share of net income of CFCs over a calculated return on specific tangible assets of the CFCs. The GILTI will be offset by net operating losses in the U.S. and a corresponding valuation allowance release and will not impact the effective tax rate. The Company has elected to account for GILTI as a period charge in the period the tax arises.


27

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

The Company has not completed its assessment for the income tax effects of the Act related to the repeal of the corporate alternative minimum tax system, remeasurement of deferred tax assets and liabilities and elimination of executive compensation exemptions. However, as noted in Note 11. “Income Taxes” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, the Company was able to reasonably estimate certain effects for these items and therefore recorded provisional adjustments. The Company has analyzed the additional regulatory guidance related to executive compensation limits that was issued during the current quarter, and determined that it will not impact the adjustments that have been recorded.  Finalization of each of these is expected to occur upon the filing of the 2017 federal tax return in the fourth quarter of 2018.  As a result, the Company has not made any additional measurement-period adjustments related to these items during the nine months ended September 30, 2018. The Company is continuing to gather additional information and anticipates completing the analysis for these items by December 22, 2018, within the one-year measurement period.
(12)     Long-term Debt 
In accordance with the Plan, the Company was recapitalized with new debt and equity instruments, including 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 2025 in the table below. The Company’s total indebtedness as of September 30, 2018 and December 31, 2017 consisted of the following:
 
September 30, 2018
 
December 31, 2017
 
(Dollars in millions)
6.000% Senior Secured Notes due March 2022
$
500.0

 
$
500.0

6.375% Senior Secured Notes due March 2025
500.0

 
500.0

Senior Secured Term Loan due 2025, net of original issue discount
397.0

 
444.2

Capital lease and other obligations
51.1

 
76.0

Less: Debt issuance costs
(71.9
)
 
(59.4
)
 
1,376.2

 
1,460.8

Less: Current portion of long-term debt
42.0

 
42.1

Long-term debt
$
1,334.2

 
$
1,418.7

In connection with the Chapter 11 Cases, the Company was required to pay adequate protection payments of $29.8 million to certain first lien creditors of the Predecessor company during the period January 1 through April 1, 2017. The adequate protection payments were recorded as “Interest expense” in the unaudited condensed consolidated statements of operations and ceased upon the Effective Date. The Company did not record interest expense subsequent to the filing of the Bankruptcy Petitions for the majority non-first lien Predecessor indebtedness, which was automatically stayed in accordance with Section 502(b)(2) of the Bankruptcy Code. The amount of contractual interest stayed was $92.9 million for the period January 1, 2017 through the Effective Date.
6.000% and 6.375% Senior Secured Notes
On February 15, 2017, one of PEC’s subsidiaries entered into an indenture (the 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 (the 2025 Notes and, together with the 2022 Notes, the Senior Notes). The Senior Notes were sold on February 15, 2017 in a private transaction exempt from the registration requirements of the Securities Act of 1933. The proceeds from the Senior Notes were used to repay the Predecessor company first lien obligations.
The Senior 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 Senior Notes. Interest payments on the Senior Notes are scheduled to occur each year on March 31st and September 30th until maturity. During the three and nine months ended September 30, 2018 and the period April 2 through September 30, 2017, the Company recorded interest expense of $19.1 million, $54.0 million and $30.6 million related to the Senior Notes, respectively.
The Company may redeem the 2022 Notes, 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 2025 Notes 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. In addition, prior to the first date on which the Senior Notes are redeemable at the redemption prices noted above, the Company may also redeem some or all of the Senior Notes at a calculated make-whole premium, plus accrued and unpaid interest.


28

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

On August 9, 2018, the Company executed an amendment to the Indenture following the solicitation of consents from the requisite majorities of holders of each series of Senior Notes. The amendment permits a category of restricted payments at any time not to exceed the sum of $650.0 million, plus an additional $150.0 million per calendar year, commencing with calendar year 2019, with unused amounts in any calendar year carrying forward to and available for restricted payments in any subsequent calendar year. The Company paid consenting Senior Note holders $10.00 in cash per $1,000 principal amount of 2022 Notes or $30.00 in cash per $1,000 principal amount of 2025 Notes, which amounted to $19.8 million. Such consent fees were capitalized as additional debt issuance costs to be amortized over the respective terms of the Senior Notes. The Company also expensed $1.5 million of other fees associated with the amendment to “Interest expense” in the accompanying unaudited condensed consolidated statements of operations during the three months ended September 30, 2018.
The 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 Senior 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 Senior 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 Senior Notes are secured on a pari passu basis by the same collateral securing the Credit Agreement (as defined below), subject to certain exceptions.
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 Credit Agreement). The Credit Agreement originally provided for a $950.0 million senior secured term loan (the Senior Secured Term Loan), which was to mature in 2022 prior to the amendments described below. The proceeds from the Senior Secured Term Loan were used to repay the Predecessor company first lien obligations.
Following the voluntary prepayments and amendments described below, the Credit Agreement provided for a $400.0 million first lien senior secured term loan, which bore interest at LIBOR plus 2.75% per annum as of September 30, 2018. During the three and nine months ended September 30, 2018 and the period April 2 through September 30, 2017, the Company recorded interest expense of $5.1 million, $18.5 million and $13.1 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 term. The loan principal is payable in quarterly installments plus accrued interest through December 2024 with the remaining balance due in March 2025. The loan principal is voluntarily prepayable at 101% of the principal amount repaid if voluntarily prepaid prior to October 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 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 the Company’s Total Leverage Ratio (as defined in the 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 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.


29

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

The Credit 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 Credit Agreement are secured on a pari passu basis by the same collateral securing the Senior Notes.
Since entering into the Credit Agreement, the Company has repaid $552.0 million of the original $950.0 million loan principal amount on the Senior Secured Term Loan in various installments. On September 18, 2017, the Company entered into an amendment to the Credit Agreement which permitted 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 Credit Agreement. The incremental revolving credit facility and/or incremental term loan facilities can be in an aggregate principal amount of up to $350.0 million plus additional amounts so long as the Company is below Total Leverage Ratio requirements as set forth in the 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 Credit Agreement) would not exceed 2.00:1.00 on a pro forma basis.
During the fourth quarter of 2017, the Company entered into the incremental revolving credit facility (the Revolver) for an aggregate commitment of $350.0 million for general corporate purposes. The Company paid aggregate debt issuance costs of $4.7 million. The Revolver matures in November 2020 and permits loans which bear interest at LIBOR plus 3.25%. The Revolver is subject to a 2.00:1.00 First Lien Leverage Ratio requirement (as defined in the Credit Agreement), modified to limit unrestricted cash netting to $800.0 million. Capacity under the Revolver may also be utilized for letters of credit which incur combined fees of 3.375% per annum. Unused capacity under the Revolver bears a commitment fee of 0.5% per annum. As of September 30, 2018, the Revolver has only been utilized for letters of credit amounting to $104.4 million. Such letters of credit were primarily in support of the Company’s reclamation obligations, as further described in Note 17. “Financial Instruments and Other Guarantees.” During the three and nine months ended September 30, 2018, the Company recorded interest expense and fees of $1.3 million and $4.3 million, respectively, related to the Revolver.
On April 11, 2018, the Company entered into another amendment to the Credit Agreement which lowered the interest rate on the Senior Secured Term Loan to its current level of LIBOR plus 2.75% and eliminated an existing 1.0% LIBOR floor. The amendment also extends the maturity of the Senior Secured Term Loan by three years to 2025 and eliminates previous capital expenditure restriction covenants on both the Senior Secured Term Loan and the Revolver. In connection with this amendment, the Company voluntarily repaid $46.0 million of principal on the Senior Secured Term Loan. 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 a pro rata portion of debt issuance costs and original issue discount of $2.0 million to “Loss on early debt extinguishment” in the accompanying unaudited condensed consolidated statements of operations during the three months ended September 30, 2018. The Company also capitalized $1.0 million of deferred financing costs for fees paid to the remaining lenders and expensed $0.9 million of other fees associated with the amendment to “Interest expense” in the accompanying unaudited condensed consolidated statements of operations during the three months ended September 30, 2018.
Restricted Payments Under the Senior Notes and Credit Agreement
In addition to the $450.0 million restricted payment basket provided for under the September 18, 2017 amendment, the Credit Agreement provides a builder basket for additional restricted payments subject to a maximum Total Leverage Ratio of 2.00:1.00 (as defined in the Credit Agreement).
In addition to the $650.0 million restricted payment basket, plus an additional $150.0 million per calendar year, provided under the August 9, 2018 amendment, the Indenture provides a builder basket for restricted payments that is calculated based upon the Company’s Consolidated Net Income, and is subject to a Fixed Charge Coverage Ratio of at least 2.25:1.00 (as defined in the Indenture).
Further, under both the Indenture and Credit Agreement, additional restricted payments are permitted through a $50.0 million general basket and an annual aggregate $25.0 million basket which allows dividends and common stock repurchases. The payment of dividends and purchases of common stock under this latter basket are permitted so long as the Company’s Total Leverage Ratio would not exceed 1.25:1.00 on a pro forma basis (as defined in the Credit Agreement and Indenture).


30

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

Copies of the Indenture documents are incorporated as Exhibit 4.3 to the Current Report on Form 8-K filed by the Company with the Securities and Exchange Commission (SEC) on April 3, 2017. A copy of the 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 copies of the subsequent amendments referenced above are included as Exhibits 10.1 to the Current Reports on Form 8-K filed by the Company with the SEC on September 18, 2017, November 20, 2017, December 19, 2017 and April 11, 2018, and as Exhibit 10.1 to this Quarterly Report on Form 10-Q.
(13) Pension and Postretirement Benefit Costs
The components of net periodic pension and postretirement benefit costs, excluding the service cost for benefits earned, are included in “Net periodic benefit costs, excluding service cost” in the unaudited condensed consolidated statements of operations.
Net periodic pension (benefit) cost included the following components:
 
Successor
 
Successor
Predecessor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
(Dollars in millions)
Service cost for benefits earned
$
0.6

 
$
0.5

 
$
1.7

 
$
1.1

$
0.6

Interest cost on projected benefit obligation
7.9

 
9.4

 
23.6

 
18.7

9.7

Expected return on plan assets
(10.7
)
 
(11.2
)
 
(32.1
)
 
(22.4
)
(11.0
)
Amortization of prior service cost and net actuarial loss
—

 
—

 
—

 
—

6.4

Net periodic pension (benefit) cost
$
(2.2
)
 
$
(1.3
)
 
$
(6.8
)
 
$
(2.6
)
$
5.7

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, 2018, the Company’s qualified plans were expected to be at or above the Pension Protection Act thresholds. 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. Based upon minimum funding requirements, the Company is not required to make any contributions to its qualified pension plans in 2018; however, during the three and nine months ended September 30, 2018, the Company made discretionary contributions of $20.0 million and $62.0 million, respectively, to its qualified pension plans.
Prior to emergence from the Chapter 11 Cases, the Company incurred pension costs for two non-qualified pension plans which it no longer sponsors.
Net periodic postretirement benefit cost included the following components:
 
Successor
 
Successor
Predecessor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
(Dollars in millions)
Service cost for benefits earned
$
2.1

 
$
2.3

 
$
6.2

 
$
4.6

$
2.3

Interest cost on accumulated postretirement benefit obligation
7.0

 
8.2

 
21.2

 
16.5

8.4

Amortization of prior service cost and net actuarial loss
—

 
—

 
—

 
—

3.2

Net periodic postretirement benefit cost
$
9.1

 
$
10.5

 
$
27.4

 
$
21.1

$
13.9



31

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

(14) Accumulated Other Comprehensive Income
The following table sets forth the after-tax components of accumulated other comprehensive income and changes thereto recorded during the nine months ended September 30, 2018:
 
 
Foreign Currency Translation
Adjustment
 
Total Accumulated Other Comprehensive Income (Loss)
 
 
(Dollars in millions)
 
December 31, 2017
$
1.4

 
$
1.4

 
Current period change
(4.5
)
 
(4.5
)
 
September 30, 2018
$
(3.1
)
 
$
(3.1
)
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 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017. The following table provides additional information regarding items reclassified out of “Accumulated other comprehensive income (loss)” into earnings during the period presented below:
 
 
Amount reclassified from accumulated other comprehensive income (loss) (1)
 
 
 
 
Predecessor
 
 
Details about accumulated other comprehensive income (loss) components

 
January 1 through April 1, 2017
 
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
 
$
(5.5
)
 
Net periodic benefit costs, excluding service cost
Defined benefit pension plans
 
(6.3
)
 
Net periodic benefit costs, excluding service cost
Insignificant items
 
2.7

 
 
 
 
(9.1
)
 
Total before income taxes
 
 
3.3

 
Income tax benefit
 
 
$
(5.8
)
 
Total after income taxes
 
 
 
 
 
Prior service credit associated with postretirement plans:
 
 
 
 
Postretirement health care and life insurance benefits
 
$
2.3

 
Net periodic benefit costs, excluding service cost
Defined benefit pension plans
 
(0.1
)
 
Net periodic benefit costs, excluding service cost
 
 
2.2

 
Total before income taxes
 
 
(0.8
)
 
Income tax provision
 
 
$
1.4

 
Total after income taxes
 
 
 
 
 
Cash flow hedges:
 
 
 
 
Foreign currency cash flow hedge contracts
 
$
(16.6
)
 
Operating costs and expenses
Fuel and explosives commodity swaps
 
(11.0
)
 
Operating costs and expenses
Insignificant items
 
(0.1
)
 
 
 
 
(27.7
)
 
Total before income taxes
 
 
9.1

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


32

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

(15) Other Events
North Goonyella
The Company’s North Goonyella Mine experienced elevated gas levels beginning in September 2018, followed by a fire in a portion of the mine. The underground mine and portions of the surface area at North Goonyella remain restricted to access through exclusion zones while work continues to seal the affected area. The Queensland Mines Inspectorate has announced an investigation into the events related to North Goonyella. The Company will cooperate fully with the investigation.
During the three and nine months ended September 30, 2018, the Company recorded $9.0 million in costs related to the events at North Goonyella and a provision of $49.3 million for expected equipment losses. This provision includes $40.2 million for the estimated cost to replace leased equipment and $9.1 million related to Company-owned equipment. This provision represents the best estimate of potential loss based on the assessments made to date. In the event that no future mining occurs at North Goonyella, the Company may record additional charges for the remaining carrying value of the North Goonyella Mine and additional leased equipment of approximately $284 million and $61 million, respectively. Incremental exposures include take-or-pay obligations and other costs associated with idling or closing the mine. The Company is pursuing an insurance claim against potentially applicable insurance policies with combined property damage and business interruption loss limits of $125 million above a $50 million deductible.
Acquisitions
On September 20, 2018, Peabody entered into a definitive asset purchase agreement (Purchase Agreement) to buy the Shoal Creek metallurgical coal mine, preparation plant and supporting assets located in Alabama (Shoal Creek Mine) from Drummond Company, Inc. (Drummond) for an aggregate purchase price of $400 million, subject to customary purchase price adjustments. The Purchase Agreement excludes legacy liabilities other than reclamation and the Company will not be responsible for other liabilities arising out of or relating to the operation of Shoal Creek Mine prior to closing, including with respect to employee benefit plans and post-employment benefits. The transaction is expected to be completed in the fourth quarter of 2018, subject to regulatory approvals and certain conditions precedent, including negotiation of a new collective bargaining agreement with the union-represented workforce that eliminates participation in the multi-employer pension plan and replaces it with a 401(k) retirement plan. Peabody intends to finance the acquisition with available cash on hand.
Joint Venture
In 2014, the Company agreed to establish an unincorporated joint venture project with Glencore plc (Glencore), in which the Company holds a 50% interest, to combine the existing operations of the Company’s Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. The Company expects the project to result in several operational synergies, including improved mining productivity, lower per-unit operating costs and an extended mine life. The joint venture is expected to be formed during the first half of 2019, subject to substantive contingencies, including the requisite regulatory and permitting approvals. At such time as control over the existing operations is exchanged, the Company will account for its interest in the combined operations at fair value.
Divestitures
In June 2018, Peabody entered into an agreement to sell approximately 23 million tonnes of metallurgical coal resources adjacent to its Millennium Mine to Stanmore Coal Limited (Stanmore) for approximately $22 million. The sale was completed in July 2018 and the Company recorded a gain of $20.5 million which is included within “Net gain on disposals” in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2018. As of September 30, 2018, Stanmore has paid Peabody approximately $7 million, and the remaining balance, which will be paid over the subsequent ten months, is included in “Accounts receivable, net” in the accompanying unaudited condensed consolidated balance sheet.
On February 6, 2018, the Company sold its 50% interest in the Red Mountain Joint Venture (RMJV) with BHP Billiton Mitsui Coal Pty Ltd (BMC) for $20.0 million and recorded a gain of $7.1 million, which is included within “Net gain on disposals” in the accompanying unaudited condensed consolidated statements of operations for the nine months ended September 30, 2018. RMJV operated the coal handling and preparation plant utilized by the Company’s Millennium Mine. BMC assumed the reclamation obligations and other commitments associated with the assets of RMJV. The Millennium Mine will have continued usage of the coal handling and preparation plant and the associated rail loading facility until the end of 2019 via a coal washing take-or-pay agreement with BMC.


33

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

In January 2018, Peabody entered into an agreement to sell its share in certain surplus land assets in Queensland’s Bowen Basin to Pembroke Resources South Pty Ltd for approximately $37 million Australian dollars, net of transaction costs. The necessary approval of the Australian Foreign Investment Review Board to complete the transaction was received on March 29, 2018, satisfying all the conditions precedent to the sale, and the Company recorded a gain of $20.6 million, which is included within “Net gain on disposals” in the accompanying unaudited condensed consolidated statements of operations for the nine months ended September 30, 2018.
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 disposals” in the accompanying unaudited condensed consolidated statements of operations during the period January 1 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 interest in Metropolitan Collieries Pty Ltd, the entity that owns the Metropolitan Mine in New South Wales, Australia and the associated interest in the Port Kembla Coal Terminal, to South32 Limited (South32). The SPA provided for a cash purchase price of $200 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 period April 2 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 million and the assumption of certain liabilities. Bowie agreed to pay the Company a termination fee of $20 million (Termination Fee) in the event the Company terminated the agreement because Bowie failed to obtain financing and close the transaction. On April 12, 2016, Peabody terminated the agreement and demanded payment of the Termination Fee. 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 period April 2 through September 30, 2017.
Asset Impairment
As described in Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, the Company adjusted the book values of its property, plant, equipment and mine development assets to their respective estimated fair values at the time of fresh start reporting.
No asset impairment charges were recognized during the three and nine months ended September 30, 2018, three months ended September 30, 2017 or the period April 2 through September 30, 2017. During the period January 1 through April 1, 2017, the Company recognized asset impairment charges of $30.5 million related to terminated coal lease contracts in the Midwestern United States.
(16) 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 was considered a participating security because holders were 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. The calculation of diluted EPS for the Predecessor Company also considered the impact of its Convertible Junior Subordinated Debentures due December 2066 (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.


34

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

For all but the performance units, the potentially dilutive impact of the Company’s share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. For the performance units, their contingent features result in an assessment for any potentially dilutive common stock by using the end of the reporting period as if it were the end of the contingency period for all units granted.
Up to the time of cancellation, a conversion of the Debentures could have resulted 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 Predecessor periods presented herein because to do so would have been anti-dilutive for those periods.
The computation of diluted EPS excluded aggregate share-based compensation awards of less than 0.1 million for the three months ended September 30, 2018 and 2017, the nine months ended September 30, 2018 and the period April 2 through September 30, 2017, respectively, and approximately 0.2 million for the period January 1 through April 1, 2017, 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.


35

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
 
Successor
Predecessor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
(In millions, except per share data)
EPS numerator:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations, net of income taxes
$
83.9

 
$
233.7

 
$
412.2

 
$
335.1

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

 
23.5

 
102.5

 
138.6

—

Less: Net income attributable to noncontrolling interests
8.3

 
5.1

 
8.9

 
8.9

4.8

Income (loss) from continuing operations attributable to common stockholders, before allocation of earnings to participating securities
75.6

 
205.1

 
300.8

 
187.6

(200.3
)
Less: Earnings allocated to participating securities
—

 
51.6

 
5.7

 
50.6

—

Income (loss) from continuing operations attributable to common stockholders, after allocation of earnings to participating securities (1)
75.6

 
153.5

 
295.1

 
137.0

(200.3
)
Loss from discontinued operations, net of income taxes
(4.1
)
 
(3.7
)
 
(9.0
)
 
(6.4
)
(16.2
)
Less: Loss from discontinued operations allocated to participating securities
—

 
(0.9
)
 
(0.2
)
 
(1.7
)
—

Loss from discontinued operations attributable to common stockholders, after allocation of earnings to participating securities
(4.1
)
 
(2.8
)
 
(8.8
)
 
(4.7
)
(16.2
)
Net income (loss) attributable to common stockholders, after allocation of earnings to participating securities (1)
$
71.5

 
$
150.7

 
$
286.3

 
$
132.3

$
(216.5
)
 
 
 
 
 
 
 
 
 
EPS denominator:
 
 
 
 
 
 
 
 
Weighted average shares outstanding — basic
118.6

 
101.6

 
121.3

 
99.2

18.3

Impact of dilutive securities
1.7

 
1.5

 
1.8

 
1.0

—

Weighted average shares outstanding — diluted (2)
120.3

 
103.1

 
123.1

 
100.2

18.3

 
 
 
 
 
 
 
 
 
Basic EPS attributable to common stockholders:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
0.64

 
$
1.51

 
$
2.43

 
$
1.38

$
(10.93
)
Loss from discontinued operations
(0.04
)
 
(0.03
)
 
(0.07
)
 
(0.05
)
(0.88
)
Net income (loss) attributable to common stockholders
$
0.60

 
$
1.48

 
$
2.36

 
$
1.33

$
(11.81
)
 
 
 
 
 
 
 
 
 
Diluted EPS attributable to common stockholders:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
0.63

 
$
1.49

 
$
2.40

 
$
1.37

$
(10.93
)
Loss from discontinued operations
(0.04
)
 
(0.02
)
 
(0.07
)
 
(0.05
)
(0.88
)
Net income (loss) attributable to common stockholders
$
0.59

 
$
1.47

 
$
2.33

 
$
1.32

$
(11.81
)
(1) 
There was no reallocation adjustment for participating securities to arrive at the numerator to calculate diluted EPS for the three months ended September 30, 2018, due to the conversion of all remaining shares of Preferred Stock as of January 31, 2018. The reallocation adjustment for participating securities to arrive at the numerator to calculate diluted EPS was $0.6 million, $0.1 million and $0.4 million for the three months ended September 30, 2017, the nine months ended September 30, 2018 and the period April 2 through September 30, 2017, respectively.
(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, 2.8 million shares and 36.7 million shares related to the participating securities for the three months ended September 30, 2017, the nine months ended September 30, 2018 and the period April 2 through September 30, 2017, respectively.


36

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 January 31, 2018, all 30.0 million shares of Preferred Stock issued upon the Effective Date had been converted into 59.3 million shares of common stock, which is inclusive of the shares that had been issued for the payable in-kind preferred stock dividends.
(17) Financial Instruments and Other Guarantees
In the normal course of business, the Company is a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying condensed consolidated balance sheets. At September 30, 2018, such instruments included $1,637.3 million of surety bonds and bank guarantees and $252.2 million of letters of credit. Such financial instruments provide support for the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. The Company periodically evaluates the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. The Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in the accompanying condensed consolidated balance sheets.
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, 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, 2018, the Company’s asset retirement obligations of $703.0 million were supported by surety bonds of $1,370.9 million, as well as letters of credit issued under the Company’s receivables securitization program and Revolver amounting to $152.7 million.
Accounts Receivable Securitization
As described in Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, the Company entered into the Sixth Amended and Restated Receivables Purchase Agreement, as amended, dated as of April 3, 2017 (the Receivables Purchase Agreement) to extend the Company’s 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 collateral and the trade receivables underlying the program, from time to time. Funding capacity under the Securitization Program may also be utilized for letters of credit in support of other obligations. During 2017, the Company entered into amendments to the Securitization Program to include the receivables of additional Australian operations, reduce the restrictions on the availability of certain eligible receivables, add an additional servicer and reduce program fees.
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 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.


37

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

At September 30, 2018, the Company had no outstanding borrowings and $146.3 million of letters of credit issued 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 collateral requirement under the Securitization Program at September 30, 2018 and December 31, 2017. The Company incurred fees associated with the Securitization Program of $1.7 million during the three months ended September 30, 2018, $5.5 million during the nine months ended September 30, 2018 and $3.9 million during the period April 2 through September 30, 2017, which have been recorded as interest expense in the accompanying unaudited condensed consolidated 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 period January 1 through April 1, 2017.
Collateral Arrangements and Restricted Cash
The Company remits cash to certain regulatory authorities and other third parties as collateral for financial assurances associated with a variety of long-term obligations and commitments surrounding the mining, reclamation and shipping of its production. The Company had $323.1 million held by third parties related to such obligations at December 31, 2017. All such collateral was returned to the Company during the nine months ended September 30, 2018, largely as the result of replacing collateral balances with third-party surety bonding in Australia.
The Company also had $40.1 million of restricted cash at December 31, 2017 related to a class of pending unsecured creditors’ claims in connection with the Chapter 11 Cases. The restriction was released on March 22, 2018 after the Debtors satisfied all such claims.
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, may 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. In this regard, the Company made a $40.2 million provision during the three and nine months ended September 30, 2018 for loss of leased equipment at North Goonyella as described in Note 15. “Other Events.”
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.
(18) Commitments and Contingencies
Commitments
Unconditional Purchase Obligations
As of September 30, 2018, purchase commitments for capital expenditures were $158.5 million, all of which is obligated within the next three years, with $146.6 million obligated within the next 12 months.
There were no other material changes to the Company’s commitments from the information provided in Note 25. “Commitments and Contingencies” to the consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 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.


38

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

Litigation Relating to the Chapter 11 Cases
Ad Hoc Committee. A group of creditors (the Ad Hoc Committee) that held certain interests in the Company's prepetition indebtedness appealed the Bankruptcy Court's order confirming the Plan. On December 29, 2017, the United States District Court for the Eastern District of Missouri (the District Court) entered an order dismissing the Ad Hoc Committee's appeal, and, in the alternative, affirming the order confirming the Plan. On January 26, 2018, the Ad Hoc Committee appealed the District Court's order to the United States Court of Appeals for the Eighth Circuit (the Eighth Circuit). In its appeal, the Ad Hoc Committee does not ask the Eighth Circuit to reverse the order confirming the Plan. Instead, the Ad Hoc Committee asks the Eighth Circuit to award the Ad Hoc Committee members either unspecified damages or the right to buy an unspecified amount of Company stock at a discount. The Company does not believe the appeal is meritorious and will vigorously defend it.
Litigation Relating to Continuing Operations
Peabody Monto Coal Pty Ltd, Monto Coal 2 Pty Ltd and Peabody Energy Australia PCI Pty Ltd. In October 2007, a claim was made against Peabody Monto Coal Pty Ltd and Monto Coal 2 Pty Ltd, wholly-owned subsidiaries of Macarthur Coal Limited (Macarthur). The claim alleged that the Macarthur companies breached certain agreements by failing to develop a mine project. The claim was amended to assert that Macarthur induced the alleged breach of the Monto Coal Joint Venture Agreement. The Company acquired Macarthur and its subsidiaries in 2011. These claims, which are pending before the Supreme Court of Queensland, Australia, seek damages of up to $1.8 billion Australian dollars, plus interest and costs.
The Company asserts that the Macarthur companies were never under an obligation to develop the mine project because the project was not economically viable. The Company disputes all of the claims brought by the plaintiffs and is vigorously defending its position. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss currently cannot be reasonably estimated.
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. Berenergy contends the Company should not be able to mine the area where Berenergy and Peabody hold conflicting leases. Berenergy also contends that if the Company does mine the area, then the Company should 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 at $13.1 million by Berenergy. The Company believes that it should be allowed to mine the area conflicting with Berenergy’s leases so long as it pays for the reasonable value of the oil reserves under Berenergy’s wells that sit on its four leases, which the Company estimates to be approximately $1.0 million. This dispute currently has proceedings before the Interior Board of Land Appeals (IBLA), the Wyoming Supreme Court and a federal court in Wyoming. The Company will vigorously defend its position in all three proceedings, as it believes Berenergy’s claims are without merit and that the likelihood of a material loss resulting from the matter is remote.
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 granted on October 24, 2017, and the Bankruptcy Court ordered the plaintiffs to dismiss their lawsuits against the Company. On November 26, 2017, the plaintiffs appealed the Bankruptcy Court’s October 24, 2017 order to the District Court. On November 28, 2017, plaintiffs sought a stay pending appeal from the Bankruptcy Court, which was denied December 8, 2017. On December 19, 2017, the plaintiffs moved the District Court for a stay pending appeal. The District Court denied the stay request on September 20, 2018, and the plaintiffs appealed that decision to the U.S. Court of Appeals from the Eighth Circuit. The parties are waiting for a decision on the merits of the appeal and on the appeal of the stay. In the underlying cases pending in California, the U.S. District Court for the Northern District of California granted plaintiffs’ motion for remand and decided the cases should be heard in state court. The defendants appealed the order granting remand to the Ninth Circuit and sought a stay of the U.S. District Court for the Northern District of California decision pending completion of the Ninth Circuit appeal. The U.S. District Court for the Northern District of California granted defendants’ request for a stay pending completion of the Ninth Circuit appeal. The plaintiffs filed a motion to dismiss part of the appeal. The parties are now litigating at the Ninth Circuit whether a state or federal court should hear these lawsuits. Regardless of whether state court or federal court is the venue, the Company believes the lawsuits against it should be dismissed under enforcement of the Confirmation Order. The Company does not believe the lawsuits are meritorious and, if the lawsuits are not dismissed, the Company intends to vigorously defend them.


39

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

10th Circuit U.S. Bureau of Land Management 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 of Wyoming with directions to order BLM to revise its environmental analysis. On November 27, 2017, the District Court of Wyoming ordered BLM to revise its environmental analysis. BLM published its draft environmental analysis on July 30, 2018. The Company, along with the National Mining Association, the Wyoming Mining Association and Arch Coal, Inc., submitted comments on the draft environmental analysis by the comment deadline of October 4, 2018. The Company cannot predict when the final environmental analysis will be completed by BLM. 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.
Central Arizona Water Conservation District (CAWCD). On May 1, 2018, the Company, along with the Hopi Tribe and the UMWA, filed a lawsuit against the CAWCD. CAWCD operates, on behalf of the Bureau of Reclamation, the Central Arizona Project (CAP), an aqueduct system that brings water from the Colorado River to three counties in Arizona. CAWCD historically obtained most of CAP’s power requirements from the Navajo Generating Station (NGS), which is served by a single Peabody mine. NGS is owned by several private companies and one governmental entity. The non-governmental owners of NGS issued a statement that they do not currently intend to be the operators of the plant beyond December 2019. Recently, CAWCD made the decision to obtain a portion of CAP’s power requirements from sources other than NGS for 2020 and thereafter. The lawsuit seeks a determination that federal law requires CAWCD to obtain CAP’s power requirements from NGS.
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.
(19) 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 uses Adjusted EBITDA as the primary metric to measure the segments’ operating performance.
Adjusted EBITDA is a non-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 the segments’ operating performance, as displayed in the reconciliation below. Management believes non-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.


40

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

Reportable segment results were as follows:
 
 
Successor
 
Successor
Predecessor
 
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
 
(Dollars in millions)
Revenues:
 
 
 
 
 
 
 
 
 
Powder River Basin Mining
 
$
373.7

 
$
420.9

 
$
1,084.5

 
$
786.3

$
394.3

Midwestern U.S. Mining
 
208.5

 
207.7

 
607.7

 
402.6

193.2

Western U.S. Mining
 
156.1

 
155.7

 
439.4

 
281.1

149.7

Australian Metallurgical Mining
 
370.3

 
415.9

 
1,254.0

 
703.7

328.9

Australian Thermal Mining
 
305.1

 
265.8

 
773.9

 
505.0

224.8

Trading and Brokerage
 
22.6

 
19.4

 
52.7

 
24.6

15.0

Corporate and Other
 
(23.7
)
 
(8.2
)
 
(27.5
)
 
32.2

20.3

Total
 
$
1,412.6

 
$
1,477.2

 
$
4,184.7

 
$
2,735.5

$
1,326.2

 
 
 
 
 
 
 
 
 
 
Adjusted EBITDA:
 
 
 
 
 
 
 
 
 
Powder River Basin Mining
 
$
88.2

 
$
112.7

 
$
224.7

 
$
197.5

$
91.7

Midwestern U.S. Mining
 
38.7

 
49.5

 
111.9

 
96.0

50.0

Western U.S. Mining
 
28.5

 
34.5

 
94.4

 
79.4

50.0

Australian Metallurgical Mining
 
90.7

 
143.1

 
415.6

 
215.0

109.6

Australian Thermal Mining
 
145.3

 
97.8

 
314.5

 
203.7

75.6

Trading and Brokerage
 
(2.4
)
 
2.7

 
1.9

 
(2.4
)
8.8

Corporate and Other (1)
 
(16.9
)
 
(29.0
)
 
(57.4
)
 
(60.1
)
(44.4
)
Total
 
$
372.1

 
$
411.3

 
$
1,105.6

 
$
729.1

$
341.3

(1)  
As described in Note 15. “Other Events,” included in the three and nine months ended September 30, 2018 is the gain of $20.5 million recognized on the sale of surplus coal resources associated with the Millennium Mine. Also included in the nine months ended September 30, 2018 is the gain of $20.6 million recognized on the sale of certain surplus land assets in Queensland and the gain of $7.1 million recognized on the sale of the Company’s interest in the RMJV. Included in the period January 1 through April 1, 2017 is the gain of $19.7 million recognized on the sale of Dominion Terminal Associates.


41

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
 
Successor
Predecessor


Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 

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

$
83.9

 
$
233.7


$
412.2

 
$
335.1

$
(195.5
)
Depreciation, depletion and amortization

169.6

 
194.5


503.1

 
342.8

119.9

Asset retirement obligation expenses

12.4

 
11.3


37.9

 
22.3

14.6

Asset impairment

—

 
—


—

 
—

30.5

Provision for North Goonyella equipment loss
 
49.3

 
—

 
49.3

 
—

—

Changes in deferred tax asset valuation allowance and amortization of basis difference related to equity affiliates

(6.1
)
 
(3.4
)

(22.1
)
 
(7.7
)
(5.2
)
Interest expense

38.2

 
42.4


112.8

 
83.8

32.9

Loss on early debt extinguishment
 
—

 
12.9

 
2.0

 
12.9

—

Interest income

(10.1
)
 
(2.0
)

(24.3
)
 
(3.5
)
(2.7
)
Reorganization items, net

—

 
—


(12.8
)
 
—

627.2

Break fees related to terminated asset sales

—

 
—


—

 
(28.0
)
—

Unrealized losses (gains) on economic hedges

26.8

 
10.8


36.3

 
1.4

(16.6
)
Unrealized (gains) losses on non-coal trading derivative contracts

(0.3
)
 
1.7


1.4

 
(1.5
)
—

Coal inventory revaluation

—

 
—


—

 
67.3

—

Take-or-pay contract-based intangible recognition

(5.4
)
 
(6.5
)

(21.5
)
 
(16.4
)
—

Income tax provision (benefit)

13.8

 
(84.1
)

31.3

 
(79.4
)
(263.8
)
Total Adjusted EBITDA

$
372.1

 
$
411.3


$
1,105.6

 
$
729.1

$
341.3

(20) Related Party Transactions
On August 14, 2018, Peabody Energy Corporation entered into a share repurchase agreement (the Share Repurchase Agreement) by and among the Company and Elliott Associates, LP, Liverpool Limited Partnership and Sprayberry Investments Inc. to repurchase 7,173,601 shares of the Company’s common stock for an aggregate purchase price of approximately $300 million. Pursuant to the Share Repurchase Agreement, the purchase price per share of $41.82 represented a 1.7% discount from the closing sale price of the common stock on the New York Stock Exchange on August 13, 2018. The repurchase transaction was made in conjunction with the Company’s existing share repurchase program and closed on August 21, 2018.


42


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.
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:
•
as a result of our emergence from our Chapter 11 Cases, our historical financial information is not indicative of our future financial performance;
•
our profitability depends upon the prices we receive for our coal;
•
if a substantial number of our long-term coal supply agreements terminate, our revenues and operating profits could suffer if we are unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts;
•
the loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues;
•
our trading and hedging activities do not cover certain risks, and may expose us to earnings volatility and other risks;
•
our operating results could be adversely affected by unfavorable economic and financial market conditions;
•
our ability to collect payments from our customers could be impaired if their creditworthiness or contractual performance deteriorates;
•
risks inherent to mining could increase the cost of operating our business, and events and conditions that could occur during the course of our mining operations could have a material adverse impact on us;
•
if transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer;
•
a decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires could decrease our anticipated profitability;
•
take-or-pay arrangements within the coal industry could unfavorably affect our profitability;
•
an inability of trading, brokerage, mining or freight counterparties to fulfill the terms of their contracts with us could reduce our profitability;
•
we may not recover our investments in our mining, exploration and other assets, which may require us to recognize impairment charges related to those assets;
•
our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel;
•
we could be negatively affected if we fail to maintain satisfactory labor relations;
•
we could be adversely affected if we fail to appropriately provide financial assurances for our obligations;
•
our mining operations are extensively regulated, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal;
•
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;
•
we may be unable to obtain, renew or maintain permits necessary for our operations, which would reduce our production, cash flows and profitability;
•
our mining operations are subject to extensive forms of taxation, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal competitively;


43


•
if the assumptions underlying our asset retirement obligations for reclamation and mine closures are materially inaccurate, our costs could be significantly greater than anticipated;
•
our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable;
•
we face numerous uncertainties in estimating our economically recoverable coal reserves and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability;
•
our global operations increase our exposure to risks unique to international mining and trading operations;
•
joint ventures, partnerships or non-managed operations may not be successful and may not comply with our operating standards;
•
we may undertake further repositioning plans that would require additional charges;
•
we could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks if we sustain cyber attacks or other security breaches that disrupt our operations or result in the dissemination of proprietary or confidential information about us, our customers or other third-parties;
•
our expenditures for postretirement benefit and pension obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect;
•
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;
•
our financial performance could be adversely affected by our indebtedness;
•
despite our and our subsidiaries’ indebtedness, we may still be able to incur substantially more debt, including secured debt. This could further increase the risks associated with our indebtedness;
•
we may not be able to generate sufficient cash to service all of our indebtedness or other obligations;
•
the terms of our indenture governing our senior secured notes and the agreements and instruments governing our other post-emergence indebtedness impose restrictions that may limit our operating and financial flexibility;
•
the price of our securities may be volatile;
•
our common stock is subject to dilution and may be subject to further dilution in the future;
•
there may be circumstances in which the interests of a significant stockholder could be in conflict with other stockholders’ interests;
•
the 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;
•
we may not be able to fully utilize our deferred tax assets;
•
divestitures and acquisitions are a potentially important part of our long-term strategy, subject to our investment criteria, and involve a number of risks, any of which could cause us not to realize the anticipated benefits;
•
our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt;
•
diversity in interpretation and application of accounting literature in the mining industry may impact our reported financial results; 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, 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.


44


Overview
We are the world’s largest private-sector coal company by volume. In 2017, we produced and sold 188.3 million and 191.5 million tons of coal, respectively, from continuing operations. As of September 30, 2018, 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.
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 19. “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.
On September 20, 2018, we entered into a definitive asset purchase agreement (Purchase Agreement) to buy the Shoal Creek metallurgical coal mine, preparation plant and supporting assets located in Alabama (Shoal Creek Mine) from Drummond Company, Inc. (Drummond) for an aggregate purchase price of $400 million, subject to customary purchase price adjustments. The Purchase Agreement excludes legacy liabilities other than reclamation and we will not be responsible for other liabilities arising out of or relating to the operation of Shoal Creek Mine prior to closing, including with respect to employee benefit plans and post-employment benefits. The transaction is expected to be completed in the fourth quarter of 2018, subject to regulatory approvals and certain conditions precedent, including negotiation of a new collective bargaining agreement with the union-represented workforce that eliminates participation in the multi-employer pension plan and replaces it with a 401(k) retirement plan. We intend to finance the acquisition with available cash on hand.
Our North Goonyella Mine experienced elevated gas levels beginning in September 2018, followed by a fire in a portion of the mine. The underground mine and portions of the surface area at North Goonyella remain restricted to access through exclusion zones while work continues to seal the affected area. The Queensland Mines Inspectorate has announced an investigation into the events related to North Goonyella. We will cooperate fully with the investigation.
During the three and nine months ended September 30, 2018, we recorded $9.0 million in costs related to the events at North Goonyella and a provision of $49.3 million for expected equipment losses. This provision includes $40.2 million for the estimated cost to replace leased equipment and $9.1 million related to the cost of Company-owned equipment. This provision represents the best estimate of potential loss based on the assessments made to date. In the event that no future mining occurs at North Goonyella, we may record additional charges for the remaining carrying value of the North Goonyella Mine and additional leased equipment of approximately $284 million and $61 million, respectively. Incremental exposures include take-or-pay obligations and other costs associated with idling or closing the mine. We are pursuing an insurance claim against potentially applicable insurance policies with combined property damage and business interruption loss limits of $125 million above a $50 million deductible.
We estimate $20 to $25 million in fourth quarter containment, monitoring and planning costs, along with approximately $15 to $20 million in quarterly costs to keep the mine in idle status pending any future re-entry. We intend to take all necessary steps to work safely, progress the plan and look to mitigate costs while pursuing options for resumption of activities at the appropriate time. Mitigation actions under consideration include pursuing means to access a small quantity of metallurgical coal remaining in the stockpile, subletting excess rail and port capacity for a limited time, and analyzing reprocessing of coal waste for potential sales into the thermal market.
Multiple scenarios are being evaluated should mining be able to resume. If the next panel that is already developed is accessible, production would be targeted for the second half of 2019, whereas the southern panels access would likely extend to 2020 since that development was in early stages. We are exploring all reasonable mine-planning steps given the long-lived nature of reserves and compelling margins of the mine during times of strong industry conditions.
Filing Under Chapter 11 of the United States Bankruptcy Code
On April 13, 2016 (the Petition Date), Peabody and a majority of its wholly owned domestic subsidiaries, as well as one international subsidiary in Gibraltar (collectively 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 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.).


45


On March 17, 2017, the Bankruptcy Court entered an order, Docket No. 2763, confirming the Debtors’ Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, 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.
A group of creditors (the Ad Hoc Committee) that held certain interests in the Company's prepetition indebtedness appealed the Bankruptcy Court's order confirming the Plan. On December 29, 2017, the United States District Court for the Eastern District of Missouri (the District Court) entered an order dismissing the Ad Hoc Committee's appeal, and, in the alternative, affirming the order confirming the Plan. On January 26, 2018, the Ad Hoc Committee appealed the District Court's order to the United States Court of Appeals for the Eighth Circuit (the Eighth Circuit). In its appeal, the Ad Hoc Committee does not ask the Eighth Circuit to reverse the order confirming the Plan. Instead, the Ad Hoc Committee asks the Eighth Circuit to award the Ad Hoc Committee members either unspecified damages or the right to buy an unspecified amount of Company stock at a discount. The Company does not believe the appeal is meritorious and will vigorously defend it.
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). For additional details, refer to Note 1. “Basis of Presentation” to the unaudited condensed consolidated financial statements and Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.
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 the 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 current year.
Results of Operations
Non-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 (U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of our segment’s operating performance.
Also included in the discussion of our results of operations are references to Revenues per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each mining segment. These metrics are used by management to measure each of our mining segment’s operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the mining segment level. We consider all measures reported on a per ton basis to be operating/statistical measures; however, we include reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” contained within this Item 2.
In our discussion of liquidity and capital resources, we include references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of our financial performance and our ability to generate excess cash flow from our business operations.
We believe non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” contained within this Item 2 for definitions and reconciliations to the most comparable measures under U.S. GAAP.


46


Three and Nine Months Ended September 30, 2018 Compared to the Three and Nine Months Ended September 30, 2017
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, 2018 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.
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, 2018 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, 2018 due to quality differentials and the majority of our Australian sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Our typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.
 
 
High
 
Low
 
Average
 
September 30, 2018
Premium HCC (1)
 
$
208.50

 
$
172.00

 
$
188.55

 
$
201.50

Premium PCI coal (1)
 
$
135.20

 
$
118.15

 
$
127.99

 
$
130.10

Newcastle index thermal coal (1)
 
$
119.90

 
$
113.15

 
$
116.67

 
$
113.85

PRB 8,800 Btu/Lb coal (2)
 
$
12.55

 
$
12.25

 
$
12.41

 
$
12.50

Illinois Basin 11,500 Btu/Lb coal (2)
 
$
46.00

 
$
41.00

 
$
43.44

 
$
46.00

(1) 
Prices expressed per tonne.
(2) 
Prices expressed per ton.
With respect to seaborne metallurgical coal, global steel production increased approximately 5% during the nine months ended September 30, 2018 as compared to the prior year period. India imports increased approximately 10% through September 30, 2018, compared to the prior year driven by a 6% increase in steel production through the nine months ended September 30, 2018. Despite continued strength in Chinese steel production, metallurgical coal imports declined approximately 2 million tonnes during the nine months ended September 30, 2018, as compared to the prior year primarily due to increased reliance on domestic supplies and scrap steel.
Seaborne thermal coal demand and pricing continue to be supported by robust Asian demand, primarily in China and India. Chinese thermal coal imports rose approximately 18%, or 27 million tonnes, through September 30, 2018, compared to the prior year on sturdy industrial activity and an increase of approximately 7% in thermal coal power generation driven by economic growth and favorable weather conditions. In addition, Chinese domestic coal production has been unable to keep pace with the increased power generation and industrial demands, along with customer restocking. India’s domestic coal production has also been unable to keep pace with growing electricity demand, resulting in an increase of approximately 19%, or 20 million tonnes, in thermal coal imports through September 30, 2018, compared to the prior year. Coal inventories at India’s power plants remain below targeted levels while industrial demand is strong, supporting the need for additional thermal coal imports.
In the United States, stronger weather compared to the first nine months of 2017 drove overall electricity demand higher year-over-year through September 30, 2018. However, the combination of year-to-date coal plant retirements, weak natural gas prices and increased renewable generation have negatively impacted coal generation. Through the nine months ended September 30, 2018, utility consumption of Powder River Basin coal fell approximately 4% compared to the prior year due to ongoing pressure from retirements and regional natural gas prices that continue to trade at a discount to quoted Henry Hub natural gas spot prices.


47


Revenues for the three months ended September 30, 2018 decreased as compared to the same period in 2017 ($64.6 million) primarily due to lower sales volumes driven by demand factors mentioned above and a longwall move at our North Goonyella Mine. The impact of the decrease in sales volumes was partially offset by higher Australian realized pricing. During the three months ended September 30, 2018, we experienced year-over-year decreases in net interest expense ($25.2 million) as the result of higher cash balances, principal prepayments and debt refinancing and in depreciation, depletion and amortization ($24.9 million) primarily due to lower amortization of the fair value of certain U.S. coal supply agreements. We experienced a year-over-year increase in gains on assets disposals ($20.4 million) during the three months ended September 30, 2018.
Income from continuing operations, net of income taxes decreased by $149.8 million for the three months ended September 30, 2018 compared to the same period in the prior year. The decrease was driven by a tax benefit of $84.1 million recorded in the third quarter of 2017 related to refunds for U.S. net operating loss carrybacks as compared to a tax provision of $13.8 million recorded in the current period and a $49.3 million provision recorded in the current year period related to the equipment loss at North Goonyella. The decrease in net income attributable to common stockholders in the three months ended September 30, 2018 as compared to the same period in 2017 was less than the decrease in net income from continuing operations, net of income taxes due to dividends ($23.5 million) recorded in the prior year period related to the Series A Convertible Preferred Stock (Preferred Stock) issued by the Successor Company. Adjusted EBITDA for the three months ended September 30, 2018, reflected a year-over-year decrease of $39.2 million.
For the nine months ended September 30, 2018, income from continuing operations, net of income taxes of $412.2 million included revenues of $4,184.7 million, income from equity affiliates of $64.4 million and net gain on disposals of $49.8 million. These were offset by operating costs of $3,051.6 million, depreciation, depletion and amortization of $503.1 million, selling and administrative expenses of $119.7 million, interest expense of $112.8 million and a provision related to the North Goonyella equipment loss of $49.3 million. Net income attributable to common stockholders of $291.8 million included dividends of $102.5 million related to the conversion of the remaining shares of Preferred Stock. Adjusted EBITDA for the nine months ended September 30, 2018 was $1,105.6 million.
Income from continuing operations, net of income taxes of $335.1 million for the 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 $1,967.0 million, depreciation, depletion and amortization of $342.8 million and interest expense of $83.8 million related to the new debt instruments for the Successor Company. Net income attributable to common stockholders of $181.2 million was impacted by Preferred Stock dividends of $138.6 million. Adjusted EBITDA for the period April 2 through September 30, 2017 was $729.1 million.
For the period January 1 through April 1, 2017, loss from continuing operations, net of income taxes of $195.5 million included revenues of $1,326.2 million and a tax benefit of $263.8 million. These were offset by operating costs of $950.2 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 period January 1 through April 1, 2017 was $341.3 million.
As of September 30, 2018, our available liquidity was approximately $1.69 billion. Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of factors affecting our available liquidity.


48


Tons Sold
The following tables present tons sold by operating segment:
Three Month Comparison
Successor
 
(Decrease) Increase
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
to Volumes
 
 
 
Tons
 
%
 
(Tons in millions)
 
 
Powder River Basin Mining
31.7

 
33.7

 
(2.0
)
 
(6
)%
Midwestern U.S. Mining
4.9

 
4.9

 
—

 
—
 %
Western U.S. Mining
4.0

 
4.0

 
—

 
—
 %
Australian Metallurgical Mining
2.8

 
3.5

 
(0.7
)
 
(20
)%
Australian Thermal Mining
4.8

 
5.2

 
(0.4
)
 
(8
)%
Total tons sold from mining segments
48.2

 
51.3

 
(3.1
)
 
(6
)%
Trading and Brokerage
0.9

 
0.7

 
0.2

 
29
 %
Total tons sold
49.1

 
52.0

 
(2.9
)
 
(6
)%
Nine Month Comparison
Successor
Predecessor
 
Combined
 
(Decrease) Increase
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2017
 
to Volumes
 
 
 
 
Tons
 
%
 
(Tons in millions)
 
 
Powder River Basin Mining
90.3

 
62.2

31.0

 
93.2

 
(2.9
)
 
(3
)%
Midwestern U.S. Mining
14.3

 
9.5

4.5

 
14.0

 
0.3

 
2
 %
Western U.S. Mining
11.2

 
7.2

3.4

 
10.6

 
0.6

 
6
 %
Australian Metallurgical Mining
8.7

 
5.5

2.2

 
7.7

 
1.0

 
13
 %
Australian Thermal Mining
13.6

 
9.8

4.6

 
14.4

 
(0.8
)
 
(6
)%
Total tons sold from mining segments
138.1

 
94.2

45.7

 
139.9

 
(1.8
)
 
(1
)%
Trading and Brokerage
2.4

 
1.4

0.4

 
1.8

 
0.6

 
33
 %
Total tons sold
140.5

 
95.6

46.1

 
141.7

 
(1.2
)
 
(1
)%


49


Supplemental Financial Data
The following tables present supplemental financial data by operating segment:
Three Month Comparison
Successor
 
 
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
(Decrease) Increase
 
 
 
$
 
%
 
 
 
 
 
 
 
 
Revenues per Ton - Mining Operations (1)
 
 
 
 
 
 
 
Powder River Basin
$
11.80

 
$
12.48

 
$
(0.68
)
 
(5
)%
Midwestern U.S.
42.45

 
42.52

 
(0.07
)
 
—
 %
Western U.S.
38.91

 
38.25

 
0.66

 
2
 %
Australian Metallurgical
132.50

 
119.55

 
12.95

 
11
 %
Australian Thermal
63.50

 
51.78

 
11.72

 
23
 %
Costs per Ton - Mining Operations (1)(2)
 
 
 
 
 
 
 
Powder River Basin
$
9.01

 
$
9.13

 
$
(0.12
)
 
(1
)%
Midwestern U.S.
34.57

 
32.39

 
2.18

 
7
 %
Western U.S.
31.80

 
29.77

 
2.03

 
7
 %
Australian Metallurgical
100.14

 
78.42

 
21.72

 
28
 %
Australian Thermal
33.20

 
32.72

 
0.48

 
1
 %
Adjusted EBITDA Margin per Ton - Mining Operations (1)(2)
 
 
 
 
 
 
 
Powder River Basin
$
2.79

 
$
3.35

 
$
(0.56
)
 
(17
)%
Midwestern U.S.
7.88

 
10.13

 
(2.25
)
 
(22
)%
Western U.S.
7.11

 
8.48

 
(1.37
)
 
(16
)%
Australian Metallurgical
32.36

 
41.13

 
(8.77
)
 
(21
)%
Australian Thermal
30.30

 
19.06

 
11.24

 
59
 %
(1) 
This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
(2) 
Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; provision for North Goonyella equipment loss; take-or-pay contract-based intangible recognition; and certain other costs related to post-mining activities.


50


Nine Month Comparison
Successor
Predecessor
 
Combined
 
 
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2017
 
(Decrease) Increase
 
 
 
 
$
 
%
 
 
 
 
 
 
 
 
 
 
 
Revenues per Ton - Mining Operations (1)
 
 
 
 
 
 
 
 
 
 
Powder River Basin
$
12.01

 
$
12.65

$
12.70

 
$
12.67

 
$
(0.66
)
 
(5
)%
Midwestern U.S.
42.41

 
42.57

42.96

 
42.69

 
(0.28
)
 
(1
)%
Western U.S.
39.23

 
38.54

44.68

 
40.47

 
(1.24
)
 
(3
)%
Australian Metallurgical
143.44

 
128.89

150.22

 
135.03

 
8.41

 
6
 %
Australian Thermal
57.09

 
51.65

48.65

 
50.69

 
6.40

 
13
 %
Costs per Ton - Mining
Operations (1)(2)
 
 
 
 
 
 
 
 
 
 
Powder River Basin
$
9.52

 
$
9.47

$
9.75

 
$
9.57

 
$
(0.05
)
 
(1
)%
Midwestern U.S.
34.60

 
32.42

31.84

 
32.23

 
2.37

 
7
 %
Western U.S.
30.80

 
27.65

29.76

 
28.31

 
2.49

 
9
 %
Australian Metallurgical
95.90

 
89.53

100.16

 
92.57

 
3.33

 
4
 %
Australian Thermal
33.89

 
30.79

32.27

 
31.29

 
2.60

 
8
 %
Adjusted EBITDA Margin per Ton - Mining Operations (1)(2)
 
 
 
 
 
 
 
 
 
 
Powder River Basin
$
2.49

 
$
3.18

$
2.95

 
$
3.10

 
$
(0.61
)
 
(20
)%
Midwestern U.S.
7.81

 
10.15

11.12

 
10.46

 
(2.65
)
 
(25
)%
Western U.S.
8.43

 
10.89

14.92

 
12.16

 
(3.73
)
 
(31
)%
Australian Metallurgical
47.54

 
39.36

50.06

 
42.46

 
5.08

 
12
 %
Australian Thermal
23.20

 
20.86

16.38

 
19.40

 
3.80

 
20
 %
(1) 
This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
(2) 
Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; asset impairment; provision for North Goonyella equipment loss; 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
Successor
 
(Decrease) Increase
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
to Revenues
 
 
 
$
 
%
 
(Dollars in millions)
 
 
Powder River Basin Mining
$
373.7

 
$
420.9

 
$
(47.2
)
 
(11
)%
Midwestern U.S. Mining
208.5

 
207.7

 
0.8

 
—
 %
Western U.S. Mining
156.1

 
155.7

 
0.4

 
—
 %
Australian Metallurgical Mining
370.3

 
415.9

 
(45.6
)
 
(11
)%
Australian Thermal Mining
305.1

 
265.8

 
39.3

 
15
 %
Trading and Brokerage
22.6

 
19.4

 
3.2

 
16
 %
Corporate and Other
(23.7
)
 
(8.2
)
 
(15.5
)
 
(189
)%
Total revenues
$
1,412.6

 
$
1,477.2

 
$
(64.6
)
 
(4
)%


51


Nine Month Comparison
Successor
Predecessor
 
Combined
 
(Decrease) Increase
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2017
 
to Revenues
 
 
 
 
$
 
%
 
(Dollars in millions)
 
 
Powder River Basin Mining
$
1,084.5

 
$
786.3

$
394.3

 
$
1,180.6

 
$
(96.1
)
 
(8
)%
Midwestern U.S. Mining
607.7

 
402.6

193.2

 
595.8

 
11.9

 
2
 %
Western U.S. Mining
439.4

 
281.1

149.7

 
430.8

 
8.6

 
2
 %
Australian Metallurgical Mining
1,254.0

 
703.7

328.9

 
1,032.6

 
221.4

 
21
 %
Australian Thermal Mining
773.9

 
505.0

224.8

 
729.8

 
44.1

 
6
 %
Trading and Brokerage
52.7

 
24.6

15.0

 
39.6

 
13.1

 
33
 %
Corporate and Other
(27.5
)
 
32.2

20.3

 
52.5

 
(80.0
)
 
(152
)%
Total revenues
$
4,184.7

 
$
2,735.5

$
1,326.2

 
$
4,061.7

 
$
123.0

 
3
 %
Powder River Basin Mining. Segment revenues decreased during the three and nine months ended September 30, 2018 compared to the same periods in the prior year due to lower realized coal pricing (three months, $19.5 million; nine months, $54.3 million) and demand-based volume decreases (three months, 2.0 million tons, $27.7 million; nine months, 2.9 million tons, $41.8 million) which were impacted by natural gas pricing and plant retirements.
Midwestern U.S. Mining. Segment revenues increased during the nine months ended September 30, 2018 compared to the same period in the prior year due to favorable volume and mix variances ($13.9 million), which were slightly offset by lower realized coal pricing ($2.0 million).
Western U.S. Mining. Segment revenues increased during the nine months ended September 30, 2018 compared to the same period in the prior year primarily due to favorable volume and mix variances ($15.3 million), which were offset by lower liquidated damages received ($7.4 million).
Australian Metallurgical Mining. Segment revenues decreased during the three months ended September 30, 2018 compared to the same period in the prior year due to unfavorable volume and mix variances (0.7 million tons, $102.2 million) resulting from a longwall move at our North Goonyella Mine and the winding down of operations at our Millennium Mine. The decrease in volumes was partially offset by higher realized coal pricing ($56.6 million) due to higher spot pricing. Segment revenues increased during the nine months ended September 30, 2018 compared to the same period in the prior year primarily due to favorable volume and mix variances (1.0 million tons, $130.7 million) resulting from the 2017 impacts of Cyclone Debbie and an extended longwall move at our Metropolitan Mine, partly offset by the 2018 impacts of the longwall move at our North Goonyella Mine. The increase in revenues was also impacted by higher realized coal pricing ($90.7 million).
Australian Thermal Mining. Segment revenues increased during the three and nine months ended September 30, 2018 compared to the same periods in the prior year primarily due to higher realized coal pricing (three months, $57.1 million; nine months, $113.4 million) related to spot pricing. The increases were offset by unfavorable volume and mix variances (three months, $17.8 million; nine months, $69.3 million).
Trading and Brokerage. Segment revenues increased during the three and nine months ended September 30, 2018 compared to the same periods in the prior year due to increased prices and physical volumes shipped.
Corporate and Other. Segment revenues decreased during the three and nine months ended September 30, 2018 compared to the same periods in the prior year due to unrealized losses on economic hedges (three months, $16.0 million; nine months, $51.5 million) and the prior year receipt of break fees (nine months, $28.0 million) related to terminated asset sales which are further described in Note 15. “Other Events” of the accompanying unaudited condensed consolidated financial statements.


52


Adjusted EBITDA
The following tables present Adjusted EBITDA for each of our reporting segments:
Three Month Comparison
Successor
 
(Decrease) Increase
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
to Segment Adjusted EBITDA
 
 
 
$
 
%
 
(Dollars in millions)
 
 
Powder River Basin Mining
$
88.2

 
$
112.7

 
$
(24.5
)
 
(22
)%
Midwestern U.S. Mining
38.7

 
49.5

 
(10.8
)
 
(22
)%
Western U.S. Mining
28.5

 
34.5

 
(6.0
)
 
(17
)%
Australian Metallurgical Mining
90.7

 
143.1

 
(52.4
)
 
(37
)%
Australian Thermal Mining
145.3

 
97.8

 
47.5

 
49
 %
Trading and Brokerage
(2.4
)
 
2.7

 
(5.1
)
 
(189
)%
Corporate and Other
(16.9
)
 
(29.0
)
 
12.1

 
42
 %
Adjusted EBITDA (1)
$
372.1

 
$
411.3

 
$
(39.2
)
 
(10
)%
(1) 
This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Nine Month Comparison
Successor
Predecessor
 
Combined
 
(Decrease) Increase
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2017
 
to Segment Adjusted EBITDA
 
 
 
 
$
 
%
 
(Dollars in millions)
 
 
Powder River Basin Mining
$
224.7

 
$
197.5

$
91.7

 
$
289.2

 
$
(64.5
)
 
(22
)%
Midwestern U.S. Mining
111.9

 
96.0

50.0

 
146.0

 
(34.1
)
 
(23
)%
Western U.S. Mining
94.4

 
79.4

50.0

 
129.4

 
(35.0
)
 
(27
)%
Australian Metallurgical Mining
415.6

 
215.0

109.6

 
324.6

 
91.0

 
28
 %
Australian Thermal Mining
314.5

 
203.7

75.6

 
279.3

 
35.2

 
13
 %
Trading and Brokerage
1.9

 
(2.4
)
8.8

 
6.4

 
(4.5
)
 
(70
)%
Corporate and Other
(57.4
)
 
(60.1
)
(44.4
)
 
(104.5
)
 
47.1

 
45
 %
Adjusted EBITDA (1)
$
1,105.6

 
$
729.1

$
341.3

 
$
1,070.4

 
$
35.2

 
3
 %
(1) 
This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Powder River Basin Mining. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2018 compared to the same periods in the prior year due to lower realized coal pricing, net of sales-related costs (three months, $18.6 million; nine months, $48.0 million), lower sales volumes (three months, $13.6 million; nine months, $15.4 million) and increased pricing for fuel and explosives (three months, $5.8 million; nine months, $16.5 million). The decrease was partially offset by lower costs for materials, services and repairs (three months, $9.7 million; nine months, $9.8 million) and operating leases (three months, $2.9 million; nine months, $6.8 million).
Midwestern U.S. Mining. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2018 compared to the same periods in the prior year as the result of increased pricing for fuel and explosives (three months, $4.3 million; nine months, $12.2 million), higher materials, services and repairs costs (nine months, $9.2 million), increased labor costs (three months, $1.9 million; nine months, $7.3 million) and unfavorable production costs (three months, $6.3 million; nine months, $6.0 million) due to heavier rainfall in the current year periods.
Western U.S. Mining. Segment Adjusted EBITDA decreased during the three months ended September 30, 2018 compared to the same period in the prior year primarily due to higher materials, services and repairs costs ($10.8 million), partially offset by production efficiencies ($3.8 million). Segment Adjusted EBITDA decreased during the nine months ended September 30, 2018 compared to the same period in the prior year primarily due to higher materials, services and repairs costs ($22.7 million), the unfavorable impact of mine sequencing ($13.7 million), lower liquidated damages received ($7.4 million) and lower realized coal pricing, net of sales related costs ($5.6 million), partially offset by increased sales volumes ($8.7 million).


53


Australian Metallurgical Mining. Segment Adjusted EBITDA decreased during the three months ended September 30, 2018 compared to the same period in the prior year primarily due to unfavorable volume variances ($70.2 million) resulting from the longwall move during the current year period at our North Goonyella Mine, the winding down of operations at our Millennium Mine and unfavorable production costs at our North Goonyella Mine related to the longwall move ($56.8 million) and the events further described in Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements ($9.0 million). The decrease was partly offset by improved realized coal pricing, net of sales-related costs ($51.7 million) and improved production costs at our Metropolitan Mine ($27.6 million). Segment Adjusted EBITDA increased during the nine months ended September 30, 2018 compared to the same period in the prior year primarily due to improved realized coal pricing, net of sales-related costs ($81.1 million), favorable production costs at our Metropolitan Mine due to an extended longwall move in the prior year ($60.1 million) and favorable volume variances ($13.4 million) resulting from the impact of Cyclone Debbie in 2017. These increases were offset by unfavorable production costs at our North Goonyella Mine resulting from the longwall move ($54.4 million) and the events noted above ($9.0 million).
Australian Thermal Mining. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2018 as compared to the same periods in the prior year due to improved realized coal pricing, net of sales-related costs (three months, $52.6 million; nine months, $104.5 million), partially offset by unfavorable volume variances (three months, $17.7 million; nine months, $44.4 million) resulting from decreased sales and geologic and longwall production issues at our Wambo Mine which contributed to unfavorable production costs (nine months, $19.3 million).
Trading and Brokerage. Segment Adjusted EBITDA decreased during the three months ended September 30, 2018 compared to the same period in the prior year primarily due to lower realizations. Segment Adjusted EBITDA decreased during the nine months ended September 30, 2018 compared to the same period in the prior year primarily due to losses recorded in the current period on forward financial hedging as relevant pricing decreased.
Corporate and Other Adjusted EBITDA. The following tables present a summary of the components of Corporate and Other Adjusted EBITDA:
Three Month Comparison
Successor
 
Increase (Decrease)
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
to Adjusted EBITDA
 
 
 
$
 
%
 
(Dollars in millions)
 
 
Resource management activities (1)
$
21.3

 
$
0.4

 
$
20.9

 
5,225
 %
Selling and administrative expenses
(38.6
)
 
(33.7
)
 
(4.9
)
 
(15
)%
Acquisition costs related to Shoal Creek
(2.5
)
 
—

 
(2.5
)
 
n.m.

Corporate hedging
(1.8
)
 
7.3

 
(9.1
)
 
(125
)%
Other items, net (2)
4.7

 
(3.0
)
 
7.7

 
257
 %
Corporate and Other Adjusted EBITDA
$
(16.9
)
 
$
(29.0
)
 
$
12.1

 
42
 %
(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.


54


Nine Month Comparison
Successor
Predecessor
 
Combined
 
Increase (Decrease)
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2017
 
to Adjusted EBITDA
 
 
 
 
$
 
%
 
(Dollars in millions)
 
 
Resource management activities (1)
$
42.8

 
$
1.6

$
2.9

 
$
4.5

 
$
38.3

 
851
 %
Selling and administrative expenses
(119.7
)
 
(68.4
)
(36.3
)
 
(104.7
)
 
(15.0
)
 
(14
)%
Acquisition costs related to Shoal Creek
(2.5
)
 
—

—

 
—

 
(2.5
)
 
n.m.

Corporate hedging
(6.5
)
 
6.9

(27.6
)
 
(20.7
)
 
14.2

 
69
 %
Gain on sale of interest in Dominion Terminal Associates
—

 
—

19.7

 
19.7

 
(19.7
)
 
(100
)%
Other items, net (2)
28.5

 
(0.2
)
(3.1
)
 
(3.3
)
 
31.8

 
964
 %
Corporate and Other Adjusted EBITDA
$
(57.4
)
 
$
(60.1
)
$
(44.4
)
 
$
(104.5
)
 
$
47.1

 
45
 %
(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.
During the three months ended September 30, 2018, Corporate and Other Adjusted EBITDA was favorably impacted as compared to the same period in the prior year by resource management activities that included a gain recorded in connection with the sale of surplus coal resources associated with the Millennium Mine ($20.5 million) and an increase in “Other items, net” primarily related to improved Middlemount results driven by higher pricing ($3.5 million). These results were offset by a decrease in corporate hedging results for foreign currency due to realized losses in the current year as compared to the prior year, higher selling and administrative expenses related to charges for share-based compensation and project work around the industry and our portfolio and expenses related to our acquisition of the Shoal Creek Mine as discussed in Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements.
During the nine months ended September 30, 2018, the increase associated with resource management activities was due to gains recorded during 2018 in connection with the sale of certain surplus land assets in Queensland’s Bowen Basin ($20.6 million) and the sale of surplus coal resources associated with the Millennium Mine ($20.5 million). The increase in “Other items, net” was attributable to improved Middlemount results as compared to the prior year driven by higher pricing and sales volumes ($13.2 million), a gain recognized on the sale of our interest in the Red Mountain Joint Venture ($7.1 million) and the impact of the accounting policy election made in connection with fresh start reporting to prospectively record amounts attributable to prior service cost and actuarial valuation changes in earnings rather than accumulated other comprehensive income and amortizing to expense ($7.1 million). The increase associated with corporate hedging results, which includes foreign currency and commodity hedging, was due to a decrease in realized losses as compared to the same period in the prior year. These increases were offset by higher selling and administrative expenses as compared to the prior year resulting from charges for share-based compensation and project work around the industry and our portfolio. In addition, 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.


55


Income (Loss) From Continuing Operations, Net of Income Taxes
The following tables present income (loss) from continuing operations, net of income taxes:
Three Month Comparison
Successor
 
(Decrease) Increase
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
to Income
 
 
 
$
 
%
 
(Dollars in millions)
 
 
Adjusted EBITDA (1)
$
372.1

 
$
411.3

 
$
(39.2
)
 
(10
)%
Depreciation, depletion and amortization
(169.6
)
 
(194.5
)
 
24.9

 
13
 %
Asset retirement obligation expenses
(12.4
)
 
(11.3
)
 
(1.1
)
 
(10
)%
Provision for North Goonyella equipment loss
(49.3
)
 
—

 
(49.3
)
 
n.m.

Changes in deferred tax asset valuation allowance and amortization of basis difference related to equity affiliates
6.1

 
3.4

 
2.7

 
79
 %
Interest expense
(38.2
)
 
(42.4
)
 
4.2

 
10
 %
Loss on early debt extinguishment
—

 
(12.9
)
 
12.9

 
100
 %
Interest income
10.1

 
2.0

 
8.1

 
405
 %
Unrealized losses on economic hedges
(26.8
)
 
(10.8
)
 
(16.0
)
 
(148
)%
Unrealized gains (losses) on non-coal trading derivative contracts
0.3

 
(1.7
)
 
2.0

 
118
 %
Take-or-pay contract-based intangible recognition
5.4

 
6.5

 
(1.1
)
 
(17
)%
Income tax (provision) benefit
(13.8
)
 
84.1

 
(97.9
)
 
(116
)%
Income from continuing operations, net of income taxes
$
83.9

 
$
233.7

 
$
(149.8
)
 
(64
)%
(1) 
This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.


56


Nine Month Comparison
Successor
Predecessor
 
Combined
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2017
 
 
 
 
(Dollars in millions)
Adjusted EBITDA (1)
$
1,105.6

 
$
729.1

$
341.3

 
$
1,070.4

Depreciation, depletion and amortization
(503.1
)
 
(342.8
)
(119.9
)
 
(462.7
)
Asset retirement obligation expenses
(37.9
)
 
(22.3
)
(14.6
)
 
(36.9
)
Asset impairment
—

 
—

(30.5
)
 
(30.5
)
Provision for North Goonyella equipment loss
(49.3
)
 
—

—

 
—

Changes in deferred tax asset valuation allowance and amortization of basis difference related to equity affiliates
22.1

 
7.7

5.2

 
12.9

Interest expense
(112.8
)
 
(83.8
)
(32.9
)
 
(116.7
)
Loss on early debt extinguishment
(2.0
)
 
(12.9
)
—

 
(12.9
)
Interest income
24.3

 
3.5

2.7

 
6.2

Reorganization items, net
12.8

 
—

(627.2
)
 
(627.2
)
Break fees related to terminated asset sales
—

 
28.0

—

 
28.0

Unrealized (losses) gains on economic hedges
(36.3
)
 
(1.4
)
16.6

 
15.2

Unrealized (losses) gains on non-coal trading derivative contracts
(1.4
)
 
1.5

—

 
1.5

Coal inventory revaluation
—

 
(67.3
)
—

 
(67.3
)
Take-or-pay contract-based intangible recognition
21.5

 
16.4

—

 
16.4

Income tax (provision) benefit
(31.3
)
 
79.4

263.8

 
343.2

Income (loss) from continuing operations, net of income taxes
$
412.2

 
$
335.1

$
(195.5
)
 
$
139.6

(1) 
This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Depreciation, Depletion and Amortization. The following tables present a summary of depreciation, depletion and amortization expense by segment:
Three Month Comparison
Successor
 
Increase (Decrease)
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
to Income
 
 
 
$
 
%
 
(Dollars in millions)
 
 
Powder River Basin Mining
$
(46.4
)
 
$
(57.4
)
 
$
11.0

 
19
 %
Midwestern U.S. Mining
(29.4
)
 
(38.1
)
 
8.7

 
23
 %
Western U.S. Mining
(38.9
)
 
(32.9
)
 
(6.0
)
 
(18
)%
Australian Metallurgical Mining
(31.9
)
 
(37.1
)
 
5.2

 
14
 %
Australian Thermal Mining
(21.4
)
 
(25.7
)
 
4.3

 
17
 %
Trading and Brokerage
—

 
(0.1
)
 
0.1

 
100
 %
Corporate and Other
(1.6
)
 
(3.2
)
 
1.6

 
50
 %
Total
$
(169.6
)
 
$
(194.5
)
 
$
24.9

 
13
 %


57


Nine Month Comparison
Successor
Predecessor
 
Nine Months Ended September 30, 2018

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

 
(Dollars in millions)
Powder River Basin Mining
$
(142.6
)
 
$
(95.6
)
$
(32.0
)
Midwestern U.S. Mining
(85.2
)
 
(73.4
)
(13.3
)
Western U.S. Mining
(107.8
)
 
(57.7
)
(23.6
)
Australian Metallurgical Mining
(96.8
)
 
(64.3
)
(20.6
)
Australian Thermal Mining
(63.9
)
 
(45.5
)
(24.0
)
Trading and Brokerage
(0.1
)
 
(0.1
)
—

Corporate and Other
(6.7
)
 
(6.2
)
(6.4
)
Total
$
(503.1
)
 
$
(342.8
)
$
(119.9
)
Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments:
 
Successor
 
Successor
Predecessor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
 
 
 
Powder River Basin Mining
$
0.81

 
$
0.84

 
$
0.81

 
$
0.83

$
0.69

Midwestern U.S. Mining
0.91

 
0.83

 
0.88

 
0.78

0.61

Western U.S. Mining
2.37

 
1.06

 
2.33

 
1.06

4.30

Australian Metallurgical Mining
0.94

 
0.66

 
0.98

 
0.68

4.72

Australian Thermal Mining
1.69

 
1.73

 
1.80

 
1.72

2.62

Depreciation, depletion and amortization expense decreased during the three months ended September 30, 2018 as compared to the same period in the prior year primarily due to lower amortization of the fair value of certain U.S. coal supply agreements and decreased depreciation across the organization.
Depreciation, depletion and amortization expense for the nine months ended September 30, 2018 includes depreciation expense ($196.7 million), depletion expense ($144.8 million), amortization of the fair value of certain U.S. coal supply agreements ($78.4 million) and amortization associated with our asset retirement obligation assets ($58.2 million).
Depreciation, depletion and amortization expense for the period January 1 through April 1, 2017 included depletion expense ($62.0 million) and depreciation expense ($48.2 million).
Asset Impairment. Refer to Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements for information surrounding the impairment charges recorded during period January 1 through April 1, 2017.
Provision for North Goonyella Equipment Loss. A provision was recorded during the three and nine months ended September 30, 2018 for expected equipment losses related to the events at North Goonyella as discussed in Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements. The provision includes $40.2 million for the estimated cost to replace leased equipment and $9.1 million related to the cost of Company-owned equipment. This provision represents the best estimate of potential loss associated with these events based on assessments made to date.
Interest Expense. Interest expense decreased for the three months ended September 30, 2018 compared to the same period in the prior year, primarily due to lower expense for the Senior Secured Term Loan due 2025 as the result of principal prepayments and refinancing ($8.7 million), partially offset by increased expenses for surety bonds, letters of credit. and non-cash interest related to certain contractual arrangements ($3.8 million) and expenses related to an amendment to the indenture governing the 6.000% Senior Secured Notes due 2022 and the 6.375% Senior Secured Notes due 2025 ($1.5 million) as discussed in Note 12. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements.


58


Interest expense for the nine months ended September 30, 2018 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 2025 ($74.5 million). For additional details on debt, refer to Note 12. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements. The remainder of the interest expense ($38.3 million) for the nine months ended September 30, 2018 related to the new surety program, additional letters of credit issued under the revolver, fees for the accounts receivable securitization program, and non-cash interest related to certain contractual arrangements.
Interest expense for the period January 1 through April 1, 2017 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 during the three months ended September 30, 2017 related to the amendment of the Senior Secured Term Loan due 2025 that was entered into on September 18, 2017. The loss on early debt extinguishment recorded during the nine months ended September 30, 2018, related to the April 11, 2018 amendment of the Senior Secured Term Loan due 2025 as described in Note 12. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements.
Interest Income. The increase in interest income for the three months ended September 30, 2018 compared to the same period in the prior year, was driven by higher cash balances and the Company’s adoption of ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606) on January 1, 2018. As a result of the adoption, the Company is prospectively required to recognize a portion of consideration received for the reimbursement of certain post-mining costs as interest income rather than revenue, due to the embedded financing element within the related contract. For additional details on the adoption of ASC 606, refer to Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” and Note 3. “Revenue Recognition” to the accompanying unaudited condensed consolidated financial statements.
Interest income for the nine months ended September 30, 2018 was impacted by the same drivers as discussed above.
Reorganization Items, Net. The reorganization items recorded during the nine months ended September 30, 2018 were impacted by a favorable adjustment of the bankruptcy claims accrual. The reorganization items recorded during the period January 1 through April 1, 2017 reflected the impact of the Plan provisions and the application of fresh start reporting and other expenses recorded in connection with our Chapter 11 Cases. Refer to Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 and Note 1. “Basis of Presentation” to the accompanying unaudited condensed consolidated financial statements for further information regarding our reorganization items.
Break Fees Related to Terminated Asset Sales. During the period April 2 through September 30, 2017 we received break fees of $28.0 million related to terminated asset sales which are further described in Note 15. “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 economic hedge activities intended to hedge future coal sales. For additional information, refer to Note 3. “Revenue Recognition” to the accompanying unaudited condensed consolidated financial statements.
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 period April 2 through September 30, 2017, this adjustment was fully amortized as the inventory was sold. For additional details, refer to Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.
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 three and nine months ended September 30, 2018 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 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 and Note 8. “Intangible Contract Assets and Liabilities” to the accompanying unaudited condensed consolidated financial statements.
Income Tax (Provision) Benefit. The increase in the income tax provision for the three months ended September 30, 2018 as compared to the prior year period was primarily due to benefits recorded in the prior year related to refunds for U.S. net operating loss carrybacks. The tax provision recorded in the three and nine months ended September 30, 2018 was computed using the annual effective tax rate method and was comprised primarily of the expected statutory tax provision offset by foreign rate differential and changes in valuation allowances.


59


The income tax benefit recorded for the 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 11. “Income Taxes” in the accompanying unaudited condensed consolidated financial statements for additional information.
Net Income (Loss) Attributable to Common Stockholders
The following tables present net income (loss) attributable to common stockholders:
Three Month Comparison
Successor
 
(Decrease) Increase
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
to Income
 
 
 
$
 
%
 
(Dollars in millions)
Income from continuing operations, net of income taxes
$
83.9

 
$
233.7

 
$
(149.8
)
 
(64
)%
Loss from discontinued operations, net of income taxes
(4.1
)
 
(3.7
)
 
(0.4
)
 
(11
)%
Net income
79.8

 
230.0

 
(150.2
)
 
(65
)%
Less: Series A Convertible Preferred Stock dividends
—

 
23.5

 
(23.5
)
 
(100
)%
Less: Net income attributable to noncontrolling interests
8.3

 
5.1

 
3.2

 
63
 %
Net income attributable to common stockholders
$
71.5

 
$
201.4

 
$
(129.9
)
 
(64
)%
Nine Month Comparison
Successor
Predecessor
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
 
 
(Dollars in millions)
Income (loss) from continuing operations, net of income taxes
$
412.2

 
$
335.1

$
(195.5
)
Loss from discontinued operations, net of income taxes
(9.0
)
 
(6.4
)
(16.2
)
Net income (loss)
403.2

 
328.7

(211.7
)
Less: Series A Convertible Preferred Stock dividends
102.5

 
138.6

—

Less: Net income attributable to noncontrolling interests
8.9

 
8.9

4.8

Net income (loss) attributable to common stockholders
$
291.8

 
$
181.2

$
(216.5
)
Loss from Discontinued Operations, Net of Income Taxes. The loss from discontinued operations for the period January 1 through April 1, 2017, primarily consisted of fresh start tax adjustments ($12.1 million) as discussed in Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.
Series A Convertible Preferred Stock Dividends. The Series A Convertible Preferred Stock dividends for the three months ended September 30, 2017 were comprised of the deemed dividends granted for the Preferred Stock shares that were converted during the period. The Series A Convertible Preferred Stock dividends for the nine months ended September 30, 2018 were comprised of the deemed dividends granted for all remaining Preferred Stock shares that were converted as of January 31, 2018. The Series A Convertible Preferred Stock dividends for the period April 2 through September 30, 2017 were comprised of the deemed dividends ($135.5 million) granted for the Preferred Stock shares that were converted during the period and the first semi-annual payment of preferred dividends ($3.1 million) which was pro-rated for the period of April 3 through April 30, 2017.


60


Diluted EPS
The following tables present diluted EPS:
Three Month Comparison
Successor
 
Decrease
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
to EPS
 
 
 
$
 
%
Diluted EPS attributable to common stockholders:
 
 
 
 
 
 
 
Income from continuing operations
$
0.63

 
$
1.49

 
$
(0.86
)
 
(58
)%
Loss from discontinued operations
(0.04
)
 
(0.02
)
 
(0.02
)
 
(100
)%
Net income attributable to common stockholders
$
0.59

 
$
1.47

 
$
(0.88
)
 
(60
)%
Nine Month Comparison
Successor
Predecessor
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
 
Diluted EPS attributable to common stockholders:
 
 
 
 
Income (loss) from continuing operations
$
2.40

 
$
1.37

$
(10.93
)
Loss from discontinued operations
(0.07
)
 
(0.05
)
(0.88
)
Net income (loss) attributable to common stockholders
$
2.33

 
$
1.32

$
(11.81
)
Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 120.3 million and 103.1 million for the three months ended September 30, 2018 and 2017, respectively, and 123.1 million, 100.2 million and 18.3 million for the nine months ended September 30, 2018, the period April 2 through September 30, 2017 and the period January 1 through April 1, 2017, respectively.
Reconciliation of Non-GAAP Financial Measures
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 reconciliations below.
Three Month Comparison
Successor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
(Dollars in millions)
Income from continuing operations, net of income taxes
$
83.9

 
$
233.7

Depreciation, depletion and amortization
169.6

 
194.5

Asset retirement obligation expenses
12.4

 
11.3

Provision for North Goonyella equipment loss
49.3

 
—

Changes in deferred tax asset valuation allowance and amortization of basis difference related to equity affiliates
(6.1
)
 
(3.4
)
Interest expense
38.2

 
42.4

Loss on early debt extinguishment
—

 
12.9

Interest income
(10.1
)
 
(2.0
)
Unrealized losses on economic hedges
26.8

 
10.8

Unrealized (gains) losses on non-coal trading derivative contracts
(0.3
)
 
1.7

Take-or-pay contract-based intangible recognition
(5.4
)
 
(6.5
)
Income tax provision (benefit)
13.8

 
(84.1
)
Total Adjusted EBITDA
$
372.1

 
$
411.3



61


Nine Month Comparison
Successor
Predecessor
 
Combined
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2017
 
(Dollars in millions)
Income (loss) from continuing operations, net of income taxes
$
412.2

 
$
335.1

$
(195.5
)
 
$
139.6

Depreciation, depletion and amortization
503.1

 
342.8

119.9

 
462.7

Asset retirement obligation expenses
37.9

 
22.3

14.6

 
36.9

Asset impairment
—

 
—

30.5

 
30.5

Provision for North Goonyella equipment loss
49.3

 
—

—

 
—

Changes in deferred tax asset valuation allowance and amortization of basis difference related to equity affiliates
(22.1
)
 
(7.7
)
(5.2
)
 
(12.9
)
Interest expense
112.8

 
83.8

32.9

 
116.7

Loss on early debt extinguishment
2.0

 
12.9

—

 
12.9

Interest income
(24.3
)
 
(3.5
)
(2.7
)
 
(6.2
)
Reorganization items, net
(12.8
)
 
—

627.2

 
627.2

Break fees related to terminated asset sales
—

 
(28.0
)
—

 
(28.0
)
Unrealized losses (gains) on economic hedges
36.3

 
1.4

(16.6
)
 
(15.2
)
Unrealized losses (gains) on non-coal trading derivative contracts
1.4

 
(1.5
)
—

 
(1.5
)
Coal inventory revaluation
—

 
67.3

—

 
67.3

Take-or-pay contract-based intangible recognition
(21.5
)
 
(16.4
)
—

 
(16.4
)
Income tax provision (benefit)
31.3

 
(79.4
)
(263.8
)
 
(343.2
)
Total Adjusted EBITDA
$
1,105.6

 
$
729.1

$
341.3

 
$
1,070.4

Revenues per Ton and Adjusted EBITDA Margin per Ton are equal to revenues by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to Revenues per Ton less Adjusted EBITDA Margin per Ton, and are reconciled to operating costs and expenses as follows:
Three Month Comparison
Successor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
(Dollars in millions)
Operating costs and expenses
$
1,047.9

 
$
1,039.1

Unrealized gains (losses) on non-coal trading derivative contracts
0.3

 
(1.7
)
Take-or-pay contract-based intangible recognition
5.4

 
6.5

Net periodic benefit costs, excluding service cost
4.5

 
6.6

Total Reporting Segment Costs
$
1,058.1

 
$
1,050.5



62


Nine Month Comparison
Successor
Predecessor
 
Combined
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2017
 
(Dollars in millions)
Operating costs and expenses
$
3,051.6

 
$
1,967.0

$
950.2

 
$
2,917.2

Break fees related to terminated asset sales
—

 
28.0

—

 
28.0

Unrealized (losses) gains on non-coal trading derivative contracts
(1.4
)
 
1.5

—

 
1.5

Coal inventory revaluation
—

 
(67.3
)
—

 
(67.3
)
Take-or-pay contract-based intangible recognition
21.5

 
16.4

—

 
16.4

Net periodic benefit costs, excluding service cost
13.6

 
13.2

14.4

 
27.6

Total Reporting Segment Costs
$
3,085.3

 
$
1,958.8

$
964.6

 
$
2,923.4

The following tables present Reporting Segment Costs by reporting segment:
Three Month Comparison
Successor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
(Dollars in millions)
Powder River Basin Mining
$
285.5

 
$
308.2

Midwestern U.S. Mining
169.8

 
158.2

Western U.S. Mining
127.6

 
121.2

Australian Metallurgical Mining
279.6

 
272.8

Australian Thermal Mining
159.8

 
168.0

Trading and Brokerage
25.0

 
16.7

Corporate and Other
10.8

 
5.4

Total Reporting Segment Costs
$
1,058.1

 
$
1,050.5

Nine Month Comparison
Successor
Predecessor
 
Combined
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
Nine Months Ended September 30, 2017
 
(Dollars in millions)
Powder River Basin Mining
$
859.8

 
$
588.8

$
302.6

 
$
891.4

Midwestern U.S. Mining
495.8

 
306.6

143.2

 
449.8

Western U.S. Mining
345.0

 
201.7

99.7

 
301.4

Australian Metallurgical Mining
838.4

 
488.7

219.3

 
708.0

Australian Thermal Mining
459.4

 
301.3

149.2

 
450.5

Trading and Brokerage
50.8

 
27.0

6.2

 
33.2

Corporate and Other
36.1

 
44.7

44.4

 
89.1

Total Reporting Segment Costs
$
3,085.3

 
$
1,958.8

$
964.6

 
$
2,923.4



63


The following tables present revenues, Reporting Segment Costs, Adjusted EBITDA and tons sold by mining segment:
Three Month Comparison
Successor
 
Three Months Ended September 30, 2018
 
Powder River Basin Mining
 
Midwestern
U.S. Mining
 
Western
U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
(Amounts in millions, except per ton data)
Revenues
$
373.7

 
$
208.5

 
$
156.1

 
$
370.3

 
$
305.1

Reporting Segment Costs
285.5

 
169.8

 
127.6

 
279.6

 
159.8

Adjusted EBITDA
88.2

 
38.7

 
28.5

 
90.7

 
145.3

Tons sold
31.7

 
4.9

 
4.0

 
2.8

 
4.8

 
 
 
 
 
 
 
 
 
 
Revenues per Ton
$
11.80

 
$
42.45

 
$
38.91

 
$
132.50

 
$
63.50

Costs per Ton
9.01

 
34.57

 
31.80

 
100.14

 
33.20

Adjusted EBITDA Margin per Ton
2.79

 
7.88

 
7.11

 
32.36

 
30.30

 
Successor
 
Three Months Ended September 30, 2017
 
Powder River Basin Mining
 
Midwestern
U.S. Mining
 
Western
U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
(Amounts in millions, except per ton data)
Revenues
$
420.9

 
$
207.7

 
$
155.7

 
$
415.9

 
$
265.8

Reporting Segment Costs
308.2

 
158.2

 
121.2

 
272.8

 
168.0

Adjusted EBITDA
112.7

 
49.5

 
34.5

 
143.1

 
97.8

Tons sold
33.7

 
4.9

 
4.0

 
3.5

 
5.2

 
 
 
 
 
 
 
 
 
 
Revenues per Ton
$
12.48

 
$
42.52

 
$
38.25

 
$
119.55

 
$
51.78

Costs per Ton
9.13

 
32.39

 
29.77

 
78.42

 
32.72

Adjusted EBITDA Margin per Ton
3.35

 
10.13

 
8.48

 
41.13

 
19.06

Nine Month Comparison
Successor
 
Nine Months Ended September 30, 2018
 
Powder River Basin Mining
 
Midwestern
U.S. Mining
 
Western
U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
(Amounts in millions, except per ton data)
Revenues
$
1,084.5

 
$
607.7

 
$
439.4

 
$
1,254.0

 
$
773.9

Reporting Segment Costs
859.8

 
495.8

 
345.0

 
838.4

 
459.4

Adjusted EBITDA
224.7

 
111.9

 
94.4

 
415.6

 
314.5

Tons sold
90.3

 
14.3

 
11.2

 
8.7

 
13.6

 
 
 
 
 
 
 
 
 
 
Revenues per Ton
$
12.01

 
$
42.41

 
$
39.23

 
$
143.44

 
$
57.09

Costs per Ton
9.52

 
34.60

 
30.80

 
95.90

 
33.89

Adjusted EBITDA Margin per Ton
2.49

 
7.81

 
8.43

 
47.54

 
23.20



64


 
Successor
 
April 2 through September 30, 2017
 
Powder River Basin Mining
 
Midwestern
U.S. Mining
 
Western
U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
(Amounts in millions, except per ton data)
Revenues
$
786.3

 
$
402.6

 
$
281.1

 
$
703.7

 
$
505.0

Reporting Segment Costs
588.8

 
306.6

 
201.7

 
488.7

 
301.3

Adjusted EBITDA
197.5

 
96.0

 
79.4

 
215.0

 
203.7

Tons sold
62.2

 
9.5

 
7.2

 
5.5

 
9.8

 
 
 
 
 
 
 
 
 
 
Revenues per Ton
$
12.65

 
$
42.57

 
$
38.54

 
$
128.89

 
$
51.65

Costs per Ton
9.47

 
32.42

 
27.65

 
89.53

 
30.79

Adjusted EBITDA Margin per Ton
3.18

 
10.15

 
10.89

 
39.36

 
20.86

 
Predecessor
 
January 1 through April 1, 2017
 
Powder River Basin Mining
 
Midwestern
U.S. Mining
 
Western
U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
(Amounts in millions, except per ton data)
Revenues
$
394.3

 
$
193.2

 
$
149.7

 
$
328.9

 
$
224.8

Reporting Segment Costs
302.6

 
143.2

 
99.7

 
219.3

 
149.2

Adjusted EBITDA
91.7

 
50.0

 
50.0

 
109.6

 
75.6

Tons sold
31.0

 
4.5

 
3.4

 
2.2

 
4.6

 
 
 
 
 
 
 
 
 
 
Revenues per Ton
$
12.70

 
$
42.96

 
$
44.68

 
$
150.22

 
$
48.65

Costs per Ton
9.75

 
31.84

 
29.76

 
100.16

 
32.27

Adjusted EBITDA Margin per Ton
2.95

 
11.12

 
14.92

 
50.06

 
16.38

 
Combined
 
Nine Months Ended September 30, 2017
 
Powder River Basin Mining
 
Midwestern
U.S. Mining
 
Western
U.S. Mining
 
Australian Metallurgical Mining
 
Australian Thermal Mining
 
(Amounts in millions, except per ton data)
Revenues
$
1,180.6

 
$
595.8

 
$
430.8

 
$
1,032.6

 
$
729.8

Reporting Segment Costs
891.4

 
449.8

 
301.4

 
708.0

 
450.5

Adjusted EBITDA
289.2

 
146.0

 
129.4

 
324.6

 
279.3

Tons sold
93.2

 
14.0

 
10.6

 
7.7

 
14.4

 
 
 
 
 
 
 
 
 
 
Revenues per Ton
$
12.67

 
$
42.69

 
$
40.47

 
$
135.03

 
$
50.69

Costs per Ton
9.57

 
32.23

 
28.31

 
92.57

 
31.29

Adjusted EBITDA Margin per Ton
3.10

 
10.46

 
12.16

 
42.46

 
19.40



65


Free Cash Flow is defined as net cash provided by operating activities less net cash used in investing activities and excludes cash outflows related to business combinations. See the table below for a reconciliation of Free Cash Flow to its most comparable measure under U.S. GAAP.
Nine Month Comparison
Successor
Predecessor
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
(Dollars in millions)
Net cash provided by (used in) operating activities
$
1,260.8

 
$
313.7

$
(813.0
)
Net cash (used in) provided by investing activities
(65.5
)
 
(34.9
)
15.1

Free Cash Flow
$
1,195.3

 
$
278.8

$
(797.9
)
Outlook
As part of its normal planning and forecasting process, Peabody utilizes a broad 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 for key demand centers for coal, electricity generation and steel. Specific to the U.S., the Company evaluates individual plant needs, including expected retirements, on a plant by plant basis in developing its demand models. Supply models and 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
Seaborne Thermal Coal. Strong seaborne thermal coal supply-demand dynamics remained in place during the third quarter with the 6,000-specification average prompt Newcastle thermal pricing rising 13% to approximately $117 per tonne from the second quarter of 2018. At the same time, the prompt API 5 5,500 quality thermal product declined approximately $6 to an average of $69 per tonne for the third quarter.
China and India continue to drive seaborne thermal demand growth with ASEAN nations also representing persistent import strength. Through September, China thermal coal imports rose 27 million tonnes, supported by an approximately 7% increase in thermal power generation that has outpaced domestic coal production growth. Through September, India thermal imports increased 20 million tonnes on strong industrial demand and coal power generation, despite an approximately 8% increase in domestic production. In addition, ASEAN thermal import demand rose 9% through September over the prior year as additional new coal-fueled generation came online.
Through September, Australian thermal exports increased 2%, while lower-quality Indonesian coal exports rose 12% compared to the prior year. In addition, U.S. seaborne thermal coal exports have benefited from the higher pricing environment, rising 13 million tonnes through August.
Seaborne Metallurgical Coal. Within metallurgical coal fundamentals, third quarter Premium HCC spot pricing continued to be favorable to historical averages and was in line with the prior quarter. Pricing reached a high of $209 per tonne during the third quarter with an average of $189 per tonne. The third-quarter index settlement price for Premium HCC was $188 per tonne compared to $170 per tonne in the prior year. The benchmark for low-vol PCI in the third quarter was settled at $150 per tonne compared to the benchmark settlements of $115 and $127 per tonne in the prior year. In addition, the fourth quarter benchmark price for low-vol PCI has been settled at $139 per tonne.
Seaborne metallurgical coal pricing has been supported by a 5% increase in global steel production through September. India seaborne metallurgical coal demand increased 4 million tonnes compared to the prior year through September, more than offsetting a 2 million tonne decline in Chinese imports.
Regarding seaborne metallurgical coal supply, overall growth remains limited with the greatest increases from Australia and the U.S. While Australian metallurgical coal export rose 2 million tonnes year-to-date through September, lower 2017 volumes reflect the impacts of Cyclone Debbie.


66


U.S. Thermal Coal. In the U.S., coal demand has been impacted by weak natural gas pricing, coal plant retirements and increased renewable generation, despite a 4% increase in total generation load over the prior year through September. Average Henry Hub gas prices fell approximately $0.20 per mmbtu through September compared to the prior year. Overall, U.S. coal production has declined 12 million tons year-to-date through September compared to prior year levels. Lower production and increased thermal coal exports have reduced overall utility stockpiles to approximately 100 million tons, the lowest levels since 2005.
Long-Term Outlook
There were no significant changes to our Long-term Outlook subsequent to December 31, 2017. 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, 2017.
Regulatory Update
Other than as described in the following section, there were no significant changes to our regulatory matters subsequent to December 31, 2017. 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, 2017.
Regulatory Matters - U.S.
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 United States Environmental Protection Agency (EPA). Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the CWA section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.
A final rule defining the scope of waters protected under the Clean Water Act (commonly called the Waters of the United States (WOTUS Rule)), was published by the EPA and the Corps in June 2015. The U.S. Court of Appeals for the Sixth Circuit stayed the 2015 Rule nationwide on October 9, 2015, and that stay remained in place until early 2018. Before the Sixth Circuit lifted its stay, EPA and the Corps finalized a rule, also known as the “Delay Rule,” on February 6, 2018 that amended the 2015 WOTUS Rule by specifying that the Rule does not apply until February 6, 2020. Consequently, the pre-2015 definitions of WOTUS remained in effect nationwide. However, in August, 2018 a U.S. District Court in South Carolina overturned the “Delay Rule” saying the administration had failed to offer the public a proper opportunity to comment. That put the 2015 rule in effect in 26 states, but not in the other 24 states where federal court injunctions are still in place. In September 2018, a federal district court judge in Texas granted an injunction request for three more states; Texas, Louisiana and Mississippi. Also that month, industry filed a motion in a Georgia district court to expand its previous injunction, which stopped implementation in 11 states, to apply nationwide. Other district courts may also consider the issue in the coming months. EPA and the Corps are still in the process of repealing the 2015 WOTUS Rule and developing a replacement rule. The agencies proposed to repeal the 2015 Rule in July 2017, but they have not yet finalized a repeal action, and the final rule is expected before the end of this year. Further, EPA and the Corps have indicated that they plan to propose a replacement definition of WOTUS, which is expected prior to the end of the year. Depending on the outcome of litigation and/or rulemaking activity, the scope of CWA authority could increase, decrease, or stay the same relative to the current, pre-2015 definitions of WOTUS. An expansion of CWA authority may impact our operations in some areas by way of additional requirements.
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.


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Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to particulate matter (PM), nitrogen dioxide, ozone and sulfur dioxide (SO2). In recent years the United States Environmental Protection Agency (EPA) has adopted more stringent national ambient air quality standards (NAAQS) for PM, nitrogen oxide, ozone and SO2. It is possible that these modifications as well as future modifications to NAAQS could directly or indirectly impact our mining operations in a manner that includes, but is not limited to, designating new nonattainment areas or expanding existing nonattainment areas, serving as a basis for changes in vehicle emission standards or prompting additional local control measures pursuant to state implementation plans required to address revised NAAQS.
In 2009, the EPA 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 in 2012. In 2015, the EPA issued a final rule setting the ozone NAAQS at 70 parts per billion (ppb). (80 Fed. Reg. 65,292, (Oct. 25, 2015)). This final rule has been challenged in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit), however, the case had been held in abeyance pending the EPA’s review of the final rule. In August 2018, EPA said it would continue with the rule, meaning the lawsuit was revived and arguments are likely this fall. More stringent ozone standards would require new state implementation plans to be developed and filed with the EPA and may trigger additional control technology for mining equipment, or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to the implementation for other NAAQS for nitrogen oxide and SO2.
The CAA also indirectly, but significantly affects the U.S. coal industry by extensively regulating the air emissions of SO2, nitrogen oxides, mercury, PM and other substances emitted by coal-fueled electricity generating plants, imposing more capital and operating costs on such facilities. In addition, other CAA programs may require further emission reductions to address the interstate transport of air pollution or regional haze. The air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, interstate transport rules such as the Cross-State Air Pollution Rule (CSAPR) and the CSAPR Update 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.
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. At present, however, the EPA does not directly regulate such emissions.
Final Rule Regulating Carbon Dioxide Emissions From Existing Fossil Fuel-Fired EGUs. On October 23, 2015, the EPA published a final rule in the Federal Register regulating CO2 emissions from existing fossil fuel-fired EGUs under section 111(d) of the CAA (80 Fed. Reg. 64,662 (Oct. 23, 2015)). The rule (known as the Clean Power Plan (CPP)) establishes emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs. These final guidelines require that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline).
Following Federal Register publication, 39 separate petitions for review of the CPP by approximately 157 entities were filed in the D.C. Circuit. The petitions reflect challenges by 27 states and governmental entities, as well as challenges by utilities, industry groups, trade associations, coal companies, and other entities. The lawsuits were consolidated with the case filed by West Virginia and Texas (in which other states have also joined). (D.C. Cir. No. 15-1363). On October 29, 2015, we filed a motion to intervene in the case filed by West Virginia and Texas, in support of the petitioning states. The motion was granted on January 11, 2016. Numerous states and cities have also been allowed to intervene in support of the EPA.
On February 9, 2016, the Supreme Court granted a motion to stay implementation of the CPP until its legal challenges are resolved. Thereafter, oral arguments in the case were heard in the D.C. Circuit sitting en banc by ten active D.C. Circuit judges, but to date, the D.C. Circuit has not issued an opinion. On April 28, 2017, the D.C. Circuit granted a motion by the EPA to hold the case in abeyance for 60 days while the Agency reconsidered the rule. The D.C. Circuit has renewed the abeyance several times, but the most recent abeyance expired on August 27, 2018. The D.C. Circuit is considering filings by the EPA and the petitioners that ask it to issue an additional abeyance over the opposition of some states and their supporters that asked the court to issue a decision on the merits.
In October 2017, the EPA proposed to change its legal interpretation of CAA section 111(d), the authority that the Agency relied on for the 2015 CPP. (82 Fed. Reg. 48,035 (Oct. 16, 2017)). If this proposed reinterpretation is finalized by the EPA, the CPP would be repealed.


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The EPA relied on the proposed reinterpretation until August 2018, when it proposed the Affordable Clean Energy (ACE) Rule, which proposes to replace the CPP with a system where states will develop emissions reduction plans using Best System of Emission Reduction (BSER) measures, which are essentially efficiency heat rate improvements, and the EPA will approve the state plans if they use EPA-approved candidate technologies. Changes in the New Source Review (NSR) program are also proposed to allow efficiency improvements to be made without triggering NSR requirements. If adopted, ACE will provide states with the flexibility to regulate on a plant-by-plant basis with a focus on coal-fired EGUs. Public comments on the rule are due October 31, 2018, and the EPA is expected to finalize the rule in the first half of 2019. Litigation may be initiated, however, and the final timeline may shift.
Federal Coal Leasing Moratorium. President Trump’s Executive Order on Promoting Energy Independence and Economic Growth (EI Order) signed on March 28, 2017, 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. Environmental groups took the issue to court and in September 2018, Wyoming and Montana opposed the suits in court and defended against the freeze possibly being reinstated.
National Environmental Policy Act (NEPA). NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. We must provide information to agencies when we propose actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. The White House Council on Environmental Quality (CEQ) issued an Advance Notice of Proposed Rulemaking in June 2018 seeking comment on a number of ways to streamline and improve the NEPA process. The comment period closed in August 2018. It is unclear how far reaching the changes will be and if they will be able to withstand expected court challenges.
Endangered Species Act (ESA). The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on our costs or our ability to mine some of our properties in accordance with our current mining plans. The Interior Department issued three proposed rules in August 2018 aiming to streamline and update the ESA.
Wyoming Land Quality Division Self-Bonding Rules. On August 20, 2018, the Wyoming Land Quality Division, through the Land Quality Advisory Board, offered for public comment proposed changes to self-bonding rules related to reclamation obligations. The proposal included requiring that the self-bonding guarantor be the ultimate parent company and that the maximum amount of bonding be limited to 75% of the company’s calculated bond amount. Additionally, the proposal required the self-bonding party to qualify using ratings issued by nationally recognized credit rating services, such as the Moody’s Investor Service or Standard and Poor’s Corporation. This requirement would replace the current qualifying tests using a bonding party’s audited financial statements.
The Company currently meets all its bonding obligations in Wyoming through the use of commercial surety bonds. If the proposed rule is adopted, the Company would not qualify for self-bonding based on its current credit rating. The proposed rule was approved by the Wyoming Land Quality Advisory Board on September 19, 2018, and will now be considered by the Environmental Quality Council for formal rulemaking. 
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.
A small number of coal mine workers in Queensland and New South Wales have been diagnosed with coal worker’s pneumoconiosis (CWP, also known as black lung) following decades of assumed eradication of the disease. This has led the Queensland government to sponsor review of the system of screening coal mine workers for the disease with a view to improving early detection. The Queensland government has instituted increased reporting requirements for dust monitoring results, broader coal mine worker health assessment requirements and voluntary retirement examinations for coal mine workers to be arranged by the relevant employer and further reform may follow. Peabody has undertaken a review of its practices and offered its Queensland workers the opportunity for additional CWP screening.


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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 us, coal mine workers, the Department of Natural Resources and others. The Queensland Parliamentary Committee conducting the inquiry issued its final report on May 29, 2017. In finding that it is highly unlikely CWP was ever eradicated in Queensland, the Committee 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 0.05 mg/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 Parliamentary Portfolio Committee for review.
On September 7, 2017, the Queensland Parliament introduced a bill to amend legislation which, if passed, would increase civil penalties for mining companies breaching their obligations under the Coal Mining Safety and Health Act 1999. The proposed amendments contained in the Mines Legislation (Resources Safety) Amendment Bill (MLA Bill) 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 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.
The MLA Bill lapsed on October 29, 2017 when a Queensland state election was called. However, on March 20, 2018 the MLA Bill was re-introduced to Parliament and the legislative amendments are expected to commence later in 2018.
Sydney Water Catchment Areas. The New South Wales government has commissioned an independent expert panel to advise the Department of Planning and Environment on the impact of underground mining activities in Sydney’s water catchment areas. This area includes Peabody’s Metropolitan Mine.  The panel is due to issue an interim report in November 2018, with a final report to follow in December 2018.  The panel has been tasked with (i) undertaking an initial review and report on specific coal mining activities at the Metropolitan and Dendrobium coal mines in the Greater Sydney Water Catchment Special Areas; (ii) undertaking a review of current coal mining in the Greater Sydney Water Catchment Special Areas with a particular focus on risks to the quantity of water available, the environmental consequences for swamps and the issue of cumulative impacts, including with respect to the Russell Vale and Wongawilli coal mines as well as the Metropolitan and Dendrobium coal mines; and (iii) providing advice as required to the Department of Planning and Environment on mining activities in the Greater Sydney Water Catchment Special Areas, including with respect to the Russell Vale and Wongawilli coal mines as well as the Metropolitan and Dendrobium coal mines.
Mining Rehabilitation (Reclamation). Mine reclamation is regulated by state specific legislation. As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding to the relevant state government as a safeguard to cover the costs of reclamation in circumstances where mine operators are unable to do so. Self-bonding is not permitted. Our mines provide financial assurance to the relevant authorities which is calculated in accordance with current regulatory requirements. This financial assurance is in the form of cash, surety bonds or bank guarantees which are supported by a combination of cash collateral, deeds of indemnity and guarantee and letters of credit issued under our credit facility and accounts receivable securitization program. We operate in both the Queensland and New South Wales state jurisdictions.


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On February 15, 2018, the Queensland Government re-introduced the Mineral and Energy Resources (Financial Provisioning) Bill 2018 (MERFP Bill) to Parliament, which contained proposed legislation to give effect to certain policy reforms, including a remodeled financial assurance (FA) framework that takes into account the financial strength of the Environmental Authority 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 cost calculations, and regular monitoring and reporting measures for progressive mine rehabilitation. In June 2018, the government released draft regulations and a number of guidelines on the operation of certain aspects of the proposed new law. Peabody has made submissions to the government as part of the consultation process for these draft regulations and guidelines and will continue to assess the impact of the proposed FA framework and progressive rehabilitation and closure planning requirements on its business, including the extent of retrospective protection. It is expected that the MERFP Bill will be enacted and commence in late 2018 or early 2019 with a three-year transition period.
Planning and Environment. Effective from March 1, 2018, the Environmental Planning and Assessment Act 1979 (EPA Act) was amended to introduce a number of changes to planning and environment laws in New South Wales. One of these changes was to revoke a process for modifying development approvals under section 75W of the EPA Act. As a result, new development approvals will need to be obtained in lieu of modification of existing approvals, which could take additional time to achieve. Peabody and other mining companies will be required to comply with this in respect of future development approvals in New South Wales. On June 29, 2018, the Environmental Planning and Assessment (Miscellaneous) Regulation 2018 became effective. The changes include further extending an existing transitional provision dealing with modifications of previously approved Part 3A projects that relate to substantially the same development as last modified, to proposed modifications that involve minimal environmental impact or modification of consents granted by the Land and Environment Court.
National Energy Guarantee. In October 2017, the Australian Federal Government released a plan aimed at delivering an affordable and reliable energy system that meets Australia’s international commitments to emissions reduction. The plan was formerly referred to as the National Energy Guarantee (NEG) and was aimed at changing the National Electricity Market and associated legislative framework. The NEG was abandoned in September 2018. The government has confirmed that it remains committed to meeting Australia’s Paris Agreement targets but that the focus of energy policy will be on driving down electricity prices. The opposition party has indicated that it will adopt a NEG-style energy policy if it wins the next Federal election.
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, borrowings under our credit facilities and, from time to time, the issuance of securities. 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. We have also used cash for dividends and share repurchases. We believe that our capital structure 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 (excluding repurchases authorized under the Repurchase Program described in “Unregistered Sales of Equity Securities and Use of Proceeds” in Part II, Item 2 of this report), 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 various debt obligations, 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.


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Total Indebtedness. Our total indebtedness as of September 30, 2018 and December 31, 2017 consisted of the following:
 
September 30, 2018
 
December 31, 2017
 
(Dollars in millions)
6.000% Senior Secured Notes due March 2022
$
500.0

 
$
500.0

6.375% Senior Secured Notes due March 2025
500.0

 
500.0

Senior Secured Term Loan due 2025, net of original issue discount
397.0

 
444.2

Capital lease and other obligations
51.1

 
76.0

Less: Debt issuance costs
(71.9
)
 
(59.4
)
 
1,376.2

 
1,460.8

Less: Current portion of long-term debt
42.0

 
42.1

Long-term debt
$
1,334.2

 
$
1,418.7

Refer to Note 12. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements for further information regarding our indebtedness.
Liquidity
As of September 30, 2018, our available liquidity was $1,694.6 million which was comprised of cash and cash equivalents and availability under our revolver and accounts receivable securitization program as described below. As of September 30, 2018, our cash balances totaled $1,371.0 million, including approximately $973.3 million held by U.S. subsidiaries, $385.9 million held by Australian subsidiaries, and the remaining balance held by other 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. During the nine months ended September 30, 2018, we repatriated to the U.S. approximately $1.1 billion previously held by foreign subsidiaries. If we repatriate additional foreign-held cash in the future, we do not expect restrictions or potential taxes to have a material effect on our overall liquidity.
During the nine months ended September 30, 2018, collateral balances of $323.1 million related primarily to reclamation assurance for our Australian mines, and various port, rail and other contract performance requirements in Australia were returned to the Company as a result of implementing third-party surety bonding in Australia.
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 Senior Notes and Credit Agreement
As described in Note 12. “Long-term Debt” of the accompanying unaudited condensed consolidated financial statements, on the Effective Date, the proceeds from the 6.000% Senior Secured Notes due March 2022 and the 6.375% Senior Secured Notes due March 2025 (collectively, the Senior Notes) and the Senior Secured Term Loan under the Credit Agreement (the Credit Agreement) were used to repay the Predecessor company first lien obligations. The proceeds from the Senior 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.
Since entering into the Credit Agreement, we have repaid $553.0 million of the original $950.0 million loan principal on the Senior Secured Term Loan through September 30, 2018 in various installments. The Credit Agreement has been amended at various dates since its inception primarily to (i) lower the interest rate on the Senior Secured Term Loan from LIBOR plus 4.50% per annum with a 1.00% LIBOR floor to LIBOR plus 2.75% with no floor, (ii) extend the maturity of the Senior Secured Term Loan by three years to 2025, (iii) allow for an incremental revolving credit facility and one or more incremental term loans in an aggregate principal amount of up to $350.0 million plus additional amounts so long as the Company maintains compliance with the Total Leverage Ratio, as defined in the Credit Agreement, (iv) make 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 Credit Agreement, would not exceed 2.00:1.00 on a pro forma basis, and (v) eliminate the previous capital expenditure restriction covenants on both the Senior Secured Term Loan and the Revolver (as defined below).


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Interest payments on the Senior Notes are scheduled to occur each year on March 31 and September 30 until maturity. We may redeem the 6.000% 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. We may also redeem some or all of the Senior Notes by means of a tender offer or open market repurchases.
The Senior Secured Term Loan principal is payable in quarterly installments plus accrued interest through December 2024 with the remaining balance due in March 2025. The loan principal is voluntarily prepayable at 101% of the principal amount repaid if voluntarily prepaid prior to October 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 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 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 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.
During the fourth quarter of 2017, we entered into the incremental revolving credit facility permitted under the Credit Agreement (the Revolver) for an aggregate commitment of $350.0 million for general corporate purposes. The Revolver matures in November 2020 and permits loans which bear interest at LIBOR plus 3.25%. The Revolver is subject to a 2.00:1.00 First Lien Leverage Ratio requirement, modified to limit unrestricted cash netting to $800.0 million. Capacity under the Revolver may also be utilized for letters of credit which incur combined fees of 3.375% per annum. Unused capacity under the Revolver bears a commitment fee of 0.5% per annum. As of September 30, 2018, the Revolver had utilized for letters of credit amounting to $104.4 million. Such letters of credit were primarily in support of our reclamation obligations.
In addition to the $450.0 million restricted payment basket provided for under the amendments described above, the Credit Agreement provides a builder basket for additional restricted payments subject to a maximum Total Leverage Ratio of 2.00:1.00 (as defined in the Credit Agreement).
The Indenture provides a builder basket for restricted payments that is calculated based upon our Consolidated Net Income, and is subject to a Fixed Charge Coverage Ratio of at least 2.25:1.00 (as defined in the Indenture).
Under both the Indenture and Credit Agreement, additional restricted payments are permitted through a $50.0 million general basket and an annual aggregate $25.0 million basket which allows dividends and common stock repurchases. The payment of dividends and purchases of common stock under this latter basket are permitted so long as our Total Leverage Ratio would not exceed 1.25:1.00 on a pro forma basis (as defined in the Credit Agreement and Indenture).
On August 9, 2018, we executed an amendment to the Indenture following the solicitation of consents from the requisite majorities of holders of each series of Senior Notes. The amendment permits an additional category of restricted payments at any time not to exceed the sum of $650.0 million, plus an additional $150.0 million per calendar year, commencing with calendar year 2019, with unused amounts in any calendar year carrying forward to and available for restricted payments in any subsequent calendar year. We paid consenting Senior Note holders $10.00 in cash per $1,000 principal amount of 2022 Notes or $30.00 in cash per $1,000 principal amount of 2025 Notes, which amounted to $19.8 million.
Accounts Receivable Securitization
As described in Note 17. “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 accounts receivable securitization facility previously in place and expand that facility to include certain receivables from our Australian operations. The term of the accounts receivable securitization program (Securitization Program) ends on April 3, 2020, subject to certain liquidity requirements and other customary events of default. 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 utilized for letters of credit in support of other obligations.
At September 30, 2018, we had no outstanding borrowings and $146.3 million of letters of credit issued under the Securitization Program. The letters of credit were primarily in support of portions of our obligations for reclamation, workers’ compensation and postretirement benefits.


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Capital Requirements
On September 20, 2018, we entered into a definitive asset purchase agreement to buy the Shoal Creek metallurgical coal mine located in Alabama from Drummond for an aggregate purchase price of $400 million, subject to customary purchase price adjustments. The transaction is expected to be completed in the fourth quarter of 2018, subject to certain conditions precedent and regulatory approvals. We intend to finance the acquisition with available cash on hand.
There were no other 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, 2017. The Company has no minimum pension funding requirement for 2018, but made discretionary contributions of $62.0 million to its qualified plans during the nine months ended September 30, 2018.
Contractual Obligations
There were no 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, 2017 and Item 2 of our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018.
Historical Cash Flows
The following table summarizes our cash flows for the nine months ended September 30, 2018 and the periods April 2 through September 30, 2017 and January 1 through April 1, 2017, as reported in the accompanying unaudited condensed consolidated financial statements:
 
Successor
Predecessor
 
Nine Months Ended September 30, 2018
 
April 2 through September 30, 2017
January 1 through April 1, 2017
 
(Dollars in millions)
Net cash provided by (used in) operating activities
$
1,260.8

 
$
313.7

$
(813.0
)
Net cash (used in) provided by investing activities
(65.5
)
 
(34.9
)
15.1

Net cash (used in) provided by financing activities
(863.1
)
 
(424.1
)
952.3

Net change in cash, cash equivalents and restricted cash
332.2

 
(145.3
)
154.4

Cash, cash equivalents and restricted cash at beginning of period
1,070.2

 
1,095.6

941.2

Cash, cash equivalents and restricted cash at end of period
$
1,402.4

 
$
950.3

$
1,095.6

Cash Flow - Successor
Cash provided by operating activities in the nine months ended September 30, 2018 resulted from cash generated from our mining operations and $323.1 million of collateral returned as we replaced collateral with other forms of financial assurance, partially offset by $62.0 million of discretionary contributions to our qualified pension plans.
Cash provided by operating activities in the 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 nine months ended September 30, 2018 resulted from $193.5 million of additions to property, plant, equipment and mine development, which was partially offset by $81.1 million of cash receipts from Middlemount and proceeds from disposals of assets of $69.0 million.
Cash used in investing activities in the period April 2, 2017 through September 30, 2017 resulted from $66.8 million of additions to property, plant, equipment and mine development, which was partially offset by $35.2 million of cash receipts from Middlemount.
Cash used in financing activities in the nine months ended September 30, 2018 resulted primarily from $699.6 million of repurchases of common stock and $44.6 million of stock dividends paid in accordance with our shareholder return initiatives, $73.0 million of payments of long-term debt, and $21.2 million of debt issuance costs, primarily related to an amendment to the Indenture.


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Cash used in financing activities in the 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.
Cash Flow - Predecessor
Cash used in operating activities in the period January 1, 2017 through April 1, 2017 resulted from cash used in settlement of bankruptcy claims, partially offset by cash generated from our operations from improved supply and demand conditions.
Cash provided by investing activities in the period January 1, 2017 through April 1, 2017 resulted from $31.1 million of cash receipts from Middlemount and proceeds from disposals of assets of $24.3 driven by the sale of Dominion Terminal Associates, which was offset by $34.2 million of payments for additions to property, plant, equipment and mine development.
Cash provided by financing activities in the period January 1, 2017 through April 1, 2017 resulted from $1.0 billion of debt proceeds related to our recapitalization upon emergence from the Chapter 11 cases, partially offset by $45.4 million of related deferred financing costs.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying condensed consolidated balance sheets. At September 30, 2018, such instruments included $1,637.3 million of surety bonds and bank guarantees and $252.2 million of letters of credit. Such financial instruments provide support for our reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. We periodically evaluate the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. We do not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in our 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.
As described in Note 17. “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 collateral requirements and surety and related fees.
At September 30, 2018, we had total asset retirement obligations of $703.0 million which were backed by a combination of surety bonds, bank guarantees and letters of credit.
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.
Guarantees and Other Financial Instruments with Off-Balance Sheet Risk. See Note 17. “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.


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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, 2017. Our critical accounting policies remain unchanged at September 30, 2018.
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 6. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. As of September 30, 2018, the Company had currency options outstanding with an aggregate notional amount of $675.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the remainder of 2018 and through the first quarter of 2019. 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. Based upon the Australian dollar/U.S. dollar exchange rate at September 30, 2018, the currency option contracts outstanding at that date would not limit our net exposure to a $0.05 unfavorable change in the exchange rate for the next twelve months.
Subsequent to September 30, 2018, the Company purchased additional quarterly average rate options with an aggregate notional amount of $275.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the remainder of 2018 and through the first half of 2019.
Other Non-Coal Trading Activities — Diesel Fuel Price Risk
Diesel Fuel Hedges. Previously, we managed price risk of the diesel fuel used in our mining activities through the use of cost pass-through contracts and from time to time, derivatives, primarily swaps. However, as of September 30, 2018, we did not have any diesel fuel derivative instruments in place.
We expect to consume 115 to 125 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 $30 million based on our expected usage.
Item 4. Controls and Procedures.
Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including our principal executive and financial officers, on a timely basis. Our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of September 30, 2018, and concluded that such controls and procedures are effective to provide reasonable assurance that the desired control objectives were achieved. Additionally, there have been no changes to our internal control over financial reporting during the most recent fiscal quarter that 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 4. “Discontinued Operations” and Note 18. “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.


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Item 1A. Risk Factors.
The risk factor set forth below updates the corresponding risk factor previously disclosed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017 filed with the SEC on February 26, 2018.
Risks inherent to mining could increase the cost of operating our business, and events and conditions that could occur during the course of our mining operations could have a material adverse impact on us.
Our mining operations are subject to events and conditions that can impact the safety of our workforce, or delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These events and conditions, which could materially and adversely impact on our results of operations, financial condition and cash flows, include:
•
fires and explosions, including from methane or coal dust;
•
accidental mine water discharges;
•
weather, flooding and natural disasters;
•
hazardous geologic events such as roof falls and high wall failures;
•
key equipment failures;
•
variations in coal seam thickness, coal quality, the amount of rock and soil overlying coal deposits, and geologic conditions impacting mine sequencing;
•
unexpected maintenance problems; and
•
unforeseen delays in implementation of mining technologies that are new to our operations.
In this regard, our North Goonyella Mine in Queensland, Australia experienced elevated gas levels beginning in September 2018, followed by a fire in a portion of the mine. The underground mine and portions of the surface area at North Goonyella remain restricted to access through exclusion zones while the work to contain the impacts of the fire continues. The situation at North Goonyella remains complex and uncertain, and we are continuing to evaluate potential next phases. Mining operations were suspended in September 2018 and it is uncertain when or if mining operations will restart. If after exploring all reasonable mine-planning steps focused on resuming mining activities at the North Goonyella Mine we determine that we are unable to extract coal from all or a significant portion of the mine, our results of operations, financial condition and cash flows could be materially and adversely impacted. In addition, the costs that may be incurred to address the impacts of the fire and to return the mine to active operations (if the mine returns to active operations) are uncertain and could be significant. We maintain potentially applicable insurance policies for losses associated with the events at our North Goonyella Mine, as well as the other risks referenced above, and those insurance policies may lessen the impact associated with these events and risks. However, there can be no assurance as to the amount or timing of recovery under our insurance policies in connection with losses associated with these events and risks.
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 (Repurchase Program). On April 25, 2018, we announced that the Board authorized the expansion of the Repurchase Program to $1.0 billion. On October 30, 2018, we announced that the Board authorized an additional expansion of the Repurchase Program to $1.5 billion. 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. Through September 30, 2018, we have repurchased approximately 22.8 million shares of our common stock for $874.9 million, leaving $625.1 million available for share repurchase under the Repurchase Program. Included in the shares repurchased during the three months ended September 30, 2018 were approximately 7.2 million shares of our common stock for $300.0 million in connection with a definitive agreement to directly repurchase shares from entities advised by Elliott Management. The purchases were made in compliance with our debt instruments. Limitations on share repurchases imposed by our debt instruments are discussed in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Share Relinquishments
We routinely allow employees to relinquish common stock to pay estimated taxes upon the vesting of restricted stock units and the payout of performance units that are settled in common stock under our equity incentive plans. The value of common stock tendered by employees is determined based on the closing price of our common stock on the dates of the respective relinquishments.


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Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended September 30, 2018:
Period
 
Total
Number of
Shares
Purchased (1)
 
Average
Price Paid 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, 2018
 
560,429

 
$
44.67

 
559,641

 
$
925.1

August 1 through August 31, 2018
 
7,173,613

 
41.82

 
7,173,601

 
625.1

September 1 through September 30, 2018
 
24

 
—

 
—

 
625.1

Total
 
7,734,066

 
$
42.03

 
7,733,242

 
 
(1) 
Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not part of the Repurchase Program.
Dividends
During the three and nine months ended September 30, 2018, the Company declared dividends per share of $0.125 and $0.355, respectively. On October 17, 2018, the Company declared an additional dividend per share of $0.13 to be paid on November 21, 2018 to shareholders of record as of October 31, 2018. The declaration and payment of dividends and the amount of dividends will depend on our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by our debt covenants and other factors that our Board of Directors may deem relevant to such evaluations. Payment of dividends is subject to certain limitations following the Effective Date, as set forth in our debt provisions. Such limitations on dividends are discussed in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Mandatory Conversion of Preferred Stock
Each outstanding share of our Preferred Stock was subject to mandatory automatic conversion into a number of shares of common stock if the volume weighted average price of the common stock exceeded $32.50 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. On January 31, 2018, the requirements for such a mandatory conversion were met and the then outstanding 13.2 million shares of Preferred Stock were automatically converted into 24.8 million shares of common stock. As a result of this mandatory conversion, we recorded a non-cash preferred dividend charge of $102.5 million during the nine months ended September 30, 2018. After the mandatory conversion, no shares of Preferred Stock are issued or outstanding and all rights of the prior holders of Preferred Stock have terminated.
Item 4. Mine Safety Disclosures.
Our “Safety a Way of Life Management System” has been designed to set clear and consistent expectations for safety and health across our business. It aligns to the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, safety and health risk management and assurance. We also partner with other companies and certain governmental agencies to pursue new technologies that have the potential to improve our safety performance and provide better safety protection for employees. On September 7, 2018, a haul truck driver at the Bear Run Mine was transporting spoil to a dump site when a bulldozer operator saw a fire on the truck. While exiting the truck, the driver received burns and was taken to the hospital. Tragically, on September 12, 2018, he suffered a cardiac arrest and passed away. The investigation surrounding the incident is ongoing.
We continually monitor our safety performance and regulatory compliance. The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95 to this Quarterly Report on Form 10-Q.
Item 6. Exhibits.
See Exhibit Index at page 79 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
 
 
 
10.1†
 
 
 
 
10.2
 
 
 
 
10.3
 
 
 
 
31.1†
 
 
 
 
31.2†
 
 
 
 
32.1†
 
 
 
 
32.2†
 
 
 
 
95†
 
 
 
 
101†
 
Interactive Data File (Form 10-Q for the quarterly period ended September 30, 2018 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 1, 2018
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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