UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q

(Mark One)
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, 2017March 31, 2023

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

peabodylogoa36.jpg
PEABODY ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware13-4004153
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
701 Market Street,St. Louis, MissouriMissouri63101-1826
(Address of principal executive offices)(Zip Code)
(314) 342-3400
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, par value $0.01 per shareBTUNew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ☑   No ¨☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ☑   No ¨☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”,filer,” “smaller reporting company”company,” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934. (Check one):Act:
Large accelerated filer ☑Accelerated filer ☐
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)
Smaller reporting company þ
Emerging growth company ¨
Non-accelerated filer ☐                         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 Exchange Act subsequent to the distribution of securities under a plan confirmed by a court. Yes þ No¨☑
There were 104.5144.7 million shares of the registrant’s common stock (par value of $0.01 per share) outstanding at October 30, 2017.
There were 14.3 million shares of the registrant’s Series A convertible preferred stock (par value of $0.01 per share) outstanding at October 30, 2017.
April 28, 2023.





TABLE OF CONTENTS
Page
Item 1. Financial Statements
1
Unaudited Condensed Consolidated Statements of Operations
1
Unaudited Condensed Consolidated Statements of Comprehensive Income
2
Condensed Consolidated Balance Sheets
3
Unaudited Condensed Consolidated Statements of Cash Flows
4
Unaudited Condensed Consolidated StatementStatements of Changes in Stockholders’ Equity
56
Notes to Unaudited Condensed Consolidated Financial Statements
67
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
5024
Item 3. Quantitative and Qualitative Disclosures About Market Risk
7943
Item 4. Controls and Procedures
7943
Item 1. Legal Proceedings
8044
Item 1A. Risk Factors
8044
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
8046
Item 4. Mine Safety Disclosures
8148
Item 6. Exhibits
8148
8249
8450



Table of Contents





PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Three Months Ended March 31,
SuccessorPredecessor SuccessorPredecessor20232022
Three Months Ended September 30, 2017Three Months Ended September 30, 2016
April 2 through September 30, 2017January 1 through April 1, 2017
Nine Months Ended September 30, 2016(Dollars in millions, except per share data)
(Dollars in millions, except per share data)
Revenues 
      
Sales$1,264.2
$1,064.0
 $2,323.8
$1,081.4
 $2,835.9
Other revenues213.0
143.1
 411.7
244.8
 438.6
Total revenues1,477.2
1,207.1
 2,735.5
1,326.2
 3,274.5
RevenueRevenue$1,364.0 $691.4 
Costs and expenses   
   Costs and expenses
Operating costs and expenses (exclusive of items shown separately below)1,044.9
1,064.8
 1,979.7
963.7
 2,981.2
Operating costs and expenses (exclusive of items shown separately below)846.6 699.0 
Depreciation, depletion and amortization194.5
117.8
 342.8
119.9
 345.5
Depreciation, depletion and amortization76.3 72.9 
Asset retirement obligation expenses11.3
12.7
 22.3
14.6
 37.3
Asset retirement obligation expenses15.4 15.0 
Selling and administrative expenses33.4
32.1
 67.8
37.2
 114.6
Selling and administrative expenses22.8 23.1 
Restructuring charges1.1
0.3
 1.1
—
 15.5
Restructuring charges0.1 1.6 
Other operating (income) loss:       
Net gain on disposal of assets(0.4)(1.9) (0.9)(22.8) (17.4)
Other operating income:Other operating income:
Net gain on disposalsNet gain on disposals(1.9)(4.9)
Asset impairment—
—
 —
30.5
 17.2
Asset impairment2.0 — 
(Income) loss from equity affiliates(10.5)2.9
 (26.2)(15.0) 12.6
Income from equity affiliatesIncome from equity affiliates(1.8)(44.7)
Operating profit (loss)202.9
(21.6)
348.9
198.1
 (232.0)Operating profit (loss)404.5 (70.6)
Interest expense42.4
58.5
 83.8
32.9
 243.7
Interest expense18.4 39.4 
Loss on early debt extinguishment12.9
—
 12.9
—
 —
Net loss on early debt extinguishmentNet loss on early debt extinguishment6.8 23.5 
Interest income(2.0)(1.3) (3.5)(2.7) (4.0)Interest income(13.1)(0.5)
Reorganization items, net—
29.7
 —
627.2
 125.1
Net periodic benefit credit, excluding service costNet periodic benefit credit, excluding service cost(9.7)(12.2)
Income (loss) from continuing operations before income taxes149.6
(108.5) 255.7
(459.3) (596.8)Income (loss) from continuing operations before income taxes402.1 (120.8)
Income tax benefit(84.1)(10.8) (79.4)(263.8) (108.2)
Income tax provision (benefit)Income tax provision (benefit)118.0 (1.0)
Income (loss) from continuing operations, net of income taxes233.7
(97.7) 335.1
(195.5) (488.6)Income (loss) from continuing operations, net of income taxes284.1 (119.8)
Loss from discontinued operations, net of income taxes(3.7)(38.1) (6.4)(16.2) (44.5)Loss from discontinued operations, net of income taxes(1.3)(0.8)
Net income (loss)230.0
(135.8) 328.7
(211.7) (533.1)Net income (loss)282.8 (120.6)
Less: Series A Convertible Preferred Stock dividends23.5
—
 138.6
—
 —
Less: Net income attributable to noncontrolling interests5.1
1.8
 8.9
4.8
 3.5
Less: Net income (loss) attributable to noncontrolling interestsLess: Net income (loss) attributable to noncontrolling interests14.3 (1.1)
Net income (loss) attributable to common stockholders$201.4
$(137.6) $181.2
$(216.5) $(536.6)Net income (loss) attributable to common stockholders$268.5 $(119.5)
       
Income (loss) from continuing operations:       Income (loss) from continuing operations:
Basic income (loss) per share$1.51
$(5.44) $1.38
$(10.93) $(26.91)Basic income (loss) per share$1.87 $(0.87)
Diluted income (loss) per share$1.49
$(5.44) $1.37
$(10.93) $(26.91)Diluted income (loss) per share$1.69 $(0.87)
       
Net income (loss) attributable to common stockholders:       Net income (loss) attributable to common stockholders: 
Basic income (loss) per share$1.48
$(7.53) $1.33
$(11.81) $(29.34)Basic income (loss) per share$1.86 $(0.88)
Diluted income (loss) per share$1.47
$(7.53) $1.32
$(11.81) $(29.34)Diluted income (loss) per share$1.68 $(0.88)
       
Dividends declared per share$—
$—
 $—
$—
 $—
See accompanying notes to unaudited condensed consolidated financial statements.



1


Table of Contents





PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


Three Months Ended March 31,
20232022
(Dollars in millions)
Net income (loss)$282.8 $(120.6)
Postretirement plans (net of $0.0 tax provisions in each period)(13.4)(13.4)
Foreign currency translation adjustment(0.2)1.9 
Other comprehensive loss, net of income taxes(13.6)(11.5)
Comprehensive income (loss)269.2 (132.1)
Less: Net income (loss) attributable to noncontrolling interests14.3 (1.1)
Comprehensive income (loss) attributable to common stockholders$254.9 $(131.0)
 SuccessorPredecessor SuccessorPredecessor
 Three Months Ended September 30, 2017Three Months Ended September 30, 2016 April 2 through September 30, 2017January 1 through April 1, 2017 Nine Months Ended September 30, 2016
 (Dollars in millions)
Net income (loss)$230.0
$(135.8) $328.7
$(211.7) $(533.1)
Reclassification for realized losses on cash flow hedges (net of respective net tax provision of $0.0, $17.6, $0.0, $9.1 and $69.9) included in net income (loss)—
29.9
 —
18.6
 119.0
Postretirement plans and workers’ compensation obligations (net of respective net tax provision of $0.0, $2.1, $0.0, $2.5 and $6.3)—
3.6
 —
4.4
 10.8
Foreign currency translation adjustment1.3
1.5
 1.8
5.5
 2.4
Other comprehensive income, net of income taxes1.3
35.0
 1.8
28.5
 132.2
Comprehensive income (loss)231.3
(100.8) 330.5
(183.2) (400.9)
Less: Series A Convertible Preferred Stock dividends23.5
—
 138.6
—
 —
Less: Comprehensive income attributable to noncontrolling interests5.1
1.8
 8.9
4.8
 3.5
Comprehensive income (loss) attributable to common stockholders$202.7
$(102.6) $183.0
$(188.0) $(404.4)


See accompanying notes to unaudited condensed consolidated financial statements.



2


Table of Contents





PEABODY ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
 (Unaudited) 
 SuccessorPredecessor(Unaudited)
 September 30, 2017December 31, 2016March 31, 2023December 31, 2022
 (Amounts in millions, except per share data)(Amounts in millions, except per share data)
ASSETS   ASSETS  
Current assets   Current assets  
Cash and cash equivalents $925.0
$872.3
Cash and cash equivalents$892.2 $1,307.3 
Restricted cash 7.8
54.3
Accounts receivable, net of allowance for doubtful accounts of $4.6 at September 30, 2017 and $13.1 at December 31, 2016 431.0
473.0
Inventories 307.7
203.7
Assets from coal trading activities, net 2.5
0.7
Accounts receivable, net of allowance for credit losses of $0.0 at March 31, 2023 and December 31, 2022Accounts receivable, net of allowance for credit losses of $0.0 at March 31, 2023 and December 31, 2022394.7 465.5 
Inventories, netInventories, net331.5 296.1 
Other current assets 268.6
486.6
Other current assets260.1 303.6 
Total current assets 1,942.6
2,090.6
Total current assets1,878.5 2,372.5 
Property, plant, equipment and mine development, net 5,082.6
8,776.7
Property, plant, equipment and mine development, net2,847.9 2,865.0 
Restricted cash collateral 530.3
529.3
Operating lease right-of-use assetsOperating lease right-of-use assets22.7 26.9 
Restricted cash and collateralRestricted cash and collateral936.7 187.4 
Investments and other assets 517.9
381.1
Investments and other assets85.6 84.3 
Deferred income taxesDeferred income taxes28.5 74.7 
Total assets $8,073.4
$11,777.7
Total assets$5,799.9 $5,610.8 
LIABILITIES AND STOCKHOLDERS’ EQUITY   LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current liabilities   Current liabilities  
Current portion of long-term debt $47.1
$20.2
Current portion of long-term debt$13.2 $13.2 
Liabilities from coal trading activities, net 1.0
1.2
Accounts payable and accrued expenses 1,065.0
990.4
Accounts payable and accrued expenses853.2 905.5 
Total current liabilities 1,113.1
1,011.8
Total current liabilities866.4 918.7 
Long-term debt, less current portion 1,612.0
—
Long-term debt, less current portion322.4 320.6 
Deferred income taxes 2.2
173.9
Deferred income taxes20.2 20.4 
Asset retirement obligations 636.0
717.8
Asset retirement obligations668.3 665.8 
Accrued postretirement benefit costs 745.8
756.3
Accrued postretirement benefit costs155.6 156.5 
Operating lease liabilities, less current portionOperating lease liabilities, less current portion6.9 11.0 
Other noncurrent liabilities 573.7
496.2
Other noncurrent liabilities230.4 223.0 
Total liabilities not subject to compromise 4,682.8
3,156.0
Liabilities subject to compromise —
8,440.2
Total liabilities 4,682.8
11,596.2
Total liabilities2,270.2 2,316.0 
Stockholders’ equity   Stockholders’ equity  
Predecessor Preferred Stock — $0.01 per share par value; 10.0 shares authorized, no shares issued or outstanding as December 31, 2016 —
—
Predecessor Perpetual Preferred Stock — 0.8 shares authorized, no shares issued or outstanding as of December 31, 2016 —
—
Predecessor Series Common Stock — $0.01 per share par value; 40.0 shares authorized, no shares issued or outstanding as of December 31, 2016 —
—
Predecessor Common Stock — $0.01 per share par value; 53.3 shares authorized,19.3 shares issued and 18.5 shares outstanding as of December 31, 2016 —
0.2
Successor Series A Convertible Preferred Stock — $0.01 per share par value; 50.0 shares authorized, 30.0 shares issued and 15.9 shares outstanding as of September 30, 2017 691.7
—
Successor Preferred Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of September 30, 2017 —
—
Successor Series Common Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of September 30, 2017 —
—
Successor Common Stock — $0.01 per share par value; 450.0 shares authorized, 106.0 shares issued and 102.7 shares outstanding as of September 30, 2017 1.0
—
Preferred Stock — $0.01 per share par value; 100.0 shares authorized, no shares issued or outstanding as of March 31, 2023 and December 31, 2022Preferred Stock — $0.01 per share par value; 100.0 shares authorized, no shares issued or outstanding as of March 31, 2023 and December 31, 2022— — 
Series Common Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of March 31, 2023 and December 31, 2022Series Common Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of March 31, 2023 and December 31, 2022— — 
Common Stock — $0.01 per share par value; 450.0 shares authorized, 188.4 shares issued and 144.7 shares outstanding as of March 31, 2023 and 187.1 shares issued and 143.9 shares outstanding as of December 31, 2022Common Stock — $0.01 per share par value; 450.0 shares authorized, 188.4 shares issued and 144.7 shares outstanding as of March 31, 2023 and 187.1 shares issued and 143.9 shares outstanding as of December 31, 20221.9 1.9 
Additional paid-in capital 2,425.9
2,422.0
Additional paid-in capital3,977.6 3,975.9 
Treasury stock, at cost — 2.5 Successor common shares as of September 30, 2017 and 0.8 Predecessor common shares as of December 31, 2016 (69.2)(371.8)
Retained earnings (accumulated deficit) 296.3
(1,399.5)
Accumulated other comprehensive income (loss) 1.8
(477.0)
Treasury stock, at cost — 43.7 and 43.2 common shares as of March 31, 2023 and December 31, 2022Treasury stock, at cost — 43.7 and 43.2 common shares as of March 31, 2023 and December 31, 2022(1,386.1)(1,372.9)
Retained earningsRetained earnings652.4 383.9 
Accumulated other comprehensive incomeAccumulated other comprehensive income228.9 242.5 
Peabody Energy Corporation stockholders’ equity 3,347.5
173.9
Peabody Energy Corporation stockholders’ equity3,474.7 3,231.3 
Noncontrolling interests 43.1
7.6
Noncontrolling interests55.0 63.5 
Total stockholders’ equity 3,390.6
181.5
Total stockholders’ equity3,529.7 3,294.8 
Total liabilities and stockholders’ equity $8,073.4
$11,777.7
Total liabilities and stockholders’ equity$5,799.9 $5,610.8 
See accompanying notes to unaudited condensed consolidated financial statements.



3


Table of Contents





PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended March 31,
20232022
 (Dollars in millions)
Cash Flows From Operating Activities 
Net income (loss)$282.8 $(120.6)
Loss from discontinued operations, net of income taxes1.3 0.8 
Income (loss) from continuing operations, net of income taxes284.1 (119.8)
Adjustments to reconcile income (loss) from continuing operations, net of income taxes to net cash provided by (used in) operating activities: 
Depreciation, depletion and amortization76.3 72.9 
Noncash interest expense, net1.6 3.8 
Deferred income taxes46.0 (6.4)
Noncash share-based compensation1.7 2.0 
Asset impairment2.0 — 
Net gain on disposals(1.9)(4.9)
Noncash income from port and rail capacity assignment(9.2)— 
Net loss on early debt extinguishment6.8 23.5 
Income from equity affiliates(1.8)(44.7)
Foreign currency option contracts2.2 (3.3)
Changes in current assets and liabilities: 
Accounts receivable70.8 (6.9)
Inventories(35.4)(42.4)
Other current assets43.5 (80.0)
Accounts payable and accrued expenses(39.6)(28.4)
Collateral arrangements(45.9)(28.7)
Asset retirement obligations2.5 4.7 
Workers’ compensation obligations(0.9)(0.6)
Postretirement benefit obligations(14.4)(15.9)
Pension obligations0.4 (0.6)
Other, net0.6 3.2 
Net cash provided by (used in) continuing operations389.4 (272.5)
Net cash used in discontinued operations(3.1)(1.2)
Net cash provided by (used in) operating activities386.3 (273.7)
PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

4

Table of Contents


  SuccessorPredecessor
  April 2 through September 30, 2017January 1 through April 1, 2017 Nine Months Ended September 30, 2016
  (Dollars in millions)
Cash Flows From Operating Activities     
Net income (loss) $328.7
$(211.7) $(533.1)
Loss from discontinued operations, net of income taxes 6.4
16.2
 44.5
Income (loss) from continuing operations, net of income taxes 335.1
(195.5) (488.6)
Adjustments to reconcile income (loss) from continuing operations, net of income taxes to net cash provided by (used in) operating activities:     
Depreciation, depletion and amortization 342.8
119.9
 345.5
Noncash coal inventory revaluation 67.3
—
 —
Noncash interest expense including loss on early debt extinguishment 21.8
0.5
 30.0
Deferred income taxes 1.6
(252.2) (39.4)
Noncash share-based compensation 14.1
1.9
 8.9
Asset impairment —
30.5
 17.2
Net gain on disposal of assets (0.9)(22.8) (17.4)
(Income) loss from equity affiliates (26.2)(15.0) 12.6
Gain on voluntary employee beneficiary association settlement —
—
 (68.1)
Foreign currency option contracts (5.1)—
 —
Reclassification from other comprehensive earnings for terminated hedge contracts —
27.6
 82.0
Settlement of hedge positions —
—
 (25.0)
Noncash reorganization items, net —
569.3
 96.5
Changes in current assets and liabilities:     
Accounts receivable (118.9)159.3
 24.4
Change in receivable from accounts receivable securitization program —
—
 (168.5)
Inventories (54.1)(47.2) 47.8
Net assets from coal trading activities (1.6)(0.5) 7.5
Other current assets (23.4)0.1
 (28.6)
Accounts payable and accrued expenses (261.0)(64.9) 5.2
Restricted cash 99.4
(94.1) (94.8)
Asset retirement obligations 7.6
10.2
 19.0
Workers’ compensation obligations (1.1)(3.1) (8.7)
Accrued postretirement benefit costs (1.2)0.8
 (0.6)
Accrued pension costs (32.7)5.4
 16.4
Take-or-pay obligation settlement —
(5.5) (15.5)
Other, net (18.8)(2.5) (15.7)
Net cash provided by (used in) continuing operations 344.7
222.2
 (257.9)
Net cash used in discontinued operations (14.4)(8.2) (18.9)
Net cash provided by (used in) operating activities 330.3
214.0
 (276.8)
Cash Flows From Investing Activities     
Additions to property, plant, equipment and mine development (68.6)(32.8) (56.6)
Changes in accrued expenses related to capital expenditures 1.8
(1.4) (5.5)
Federal coal lease expenditures —
(0.5) (249.0)
Proceeds from disposal of assets 5.2
24.3
 134.7
Contributions to joint ventures (210.0)(95.4) (241.7)
Distributions from joint ventures 208.0
90.5
 236.7
Advances to related parties (4.1)(0.4) (23.3)
Repayments of loans from related parties 35.2
31.1
 13.2
Other, net (2.4)(0.3) (8.2)
Net cash (used in) provided by investing activities (34.9)15.1
 (199.7)
Cash Flows From Financing Activities     
Proceeds from long-term debt —
1,000.0
 1,429.8
Successor Notes issuance proceeds into escrow —
(1,000.0) —
Repayments of long-term debt (332.1)(2.1) (11.2)
Payment of deferred financing costs (6.1)(45.4) (29.8)
Common stock repurchases (69.2)—
 —
Distributions to noncontrolling interests (16.7)(0.1) (3.9)
Other, net —
(0.1) (1.9)
Net cash (used in) provided by financing activities (424.1)(47.7) 1,383.0
Net change in cash and cash equivalents (128.7)181.4
 906.5
Cash and cash equivalents at beginning of period 1,053.7
872.3
 261.3
Cash and cash equivalents at end of period $925.0
$1,053.7
 $1,167.8

PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
Three Months Ended March 31,
20232022
(Dollars in millions)
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development(55.7)(29.7)
Changes in accrued expenses related to capital expenditures(1.6)(7.0)
Proceeds from disposal of assets, net of receivables2.9 3.6 
Contributions to joint ventures(206.2)(126.6)
Distributions from joint ventures202.0 148.2 
Cash receipts from Middlemount Coal Pty Ltd and other related parties— 47.2 
Other, net0.1 (0.5)
Net cash (used in) provided by investing activities(58.5)35.2 
Cash Flows From Financing Activities
Proceeds from long-term debt— 545.0 
Repayments of long-term debt(2.7)(599.9)
Payment of debt issuance and other deferred financing costs(0.3)(19.2)
Proceeds from common stock issuances, net of costs— 222.0 
Repurchase of employee common stock relinquished for tax withholding(13.2)(2.0)
Distributions to noncontrolling interests(22.8)(13.8)
Other, net— 0.1 
Net cash (used in) provided by financing activities(39.0)132.2 
Net change in cash, cash equivalents and restricted cash288.8 (106.3)
Cash, cash equivalents and restricted cash at beginning of period (1)
1,417.6 954.3 
Cash, cash equivalents and restricted cash at end of period (2)
$1,706.4 $848.0 
(1) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at beginning of period”:
Cash and cash equivalents$1,307.3 
Restricted cash included in “Restricted cash and collateral”110.3 
Cash, cash equivalents and restricted cash at beginning of period$1,417.6 
(2) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at end of period”:
Cash and cash equivalents$892.2 
Restricted cash included in “Restricted cash and collateral”814.2
Cash, cash equivalents and restricted cash at end of period$1,706.4 
See accompanying notes to unaudited condensed consolidated financial statements.



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


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

$0.2

$2,422.0

$(371.8)
$(1,399.5)
$(477.0)
$7.6

$181.5
Net (loss) income—

—

—

—

(216.5)
—

4.8

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

—

—

—

—

18.6

—

18.6
Postretirement plans and workers’ compensation obligations (net of $2.5 net tax provision)—

—

—

—

—

4.4

—

4.4
Foreign currency translation adjustment—

—

—

—

—

5.5

—

5.5
Share-based compensation for equity-classified awards—

—

1.9

—

—

—

—

1.9
Repurchase of employee common stock relinquished for tax withholding—

—

—

(0.1)
—

—

—

(0.1)
Distributions to noncontrolling interests—

—

—

—

—

—

(0.1)
(0.1)
Elimination of Predecessor equity—

(0.2)
(2,423.9)
371.9

1,616.0

448.5

(12.3)
—
April 1, 2017 - Predecessor$—

$—

$—

$—

$—

$—

$—

$—
Issuance of Successor equity1,305.4

0.7

1,774.9

—

—

—

50.9

3,131.9
April 2, 2017 - Successor$1,305.4

$0.7

$1,774.9

$—

$—

$—

$50.9

$3,131.9
Net income—

—

—

—

319.8

—

8.9

328.7
Foreign currency translation adjustment—

—

—

—

—

1.8

—

1.8
Warrant conversions—
 0.1

(0.1)
—

—

—

—

—
Series A Convertible Preferred Stock conversions(616.7)
0.2

640.0

—

(23.5)
—

—

—
Series A Convertible Preferred Stock dividends3.0

—

(3.0)
—

—

—

—

—
Share-based compensation for equity-classified awards—

—

14.1

—

—

—

—

14.1
Common stock repurchases—

—

—

(69.2)
—

—

—

(69.2)
Distributions to noncontrolling interests—

—

—

—

—

—

(16.7)
(16.7)
September 30, 2017 - Successor$691.7

$1.0

$2,425.9

$(69.2)
$296.3

$1.8

$43.1

$3,390.6

Three Months Ended March 31,
20232022
 (Dollars in millions)
Common Stock
Balance, beginning of period$1.9 $1.8 
Common stock issuances, net of costs— 0.1 
Balance, end of period1.9 1.9 
Additional paid-in capital
Balance, beginning of period3,975.9 3,745.6 
Share-based compensation for equity-classified awards1.7 2.0 
Common stock issuances, net of costs— 221.9 
Balance, end of period3,977.6 3,969.5 
Treasury stock
Balance, beginning of period(1,372.9)(1,370.3)
Repurchase of employee common stock relinquished for tax withholding(13.2)(2.0)
Balance, end of period(1,386.1)(1,372.3)
Retained earnings (Accumulated deficit)
Balance, beginning of period383.9 (913.2)
Net income (loss) attributable to common stockholders268.5 (119.5)
Balance, end of period652.4 (1,032.7)
Accumulated other comprehensive income
Balance, beginning of period242.5 297.9 
Postretirement plans (net of $0.0 tax provisions in each period)(13.4)(13.4)
Foreign currency translation adjustment(0.2)1.9 
Balance, end of period228.9 286.4 
Noncontrolling interests
Balance, beginning of period63.5 59.0 
Net income (loss) attributable to noncontrolling interests14.3 (1.1)
Distributions to noncontrolling interests(22.8)(13.8)
Balance, end of period55.0 44.1 
Total stockholders’ equity$3,529.7 $1,896.9 
See accompanying notes to unaudited condensed consolidated financial statements.



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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 unincorporateda joint venture. In those cases, the Company includes its proportionate share in the assets, liabilities, revenuesrevenue and expenses of the jointly controlled entities within each applicable line item of the unaudited condensed consolidated financial statements. All intercompany transactions, profits and balances have been eliminated in consolidation.
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements and should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.2022. In the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation and certain prior year amounts have been reclassified for consistency with the current period presentation. Balance sheet information presented herein as of December 31, 20162022 has been derived from the Company’s audited consolidated balance sheet at that date. The Company’s results of operations for the three months ended September 30, 2017 and the period April 2, 2017 through September 30, 2017March 31, 2023 are not necessarily indicative of the results that may be expected for future quarters.quarters or for the year ending December 31, 2023.
TheAlthough there are new accounting pronouncements issued by the Financial Accounting Standards Board that the Company has classified items within discontinued operations inwill adopt, as applicable, the Company does not believe any of these accounting pronouncements will have a material impact on its unaudited condensed consolidated financial statements for disposals (by sale or otherwise) that have occurred priordisclosures.
(2)    Revenue Recognition
Refer to January 1, 2015 when the operations and cash flowsNote 1. “Summary of a disposed component of the Company were eliminated from the ongoing operations of the Company as a result of the disposal and the Company no longer had any significant continuing involvementSignificant Accounting Policies” in the operation of that component.
Plan of Reorganization and Emergence from Chapter 11 Cases
On April 13, 2016, (the Petition Date), PEC and a majority of its wholly owned domestic subsidiaries, as well as one international subsidiary in Gibraltar (collectively with PEC, the Debtors), filed voluntary petitions (the Bankruptcy Petitions) under Chapter 11 of Title 11 of the U.S. Code (the Bankruptcy Code) in the United States Bankruptcy CourtCompany’s Annual Report on Form 10-K for the Eastern District of Missouri (the Bankruptcy Court). The Debtors’ Chapter 11 cases (the Chapter 11 Cases) were jointly administered under the caption In re Peabody Energy Corporation, et al., Case No. 16-42529.
For periods subsequent to filing the Bankruptcy Petitions, the Company applied the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, “Reorganizations”, in preparing its consolidated financial statements. ASC 852 requires that financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that were realized or incurred in the bankruptcy proceedings were recorded in “Reorganization items, net” in the unaudited condensed consolidated statements of operations. In addition, the pre-petition obligations that were impacted by the bankruptcy reorganization process were classified as “Liabilities subject to compromise” in the accompanying condensed consolidated balance sheet atyear ended December 31, 2016.2022, for the Company’s policies regarding “Revenue” and “Accounts receivable, net.”
On January 27, 2017, the Debtors filed with the Bankruptcy Court the Second Amended Joint PlanDisaggregation of Reorganization of DebtorsRevenue
Revenue by product type and Debtors in Possession (as further modified, the Plan) and the Second Amended Disclosure Statement with Respect to the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (previous versions of the Plan and Disclosure Statement were filed with the Bankruptcy Court on December 22, 2016, January 25, 2017 and January 27, 2017). Subsequently, the Debtors solicited votes on the Plan. On March 15, 2017, the Debtors filed a revised version of the Plan and on March 16, 2017, the Bankruptcy Court held a hearing to determine whether the Plan should be confirmed. On March 17, 2017, the Bankruptcy Court entered an order, Docket No. 2763 (the Confirmation Order), confirming the Plan. On April 3, 2017, (the Effective Date), the Debtors satisfied the conditions to effectivenessmarket is set forth in the Plan,following tables. With respect to its seaborne reporting segments, the Plan became effectiveCompany classifies as “Export” certain revenue from domestically-delivered coal under contracts in accordance with its terms andwhich the Debtors emerged from the Chapter 11 Cases.price is derived on a basis similar to export contracts.

Three Months Ended March 31, 2023
Seaborne Thermal MiningSeaborne Metallurgical MiningPowder River Basin MiningOther U.S. Thermal Mining
Corporate and Other (1)
Consolidated
(Dollars in millions)
Thermal coal
Domestic$37.5 $— $305.0 $247.9 $— $590.4 
Export308.8 — — — — 308.8 
Total thermal346.3 — 305.0 247.9 — 899.2 
Metallurgical coal
Export— 287.2 — — — 287.2 
Total metallurgical— 287.2 — — — 287.2 
Other (2)
0.2 1.2 0.3 1.5 174.4 177.6 
Revenue$346.5 $288.4 $305.3 $249.4 $174.4 $1,364.0 


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

Three Months Ended March 31, 2022
Seaborne Thermal MiningSeaborne Metallurgical MiningPowder River Basin MiningOther U.S. Thermal Mining
Corporate and Other (1)
Consolidated
(Dollars in millions)
Thermal coal
Domestic$40.4 $— $251.5 $199.9 $— $491.8 
Export210.5 — — — — 210.5 
Total thermal250.9 — 251.5 199.9 — 702.3 
Metallurgical coal
Export— 318.0 — — — 318.0 
Total metallurgical— 318.0 — — — 318.0 
Other (2)
0.3 3.3 (0.3)3.2 (335.4)(328.9)
Revenue$251.2 $321.3 $251.2 $203.1 $(335.4)$691.4 
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(1)    Corporate and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. The Company was permitted to use fresh start reporting because (i) the holders of existing voting shares of the Predecessor (as defined below) company received less than 50% of the voting shares of the emerging entity upon reorganization and (ii) the reorganization value of the Company’s assets immediately prior to Plan confirmation was less than the total of all postpetition liabilities and allowed claims.
Upon adoption of fresh start reporting, the Company became a new entity for financial reporting purposes, reflecting the Successor (as defined below) capital structure. As a result, a new accounting basis in the identifiable assets and liabilities assumed was established with no retained earnings or accumulated other comprehensive income (loss) (OCI) for financial reporting purposes. The Company selected an accounting convenience date of April 1, 2017 for purposes of applying fresh start reporting as the activity between the convenience date and the Effective Date does not result in a material difference in the results. References to “Successor” in the financial statements and accompanying footnotes are in reference to reporting dates on or after April 2, 2017; references to “Predecessor” in the financial statements and accompanying footnotes are in reference to reporting dates through April 1, 2017 whichOther includes the impact of the Plan provisions and the application of fresh start reporting. Asfollowing:
Three Months Ended March 31,
20232022
(Dollars in millions)
Unrealized gains (losses) on derivative contracts related to forecasted sales$118.7 $(301.0)
Realized losses on derivative contracts related to forecasted sales(50.6)(68.0)
Revenue from physical sale of coal (3)
84.5 19.1 
Trading revenue— 10.1 
Other (2)
21.8 4.4 
Total Corporate and Other$174.4 $(335.4)
(2)    Includes revenue from arrangements such the Company’s financial statements for the Successor will not be comparable in many respects to its financial statements for periods prior to the adoption of fresh start reporting and prior to the accounting for the effects of the Plan. For further information on the Plan and fresh start reporting, see Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting.”
In connection with fresh start reporting, the Company made certain accounting policy elections that impact the Successor periods presented herein and will impact prospective periods. The Company will classify the amortizationas customer contract-related payments associated with its asset retirement obligation assets within “Depreciation, depletionvolume shortfalls; royalties related to coal lease agreements; sales agency commissions; farm income; property 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 benefitfacility rentals; and pension obligations, the Company will prospectively record amounts attributable to prior service cost and actuarial valuation changes, as applicable, currently in earnings rather than recording such amounts within accumulated other comprehensive income and amortizing to expense over applicable time periods.
(2)    Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
Newly Adopted Accounting Standards
Inventory. In July 2015, the FASB issued guidance which requires entities to measure most inventory “at the lower of cost and net realizable value”, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market (market in this context is defined as one of three different measures, one of which is net realizable value). The guidance does not apply to inventories that are measured by using either the last-in, first-out method or the retail inventory method. The new guidance became effective prospectively for annual periods beginning after December 15, 2016 (January 1, 2017 for the Company). There was no material impactrevenue related to the Company’s resultsassignment of operations, financial condition, cash flows or financial statement presentation in connection withrights to its excess port and rail capacity.
(3)    Includes revenue recognized upon the adoptionphysical sale of the guidance.
Compensation - Stock Compensation. In March 2016, the FASB issued accounting guidance which identifies areas for simplification involving several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, an option to recognize gross stock compensation expense with actual forfeitures recognized as they occur, as well as certain classifications on the statement of cash flows. The new guidance was effective prospectively for annual periods beginning after December 15, 2016 and interim periods therein, with early adoption permitted. The Company elected early adoption of this guidance effective December 31, 2016. There was no material impact tocoal purchased from the Company’s resultsoperating segments and sold to customers through the Company’s coal trading business as part of operations, financial condition, cash flows or financial statement presentation in connection withsettling certain derivative contracts. Primarily represents the adoption ofdifference between the guidance.
Accounting Standards Not Yet Implemented
Revenue Recognition. In May 2014, the FASB issued a comprehensive revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The new standard provides a single principles-based, five-step model to be applied to all contracts with customers, which steps are to (1) identify the contract(s)price contracted with the customer (2) identifyand the performance obligations in the contract, (3) determine the transaction price (4) allocate the transaction priceallocated to the performance obligations inoperating segment.
Accounts Receivable
“Accounts receivable, net” at March 31, 2023 and December 31, 2022 consisted of the contract and (5) recognize revenue when each performance obligation is satisfied. More specifically, revenue will befollowing:
March 31, 2023December 31, 2022
 (Dollars in millions)
Trade receivables, net$353.2 $416.3 
Miscellaneous receivables, net41.5 49.2 
Accounts receivable, net$394.7 $465.5 
None of the above receivables included allowances for credit losses at March 31, 2023 or December 31, 2022. No charges for credit losses were recognized when promised goodsduring the three months ended March 31, 2023 or services are transferred to the customer in an amount that reflects the consideration expected in exchange for those goods or services. The standard also requires entities to disclose sufficient qualitative and quantitative information to enable financial statement users to understand the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers.

2022.


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

(3)     Inventories
“Inventories, net” as of March 31, 2023 and December 31, 2022 consisted of the following:
March 31, 2023December 31, 2022
 (Dollars in millions)
Materials and supplies, net$145.5 $130.8 
Raw coal83.5 98.3 
Saleable coal102.5 67.0 
Inventories, net$331.5 $296.1 
Materials and supplies inventories, net presented above have been shown net of reserves of $9.4 million and $9.5 million as of March 31, 2023 and December 31, 2022.
(4) Equity Method Investments
The new standard will be effective for interimCompany’s equity method investments include its joint venture interest in Middlemount Coal Pty Ltd (Middlemount), R3 Renewables LLC (R3) and annual periods beginning after December 15, 2017 (January 1, 2018 forcertain other equity method investments.
The table below summarizes the Company), with early adoption permitted. book value of those investments, which are reported in “Investments and other assets” in the condensed consolidated balance sheets, and the related “Income from equity affiliates”:
(Income) Loss from Equity Affiliates
Book Value atThree Months Ended March 31,
March 31, 2023December 31, 202220232022
(Dollars in millions)
Equity method investment related to Middlemount$29.4 $27.1 $(2.6)$(45.7)
Equity method investment related to R38.2 7.0 0.8 1.0 
Total equity method investments$37.6 $34.1 $(1.8)$(44.7)
The standard allows for eitherCompany received no cash payments from Middlemount during the three months ended March 31, 2023. Payments of $47.0 million were received from Middlemount during the three months ended March 31, 2022.
One of the Company’s Australian subsidiaries is party to an agreement to provide a full retrospective adoption or a modified retrospective adoption.revolving loan to Middlemount. The Company’s primary sourceparticipation in the revolving loan will not, at any time, exceed its 50% equity interest of revenue is from the salerevolving loan limit, which was $50 million Australian dollars at March 31, 2023. The revolving loan bears interest at 10% per annum and expires on December 31, 2023. There was no outstanding revolving loan at March 31, 2023 or December 31, 2022.
In March 2022, the Company entered into a joint venture with unrelated partners to form R3. R3 was formed with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage. The Company contributed $2.0 million to R3 during both the three months ended March 31, 2023 and 2022.
(5) Derivatives and Fair Value Measurements
Derivatives
From time to time, the Company may utilize various types of derivative instruments to manage its exposure to risks in the normal course of business, including (1) foreign currency exchange rate risk and the variability of cash flows associated with forecasted Australian dollar expenditures made in its Australian mining platform, (2) price risk of fluctuating coal prices related to forecasted sales or purchases of coal, through both short-termor changes in the fair value of a fixed price physical sales contract, (3) price risk and the variability of cash flows related to forecasted diesel fuel purchased for use in its operations and (4) interest rate risk on long-term contractsdebt. These risk management activities are actively monitored for compliance with utilities, industrial customers and steel producers whereby revenue is currently recognized whenthe Company’s risk of loss has passed to the customer. Upon adoption of this new standard,management policies.
On a limited basis, the Company believes thatengages in the timingdirect and brokered trading of revenue recognition related to its coal sales will remain consistent with its current practice. Theand freight-related contracts. Except those contracts for which the Company has reviewed its portfolio ofelected to apply a normal purchases and normal sales exception, all derivative coal salestrading contracts and the various terms and clauses within each contract and believes it is unlikely that its revenue recognition policies for such contracts will be materially impacted by the standard. The Company is also evaluating other revenue streams to determine the potential impact related to the adoption of the standard, as well as potential disclosures required by the standard. The Company plans to adopt the standard under the modified retrospective approach.
Lease Accounting. In February 2016, the FASB issued accounting guidance that will require a lessee to recognize on its balance sheet a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases with lease terms of more than 12 months. Consistent with current U.S. GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. Additional qualitative disclosures along with specific quantitative disclosures will also be required. The new guidance will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 (January 1, 2019 for the Company), with early adoption permitted. Upon adoption, the Company will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company is in the process of evaluating the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.
Financial Instruments - Credit Losses. In June 2016, the FASB issued accounting guidance related to the measurement of credit losses on financial instruments. The pronouncement replaces the incurred loss methodology to record credit losses with a methodology that reflects the expected credit losses for financial assets notare accounted for at fair value with gains and losses recognized through net income. This standard is effective for fiscal years beginning after December 15, 2019 (January 1, 2020 for the Company) and interim periods therein, with early adoption permitted for fiscal years, and interim periods therein, beginning after December 15, 2018.value. The Company ishad no diesel fuel or interest rate derivatives in the processplace as of evaluating the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.
Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued accounting guidance to amend the classification of certain cash receipts and cash payments in the statement of cash flows to reduce diversity in practice. The new guidance will be effective for fiscal years beginning after December 15, 2017 (January 1, 2018 for the Company) and interim periods therein, with early adoption permitted. The amendments in the classification should be applied retrospectively to all periods presented, unless deemed impracticable, in which case, prospective application is permitted. The Company is currently evaluating this guidance and its impact on classification of certain cash receipts and cash payments in the Company’s statements of cash flows.
Restricted Cash. In November 2016, the FASB issued accounting guidance which will reduce diversity in the presentation of restricted cash and restricted cash equivalents in the statement of cash flows. The new guidance will be effective retrospectively for fiscal years beginning after December 15, 2017 (January 1, 2018 for the Company) and interim periods therein, with early adoption permitted. The Company is currently evaluating this guidance and its impact on the Company’s statements of cash flows.
Compensation - Retirement Benefits. In March 2017, the FASB issued accounting guidance which requires employers that sponsor defined benefit pension and other postretirement plans to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. The new guidance will be effective retrospectively for fiscal years beginning after December 15, 2017 (January 1, 2018 for the Company) and interim periods therein, with early adoption permitted. The Company is currently evaluating the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.

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

Foreign Currency Option Contracts
DerivativesThe Company has historically utilized currency forwards and Hedging. In August 2017,options to hedge currency risk associated with anticipated Australian dollar expenditures. As of March 31, 2023, the FASB issued accounting guidanceCompany held average rate options with an aggregate notional amount of $632.0 million Australian dollars to amendhedge currency risk associated with anticipated Australian dollar expenditures over the hedge accounting rulesnine-month period ending December 31, 2023. The instruments entitle the Company to simplifyreceive payment on the applicationnotional amount should the quarterly average Australian dollar-to-U.S. dollar exchange rate exceed amounts ranging from $0.70 to $0.75 over the nine-month period ending December 31, 2023. As of hedge accounting guidanceMarch 31, 2023, the Company also held purchased collars with an aggregate notional amount of $350.0 million Australian dollars related to anticipated Australian dollar expenditures during the third and better alignfourth quarters of 2023. The purchased collars have a floor and ceiling of approximately $0.63 and $0.73, respectively, whereby the recognitionCompany will incur a loss on the instruments for rates below the floor and presentationa gain for rates above the ceiling.
Derivative Contracts Related to Forecasted Sales
As of March 31, 2023, the Company held coal derivative contracts related to a portion of its forecasted sales with an aggregate notional volume of 0.3 million tonnes. Such financial contracts may include futures, forwards and options. The notional volume is related predominantly to financial derivatives entered to support the profitability of the effectsWambo Underground Mine as part of a strategy to extend the hedging instrumentmine’s life. All such tonnes will settle in 2023. Additionally, the Company classifies certain physical forward sales contracts as derivatives for which the normal purchase, normal sales exception does not apply.
During the three months ended March 31, 2023, the Company recorded a net unrealized mark-to-market gain of $118.7 million on financial coal derivative contracts, and no unrealized mark-to-market gains or losses on physical forward sales contracts. During the hedged itemthree months ended March 31, 2022, the Company recorded a net unrealized mark-to-market loss of $301.0 million on these coal derivative contracts, which included approximately $237 million of unrealized mark-to-market losses on financial derivatives and approximately $64 million of unrealized mark-to-market losses on physical forward sales contracts.
Financial Trading Contracts
On a limited basis, the Company may enter coal or freight derivative contracts for trading purposes. Such financial contracts may include futures, forwards and options. The Company held nominal financial trading contracts as of March 31, 2023.
Tabular Derivatives Disclosures
The Company has master netting agreements with certain of its counterparties which allow for the settlement of contracts in an asset position with contracts in a liability position in the financial statements. The guidance expandsevent of default or termination. Such netting arrangements reduce the abilityCompany’s credit exposure related to hedge nonfinancial and financial risk components, reduces complexity inthese counterparties. For classification purposes, the Company records the net fair value hedges of interest rate risk, eliminatesall the requirement to separately measure and report hedge ineffectiveness,positions with a given counterparty 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 anda net investment hedge relationships that exist on the date of adoption will be applied using a modified retrospective approach. The presentation and disclosure requirements will be applied prospectively. The Company is currently evaluating the impact that the adoption of this guidance will have on its results of operations, financial condition, cash flows and financial statement presentation.
(3)    Emergence from the Chapter 11 Cases and Fresh Start Reporting
The following is a summary of certain provisions of the Plan, as confirmed by the Bankruptcy Court pursuant to the Confirmation Order, and is not intended to be a complete description of the Plan, which is included in its entirety as Exhibit 2.2 of the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission (SEC) on March 20, 2017.
The consummation of the Plan resultedasset or liability in the following capital structure on the Effective Date:
•Successor Notes - $1,000.0 million first lien senior secured notes
•Successor Credit Facility - a first lien credit facilitycondensed consolidated balance sheets. The fair value of $950.0 million
Series A Convertible Preferred Stock - $750.0 million for 30.0 million shares of Series A Convertible Preferred Stock
Common Stock and Warrants - $750.0 million for common stock and warrants issued in connection with a Rights Offering (as defined below), resulting in, together with other issuances of common stock, the issuance of 70.9 million shares of a single class of common stock and warrants to purchase 6.2 million shares of common stock
The new debt and equity instruments comprising the Successor Company’s capital structure are further described below.
Treatment of Classified Claims and Interests
The following summarizes the various classes of claimants’ recoveries under the Plan. Undefined capitalized terms used in this section, Treatment of Classified Claims and Interests, are definedderivatives reflected in the Plan.accompanying condensed consolidated balance sheets are set forth in the table below.

 March 31, 2023December 31, 2022
 Asset DerivativeLiability DerivativeAsset DerivativeLiability Derivative
 (Dollars in millions)
Foreign currency option contracts$— $— $3.0 $— 
Derivative contracts related to forecasted sales31.1 (79.8)100.6 (310.3)
Financial trading contracts— (0.1)11.7 — 
Total derivatives31.1 (79.9)115.3 (310.3)
Effect of counterparty netting(31.1)31.1 (100.6)100.6 
Variation margin posted (received)— 48.8 (11.7)209.7 
Net derivatives and variation margin as classified in the balance sheets$— $— $3.0 $— 


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

The Company generally posts or receives variation margin cash with its clearing broker on the majority of its financial derivatives as market values of the financial derivatives fluctuate. As of March 31, 2023, the Company had posted $59.8 million aggregate margin cash, consisting of $48.8 million variation margin cash and $11.0 million initial margin. As of December 31, 2022, the Company had posted $255.5 million aggregate margin cash, consisting of $198.0 million variation margin cash and $57.5 million initial margin.
The net amount of asset derivatives, net of variation margin, is included in “Other current assets” and the net amount of liability derivatives, net of variation margin, is included in “Accounts payable and accrued expenses” in the accompanying condensed consolidated balance sheets. The amounts of initial margin are not included with the derivatives presented in the tabular disclosures above and are included in “Other current assets” in the accompanying condensed consolidated balance sheets.
Currently, the Company does not seek cash flow hedge accounting treatment for its derivative financial instruments and thus changes in fair value are reflected in current earnings. The tables below show the amounts of pretax gains and losses related to the Company’s derivatives and their classification within the accompanying unaudited condensed consolidated statements of operations.
Three Months Ended March 31, 2023
Total (loss) gain recognized in income(Loss) gain realized in income on derivativesUnrealized (loss) gain recognized in income on derivatives
Derivative InstrumentClassification
(Dollars in millions)
Foreign currency option contractsOperating costs and expenses$(5.0)$(2.8)$(2.2)
Derivative contracts related to forecasted salesRevenue68.1 (50.6)118.7 
Financial trading contractsRevenue— 17.3 (17.3)
Total$63.1 $(36.1)$99.2 
Three Months Ended March 31, 2022
Total gain (loss) recognized in incomeLoss realized in income on derivativesUnrealized gain (loss) recognized in income on derivatives
Derivative InstrumentClassification
(Dollars in millions)
Foreign currency option contractsOperating costs and expenses$2.3 $(1.0)$3.3 
Derivative contracts related to forecasted salesRevenue(369.0)(68.0)(301.0)
Financial trading contractsRevenue10.1 (0.7)10.8 
Total$(356.6)$(69.7)$(286.9)
The Company classifies the cash effects of its derivatives within the “Cash Flows From Operating Activities” section of the unaudited condensed consolidated statements of cash flows.
Fair Value Measurements
The Company uses a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1 - inputs are quoted prices in active markets for the identical assets or liabilities; Level 2 - inputs are other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3 - inputs are unobservable, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.

First Lien Lender Claims (Classes 1A - 1D)Paid in full in cash.
Second Lien Notes Claims (Classes 2A - 2D)A combination of (1) $450 million of cash, first lien debt and/or new second lien notes and (2)(a) new common stock, par value $0.01 per share, of the Reorganized Peabody (Common Stock) and (b) subscription rights in the Rights Offering.
Other Secured Claims (Classes 3A - 3E)At the election of the Debtors, (1) reinstatement, (2) payment in full in cash, (3) receipt of the applicable collateral or (4) such other treatment consistent with section 1129(b) of the Bankruptcy Code.
Other Priority Claims (Classes 4A - 4E)Paid in full in cash.
General Unsecured ClaimsClass 5A: Against Peabody Energy: a pro rata share of $5 million in cash plus an amount of additional cash (up to $2 million) not otherwise paid to holders of Convenience Claims.
Class 5B: Against the Encumbered Guarantor Debtors: (1) Common Stock and subscription rights in the Rights Offering or (2) at the election of the claim holder, cash from a pool of $75 million in cash to be paid by the Debtors and the Reorganized Debtors into a segregated account in accordance with the terms set forth in the Plan.
Class 5C: Against the Gold Fields Debtors: units in the Gold Fields Liquidating Trust.
Class 5D: Against Peabody Holdings (Gibraltar) Limited: no recoveries.
Class 5E: Against the Unencumbered Debtors: cash in the amount of such holder’s allowed claim, less any amounts attributable to late fees, postpetition interest or penalties.
Convenience ClaimsClass 6A: Against Peabody Energy: up to 72.5% of such claim in cash, provided that total payments to Convenience Claims may not exceed $2 million.
Class 6B: Against the Encumbered Guarantor Debtors: up to 72.5% of such claim in cash, provided that total payments to Convenience Claims may not exceed $18 million.
United Mine Workers of America 1974 Pension Plan Claim
(Classes 7A - 7E)
$75 million in cash paid over five years. See Note 5. “Discontinued Operations,” for additional details.
11

Unsecured Subordinated Debentures Claims
(Class 8A)
(1) Payment of the reasonable and documented fees and expenses of the trustee under the 2066 subordinated indenture up to $350,000; and (2) because this class voted in favor of the Plan and in connection with the settlement of certain potential intercreditor disputes as part of the global settlement embodied therein, and because the trustee under the 2066 subordinated indenture did not object to, and affirmatively supported, the Plan, holders of allowed Unsecured Subordinated Debenture Claims received from specified noteholder co-proponents their pro rata share of penny warrants exercisable for 1.0% of the fully diluted Reorganized Peabody common stock from the pool of penny warrants issued to the noteholder co-proponents under the Rights Offering and/or the terms of the Backstop Commitment Agreement (as defined below).
Section 510(b) Claims
(Class 10A)
No recovery.
Peabody Energy Equity Interests
(Class 11A)
No recovery, as further described under Cancellation of Prior Common Stock below.



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

Cancellation of Prior Common Stock
In accordance withThe following tables set forth the Plan and as previously disclosed, each sharehierarchy of the Company’s common stock outstanding prior tonet (liability) asset positions for which fair value is measured on a recurring basis. Variation margin cash associated with the Effective Date,derivative balances is excluded from this table.
 March 31, 2023
 Level 1Level 2Level 3Total
 (Dollars in millions)
Foreign currency option contracts$— $— $— $— 
Derivative contracts related to forecasted sales— (48.7)— (48.7)
Financial trading contracts— (0.1)— (0.1)
Equity securities0.3 — — 0.3 
Total net assets (liabilities)$0.3 $(48.8)$— $(48.5)
 December 31, 2022
 Level 1Level 2Level 3Total
 (Dollars in millions)
Foreign currency option contracts$— $3.0 $— $3.0 
Derivative contracts related to forecasted sales— (209.7)— (209.7)
Financial trading contracts— 11.7 — 11.7 
Equity securities— — 2.5 2.5 
Total net (liabilities) assets$— $(195.0)$2.5 $(192.5)
For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including all optionsinterest rate yield curves, exchange indices, broker/dealer quotes, published indices, issuer spreads, benchmark securities and warrants to purchase such stock, were extinguished, canceled and discharged, and each such share, option or warrant has no further force or effect asother market quotes. In the case of the Effective Date. Furthermore, allcertain 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 option contracts are 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.
•Derivative contracts related to forecasted sales and financial trading contracts are 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.
•Investments in equity award agreements under prior incentive plans,securities are currently based on unadjusted quoted prices in active markets (Level 1).
Other Financial Instruments. The following methods and assumptions were used by the awards granted pursuant thereto, were extinguished, canceled and discharged and have no further force or effectCompany in estimating fair values for other financial instruments as of the Effective Date.March 31, 2023 and December 31, 2022:
Issuance of Equity Securities
Section 1145 Securities
On the Effective Date•Cash and simultaneous with the cancellation of the prior common stock discussed above, in connection withcash equivalents, restricted cash, accounts receivable, including those within the Company’s emergence from the Chapter 11 Casesaccounts receivable securitization program, margining cash, notes receivable and in reliance on the exemption from registration requirements of the Securities Act of 1933 (the Securities Act) provided by Section 1145 of the Bankruptcy Code, the Company issued:
11.6 million shares of Common Stock to holders of Allowed Claims (as defined in the Plan) in Classes 2A, 2B, 2C, 2D and 5B on account of such claims as provided in the Plan; and
51.2 million shares of Common Stock and 2.9 million Warrants (the 1145 Warrants) pursuantaccounts payable have carrying values which approximate fair value due to the completed Rights Offering to certain holders of the Company’s prepetition indebtedness for total consideration of $704.4 million.
Any shares of Common Stock issued pursuant to the exercise of such 1145 Warrants were similarly issued pursuant to the exemption from registration provided by Section 1145 of the Bankruptcy Code.
Section 4(a)(2) Securities
In addition, on the Effective Date, in connection with the Company’s emergence from the Chapter 11 Cases and in reliance on the exemption from registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act, the Company issued:
30.0 million shares of Series A Convertible Preferred Stock (the Preferred Stock) to parties to the Private Placement Agreement, dated as of December 22, 2016 (as amended, the Private Placement Agreement), among the Company and the other parties thereto, for total consideration of $750.0 million;
3.3 million shares of Common Stock and 0.2 million Warrants (the Private Warrants, and together with the 1145 Warrants, the Warrants) to parties to the Backstop Commitment Agreement, dated as of December 22, 2016 (as amended, the Backstop Commitment Agreement), among the Company and the other parties thereto, on account of their commitments under that agreement, for total consideration of $45.6 million; and
4.8 million shares of Common Stock and 3.1 million additional Private Warrants to specified parties to the Private Placement Agreement and Backstop Commitment Agreement on account of commitment premiums contemplated by those agreements.
Any shares of Common Stock issued pursuant to the conversion of the Preferred Stockshort maturity or the exerciseliquid nature of such Private Warrants have been or will be issued pursuantthese instruments.
•Long-term debt fair value estimates are based on observed prices for securities when available (Level 2), and otherwise on estimated borrowing rates to discount the exemption from registration provided by Section 3(a)(9) and/or Section  4(a)(2) of the Securities Act. The securities issued in reliance on Section 4(a)(2) of the Securities Act were subjectcash flows to restrictions on transfer; however, substantially all such shares were registered with the SEC on a resale Form S-1 effective July 14, 2017.
Current Equity Structure
During the three months ended September 30, 2017, the Company made repurchases of approximately 2.5 million shares of its Common Stock pursuant to its share repurchase program, as described in Note 16. “Other Events”their present value (Level 3). As of September 30, 2017, the Company would have approximately 134.8 million shares of Common Stock outstanding, assuming full conversion of the Preferred Stock (including make-whole shares issuable upon conversion of the Preferred Stock). This amount excludes approximately 3.5 million shares of Common Stock which underlie unvested equity awards granted under the 2017 Incentive Plan (as defined below).



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

Other Forms of Equity Authorized underMarket risk associated with the Company’s Certificatefixed- and variable-rate long-term debt relates to the potential reduction in the fair value and negative impact to future earnings, respectively, from an increase in interest rates. The fair value of Incorporationdebt, shown below, is principally based on reported market values and estimates based on interest rates, maturities, credit risk, underlying collateral and completed market transactions.
As noted on the accompanying condensed consolidated balance sheets, the
 March 31, 2023December 31, 2022
 (Dollars in millions)
Total debt at par value$345.0 $343.6 
Less: Unamortized debt issuance costs(9.4)(9.8)
Net carrying amount$335.6 $333.8 
Estimated fair value$511.3 $560.0 
The Company’s Fourth Amended and Restated Certificate of Incorporation authorizes the issuances of additional series of preferred stock, as well as series common stock. Other than the Series A Convertible Preferred Stock, no other series of preferred stockrisk management function, which is outstanding as of September 30, 2017. Additionally, as of September 30, 2017, no series common stock is outstanding. A copyindependent of the Company’s Fourth Amendedcoal trading function, is responsible for valuation policies and Restated Certificateprocedures, with oversight from executive management. The fair value of Incorporation is included as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed bycoal derivative assets and liabilities reflects adjustments for credit risk. The Company’s exposure to credit risk is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses.
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.
During the three months ended March 31, 2023, the entity in which the Company with the SEC on Aprilheld a Level 3 2017.
Preferred Stock
The Preferred Stock accrues dividends atinvestment in equity securities completed a rate of 8.5% per year, payable in-kind semi-annually on April 30merger transaction and October 31 of each year as additionalits shares of Series A Convertible Preferred Stock, and may be converted into a number of shares of Common Stock as described below. The Preferred Stock will also participate on an as-converted basis (giving effect to any accrued and unpaid dividends) in any dividend, distribution or payments to holders of Common Stock. Upon the Company’s liquidation, dissolution or wind up, whether voluntarily or involuntarily, the holders of Preferred Stock are granted a liquidation preference of $25.00 per share of Preferred Stock, plus any accrued but unpaid dividends through the date of liquidation. The Preferred Stock may also participate on an as-converted basis in any payments upon liquidation payable to the holders of Common Stock.
The Preferred Stock shall be convertible into Common Stock at any time, at the option of the holders at an initial conversion price of $16.25, representing a discount of 35% to the equity value assigned to the Common Stock by the Plan (subject to customary anti-dilution adjustments, the Conversion Price). If at any time following the Effective Date, less than 7,500,000 shares of Preferred Stock remain outstanding, then the Company shall have the right, but not the obligation, to redeem all (but not less than all) of the remaining shares of Preferred Stock, following thirty days’ notice, and on no more than 60 days’ notice, at a redemption price equal to $25.00 per share of Preferred Stock, payable in cash or shares of Common Stock at the Company’s election, subject to certain adjustments; provided that the Company shall not redeem any shares of Preferred Stockwere exchanged for cash during any time that any obligations under the Successor Credit Agreement (as defined below) remain outstanding. At any time following the Effective Date, if holders of at least 66 2/3% of the outstanding Preferred Stock elect to convert, then all remaining outstanding Preferred Stock will automatically convert at the same time and on the same terms.
In addition, beginning on the Effective Date, each outstanding share of Preferred Stock shall automatically convert into a number of shares of Common Stock at the Conversion Price (such conversion, the Mandatory Conversion) if the volume weighted average price of the Common Stock exceeds $32.50 (the Conversion Threshold) for at least 45 trading days in a 60 consecutive trading day period, including each of the last 20 days in such 60 consecutive trading day period (such period, the Mandatory Conversion Period).
Finally, the Preferred Stock shall automatically convert into shares of Common Stock immediately prior to the consummation of a Fundamental Change (generally defined as significant business combinations, as fully defined in the Certificate of Designation of Series A Convertible Preferred Stock included as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on April 3, 2017) if either (1) at consummation of the Fundamental Change, the price of the Common Stock exceeds the Conversion Threshold, or (2) the consideration payable in the Fundamental Change per share of Common Stock exceeds the Conversion Threshold and is payable in cash.
Upon any optional or mandatory conversion of the Preferred Stock that occurs on or prior to the three year anniversary of its initial issuance, holders of the Preferred Stock will be deemed to have (1) received dividends through the last payment of dividends prior to the conversion, including dividends received on prior dividends, to the extent accrued and not previously paid; and (2) dividends on the shares of Preferred Stock then outstandingthe newly-combined entity, which are publicly traded. The Company recorded an impairment loss of $2.0 million upon the exchange of shares, and any shares deemed issued pursuantwill mark the investment to market as a Level 1 asset prospectively.
The Company had no transfers between Levels 1, 2 and 3 during the three months ended March 31, 2023 and 2022. The Company’s policy is to value all transfers between levels using the beginning of period valuation.
(6) Property, Plant, Equipment and Mine Development
The composition of property, plant, equipment and mine development, net, as of March 31, 2023 and December 31, 2022 is set forth in the table below:
March 31, 2023December 31, 2022
(Dollars in millions)
Land and coal interests$2,514.8 $2,514.7 
Buildings and improvements617.3 594.2 
Machinery and equipment1,578.5 1,543.1 
Less: Accumulated depreciation, depletion and amortization(1,862.7)(1,787.0)
Property, plant, equipment and mine development, net$2,847.9 $2,865.0 
(7)  Income Taxes
The Company's effective tax rate before remeasurement for the three months ended March 31, 2023 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 allowance. The Company’s income tax provision of $118.0 million and income tax benefit of $1.0 million for the three months ended March 31, 2023 and 2022, respectively, included tax provisions of $0.4 million and $1.6 million, respectively, related to the preceding clause accruing from the last dividend date preceding the dateremeasurement of the conversion through, but not including, the threeforeign income tax accounts. The Company’s estimated full year anniversary of their initial issuance, and all dividends on prior dividends. In respect of an optional or mandatory conversion occurring after the three year anniversary of its initial issuance, there shallpretax income is expected to be deemed to have been issuedprimarily generated in respect of all shares of Preferred Stock at the time outstanding (1) dividends through the date of payment of the dividend immediately preceding the date of the conversion, including dividends on such dividends, to the extent accrued and not previously paid, and (2) dividends on (a) the shares of Preferred Stock at the time outstanding and (b) any shares of Preferred Stock deemed issued pursuant to the preceding clause (1) accruing from the date of payment of the dividend immediately preceding the conversion, through, but not including, the date of conversion and all dividends on such dividends.
There are no restrictions on the repurchase or redemption of the Preferred Stock while there is any arrearage in the payment of dividends.

Australia.


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

(8)     Long-term Debt 
The Preferred Stock votes with the Common StockCompany’s total indebtedness as a single class on an as-converted basis on all matters submitted to a voteof March 31, 2023 and December 31, 2022 consisted of the holdersfollowing:
Debt Instrument (defined below, as applicable)March 31, 2023December 31, 2022
(Dollars in millions)
3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes)$320.0 $320.0 
Finance lease obligations25.0 23.6 
Less: Debt issuance costs(9.4)(9.8)
335.6 333.8 
Less: Current portion of long-term debt13.2 13.2 
Long-term debt$322.4 $320.6 
During 2022, the Company utilized various methods allowable or required under its then-existing debt agreements to retire all of Common Stock with the exception of certain matters, as outlined in the Certificate of Designation of Series Aits senior secured long-term debt, leaving only its unsecured 3.250% Convertible Preferred Stock, inSenior Notes due 2028 (the 2028 Convertible Notes), which the holders of Preferred Stock are entitled to vote as a separate class with a majority vote required for approval. Such matters include any Fundamental Change requiring approval of the holders of Common Stockfurther described below, and authorization of cash dividends on Common Stock in excess of $100 million payable in any 12-month period.various finance lease obligations outstanding at December 31, 2022.
Rights Offering
Pursuant to the Plan and Rights Offering, holders of Allowed Claims in Classes 2A, 2B, 2C, 2D and 5B were offered the opportunity to purchase up to 54.5 million units, each unit being comprised of (1) one share of Common Stock and (2) a fraction of a Warrant. The purchase price for the units offered in the Rights Offering was $13.75 per unit. A total of 51.2 million units were purchased in the Rights Offering. Pursuant to the Backstop Commitment Agreement, the remaining 3.3 million units that were not purchased in the Rights Offering were purchased by the parties to the Backstop Commitment Agreement at the same per-unit price.
Registration Rights Agreement2028 Convertible Notes
On the Effective Date, the Company entered intoMarch 1, 2022, through a registration rights agreement (Registration Rights Agreement) with certain parties (together with any person or entity that becomes a party to the Registration Rights Agreement, the Holders) that received shares of the Company’s Common Stock and Preferred Stock in the Company on the Effective Date, as provided in the Plan. The Registration Rights Agreement provides Holders with registration rights for the Holders’ Registrable Securities (as defined in the Registration Rights Agreement). Substantially all of the Holders’ Registrable Securities were registered with the SEC on Form S-1 effective July 14, 2017.
The registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in an underwrittenprivate offering, and the Company’s right to delay or withdraw a registration statement under certain circumstances. A copy of the Registration Rights Agreement is included as Exhibit 10.1 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.
Warrant Agreement
On the Effective Date, the Company entered into a warrant agreement (the Warrant Agreement) with American Stock Transfer and Trust Company, LLC. In accordance with the Plan, the Company issued 6.2 million warrants to purchase one share of Common Stock each at an exercise price of $0.01 per share to all Noteholder Co-Proponents (as definedthe 2028 Convertible Notes in the Plan) and subscribers in the Rights Offering (as defined in the Plan) and related backstop commitment. All Warrants described above under the heading Issuance of Equity Securities were issued under the Warrant Agreement. All unexercised Warrants expired, and the rights of the holders of such Warrants to purchase Common Stock terminated on July 3, 2017, with less than 0.1% of the Warrants unexercised.
A copy of the Warrant Agreement is included as Exhibit 4.1 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.
6.000% and 6.375% Senior Secured Notes (collectively, the Successor Notes)
On February 15, 2017, one of PEC’s subsidiaries entered into an indenture with Wilmington Trust, National Association, as trustee, relating to the issuance by PEC’s subsidiary of $500.0 million aggregate principal amount of 6.000%$320.0 million. The 2028 Convertible Notes are senior secured notes due 2022 (the 2022 Notes) and $500.0 million aggregate principal amount of 6.375% senior secured notes due 2025 (together with the 2022 Notes, the Successor Notes). The Successor Notes were sold on February 15, 2017 in a private transaction exempt from the registration requirementsunsecured obligations of the Securities Act.Company and are governed under an indenture.
Prior to the Effective Date, PEC’s subsidiary depositedThe Company used the proceeds of the offering of the Successor2028 Convertible Notes into an escrow account pending confirmationand available cash to redeem $62.6 million of senior secured notes maturing in 2024 and $257.4 million of senior secured notes maturing in 2025, and to pay related premiums, fees and expenses relating to the offering and redemptions. The Company capitalized $11.2 million of debt issuance costs related to the offering and recognized a loss on early debt extinguishment of $23.0 million during the three months ended March 31, 2022.
The 2028 Convertible Notes will mature on March 1, 2028, unless earlier converted, redeemed or repurchased in accordance with their terms. The 2028 Convertible Notes will bear interest from March 1, 2022 at a rate of 3.250% per year payable semi-annually in arrears on March 1 and September 1 of each year, beginning on September 1, 2022.
During the first quarter of 2023, the Company’s reported common stock prices did not prompt the conversion feature of the Plan and certain other conditions being satisfied. On2028 Convertible Notes. As a result, the Effective Date,2028 Convertible Notes are not convertible at the proceeds fromoption of the Successorholders during the second quarter of 2023.
As of March 31, 2023, the if-converted value of the 2028 Convertible Notes were used to repayexceeded the predecessor first lien obligations.principal amount by $92.6 million.
Interest Charges
The Successor Notes are further described in Note 13. “Long-term Debt” and copiesfollowing table presents the components of the indenture documents underlyingCompany’s interest expense related to its indebtedness and financial assurance instruments such as surety bonds and letters of credit. Additionally, the Successor Notes are incorporated as Exhibit 4.3table sets forth the amount of cash paid for interest and the amount of non-cash interest expense primarily related to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.amortization of debt issuance costs.

Three Months Ended March 31,
20232022
 (Dollars in millions)
Indebtedness$6.4 $25.9 
Financial assurance instruments12.0 13.5 
Interest expense$18.4 $39.4 
Cash paid for interest$19.1 $37.2 
Non-cash interest expense$1.6 $3.8 


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

Covenant Compliance
Successor Credit AgreementThe Company was compliant with all relevant covenants under its debt and other finance agreements at March 31, 2023. The April 2023 termination of the Company’s credit agreement and related letter of credit facility, as described in Note 11. “Financial Instruments and Other Guarantees,” eliminated the related compliance requirements as of March 31, 2023 and prospectively.
(9) 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 credit, excluding service cost” in the unaudited condensed consolidated statements of operations.
Net periodic pension cost (credit) included the following components:
Three Months Ended March 31,
20232022
 (Dollars in millions)
Interest cost on projected benefit obligation$7.4 $5.3 
Expected return on plan assets(6.6)(5.9)
Net periodic pension cost (credit)$0.8 $(0.6)
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 March 31, 2023, the Company’s qualified plans were expected to be at or above the Pension Protection Act thresholds. The Company is not required to make any contributions to its qualified pension plans in 2023 based on minimum funding requirements and does not expect to make any discretionary contributions in 2023 at this time.
In connection with an exit facility commitment letter, on the Effective Date, the CompanyMarch 2022, Peabody Investments Corp. (PIC), a wholly-owned subsidiary of PEC, entered into a creditcommitment agreement datedrelating to the Peabody Investments Corp. Retirement Plan (the Peabody Plan) with The Prudential Insurance Company of America (Prudential) and Fiduciary Counselors Inc., as independent fiduciary to the Peabody Plan. Under the commitment agreement, the Peabody Plan purchased a buy-in group annuity contract (GAC) from Prudential for approximately $500 million and Prudential will reimburse the Peabody Plan for benefit payments to be made to the Peabody Plan’s participants. The benefit obligation was not transferred to Prudential and the Peabody Plan continues to administer and pay the retirement benefits of April 3, 2017, amongPeabody Plan participants and is reimbursed by Prudential for the payment of all benefits covered by the GAC. The purchase of the GAC was funded directly by the Peabody Plan’s assets. There was no impact on the monthly retirement benefits paid to Peabody Plan participants and no material impact on contributions for the Peabody Plan in 2022 or 2023 as a result of this transaction.
In May 2022, the Board of Directors of PIC approved the termination of the Peabody Plan effective July 31, 2022. In June 2022, the Peabody Plan’s participants were notified of the Peabody Plan termination and the Peabody Plan filed an application with the Internal Revenue Service to request a determination as to the qualified status under §401(a) of the Internal Revenue Code of 1986 with respect to the amendment and termination of the Peabody Plan.
In February 2023, as part of the Peabody Plan termination process, the Company announced a program to offer a voluntary lump-sum pension payout to certain active and deferred participants of the Peabody Plan which would fully settle the Peabody Plan’s obligation to them. The program provided participants with a limited-time opportunity to elect to receive a lump-sum settlement of their pension benefit or begin to receive their benefit in the form of a monthly annuity in May 2023. Participants not electing the lump-sum settlement or annuity options will have their pension benefit transferred to a highly qualified insurance company. Through May 1, 2023, the Company settled $21.5 million of its pension obligations for active and deferred participants in the Peabody Plan with an equal amount paid from plan assets.

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Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Net periodic postretirement benefit credit included the following components:
Three Months Ended March 31,
20232022
 (Dollars in millions)
Service cost for benefits earned$0.1 $0.2 
Interest cost on accumulated postretirement benefit obligation2.5 1.7 
Expected return on plan assets(0.1)(0.2)
Amortization of prior service credit(13.4)(13.4)
Net periodic postretirement benefit credit$(10.9)$(11.7)
The Company has established a Voluntary Employees’ Beneficiary Association (VEBA) trust to pre-fund a portion of benefits for non-represented retirees. The Company does not expect to make any discretionary contributions to the VEBA trust in 2023 and plans to utilize a portion of VEBA assets to make certain benefit payments.
(10) Earnings per Share (EPS)
Basic EPS is computed based on the weighted average number of shares of common stock outstanding during the period. Diluted EPS is computed based on the weighted average number of shares of common stock plus the effect of dilutive potential common shares outstanding. As such, the Company includes the 2028 Convertible Notes and share-based compensation awards in its potentially dilutive securities. Generally, dilutive securities are not included in the computation of loss per share when a company reports a net loss from continuing operations as Borrower, Goldman Sachs Bank USA,the impact would be anti-dilutive.
For all but 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 Administrative Agent,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 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.
A conversion of the 2028 Convertible Notes may result in payment in the Company’s common stock. For diluted EPS purposes, the potentially dilutive common stock is assumed to have been converted at the beginning of the period (or at the time of issuance, if later). In periods where the potentially dilutive common stock is included in the computation of diluted EPS, the numerator will be adjusted to add back tax adjusted interest expense related to the convertible debt.
The computation of diluted EPS excluded aggregate share-based compensation awards of less than 0.1 million and approximately 1.2 million for the three months ended March 31, 2023 and 2022, respectively, because to do so would have been anti-dilutive for those periods. Because the potential dilutive impact of such share-based compensation awards is calculated under the treasury stock method, anti-dilution generally occurs when the exercise prices or unrecognized compensation cost per share of such awards are higher than the Company’s average stock price during the applicable period. Anti-dilution also occurs when a company reports a net loss from continuing operations, and the dilutive impact of all share-based compensation awards are excluded accordingly.

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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.
Three Months Ended March 31,
 20232022
(In millions, except per share data)
Basic EPS numerator: 
Income (loss) from continuing operations, net of income taxes$284.1 $(119.8)
Less: Net income (loss) attributable to noncontrolling interests14.3 (1.1)
Income (loss) from continuing operations attributable to common stockholders269.8 (118.7)
Loss from discontinued operations, net of income taxes(1.3)(0.8)
Net income (loss) attributable to common stockholders$268.5 $(119.5)
Diluted EPS numerator:
Income (loss) from continuing operations, net of income taxes$284.1 $(119.8)
Add: Tax adjusted interest expense related to 2028 Convertible Notes2.6 — 
Less: Net income (loss) attributable to noncontrolling interests14.3 (1.1)
Income (loss) from continuing operations attributable to common stockholders272.4 (118.7)
Loss from discontinued operations, net of income taxes(1.3)(0.8)
Net income (loss) attributable to common stockholders$271.1 $(119.5)
EPS denominator: 
Weighted average shares outstanding — basic144.6 136.2 
Dilutive impact of share-based compensation awards0.7 — 
Dilutive impact of 2028 Convertible Notes16.1 — 
Weighted average shares outstanding — diluted161.4 136.2 
Basic EPS attributable to common stockholders: 
Income (loss) from continuing operations$1.87 $(0.87)
Loss from discontinued operations(0.01)(0.01)
Net income (loss) attributable to common stockholders$1.86 $(0.88)
 
Diluted EPS attributable to common stockholders: 
Income (loss) from continuing operations$1.69 $(0.87)
Loss from discontinued operations(0.01)(0.01)
Net income (loss) attributable to common stockholders$1.68 $(0.88)
(11) 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. Such financial instruments provide support for the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other lenders party thereto (the Successor Credit Agreement).performance guarantees. The Successor Credit Agreement originallyCompany 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.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk.
 March 31, 2023December 31, 2022
 Reclamation Support
Other Support (1)
TotalReclamation Support
Other Support (1)
Total
 (Dollars in millions)
Surety bonds$1,236.4 $152.1 $1,388.5 $1,250.1 $126.7 $1,376.8 
Letters of credit (2)
22.4 67.0 89.4 437.8 131.8 569.6 
1,258.8 219.1 1,477.9 1,687.9 258.5 1,946.4 
Less: Letters of credit in support of surety
bonds (3)
(22.4)(5.4)(27.8)(431.7)(37.2)(468.9)
Obligations supported, net$1,236.4 $213.7 $1,450.1 $1,256.2 $221.3 $1,477.5 
(1)    Instruments support obligations related to pension and health care plans, workers’ compensation, property and casualty insurance, customer and vendor contracts, and certain restoration ancillary to prior mining activities.
(2)    March 31, 2023 balances exclude $223.8 million of letters of credit outstanding under the LC Facility and $101.3 million of letters of credit outstanding under the Company’s accounts receivable securitization program that were cancelled by April 14, 2023. The collateral obligations related to such letters of credit were met by the March 31, 2023 funding of collateral trust accounts in connection with the surety agreement amendment described below. Amounts do not include cash collateralized letters of credit.
(3)    Certain letters of credit serve as collateral for surety bonds at the request of surety bond providers.
Surety Agreement Amendment and Collateral Requirements
In April 2023, the Company amended its existing agreement with the providers of its surety bond portfolio, dated November 6, 2020. Under the agreement, the Company was required to post collateral on a $950.0periodic basis through December 31, 2025. Prior to the April 2023 amendment, the Company had posted cumulative collateral of $557.8 million, senior secured term loan, which maturesprimarily in 2022the form of letters of credit.
Under the April 2023 amendment, the Company and surety providers agreed to a maximum aggregate collateral amount of $721.8 million based upon bonding levels at the effective date of the amendment. This maximum collateral amount represents a negotiated increase from the uncapped cumulative collateral amount prior to the amendment describedand may vary prospectively as future bonding levels increase or decrease. The amendment also removes restrictions on the payment of dividends and share repurchases, and extends the agreement through December 31, 2026. In order to maintain the new maximum collateral standstill, the Company must remain compliant with a minimum liquidity test and a maximum net leverage ratio, as measured each quarter. The minimum liquidity test requires the Company to maintain liquidity at the greater of $400 million or the difference between the penal sum of all surety bonds and the amount of collateral posted in Note 13. “Long-term Debt,”favor of surety providers. The Company must also maintain a maximum net leverage ratio of 1.5 to 1.0, where the numerator consists of its funded debt, net of cash, and the denominator consists of its Adjusted EBITDA for the trailing twelve months. For purposes of calculating the ratio, only 50% of the outstanding principal amount of the Company’s 2028 Convertible Notes is deemed to be funded debt. The Company’s ability to pay dividends and make share repurchases is also subject to the quarterly minimum liquidity test. Such compliance requirements will commence for the second quarter of 2023. The Company granted second liens on $200.0 million of mining equipment under the original agreement, which remain in force under the April 2023 amendment.
To fund the maximum collateral amount, the Company deposited $566.3 million into trust accounts for the benefit of certain surety providers on March 31, 2023. The remainder was comprised of $140.5 million of existing cash-collateralized letters of credit and $15.0 million already held on behalf of a surety provider. The amendment became effective on April 14, 2023, when the Company terminated a credit agreement which, as amended, provided for $237.2 million of capacity for irrevocable standby letters of credit (LC Facility). The $223.8 million of letters of credit that were outstanding under the LC Facility at March 31, 2023 were subsequently cancelled and, in certain cases, replaced by cash-collateralized letters of credit or letters of credit issued under the Company’s accounts receivable securitization program.
LC Facility
The now-terminated LC Facility had an original capacity of $324.0 million and was subsequently amended at various dates to reduce its capacity and effect certain other changes, including in February 2023 to reduce capacity by $65.0 million, accelerate the expiration date to December 31, 2023 from December 31, 2024, and eliminate the prepayment premium due upon any reduction of commitments thereunder prior to July 29, 2023. The Company recorded early debt extinguishment losses of $6.8 million during the three months ended March 31, 2023, primarily as a result of the February 2023 amendment.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Prior to its termination, undrawn letters of credit under the LC Facility bore interest at LIBOR plus 4.50%6.00% per annum withand unused commitments were subject to a 1.00% LIBOR floor. Following the amendment the loan bears interest at LIBOR plus 3.50%0.50% per annum with a 1.00% LIBOR floor. On the Effective Date, the proceeds from the Successor Credit Agreement were used to repay the predecessor first lien obligations.commitment fee.
The Successor Credit Agreement and the amendment are further described in Note 13. “Long-term Debt.” A copy of the Successor Credit Agreement is included as Exhibit 10.3 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017 and a copy of the amendment is included as Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on September 18, 2017.
Accounts Receivable Securitization Facility
In connection with a receivables securitization program commitment letter, on the Effective Date,2017, the Company entered into the Sixth Amended and Restated Receivables Purchase Agreement, as amended dated asfrom time to time (the Receivables Purchase Agreement.) The receivables securitization program authorized under the agreement (Securitization Program) is subject to customary events of April 3, 2017 (Receivables Purchase Agreement), among P&L Receivables Company, LLC (P&L Receivables), as the Seller, the Company, as the Servicer, the sub-servicers party thereto, the various purchasers and purchaser agents party thereto and PNC Bank, National Association (PNC), as administrator.default. The Receivables Purchase Agreement extendswas amended in February 2023 to increase the available funding capacity from $175.0 million to $225.0 million and adjust the relevant interest rate for borrowings to a secured overnight financing rate (SOFR). Such funding is accounted for as a secured borrowing, limited to the availability of eligible receivables, securitization facility previouslyand may be secured by a combination of collateral and the trade receivables underlying the program. Funding capacity under the Securitization Program may also be utilized for letters of credit in place and expands that facility to include certain receivables fromsupport of other obligations, which has been the Company’s Australianprimary utilization.
Borrowings under the Securitization Program bear interest at SOFR plus 2.1% per annum and remain outstanding throughout the term of the agreement, subject to the Company maintaining sufficient eligible receivables.
At March 31, 2023, the Company had no outstanding borrowings and $190.7 million of letters of credit outstanding under the Securitization Program, primarily in support of reclamation obligations. Availability under the Securitization Program, which is adjusted for certain ineligible receivables, was $15.3 million at March 31, 2023. The Company was not required to post cash collateral under the Securitization Program at March 31, 2023. By April 14, 2023, $101.3 million of letters of credit outstanding under the Securitization Program were cancelled in connection with the surety agreement amendment and related trust accounts described above.
The Company incurred interest and fees associated with the Securitization Program of $1.0 million and $0.9 million during the three months ended March 31, 2023 and 2022, respectively, which have been recorded as “Interest expense” in the accompanying unaudited condensed consolidated statements of operations.
Collateralized Letter of Credit Agreement
In February 2022, the Company entered into an agreement which provides up to $250.0 million of capacity for irrevocable standby letters of credit, primarily to support reclamation bonding requirements. The Receivables Purchase Agreement is further described in Note 18. “Financial Instruments and Other Guarantees” andagreement requires the Company to provide cash collateral at a copylevel of 103% of the Receivables Purchase Agreement is included as Exhibit 10.4aggregate amount of letters of credit outstanding under the arrangement (limited to $5.0 million total excess collateralization.) Outstanding letters of credit bear a fixed fee in the Current Reportamount of 0.75% per annum. The Company receives a variable deposit rate on Form 8-K filedthe amount of cash collateral posted in support of letters of credit. The agreement has an initial expiration date of December 31, 2025. At March 31, 2023, letters of credit of $245.3 million were outstanding under the agreement, which were collateralized by the Company with the SEC on April 3, 2017.

cash of approximately $250.0 million.


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

Restricted Cash and Collateral
Cancellation of Prepetition Obligations
In accordanceThe following table summarizes the Company’s “Restricted cash and collateral” in the accompanying condensed consolidated balance sheets. Restricted cash balances are held in controlled accounts with the Plan, on the Effective Date all of the obligations of the Debtors with respectminimum balance requirements; withdrawals are subject to the following debt instruments were canceled:
Indenture governing $1,000.0 million outstanding aggregate principal amountapproval of account beneficiaries, such as the Company’s 10.00% Senior Secured Second Lien Notes due 2022, dated as of March 16, 2015, amongsurety providers, who have perfected security interests in the funds. The Company’s other collateral generally includes deposits held by regulatory authorities or financial institutions over which the Company U.S. Bank National Association (U.S. Bank),has no control or ability to access.
March 31, 2023December 31, 2022
 (Dollars in millions)
Restricted cash (1)
Surety trust accounts (2)
$566.3 $— 
Collateralized letters of credit funding (2)
247.9 110.3 
814.2 110.3 
Other collateral (1)
Deposits with regulatory authorities for reclamation and other obligations78.4 33.6 
LC Facility (3)
29.1 28.5 
Deposit held on behalf of surety15.0 15.0 
122.5 77.1 
Restricted cash and collateral$936.7 $187.4 
(1)    Restricted cash balances are combined with unrestricted cash and cash equivalents in the accompanying unaudited condensed consolidated statements of cash flows; changes in restricted cash balances are thus not reflected in the operating, investing or financing activities therein. Changes in other collateral balances are reflected as trustee and collateral agent,operating activities therein.
(2)    Surety trust accounts and the guarantors named therein, as supplemented;
Indenture governing $650.0 million outstanding aggregate principal amount of the Company’s 6.50% Senior Notes due 2020, dated as of March 19, 2004, among the Company, U.S. Bank, as trustee, and the guarantors named therein, as supplemented;
Indenture governing $1,518.8 million outstanding aggregate principal amount of the Company’s 6.00% Senior Notes due 2018, dated as of November 15, 2011, among the Company, U.S. Bank, as trustee, and the guarantors named therein, as supplemented;
Indenture governing $1,339.6 million outstanding aggregate principal amount of the Company’s 6.25% Senior Notes due 2021, dated as of November 15, 2011, by and among the Company, U.S. Bank, as trustee, and the guarantors named therein, as supplemented;
Indenture governing $250.0 million outstanding aggregate principal amount of the Company’s 7.875% Senior Notes due 2026, dated as of March 19, 2004, among the Company, U.S. Bank, as trustee, and the guarantors named therein, as supplemented;
Subordinated Indenture governing $732.5 million outstanding aggregate principal amount of the Company’s Convertible Junior Subordinated Debentures due 2066, dated as of December 20, 2006, among the Company and U.S. Bank, as trustee, as supplemented; and
Amended and Restated Credit Agreement, as amended and restated as of September 24, 2013 (the 2013 Credit Facility), related to $1,170.0 million outstanding aggregate principal amount of term loans under a term loan facility (the 2013 Term Loan Facility) and $1,650.0 million under a revolving credit facility (the 2013 Revolver), which includes approximately $675.0 million of posted but undrawnfunding for collateralized letters of credit are comprised of highly liquid investments with original maturities of three months or less; interest and approximately $947.0 million in outstanding borrowings, by and among the Company, Citibank, N.A., as administrative agent, swing line lender and letter of credit issuer, Citigroup Global Markets, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, BNP Paribas Securities Corp., Crédit Agricole Corporate and Investment Bank, HSBC Securities (USA) Inc., Morgan Stanley Senior Funding, Inc., PNC Capital Markets LLC and RBS Securities Inc., as joint lead arrangers and joint book managers, and the lender parties thereto, as amended by that certain Omnibus Amendment Agreement, dated as of February 5, 2015.
2017 Incentive Compensation Plan
In accordance with the Plan, the Peabody Energy Corporation 2017 Incentive Plan (the 2017 Incentive Plan) became effective as of the Effective Date. The 2017 Incentive Plan is intended to, among other things, help attract and retain employees and directors upon whom, in large measure, the Company depends for sustained progress, growth and profitability. The 2017 Incentive Plan also permits awards to consultants.
Unless otherwise determined by the Board, the compensation committee of the Board will administer the 2017 Incentive Plan. The 2017 Incentive Plan generally provides for the following types of awards:
options (including non-qualified stock options and incentive stock options);
stock appreciation rights;
restricted stock;
restricted stock units;
deferred stock;
performance units;
dividend equivalents; and
cash incentive awards.
The aggregate number of shares of Common Stock reserved for issuance pursuantearnings on such funds accrue to the 2017 Incentive Plan is 14.1 million. The 2017 Incentive Plan will remain in effect, subject to the right of the Board to terminate the 2017 Incentive Plan at any time, subject to certain restrictions, until the earlier to occur of (a) the date all shares of Common Stock subject to the 2017 Incentive Plan are purchased or acquired and the restrictions on all restricted stock granted under the 2017 Incentive Plan have lapsed, according to the 2017 Incentive Plan’s provisions, and (b) ten years from the Effective Date.Company.


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

Reorganization Value
Fresh start reporting provides, among other things, for a determination of the value to be assigned to the equity of the emerging company as of a date selected for financial reporting purposes. In conjunction with the bankruptcy proceedings, a third-party financial advisor provided an enterprise value of the Company of approximately $4.2 billion to $4.9 billion. The final equity value of $3,081.0 million was based upon the approximate low end of the enterprise value established by the third-party valuation and cash held by the Successor company in connection with the emergence from the Chapter 11 Cases, less the fair value of Successor debt issued on the Effective Date as described above. The final equity value equated to a per share value of $22.03 per equivalent common share issued in accordance with the Plan.
The enterprise value of the Company was estimated using two primary valuation methods: a comparable public company analysis and a discounted cash flow (DCF) analysis. The comparable public company analysis is based on the enterprise value of selected publicly traded companies that have operating and financial characteristics comparable in certain respects to the Company, for example, operational requirements and risk and profitability characteristics. Selected companies were comprised of coal mining companies with primary operations in the United States. Under this methodology, certain financial multiples and ratios that measure financial performance and value were calculated for each selected company and then applied(3)    Balance relates to the Company’s financials to imply an enterprise value formandatory repurchase of $30.0 million priority lien obligations under the Company.
LC Facility during 2022 at approximately 95%. The DCF analysis is a forward-looking enterprise valuation methodology that estimates the value of an asset or business by calculating the present value of expected future cash flows by that asset or business. The basisCompany received $30.0 million upon termination of the DCF analysis was the Company’s prepared projections which included a varietyLC Facility on April 14, 2023.
(12) Commitments and Contingencies
Commitments
Unconditional Purchase Obligations
As of estimates and assumptions, such as pricing and demandMarch 31, 2023, purchase commitments for coal. The Company’s pricing was based on its view of the market taking into account third-party forward pricing curves adjusted for the quality of products sold by the Company. While the Company considers such estimates and assumptions reasonable, they are inherently subject to significant business, economic and competitive uncertainties, manycapital expenditures were $105.4 million, all of which are beyondis obligated within the Company’s control and, therefore, may not be realized. Changes in these estimates and assumptions may have a significant effect onnext two years, with $97.4 million obligated within the determination of the Company’s enterprise value. The assumptions used in the calculations for the DCF analysis included projected revenue, cost and cash flows for the nine months ending December 31, 2017 through each respective mine life and represented the Company’s best estimates at the time the analysis was prepared. The DCF analysis was completed using discount rates ranging from 11% to 14%. The DCF analysis involves complex considerations and judgments concerning appropriate discount rates. Due to the unobservable inputs to the valuation, the fair value would be considered Level 3 in the fair value hierarchy.next 12 months.
Grant of Emergence Awards
On the Effective Date, the Company granted restricted stock units under the 2017 Incentive Plan and the terms of the relevant restricted stock unit agreement to all employees, including its executive officers (the Emergence Awards). The fair value of the Emergence Awards on the Effective Date was $80.0 million. The Emergence Awards grantedThere were no other material changes to the Company’s executive officers generally will vest ratably on each ofcommitments from the first three anniversaries of the Effective Date, subject to, among other things, each such executive officer’s continued employment with the Company. The Emergence Awards will become fully vested upon each such executive officer’s termination of employment by the Company and its subsidiaries without Cause or by the executive for Good Reason (each, as definedinformation provided in the 2017 Incentive Plan or award agreement) or due to a termination of employment with the Company and its subsidiaries by reason of death or Disability (as defined in the 2017 Incentive Plan or award agreement). In order to receive the Emergence Awards, the executive officers were required to execute restrictive covenant agreements protecting the Company’s interests.
Copies of the 2017 Incentive Plan and related documents are included as Exhibits 10.7 and 10.8 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017.


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

Effect of Plan and Fresh Start Reporting Adjustments
The following balance sheet illustrates the impacts of the implementation of the Plan and the application of fresh start reporting, which results in the opening balance sheet of the Successor company.
As of April 1, 2017Predecessor (a) 
Effect of Plan
(b)
 Fresh Start Adjustments (c) Successor
 (Dollars in millions)
ASSETS       
Current assets       
Cash and cash equivalents$1,068.1
 $(14.4)(d)$—
 $1,053.7
Restricted cash80.7
 (54.7)(d)—
 26.0
Successor Notes issuance proceeds - restricted cash1,000.0
 (1,000.0)(d)—
 —
Accounts receivable, net312.1
 —
 —
 312.1
Inventories250.8
 —
 70.1
(k)320.9
Assets from coal trading activities, net0.6
 —
 —
 0.6
Other current assets493.9
 (18.1)(e)(333.0)(l)142.8
Total current assets3,206.2
 (1,087.2) (262.9) 1,856.1
Property, plant, equipment and mine development, net8,653.9
 —
 (3,461.4)(m)5,192.5
Investments and other assets976.4
 3.9
(f)238.0
(n)1,218.3
Total assets$12,836.5
 $(1,083.3) $(3,486.3) $8,266.9
LIABILITIES AND STOCKHOLDERS’ EQUITY       
Current liabilities       
Current portion of long-term debt$18.2
 $9.5
(g)$—
 $27.7
Liabilities from coal trading activities, net0.7
 —
 —
 0.7
Accounts payable and accrued expenses967.3
 257.6
(h)14.8
(o)1,239.7
Total current liabilities986.2
 267.1
 14.8
 1,268.1
Long-term debt, less current portion950.5
 903.2
(g)—
 1,853.7
Deferred income taxes179.2
 —
 (177.8)(p)1.4
Asset retirement obligations707.0
 —
 (73.9)(q)633.1
Accrued postretirement benefit costs753.9
 —
 (6.9)(r)747.0
Other noncurrent liabilities511.1
 —
 120.6
(s)631.7
Total liabilities not subject to compromise4,087.9
 1,170.3
 (123.2) 5,135.0
Liabilities subject to compromise8,416.7
 (8,416.7)(i)—
 —
Total liabilities12,504.6
 (7,246.4) (123.2) 5,135.0
Stockholders’ equity       
Common Stock (Predecessor)0.2
 (0.2)(j)—
 —
Common Stock (Successor)—
 0.7
(b)—
 0.7
Series A Preferred Stock (Successor)—
 1,305.4
(b)—
 1,305.4
Additional paid-in capital (Predecessor)2,423.9
 (2,423.9)(j)—
 —
Additional paid-in capital (Successor)—
 1,774.9
(b)—
 1,774.9
Treasury stock, at cost(371.9) 371.9
(j)—
 —
Accumulated deficit(1,284.1) 5,134.3
(j)(3,850.2)(t)—
Accumulated other comprehensive loss(448.5) —
 448.5
(t)—
Peabody Energy Corporation stockholders’ equity319.6
 6,163.1
 (3,401.7) 3,081.0
Noncontrolling interests12.3
 —
 38.6
(u)50.9
Total stockholders’ equity331.9
 6,163.1
 (3,363.1) 3,131.9
Total liabilities and stockholders’ equity$12,836.5
 $(1,083.3) $(3,486.3) $8,266.9





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

(a)Represents the Predecessor consolidated balance sheet at April 1, 2017.
(b)Represents amounts recorded for the implementation of the Plan on the Effective Date. This includes the settlement of liabilities subject to compromise through a combination of cash payments, the issuance of new common stock and warrants and the issuance of new debt. The following is the calculation of the total pre-tax gain on the settlement of the liabilities subject to compromise.
  (Dollars in millions)
Liabilities subject to compromise $8,416.7
Less amounts issued to settle claims:  
Successor Common Stock (at par) (0.7)
Successor Series A Convertible Preferred Stock (1,305.4)
Successor Additional paid-in capital (1,774.9)
Issuance of Successor Notes (1,000.0)
Issuance of Successor Term Loan (950.0)
Cash payments and accruals for claims and professional fees (336.4)
Other:  
Write-off of Predecessor debt issuance costs, see also (e) below (18.1)
Total pre-tax gain on plan effects, see also (j) below $3,031.2
At the Effective Date, 70.9 million shares of Common Stock were issued and outstanding at a par value of $0.01 per share.
Preferred Stock was recorded at fair value and is based upon the $750.0 million cash raised upon emergence from bankruptcy through the Private Placement Agreement, plus a premium to account for the fair value of the Preferred Stocks’ conversion and dividend features. Each share of Preferred Stock is convertible, at the holder’s election or upon the occurrence of certain triggering events, into shares of Common Stock at a 35% discount relative to the initial per share purchase price of $25.00 and provides for three years of guaranteed paid-in-kind dividends, payable semiannually, at a rate of 8.5% per annum. The 46.2 million shares of Common Stock issuable upon conversion of the Preferred Stock issued under the Plan and an additional 13.1 million shares of Common Stock attributable to such Preferred Stocks’ guaranteed paid-in-kind dividend feature constitute approximately 42% ownership of the Plan Equity Value (as defined in the Plan) of $3,105.0 million in the reorganized Company, and thus have a fair value of $1,305.4 million.
Successor Additional paid-in capital was recorded at the Plan Equity Value less the amounts recorded for par value of the Common Stock, the fair value of the Preferred Stock, and certain fees incurred associated with the Registration Rights Agreement.
(c)Represents the fresh start reporting adjustments required to record the assets and liabilities of the Company at fair value.
(d)The following table reflects the sources and uses of cash and restricted cash at emergence:
  (Dollars in millions)
Sources:  
Private placement and rights offering $1,500.0
Net proceeds from Senior Secured Term Loan 912.7
Escrowed interest from Successor Notes offering 8.0
Net impact on collateral requirements 11.6
Uses:  
Payments to secured lenders (3,489.2)
Professional fees (8.3)
Securitization facility deferred financing costs (3.9)
Total cash outflow at emergence $(1,069.1)


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

(e)Primarily represents the write off of deferred financing costs associated with the cancellation and discharge of Predecessor revolving debt obligations.
(f)Represents the payment of deferred financing costs associated with the Receivables Purchase Agreement.
(g)Represents a new $950 million Senior Secured Term Loan, net of an original issue discount and deferred financing costs of $37.3 million, as contemplated by the Plan. Under the Plan, the Company also issued $1.0 billion of Successor Notes, net of $49.5 million of deferred financing costs. The Successor Notes and the related proceeds held in escrow were included on the Company’s unaudited condensed consolidated balance sheet at March 31, 2017. The new debt instruments issued in accordance with the Plan are further described in Note 13. “Long-term Debt.”
(h)Represents an accrual to account for amounts paid subsequent to the Effective Date for professional fees and certain unsecured claims and settlements set forth in the Plan.
(i)Liabilities subject to compromise include secured and unsecured liabilities incurred prior to the Petition Date. These liabilities represent the amounts expected to be allowed on known or potential claims to be resolved through the Chapter 11 Cases and remain subject to future adjustments based on negotiated settlements with claimants, actions of the Bankruptcy Court, rejection of executory contracts, proofs of claims or other events. Additionally, liabilities subject to compromise also include certain items that were assumed under the Plan, and as such, were subsequently reclassified to liabilities not subject to compromise. Generally, actions to enforce or otherwise effect payment of prepetition liabilities are subject to the injunction provisions set forth in the Plan, as discussed in Note 19.Note 21. “Commitments and Contingencies”. Liabilities subject to compromise consisted of the following immediately prior to emergence and at December 31, 2016:
 Predecessor
 April 1, 2017December 31, 2016
 (Dollars in millions)
Debt (1)
$8,077.4
$8,080.3
Interest payable172.6
172.6
Environmental liabilities61.9
61.9
Trade payables55.2
58.4
Postretirement benefit obligations (2)
23.0
34.6
Other accrued liabilities26.6
32.4
Liabilities subject to compromise$8,416.7
$8,440.2
(1)
Includes $7,768.3 million and $7,771.2 million of first lien, second lien and unsecured debt at April 1, 2017 and December 31, 2016, respectively, and $257.3 million of derivative contract terminations, and $51.8 million of liabilities secured by prepetition letters of credit at April 1, 2017 and December 31, 2016.
(2)
Includes liabilities for unfunded non-qualified pension plans, all the participants of which are former employees.
(j)Reflects the impacts of the reorganization adjustments:
  (Dollars in millions)
Total pre-tax gain on plan effects, see also (b) above $3,031.2
Cancellation of Predecessor Common Stock 0.2
Cancellation of Predecessor Additional paid-in capital 2,423.9
Cancellation of Predecessor Treasury stock (371.9)
Successor debt issuance costs and other items, see also (f) and (g) above 50.9
Net impact on accumulated deficit $5,134.3
(k)Represents adjustment to increase the book value of coal inventories to their estimated fair value, less costs to sell the inventories.
(l)Represents adjustments comprising $228.5 million related to assets classified as held-for-sale at March 31, 2017 which were reclassified as held-for-use and considered in connection with the valuations described in (m) below, $89.5 million to write off certain existing short-term mine development costs, and $15.0 million of various prepaid assets deemed to have no future utility subsequent to the Effective Date.


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

(m)Represents a $3,461.4 million reduction in property, plant and equipment to estimated fair value as discussed below:
  Predecessor Fresh Start Adjustments Successor
  (Dollars in millions)
Land and coal interests $10,297.7
 $(6,511.8) $3,785.9
Buildings and improvements 1,479.3
 (1,013.2) 466.1
Machinery and equipment 2,143.8
 (1,203.3) 940.5
Less: Accumulated depreciation, depletion and amortization (5,266.9) 5,266.9
 —
Net impact on accumulated deficit $8,653.9
 $(3,461.4) $5,192.5
The fair value of land and coal interests, excluding the asset related to the Company’s asset retirement obligations described below, was established at $3,504.7 million utilizing a DCF model and the market approach. The market approach was used to provide a starting value of the coal mineral reserves without consideration for economic obsolescence. The DCF model was based on assumptions market participants would use in the pricing of these assets as well as projections of revenues and expenditures that would be incurred to mine or maintain these coal reserves through the life of mine. The basis of the DCF analysis was the Company’s prepared projections which included a variety of estimates and assumptions, such as pricing and demand for coal. The Company’s pricing was based on its view of the market taking into account third-party forward pricing curves adjusted for the quality of products sold by the Company. The fair value of land and coal interests also includes $281.2 million corresponding to the asset retirement obligation discussed in item (q) below.
The fair value of buildings and improvements and machinery and equipment were set at $466.1 million and $940.5 million, respectively, utilizing both market and cost approaches. The market approach was used to estimate the value of assets where detailed information for the asset was available and an active market was identified with a sufficient number of sales of comparable property that could be independently verified through reliable sources. The cost approach was utilized where there were limitations in the secondary equipment market to derive values from. The first step in the cost approach is the estimation of the cost required to replace the asset via construction or purchasing a new asset with similar utility adjusting for depreciation due to physical deterioration, functional obsolescence due to technology changes and economic obsolescence due to external factors such as regulatory changes. Useful lives were assigned to all assets based on remaining future economic benefit of each asset.
(n)Primarily to recognize fair value of $314.9 million inherent in certain U.S. coal supply agreements as a result of favorable differences between contract terms and estimated market terms for the same coal products, partially offset by a reduction in the fair value of certain equity method investments. The intangible asset related to coal supply agreements will be amortized on a per ton shipped basis through 2025, predominately over the next three years. See also Note 9. “Intangible Contract Assets and Liabilities.”
(o)Represents $32.6 million to account for the short-term portion of the value of certain contract-based intangibles primarily consisting of unutilized capacity of certain port and rail take-or-pay contracts, partially offset by $15.7 million related to liabilities classified as held-for-sale at March 31, 2017 which were reclassified as held-for-use and considered in connection with the valuations described in (m) above, and various other fair value adjustments. The intangible liabilities related to port and rail take-or-pay contracts will be amortized ratably over the terms of each contact, which vary in duration through 2043.
(p)Represents the tax impact of fresh start reporting. See also Note 12. “Income Taxes.”
(q)Represents the fair value adjustment related to the Company’s asset retirement obligations which was calculated using DCF models based on current mine plans. The credit-adjusted, risk-free interest rates utilized to estimate the Company’s asset retirement obligations were 9.36% for its U.S. reclamation obligations and 4.36% for its Australia reclamation obligations.
(r)Represents the remeasurement of liabilities associated with the Company’s postretirement benefits obligations as of the Effective Date as the reorganization of the Company pursuant to the Plan represented a remeasurement event under ASC 715 “Compensation - Retirement Benefits.” The relevant discount rate was adjusted to 4.1% from 4.15% used in the Company’s most recent year-end remeasurement process.


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

(s)Represents $83.6 million to account for the long-term portion of the value of contract-based intangibles related to unutilized capacity of port and rail take-or-pay contracts as described in (o) above and $58.7 million to account for the fair value inherent in certain U.S. coal supply agreements as a result of unfavorable differences between contract terms and estimated market terms for the same coal products as described in (n) above, partially offset by a remeasurement reduction of $9.2 million of the Company’s pension liabilities in accordance with ASC 715 as described in (r) above, as the relevant discount rate was adjusted to 4.1% from 4.15% used in the Company’s most recent year-end remeasurement process, and certain other valuation adjustments.
(t)Represents the elimination of remaining equity balances in accordance with fresh start reporting requirements.
(u)Represents adjustment to increase the book value of noncontrolling interests to fair value based on an estimate of the rights of the noncontrolling interests.
Reorganization Items, Net
The Company’s reorganization items for the period January 1 through April 1, 2017, and the three and nine months ended September 30, 2016 consisted of the following:
 Predecessor
  Three Months Ended September 30, 2016 
January 1 through
April 1, 2017
 Nine Months Ended September 30, 2016
 (Dollars in millions)
Gain on settlement of claims (per above) $—
 $(3,031.2) $—
Fresh start adjustments, net (per above) —
 3,363.1
 —
Fresh start income tax adjustments, net —
 253.9
 —
Loss on termination of derivative contracts —
 —
 75.2
Professional fees 31.1
 42.5
 52.7
Accounts payable settlement gains (0.5) (0.7) (0.7)
Interest income (0.9) (0.4) (1.1)
Other —
 —
 (1.0)
Reorganization items, net $29.7
 $627.2
 $125.1
       
Cash paid for “Reorganization items, net” $30.7
 $45.8
 $30.7
The fresh start income tax adjustments included in the above table are comprised of tax benefits related to Predecessor deferred tax liabilities of $177.8 million, accumulated other comprehensive income of $81.5 million and unrecognized tax benefits of $6.7 million, partially offset by $12.1 million of tax expense related to the deferred tax assets of Predecessor discontinued operations.
Professional fees are only those that are directly related to the reorganization including, but not limited to, fees associated with advisors to the Debtors, the unsecured creditors’ committee and certain other secured and unsecured creditors.
During the Successor period April 2, 2017 through September 30, 2017, the Company paid approximately $250 million related to professional fees and certain unsecured claims and settlements set forth in the Plan.
(4)    Asset Impairment
The Company’s mining and exploration assets and mining-related investments may be adversely affected by numerous factors that may cause the Company to be unable to recover all or a portion of the carrying value of those assets. As a result of various unfavorable conditions, including but not limited to sustained trends of weakness in U.S. and international seaborne coal market pricing and certain asset-specific factors, the Company recognized aggregate impairment charges of $247.9 million during the year ended December 31, 2016, which included $17.2 million during the first nine months of 2016 to write down certain targeted divestiture assets in Queensland, Australia. For additional information surrounding those charges, refer to Note 4. “Asset Impairment” to the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 20172022.
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 August 14, 2017.

those that impacted the Company’s consolidated results of operations for the periods presented.


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

Litigation and Matters Relating to Continuing Operations
Metropolitan Mine Stormwater Discharge. Over the past few years, there has been significantly high rainfall in New South Wales, including unprecedented rain totals at the Metropolitan Mine site. While stormwater collected at the mine site is managed through two sedimentation dams, at times the heavy rainfall has presented challenges with managing the significant volumes of stormwater, as the surface water management infrastructure has not had sufficient capacity. As a result, on multiple occasions throughout 2021 and 2022 stormwater has been discharged from the mine site. Metropolitan Collieries Pty Ltd (MCPL), a wholly-owned subsidiary of PEC, removed accumulated material from the sedimentation dams to restore full site stormwater capacity by December 31, 2022 and has identified and is implementing additional controls for the management of sediment moving forward. Despite the measures undertaken by MCPL to manage and improve the situation, the Environment Protection Authority is currently undertaking an investigation in relation to the discharges of sediment laden water from the mine site and a review process of the Metropolitan Mine’s environmental protection license is ongoing. The Environment Protection Authority is investigating potential offenses against the environmental protection legislation arising from the stormwater discharges from the site.
Puerto Rico Climate Change Lawsuit. On November 22, 2022, the Municipalities of Puerto Rico filed a class action complaint for damages against several major energy fuel producers, including Peabody Energy. This lawsuit represents the latest in a series of lawsuits that have been brought in both state and federal court around the United States, generally seeking to impose liability on the energy fuel producers for the effects allegedly caused by climate change. Many of these lawsuits have been brought on behalf of governmental entities (counties, cities, and towns) by plaintiff law firms on a contingent fee arrangement. The causes of action in the Puerto Rico lawsuit include public and private nuisance, liability for failure to warn, consumer fraud, antitrust and claims under the Racketeer Influenced and Corrupt Organizations Act. On April 21, 2023, the plaintiffs filed a Notice of Voluntary Dismissal dismissing all claims against the Company without prejudice.
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 consolidated financial condition, results of operations or cash flows. The Company generally does not view short-term declines subsequentreassesses the probability and estimability of contingent losses as new information becomes available.
Claims, Litigation and Settlements Relating to previous impairment assessments in thermal and metallurgical coal prices in the markets in which it sells its products as an indicator of impairment. However, the Company generally views a sustained trend (for example, over periods exceeding one year) of adverse coal market pricingIndemnities or unfavorable changes thereto as a potential indicator of impairment. Because of the volatile and cyclical nature of U.S. and international seaborne coal markets, it is reasonably possible that prices in those market segments may decrease and/or fail to improve in the near term, which, absent sufficient mitigation such as an offsetting reductionHistorical Operations
Patriot-Related Matters. Included in the Company’s operating costs, may result indiscontinued operations are the need for future adjustments to the carrying value of the Company’s long-lived mining assets and mining-related investments.
During the period January 1 through April 1, 2017, the Company recognized impairment charges of $30.5 million related to terminated coal lease contracts in the Midwestern United States.
(5)    Discontinued Operations
Discontinued operations include certain former Australian Thermal Mining and Midwestern U.S. Mining segment assets that have ceased production and other previously divested legacy operations includingof 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 periodsApril 2 through September 30, 2017, January 1 through April 1, 2017, and the three and nine months ended September 30, 2016:
  SuccessorPredecessor SuccessorPredecessor
  Three Months Ended September 30, 2017Three Months Ended September 30, 2016 April 2 through September 30, 2017January 1 through April 1, 2017 Nine Months Ended September 30, 2016
  (Dollars in millions)
Loss from discontinued operations, net of income taxes $(3.7)$(38.1) $(6.4)$(16.2) $(44.5)


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

Assets and Liabilities of Discontinued Operations
Assets and liabilities classified as discontinued operations included in the Company’s condensed consolidated balance sheets were as follows:
  SuccessorPredecessor
  September 30, 2017December 31, 2016
  (Dollars in millions)
Assets:   
Other current assets $0.2
$0.2
Investments and other assets —
15.9
Total assets classified as discontinued operations $0.2
$16.1
    
Liabilities:   
Accounts payable and accrued expenses $46.2
$55.9
Other noncurrent liabilities 185.5
198.5
Liabilities subject to compromise —
20.9
Total liabilities classified as discontinued operations $231.7
$275.3
Patriot-Related Matters
A significant portion of the liabilities in the table above relate to a former subsidiary, Patriot Coal Corporation. In 2012, Patriot filed voluntary petitions for relief under Chapter 11 of Title 11 of the U.S. Code.Code (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 disputedthen-disputed issues related to Patriot’s bankruptcy. In May 2015, Patriot again filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. District Court for the Eastern District of Virginia and subsequently initiated a process to sell some orsubstantially 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 hashad 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.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
By statute, the Company remains secondarily liablehad 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. The amount of these liabilities could be reduced in the future. Whether the Company will ultimately be required to fund certain of those obligations in the future as a result of Patriot’s May 2015 bankruptcy remains uncertain. The amount of the liability, which was determined on an actuarial basis based on the best information available to the Company, was $125.4$80.7 million and $82.3 million at September 30, 2017.March 31, 2023 and December 31, 2022, respectively. The liability, which is classified as discontinued operations, is included in the Company’s condensed consolidated balance sheets within “Accounts payable and accrued expenses” and “Other noncurrent liabilities.” While the Company has recorded thisa liability, it intends to review each claim on a case-by-case basis and contest liability estimates as appropriate. The amount of the Company’s recorded liability reflects only Patriot workers employed by former subsidiaries of the Company that are presently retired, disabled or otherwise not actively employed. The Company cannot reliably estimate the potential liabilities for Patriot’s workers employed by former subsidiaries of the Company that are presently active in the workforce because of the potential for such workers to continue to work for another coal operator that is a going concern.
The Company’s accounting for the black lung liabilities related to Patriot is based on an interpretation of applicable statutes. Management believes that there exist inconsistencies among the applicable statutes, regulations promulgated under those statutes and the Department of Labor’s interpretative guidance. The Company may seek clarification from the Department of Labor regarding these inconsistencies and the accounting for these liabilities could be reduced in the future depending on the Department of Labor’s responses to inquiries.


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

UMWA VEBA. In connection with the 2013 Agreement, the Company was required to provide total payments of $310.0 million, payable over four years through 2017, to partially fund the newly established voluntary employee beneficiary association (VEBA) and settle all Patriot and UMWA claims involving the Patriot bankruptcy. After making scheduled payments to Patriot and the VEBA amounting to $165 million through 2015, the parties agreed to a settlement of the Company’s remaining VEBA payment obligations for $75 million. As a result of the settlement, the Company recognized a gain of $68.1 million during the nine months ended September 30, 2016, which was classified in “Operating costs and expenses” in the unaudited condensed consolidated statement of operations and is included in the Company’s Corporate and Other segment results. The Company’s obligation has been satisfied and the matter has concluded.
UMWA 1974 Pension Plan (UMWA Plan) Litigation. On July 16, 2015, a lawsuit was filed by the UMWA Plan, the UMWA 1974 Pension Trust (Trust) and the Trustees of the UMWA Plan and Trust (Trustees) in the United States District Court for the District of Columbia, against PEC, Peabody Holding Company, LLC (PHC), a subsidiary of the Company, and Arch Coal, Inc. (Arch). The plaintiffs sought, pursuant to the Employee Retirement Income Security Act of 1974 (ERISA) and the Multiemployer Pension Plan Amendments Act of 1980 (MPPAA), a declaratory judgment that the defendants were obligated to arbitrate any opposition to the Trustees’ determination that the defendants have statutory withdrawal liability as a result of the 2015 Patriot bankruptcy. After a legal and arbitration process and with the approval of the Bankruptcy Court, on January 25, 2017, the UMWA Plan and the Debtors agreed to a settlement of the claim whereby the UMWA Plan will be entitled to $75 million to be paid by the Company in increments through 2021. In connection with the settlement, the Company recorded a liability representing the present value of the installments of $54.3 million and recognized an equivalent charge to “Loss from discontinued operations, net of income taxes” during 2016. The balance of the liability was $44.3 million at September 30, 2017.
(6)     Inventories
Inventories as of September 30, 2017 and December 31, 2016 consisted of the following:
 SuccessorPredecessor
 September 30, 2017December 31, 2016
 (Dollars in millions)
Materials and supplies$104.0
$104.5
Raw coal58.0
29.6
Saleable coal145.7
69.6
Total$307.7
$203.7
Materials and supplies inventories presented above have been shown net of reserves of $5.6 million as of December 31, 2016. At September 30, 2017, the amount of such reserves was immaterial due to the application of fresh start reporting at the Effective Date.
(7)     Derivatives and Fair Value Measurements
Risk Management — Non-Coal Trading Activities
The Company is exposed to several risks in the normal course of business, including (1) foreign currency exchange rate risk for non-U.S. dollar expenditures and balances, (2) price risk on coal produced by, and diesel fuel utilized in, the Company’s mining operations and (3) interest rate risk that has been partially mitigated by fixed rates on long-term debt. The Company manages a portion of its price risk related to the sale of coal (excluding coal trading activities) using long-term coal supply agreements (those with terms longer than one year), rather than using derivative instruments. Derivative financial instruments have historically been used to manage the Company’s risk exposure to foreign currency exchange rate risk, primarily on Australian dollar expenditures made in its Australian mining platform. This risk has historically been managed using forward contracts and options designated as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted foreign currency expenditures. The Company has also used derivative instruments to manage its exposure to the variability of diesel fuel prices used in production in the U.S. and Australia with swaps and/or options, which it has also designated as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted diesel fuel purchases. These risk management activities are collectively referred to as “Corporate Hedging” and are actively monitored for compliance with the Company’s risk management policies.


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

As of September 30, 2017, the Company had no diesel fuel derivatives in place. Subsequent to the Effective Date, the Company entered into a series of currency options and, as of September 30, 2017, had currency options outstanding with aggregate notional amounts of $450.0 million and $675.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the remainder of 2017 and the first half of 2018, respectively. The instruments are average rate options whereby the Company is entitled to receive payment on the notional amount should the average Australian dollar-to-U.S. dollar exchange rate exceed approximately $0.78 over the fourth quarter of 2017 and $0.85 over the first half of 2018. The currency options are not expected to receive cash flow hedge accounting treatment and changes in fair value will be reflected in current earnings. At September 30, 2017, the currency options’ fair value of $8.6 million was included in “Other current assets” in the accompanying unaudited condensed consolidated balance sheet.
The tables below show the classification and amounts of pre-tax gains and losses related to the Company’s Corporate Hedging derivatives:
         
    Successor
    Three Months Ended September 30, 2017
Financial Instrument 
Income Statement
Classification of (Losses) Gains
 Total gain recognized in income Gain realized in income on derivatives Unrealized loss recognized in income on non- designated derivatives
   (Dollars in millions)
Foreign currency option contracts Operating costs and expenses $5.6
 $7.3
 $(1.7)
Total   $5.6
 $7.3
 $(1.7)

           
    Predecessor
    Three Months Ended September 30, 2016
Financial Instrument 
Income Statement
Classification of (Losses) Gains
 Total loss recognized in income Loss reclassified from other comprehensive income into income (Loss) gain realized in income on derivatives Unrealized gain (loss) recognized in income on non- designated derivatives
   (Dollars in millions)
Commodity swap contracts Operating costs and expenses $(19.4) $(19.4) $—
 $—
Foreign currency forward contracts Operating costs and expenses (28.0) (28.0) —
 —
Total   $(47.4) $(47.4) $—
 $—

         
    Successor
    April 2 through September 30, 2017
Financial Instrument Income Statement
Classification of (Losses) Gains		 Total gain recognized in income Gain realized in income on derivatives Unrealized gain recognized in income on non- designated derivatives
   (Dollars in millions)
Foreign currency option contracts Operating costs and expenses $8.5
 $7.0
 $1.5
Total   $8.5
 $7.0
 $1.5


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

           
    Predecessor
    January 1 through April 1, 2017
Financial Instrument Income Statement
Classification of (Losses) Gains		 Total loss recognized in income Loss reclassified from other comprehensive loss into income (Loss) gain realized in income on derivatives Unrealized gain (loss) recognized in income on non- designated derivatives
   (Dollars in millions)
Commodity swap contracts Operating costs and expenses $(11.0) $(11.0) $—
 $—
Foreign currency forward contracts Operating costs and expenses (16.6) (16.6) —
 —
Total   $(27.6) $(27.6) $—
 $—

           
    Predecessor
    Nine Months Ended September 30, 2016
Financial Instrument Income Statement
Classification of (Losses) Gains		 Total loss recognized in income 
Loss reclassified from other comprehensive income into income (1)
 (Loss) gain realized in income on derivatives Unrealized gain (loss) recognized in income on non- designated derivatives
   (Dollars in millions)
Commodity swap contracts Operating costs and expenses $(78.3) $(66.4) $(11.9) $—
Commodity swap contracts Reorganization items, net (38.8) —
 (38.8) —
Foreign currency forward contracts Operating costs and expenses (119.4) (122.1) 2.7
 —
Foreign currency forward contracts Reorganization items, net (36.4) —
 (36.4) —
Total   $(272.9) $(188.5) $(84.4) $—
(1)
Includes the reclassification from “Accumulated other comprehensive income (loss)” into earnings of $13.6 million and $9.0 million of previously unrecognized losses on foreign currency and fuel contracts, respectively, monetized in the first quarter of 2016.
Cash Flow Presentation. The Company classifies the cash effects of its Corporate Hedging derivatives within the “Cash Flows From Operating Activities” section of the unaudited condensed consolidated statements of cash flows.
Fair Value Measurements
The Company uses a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1 - inputs are quoted prices in active markets for the identical assets or liabilities; Level 2 - inputs are other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3 - inputs are unobservable, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.
Financial Instruments Measured on a Recurring Basis. The following tables set forth the hierarchy of the Company’s net financial asset positions for which fair value is measured on a recurring basis:
 Successor
 September 30, 2017
 Level 1 Level 2 Level 3 Total
 (Dollars in millions)
Foreign currency contracts$—
 $8.6
 $—
 $8.6
Total net financial assets$—
 $8.6
 $—
 $8.6
The Company had no transfers between fair value hierarchy levels subsequent to the Effective Date. As of December 31, 2016, the Company did not have any outstanding financial positions.


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

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including interest rate yield curves, exchange indices, broker/dealer quotes, published indices, issuer spreads, benchmark securities and other market quotes. In the case of certain debt securities, fair value is provided by a third-party pricing service. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:
Investments in debt and equity securities: U.S. government securities and marketable equity securities are valued based on quoted prices in active markets (Level 1) and investment-grade corporate bonds and U.S. government agency securities are valued based on the various inputs listed above that may preclude the security from being measured using an identical asset in an active market (Level 2).
Commodity swap contracts — diesel fuel and explosives: valued based on a valuation that is corroborated by the use of market-based pricing (Level 2) except when credit and non-performance risk is considered to be a significant input, then the Company classifies such contracts as Level 3.
Foreign currency forward and option contracts: valued utilizing inputs obtained in quoted public markets (Level 2) except when credit and non-performance risk is considered to be a significant input, then the Company classifies such contracts as Level 3.
Other Financial Instruments. The Company used the following methods and assumptions in estimating fair values for other financial instruments as of September 30, 2017 and December 31, 2016:
Cash and cash equivalents, accounts receivable, including those within the Company’s accounts receivable securitization program, notes receivable and accounts payable have carrying values which approximate fair value due to the short maturity or the liquid nature of these instruments.
Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available (Level 2), and otherwise on estimated borrowing rates to discount the cash flows to their present value (Level 3).
The estimated fair value of the Company’s current and long-term debt as of December 31, 2016 is unable to be determined given it was subject to compromise in connection with the Plan. The carrying amounts and estimated fair values of the Company’s long-term debt as of September 30, 2017 are summarized as follows:
 Successor
 September 30, 2017
 Carrying
Amount		 Estimated
Fair Value
 (Dollars in millions)
Long-term debt$1,659.1
 $1,744.3

(8)     Coal Trading
The Company engages in the direct and brokered trading of coal and freight-related contracts (coal trading). Except those contracts for which the Company has elected to apply a normal purchases and normal sales exception, all derivative coal trading contracts are accounted for at fair value.
The Company includes instruments associated with coal trading transactions as a part of its trading book. Trading revenues from such transactions are recorded in “Other revenues” in the unaudited condensed consolidated statements of operations and include realized and unrealized gains and losses on derivative instruments, including those that arise from coal deliveries related to contracts accounted for on an accrual basis under the normal purchases and normal sales exception. Therefore, the Company has elected the trading exemption surrounding disclosure of its coal trading activities.


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

Trading revenues (losses) recognized during the periods presented below were as follows:
  SuccessorPredecessor SuccessorPredecessor
Trading Revenues (Losses) by Type of Instrument Three Months Ended September 30, 2017Three Months Ended September 30, 2016 April 2 through September 30, 2017January 1 through April 1, 2017Nine Months Ended September 30, 2016
  (Dollars in millions)
Futures, swaps and options $(17.1)$(19.6) $(24.4)$(10.2)$(42.7)
Physical purchase/sale contracts 36.5
22.3
 49.0
25.2
59.2
Total trading revenues $19.4
$2.7
 $24.6
$15.0
$16.5
Offsetting and Balance Sheet Presentation
The Company’s coal trading assets and liabilities include financial instruments, such as swaps, futures and options, cleared through various exchanges, which involve the daily net settlement of open positions. The Company must post cash collateral in the form of initial margin, in addition to variation margin, on exchange-cleared positions that are in a net liability position and receives variation margin when in a net asset position. The Company also transacts in coal trading financial swaps and options through over-the-counter (OTC) markets with financial institutions and other non-financial trading entities under International Swaps and Derivatives Association (ISDA) Master Agreements, which contain symmetrical default provisions. Certain of the Company’s coal trading agreements with OTC counterparties also contain credit support provisions that may periodically require the Company to post, or entitle the Company to receive, variation margin. Physical coal and freight-related purchase and sale contracts included in the Company’s coal trading assets and liabilities are executed pursuant to master purchase and sale agreements that also contain symmetrical default provisions and allow for the netting and setoff of receivables and payables that arise during the same time period. The Company offsets its coal trading asset and liability derivative positions, and variation margin related to those positions, on a counterparty-by-counterparty basis in the condensed consolidated balance sheets, with the fair values of those respective derivatives reflected in “Assets from coal trading activities, net” and “Liabilities from coal trading activities, net.”
The fair value of assets and liabilities from coal trading activities presented on a gross and net basis as of September 30, 2017 and December 31, 2016 is set forth below:
Affected Line Item in the Condensed Consolidated Balance Sheets Gross Amounts of Recognized Assets (Liabilities) Gross Amounts Offset in the Condensed Consolidated Balance Sheets 
Variation Margin Posted (1)
 Net Amounts of Assets (Liabilities) Presented in the Condensed Consolidated Balance Sheets
  (Dollars in millions)
  Successor
  Fair Value as of September 30, 2017
Assets from coal trading activities, net $127.1
 $(124.6) $—
 $2.5
Liabilities from coal trading activities, net (157.5) 124.6
 31.9
 (1.0)
Total, net $(30.4) $—
 $31.9
 $1.5
         
  Predecessor
  Fair Value as of December 31, 2016
Assets from coal trading activities, net $191.2
 $(190.5) $—
 $0.7
Liabilities from coal trading activities, net (249.1) 190.5
 57.4
 (1.2)
Total, net $(57.9) $—
 $57.4
 $(0.5)
(1)
None of the net variation margin posted at September 30, 2017 and December 31, 2016, respectively, related to cash flow hedges.
See Note 7. “Derivatives and Fair Value Measurements” for information on balance sheet offsetting related to the Company’s Corporate Hedging activities.


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

Fair Value Measurements
The following tables set forth the hierarchy of the Company’s net financial asset (liability) coal trading positions for which fair value is measured on a recurring basis as of September 30, 2017 and December 31, 2016:
 Successor
 September 30, 2017
 Level 1 Level 2 Level 3 Total
 (Dollars in millions)
Futures, swaps and options$—
 $0.5
 $—
 $0.5
Physical purchase/sale contracts—
 1.0
 —
 1.0
Total net financial assets$—
 $1.5
 $—
 $1.5
 Predecessor
 December 31, 2016
 Level 1 Level 2 Level 3 Total
 (Dollars in millions)
Futures, swaps and options$—
 $(0.1) $—
 $(0.1)
Physical purchase/sale contracts—
 0.7
 (1.1) (0.4)
Total net financial assets (liabilities)$—
 $0.6
 $(1.1) $(0.5)
For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including U.S. interest rate curves; LIBOR yield curves; Chicago Mercantile Exchange (CME) Group, Intercontinental Exchange (ICE), Baltic Exchange and Singapore Exchange (SGX) contract prices; broker quotes; published indices and other market quotes. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:
Futures, swaps and options: generally valued based on unadjusted quoted prices in active markets (Level 1) or a valuation that is corroborated by the use of market-based pricing (Level 2) except when credit and non-performance risk is considered to be a significant input (greater than 10% of fair value), then the Company classifies as Level 3.
Physical purchase/sale contracts: purchases and sales at locations with significant market activity corroborated by market-based information (Level 2) except when credit and non-performance risk is considered to be a significant input (greater than 10% of fair value), then the Company classifies as Level 3.
Physical purchase/sale contracts include a credit valuation adjustment based on credit and non-performance risk (Level 3). The credit valuation adjustment has not historically had a material impact on the valuation of the contracts resulting in Level 2 classification. However, due to the Company’s corporate credit rating downgrades in 2016, the credit valuation adjustment as of December 31, 2016 is considered to be a significant unobservable input in the valuation of the contracts resulting in Level 3 classification. During the second quarter of 2017, two of the major rating agencies upgraded the Company’s corporate credit rating upon emergence from the Chapter 11 proceedings. With the credit rating upgrade, the credit valuation adjustment as of September 30, 2017 no longer has a material impact on the valuation of contracts and is in line with the Company’s historical range.
The Company’s risk management function, which is independent of the Company’s commercial trading function, is responsible for valuation policies and procedures, with oversight from executive management. Generally, the Company’s Level 3 instruments or contracts are valued using bid/ask price quotations and other market assessments obtained from multiple, independent third-party brokers or other transactional data incorporated into internally-generated DCF models. Decreases in the number of third-party brokers or market liquidity could erode the quality of market information and therefore the valuation of the Company’s market positions. The Company’s valuation techniques include basis adjustments to the foregoing price inputs for quality, such as sulfur and ash content, location differentials, expressed as port and freight costs, and credit risk. The Company’s risk management function independently validates the Company’s valuation inputs, including unobservable inputs, with third-party information and settlement prices from other sources where available. A daily process is performed to analyze market price changes and changes to the portfolio. Further periodic validation occurs at the time contracts are settled with the counterparty. These valuation techniques have been consistently applied in all periods presented, and the Company believes it has obtained the most accurate information available for the types of derivative contracts held.


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

Significant increases or decreases in the inputs in isolation could result in a significantly higher or lower fair value measurement. The unobservable inputs do not have a direct interrelationship; therefore, a change in one unobservable input would not necessarily correspond with a change in another unobservable input.
The following table summarizes the changes in the Company’s recurring Level 3 net financial liabilities:
 Predecessor SuccessorPredecessor
 Three Months Ended September 30, 2016 April 2 through September 30, 2017January 1 through April 1, 2017 Nine Months Ended September 30, 2016
 (Dollars in millions)
Beginning of period$(1.1) $(0.7)$(1.1) $(15.6)
Transfers into Level 34.6
 —
—
 5.0
Transfers out of Level 3(11.1) 0.7
0.2
 (0.4)
Total gains realized/unrealized:      
Included in earnings2.6
 —
0.2
 1.2
Sales0.1
 —
—
 —
Settlements4.2
 —
—
 9.1
End of period$(0.7) $—
$(0.7) $(0.7)
The Company had no transfers between Levels 1 and 2 during any of the periods presented. Transfers of liabilities into/out of Level 3 from/to Level 2 during the Successor period April 2 through September 30, 2017, and the Predecessor periods January 1 through April 1, 2017, and the three and nine months ended September 30, 2016 were due to the relative value of unobservable inputs to the total fair value measurement of certain derivative contracts falling below, or in the case of transfers in rising above, the 10% threshold. The Company’s policy is to value all transfers between levels using the beginning of period valuation.
The following table summarizes the changes in net unrealized gains (losses) relating to Level 3 net financial assets held both as of the beginning and the end of the period:
 Predecessor SuccessorPredecessor
 Three Months Ended September 30, 2016 April 2 through September 30, 2017January 1 through April 1, 2017 Nine Months Ended September 30, 2016
 (Dollars in millions)
Changes in unrealized gains (losses) (1)
$0.1
 $—
$0.3
 $(0.1)
(1)
Within the unaudited condensed consolidated statements of operations and unaudited condensed consolidated statements of comprehensive income for the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.


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

As of September 30, 2017, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:
  Percentage of
Year of Expiration Portfolio Total
2017 15%
2018 82%
2019 3%
  100%
Credit and Non-performance Risk. The fair value of the Company’s coal derivative assets and liabilities reflects adjustments for credit risk. The Company’s exposure is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses. The Company’s policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If the Company engages in a transaction with a counterparty that does not meet its credit standards, the Company seeks to protect its position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by its credit management function), the Company has taken steps to reduce its exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for the Company’s benefit to serve as collateral in the event of a failure to pay or perform. To reduce its credit exposure related to trading and brokerage activities, the Company seeks to enter into netting agreements with counterparties that permit the Company to offset asset and liability positions with such counterparties and, to the extent required, the Company will post or receive margin amounts associated with exchange-cleared and certain OTC positions. The Company also continually monitors counterparty and contract non-performance risk, if present, on a case-by-case basis.
At September 30, 2017, 33% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties, while 67% was with counterparties that are not rated.
Performance Assurances and Collateral
The Company is required to post variation margin on positions that are in a net liability position and is entitled to receive and hold variation margin on positions that are in a net asset position with an exchange and certain of its OTC derivative contract counterparties. At September 30, 2017 and December 31, 2016, the Company posted a net variation margin of $31.9 million and $57.4 million, respectively.
In addition to the requirements surrounding variation margin, the Company is required by the exchanges upon which it transacts to post certain additional collateral, known as initial margin, which represents an estimate of potential future adverse price movements across the Company’s portfolio under normal market conditions. The Company posted initial margin of $14.6 million as of September 30, 2017, compared to $16.2 million as of December 31, 2016, which is reflected in “Other current assets” in the condensed consolidated balance sheets.
Certain of the Company’s derivative trading instruments require the parties to provide additional performance assurances whenever a material adverse event jeopardizes one party’s ability to perform under the instrument. If the Company was to sustain a material adverse event (using commercially reasonable standards), its counterparties could request collateralization on derivative trading instruments in net liability positions which, based on an aggregate fair value at September 30, 2017 and December 31, 2016, would have amounted to collateral postings to counterparties of approximately $0.4 million and $2.0 million, respectively. As of September 30, 2017, the Company was required to post no collateral to counterparties for such positions. Approximately $1.0 million collateral was required to be posted to counterparties as of December 31, 2016.
Certain of the Company’s other derivative trading instruments require the parties to provide additional performance assurances whenever a credit downgrade occurs below a certain level, as specified in each underlying contract. The terms of such derivative trading instruments typically require additional collateralization, which is commensurate with the severity of the credit downgrade. During the second quarter of 2017, two of the major rating agencies upgraded the Company’s corporate credit rating upon emergence from the Chapter 11 proceedings. The Company’s collateral requirement owed to its counterparties for these ratings based derivative trading instruments for September 30, 2017 remained at zero, consistent with December 31, 2016. As of September 30, 2017 and December 31, 2016, no collateral was posted to counterparties to support such derivative trading instruments.


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

(9)     Intangible Contract Assets and Liabilities
As described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting,” at the Effective Date, the Company recorded intangible assets of $314.9 million and liabilities of $58.7 million to reflect the inherent fair value of certain U.S. coal supply agreements as a result of favorable and unfavorable differences between contract terms and estimated market terms for the same coal products, and also recorded intangible liabilities of $116.2 million related to unutilized capacity under its port and rail take-or-pay contracts. The balances and respective balance sheet classifications of such assets and liabilities at September 30, 2017, net of accumulated amortization, are set forth in the following table:
 Successor
 September 30, 2017
 (Dollars in millions)
 Assets Liabilities Net Total
Coal supply agreements$231.6
 $(46.9) $184.7
Take-or-pay contracts—
 (108.4) (108.4)
Total$231.6
 $(155.3) $76.3
      
Balance sheet classification:     
Investments and other assets$231.6
 $—
 $231.6
Accounts payable and accrued expenses—
 (35.7) (35.7)
Other noncurrent liabilities—
 (119.6) (119.6)
Total$231.6
 $(155.3) $76.3
Amortization of the intangible assets and liabilities related to coal supply agreements occurs ratably based upon coal volumes shipped per contract and is recorded as a component of “Depreciation, depletion and amortization” in the accompanying condensed consolidated statements of operations. Such amortization amounted to $41.5 million and $71.2 million during the Successor three months ended September 30, 2017 and the Successor period April 2, 2017 through September 30, 2017, respectively. The Company anticipates net amortization of sales contracts, based upon expected shipments in the next five years, to be an expense of approximately $40 million during the three months ended December 31, 2017, and for the years 2018 through 2021, expense of approximately $80 million, $40 million, $10 million, and $10 million, respectively.
Future unutilized capacity and the amortization periods related to the take-or-pay contract intangible liabilities are based upon estimates of forecasted usage. Such amortization, which is classified as a reduction to “Operating costs and expenses” in the accompanying condensed consolidated statements of operations, amounted to $6.5 million and $16.4 million during the Successor three months ended September 30, 2017 and the Successor period April 2, 2017 through September 30, 2017, respectively. The Company anticipates net amortization of take-or-pay contract intangible liabilities to be approximately $6 million during the three months ended December 31, 2017, and for the years 2018 through 2021, approximately $30 million, $20 million, $10 million, and $5 million, respectively.
(10) Equity Method Investments and Financing Receivables
The Company had total equity method investments and financing receivables of $75.0 million and $84.8 million reflected in “Investments and other assets” in the condensed consolidated balance sheets as of September 30, 2017 and December 31, 2016, respectively, related to Middlemount Coal Pty Ltd (Middlemount). As noted in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting,” the carrying value of the equity method investments and financing receivables was adjusted to fair value in connection with fresh start reporting based on the net present value of future cash flows associated with the Company’s 50% equity interest in Middlemount.


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

The Company periodically makes loans to Middlemount pursuant to the related shareholders’ agreement for purposes of funding capital expenditures and working capital requirements. The Priority Loans (the amount loaned by the Company in excess of the amount loaned by the other shareholder) bear interest at a rate equal to the monthly average 30-day Australian Bank Bill Swap Reference Rate plus 3.5%. They were due to expire on June 30, 2017, but have been extended to December 31, 2018 in conjunction with a commercial agreement with the stockholders concerning the distribution of available cash against outstanding payables and the loans. The agreement requires the distribution of available cash at least twice each month. Available cash is defined as the amount in Middlemount’s bank accounts that will not be required to pay known bills within the next 35 days. The available cash is distributed to stockholders in a 50/50 ratio, unless there is no marketing royalty payment overdue. In that situation, 100% of the available cash is distributed to the Company until its Priority Loans are repaid in full. Based on the existence of letters of support from related entities of the stockholders, the expected timing of repayment of these loans is projected to extend beyond the stated expiration date, and so the Company considers these loans to be of a long-term nature and in-substance equity. As a result, (i) the foreign currency impact related to the shareholder loans is included in foreign currency translation adjustment in the condensed consolidated balance sheets and the unaudited condensed consolidated statements of comprehensive income and (ii) interest income on the Priority Loans is recognized when cash is received. The Company received loan repayments and other cash payments from Middlemount of approximately $35.2 million during the Successor period April 2 through September 30, 2017 and approximately $31.1 million and $13.2 million during the Predecessor period January 1 through April 1, 2017 and the nine months ended September 30, 2016, respectively.
One of the Company’s Australian subsidiaries and the other shareholder of Middlemount are parties to an agreement, as amended from time to time, to provide a revolving loan (Revolving Loans) to Middlemount not to exceed $50.0 million Australian dollars (Revolving Loan Limit). The Company’s participation in the Revolving Loans will not, at any time, exceed its 50% equity interest of the Revolving Loan Limit. The Revolving Loans bear interest at 15% per annum and expire on December 31, 2018. As of September 30, 2017 and December 31, 2016, the carrying value of the Revolving Loans due to the Company’s Australian subsidiary was zero.
(11) Property, Plant, Equipment and Mine Development
The composition of property, plant, equipment and mine development, net, as of September 30, 2017 and December 31, 2016 is set forth in the table below. Refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” for details regarding the impact of fresh start reporting on property, plant, equipment and mine development.
 SuccessorPredecessor
 September 30, 2017December 31, 2016
 (Dollars in millions)
Land and coal interests$3,819.7
$10,330.8
Buildings and improvements457.3
1,507.6
Machinery and equipment1,077.4
2,130.2
Less: Accumulated depreciation, depletion and amortization(271.8)(5,191.9)
Total, net$5,082.6
$8,776.7
(12)  Income Taxes
The Company’s income tax benefit of $84.1 million and $10.8 million for the three months ended September 30, 2017 and 2016, respectively, included tax provisions of $0.9 million and $5.0 million related to the remeasurement of foreign income tax accounts. The Company’s income tax benefit of $79.4 million and $108.2 million for the Successor period of April 2 through September 30, 2017 and the nine months ended September 30, 2016, respectively, included tax provisions of $1.0 million and $7.4 million, respectively, related to the remeasurement of foreign income tax accounts. The Company recorded an income tax benefit of $266.0 million on April 1, 2017 that was primarily comprised of benefits related to Predecessor deferred tax liabilities and accumulated comprehensive income. The Company’s income tax benefit of $263.8 million for the period of January 1 through April 1, 2017 included a tax provision of $9.4 million related to the remeasurement of foreign income tax accounts and was calculated using a discrete period method.
The Company’s effective tax rate for the three month period ended September 30, 2017 and the period of April 2 through September 30, 2017 is comprised of the expected statutory tax expense offset by foreign rate differential and changes in valuation allowance, plus tax benefits for expected refunds for U.S. net operating loss carrybacks.


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

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


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

(13)     Long-term Debt 
The Company’s total indebtedness as of September 30, 2017 and December 31, 2016 is set forth in the table below. As of December 31, 2016, substantially all of the Company’s long-term debt, with the exception of capital lease obligations, was recorded in “Liabilities subject to compromise” in the consolidated balance sheets. Refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” for additional information.
 SuccessorPredecessor
 September 30, 2017December 31, 2016
 (Dollars in millions)
6.00% Senior Secured Notes due March 2022$500.0
$—
6.375% Senior Secured Notes due March 2025500.0
—
Senior Secured Term Loan due 2022645.0
—
2013 Revolver—
1,558.1
2013 Term Loan Facility due September 2020—
1,162.3
6.00% Senior Notes due November 2018—
1,518.8
6.50% Senior Notes due September 2020—
650.0
6.25% Senior Notes due November 2021—
1,339.6
10.00% Senior Secured Second Lien Notes due March 2022—
979.4
7.875% Senior Notes due November 2026—
247.8
Convertible Junior Subordinated Debentures due December 2066—
386.1
Capital lease and other obligations84.0
20.1
Less: Debt issuance costs(69.9)(70.8)
 1,659.1
7,791.4
Less: Current portion of long-term debt47.1
20.2
Less: Liabilities subject to compromise—
7,771.2
Long-term debt$1,612.0
$—
As more fully described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting”, on the Effective Date, all of the debt instruments associated with the Predecessor indebtedness included in the above table, with the exception of “Capital lease and other obligations”, were canceled and the debt obligations discharged. In accordance with the Plan, the Company was concurrently recapitalized with new debt and equity instruments, including the 6.000% Senior Notes due March 2022, the 6.375% Senior Notes due March 2025, and the Senior Secured Term Loan due 2022, included with the Successor obligations in the above table.
In connection with the Chapter 11 Cases, the Company was required to pay monthly adequate protection payments to certain first lien creditors in accordance with the rates defined in its existing prepetition credit facility which included the 2013 Revolver and the 2013 Term Loan Facility due September 2020. The adequate protection payments were recorded as “Interest expense” in the consolidated statement of operations, which totaled $29.8 million during the Predecessor period January 1, 2017 through April 1, 2017.
For the remaining non-first lien Predecessor indebtedness included in the table above, with the exception of capital lease and other obligations, the Company did not record interest expense subsequent to the filing of the Bankruptcy Petitions. The amount of contractual interest for such obligations which was automatically stayed in accordance with Section 502(b)(2) of the Bankruptcy Code was $92.9 million for the period January 1, 2017 through the Effective Date.
6.00% and 6.375% Senior Secured Notes (collectively, the Successor Notes)
The Successor Notes were issued at par value. The Company paid aggregate debt issuance costs of $49.5 million related to the offering, which will be amortized over the respective terms of the Successor Notes.
Interest payments on the Successor Notes are scheduled to occur each year on March 31st and September 30th until maturity. During the Successor three months ended September 30, 2017 and the Successor period April 2, 2017 through September 30, 2017, the Company recorded interest expense of $15.5 million and $30.6 million related to the Successor Notes, respectively.


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

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


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

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


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

(14) Pension and Postretirement Benefit Costs
Net periodic pension (income) cost included the following components:
  SuccessorPredecessor SuccessorPredecessor
  Three Months Ended September 30, 2017Three Months Ended September 30, 2016 April 2 through September 30, 2017January 1 through April 1, 2017
Nine Months Ended September 30, 2016
  (Dollars in millions)
Service cost for benefits earned $0.5
$0.7
 $1.1
$0.6
 $2.0
Interest cost on projected benefit obligation 9.4
10.3
 18.7
9.7
 31.0
Expected return on plan assets (11.2)(11.3) (22.4)(11.0) (33.9)
Amortization of prior service cost and net actuarial loss —
6.3
 —
6.4
 18.8
Net periodic pension (income) cost $(1.3)$6.0
 $(2.6)$5.7
 $17.9
Annual contributions to the qualified plans are made in accordance with minimum funding standards and the Company’s agreement with the Pension Benefit Guaranty Corporation. Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006 (generally 80%). As of September 30, 2017, the Company’s qualified plans were expected to be at or above the Pension Protection Act thresholds. Prior to emergence from the Chapter 11 Cases, the Company incurred pension costs for two non-qualified pension plans which it no longer sponsors. Minimum funding standards are legislated by ERISA and are modified by pension funding stabilization provisions included in the Moving Ahead for Progress in the 21st Century Act of 2012, the Highway and Transportation Funding Act of 2014 and the Bipartisan Budget Act of 2015. During the Successor period April 2 through September 30, 2017, the Company contributed $30.1 million to its qualified pension plans including a discretionary contribution of $25.0 million.
Net periodic postretirement benefit cost included the following components:
  SuccessorPredecessor SuccessorPredecessor
  Three Months Ended September 30, 2017Three Months Ended September 30, 2016 April 2 through September 30, 2017January 1 through April 1, 2017 Nine Months Ended September 30, 2016
  (Dollars in millions)
Service cost for benefits earned $2.3
$2.6
 $4.6
$2.3
 $7.8
Interest cost on accumulated postretirement benefit obligation 8.2
8.8
 16.5
8.4
 26.4
Amortization of prior service cost and net actuarial loss —
2.4
 —
3.2
 7.1
Net periodic postretirement benefit cost $10.5
$13.8
 $21.1
$13.9
 $41.3


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

(15) Accumulated Other Comprehensive Income (Loss)
The following table sets forth the after-tax components of accumulated other comprehensive income (loss) and changes thereto recorded during the Predecessor period January 1 through April 1, 2017 and the Successor period April 2 through September 30, 2017:
  
Foreign
Currency
Translation
Adjustment
 
Net
Actuarial Loss
Associated with
Postretirement
Plans and
Workers’
Compensation
Obligations
 
Prior Service
Cost Associated
with
Postretirement
Plans
 
Cash Flow
Hedges
 
Total
Accumulated
Other
Comprehensive
Income (Loss)
  (Dollars in millions)
Predecessor Company         
 December 31, 2016$(148.2) $(256.3) $21.7
 $(94.2) $(477.0)
 Reclassification from other comprehensive income to earnings—
 5.8
 (1.4) 18.6
 23.0
 Current period change5.5
 —
 —
 —
 5.5
 Fresh start reporting adjustment142.7
 250.5
 (20.3) 75.6
 448.5
 April 1, 2017$—
 $—
 $—
 $—
 $—
Successor Company         
 Current period change1.8
 —
 —
 —
 1.8
 September 30, 2017$1.8
 $—
 $—
 $—
 $1.8


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

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

 Three Months Ended September 30, 2016January 1 through April 1, 2017Nine Months Ended September 30, 2016 Affected line item in the unaudited condensed consolidated statement of operations
  (Dollars in millions)  
Net actuarial loss associated with postretirement plans and workers’ compensation obligations:      
Postretirement health care and life insurance benefits $(5.2)$(5.5)$(15.4) Operating costs and expenses
Defined benefit pension plans (5.1)(5.3)(15.3) Operating costs and expenses
Defined benefit pension plans (1.1)(1.0)(3.2) Selling and administrative expenses
Insignificant items 3.0
2.7
8.8
  
  (8.4)(9.1)(25.1) Total before income taxes
  3.1
3.3
9.3
 Income tax benefit
  $(5.3)$(5.8)$(15.8) Total after income taxes
       
Prior service credit associated with postretirement plans:      
Postretirement health care and life insurance benefits $2.8
$2.3
$8.3
 Operating costs and expenses
Defined benefit pension plans (0.1)(0.1)(0.3) Operating costs and expenses
  2.7
2.2
8.0
 Total before income taxes
  (1.0)(0.8)(3.0) Income tax provision
  $1.7
$1.4
$5.0
 Total after income taxes
       
Cash flow hedges:      
Foreign currency cash flow hedge contracts $(28.0)$(16.6)$(122.1) Operating costs and expenses
Fuel and explosives commodity swaps (19.4)(11.0)(66.4) Operating costs and expenses
Insignificant items (0.1)(0.1)(0.4)  
  (47.5)(27.7)(188.9) Total before income taxes
  17.6
9.1
69.9
 Income tax benefit
  $(29.9)$(18.6)$(119.0) Total after income taxes
(1)
Presented as gains (losses) in the unaudited condensed consolidated statements of operations.


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

(16) Other Events
Divestitures
On September 5, 2017, the Company entered into an agreement to sell the majority of its Burton Mine and related infrastructure to the Lenton Joint Venture for approximately $11.0 million. The transaction is conditional on a number of regulatory and other requirements and completion is expected to take place by March 31, 2018. The Lenton Joint Venture will assume the reclamation obligations associated with the assets being acquired by the Lenton Joint Venture. If completed, the transaction is expected to reduce the Company’s asset retirement obligation by approximately $53.0 million and reduce the amount of restricted cash held in support of such obligations by approximately $30.0 million. The Burton Mine, located in Queensland's Bowen Basin, entered a care, maintenance and rehabilitation phase in December 2016. At September 30, 2017, the Company’s assets associated with the pending transaction had no carrying value.
On August 29, 2017, the Company entered into an agreement to sell its 50% interest in the Red Mountain Joint Venture (RMJV) with BHP Billiton Mitsui Coal Pty Ltd (BMC) for $20.0 million. RMJV operates the coal handling and preparation plant utilized by the Company’s Millennium Mine. The transaction is conditional on a number of regulatory and other requirements and completion is expected to take place in the fourth quarter of 2017. BMC will assume the reclamation obligations and other commitments associated with the assets of RMJV. The agreement contains provisions allowing the Millennium Mine continued usage of the coal handling and preparation plant and the associated rail loading facility until the end of 2019.
The Company had a 37.5% interest in Dominion Terminal Associates, a partnership that operates a coal export terminal in Newport News, Virginia that exports both metallurgical and thermal coal primarily to Europe and Brazil. On March 31, 2017, the Company completed a sale of its interest in Dominion Terminal Associates to Contura Terminal, LLC and Ashland Terminal, Inc., both of which are partners of the Dominion Terminal Associates. The Company collected $20.5 million in proceeds and recorded $19.7 million of gain on the sale, which was classified in “Net gain on disposal of assets” in the accompanying unaudited condensed consolidated statement of operations during the Predecessor period January 1, 2017 through April 1, 2017.
In November 2016, the Company entered into a definitive share sale and purchase agreement (SPA) for the sale of all of the equity interests in Metropolitan Collieries Pty Ltd, the entity that owns Metropolitan Mine in New South Wales, Australia, and the associated interest in the Port Kembla Coal Terminal, to South32 Limited (South32). The SPA provided for a cash purchase price of $200.0 million and certain contingent consideration, subject to a customary working capital adjustment. South32 terminated the agreement in April 2017 after it was unable to obtain necessary approvals from the Australian Competition and Consumer Commission within the timeframe required under the SPA. As a result of the termination, the Company retained an earnest deposit posted by South32 which was recorded in “Other revenues” in the accompanying unaudited condensed consolidated statements of operations during the Successor period April 2, 2017 through September 30, 2017.
In November 2015, the Company entered into a definitive agreement to sell its New Mexico and Colorado assets to Bowie Resource Partners, LLC (Bowie) in exchange for cash proceeds of $358.0 million and the assumption of certain liabilities. Bowie agreed to pay the Company a termination fee of $20.0 million (Termination Fee) in the event the Company terminated the agreement because Bowie failed to obtain financing and close the transaction. On April 12, 2016, Peabody terminated the agreement and demanded payment of the Termination Fee. Following a favorable judgment by the Bankruptcy Court, the Company collected the Termination Fee from Bowie. The Termination Fee is included in “Other revenues” in the accompanying unaudited condensed consolidated statements of operations during the Successor period April 2, 2017 through September 30, 2017.
In May 2016, the Company completed the sale of its 5.06% participation interest in the Prairie State Energy Campus to the Wabash Valley Power Association for $57.1 million. The Company recognized a gain on sale of $6.2 million related to the transaction, which was classified in “Net gain on disposal of assets” in the unaudited condensed consolidated statement of operations for the Predecessor nine months ended September 30, 2016.
In April 2016, the Company entered into sale and purchase agreements with Australia-based Pembroke Resources to sell its interest in undeveloped metallurgical reserve tenements in Queensland's Bowen Basin. The transaction included Olive Downs South, Olive Downs South Extended and Willunga tenements, which were sold for $64.1 million in cash plus a royalty stream. The Company recognized a gain on sale of $2.8 million related to those tenements, which was classified in “Net gain on disposal of assets” in the unaudited condensed consolidated statement of operations for the Predecessor nine months ended September 30, 2016. The sale and purchase agreement for the remaining tenements, namely the Olive Downs North tenements, terminated in October 2017 as certain closing conditions were not satisfied within the prescribed time period.


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

Share Repurchase Program
On August 1, 2017, the Board authorized a $500.0 million share repurchase program. Repurchases may be made from time to time at the Company’s discretion. The specific timing, price and size of purchases will depend on the share price, general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time. No expiration date has been set for the repurchase program, and the program may be suspended or discontinued at any time. On August 23, 2017, the Company repurchased approximately 1.5 million shares of its Common Stock for $40.0 million in connection with an underwritten secondary offering. During September 2017, the Company made additional open-market purchases of approximately 1.0 million shares of its Common Stock for $29.2 million. Subsequent to September 30, 2017 and through October 30, 2017, the Company purchased an additional approximately 1.3 million shares of Common Stock for $37.7 million.
(17) Earnings per Share (EPS)
Basic and diluted EPS are computed using the two-class method, which is an earnings allocation that determines EPS for each class of common stock and participating securities according to dividends declared and participation rights in undistributed earnings. The Company’s convertible preferred stock is considered a participating security because holders are entitled to receive dividends on an if-converted basis. The Predecessor Company’s restricted stock awards were considered participating securities because holders were entitled to receive non-forfeitable dividends during the vesting term. Diluted EPS includes securities that could potentially dilute basic EPS during a reporting period and assumes that participating securities are not executed or converted. As such, the Company includes the share-based compensation awards in its potentially dilutive securities. Diluted EPS for the Predecessor Company also included the Debentures. Dilutive securities are not included in the computation of loss per share when a company reports a net loss from continuing operations as the impact would be anti-dilutive.
For all but the Predecessor Company’s performance units, which are further described in Note 20. “Share-Based Compensation” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017, the potentially dilutive impact of the Company’s share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. For the Predecessor Company’s performance units, their contingent features resulted in an assessment for any potentially dilutive common stock by using the end of the reporting period as if it were the end of the contingency period for all units granted.
A conversion of the Debentures could have resulted, up to the time of the cancellation, in payment for any conversion value in excess of the principal amount of the Debentures in the Predecessor Company’s common stock. For diluted EPS purposes, potential common stock was calculated based on whether the market price of the Predecessor Company’s common stock at the end of each reporting period was in excess of the conversion price of the Debentures. The effect of the Debentures was excluded from the calculation of diluted EPS for all periods presented herein because to do so would have been anti-dilutive for those periods.
The computation of diluted EPS for the Successor Company excluded aggregate share-based compensation awards of less than 0.1 million for three months ended September 30, 2017 and the period of April 2 through September 30, 2017, respectively. The computation of diluted EPS for the Predecessor Company excluded aggregate share-based compensation awards of approximately 0.2 million for the period January 1 through April 1, 2017 and 0.4 million for the three and nine months ended September 30, 2016, respectively, because to do so would have been anti-dilutive for those periods. Because the potential dilutive impact of such share-based compensation awards is calculated under the treasury stock method, anti-dilution generally occurs when the exercise prices or unrecognized compensation cost per share of such awards are higher than the Company’s average stock price during the applicable period.


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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.
  SuccessorPredecessor SuccessorPredecessor
  Three Months Ended September 30, 2017Three Months Ended September 30, 2016 April 2 through September 30, 2017January 1 through April 1, 2017 Nine Months Ended September 30, 2016
    
  (In millions, except per share data)
EPS numerator:        
Income (loss) from continuing operations, net of income taxes $233.7
$(97.7) $335.1
$(195.5) $(488.6)
Less: Series A Convertible Preferred Stock dividends 23.5
—
 138.6
—
 —
Less: Net income attributable to noncontrolling interests 5.1
1.8
 8.9
4.8
 3.5
Income (loss) from continuing operations attributable to common stockholders, before allocation of earnings to participating securities 205.1
(99.5) 187.6
(200.3)
(492.1)
Less: Earnings allocated to participating securities 51.6
—
 50.6
—
 —
Income (loss) from continuing operations attributable to common stockholders, after allocation of earnings to participating securities (1)
 153.5
(99.5) 137.0
(200.3) (492.1)
Loss from discontinued operations, net of income taxes (3.7)(38.1) (6.4)(16.2) (44.5)
Less: Loss from discontinued operations allocated to participating securities (0.9)—
 (1.7)—
 —
Loss from discontinued operations attributable to common stockholders, after allocation of earnings to participating securities (2.8)(38.1) (4.7)(16.2) (44.5)
Net income (loss) attributable to common stockholders, after allocation of earnings to participating securities (1)
 $150.7
$(137.6) $132.3
$(216.5) $(536.6)
         
EPS denominator:        
Weighted average shares outstanding — basic 101.6
18.3
 99.2
18.3
 18.3
Impact of dilutive securities 1.5
—
 1.0
—
 —
Weighted average shares
   outstanding — diluted (2)
 103.1
18.3
 100.2
18.3
 18.3
         
Basic EPS attributable to common stockholders:        
Income (loss) from continuing operations $1.51
$(5.44) $1.38
$(10.93) $(26.91)
Loss from discontinued operations (0.03)(2.09) (0.05)(0.88) (2.43)
Net income (loss) attributable to common stockholders $1.48
$(7.53) $1.33
$(11.81) $(29.34)
         
Diluted EPS attributable to common stockholders:        
Income (loss) from continuing operations $1.49
$(5.44) $1.37
$(10.93) $(26.91)
Loss from discontinued operations (0.02)(2.09) (0.05)(0.88) (2.43)
Net income (loss) attributable to common stockholders $1.47
$(7.53) $1.32
$(11.81) $(29.34)
(1)
The reallocation adjustment for participating securities to arrive at the numerator to calculate diluted EPS was $0.6 million for the Successor three months ended September 30, 2017 and $0.4 million for the Successor period April 2 through September 30, 2017.
(2)
The two-class method assumes that participating securities are not exercised or converted. As such, weighted average diluted shares outstanding excluded 34.2 million shares and 36.7 million shares related to the participating securities for the Successor three months ended September 30, 2017 and the Successor period April 2 through September 30, 2017, respectively.


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

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


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

At September 30, 2017, the Company had no outstanding borrowings and $179.5 million of letters of credit drawn under the Securitization Program. The letters of credit were primarily in support of portions of the Company’s obligations for reclamation, workers’ compensation and postretirement benefits. The Company had no cash collateral requirement under the Securitization Program at September 30, 2017 and $40.5 million required under its former receivables securitization facility in place prior to the Effective Date at December 31, 2016. The Company incurred fees associated with the Securitization Program of $3.9 million during the Successor period April 2, 2017 through September 30, 2017, which have been recorded as interest expense in the accompanying unaudited statements of operations. As it relates to the former receivables securitization facility in place prior to the Effective Date, the Company incurred interest expense of $2.0 million during the Predecessor period January 1, 2017 through April 1, 2017, $2.4 million during the three months ended September 30, 2016 and $5.6 million during the nine months ended September 30, 2016.
Restricted Cash Collateral
The Company has restricted cash held as collateral for financial assurances associated with a variety of long-term obligations and commitments surrounding the mining, reclamation and shipping of its production. At September 30, 2017 and December 31, 2016, the Company had $530.3 million and $529.3 million, respectively, related to such obligations. The Company also had $7.8 million and $13.8 million of restricted cash at September 30, 2017 and December 31, 2016, respectively, related to various short-term obligations.
Other
The Company is the lessee under numerous equipment and property leases. It is common in such commercial lease transactions for the Company, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property, if any, would be covered by insurance (subject to deductibles). The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under various lease obligations. Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments, and the Company assumes that no amounts could be recovered from third parties.
The Company has provided financial guarantees under certain long-term debt agreements entered into by its subsidiaries and substantially all of the Company’s U.S. subsidiaries provide financial guarantees under long-term debt agreements entered into by the Company. The maximum amounts payable under the Company’s debt agreements are equal to the respective principal and interest payments.
(19) Commitments and Contingencies
Commitments
Unconditional Purchase Obligations
As of September 30, 2017, purchase commitments for capital expenditures were $56.3 million, all of which is obligated within the next 12 months.
There were no other material changes to the Company’s commitments from the information provided in Note 26 to the consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.
Contingencies
From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities. The Company discusses its significant legal proceedings below, including ongoing proceedings and those that impacted the Company’s results of operations for the periods presented.
Effect of Automatic Stay. The Debtors filed voluntary petitions for relief under the Bankruptcy Code on the Petition Date in the Bankruptcy Court. During the pendency of the Chapter 11 Cases, each of the Debtors continued to operate its business and manage its property as a debtor-in-possession pursuant to Sections 1107 and 1108 of the Bankruptcy Code. Subject to certain exceptions under the Bankruptcy Code, the filing of the Debtors’ Chapter 11 Cases, pursuant to Section 362(a) of the Bankruptcy Code, automatically enjoined, or stayed, among other things, the continuation of most judicial or administrative proceedings or the filing of other actions against or on behalf of the Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date or to exercise control over property of the Debtors’ bankruptcy estates.


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

The automatic stay was lifted when the Plan became effective on April 3, 2017 and was replaced by the injunction provisions under the Debtors’ confirmed Plan. The Plan’s injunction provisions provide that all holders of prepetition claims or interests are enjoined, or stayed, from, among other things, (a) commencing, conducting or continuing any suit, action or other proceeding against the Debtors, their estates or the reorganized Debtors, (b) enforcing, levying, attaching, collecting or otherwise recovering an award against the Debtors, their property or the assets or property of the reorganized Debtors, (c) creating, perfecting or otherwise enforcing a lien against the Debtors, their estates or the reorganized Debtors, and (d) asserting any setoff, right of subrogation or recoupment against any obligation due a Debtor or a reorganized Debtor.
The Chapter 11 Cases impacted the liabilities of the Debtors described below and in Note 5. “Discontinued Operations,” as well as certain other contingent liabilities the Debtors may have. For example, if a contingent litigation liability of the Debtors is ultimately allowed as a prepetition claim under the Bankruptcy Code, that claim will be subject to the applicable treatment set forth in the Plan and be discharged pursuant to the terms of the Plan.
Litigation Relating to Continuing Operations
Peabody Monto Coal Pty Ltd, Monto Coal 2 Pty Ltd and Peabody Energy Australia PCI Pty Ltd (PEA-PCI). In October 2007, a statement of claim was delivered to Peabody Monto Coal Pty Ltd, a wholly-owned subsidiary of PEA-PCI, that was then known as Macarthur Coal Limited, and Monto Coal 2 Pty Ltd, an equity accounted investee, from the minority interest holders in the Monto Coal Joint Venture, alleging that Monto Coal 2 Pty Ltd breached the Monto Coal Joint Venture Agreement and Peabody Monto Coal Pty Ltd breached the Monto Coal Management Agreement. Peabody Monto Coal Pty Ltd is the manager of the Monto Coal Joint Venture pursuant to the Management Agreement. Monto Coal 2 Pty Ltd holds a 51% interest in the Monto Coal Joint Venture. The plaintiffs are Sanrus Pty Ltd, Edge Developments Pty Ltd and H&J Enterprises (Qld) Pty Ltd. An additional statement of claim was delivered to PEA-PCI in November 2010 from the same minority interest holders in the Monto Coal Joint Venture, alleging that PEA-PCI induced Monto Coal 2 Pty Ltd and Peabody Monto Coal Pty Ltd to breach the Monto Coal Joint Venture Agreement and the Monto Coal Management Agreement, respectively. The plaintiffs later amended their claim to allege damages for lost opportunities to sell their joint venture interest. These actions, which are pending before the Supreme Court of Queensland, Australia, seek damages from the three defendants collectively of amounts ranging from $15.6 million Australian dollars to $1.8 billion Australian dollars, plus interest and costs. The defendants dispute the claims and are vigorously defending their positions. Orders have been made by the court relating to trial preparation steps, with the steps expected to be completed by the end of February 2018. A trial date is expected in the second half of 2018 (at the earliest) or in 2019. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss currently cannot be reasonably estimated.
Lori J. Lynn Class Action. On June 11, 2015, a former Peabody Investments Corp. (PIC) employee filed a putative class action lawsuit in the United States District Court, Eastern District of Missouri on behalf of three of the Company’s or its subsidiaries’ 401(k) retirement plans and certain participants and beneficiaries of the plans. The lawsuit, which was brought against Peabody Energy Corporation (PEC), PHC, PIC and a number of the Company’s and PIC’s current and former executives and employees, alleges breach of fiduciary duties and seeks monetary damages under ERISA relating to the offering of the Peabody Energy Stock Fund as an investment option in the 401(k) retirement plans.
On September 8, 2015, the plaintiffs filed an amended complaint which, among other things, named a new plaintiff and named all of the then current members and two former members of the relevant boards of directors as defendants. The class period (December 2012 to present) remains unchanged. On November 9, 2015, the defendants filed a motion seeking dismissal of all claims.
Plaintiffs filed a second amended complaint on March 11, 2016 that included new allegations against the Company related to the Company’s disclosure to investors of risks associated with climate change and related legislation and regulations. The second amended complaint also added the three committees responsible for administering the three 401(k) retirement plans at issue and dropped several individual defendants, including the then current directors of PEC’s board of directors. As a result of filing the Chapter 11 Cases, the plaintiffs voluntarily dismissed the three Debtor defendants (PEC, PIC and PHC) and elected to proceed against the individual defendants and the three named committees with the second amended complaint. On November 17, 2016, the parties presented arguments on the defendants’ motion to dismiss. On March 30, 2017, the United States District Court granted the motion to dismiss. On May 1, 2017, the plaintiffs filed a notice of appeal regarding the March 30th order granting the motion to dismiss.
On July 7, 2017 the Bankruptcy Court entered an order on the agreed stipulation of the Debtors and plaintiffs such that the claim of the plaintiffs was estimated to have no value for purposes of any distribution under the Plan, except that plaintiffs are not precluded from pursuing recovery from applicable insurance, and that plaintiffs will limit their recovery solely to applicable insurance.


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

On September 28 2017, plaintiffs unilaterally filed a notice of dismissal of the appeal with the Eighth Circuit Court of Appeals. On September 29, 2017, the Eighth Circuit Court of Appeals granted the motion to dismiss the appeal. The March 30, 2017 United States District Court’s order granting the motion to dismiss is now a final judgment.
Berenergy Corporation. The Company has been in a legal dispute with Berenergy Corporation (Berenergy) regarding Berenergy’s access to certain of its underground oil deposits beneath the Company’s North Antelope Rochelle Mine and contiguous undisturbed areas. The Company believes that any claims related to this matter constitute prepetition claims. On October 13, 2016, the Sixth Judicial Court in the state of Wyoming (Wyoming Court) entered an order (Wyoming Court Decision) allowing the Company the right to mine through certain wells owned by Berenergy but required the Company to compensate Berenergy for damages of $0.9 million, which the Company recognized during 2016. Further, the Wyoming Court ruled that should Berenergy obtain approval from the Wyoming Oil and Gas Conservation Commission (the Commission) to recover certain secondary deposits beneath the mine’s contiguous undisturbed areas, the Company would be liable to Berenergy for the cost of certain special procedures and equipment required to access the secondary deposits remotely from outside the Company’s mine area, which has been estimated as $13.1 million by Berenergy. Berenergy so far has not applied to the Commission for approval and the Company believes it is not probable that the Commission would approve access to the secondary deposits if Berenergy applied based on the Company’s view of a lack of economic feasibility and certain restrictions on Berenergy’s legal claim to the deposits. Based upon these factors, the Company has not accrued a liability related to the secondary deposits as of September 30, 2017. On December 21, 2016, Berenergy filed a Notice of Appeal with the Wyoming Supreme Court of the Wyoming Court Decision. On January 5, 2017, Peabody filed a Notice of Cross-Appeal with the Wyoming Supreme Court of the Wyoming Court Decision. Both parties filed appellate briefs on April 17, 2017. The matter before the Wyoming Supreme Court has been fully briefed by the parties and oral arguments were held on August 16, 2017. On June 22, 2017, the Bankruptcy Court entered an order disallowing Berenergy’s proof of claim for the amounts awarded in the Wyoming Court Decision, which the Company believes discharged its obligation to pay these amounts.
County of San Mateo, County of Marin, City of Imperial Beach. The Company was named as a defendant, along with numerous other companies, in three nearly identical lawsuits. The lawsuits seek to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions attributable to those fuels. The lawsuits primarily assert that the companies’ products have caused a sea level rise that is damaging the plaintiffs. The complaints specifically alleged that the defendants’ activities from 1965 to 2015 caused such damage. The Company filed a motion to enforce the Confirmation Order in the Bankruptcy Court because the Confirmation Order enjoins claims that arose before the effective date of the Plan. The motion to enforce was heard on October 5, 2017 and granted on October 24, 2017. The Bankruptcy Court ordered the plaintiffs to dismiss their lawsuits against the Company.
10th Circuit U.S. Bureau of Land Management (BLM) Appeal. On September 15, 2017, the Tenth Circuit Court of Appeals reversed the District Court of Wyoming’s decision upholding BLM’s approval of four coal leases in the Powder River Basin. Two of the four leases relate to the Company’s North Antelope Rochelle Mine in Wyoming. There is no immediate impact on the Company’s leases as the Court of Appeals did not vacate the leases as part of its ruling. Rather, the Court of Appeals remanded the case back to the District Court with directions to order BLM to revise its environmental analysis. The Company’s operations will continue in the normal course during this period since the decision has no impact on mining at this time. The Company currently believes that its operations are unlikely to be materially impacted by this case, but the timing and magnitude of any impact on the Company’s future operations is not certain. 
Wilpinjong Extension Project (WEP). Wollar Progress Association has applied to the Land & Environment Court for a judicial review of the New South Wales Planning Assessment Commission’s (PAC) decision to approve the WEP. In the interim, the Company’s Wilpinjong Mine can continue to mine in accordance with its approvals. The Company intends to fully defend the validity of the PAC’s decision.
Claims, Litigation and Settlements Relating to Indemnities or Historical Operations
Environmental Claims and Litigation Arising From Historical, Non-Coal Producing Operations. Gold Fields Mining, LLC (Gold Fields) is a non-coal producing entity that was previously managed and owned by Hanson plc, the Company’s predecessor owner. In a February 1997 spin-off, Hanson plc transferred ownership of Gold Fields to PEC despite the fact that Gold Fields and many of its subsidiaries had no ongoing operations and PEC had no prior involvement in the past operations of Gold Fields and its subsidiaries. Prior to the Effective Date, Gold Fields was one of PEC’s subsidiaries. As part of separate transactions, both PEC and Gold Fields agreed to indemnify Blue Tee with respect to certain claims relating to the historical operations of a predecessor of Blue Tee, which is a former affiliate of Gold Fields. Neither PEC nor Gold Fields had any involvement with the past operations of the Blue Tee predecessor.


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

Pursuant to the indemnity, Blue Tee tendered its environmental claims for remediation, past and future costs, and/or natural resource damages (Blue Tee Liabilities) to Gold Fields. Although Gold Fields has paid remediation costs as a result of the indemnification obligations, Blue Tee has been identified as a potentially responsible party (PRP) at various designated national priority list (NPL) sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and similar statutes. Of these sites where Blue Tee has been identified as a PRP, neither Gold Fields nor PEC is a party to any cleanup orders relating to the operations of Blue Tee’s predecessor. In addition to the NPL sites, Blue Tee has been named a PRP at multiple other sites, where Gold Fields has either paid remediation costs or settled the environmental claims on behalf of Blue Tee. As a result of filing the Chapter 11 Cases, Gold Fields stopped paying these remediation costs.
Environmental assessments for remediation, past and future costs, and/or natural resource damages were also asserted by the United States Environmental Protection Agency (EPA) and natural resources trustees against Gold Fields related to historical activities of Gold Fields’ predecessor. Gold Fields has been identified as a PRP at four NPL sites and has been conducting response actions or working with the EPA to resolve past cost recovery claims at these sites pursuant to cleanup orders or other negotiations. As a result of filing the Chapter 11 Cases, Gold Fields ceased its response actions and other engagements with the EPA at these sites.
Undiscounted liabilities for environmental cleanup-related costs relating to (i) the contractual indemnification obligations owed to Blue Tee and (ii) for the sites noted above for which Gold Fields has been identified as a PRP as a result of the operations of its predecessor, were collectively estimated to be $62.8 million as of December 31, 2016 in the condensed consolidated balance sheets. The majority of these estimated costs related to Blue Tee site liabilities.
Prior to the August 19, 2016 bar date for filing claims in the Chapter 11 Cases, Blue Tee filed an unliquidated, general unsecured claim in the amount of $65.6 million against Gold Fields regarding the Blue Tee Liabilities, additional unliquidated claims in an unknown amount in excess of $150 million at known sites, and further contingent claims at known and unknown sites, including natural resources damages (NRDs) claims alleged, without explanation, to be in the range of $500 million. On November 17, 2016 Blue Tee amended it claim to increase the amount of the claim to $1.2 billion.
Prior to the October 11, 2016 government bar date for filing claims in the Chapter 11 Cases, several governmental entities including the EPA, the Department of the Interior and several states filed unliquidated, secured and general unsecured claims against PEC and Gold Fields. These claims totaled in excess of $2.7 billion and alleged damages for past and future remediation costs as well as for alleged NRDs at several sites. As noted in the claims, many of the claims were duplicative as they overlapped with each other as well as with claims made by Blue Tee.
On January 27, 2017, PEC filed objections to claims filed by the U.S. Department of Interior, the U.S. Department of Justice and the EPA (collectively the PEC Objections). The PEC Objections dispute that PEC has liability to the claimant under applicable federal environmental statutes for the Blue Tee sites listed in the claims based on the fact that PEC never owned any of the sites or disposed or arranged for the disposal of hazardous substances at any of the sites.
On February 2, 2017, Gold Fields filed objections to claims filed by the State of Oklahoma, the State of Missouri, the U.S. Department of Interior, the EPA, the Kansas Department of Health and Environment, the Illinois Department of Natural Resources and the Missouri Department of Natural Resources (collectively the Gold Fields Objections). The Gold Fields Objections dispute that Gold Fields has liability to the claimant under applicable federal and state environmental statutes for the Blue Tee sites listed in the claims based on the fact that Gold Fields never owned any of the sites or disposed or arranged for the disposal of hazardous substances at any of the sites.
On March 16, 2017, the Debtors agreed to settle the objections to the Plan filed by Blue Tee and several government entities in the Chapter 11 Cases. Under the settlements, the Debtors will (1) not seek to recover federal tax refunds owed to Debtors in the amount of approximately $11 million; (2) transfer $12 million of insurance settlement proceeds from Century and Pacific Employers Insurance Company relating to environmental liabilities to the Gold Fields Liquidating Trust (as described in the Plan); and (3) pay $20 million to the Gold Fields Liquidating Trust. On March 16 and 17, 2017, the Bankruptcy Court entered orders approving these settlements. On July 13, 2017, the Debtors and government entities entered into a settlement agreement to reflect the above settlement.  Notice of the settlement agreement was given in the Federal Register on July 20, 2017. On September 5, 2017, the Bankruptcy Court gave final approval of the settlement agreement after the notice and comment period expired. As of the Effective Date, all Gold Fields assets and liabilities have been transferred to the Gold Fields Liquidating Trust and Reorganized Debtors have no further obligations with respect to Gold Fields.


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

Other
At times the Company becomes a party to other disputes, including those related to contract miner performance, claims, lawsuits, arbitration proceedings, regulatory investigations and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where the Company does business. Based on current information, the Company believes that such other pending or threatened proceedings are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.
(20) Segment Information
The Company reports its results of operations primarily through the following reportable segments: “PowderSeaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining,” “Midwestern Other U.S. Mining,” “Western U.S. Mining,” “Australian Metallurgical Mining,” “Australian Thermal Mining” “Trading and Brokerage”Corporate and “Corporate and Other.” The Company’s chief operating decision maker, (CODM)defined as its Chief Executive Officer, uses Adjusted EBITDA as the primary metric to measure each of the segment’ssegments’ operating performance.performance and allocate resources.
Adjusted EBITDA is a non-U.S. GAAPnon-GAAP financial measure defined as income (loss) from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization and reorganization items, net.amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of the segment’ssegments’ operating performance, as displayed in the reconciliation below. Management believes non-U.S. GAAPnon-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.performance. Adjusted EBITDA is not intended to serve as an alternative to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.
Reportable segment results were as follows:
  SuccessorPredecessor SuccessorPredecessor
  Three Months Ended September 30, 2017Three Months Ended September 30, 2016 April 2 through September 30, 2017January 1 through April 1, 2017 Nine Months Ended September 30, 2016
   
Revenues:        
Powder River Basin Mining $420.9
$419.6
 $786.3
$394.3
 $1,062.2
Midwestern U.S. Mining 207.7
211.0
 402.6
193.2
 599.6
Western U.S. Mining 155.7
162.4
 281.1
149.7
 387.0
Australian Metallurgical Mining 415.9
232.5
 703.7
328.9
 682.8
Australian Thermal Mining 265.8
197.9
 505.0
224.8
 561.4
Trading and Brokerage 19.4
2.7
 24.6
15.0
 16.5
Corporate and Other (8.2)(19.0) 32.2
20.3
 (35.0)
Total $1,477.2
$1,207.1
 $2,735.5
$1,326.2
 $3,274.5
         
Adjusted EBITDA:        
Powder River Basin Mining $112.7
$123.9
 $197.5
$91.7
 $278.3
Midwestern U.S. Mining 49.5
59.1
 96.0
50.0
 172.4
Western U.S. Mining 34.5
34.3
 79.4
50.0
 83.2
Australian Metallurgical Mining 143.1
(34.5) 215.0
109.6
 (121.0)
Australian Thermal Mining 97.8
48.9
 203.7
75.6
 137.2
Trading and Brokerage 2.7
(9.4) (2.4)8.8
 (41.3)
Corporate and Other (1)
 (29.0)(92.1) (60.1)(44.4) (270.8)
Total $411.3
$130.2
 $729.1
$341.3
 $238.0
(1)
Includes a gain of $19.7 million related to the sale of Dominion Terminal Associates during the predecessor period January 1 through April 1, 2017 and a gain of $68.1 million related to the 2016 Settlement Agreement described in Note 5. “Discontinued Operations” during the predecessor nine months ended September 30, 2016.

Three Months Ended March 31,
 20232022
 (Dollars in millions)
Revenue:
Seaborne Thermal Mining$346.5 $251.2 
Seaborne Metallurgical Mining288.4 321.3 
Powder River Basin Mining305.3 251.2 
Other U.S. Thermal Mining249.4 203.1 
Corporate and Other174.4 (335.4)
Total$1,364.0 $691.4 
Adjusted EBITDA:
Seaborne Thermal Mining$164.0 $90.5 
Seaborne Metallurgical Mining90.8 181.0 
Powder River Basin Mining35.8 7.6 
Other U.S. Thermal Mining64.2 50.0 
Corporate and Other35.8 (1.6)
Total$390.6 $327.5 


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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:
Three Months Ended March 31,
20232022
 (Dollars in millions)
Income (loss) from continuing operations, net of income taxes$284.1 $(119.8)
Depreciation, depletion and amortization76.3 72.9 
Asset retirement obligation expenses15.4 15.0 
Restructuring charges0.1 1.6 
Asset impairment2.0 — 
Changes in amortization of basis difference related to equity affiliates(0.3)(0.6)
Interest expense18.4 39.4 
Net loss on early debt extinguishment6.8 23.5 
Interest income(13.1)(0.5)
Unrealized (gains) losses on derivative contracts related to forecasted sales(118.7)301.0 
Unrealized losses (gains) on foreign currency option contracts2.2 (3.3)
Take-or-pay contract-based intangible recognition(0.6)(0.7)
Income tax provision (benefit)118.0 (1.0)
Adjusted EBITDA$390.6 $327.5 
(14) Other Events
Shoal Creek Incident
On March 29, 2023, the Company’s Shoal Creek Mine experienced a fire involving void fill material utilized to stabilize the roof structure of the mine. All mine personnel were safely evacuated from the mine. The Mine Safety and Health Administration (MSHA) has allowed mine rescue-equipped personnel into the mine at various times to assess the situation. On April 26, 2023, MSHA approved a temporary sealing program which was completed on April 28, 2023, and the Company continues to monitor air quality in the affected underground area.
Port and Rail Capacity Assignment
During the three months ended March 31, 2023, the Company entered into an agreement to assign the right to its excess port and rail capacity related to its North Goonyella Mine to an unrelated party in exchange for $30.0 million Australian dollars. Half of such amount was received by the Company upon entry into the agreement, and half is payable in June 2024, subject to certain conditions. The Company recorded revenue of $19.2 million and a discounted long-term receivable of $9.2 million in connection with the transaction during the three months ended March 31, 2023.

23

  SuccessorPredecessor SuccessorPredecessor


Three Months Ended September 30, 2017Three Months Ended September 30, 2016
April 2 through September 30, 2017January 1 through April 1, 2017
Nine Months Ended September 30, 2016
 
(Dollars in millions)
  Income (loss) from continuing operations, net of income taxes
$233.7
$(97.7)
$335.1
$(195.5)
$(488.6)
Depreciation, depletion and amortization
194.5
117.8

342.8
119.9

345.5
Asset retirement obligation expenses
11.3
12.7

22.3
14.6

37.3
Selling and administrative expenses related to debt restructuring
—
—

—
—

21.5
Asset impairment
—
—

—
30.5

17.2
Change in deferred tax asset valuation allowance related to equity affiliates
(3.4)(0.6)
(7.7)(5.2)
(0.6)
Interest expense
42.4
58.5

83.8
32.9

243.7
Loss on early debt extinguishment 12.9
—
 12.9
—
 —
Interest income
(2.0)(1.3)
(3.5)(2.7)
(4.0)
Break fees related to terminated asset sales
—
—

(28.0)—

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

(1.5)—

—
Unrealized losses (gains) on economic hedges
10.8
21.9

1.4
(16.6)
49.1
Coal inventory revaluation
—
—

67.3
—

—
Take-or-pay contract-based intangible recognition
(6.5)—

(16.4)—

—
Reorganization items, net
—
29.7

—
627.2

125.1
Income tax benefit
(84.1)(10.8)
(79.4)(263.8)
(108.2)
Total Adjusted EBITDA
$411.3
$130.2

$729.1
$341.3

$238.0
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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”“Peabody” or “the Company” refer to Peabody Energy Corporation andor its consolidated subsidiaries and affiliates, collectively, unlessapplicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Quarterly Report on Form 10-Q relate only to the context indicates otherwise. TheCompany’s continuing operations.
When used in this filing, the term “Peabody”“ton” refers to Peabody Energy Corporation and not its consolidated subsidiaries and affiliates.short or net tons, equal to 2,000 pounds (907.18 kilograms), while “tonne” refers to metric tons, equal to 2,204.62 pounds (1,000 kilograms).
Cautionary Notice Regarding Forward-Looking Statements
This report includes statements of ourPeabody’s expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or ourPeabody’s future financial performance, including, without limitation, the section captioned “Outlook” in this Item 2. We useperformance. The Company uses words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements.


50


Without limiting the foregoing, all statements relating to ourPeabody’s 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 believePeabody believes 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 ourthe Company’s control. Factors that could affect our results or an investment in our securities include, but are not limited to:
the impact of assumptions and analyses developed by us which formed, in large part, the basis of the Plan could be incorrect, also persisting or worsening adverse market conditions could affect our ability to successfully implement the Plan;
certain claims that may not ultimately be discharged in the Plan could have a material adverse effect on our financial condition and results of operation;
adjustments to our historical financial information, which as a result of our emergence from our Chapter 11 Cases, will not be indicative of our future financial performance and realization of assets and liquidation of liabilities are subject to uncertainty;
the impairment of certain of the tax assets of our Australian operations as a result of the consummation of the Plan;
our dependence on the prices we receive for our coal, which are dependent on factors beyond our control, including, the demand for electricity, the strength of the global economy, the relative price of natural gas and other energy sources used to generate electricity, the demand for electricity and the capacity utilization of electricity generating units (whether coal or non-coal), the demand for steel, which may lead to price fluctuations in the monthly and quarterly repricing of our metallurgical coal contracts, the global supply and production costs of thermal and metallurgical coal, changes in fuel consumption and dispatch patterns of electric power generators, weather patterns and natural disasters, competition within our industry and the availability, quality and price of alternative fuels, including natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power, the proximity, capacity and cost of transportation and terminal facilities, coal and natural gas industry output and capacity, governmental regulations and taxes, including those establishing air emission standards for coal-fueled power plants or mandating or subsidizing increased use of electricity from renewable sources, regulatory, administrative and judicial decisions, including those affecting future mining permits and leases, and technological developments, including those related to alternative energy sources, those intended to convert coal-to-liquids or gas and those aimed at capturing, using and storing carbon dioxide;
our ability to find alternate buyers willing to purchase our coal on comparable terms in the event that a substantial number of our long-term coal supply agreements terminate, which could cause our revenues and operating profits to suffer;
the loss of, or significant reduction in, purchases by our largest customers, which could adversely affect our revenues;
our trading and hedging activities that no longer cover certain risks, and which could expose us to earnings volatility and other risks, including increasing requirements to post collateral;
unfavorable economic and financial market conditions, which could adversely affect our operating results;
our ability to collect payments from our customers could be impaired if their creditworthiness or contractual performance deteriorates;
risks inherent to mining, such as fires and explosions from methane gas or coal dust, accidental mine water discharges, weather, flooding and natural disasters, unexpected maintenance problems, unforeseen delays in implementation of mining technologies that are new to our operations, key equipment failures, variations in coal seam thickness, variations in coal quality, variations in the amount of rock and soil overlying the coal deposit, variations in rock and other natural materials and variations in geologic conditions, could increase the cost of operating our business;
any substantial increase in the price or the unavailability of transportation of our coal for our customers, in which case our ability to sell coal could suffer;
any decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires, which could decrease our anticipated profitability;
impacts of any unfavorable take-or-pay arrangements within the coal industry on our profitability;
inability of trading, brokerage, mining or freight counterparties to fulfill the terms of their contracts with us, which could reduce our profitability;
impairment charges that may result from any failure to recover our investments in our mining, exploration and other assets;
loss of key personnel or failure to attract qualified personnel may impact our ability to operate our company effectively;
our ability to maintain satisfactory labor relations;


51


our ability to appropriately provide financial assurances for our obligations, including land reclamation, federal and state workers’ compensation, coal leases and other obligations related to our operations;
the extensive regulation of our mining operations, which imposes significant costs, and future regulations and developments, which could impose significant costs on us and limit our ability to produce coal;
our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us;
our ability to obtain and renew permits necessary for our operations, which would reduce our production, cash flows and profitability;
the extensive forms of taxation of our mining operations, which imposes significant costs on us, and future regulations and developments which could increase those costs or limit our ability to produce coal competitively;
accuracy of our assumptions underlying our asset retirement obligations for reclamation and mine closures, which could raise our costs significantly greater than anticipated if the assumptions are materially inaccurate;
our ability to continue to acquire and develop coal reserves that are economically recoverable;
uncertainties in estimating our economically recoverable coal reserves, where inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability;
increased exposure to risks unique to international mining and trading operations, such as country risks, international regulatory requirements and the effects of changes in currency exchange rates;
the success or failure of joint ventures, partnerships or non-managed operations in which we participate, and the limited control over compliance with our operational standards that we may exercise over such non-managed operations;
further repositioning plans that we may undertake, and associated additional charges;
significant liability, reputational harm, loss of revenue, increased costs or other risks that we may sustain as a result of cyber attacks or other security breaches that disrupt our operations or result in the dissemination of proprietary or confidential information about us, our customers or other third parties;
accuracy of our assumptions underlying our predicted expenditures for postretirement benefit and pension obligations;
concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by government-backed lending institutions and development banks toward the financing of new overseas coal-fueled power plants and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities;
risks that could materially and adversely affect our business, including deterioration or other changes in economic conditions, changes in the industry, changes in customer demand for, and acceptance of, our coal, and increasing expenses;
dilution of our Common Stock;
our ability to pay dividends on our stock or to repurchase our stock, and our inability to assure future payments and repurchases;
our substantial indebtedness, which could adversely affect our financial performance. The degree to which we are leveraged could have important consequences, including, but not limited to, make it more difficult for us to pay interest and satisfy our debt obligations, increase the cost of borrowing under our credit facilities, increase our vulnerability to general economic and industry conditions, require the dedication of a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, business development or other general corporate requirements, limit our ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements, limit our flexibility in planning for and reacting to changes in our business and in the coal industry, cause a decline in our credit ratings and place us at a competitive disadvantage to less leveraged competitors;
our and our subsidiaries’ ability to incur substantially more debt despite our and our subsidiaries’ level of indebtedness following the Plan Effective Date, including secured debt, which could further increase the risks associated with our substantial indebtedness;
any failure to generate sufficient cash to service all of our post-emergence indebtedness or other obligations;
restrictions imposed by the terms of our indenture governing the Senior Secured Notes and the agreements and instruments governing our other post-emergence indebtedness, which may impose restrictions that may limit our operating and financial flexibility;


52


our ability to fully utilize our deferred tax assets;
provisions in our Certificate of Incorporation and By-laws that may discourage a takeover attempt;
diversity in interpretation and application of accounting literature in the mining industry that may impact our reported financial results;
volatility in the price of our securities;
conflicts of interest among our significant stockholders and other holders of our securities;
reports and projections published by analysts, including projections in those reports that exceed our actual results, which could adversely affect the price and trading volume of our securities;
sales of our common stock that could exert downward pressure on the market price of our common stock, and could encourage short selling that could exert further downward pressure; and
other risks and factors detailed in this report, including, but not limited to, those discussed in “Legal Proceedings,” set forth in Part II, Item 1 and in “Risk Factors,” set forth in Part II, Item 1A of this Quarterly Report on Form 10-Q.
When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in ourthe Company’s 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 ourits results contained in Item 1A. “Risk Factors” of Part II of this Quarterly Report on Form 10-Q, and Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” of ourPart I of its Annual Report on Form 10-K for the year ended December 31, 2016, Exhibit 99.2 to our Current Report on Form 8-K2022 filed with the SEC on April 11, 2017, and in Amendment No. 1 to our Annual Report on Form 10-K/A for the year ended December 31, 2016 filed with the SEC on July 10, 2017.February 24, 2023. These forward-looking statements speak only as of the date on which such statements were made, and we undertakethe Company undertakes no obligation to update these statements except as required by federal securities laws.
Non-GAAP Financial Measures
The following discussion of the Company’s results of operations includes references to and analysis of Adjusted EBITDA and Total Reporting Segment Costs, which are financial measures 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 its segments’ operating performance and allocate resources. Total Reporting Segment Costs is also used by management as a component of a metric to measure each of its segments’ operating performance.
Also included in the following discussion of the Company’s results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each reporting segment. These metrics are used by management to measure each of its reporting segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reporting segment level. The Company considers all measures reported on a per ton basis to be operating/statistical measures; however, the Company includes reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2.
The Company believes non-GAAP performance measures are used by investors to measure its operating performance. 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” section contained within this Item 2 for definitions and reconciliations to the most comparable measures under U.S. GAAP.

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Overview
We arePeabody is a leading producer of metallurgical and thermal coal. In 2022, the world’s largest private-sectorCompany produced and sold 122.9 million and 123.7 million tons of coal, company by volume. As of September 30, 2017, werespectively, from continuing operations. At March 31, 2023, the Company owned interests in 2317 active coal mining operations located in the United States (U.S.) and Australia. We have a majority interestIncluded in 22 of those mining operations and athat count is Peabody’s 50% equity interest in Middlemount Coal Pty Ltd.Ltd (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to ourits mining operations, we marketthe Company markets and brokerbrokers coal from other coal producers, both as principal and agent, and tradeproducers; trades coal and freight-related contracts.
In 2016, we produced 175.6 million tonscontracts; and during 2022, partnered in a joint venture with the intent of coal and sold 186.8 million tons of coal from continuing operations. During that period, 76% of our total sales (by volume) were to U.S. electricity generators, 21% were to customers outsidedeveloping various sites, including certain reclaimed mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and 3% were tobattery storage.
The Company reports its results of operations primarily through the U.S. industrial sector, with approximately 86% of our worldwide sales (by volume) delivered under long-term contracts.
We conduct business through six operatingfollowing reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, MidwesternOther U.S. Mining, Western U.S. Mining, Australian Metallurgical Mining, Australian Thermal Mining and TradingCorporate and Brokerage.Other. Refer to Note 20.13. “Segment Information” to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of ourits Corporate and Other segment.
Filing Under Chapter 11 of the United States Bankruptcy Code
On April 13, 2016 (the Petition Date), Peabody Energy Corporation and a majority of its wholly owned domestic subsidiaries as well as one international subsidiary in Gibraltar (the Filing Subsidiaries, and together with Peabody, the Debtors) filed voluntary petitions for reorganization (the Bankruptcy Petitions) under Chapter 11 of Title 11 of the U.S. Code (the Bankruptcy Code) in the United States Bankruptcy Court for the Eastern District of Missouri (the Bankruptcy Court). The Company’s Australian operations and other international subsidiaries were not included in the filings. The Debtors’ Chapter 11 cases (collectively, the Chapter 11 Cases) were jointly administered under the caption In re Peabody Energy Corporation, et al., Case No. 16-42529 (Bankr. E.D. Mo.). During the Chapter 11 Cases, the Debtors continued to operate their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In general, as debtors-in-possession, the Debtors were authorized under Chapter 11 to continue to operate as an ongoing business, but could not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court.


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On January 27, 2017, the Debtors filed with the Bankruptcy Court the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, the Plan) and the Second Amended Disclosure Statement with Respect to the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (previous versions of the Plan and Disclosure Statement were filed with the Bankruptcy Court on December 22, 2016, January 25, 2017 and January 27, 2017). Subsequently, the Debtors solicited votes on the Plan. On March 15, 2017, the Debtors filed a revised version of the Plan and on March 16, 2017, the Bankruptcy Court held a hearing to determine whether the Plan should be confirmed. On March 17, 2017, the Bankruptcy Court entered an order, Docket No. 2763 (the Confirmation Order), confirming the Plan. On April 3, 2017 (the Effective Date), the Debtors satisfied the conditions to effectiveness set forth in the Plan, the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases.
Upon emergence, in accordance with Accounting Standards Codification (ASC) 852, we applied fresh start reporting to our consolidated financial statements as of April 1, 2017 and became a new entity for financial reporting purposes reflecting the Successor (as defined below) capital structure. As a new entity, a new accounting basis in the identifiable assets and liabilities assumed was established with no retained earnings or accumulated other comprehensive income (loss) (OCI). For additional details, refer to Note 1. “Basis of Presentation” and Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” to the unaudited condensed consolidated financial statements.
In connection with our emergence from the Chapter 11 Cases and the adoption of fresh start reporting, the results of operations for 2017 separately present a Successor period (for the period April 2, 2017 through September 30, 2017) and a Predecessor period (for the period January 1, 2017 through April 1, 2017). The results of operations for 2016 include Predecessor periods for the three and nine months ended September 30, 2016. References to “Successor” are in reference to reporting dates on or after April 2, 2017; references to “Predecessor” are in reference to reporting dates through April 1, 2017, which include the impact of the Plan provisions and the application of fresh start reporting. Although the 2017 Successor period and the 2017 Predecessor period are distinct reporting periods, the effects of emergence and fresh start reporting did not have a material impact on the comparability of our results of operations between the periods, unless otherwise noted below. Accordingly, references to 2017 results of operations for the nine months ended September 30, 2017 combine the two periods to enhance the comparability of such information to the prior year.
Results of Operations
Non-U.S. GAAP Financial Measures
The following discussion of our results of operations includes references to and analysis of Adjusted EBITDA, which is a financial measure not recognized in accordance with U.S. generally accepted accounting principles (GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of our segment’s operating performance. We believe non-U.S. GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt.
Adjusted EBITDA is defined as income (loss) from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses, depreciation, depletion and amortization and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of our segment’s operating performance, as displayed in the reconciliation below. Adjusted EBITDA is not intended to serve as an alternative to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.
A reconciliation of Adjusted EBITDA to its most comparable measure under U.S. GAAP is included in Note 20. “Segment Information” of the accompanying unaudited condensed consolidated financial statements.
Also included in the following discussion of our results of operations are references to Revenues per Ton, Operating Costs per Ton and Gross Margin per Ton for each reporting segment which are all non-U.S. GAAP measures. Revenues per Ton and Gross Margin per Ton are approximately equal to revenues by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Operating Costs per Ton is equal to Revenues per Ton less Gross Margin per Ton.
Three and Nine Months Ended September 30, 2017 Compared to the Three and Nine Months Ended September 30, 2016
Summary
Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and NewcastleAPI 5 index thermal coal, and prompt month pricing for Powder River Basin (PRB)PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended September 30, 2017March 31, 2023 is set forth in the table below. Pricing for our Western U.S. Mining segment is not included as there is no similar spot or prompt pricing data available.


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In the U.S., theThe seaborne pricing included in the table below is not necessarily indicative of the pricing wethe Company realized during the three months ended September 30, 2017March 31, 2023 due to quality differentials and a portion of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized. 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.
In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months ended March 31, 2023 since wethe Company generally sellsells 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 producersfuel sources may also impact ourthe Company’s realized pricing.
The
HighLowAverageMarch 31, 2023April 28, 2023
Premium HCC (1)
$390.00 $294.50 $343.91 $301.00 $231.50 
Premium PCI coal (1)
344.00 263.50 313.01 263.50 201.00 
Newcastle index thermal coal (1)
397.30 170.80 242.37 178.53 186.31 
API 5 index thermal coal (1)
135.29 117.72 125.12 120.68 116.66 
PRB 8,800 Btu/Lb coal (2)
15.50 14.60 14.96 14.60 14.55 
Illinois Basin 11,500 Btu/Lb coal (2)
133.00 73.00 92.08 73.00 65.00 
(1)    Prices expressed per metric tonne.
(2)    Prices expressed per short ton.
Within the global coal industry, supply and demand for its products and the supplies used for mining have been impacted by the ongoing Russian-Ukrainian conflict. Furthermore, inflationary pressures and supply chain constraints have contributed to rising costs and may continue to impact future periods. As future developments related to the Russian-Ukrainian conflict and rising inflation are unknown, the global coal industry data for the three months ended March 31, 2023 presented herein may not be indicative of their ultimate impacts.

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Within the seaborne pricing includedmetallurgical coal market, the three months ended March 31, 2023 were characterized by ongoing volatility as global macroeconomic turbulence counteracted improving demand and further weather-induced supply disruptions in Australia. Several steelmakers announced blast furnace capacity restarts in the table belowthree months ended March 31, 2023, as growth in forward orders drives improvements to steel prices and margins. This is also not necessarily indicativesupportive for seaborne metallurgical coal demand in the coming period. Furthermore, China has ended its unofficial ban of Australian coal imports providing increased market depth for Australian products, especially for Premium HCC. Russian coal remains banned in the pricing we realizedEuropean Union, Japan and elsewhere, disrupting natural trade flows and resulting in low priced Russian products being made available to countries, such as China and India, which can continue procurement. The PCI market remained exceedingly tight during the three months ended September 30, 2017 dueMarch 31, 2023, especially in Europe, where Russia traditionally held dominant market share. The Company believes energy shortages and the global inflationary environment present a risk to price discounts based on coal qualitiesindustrial activity in some markets, but the underlying market fundamentals remain constructive with continuing themes of supply tightness, resilient demand and properties.
  High Low Average September 30, 2017
Premium HCC $211.00
 $151.50
 $188.78
 $187.25
Premium PCI coal $128.55
 $102.35
 $116.75
 $124.80
Newcastle index thermal coal $100.30
 $79.45
 $93.23
 $97.25
PRB 8,800 Btu/Lb coal $11.90
 $11.20
 $11.62
 $11.50
Illinois Basin 11,500 Btu/Lb coal $35.00
 $33.25
 $34.45
 $35.00
Seaborne thermal and metallurgical coal pricing remained well above prior-year levels on continued strengthfurther economic stimulus in China and elsewhere.
Within the seaborne thermal coal market, global thermal coal prices stabilized in March and recently showed improvement amid supply distributions in Colombia and Australia and ongoing robust demand from India and China. China has ended its unofficial ban of Australian coal imports, providing additional demand for Australian thermal coal. In China, domestic coal production and renewable generation have been strong to start the year, however, import demand has been higher year-over-year, as overall coal demand has been strong. In India, strong growth in coal generation has supported increased import demand, despite elevated domestic coal production. Overall, global thermal coal markets remain turbulent as supply constraints.has been disrupted due to logistics and weather issues and lower global natural gas prices.
With respectIn the United States, overall electricity demand decreased nearly 4% year-over-year, negatively impacted by weather. Through the three months ended March 31, 2023, electricity generation from thermal coal has declined year-over-year due to seaborne metallurgical coal, global steel productionlow gas prices, and stronger gas and renewable generation despite lower overall electricity demand. Coal’s share of electricity generation has risendeclined to approximately 5%15% for the three months ended March 31, 2023, while wind and solar’s combined generation share has increased to 17% and the share of gas generation has increased to 39%. Coal inventories have increased during the ninethree months ended September 30, 2017 asMarch 31, 2023, with an increase of approximately 25% or 22 million tons. During the three months ended March 31, 2023, utility consumption of PRB coal declined approximately 25% compared to the prior year period, led by record Chinese steel production. In addition, Chinese steel exports are down 30% year-to-date through September. Throughperiod.
Surety Agreement Amendment
On April 14, 2023, the nine months ended September 30, 2017 metallurgical coal imports in China rose 9 million tonnes as comparedCompany amended its existing agreement with the providers of its surety bond portfolio, dated November 6, 2020. Under the agreement, the Company was required to post collateral on a periodic basis. Pursuant to the prior year periodamendment, the Company and its surety bond providers agreed to (i) establish a combined maximum collateral cap, (ii) remove the restrictions on strong demand and curtailed domestic production.
Seaborne thermal coal demand and pricing continue to be supported by robust Asian demand primarily in China and South Korea. Chinese thermal coal imports are up approximately 15 million tonnes year-to-date through September compared to the prior year period on strong electricity generation that exceeded domestic production growth. In addition, South Korean imports have strengthened approximately 15 million tonnes through September, a 23% increase year-over-year, as nuclear generation has been curtailed. While import demand from India has been sluggish on increased domestic coal usage, stockpiles are currently at multi-year lows, which is supportive of additional importsshareholder returns contained in the fourth quarter.
Inoriginal agreement, subject to a minimum liquidity threshold, and (iii) extend the United States, demand was impacted by mild weather and weaker gas pricing in the third quarter of 2017. Even as overall electricity demand weakened year-over-year through September, utility consumption of Powder River Basin coal rose approximately 8% with natural gas consumption decreasing 12% compared to the prior year period (on 30% higher average natural gas prices year-over-year through September).
Net results of $230.0 million for the Successor three months ended September 30, 2017 included revenues of $1,477.2 million, a tax benefit of $84.1 million and income from equity affiliates of $10.5 million. These were offset by operating costs of $1,044.9 million, depreciation, depletion and amortization of $194.5 million and interest expense of $42.4 million related to the new debt instruments for the Successor Company. Net income attributable to common stockholders of $201.4 million included dividends of $23.5 million related to the Series A Convertible Preferred Stock (Preferred Stock) issued by the Successor Company. Adjusted EBITDA for the three months ended September 30, 2017 was $411.3 million.
Net results of $328.7 million for the Successor period April 2 through September 30, 2017 included revenues of $2,735.5 million, a tax benefit of $79.4 million and income from equity affiliates of $26.2 million. These were offset by operating costs of $1,979.7 million, depreciation, depletion and amortization of $342.8 million and interest expense of $83.8 million. Net income attributable to common stockholders of $181.2 million for the Successor period April 2 through September 30, 2017 was impacted by Preferred Stock dividends of $138.6 million. Adjusted EBITDA for the Successor period April 2 through September 30, 2017 was $729.1 million.
For the Predecessor period January 1 through April 1, 2017, net loss attributable to common stockholders of $216.5 million included revenues of $1,326.2 million, a tax benefit of $263.8 million and income from equity affiliates of $15.0 million. These were offset by operating costs of $963.7 million, depreciation, depletion and amortization of $119.9 million, interest expense of $32.9 million and reorganization items, net of $627.2 million which included the impactexpiration date of the Plan provisionsexisting agreement from December 31, 2025 to December 31, 2026. Peabody also terminated the letter of credit facility which was previously used primarily for surety collateral, further reducing interest costs and the application of fresh start reporting. Adjusted EBITDA for the Predecessor period January 1 through April 1, 2017 was $341.3 million.increasing financial flexibility.


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During the three and nine months ended September 30, 2016, the Predecessor Company had net loss attributable to common stockholders of $137.6 million and $536.6 million, respectively. The three months ended September 30, 2016 had revenues of $1,207.1 million which were offset by operating costs of $1,064.8 million, depreciation, depletion and amortization of $117.8 million, selling and administrative expenses of $32.1 million, interest expense of $58.5 million, and reorganization items, net of $29.7 million. The nine months ended September 30, 2016 had revenues of $3,274.5 million, which were offset by operating costs of $2,981.2 million, depreciation, depletion and amortization of $345.5 million, selling and administrative expenses of $114.6 million, interest expense of $243.7 million and reorganization items, net of $125.1 million. The Adjusted EBITDA for the three and nine months ended September 30, 2016 was $130.2 million and $238.0 million, respectively.
As of September 30, 2017, our available liquidity was approximately $942.7 million. Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of factors affecting our available liquidity.the surety agreement amendment.
Other
On March 29, 2023, the Company’s Shoal Creek Mine experienced a fire involving void fill material utilized to stabilize the roof structure of the mine. All mine personnel were safely evacuated from the mine. The Mine Safety and Health Administration (MSHA) has allowed mine rescue-equipped personnel into the mine at various times to assess the situation. On April 26, 2023, MSHA approved a temporary sealing program which was completed on April 28, 2023, and the Company continues to monitor air quality in the affected underground area.
Results of Operations
Three Months Ended March 31,2023 Compared to the Three Months Ended March 31,2022
Summary
The increase in results from continuing operations, net of income taxes for the three months ended March 31, 2023 compared to the same period in the prior year ($403.9 million), was primarily driven by higher revenue ($672.6 million) due to higher realized prices and volumes. This favorable variance was partially offset by higher operating costs and expenses ($147.6 million), which reflect increased sales price sensitive costs and inflationary pressures for commodities, materials, services, repairs and labor; and a higher income tax provision ($119.0 million).

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Adjusted EBITDA for the three months ended March 31, 2023 reflected a year-over-year increase of $63.1 million.
Tons Sold
The following tables presenttable presents tons sold by operating segment:
Three Month Comparison2017  2016    
 Successor  Predecessor Increase (Decrease)
 Three Months Ended to Volumes
 September 30 Tons %
 (Tons in millions)  
Powder River Basin Mining33.7
  33.0
 0.7
 2 %
Midwestern U.S. Mining4.9
  4.9
 —
 — %
Western U.S. Mining4.0
  4.3
 (0.3) (7)%
Australian Metallurgical Mining3.5
  3.2
 0.3
 9 %
Australian Thermal Mining5.2
  5.4
 (0.2) (4)%
Total tons sold from mining segments51.3
  50.8
 0.5
 1 %
Trading and Brokerage0.7
  2.0
 (1.3) (65)%
Total tons sold52.0
  52.8
 (0.8) (2)%
Nine Month Comparison2017 2016    
 Successor  Predecessor Combined Predecessor Increase (Decrease)
 April 2 through September 30  January 1 through April 1 Nine Months Ended to Volumes
    September 30 Tons %
 (Tons in millions)  
Powder River Basin Mining62.2
  31.0
 93.2
 80.0
 13.2
 17 %
Midwestern U.S. Mining9.5
  4.5
 14.0
 13.8
 0.2
 1 %
Western U.S. Mining7.2
  3.4
 10.6
 10.0
 0.6
 6 %
Australian Metallurgical Mining5.5
  2.2
 7.7
 10.1
 (2.4) (24)%
Australian Thermal Mining9.8
  4.6
 14.4
 15.8
 (1.4) (9)%
Total tons sold from mining segments94.2
  45.7
 139.9
 129.7
 10.2
 8 %
Trading and Brokerage1.4
  0.4
 1.8
 5.4
 (3.6) (67)%
Total tons sold95.6
  46.1
 141.7
 135.1
 6.6
 5 %


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Three Months Ended March 31,(Decrease) Increase
to Volumes
 20232022Tons%
 (Tons in millions)
Seaborne Thermal Mining3.6 3.8 (0.2)(5)%
Seaborne Metallurgical Mining1.3 1.2 0.1 8 %
Powder River Basin Mining22.0 20.6 1.4 7 %
Other U.S. Thermal Mining4.5 4.2 0.3 7 %
Total tons sold from operating segments31.4 29.8 1.6 5 %
Corporate and Other0.1 0.1 — — %
Total tons sold31.5 29.9 1.6 5 %
Supplemental Financial Data
The following tables presenttable presents supplemental financial data by operating segment:
Three Months Ended March 31,Increase
(Decrease)
 20232022$%
Revenue per Ton - Mining Operations (1)
Seaborne Thermal$96.82 $66.86 $29.96 45 %
Seaborne Metallurgical220.60 258.43 (37.83)(15)%
Powder River Basin13.89 12.18 1.71 14 %
Other U.S. Thermal54.73 48.46 6.27 13 %
Costs per Ton - Mining Operations (1)(2)
Seaborne Thermal$51.01 $42.77 $8.24 19 %
Seaborne Metallurgical151.13 112.87 38.26 34 %
Powder River Basin12.26 11.81 0.45 4 %
Other U.S. Thermal40.65 36.54 4.11 11 %
Adjusted EBITDA Margin per Ton - Mining Operations (1)(2)
Seaborne Thermal$45.81 $24.09 $21.72 90 %
Seaborne Metallurgical69.47 145.56 (76.09)(52)%
Powder River Basin1.63 0.37 1.26 341 %
Other U.S. Thermal14.08 11.92 2.16 18 %
Three Month Comparison2017  2016    
 Successor  Predecessor  
 Three Months Ended (Decrease) Increase
 September 30 $ %
         
Revenues per Ton - Mining Operations        
Powder River Basin$12.48
  $12.73
 $(0.25) (2)%
Midwestern U.S.42.52
  43.02
 (0.50) (1)%
Western U.S.38.25
  38.03
 0.22
 1 %
Australian Metallurgical119.55
  71.34
 48.21
 68 %
Australian Thermal51.78
  36.53
 15.25
 42 %
Operating Costs per Ton - Mining Operations (1)
        
Powder River Basin$9.13
  $8.97
 $0.16
 2 %
Midwestern U.S.32.39
  30.96
 1.43
 5 %
Western U.S.29.77
  30.00
 (0.23) (1)%
Australian Metallurgical78.42
  81.93
 (3.51) (4)%
Australian Thermal32.72
  27.50
 5.22
 19 %
Gross Margin per Ton - Mining Operations (1)
        
Powder River Basin$3.35
  $3.76
 $(0.41) (11)%
Midwestern U.S.10.13
  12.06
 (1.93) (16)%
Western U.S.8.48
  8.03
 0.45
 6 %
Australian Metallurgical41.13
  (10.59) 51.72
 488 %
Australian Thermal19.06
  9.03
 10.03
 111 %
(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.
(1)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; coal inventory revaluation; take-or-pay contract-based intangible recognition; and certain other costs related to post-mining activities.

(2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities.


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Nine Month Comparison2017 2016    
 Successor  Predecessor Combined Predecessor  
 April 2 through September 30

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

 September 30 $ %
             
Revenues per Ton - Mining Operations            
Powder River Basin$12.65
  $12.70
 $12.67
 $13.28
 $(0.61) (5)%
Midwestern U.S.42.57
  42.96
 42.69
 43.45
 (0.76) (2)%
Western U.S.38.54
  44.68
 40.47
 38.72
 1.75
 5 %
Australian Metallurgical128.89
  150.22
 135.03
 67.39
 67.64
 100 %
Australian Thermal51.65
  48.65
 50.69
 35.60
 15.09
 42��%
Operating Costs per Ton - Mining Operations (1)
            
Powder River Basin$9.47
  $9.75
 $9.57
 $9.80
 $(0.23) (2)%
Midwestern U.S.32.42
  31.84
 32.23
 30.96
 1.27
 4 %
Western U.S.27.65
  29.76
 28.31
 30.39
 (2.08) (7)%
Australian Metallurgical89.53
  100.16
 92.57
 79.34
 13.23
 17 %
Australian Thermal30.79
  32.27
 31.29
 26.90
 4.39
 16 %
Gross Margin per Ton - Mining Operations (1)
            
Powder River Basin$3.18
  $2.95
 $3.10
 $3.48
 $(0.38) (11)%
Midwestern U.S.10.15
  11.12
 10.46
 12.49
 (2.03) (16)%
Western U.S.10.89
  14.92
 12.16
 8.33
 3.83
 46 %
Australian Metallurgical39.36
  50.06
 42.46
 (11.95) 54.41
 455 %
Australian Thermal20.86
  16.38
 19.40
 8.70
 10.70
 123 %
(1)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; coal inventory revaluation; take-or-pay contract-based intangible recognition; and certain other costs related to post-mining activities.
RevenuesRevenue
The following tables present revenuestable presents revenue by reporting segment:
Three Months Ended March 31,Increase (Decrease) to Revenue
20232022$%
 (Dollars in millions) 
Seaborne Thermal Mining$346.5 $251.2 $95.3 38 %
Seaborne Metallurgical Mining288.4 321.3 (32.9)(10)%
Powder River Basin Mining305.3 251.2 54.1 22 %
Other U.S. Thermal Mining249.4 203.1 46.3 23 %
Corporate and Other174.4 (335.4)509.8 152 %
Revenue$1,364.0 $691.4 $672.6 97 %
Three Month Comparison2017  2016    
 Successor  Predecessor Increase (Decrease)
 Three Months Ended to Revenues
 September 30 $ %
 (Dollars in millions)  
Powder River Basin Mining$420.9
  $419.6
 $1.3
 — %
Midwestern U.S. Mining207.7
  211.0
 (3.3) (2)%
Western U.S. Mining155.7
  162.4
 (6.7) (4)%
Australian Metallurgical Mining415.9
  232.5
 183.4
 79 %
Australian Thermal Mining265.8
  197.9
 67.9
 34 %
Trading and Brokerage19.4
  2.7
 16.7
 619 %
Corporate and Other(8.2)  (19.0) 10.8
 57 %
Total revenues$1,477.2
  $1,207.1
 $270.1
 22 %


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Nine Month Comparison2017 2016    
 Successor  Predecessor Combined Predecessor Increase (Decrease)
 April 2 through September 30  January 1 through April 1 Nine Months Ended to Revenues
    September 30 $ %
 (Dollars in millions)  
Powder River Basin Mining$786.3
  $394.3
 $1,180.6
 $1,062.2
 $118.4
 11 %
Midwestern U.S. Mining402.6
  193.2
 595.8
 599.6
 (3.8) (1)%
Western U.S. Mining281.1
  149.7
 430.8
 387.0
 43.8
 11 %
Australian Metallurgical Mining703.7
  328.9
 1,032.6
 682.8
 349.8
 51 %
Australian Thermal Mining505.0
  224.8
 729.8
 561.4
 168.4
 30 %
Trading and Brokerage24.6
  15.0
 39.6
 16.5
 23.1
 140 %
Corporate and Other32.2
  20.3
 52.5
 (35.0) 87.5
 250 %
Total revenues$2,735.5
  $1,326.2
 $4,061.7
 $3,274.5
 $787.2
 24 %
Powder River BasinSeaborne Thermal Mining. Segment revenuesrevenue increased during the three and nine months ended September 30, 2017March 31, 2023 compared to the same periodsperiod in the prior year due to demand-based volume increases across the entire region as the result of increased natural gas pricing (three months, 0.7 million tons, $13.4 million; nine months, 13.2 million tons, $176.7favorable realized prices ($68.7 million) and favorable mix variances ($26.6 million) which drove a switch from natural gas to coal by customers, partially offset by lower realized coal pricing (three months, $12.1 million; nine months, $58.3 million).unfavorable volumes.
Midwestern U.S.Seaborne Metallurgical Mining.Segment revenuesrevenue decreased during the three months ended September 30, 2017March 31, 2023 compared to the same period in the prior year due to unfavorable volume and mix variancesrealized prices ($2.039.8 million) and lower realized coal pricing ($1.3 million). Segment revenues decreased during the nine months ended September 30, 2017 compared to the same period in the prior year primarily due to lower realized coal pricing ($5.0 million) which was slightly, partially offset by favorable volume and mix variancesvolumes ($1.26.9 million).
Western U.S.Powder River Basin Mining. Segment revenues decreasedrevenue increased during the three months ended September 30, 2017March 31, 2023 compared to the same period in the prior year due to lowerfavorable realized coal pricingprices ($3.433.3 million) and unfavorable volume and mix variancesfavorable volumes ($3.320.8 million). resulting from improved rail performance.
Other U.S. Thermal Mining. Segment revenues increased during the nine months ended September 30, 2017 compared to the same period in the prior year predominately due to favorable volume and mix variances from higher margin operations ($35.0 million) and the liquidated damages settlement collected from Arizona Public Service Company and PacifiCorp ($13.0 million).
Australian Metallurgical Mining. Segment revenuesrevenue increased during the three months ended September 30, 2017 compared to the same period in the prior year primarily as the result of significantly improved realized coal pricing ($166.4 million) and a favorable volume and mix variance ($17.0 million) driven by improved production at our North Goonyella Mine due to a longwall move in the prior year period. Segment revenues increased during the nine months ended September 30, 2017 compared to the same period in the prior year primarily due to significantly improved realized coal pricing ($513.3 million) which was partially offset by an unfavorable volume and mix variance ($163.5 million). The volume decrease reflected lower sales volumes due to the cessation of mining activities at our Burton Mine during the fourth quarter of 2016, the impact of Cyclone Debbie and an extended longwall move at the Metropolitan Mine during the first half of 2017.
Australian Thermal Mining. Segment revenues increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to significantly improved realized coal pricing (three months, $75.8 million; nine months, $214.2 million), partially offset by an unfavorable volume and mix variance (three months, $7.9 million; nine months, $45.8 million) which was attributable to lower sales volumes from our Wambo Mine as the result of temporary geological issues associated with a longwall move.
Trading and Brokerage. Segment revenues increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year due to deliveries hedged in 2016.
Corporate and Other. Segment revenues increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year due to improved results on economic hedges (three months, $11.1 million; nine months, $64.3 million) and the receipt of break fees (nine months, $28.0 million) related to terminated asset sales which are further described in Note 16. “Other Events” of the accompanying unaudited condensed consolidated financial statements.


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Income (Loss) From Continuing Operations Before Income Taxes
The following table presents income (loss) from continuing operations before income taxes:
 2017  2016 2017 2016
 Successor  Predecessor Successor  Predecessor Combined Predecessor
 Three Months Ended April 2 through September 30  January 1 through April 1 Nine Months Ended
 September 30    September 30
 (Dollars in millions)
Income (loss) from continuing operations before income taxes$149.6
  $(108.5) $255.7
  $(459.3) $(203.6) $(596.8)
Depreciation, depletion and amortization(194.5)  (117.8) (342.8)  (119.9) (462.7) (345.5)
Asset retirement obligation expenses(11.3)  (12.7) (22.3)  (14.6) (36.9) (37.3)
Selling and administrative expenses related to debt restructuring—
  —
 —
  —
 —
 (21.5)
Asset impairment—
  —
 —
  (30.5) (30.5) (17.2)
Change in deferred tax asset valuation allowance related to equity affiliates3.4
  0.6
 7.7
  5.2
 12.9
 0.6
Interest expense(42.4)  (58.5) (83.8)  (32.9) (116.7) (243.7)
Loss on early debt extinguishment(12.9)  —
 (12.9)  —
 (12.9) —
Interest income2.0
  1.3
 3.5
  2.7
 6.2
 4.0
Break fees related to terminated asset sales—
  —
 28.0
  —
 28.0
 —
Unrealized (losses) gains on non-coal trading derivative contracts(1.7)  —
 1.5
  —
 1.5
 —
Unrealized (losses) gains on economic hedges(10.8)  (21.9) (1.4)  16.6
 15.2
 (49.1)
Coal inventory revaluation—
  —
 (67.3)  —
 (67.3) —
Take-or-pay contract-based intangible recognition6.5
  —
 16.4
  —
 16.4
 —
Reorganization items, net—
  (29.7) —
  (627.2) (627.2) (125.1)
Adjusted EBITDA$411.3
  $130.2
 $729.1
  $341.3
 $1,070.4
 $238.0
Results from continuing operations before income taxes for the Successor three months ended September 30, 2017 resulted in Adjusted EBITDA of $411.3 million which was partially offset by depreciation, depletion and amortization, interest expense. and loss on early debt extinguishment. Results from continuing operations before income taxes for the Successor period April 2 through September 30, 2017 included Adjusted EBITDA of $729.1 million and break fees related to terminated asset sales, which were partially decreased by depreciation, depletion and amortization, fresh start reporting fair value adjustments, interest expense and loss on early debt extinguishment.
Results from continuing operations before income taxes for the Predecessor period January 1 through April 1, 2017 were impacted by reorganization items, net, depreciation, depletion and amortization and interest expense. These results were partially offset by Adjusted EBITDA of $341.3 million.
During the three and nine months ended September 30, 2016, the Predecessor Company’s results from continuing operations before income taxes included Adjusted EBITDA of $130.2 million and $238.0 million, respectively. These results were offset by depreciation, depletion and amortization, interest expense and reorganization items, net.


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Adjusted EBITDA
The following tables present Adjusted EBITDA for each of our reporting segments:
Three Month Comparison2017  2016 (Decrease) Increase
 Successor  Predecessor to Segment Adjusted
 Three Months Ended EBITDA
 September 30 $ %
 (Dollars in millions)  
Powder River Basin Mining$112.7
  $123.9
 $(11.2) (9)%
Midwestern U.S. Mining49.5
  59.1
 (9.6) (16)%
Western U.S. Mining34.5
  34.3
 0.2
 1 %
Australian Metallurgical Mining143.1
  (34.5) 177.6
 515 %
Australian Thermal Mining97.8
  48.9
 48.9
 100 %
Trading and Brokerage2.7
  (9.4) 12.1
 129 %
Corporate and Other(29.0)  (92.1) 63.1
 69 %
Adjusted EBITDA$411.3
  $130.2
 $281.1
 216 %
Nine Month Comparison2017 2016 Increase (Decrease)
 Successor  Predecessor Combined Predecessor to Segment Adjusted
 April 2 through September 30

January 1 through April 1 Nine Months Ended EBITDA
 

 September 30 $ %
 (Dollars in millions)  
Powder River Basin Mining$197.5
  $91.7
 $289.2
 $278.3
 $10.9
 4 %
Midwestern U.S. Mining96.0
  50.0
 146.0
 172.4
 (26.4) (15)%
Western U.S. Mining79.4
  50.0
 129.4
 83.2
 46.2
 56 %
Australian Metallurgical Mining215.0
  109.6
 324.6
 (121.0) 445.6
 368 %
Australian Thermal Mining203.7
  75.6
 279.3
 137.2
 142.1
 104 %
Trading and Brokerage(2.4)  8.8
 6.4
 (41.3) 47.7
 115 %
Corporate and Other(60.1)  (44.4) (104.5) (270.8) 166.3
 61 %
Adjusted EBITDA$729.1
  $341.3
 $1,070.4
 $238.0
 $832.4
 350 %
Powder River Basin Mining. Segment Adjusted EBITDA decreased during the three months ended September 30, 2017March 31, 2023 compared to the same period in the prior year due to lowerfavorable realized coal pricing, net of sales-related costsprices ($9.7 million), higher materials, services and repairs costs ($3.728.4 million) and favorable volumes ($17.9 million).
Corporate and Other. Segment revenue increased pricingduring the three months ended March 31, 2023 compared to the same period in the prior year due to net unrealized mark-to-market gains on derivative contracts related to forecasted coal sales in the current year compared to net unrealized mark-to-market losses in the prior year ($419.7 million); higher results from trading activities ($72.7 million) due to higher margins recognized on the physical sale of coal and lower net realized losses on derivative contracts related to forecasted coal sales; and revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 14. “Other Events” to the accompanying unaudited condensed consolidated financial statements.
Adjusted EBITDA
The following table presents Adjusted EBITDA for fueleach of the Company’s reporting segments:
 Three Months Ended March 31,Increase (Decrease) to Segment Adjusted EBITDA
20232022$%
 (Dollars in millions) 
Seaborne Thermal Mining$164.0 $90.5 $73.5 81 %
Seaborne Metallurgical Mining90.8 181.0 (90.2)(50)%
Powder River Basin Mining35.8 7.6 28.2 371 %
Other U.S. Thermal Mining64.2 50.0 14.2 28 %
Corporate and Other35.8 (1.6)37.4 2,338 %
Adjusted EBITDA (1)
$390.6 $327.5 $63.1 19 %
(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 explosives ($2.9 million), partially offset by reduced lease expenses resulting from early lease buyouts ($6.0 million).reconciliations to the most comparable measures under U.S. GAAP.

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Seaborne Thermal Mining. Segment Adjusted EBITDA increased during the ninethree months ended September 30, 2017March 31, 2023 compared to the same period in the prior year as a result of higher realized prices net of sales sensitive costs ($64.1 million) and favorable mix variances ($26.6 million), partially offset by higher commodity pricing ($8.9 million) and higher port and demurrage costs ($7.1 million).
Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreased during the three months ended March 31, 2023 compared to the same period in the prior year due to unfavorable operational costs ($50.4 million) resulting from wet weather impacts at the Coppabella and Moorvale Mines and geological conditions at the Shoal Creek Mine and lower realized prices net of sales sensitive costs ($43.8million).
Powder River Basin Mining. Segment Adjusted EBITDA increased during the three months ended March 31, 2023 compared to the same period in the prior year due to higher volume drivenrealized prices net of sales sensitive costs ($22.1 million); decreased overburden removal costs ($11.0 million); and favorable volumes ($7.3 million) resulting from improved rail performance. The increases were partially offset by increased natural gas pricing ($50.6 million) and reduced expenseshigher costs for leases ($16.5 million)materials, services, repairs and labor ($12.39.7 million), partially offset by lower realized coal pricing, net of sales-related costs ($59.0 million) due in part to timing, increased repairs for an aging equipment fleet and increased pricing for fuelinflationary pressures on materials and explosives ($11.4 million).services.
MidwesternOther U.S. Thermal Mining. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to higher materials, services and repairs costs (three months, $4.4 million; nine months, $13.3 million), increased pricing for fuel and explosives (three months, $1.5 million; nine months, $8.2 million) and lower realized coal pricing, net of sales-related costs (three months, $2.7 million; nine months, $7.4 million).
Western U.S. Mining. Segment Adjusted EBITDA increased during the ninethree months ended September 30, 2017March 31, 2023 compared to the same period in the prior year primarily due to improvedhigher realized prices net of sales volumes from higher margin operationssensitive costs ($27.3 million), the liquidated damages settlement collected from Arizona Public Service Company and PacifiCorp ($13.024.6 million) and decreased spending for materials, services and repairs costsfavorable volumes ($12.7 million), partially offset by lower realized coal pricing, net of sales-related costs ($5.5 million).


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Australian Metallurgical Mining. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily driven by improved realized coal pricing, net of sales-related costs (three months, $155.2 million; nine months, $478.2 million), improved volumes at our North Goonyella Mine (three months, $23.5 million; nine months, $14.9 million) resulting from longwall moves in the prior year, improved production volumes at our Coppabella Mine (three months, $14.8 million; nine months, $19.2 million) and lower contractor and rail costs due to the cessation of mining activities at our Burton Mine during the fourth quarter of 2016 (nine months, $14.811.0 million). TheThese increases were offset by the impact of Cyclone Debbie, unfavorable foreign exchange rate movements (three months, $9.4 million; nine months, $16.1higher costs for materials, services, repairs and labor ($16.9 million) due in part to increased equipment repairs and cost escalations (three months, $6.0 million; nine months, $17.5 million).headcount resulting from increasing volume demands and inflationary pressures on materials and services.
Australian Thermal Mining. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to improved realized coal pricing, net of sales-related costs (three months, $69.9 million; nine months, $197.5 million) and improved production and leasing costs at our Wilpinjong Mine (three months, $6.8 million), offset by lower sales volume caused by geological issues at our Wambo Mine (three months, $26.8 million; nine months, $28.2 million) and higher fuel pricing and other cost escalations (three months, $3.5 million; nine months, $13.3 million).
Trading and Brokerage. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to market and business opportunities recognized.
Corporate and Other Adjusted EBITDA. The following tables presenttable presents a summary of the components of Corporate and Other Adjusted EBITDA:
Three Months Ended March 31,(Decrease) Increase to Adjusted EBITDA
20232022$%
 (Dollars in millions)
Middlemount (1)
$2.3 $45.1 $(42.8)(95)%
Resource management activities (2)
2.3 3.5 (1.2)(34)%
Selling and administrative expenses(22.8)(23.1)0.3 1 %
Other items, net (3)
54.0 (27.1)81.1 299 %
Corporate and Other Adjusted EBITDA$35.8 $(1.6)$37.4 2,338 %
Three Month Comparison2017  2016    
 Successor  Predecessor (Decrease) Increase
 Three Months Ended to Income
 September 30 Tons $
 (Dollars in millions)  
Resource management activities (1)
$0.4
  $1.3
 $(0.9) (69)%
Selling and administrative expenses (excluding debt restructuring)(33.4)  (32.1) (1.3) (4)%
Restructuring charges(1.1)  (0.3) (0.8) (267)%
Corporate hedging7.3
  (47.4) 54.7
 115 %
Other items, net (2)
(2.2)  (13.6) 11.4
 84 %
Corporate and Other Adjusted EBITDA$(29.0)  $(92.1) $63.1
 69 %
(1)
Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues.
(2)
Includes results from equity affiliates (before the impact of related changes in deferred tax asset valuation allowance and amortization of basis difference), costs associated with post-mining activities, certain coal royalty expenses, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts and expenses related to our other commercial activities.

(1)Middlemount’s results are before the impact of related changes in amortization of basis difference. Middlemount’s standalone results included (on a 50% attributable basis) aggregate amounts of depreciation, depletion and amortization, asset retirement obligation expenses, net interest expense and income taxes of $2.6 million and $20.2 million during the three months ended March 31, 2023 and 2022, respectively.

(2)Includes gains (losses) on certain surplus coal reserve, resource and surface land sales and property management costs and revenue.
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Nine Month Comparison2017 2016    
 Successor  Predecessor Combined Predecessor (Decrease) Increase
 April 2 through September 30  January 1 through April 1 Nine Months Ended to Income
    September 30 $ %
 (Dollars in millions)  
Resource management activities (1)
$1.6
  $2.9
 $4.5
 $11.3
 $(6.8) (60)%
Selling and administrative expenses (excluding debt restructuring)(67.8)  (37.2) (105.0) (93.1) (11.9) (13)%
Restructuring charges(1.1)  —
 (1.1) (15.5) 14.4
 93 %
Corporate hedging6.9
  (27.6) (20.7) (197.8) 177.1
 90 %
UMWA voluntary employee beneficiary association settlement—
  —
 —
 68.1
 (68.1) (100)%
Gain on sale of interest in Dominion Terminal Associates—
  19.7
 19.7
 —
 19.7
 n.m.
Other items, net (2)
0.3
  (2.2) (1.9) (43.8) 41.9
 96 %
Corporate and Other Adjusted EBITDA$(60.1)  $(44.4) $(104.5) $(270.8) $166.3
 61 %
(1)
Includes gains (losses) on certain surplus coal reserve and surface land sales and property management(3)Includes trading and brokerage activities, costs and revenues.
(2)
Includes results from equity affiliates (before the impact of related changes in deferred tax asset valuation allowance and amortization of basis difference), costs associated with past mining activities, certain coal royalty expenses, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts and expenses related to our other commercial activities.
The increases associated with corporate hedging results, which includes foreign currencypost-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations including the North Goonyella Mine and commodity hedging, were dueexpenses related to a decrease in realized losses asthe Company’s other commercial activities.
Corporate and Other Adjusted EBITDA benefited during the three months ended March 31, 2023 compared to the same period in the prior year. The increases associated with “Other items, net” were primarily attributable to improved Middlemountyear from favorable trading results as compared($69.7 million) and revenue related to the prior year driven by higher pricing. During the first quarterCompany’s assignment of 2017, a $19.7 million gain was recorded in connection with the sale of our interest in Dominion Terminal Associates. Restructuring charges for the nine months ended September 30, 2017 decreasedrights to its excess port and rail capacity ($19.2 million) as workforce reductions were made during 2016 at multiple mines in our Power River Basin Mining and Midwestern U.S. Mining segments. During 2016, a gain of $68.1 million was recognized for the voluntary employee beneficiary association (VEBA) settlement with the United Mine Workers of America (UMWA) as further describeddiscussed in Note 5. “Discontinued Operations” of14. “Other Events” to the accompanying unaudited condensed consolidated financial statements. This benefit was offset by unfavorable variances in Middlemount’s results due to lower sales pricing and sales volumes.

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Income (Loss) From Continuing Operations, Net of Income Taxes
The increasesfollowing table presents income (loss) from continuing operations, net of income taxes:
Three Months Ended March 31,Increase (Decrease) to Income
 20232022$%
 (Dollars in millions) 
Adjusted EBITDA (1)
$390.6 $327.5 $63.1 19 %
Depreciation, depletion and amortization(76.3)(72.9)(3.4)(5)%
Asset retirement obligation expenses(15.4)(15.0)(0.4)(3)%
Restructuring charges(0.1)(1.6)1.5 94 %
Asset impairment(2.0)— (2.0)n.m.
Changes in amortization of basis difference related to equity affiliates0.3 0.6 (0.3)(50)%
Interest expense(18.4)(39.4)21.0 53 %
Net loss on early debt extinguishment(6.8)(23.5)16.7 71 %
Interest income13.1 0.5 12.6 2,520 %
Unrealized gains (losses) on derivative contracts related to forecasted sales118.7 (301.0)419.7 139 %
Unrealized (losses) gains on foreign currency option contracts(2.2)3.3 (5.5)(167)%
Take-or-pay contract-based intangible recognition0.6 0.7 (0.1)(14)%
Income tax (provision) benefit(118.0)1.0 (119.0)(11,900)%
Income (loss) from continuing operations, net of income taxes$284.1 $(119.8)$403.9 337 %
(1)This is a financial measure not recognized in sellingaccordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and administrative expenses were driven by charges for shared-based compensation expense.reconciliations to the most comparable measures under U.S. GAAP.
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by reporting segment:
 2017  2016 2017 2016
 Successor  Predecessor Successor  Predecessor Predecessor
 Three Months Ended September 30 April 2 through September 30  January 1 through April 1 Nine Months Ended
September 30
 (Dollars in millions)
Powder River Basin Mining$(57.4)  $(33.5) $(95.6)  $(32.0) $(90.2)
Midwestern U.S. Mining(38.1)  (12.9) (73.4)  (13.3) (40.1)
Western U.S. Mining(32.9)  (11.2) (57.7)  (23.6) (34.3)
Australian Metallurgical Mining(37.1)  (30.9) (64.3)  (20.6) (90.3)
Australian Thermal Mining(25.7)  (26.2) (45.5)  (24.0) (77.2)
Trading and Brokerage(0.1)  —
 (0.1)  —
 (0.1)
Corporate and Other(3.2)  (3.1) (6.2)  (6.4) (13.3)
Total$(194.5)  $(117.8) $(342.8)  $(119.9) $(345.5)


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Three Months Ended March 31,Increase (Decrease) to Income
20232022$%
 (Dollars in millions)
Seaborne Thermal Mining$(23.8)$(24.0)$0.2 1 %
Seaborne Metallurgical Mining(21.1)(19.9)(1.2)(6)%
Powder River Basin Mining(11.7)(10.5)(1.2)(11)%
Other U.S. Thermal Mining(17.7)(15.7)(2.0)(13)%
Corporate and Other(2.0)(2.8)0.8 29 %
Total$(76.3)$(72.9)$(3.4)(5)%
Additionally, the following table presents a summary of ourthe Company’s weighted-average depletion rate per ton for active mines in each of our miningits operating segments:
Three Months Ended March 31,
 20232022
Seaborne Thermal Mining$2.17 $2.48 
Seaborne Metallurgical Mining2.16 2.12 
Powder River Basin Mining0.31 0.33 
Other U.S. Thermal Mining1.21 1.17 
 2017  2016 2017 2016
 Successor  Predecessor Successor  Predecessor Predecessor
 Three Months Ended
September 30		 April 2 through September 30  January 1 through April 1 Nine Months Ended September 30
Powder River Basin Mining$0.84
  $0.69
 $0.83
  $0.69
 $0.73
Midwestern U.S. Mining0.83
  0.54
 0.78
  0.61
 0.52
Western U.S. Mining1.06
  0.91
 1.06
  4.30
 0.91
Australian Metallurgical Mining0.66
  4.29
 0.68
  4.72
 4.24
Australian Thermal Mining1.73
  2.59
 1.72
  2.62
 2.61
Depreciation,The decrease in the weighted-average depletion and amortization expenserate per ton for the SuccessorSeaborne Thermal Mining segment during the three months ended September March 31, 2023 compared to the same period in the prior year reflects the impact of volume and mix variances across the segment.

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Interest Expense. The decrease in interest expense ($50.3 million), amortization ofduring the fair value of certain U.S. coal supply agreements ($41.5 million), amortization associated with our asset retirement obligation assets ($14.8 million) and depreciation expense ($87.9 million). Depreciation, depletion and amortization expense was higher for the Successor three months ended September 30, 2017March 31, 2023 primarily reflects the impacts of debt retirements completed by the Company during 2022 as compared to the Successor period April 2 through June 30, 2017 as the result of volume increasesfurther described in the period which impacted the portion of our depreciation, depletion and amortization expense that is recorded on a units-of-production method.
Depreciation, depletion and amortization expense for the Predecessor period January 1 through April 1, 2017 reflected additional expense at some of our mines due to changes in the estimated life of mine and at Corporate and Other for leasehold improvements that were vacated in 2017. The additional expense was offset by a decrease at our Metropolitan Mine as the assets were classified as held for sale during the period and depreciation, depletion and amortization was therefore not recorded. The share sale and purchase agreement related to our Metropolitan Mine was terminated in April 2017, as discussed in Note. 16. “Other Events” to the accompanying unaudited condensed consolidated financial statements. Depreciation, depletion and amortization expense for the three and nine months ended September 30, 2016 was impacted by a reduction in the asset bases at several of our mines due to impairment charges that had been recognized during 2015.
Selling and Administrative Expenses Related to Debt Restructuring. The general and administrative expenses related to debt restructuring recorded during 2016 related to legal and other expenditures made in connection with debt restructuring initiatives prior to the Debtors’ filing of the Bankruptcy Petitions.
Asset Impairment. Refer to Note 4. “Asset Impairment” in the accompanying unaudited condensed consolidated financial statements for information surrounding the impairment charges recorded during the Predecessor period January 1 through April 1, 2017 and the nine months ended September 30, 2016.
Interest Expense. Interest expense for the Successor Company primarily related to the 6.000% Senior Secured Notes due March 2022, the 6.375% Senior Secured Notes due March 2025 and the Senior Secured Term Loan due 2022. For additional details on debt, refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” and Note. 13.8. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements.
Interest expensestatements and Note 10. “Long-term Debt” to the Annual Report on Form 10-K for the Predecessor period January 1 through April 1, 2017 and the three and nine monthsyear ended September 30, 2016, was impacted by our filing of the Bankruptcy Petitions, which resulted in only accruing adequate protection payments subsequent to the Petition Date to certain secured lenders and other parties in accordance with Section 502(b)(2) of the Bankruptcy Code.December 31, 2022.
Net Loss on Early Debt Extinguishment. The loss on early debt extinguishment recorded onlosses recognized during the Successor Company,three months ended March 31, 2023 were primarily related to the amendment of the Senior Secured Term Loan due 2022Company’s now-terminated letter of credit facility as further discussed in Note 11. “Financial Instruments and Other Guarantees” to the accompanying unaudited condensed consolidated financial statements. The losses recognized during the prior year period were primarily related to the redemption of existing notes during the period as further described in Note 13.8. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements.statements and Note 10. “Long-term Debt” to the Annual Report on Form 10-K for the year ended December 31, 2022.
Break FeesInterest Income. The increase in interest income during the three months ended March 31, 2023 was primarily due to higher cash balances, including restricted cash balances on which the Company earns interest, and higher interest rates in the current year. Based upon projected cash balances and interest rates, the Company anticipates significantly higher interest income throughout 2023 as compared to the prior year.
Unrealized Gains (Losses) on Derivative Contracts Related to Terminated AssetForecasted Sales. The Successor Company received break fees of $28.0 million during the period April 2 through September 30, 2017Unrealized gains (losses) primarily relate to mark-to-market activity on derivative contracts related to terminated asset sales which are further described inforecasted coal sales. For additional information, refer to Note 16. “Other Events” of5. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements.
Unrealized (Losses) Gains on Economic Hedges.Foreign Currency Option Contracts. Unrealized (losses) gains primarily relate to mark-to-market activity from financial contract trading activities.


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Coal Inventory Revaluation. As a part of the fresh start reporting adjustments, the book value of coal inventories was increased to reflect the estimated fair value, less costs to sell the inventories. During the Successor period April 2 through September 30, 2017, this adjustment was fully amortized as the inventory was sold.on foreign currency option contracts. For additional details,information, refer to Note 3. “Emergence from the Chapter 11 Cases5. “Derivatives and Fresh Start Reporting”Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements.
Take-or-Pay Contract-Based Intangible Recognition. IncludedIncome Tax (Provision) Benefit. The increase in the fresh start reporting adjustments were contract-based intangible liabilities for port and rail take-or-pay contracts. Duringincome tax provision during the Successor three months ended September 30, 2017March 31, 2023 compared to the same period in the prior year was primarily due to an increase in pretax income and the period April 2 through September 30, 2017, the Company has ratably recognized these contract-based intangible liabilities. For additional details, referrelease of valuation allowance related to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” to the accompanying unaudited condensed consolidated financial statements.
Reorganization Items, Net. The reorganization items recordedAustralian net operating losses during the Predecessor period January 1 through April 1, 2017 reflected the impactfourth quarter of the Plan provisions and the application of fresh start reporting. Expense recorded during the three and nine months ended September 30, 2016 related to expenses recorded in connection with our Chapter 11 Cases.2022. Refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting”7. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for further information regarding our reorganization items.
Income (Loss) from Continuing Operations, Net of Income Taxes
The following tables present income (loss) from continuing operations, net of income taxes:
 2017  2016 2017 2016
 Successor  Predecessor Successor  Predecessor Predecessor
 Three Months Ended September 30 April 2 through September 30  January 1 through April 1 Nine Months Ended
September 30
     
 (Dollars in millions)
Income (loss) from continuing operations before income taxes$149.6
  $(108.5) $255.7
  $(459.3) $(596.8)
Income tax benefit(84.1)  (10.8) (79.4)  (263.8) (108.2)
Income (loss) from continuing operations, net of income taxes$233.7
  $(97.7) $335.1
  $(195.5) $(488.6)
Income Tax Benefit. The income tax benefit recorded for the Successor periods presented primarily related to expected refunds for U.S. net operating loss carrybacks.
The income tax benefit recorded for the Predecessor period January 1 through April 1, 2017, was primarily comprised of benefits related to Predecessor deferred tax liabilities ($177.8 million), accumulated other comprehensive income ($81.5 million) and unrecognized tax benefits ($6.7 million). Refer to Note 12. “Income Taxes” in the accompanying unaudited condensed consolidated financial statements for additional information.


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Net Income (Loss) Attributable to Common Stockholders
The following tables presenttable presents net lossincome (loss) attributable to common stockholders:
Three Months Ended March 31,Increase (Decrease)
to Income
20232022$%
 (Dollars in millions)
Income (loss) from continuing operations, net of income taxes$284.1 $(119.8)$403.9 337 %
Loss from discontinued operations, net of income taxes(1.3)(0.8)(0.5)(63)%
Net income (loss)282.8 (120.6)403.4 334 %
Less: Net income (loss) attributable to noncontrolling interests14.3 (1.1)15.4 1,400 %
Net income (loss) attributable to common stockholders$268.5 $(119.5)$388.0 325 %
 2017  2016 2017 2016
 Successor  Predecessor Successor  Predecessor Predecessor
 Three Months Ended September 30 April 2 through September 30  January 1 through April 1 Nine Months Ended
September 30
     
 (Dollars in millions)
Income (loss) from continuing operations, net of income taxes$233.7
  $(97.7) $335.1
  $(195.5) $(488.6)
Loss from discontinued operations, net of income taxes(3.7)  (38.1) (6.4)  (16.2) (44.5)
Net income (loss)230.0
  (135.8) 328.7
  (211.7) (533.1)
Less: Series A Convertible Preferred Stock dividends23.5
  —
 138.6
  —
 —
Less: Net income attributable to noncontrolling interests5.1
  1.8
 8.9
  4.8
 3.5
Net income (loss) attributable to common stockholders$201.4
  $(137.6) $181.2
  $(216.5) $(536.6)
Loss from Discontinued Operations, Net of Income Taxes. (Loss) Attributable to Noncontrolling Interests. The loss from discontinued operations forincrease in the Predecessor three and nine months ended September 30, 2016 was primarily comprised of a charge of $35.0 million forresults attributable to noncontrolling interests during the UMWA 1974 Pension Plan. For additional details, refer to Note 5. “Discontinued Operations” to the accompanying unaudited condensed consolidated financial statements.
Series A Convertible Preferred Stock Dividends. The Series A Convertible Preferred Stock dividends for the Successor three months ended September 30, 2017 andMarch 31, 2023 compared to the same period April 2 through September 30, 2017 were comprisedin the prior year was primarily due to stronger financial results of the deemed dividends (three months, $23.5 million; nine months, $135.5 million) granted for the Preferred Stock shares that were converted during the respective periods and the first semi-annual paymentPeabody’s majority-owned Wambo operations in which there is an outside non-controlling interest.

31

Table of preferred dividends (nine months, $3.1 million) which was pro-rated for the period of April 3 through April 30, 2017.Contents

Diluted EPSEarnings per Share (EPS)
The following table presents diluted EPS:
2017  2016 2017 2016
Successor  Predecessor Successor  Predecessor Predecessor
Three Months Ended September 30 April 2 through September 30  January 1 through April 1 Nine Months Ended
September 30		Three Months Ended March 31,Increase
to EPS
     20232022$%
Diluted EPS attributable to common stockholders:           Diluted EPS attributable to common stockholders:
Income (loss) from continuing operations$1.49
  $(5.44) $1.37
  $(10.93) $(26.91)Income (loss) from continuing operations$1.69 $(0.87)$2.56 294 %
Loss from discontinued operations(0.02)  (2.09) (0.05)  (0.88) (2.43)Loss from discontinued operations(0.01)(0.01)— — %
Net income (loss)$1.47
  $(7.53) $1.32
  $(11.81) $(29.34)
Net income (loss) attributable to common stockholdersNet income (loss) attributable to common stockholders$1.68 $(0.88)$2.56 291 %
Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS for the Successor Company reflects weighted average diluted common shares outstanding of 103.1161.4 million and 136.2 million for the three months ended September 30, 2017March 31, 2023 and 100.2 million2022, 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 and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the period April 2 through September 30, 2017. Diluted EPSdiscrete items that management excluded in analyzing each of its segment’s operating performance, as displayed in the reconciliations below.
Three Months Ended March 31,
20232022
 (Dollars in millions)
Income (loss) from continuing operations, net of income taxes$284.1 $(119.8)
Depreciation, depletion and amortization76.3 72.9 
Asset retirement obligation expenses15.4 15.0 
Restructuring charges0.1 1.6 
Asset impairment2.0 — 
Changes in amortization of basis difference related to equity affiliates(0.3)(0.6)
Interest expense18.4 39.4 
Net loss on early debt extinguishment6.8 23.5 
Interest income(13.1)(0.5)
Unrealized (gains) losses on derivative contracts related to forecasted sales(118.7)301.0 
Unrealized losses (gains) on foreign currency option contracts2.2 (3.3)
Take-or-pay contract-based intangible recognition(0.6)(0.7)
Income tax provision (benefit)118.0 (1.0)
Total Adjusted EBITDA$390.6 $327.5 
Total Reporting Segment Costs is defined as operating costs and expenses adjusted for the Predecessor periods January 1 through April 1, 2017 anddiscrete items that management excluded in analyzing each of its segments’ operating performance, as displayed in the three and nine months ended September 30, 2016 reflect weighted average diluted common shares outstanding of 18.3 million, respectively.reconciliations below.

Three Months Ended March 31,
20232022
 (Dollars in millions)
Operating costs and expenses$846.6 $699.0 
Unrealized (losses) gains on foreign currency option contracts(2.2)3.3 
Take-or-pay contract-based intangible recognition0.6 0.7 
Net periodic benefit credit, excluding service cost(9.7)(12.2)
Total Reporting Segment Costs$835.3 $690.8 


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The following table presents Total Reporting Segment Costs by reporting segment:
Outlook
Three Months Ended March 31,
20232022
 (Dollars in millions)
Seaborne Thermal Mining$182.5 $160.7 
Seaborne Metallurgical Mining197.6 140.3 
Powder River Basin Mining269.5 243.6 
Other U.S. Thermal Mining185.2 153.1 
Corporate and Other0.5 (6.9)
Total Reporting Segment Costs$835.3 $690.8 
As part of its normal planningRevenue per Ton and forecasting process, Peabody utilizes a bottom-up approachAdjusted EBITDA Margin per Ton are equal to develop macroeconomic assumptions for key variables, including country level gross domestic product, industrial production, fixed asset investmentrevenue by segment and third-party inputs, driving detailed supplyAdjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to Revenue per Ton less Adjusted EBITDA Margin per Ton.
The following tables present tons sold, revenue, Total Reporting Segment Costs and demand projections. This includes demand for coal, electricity generation and steel, while cost curves concentrate on major supply regions/countries that impact the regions in which the Company operates. Our estimates involve risks and uncertainties and are subject to change based on various factors as described more fully in the “Cautionary Notice Regarding Forward-Looking Statements” section contained within this Item 2.Adjusted EBITDA by operating segment:
Our near-term outlook is intended to coincide with the next 12 to 24 months, with subsequent periods addressed in our long-term outlook.
Three Months Ended March 31, 2023
Seaborne Thermal MiningSeaborne Metallurgical MiningPowder River Basin MiningOther U.S. Thermal Mining
(Amounts in millions, except per ton data)
Tons sold3.6 1.3 22.0 4.5 
Revenue$346.5 $288.4 $305.3 $249.4 
Total Reporting Segment Costs182.5 197.6 269.5 185.2 
Adjusted EBITDA$164.0 $90.8 $35.8 $64.2 
Revenue per Ton$96.82 $220.60 $13.89 $54.73 
Costs per Ton51.01 151.13 12.26 40.65 
Adjusted EBITDA Margin per Ton$45.81 $69.47 $1.63 $14.08 
Near-Term Outlook
Three Months Ended March 31, 2022
Seaborne Thermal MiningSeaborne Metallurgical MiningPowder River Basin MiningOther U.S. Thermal Mining
(Amounts in millions, except per ton data)
Tons sold3.8 1.2 20.6 4.2 
Revenue$251.2 $321.3 $251.2 $203.1 
Total Reporting Segment Costs160.7 140.3 243.6 153.1 
Adjusted EBITDA$90.5 $181.0 $7.6 $50.0 
Revenue per Ton$66.86 $258.43 $12.18 $48.46 
Costs per Ton42.77 112.87 11.81 36.54 
Adjusted EBITDA Margin per Ton$24.09 $145.56 $0.37 $11.92 
U.S. Thermal Coal. U.S. domestic electricity generation decreased 2% in the nine months ended September 30, 2017 compared to the prior year as a result of mild weather. Even as overall electricity demand weakened year-over-year through September, utility consumption of Powder River Basin coal rose approximately 8% with natural gas consumption decreasing 12% compared to the prior year period (on 30% higher average natural gas prices year-over-year through September).
Cooling degree days in June, July and August 2017 were down approximately 16% from the prior year in coal-heavy regions. As a result, Peabody now expects U.S. coal consumption from electricity generation to be largely flat for full-year 2017 compared to 2016 levels.
Seaborne Thermal Coal. Seaborne thermal coal demand and pricing continue to be supported by robust Asian demand primarily in China and South Korea. Chinese thermal coal imports are up approximately 15 million tonnes year-to-date through September compared to the prior year period on strong electricity generation that exceeded domestic production growth. In addition, South Korean imports have strengthened approximately 15 million tonnes through September, a 23% increase year-over-year, as nuclear generation has been curtailed. While import demand from India has been sluggish on increased domestic coal usage, stockpiles are currently at multi-year lows, which is supportive of additional imports in the fourth quarter. For full-year 2017, Peabody now projects seaborne thermal coal demand to increase approximately 10 to 15 million tonnes from 2016 levels.
Seaborne Metallurgical Coal. With respect to seaborne metallurgical coal, global steel production has risen approximately 5% during the nine months ended September 30, 2017 as compared to the prior year period, led by record Chinese steel production. In addition, Chinese steel exports are down 30% year-to-date through September. Through the nine months ended September 30, 2017 metallurgical coal imports in China rose 9 million tonnes as compared to the prior year period on strong demand and curtailed domestic production on geologic issues. For full-year 2017, Peabody now expects global seaborne metallurgical coal demand to increase approximately 10 million tonnes from 2016 levels.
Seaborne metallurgical coal prompt prices averaged $189 per tonne in the third quarter of 2017, up over $50 per tonne from the prior year, with the index-based settlement price for hard coking coal set at approximately $170 per tonne. In addition, Peabody set third quarter low-vol PCI pricing at $115 per tonne with an additional settlement later in the quarter of $127.50 per tonne. The Company also negotiated a fourth quarter low-vol PCI settlement of $127.50 per tonne.
Long-Term Outlook
There were no significant changes to our Long-term Outlook subsequent to December 31, 2016. Information regarding our Long-term Outlook is outlined in Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.
Regulatory Update
Other than as described in the following section, there were no significant changes to ourthe Company’s regulatory matters subsequent to December 31, 2016.2022. Information regarding ourthe Company’s regulatory matters is outlined in Part I, Item 1. “Business” in ourits Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.

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Regulatory Matters - U.S.
Grid Resiliency Pricing RuleNational Ambient Air Quality Standards (NAAQS). On October 10, 2017, the Secretary of Energy (the Secretary) published a Notice of Proposed Rulemaking entitled the Grid Resiliency Pricing Rule (the Proposed Rule). The Proposed Rule was issued by the Secretary pursuant to section 403 of the Department of Energy Organization Act. 42 U.S.C. § 7173. In the Proposed Rule, the Secretary instructed the Federal Energy Regulatory Commission (FERC) to impose rules to ensure that reliability and resiliency attributes of certain electric generation units with a 90-day on-site fuel supply are fully compensated for the benefits and services they provide to grid operations. The Secretary directed FERC to take final action on the Proposed Rule within 60 days of publication or, in the alternative, to issue the rule as an interim final rule immediately, with provision for later modifications after consideration of public comments. The Proposed Rule cites the retirements of coal and nuclear plants as a potential threat to grid reliability and resilience, and provides for the creation of a “reliability and resiliency rate” that would compensate certain eligible resources for the benefits and services they provide to grid operations, allowing such eligible resources to recover their fully allocated costs and a fair return on equity. The “reliability and resiliency rate” would be available to eligible resources operating within FERC-approved independent system operators or regional transmission organizations with energy and capacity markets. The rate would apply only to generators that are not currently subject to cost-of-service regulation by a state or other authority.
Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect our U.S. coal mining operations both directly and indirectly and may result in additional capital and operating costs.
Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to national ambient air quality standards (NAAQS) for particulate matter (PM), sulfur dioxide and ozone. It is possible that modifications to current NAAQS could impact our mining operations in a manner that includes, but is not limited to, designating new nonattainment areas or expanding existing nonattainment areas, requiring changes in vehicle/engine emission standards for vehicles/equipment utilized in our operations, or through the adoption of additional local control measures that could be required pursuant to state implementation plans required to address revised NAAQS.
In recent years requires the United States Environmental Protection Agency (EPA) has adopted more stringent NAAQS for PM, nitrogen oxide and sulfur dioxide. In 2015,to review national ambient air quality standards every five years to determine whether revision to current standards are appropriate. As part of this recurring review process, the EPA in 2020 proposed to retain the ozone NAAQS promulgated in 2015, including both the primary (public health) and secondary (public welfare) standards. The EPA subsequently promulgated final standards to this effect. In 2021, fifteen states and other petitioners filed a more stringent NAAQSpetition for ozone (80 Fed. Reg. 65,292, (Oct. 25, 2015)). This NAAQS for ozonereview of the rule was challenged in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit). Although the ruleThe litigation is not stayed during litigation, on April 7, 2017, the Department of Justice, on behalf ofcurrently in abeyance following a motion filed by the EPA filed a motion asking that the case be removed from the argument calendar so that the EPA can consider whether it “should reconsider the rule or some part of it.” On April 14, 2017, the D.C. Circuit granted the EPA’s motion and stayed the litigation indefinitely with regular 90 day status reports due to the court. More stringent ozone standards require that states develop and submit new state implementation plans to the EPA. Depending on the need for further emission reductions necessary to meet the standard, such plans could include additional control technology requirements for mining equipment or result in additional permitting requirements affecting operations and expansion efforts.
In 2009, the EPA also adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. The PM NAAQS was thereafter revised and made more stringent (78 Fed. Reg. 3,085 (Jan. 15, 2013). The D.C. Circuit subsequently upheld the revised PM NAAQS (National Association of Manufacturers v. EPA, Nos. 13-1069, 13-1071 (May 9, 2014)). In addition, since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions. Regulations regarding reporting requirements for underground coal mines were updated in 2016 and now include the ability to cease reporting if mines are abandoned and sealed.
The CAA also indirectly, but significantly affects the U.S. coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other substances emitted by coal-fueled electricity generating plants. Other CAA programs may require further emission reductions and may affect our operations, directly or indirectly. These include, but are not limited to, the Acid Rain Program, interstate transport rules such as the Cross-State Air Pollution Rule, New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and source permitting programs, including requirements related to New Source Review.
NSPS for Fossil Fuel-Fired Electricity Utility Generating Units (EGUs). On April 13, 2012, pursuant to section 111(b) of the CAA, the EPA published for comment in the Federal Register a proposed NSPS for emissions of carbon dioxide for new, modified and reconstructed fossil fuel-fired EGUs (proposed NSPS). On January 8, 2014, however, the EPA withdrew the proposed NSPS and issued a new proposed NSPS for the same sources. The EPA then issued a Notice of Data Availability (NODA) and technical support document in support of the proposed NSPS on February 26, 2014. After extensions, the public comment period for the re-proposed NSPS and the NODA closed on May 9, 2014. The EPA released the final rule on August 3, 2015, and the rule was published in the Federal Register on October 23, 2015 (80 Fed. Reg. 64,510).


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The final NSPS requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb. carbon dioxide per megawatt-hour gross output (CO2/MWh-gross). The standard is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS). Modified and reconstructed fossil fuel-fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance. Reconstructed units must implement the most efficient generating technology based on the size of the unit (supercritical steam conditions for larger units, to meet a standard of 1,800 lb. CO2/MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb. CO2/MWh-gross).
Sixteen separate petitionsallow for review of the NSPS were filedstandards.
The EPA also proposed in 2020 to retain the particulate matter (PM) NAAQS last revised in 2012. On December 18, 2020, the EPA issued a final rule to retain both the primary annual and 24-hour PM standards for fine particulate matter (PM2.5) and the primary 24-hour standard for coarse particulate matter (PM10) and secondary PM10 standards. This rule has also been challenged in the D.C. Circuit by several states and the challengers included 25 states, utilities, mining companies (including Peabody Energy), labor unions, trade organizations and other groups.environmental organizations. The cases were consolidated undercase is currently in abeyance following a petitionmotion filed by North Dakota. States and other organizations intervened in the litigation on behalf of the Respondent EPA.
Four additional cases were filed seekingEPA to allow for review of the EPA’s denialstandards. On January 6, 2023, the EPA proposed to lower the level of reconsideration petitionsthe annual PM2.5 NAAQS from 12.0 ug/m3 to within the range of 9.0 to 10.0 ug/m3. If enacted as proposed, this rule would require fossil fuel generating units to install additional nitrogen oxide (NOx) reducing technologies ultimately increasing the cost of fossil fuel generated energy or causing potential unit retirements.
Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule. In 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to reduce power plant emissions that were submittedcross state lines and significantly contribute to ozone and/or fine particle pollution in other states. In 2016, the EPA published the final CSAPR Update Rule which imposed additional reductions in NOx beginning in 2017 in 22 states subject to CSAPR. This rule was subsequently remanded back to the EPA. Wisconsin v. EPA, 938 F.3d 303.
In April 2021, the EPA regarding the final rule. This denial was published as a final action in the May 6, 2016 Federal Register (81 Fed. Reg. 27,442). States and other organizations also intervened on behalf of the EPA. Upon petitioners’ request, the D.C. Circuit suspended the briefing schedule in this case and consolidated the challenges to the EPA’s denial of petitions for reconsideration with the previously filed North Dakota case. On August 30, 2016, the Court entered a briefing schedule under which final briefs were due February 6, 2017. Oral arguments were scheduled for April 17, 2017.
On March 28, 2017, however, the EPA moved to hold the case in abeyance pending its reconsideration of the NSPS pursuant to the terms of President Trump’s Executive Order on Promoting Energy Independence and Economic Growth (EI Order), which was signed the same day. On April 28, 2017, the court granted the motion to hold the case in abeyance for 60 days and required the EPA to file regular status reports. The court also ordered that parties file supplemental briefs on whether the cases should be remanded to the EPA, rather than held in abeyance. The EPA filed a supplemental brief on May 15, 2017 and, at the present time, the case remains in abeyance and the NSPS remains in effect.
Rules for Regulating Carbon Dioxide Emissions From Existing Fossil Fuel-Fired EGUs. On June 2, 2014, the EPA issued and later formally published for comment proposed rules for regulating carbon dioxide emissions from existing fossil fuel-fired EGUs under section 111(d) of the CAA. On August 3, 2015, the EPA announced the final rule, and published the rule in the Federal Register to address the D.C. Circuit remand. This rule imposed further reductions of NOx emissions in 12 states that were subject to the original 2016 rule, which was based on October 23, 2015. the 2008 ozone NAAQS.
In the finalsame rule, the EPA establisheddetermined that 9 states did not significantly contribute to downwind nonattainment and/or maintenance issues and therefore did not require additional emission guidelines for statesreductions. The EPA subsequently issued Federal Implementation Plans to followlower state ozone season NOx budgets in developing plans2021 to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs. These guidelines require that the states individually or collectively create systems that would reduce carbon emissions from steam electric and natural gas-fired power plants located within their borders. Individual states were required to submit their proposed implementation plans to the EPA by September 6, 2016, unless an extension was approved, in which case the states would have until September 6, 2018 to submit those plans. The rule also set emission performance rates for affected sources to be phased in over the period from 2022 through 2030. State plans were required to impose these rates on existing plants or implement other measures (such as emission caps, increased use of renewable energy or energy efficiency measures) that would yield the same result. Overall, the rule was intended to reduce carbon dioxide emissions from steam electric and natural gas-fired power plants by 28% in 2025 and 32% in 2030 compared with 2005 baseline emission rates.  
Legal challenges to the rule began when it was still being proposed. One action by an industry petitioner, joined by intervenors, including us, and another by a coalition of states led by West Virginia, asserted that the EPA does not have the authority to issue the regulations of existing power plants under section 111(d) of the CAA. The D.C. Circuit heard oral arguments on the challenges in April 2015. The petitions to enjoin the proposed rulemaking were denied as premature in June 2015.  However, the D.C. Circuit acknowledged that a legal challenge could be filed after the EPA issued a final rule.  In September 2015 the D.C. Circuit refused to stay the rule, holding that it could not review the rule until it was published2024 in the Federal Register which occurred on October 23, 2015. 
Following Federal Register publication of the rule on October 23, 2015, 39 separate petitionsaffected states. A petition for review by approximately 157 entities werechallenging the 2021 rule was filed in the D.C. Circuit challenging the final rule. The petitions reflected challenges by 27 states and governmental entities, as well as challenges by utilities, industry groups, trade associations, coal companies, and other entities. The lawsuits were consolidated with the case filed by West Virginia and Texas (which other States joined).  On October 29, 2015, we filed a motion to intervene in the case filed by West Virginia and Texas, in support of the petitioning States.  The motion was granted on January 11, 2016. Numerous states and cities were also allowed to intervene in support of the EPA.


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On January 21, 2016, the D.C. Circuit denied the state and industry petitioners’ motions to stay the implementation of the rule but provided for an expedited schedule for review of the rule, with oral arguments beginning on June 2, 2016. The state and industry petitioners appealed and filed application for stay with the United States Supreme Court on January 27, 2016. On February 9, 2016, the Supreme Court overruled the lower court and granted the motion to stay implementation of the rule until its legal challenges are resolved. The stay provides that, if a writ of certiorariCircuit. Briefing is sought and the Supreme Court denies the petition, the stay will terminate automatically. The stay also provides that, if the Supreme Court grants the petition for a writ of certiorari, the stay will terminate when the Supreme Court enters its judgment. Briefing on the merits of the petitions for review in the D.C. Circuit has concluded. Oral arguments in the case were heard en banc by ten active D.C. Circuit judges on September 27, 2016 but, to date, the D.C. Court has not yet issued an opinion.
On March 28, 2017, the EPA moved to hold the case in abeyance pending its reconsideration of the final rule pursuant to the EI Order. On April 4, 2017 the EPA published a Federal Register notice announcing that the Agency would review the rule and that it may act to suspend, revise or rescind the rule (82 Fed. Reg. 16,329).
The EI Order included a directive to reexamine the CAA 111(d) rule and, if appropriate, suspend, revise or rescind the rule. On April 28, 2017, the court granted the motion to hold the case in abeyance for 60 days and required the EPA to file regular status reports; the court also ordered that parties file supplemental briefs on whether the cases should be remanded to the EPA, rather than held in abeyance. The EPA filed a supplemental brief on May 15, 2017 and, at the present time, the case remains in abeyance. On October 10, 2017, the EPA reported to the D.C. Circuit Court of Appeals that it signed a Federal Register notice proposing to repeal the Clean Power Plan. The EPA further reported that it is considering the scope of any potential replacement rule.
Federal Coal Leasing Moratorium. The EI Order also lifted the Department of Interior’s federal coal leasing moratorium and rescinded guidance on the inclusion of social cost of carbon in federal rulemaking. Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium.
Stream Protection Rule. On December 20, 2016, the Office of Surface Mining Reclamation and Enforcement (OSM) issued its final Stream Protection Rule (SPR). The final rule would have impacted both surface and underground mining operations and would have increased testing and monitoring requirements related to the quality or quantity of surface water and groundwater or the biological condition of streams. The SPR would have also required the collection of increased pre-mining data about the site of the proposed mining operation and adjacent areas to establish a baseline for evaluation of the impacts of mining and the effectiveness of reclamation associated with returning streams to pre-mining conditions. Both chambers of Congress passed legislation to repeal and invalidate the rulemaking, pursuant to the Congressional Review Act. The House passed H.J. Res. 38 on February 1, 2017 and the Senate passed the bill the next day. On February 16, 2017, President Trump signed H.J. Res. 38, resulting in the repeal of the SPR and preventing the OSM from promulgating any substantially similar rule. As a result of this repeal, longstanding regulations implementing requirements under the Surface Mining Control and Reclamation Act will continue to govern operations.
Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.
The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain Corps permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.
States are empowered to develop and apply “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the CWA section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.


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A final rule defining the scope of waters protected under the Clean Water Act (commonly called the Waters of the United States (WOTUS Rule), was published by the EPA and the Corps in June 2015. Numerous lawsuits were filed in district courts and courts of appeals nationwide, and all courts of appeals challenges were consolidated in the U.S. Court of Appeals for the Sixth Circuit. District courts in Oklahoma and Georgia dismissed challenges for lack of jurisdiction, but a preliminary injunction was issued by the U.S. District Court in North Dakota in August 2015. On October 9, 2015, the Sixth Circuit stayed the WOTUS Rule nationwide pending further action of the court. On February 22, 2016, a three member panel of the Sixth Circuit held that the Sixth Circuit has exclusive jurisdiction to review challenges to the rule. A request for an en banc hearing was denied. The Tenth and Eleventh Circuits, which are presiding over appeals of the dismissals from Oklahoma and Georgia (respectively), have since stayed proceedings in those appeals. On October 7, 2016, several industry trade organizations and associations filed a petition requesting that the U.S. Supreme Court review the decision of the Sixth Circuit to exercise exclusive jurisdiction over challenges to the rule. The petition was granted on January 13, 2017. On February 28, 2017 the Trump Administration released an executive order directing the EPA and the Corps to consider rescinding or revising the WOTUS Rule, and the EPA and the Corps issued a similar notice that same day. The Department of Justice has notified the courts of this development and has requested that both the Supreme Court and the Sixth Circuit stay all litigation proceedings. The Supreme Court denied that stay request and merits briefing is complete,completed and oral arguments were held on October 11, 2017. The Sixth Circuit, however, grantedSeptember 28, 2022, but this does not stay the stay request and litigation in that Court is being held in abeyance pending the Supreme Court’s decision. Importantly, the Sixth Circuit’s order holding the case in abeyance did not lift the current nationwide stay against implementationeffectiveness of the WOTUS Rule, and therefore the stay will remain effective during the Supreme Court’s review, which is expected to take until late 2017 or early 2018. If CWA authority is eventually expanded, it may impact our operations in some areas by way of additional requirements. rule.
On July 27, 2017,March 15, 2023, the EPA and the Corps published their proposed rule to rescind the 2015 WOTUS Rule and re-codify the prior definition of “waters of the U.S.” The agencies took public comment on that proposal through September 27, 2017 and could issueAdministrator signed a final rule to address regional ozone transport for the 2015 ozone NAAQS by imposing new federal ozone season emission budgets for NOxin late 201723 states, including California, Nevada, Oklahoma and Texas, as well as some areas in Indian country. The rule includes emission limits for NOx for fossil fuel-fired power plants and a “backstop daily emissions rate” for large coal-fired power plants if they exceed specified limits. The rule also sets first-time limits on certain industrial sources that will apply starting with the 2026 ozone season in 20 states. The EPA estimates that annual compliance costs (for 2023 through 2042) will be $770 million to $910 million, depending on the discount rate applied. These emission limitations would apply in addition to requirements contained in State Implementation Plans to control ozone precursors in affected states, although states have the option to replace these limits with equally strict or early 2018.more stringent limitations. When implemented, this rule could influence the closure of some coal generating units that haven’t installed selective catalytic reduction technologies.
Mercury and Air Toxic Standards (MATS). The EPA published the final MATS rule in the Federal Register on February 16,in 2012. The MATS rule revised the NSPSNew Source Performance Standards for nitrogen oxides,NOx, sulfur dioxidesdioxide and PM for new and modified coal-fueled electricity generating plants, and imposed MACTmaximum achievable control technology (MACT) emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. The rule provided three years for compliance with MACT standards and a possible fourth year if a state permitting agency determined that such was necessary for the installation

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Following issuance of the final rule, numerous petitions for review were filed. The D.C. Circuit upheld the NSPS portion of the rulemaking in a unanimous decision on March 11, 2014, and upheld the limits on HAPs against all challenges on April 15, 2014 in a two-to-one decision. Industry groups and a number of states filed and were granted review of the D.C. Circuit decision in the U.S. Supreme Court. On June 29, 2015, the U.S. Supreme Court held that the EPA interpreted the CAA unreasonably when it deemed cost irrelevant to the decision to regulate HAPs from power plants. The court reversed the D.C. Circuit and remanded the case for further proceedings. On December 1, 2015, in response to the court’s decision, the EPA published in the Federal Register a proposed supplemental finding that consideration of costs does not alter the EPA’s previous determination regarding the control of HAPs in the MATS rule. On December 15, 2015, the D.C. Circuit issued an order providing that the rule will remain in effect while the EPA responds to the U.S. Supreme Court decision.
On April 14, 2016,In 2020, the EPA issued a final supplementalrule reversing a prior finding and determined that largely tracked its proposed finding. Several states, companiesit is not “appropriate and industry groupsnecessary” under the CAA to regulate HAP emissions from coal- and oil-fired power plants. This rule also finalized residual risk and technology review standards for the coal- and oil-fired electricity utility generating units source category. Both actions were challenged that supplemental finding in the D.C. Circuit in separate petitions for review, which were subsequently consolidated. Several states and environmental groups also filed as intervenors for the respondent EPA. Briefing commenced in December 2016 and has now concluded. On April 27, 2017, the D.C. Circuit issued an order which removed the previously scheduled oral argument from the court’s calendar and held the consolidated cases challenging the supplemental findingbut this litigation was placed in abeyance. The order further directedOn February 9, 2022 the EPA proposed a rule to file status reportsrevoke the 2020 finding and to reaffirm the agency’s 2016 finding that it remained “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired power plants under Section 112 of the CAA. In the same proposal, the EPA solicited comments on the performance and cost of new or improved technologies to control HAPs from these power plants as part of the agency’s review of related residual risk and technology review standards. The EPA finalized the supplemental2022 proposed rule on March 6, 2023, revoking the 2020 finding every 90 days. The EPA’s most recent status report indicatesand concluding that it is appropriate and necessary to regulate coal- and oil-fired electric steam generating units under CAA Section 112. If enacted, this rule could influence closure of additional coal generating units.
Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. On September 30, 2015, the EPA published a final rule setting new or additional requirements for various wastewater discharges from steam electric power plants. The rule set zero discharge requirements for some waste streams, as well as new, more stringent limits for arsenic, mercury, selenium and nitrogen applicable to certain other waste streams. On October 13, 2020, the EPA issued a final rule revising the technology-based effluent limitations guidelines and standards for the steam electric power generating point source category applicable to flue gas desulfurization wastewater and bottom ash transport water. However, on March 8, 2023, the EPA released the pre-publication versions of two actions to further revise certain discharge limits applicable to steam electric power plants. The first action is continuinga proposed rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate. If the proposed rule is finalized in substantially the same form, the revised effluent limitations guidelines would significantly increase costs for many coal-fired steam electric power plants. The second action is a direct final rule that extends the deadline for steam electric power plants to reviewopt in to the Supplemental Finding “to determine whether2028 early retirement provision that was part of the 2020 rule. The direct final rule should be maintained, modifiedcould influence fuel switching or otherwise reconsidered” (D.C. Cir. No. 16-1127; July 26, 2017).additional coal generating unit retirements by the end of 2028.
Regulatory Matters - Australia
Occupational Health and Safety. State legislation requires us to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision. In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry. There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation.


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A small number of coal mine workers in Queensland and New South Wales have been diagnosedCoal Directions. The State of New South Wales (NSW) enacted the Energy and Utilities Administration Amendment Act 2022 granting the State Premier and Minister for Energy the ability to issue directions in the event of a coal market price emergency (among other powers). On December 22, 2022, the State Premier declared a coal market price emergency on the basis that the declaration was necessary to reduce the risk that increases in coal prices could contribute to an increase in electricity prices. On December 23, 2022, directions were issued to Peabody Energy Australia Pty Ltd and a number of other coal producers with operations in NSW. Those directions were amended on January 31, 2023 and February 16, 2023. The most recent directions require Peabody Energy Australia Pty Ltd to reserve a portion of coal workers’ pneumoconiosis (CWP, also known as black lung) following decadesproduced by Wambo Coal Pty Ltd and by Wilpinjong Coal Pty Ltd for sale to NSW power generators at a capped price until June 30, 2024 and impose additional reporting obligations to demonstrate compliance with the directions. While these directions are currently not anticipated to significantly impact the Wambo Mines or the Wilpinjong Mine, the nature and extent of assumed eradication of the disease. This has led the Queensland government to sponsor a review of the system for screening coal mine workers for the disease with a view to improving early detection. The Queensland government has instituted increasedthose obligations and associated reporting requirements may continue to evolve if further directions are issued.
National Greenhouse and Energy Reporting Act 2007 (NGER Act). The NGER Act imposes requirements for dust monitoring results, broader coal mine worker health assessment requirementscorporations meeting a certain threshold to register and voluntary retirement examinations for coal mine workers to be arranged by the relevant employerreport greenhouse gas emissions and further reform may follow. Peabody has undertaken a review of its practicesabatement actions, as well as energy production and offered its Queensland workers the opportunity for additional CWP screening.
The Queensland government held a Parliamentary inquiry into the re-emergence of CWP in the State which included public hearings with appearances by representatives of the coal mining industry, including Peabody, coal mine workers, the Department of Natural Resources and others. The Queensland Parliamentary Committee conducting the inquiry issued an interim report on March 22, 2017 and its final report on May 29, 2017. In finding that it is highly unlikely CWP was ever eradicated in Queensland, the Committee has made 68 recommendations to ensure the safety and health of mine workers. These include an immediate reduction to the occupational exposure limit for respirable coal dust equivalent to 1.5mg/m3 for coal dust and 0.05mg/m3 for silica and the establishmentconsumption as part of a new and independent Mine Safety Authority to be funded by a dedicated proportion of coal and mineral royalties and overseeingsingle, national reporting system. The Clean Energy Regulator administers 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.NGER Act. The draft bill has been referred to the relevant Parliamentary Portfolio Committee for review.
On September 7, 2017, the Queensland Parliament introduced proposed amendments to legislation which, if passed, will increase civil penalties for mining companies breaching their obligations under the Coal Mining Safety and Health Act 1999. The proposed amendments would also give the Chief Executive of the Department of Natural Resources and Mining new powers to suspend or cancel an individual’s statutory certificate of competency and issue site senior executives (SSEs) notices if they fail to meet their safety and health obligations. Higher levels of competency for the statutory position of ventilation officer at underground mines will also be required if the legislation is passed.
Queensland Reclamation. The Environmental Protection Act 1994 (EP Act) is administered by thefederal Department of Environment and Heritage Protection, which authorizes environmentally relevant activitiesEnergy is responsible for NGER Act-related policy developments and review.
On July 1, 2016, amendments to the NGER Act implemented the Emissions Reduction Fund Safeguard Mechanism. From that date, large designated facilities such as mining activities relatingcoal mines were issued with a baseline for their covered emissions and must take steps to a mining lease through an Environmental Authority (EA). Environmental protectionkeep their emissions at or below the baseline or face penalties.
The National Greenhouse and reclamation activities are regulated by conditions in the EA, including the requirement for the submissionEnergy Reporting (Safeguard Mechanism) Rule 2015 outlines key elements of a Plan of Operations (PO) priorresponsible emitter’s duty to avoid an excess emissions situation and provides detail on how it can meet that requirement. The rule was amended between 2019 and 2021 to transition responsible emitters to new baseline setting arrangements. From the commencement of operations. All mining operations must be carried out in accordance with the PO which describes site activities and the progress toward environmental and rehabilitation outcomes, and which are updated on a regular basis or if mine plans change. The mines submit an annual return reporting on their EA compliance, including reclamation performance.
As a conditionstart of the EA, bonding requirements are calculated2020-21 compliance year, baselines must use prescribed production variables (an example being run of mine coal) and default emissions intensity values (being values set by the government to determinerepresent the amountindustry average emissions intensity of bonding required to cover the cost of reclamation based on the extent of disturbance during the PO period.
In May 2017, the Queensland government announced broad policy reform proposals in relation to financial assurance (FA) and rehabilitation for the mining and petroleum sector. The proposed regime representsproduction over five years) unless specific exemptions apply (such as a new approach to managing Queensland’s existing rehabilitation risk management.  

facility having site-specific values set).


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On October 25, 2017, the Queensland Parliament introduced the Mineral and Energy Resources (Financial Provisioning) Bill 2017 (MERFP Bill), which contained proposed legislation to give effect to some of the policy reforms, including:
a remodeled FA framework that takes into account the financial strength of the EA holder and the risk level of the mine;
•a state-wide pooled FA fund covering most mines and most of the total industry liability;
•discontinuation of prior discounting of FA requirements;
other options for providing FA for those mines that are not part of the pooled FA fund (for example, allowing insurance bonds or cash);
•updated rehabilitation calculations; and
•regular monitoring and reporting measures for progressive mine rehabilitation.
However, the MERFP Bill lapsed on October 29, 2017 when a Queensland state election was called. The nature of the FA and rehabilitation policy reforms, and the timing for the reintroduction into Parliament of the MERFP Bill or other proposed legislation for implementing those reforms, is dependent on the outcome of the election.
Federal Reclamation. In February 2017,January 10, 2023, the Australian Senate establishedfederal government released its Safeguard Mechanism Reforms Position Paper setting out the proposed changes to the emissions reduction regime. The reforms will commence on July 1, 2023 utilizing site specific baseline emissions as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030. Proponents will earn tradeable credits (Safeguard Mechanism Credits) when emissions are below their baselines or can purchase credits to offset emissions. Access to existing Australian Carbon Credit Units will continue unchanged albeit with a Committeeprice ceiling of Inquiry into$75 Australian dollars per tonne of carbon dioxide (CO2) in 2023-24, increasing with the rehabilitationConsumer Price Index plus 2% each year. On March 27, 2023, the Australian Federal Government announced a number of miningadditional measures in the Safeguard Mechanism (Crediting) Amendments Bill 2023 which was introduced and resources projects as it relatespassed both Houses of Parliament on March 30, 2023. The legislation introduces a cap on overall net emissions from facilities covered by the scheme through to Commonwealth responsibilities,2030. The legislation also sets a cap of net zero tonnes CO2-e for example,any financial year beginning after June 30, 2049. In addition, if the Minister for Environment and Water grants an approval under the Environment Protection and Biodiversity Conservation Act 1999.1999 (Cth) (EPBC Act) to a new or expanded facility covered by the scheme, the Minister will be required to give an estimate of the facility's Scope 1 emissions to the Minister for Climate Change, the Climate Change Secretary and the Climate Change Authority for assessment against scheme targets. The Committeelegislation is holding public hearingsnow awaiting assent and is currentlyexpected to commence on July 1, 2023. The potential impact of these reforms to Peabody’s Australian operations is under review.
Risks Related to Global Climate Change
Peabody recognizes that climate change is occurring and that human activity, including the use of fossil fuels, contributes to greenhouse gas (GHG) emissions. The Company’s largest contribution to GHG emissions occurs indirectly, through the coal used by its customers in the generation of electricity and the production of steel (Scope 3). To a lesser extent, the Company directly and indirectly contributes to GHG emissions from various aspects of its mining operations, including from the use of electrical power and combustible fuels, as well as from the fugitive methane emissions associated with coal mines and stockpiles (Scopes 1 and 2).
Peabody’s board of directors and management believe that coal is essential to affordable, reliable energy and will continue to play a significant role in the global energy mix for the foreseeable future. Peabody views technology as vital to advancing global climate change solutions, and the Company supports advanced coal technologies to drive continuous improvement toward the ultimate goal of net-zero emissions from coal.
The board of directors has ultimate oversight for climate-related risk and opportunity assessments, and has delegated certain aspects of these assessments to subject matter committees of the board. In addition, the board and its committees are provided regular updates on major risks and changes, including climate-related matters. The senior management team champions the strategic objectives set forth by the board of directors and Peabody’s global workforce turns those objectives into meaningful actions.
Management believes that the Company’s external communications, including environmental regulatory filings and public notices, U.S. Securities and Exchange Commission filings, its annual Environmental, Social and Governance (ESG) Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the Company’s material risks and progress. All such communications are subject to oversight and review protocols established by Peabody’s board of directors and executive leadership team.
The Company faces risks from both the global transition to a net-zero emissions economy and the potential physical impacts of climate change. Such risks may involve financial, policy, legal, technological, reputational and other impacts as the Company meets various mitigation and adaptation requirements.

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The transition to a net-zero emissions economy is driven by many factors, including, but not limited to, legislative and regulatory rulemaking processes, campaigns undertaken by non-governmental organizations to minimize or eliminate the use of coal as a source of electricity generation, and the ESG-related policies of financial institutions and other private companies. The Company has experienced, or may in the future experience, negative effects on its results of operations due to reportthe following specific risks as a result of such factors:
•Reduced utilization or closure of existing coal-fired electricity generating plants;
•Electricity generators switching from coal to alternative fuels, when feasible;
•Increased costs associated with regulatory compliance;
•Unfavorable impact of regulatory compliance on supply and demand fundamentals, such as limitations on financing or construction of new coal-fueled power stations;
•Uncertainty and inconsistency in duringrulemaking processes related to periodic governmental administrative and policy changes;
•Unfavorable costs of capital and access to financial markets and products due to the second quarterpolicies of 2018.financial institutions;
•Disruption to operations or markets due to anti-coal activism and litigation; and
•Reputational damage associated with involvement in GHG emissions.
With respect to the potential or actual physical impacts of climate change, the Company has identified the following specific risks:
•Disruption to water supplies vital to mining operations;
•Disruption to transportation and other supply chain activities;
•Damage to the Company’s, customers’ or suppliers’ plant and equipment, or third-party infrastructure, resulting from weather events or changes in environmental trends and conditions; and
•Electrical grid failures and power outages.
While the Company faces numerous risks associated with the transition to a net-zero emissions economy and the physical impacts of climate change, certain opportunities may also emerge, such as:
•Heightened emphasis among multiple stakeholders to develop high-efficiency, low-emissions (HELE) technologies and carbon capture, use and storage (CCUS) technologies;
•Increased steel demand related to construction and other infrastructure projects related to climate change concerns; and
•The relative expense and reliability of renewable energy sources compared to coal may encourage support for balanced-source energy policies and regulations.
Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to GHG emissions, including emissions of carbon dioxide from coal combustion by power plants. There have been significant developments in federal and state legislation and regulation and international accords regarding climate change. Such developments are described within Part I, Item 1. “Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022.

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The enactment of future laws or the passage of regulations regarding emissions from the use of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on Peabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement. The Company believes HELE and CCUS technologies should be part of the solution to achieve substantial reductions in GHG emissions and should be broadly supported and encouraged, including through eligibility for public funding from national and international sources. In addition, CCUS merits targeted deployment incentives, like those provided to other low-emission sources of energy.
From time to time, the Company’s board of directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on the Company’s operations, financial condition or cash flows. Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company’s results of operations, financial condition or cash flows.
Liquidity and Capital Resources
Overview
OurThe Company’s primary sourcessource of cash areis proceeds from the sale of ourits coal production to customers. We haveThe Company has also generated cash from the sale of non-strategic assets, including coal reserves and surface lands. Ourlands, and, from time to time, borrowings under its credit facilities and the issuance of securities. The Company’s 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 retirementreclamation obligations, collateral and margining requirements, and selling and administrative expenses. Historically, we haveThe Company has also generatedused cash from borrowings under our credit facilitiesfor early debt retirements, dividends, and from timeshare repurchases.
As described below, the Company recently amended its existing agreement with the providers of its surety bond portfolio, which included lifting the previous restrictions on capital returns to time,shareholders. In connection with the issuanceamendment, the Company announced a new shareholder return plan, as discussed in Part II, Item 2. “Unregistered Sales of securities. We believe that our reorganized capital structure subsequent to the Effective Date will allow us to satisfy our working capital requirementsEquity Securities and fund capital expenditures and debt-service obligations with cash generated from operations and cash on hand.
Use of Proceeds.” Any future determinations to return capital to stockholders, such as dividends or share repurchases will be at the discretion of our Board of Directors and will depend on a variety of factors, including the restrictions set forth under our Successor Notes and Successor Credit Agreement, ourits 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. OurThe Company’s ability to early retire debt, declare dividends or repurchase shares in the future will depend on ourits future financial performance, which in turn depends on the successful implementation of ourits 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 ourits industry, many of which are beyond ourthe Company’s control. See also, Debt Reduction and Shareholder Return Initiatives, below.


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Total Indebtedness. Our total indebtedness as of September 30, 2017 and December 31, 2016 consisted of the following:
 SuccessorPredecessor
 September 30, 2017December 31, 2016
 (Dollars in millions)
6.00% Senior Secured Notes due March 2022$500.0
$—
6.375% Senior Secured Notes due March 2025500.0
—
Senior Secured Term Loan due 2022645.0
—
2013 Revolver—
1,558.1
2013 Term Loan Facility due September 2020—
1,162.3
6.00% Senior Notes due November 2018—
1,518.8
6.50% Senior Notes due September 2020—
650.0
6.25% Senior Notes due November 2021—
1,339.6
10.00% Senior Secured Second Lien Notes due March 2022—
979.4
7.875% Senior Notes due November 2026—
247.8
Convertible Junior Subordinated Debentures due December 2066—
386.1
Capital lease and other obligations84.0
20.1
Less: Debt issuance costs(69.9)(70.8)
 1,659.1
7,791.4
Less: Current portion of long-term debt47.1
20.2
Less: Liabilities subject to compromise—
7,771.2
Long-term debt$1,612.0
$—
Refer to Note 1. “Basis of Presentation” and Note 13. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements for further information regarding our indebtedness, including our capital structure subsequent to the Effective Date.
Liquidity
As of September 30, 2017, our available liquidity was $942.7 million which was comprised of cash and cash equivalents and availability under our receivables securitization program described below. As of September 30, 2017, ourMarch 31, 2023, the Company’s cash balances totaled $925.0$892.2 million, including approximately $708.0$563.6 million held by Australian subsidiaries, $301.8 million held by U.S. entities, withsubsidiaries, and the remaining balanceremainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by ourthe Company’s 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 andAustralia. From time to time, the Company may repatriate excess cash from its foreign operations of our Trading and Brokerage segment. We dosubsidiaries to the U.S. During the three months ended March 31, 2023, the Company repatriated approximately $100 million through intercompany dividends. If additional foreign-held cash is repatriated in the future, the Company does not expect restrictions or potential taxes on the repatriation of amounts held by our foreign subsidiaries towill have a material effect on our overall liquidity, financial condition or results of operations.
Subsequent to our emergence from the Chapter 11 Cases our liquidity primarily consists of cash and cash equivalents and the available balances from our accounts receivable securitization program. Our ability to maintain adequate liquidity depends on the successful operation of our business and appropriate management of operating expenses and capital spending. Our anticipated liquidity needs are highly sensitive to changes in each of these and other factors.
The Successor Notes and Successor Credit Agreement
As described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” and Note 13. “Long-term Debt” of the accompanying unaudited condensed consolidated financial statements, on the Effective Date, the proceeds from the 6.00% Senior Secured Notes due March 2022 and the 6.375% Senior Secured Notes due March 2025 (collectively, the Successor Notes) and the Senior Secured Term Loan under the Successor Credit Agreement were used to repay the predecessor first lien obligations. The proceeds from the Successor Notes and the Senior Secured Term Loan, net of debt issuance costs and an original issue discount, as applicable, were $950.5 million and $912.7 million, respectively.

its near-term liquidity.


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We voluntarily prepaid $300.0 million of the original $950.0 million loan principal on the Senior Secured Term Loan in $150.0 million installments on July 31, 2017 and September 11, 2017. On September 18, 2017, we entered into an amendment to the Successor Credit Agreement which lowered the interest rate from LIBOR plus 4.50% per annum with a 1.00% LIBOR floor to LIBOR plus 3.50% per annum with a 1.00% LIBOR floor. The amendment permits us to add an incremental revolving credit facility in addition to our ability to add one or more incremental term loan facilities under the Successor Credit Agreement. The incremental revolving credit facility and/or incremental term loan facilities, which remain unutilized, can be in an aggregate principal amount of up to $300.0 million plus additional amounts so long as the Company maintains compliance with the Total Leverage Ratio, as defined in the agreement.The amendment also made available an additional restricted payment basket that permits additional repurchases, dividends or other distributions with respect to our Common and Preferred Stock in an aggregate amount up to $450.0 million so long as our Fixed Charge Coverage Ratio, as defined in the agreement, would not exceed 2.00:1.00 on a pro forma basis.
Interest payments on the Successor Notes are scheduled to occur each year on March 31 and September 30 until maturity. We may redeem the 6.00% Senior Secured Notes beginning in 2019 and the 6.375% Senior Secured Notes beginning in 2020, in whole or in part, and subject to periodically decreasing redemption premiums, through maturity.
The Senior Secured Term Loan principal is payable in quarterly installments plus accrued interest through December 2021 with the remaining balance due in March 2022. The loan principal is voluntarily prepayable at 101% of the principal amount repaid if voluntarily prepaid prior to March 18, 2018 (subject to certain exceptions, including prepayments made with internally generated cash) and is voluntarily prepayable at any time thereafter without premium or penalty. The Senior Secured Term Loan may require mandatory principal prepayments of 75% of Excess Cash Flow (as defined in the Successor Credit Agreement) for any fiscal year (commencing with the fiscal year ending December 31, 2018). The mandatory principal prepayment requirement changes to (i) 50% of Excess Cash Flow if our Total Leverage Ratio (as defined in the Successor Credit Agreement and calculatedCompany’s available liquidity decreased from $1,317.8 million as of December 31) is less than or equal31, 2022 to 2.00:1.00$907.5 million as of March 31, 2023. Available liquidity was comprised of the following:
March 31, 2023December 31, 2022
(Dollars in millions)
Cash and cash equivalents$892.2 $1,307.3 
Credit facility availability— 3.5 
Accounts receivable securitization program availability15.3 7.0 
Total liquidity$907.5 $1,317.8 
Surety Agreement Amendment and greater than 1.50:1.00, (ii) 25%Collateral Requirements
In April 2023, the Company amended its existing agreement with the providers of Excess Cash Flow if our Total Leverage Ratio is less than or equalits surety bond portfolio, dated November 6, 2020. Under the agreement, the Company was required to 1.50:1.00 and greater than 1.00:1.00, or (iii) zero ifpost collateral on a periodic basis through December 31, 2025. Prior to 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 afterApril 2023 amendment, the endCompany had posted cumulative collateral of each fiscal year. In certain circumstances, the Senior Secured Term Loan also requires that Excess Proceeds (as defined$557.8 million, primarily in the Successor Credit Agreement)form of $10 million or greater from salesletters of our assets be applied against the loan principal, unless such proceeds are reinvested within one year.credit.
Under the Successor Credit Agreement, our annual capital expenditures are limitedApril 2023 amendment, the Company and surety providers agreed to $220.0a maximum aggregate collateral amount of $721.8 million $220.0 million, $250.0 million, $250.0 million, and $300.0 millionbased upon bonding levels at the effective date of the amendment. This maximum collateral amount represents a negotiated increase from 2017 through 2021, respectively, subject to certain adjustments.
In additionthe uncapped cumulative collateral amount prior to the $450.0 million restricted payment basket provided for under the amendment the Successor Credit Agreement and Successor Notes allow for $50 million of otherwise restricted payments. Additive to this general limit are certain “builder basket” provisions that may vary prospectively as future bonding levels increase the amount of allowable restricted payments, as calculated periodically based upon our operating performance. Beginningor decrease. The amendment also removes restrictions on January 1, 2018, the payment of dividends and purchasesshare repurchases, and extends the agreement through December 31, 2026. In order to maintain the new maximum collateral standstill, the Company must remain compliant with a minimum liquidity test and a maximum net leverage ratio, as measured each quarter. The minimum liquidity test requires the Company to maintain liquidity at the greater of our own$400 million or the difference between the penal sum of all surety bonds and the amount of collateral posted in favor of surety providers. The Company must also maintain a maximum net leverage ratio of 1.5 to 1.0, where the numerator consists of its funded debt, net of cash, and the denominator consists of its Adjusted EBITDA for the trailing twelve months. For purposes of calculating the ratio, only 50% of the outstanding principal amount of the Company’s 2028 Convertible Notes is deemed to be funded debt. The Company’s ability to pay dividends and make share repurchases is also subject to the quarterly minimum liquidity test. Such compliance requirements will commence for the second quarter of 2023. The Company granted second liens on $200.0 million of mining equipment under the original agreement, which remain in force under the April 2023 amendment.
To fund the maximum collateral amount, the Company deposited $566.3 million into trust accounts for the benefit of certain surety providers on March 31, 2023. The remainder was comprised of $140.5 million of existing cash-collateralized letters of credit and $15.0 million already held on behalf of a surety provider. The amendment became effective on April 14, 2023, when the Company terminated a credit agreement which, as amended, provided for $237.2 million of capacity for irrevocable standby letters of credit (LC Facility). The $223.8 million of letters of credit that were outstanding under the LC Facility at March 31, 2023 were subsequently cancelled and, in certain cases, replaced by cash-collateralized letters of credit or letters of credit issued under the Company’s accounts receivable securitization program.
Collateralized Letter of Credit Agreement
In February 2022, the Company entered into an agreement which provides up to $250.0 million of capacity for irrevocable standby letters of credit, primarily to support reclamation bonding requirements. The agreement requires the Company to provide cash collateral at a level of 103% of the aggregate amount of letters of credit outstanding under the arrangement (limited to $5.0 million total excess collateralization.) Outstanding letters of credit bear a fixed fee in the amount of 0.75% per annum. The Company receives a variable deposit rate on the amount of cash collateral posted in support of letters of credit. The agreement has an initial expiration date of December 31, 2025. At March 31, 2023, letters of credit of $245.3 million were outstanding under the agreement, which were collateralized by cash of approximately $250 million.
Margin Requirements
From time to time, the Company enters into hedging arrangements, including economic hedging arrangements, to manage various risks, including coal price volatility. Most hedging arrangements require the Company to post margin with its clearing broker based on the value of the related instruments and other credit factors. If the fair value of its exchange-cleared hedge portfolio moves significantly, the Company could be required to post additional margin, which could negatively impact its liquidity.

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At March 31, 2023, the Company was party to coal derivative contracts related to 0.3 million metric tons of production, all of which are expected to settle during the second quarter of 2023.
At March 31, 2023 and December 31, 2022, the Company had margin posted of $59.8 million and $255.5 million, respectively, related to its coal derivative contracts. For additional information regarding the Company’s coal derivative contracts, refer to Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” of this Quarterly Report.
Indebtedness
The Company’s total indebtedness as of March 31, 2023 and December 31, 2022 is presented in the table below.
Debt Instrument (defined below, as applicable)March 31, 2023December 31, 2022
(Dollars in millions)
3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes)$320.0 $320.0 
Finance lease obligations25.0 23.6 
Less: Debt issuance costs(9.4)(9.8)
335.6 333.8 
Less: Current portion of long-term debt13.2 13.2 
Long-term debt$322.4 $320.6 
During 2022, the Company utilized various methods allowable or required under its then-existing debt agreements to retire all of its senior secured long-term debt, leaving only the 3.250% Convertible Senior Notes due 2028 (the 2028 Convertible Notes), which are further described below, and various finance lease obligations outstanding at December 31, 2022.
The Company’s remaining indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at March 31, 2023, of approximately $12 million in 2023, $23 million in 2024, $16 million in 2025, $13 million in 2026, $12 million in 2027 and $322 million thereafter.
Cash payments for interest related to the Company’s indebtedness and financial assurance instruments amounted to $19.1 million and $37.2 million during the three months ended March 31, 2023 and 2022, respectively.
2028 Convertible Notes
On March 1, 2022, through a private offering, the Company issued the 2028 Convertible Notes in the aggregate principal amount of $320.0 million. The 2028 Convertible Notes are senior unsecured obligations of the Company and are governed under an indenture.
The Company used the proceeds of the offering of the 2028 Convertible Notes and available cash to redeem $62.6 million of senior secured notes maturing in 2024 and $257.4 million of senior secured notes maturing in 2025, and to pay related premiums, fees and expenses relating to the offering and redemptions.
The 2028 Convertible Notes will mature on March 1, 2028, unless earlier converted, redeemed or repurchased in accordance with their terms. The 2028 Convertible Notes will bear interest from March 1, 2022 at a rate of 3.250% per year payable semi-annually in arrears on March 1 and September 1 of each year, beginning on September 1, 2022.
During the first quarter of 2023, the Company’s reported common stock are permitted under additional provisionsprices did not prompt the conversion feature of the Successor2028 Convertible Notes. As a result, the 2028 Convertible Notes are not convertible at the option of the holders during the second quarter of 2023.
LC Facility
The now-terminated LC Facility had an original capacity of $324.0 million and was subsequently amended at various dates to reduce its capacity and effect certain other changes, including in February 2023 to reduce capacity by $65.0 million, accelerate the Successor Credit Agreement in an aggregate amount inexpiration date to December 31, 2023 from December 31, 2024, and eliminate the prepayment premium due upon any calendar year notreduction of commitments thereunder prior to exceed $25 million, so long as our Total Leverage Ratio would not exceed 1.25:1.00 on a pro forma basis.July 29, 2023.

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Accounts Receivable Securitization Program
As described in Note 18.11. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, on the Effective Date, weCompany entered into an amended Receivables Purchase Agreement to extend the receivables securitization facility previously in place and expand that facility to include certain receivables from the Company’s Australian operations. The term of the receivablesaccounts receivable securitization program (Securitization Program) ends on April 3, 2020, subjectduring 2017. The securitization program was amended in February 2023 to certain liquidity requirementsincrease the available funding capacity from $175.0 million to $225.0 million and other customary events of default set forth inadjust the Receivables Purchase Agreement. The Securitization Program providesrelevant interest rate for upborrowings to $250 million in funding accounted for as a secured borrowing,overnight financing rate (SOFR). Funding capacity is limited to the availability of eligible receivables and may beis accounted for as a secured by a combination of cash collateral and the trade receivables underlying the program, from time to time.borrowing. Funding capacity under the Securitization Programprogram may also be drawn uponutilized for letters of credit in support of other obligations. On June 30, 2017, we entered into an amendment toobligations, which has been the Securitization Program to includeCompany’s primary utilization. At March 31, 2023, the receivables of additional Australian operations and reduce the associated fees payable.
At September 30, 2017, weCompany had no outstanding borrowings and $179.5$190.7 million of letters of credit drawnoutstanding under the Securitization Program. The letters of creditprogram, which were primarily in support of portions of our obligations forthe Company’s reclamation workers’ compensation and postretirement benefits. Thereobligations. The Company was nonot required to post cash collateral requirement under the Securitization Programsecuritization program at September 30, 2017.March 31, 2023. By April 14, 2023, $101.3 million of letters of credit outstanding under the securitization program were cancelled in connection with the surety agreement amendment and related trust accounts described above.

Covenant Compliance

The Company was compliant with all relevant covenants under its debt and other finance agreements at March 31, 2023. The April 2023 termination of the Company’s credit agreement and related letter of credit facility eliminated the related compliance requirements as of March 31, 2023 and prospectively.
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Reclamation Bonding
As describedThe following table summarizes the Company’s cash flows for the three months ended March 31, 2023 and 2022, as reported in Note 18. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, we are requiredstatements.
Three Months Ended March 31,
20232022
 (Dollars in millions)
Net cash provided by (used in) operating activities$386.3 $(273.7)
Net cash (used in) provided by investing activities(58.5)35.2 
Net cash (used in) provided by financing activities(39.0)132.2 
Net change in cash, cash equivalents and restricted cash288.8 (106.3)
Cash, cash equivalents and restricted cash at beginning of period1,417.6 954.3 
Cash, cash equivalents and restricted cash at end of period$1,706.4 $848.0 
Operating Activities. The increase in net cash provided by operating activities for the three months ended March 31, 2023 compared to provide various forms of financial assurance in support of our mining reclamation obligationsthe same period in the jurisdictionsprior year was driven by lower cash utilization with respect to the margin requirements associated with derivative financial instruments ($547.4 million) and the year-over-year increase in which we operate. Such requirements are typically establishedoperating cash flow from Company’s mining operations ($112.6 million).
Investing Activities. The increase in net cash used in investing activities for the three months ended March 31, 2023 compared to the same period in the prior year was driven by statute or under mining permits. Historically, such assurances have takenlower cash receipts from Middlemount ($47.2 million), higher net contributions to joint ventures and related parties ($25.7 million), and higher capital expenditures and the formpayment of third-party instruments such as surety bonds, bankcapital accruals ($20.6 million).
Financing Activities. The decrease in net cash provided by financing activities for the three months ended March 31, 2023 compared to the same period in the prior year was driven by the cash proceeds from common stock and debt issuances in the prior year ($222.0 million and $545.0 million, respectively), partially offset by lower repayments of long-term debt ($597.2 million) in the current year.
Off-Balance-Sheet Arrangements
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. 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.

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The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk.
 March 31, 2023December 31, 2022
 Reclamation Support
Other Support (1)
TotalReclamation Support
Other Support (1)
Total
 (Dollars in millions)
Surety bonds$1,236.4 $152.1 $1,388.5 $1,250.1 $126.7 $1,376.8 
Letters of credit (2)
22.4 67.0 89.4 437.8 131.8 569.6 
1,258.8 219.1 1,477.9 1,687.9 258.5 1,946.4 
Less: Letters of credit in support of surety
bonds (3)
(22.4)(5.4)(27.8)(431.7)(37.2)(468.9)
Obligations supported, net$1,236.4 $213.7 $1,450.1 $1,256.2 $221.3 $1,477.5 
(1)    Instruments support obligations related to pension and health care plans, workers’ compensation, property and casualty insurance, customer and vendor contracts and certain restoration ancillary to prior mining activities.
(2)    March 31, 2023 balances exclude $223.8 million of letters of credit as well as self-bonding arrangementsoutstanding under the LC Facility and $101.3 million of letters of credit outstanding under the Company’s accounts receivable securitization program that were cancelled by April 14, 2023. The collateral obligations related to such letters of credit were met by the March 31, 2023 funding of collateral trust accounts in the U.S. In connection with our emergence from the Chapter 11 Cases, we shifted away from extensive self-bonding insurety agreement amendment described above. Amounts do not include cash collateralized letters of credit.
(3)    Certain letters of credit serve as collateral for surety bonds at the U.S. in favor of increased usagerequest of surety bonds and similar third-party instruments, but have retainedbond providers.
At March 31, 2023, the ability to utilize self-bonding in the future, dependent upon state-by-state approval and internal cost-benefit considerations. This divergence in practice may impact our liquidity in the future due to increased cash collateral requirements and surety and related fees.
At September 30, 2017, weCompany had total asset retirement obligations of $636.0 million which were backed by a combination of surety bonds, bank guarantees, letters of credit and restricted cash collateral. Cash collateral balances related to reclamation and other obligations are maintained on our balance sheets within “Investments and other assets,” but are excluded from our available liquidity. Such cash collateral amounted to $530.3 million at September 30, 2017, of which $160.1 million was held in the U.S. and $370.2 million in Australia.
$752.5 million. Bonding requirement amounts may differ significantly from the relatedrelated asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas ourthe Company’s accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date.
Capital Requirements
There were no material changes to our capital requirements fromNot presented in the information providedabove table is approximately $936.7 million of restricted cash and other balances serving as collateral which are included in Item 7 of our Annual Report on Form 10-K for the year ended Decemberaccompanying condensed consolidated balance sheets at March 31, 2016,2023, as amended on July 10, 2017 and August 14, 2017.
Contractual Obligations
The consummation of the Plan and related reorganization activities resulted in significant changes to our future contractual obligations with respect to our long-term debt and capital and operating lease obligations which were disclosed in Item 2 of our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017. Our future contractual obligations with respect to our long-term debt have further changed as a result of the principal repayments on our Senior Secured Term Loan and the amendment to our Successor Credit Facility as more fully described in Note 13. “Long-term Debt” to the accompanying unaudited financial statements. Our resulting future long-term debt obligations for periods subsequent to September 30, 2017 are set forth in the table below. The related interest on long-term obligations was calculated using rates in effect at September 30, 2017 for the remaining contractual term11. “Financial Instruments and Other Guarantees” of the outstanding borrowings. There were no other material changes to our contractual obligations from the information previously provided in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017, and Item 2 of our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017.
 Payments Due By Period
 Total Three Months Ending December 31, 2017 2018-2019 2020-2021 2022-2023 Subsequent to 2023
 (Dollars in millions)
Long-term debt obligations (principal and interest)$2,176.4
 $25.1
 $204.5
 $208.3
 $1,198.7
 $539.8



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Debt Reduction and Shareholder Return Initiatives
In the second quarter of 2017, we outlined our debt reduction and shareholder return initiatives. The details of these initiatives are as follows:
Liquidity Targets. Peabody is targeting liquidity of approximately $800 million. This target takes into account variability of pricing and cash flows and the ability to sustain cyclical downdrafts.
Debt Targets. Peabody is targeting gross debt of $1.2 billion to $1.4 billion over time to enhance the sustainability of its capital structure across all cycles.  Peabody is targeting $500 million of debt reduction by December 2018 and made $300 million in voluntary payments of its term loan under the Successor Credit Agreement during the three months ended September 30, 2017.
Return of Capital to Shareholders. Peabody’s board of directors authorized a $500 million share repurchase program. Repurchases may be made from time to time at our discretion. The specific timing, price and size of purchases will depend on the share price, general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time. No expiration date has been set for the repurchase program, and the program may be suspended or discontinued at any time. During the three months ended September 30, 2017, we repurchased approximately 1.5 million shares of our Common Stock for $40.0 million in connection with an underwritten secondary offering and made additional open-market purchases of approximately 1.0 million shares of our Common Stock for $29.2 million. Subsequent to September 30, 2017 and through October 30, 2017, we have purchased an additional 1.3 million shares of our Common Stock for $37.7 million. The purchases were made in compliance with our debt provisions that limit our ability to repurchase shares following the Plan Effective Date.
Dividends. Peabody’s board of directors will regularly evaluate a sustainable dividend program, targeting commencement in the first quarter of 2018. The timing and amount of dividends under such a program will depend on general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time.
Historical Cash Flows
The following table summarizes our cash flows for the period April 2 through September 30, 2017, January 1 through April 1, 2017, and the three and nine months ended September 30, 2016, as reported in the accompanying unaudited condensed consolidated financial statements:
 SuccessorPredecessor
 April 2 through September 30, 2017January 1 through April 1, 2017 Nine Months Ended September 30, 2016
  
 (Dollars in millions)
Net cash provided by (used in) operating activities330.3
214.0
 (276.8)
Net cash (used in) provided by investing activities(34.9)15.1
 (199.7)
Net cash (used in) provided by financing activities(424.1)(47.7) 1,383.0
Net change in cash and cash equivalents(128.7)181.4
 906.5
Cash and cash equivalents at beginning of period1,053.7
872.3
 261.3
Cash and cash equivalents at end of period$925.0
$1,053.7
 $1,167.8
Cash Flow - Successor
Cash provided by operating activitiesstatements. Such collateral is primarily in support of the Successor period April 2, 2017 through September 30, 2017 resulted from improved supply and demand conditions leading to increased cash from our mining operations. In addition, $99.4 million of restricted cash collateral became unrestricted. These factors were partially offset by the greater use of working capital related to coal stockpile increases and the payment of claims and professional fees relatedfinancial instruments noted above, including in relation to the Chapter 11 Cases.
Cash used in investing activities in the Successor period April 2, 2017 through September 30, 2017 resulted from additions to property, plant, equipment and mine development, which was partially offset by repaymentsCompany’s surety bond portfolio, its collateralized letter of loans from related parties.
Cash used in financing activities in the Successor period April 2, 2017 through September 30, 2017 resulted primarily from $300.0 million of repayments on the Senior Secured Term Loan and $69.2 million ofcredit agreement, mandatory repurchases of Common Stock in accordancecredit facility capacity, and amounts held directly with our debt reduction and shareholder return initiatives.


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Cash Flow - Predecessor
Cash provided by operating activities in the Predecessor period January 1, 2017 through April 1, 2017 resulted from year-over-year increase in cash from our operations from improved supply and demand conditions.
Cash used in operating activities during the nine months ended September 30, 2016 resulted from unfavorable supply and demand conditions leading to decreased cash from our mining operations, greater use of working capital, and cash restrictions brought about by increased collateral demands on various obligations.
Cash provided by investing activities in the Predecessor period January 1, 2017 through April 1, 2017 resulted from repayments of loans from related parties and proceeds from disposals of assets driven by the sale of Dominion Terminal Associates, which was offset by payments for additions to property, plant and equipment.
Cash used in investing activities during the nine months ended September 30, 2016 resulted primarily from federal coal lease and other capital expenditures of approximately $305 million, partially offset by proceeds from the disposal of our 5.06% participation interest in the Prairie State Energy Campus, as well as our disposal of interests in undeveloped metallurgical reserve tenements in Queensland’s Bowen Basin, which included the Olive Downs South, Olive Downs South Extended and Willunga tenements.
Cash used in financing activities in the Predecessor period January 1, 2017 through April 1, 2017 resulted from payments of Predecessor deferred financing costs associated with the new Successor debt entered into upon our emergence from the Chapter 11 Cases.
Cash provided by financing activities during the nine months ended September 30, 2016 resulted from proceeds from long-term debt, primarily due to the proceeds received from our Predecessor interim financing facility during the second quarter of 2016 and the net draws on our 2013 Predecessor Revolver during the first quarter of 2016.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to guarantees and financial instruments with off-balance-sheet risk, most ofbeneficiaries which are not reflected in the accompanying unaudited condensed consolidated balance sheets. We could experience a decline in our liquidity as financial assurances associated with reclamation bonding requirements, bank guarantees,supported by surety bonds or other obligations are required to be collateralized by cash or letters of credit.bonds.
Guarantees and Other Financial Instruments with Off-Balance Sheet Risk. See Note 18. “Financial Instruments and Other Guarantees” to our unaudited condensed consolidated financial statements for a discussion of our accounts receivable securitization program and guarantees and other financial instruments with off-balance sheet risk.
Critical Accounting Policies and Estimates
OurThe Company’s discussion and analysis of ourits financial condition, results of operations, liquidity and capital resources is based upon ourits financial statements, which have been prepared in accordance with U.S. GAAP. We areThe Company is also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenuesrevenue and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate ourthe Company evaluates its estimates. We base ourThe Company bases its estimates on historical experience and on various other assumptions that we believeit believes 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.
OurThe Company’s critical accounting policies and estimates are discussed in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in ourits Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017. Our2022. The Company’s critical accounting policies remain unchanged at September 30, 2017, with the exception of the accounting policy elections describedMarch 31, 2023, and there have been no material changes in the following paragraph that we made in connection with fresh start reporting. These elections impact the Successor period presented in the accompanying condensed consolidated financial statements and will impact prospective periods.Company’s critical accounting estimates.
We will classify the amortization associated with our asset retirement obligation assets within “Depreciation, depletion and amortization” in our consolidated statements of operations, rather than within “Asset retirement obligation expenses”, as in Predecessor periods. With respect to our accrued postretirement benefit and pension obligations, we will prospectively record amounts attributable to prior service cost and actuarial valuation changes, as applicable, currently in earnings rather than recording such amounts within accumulated other comprehensive income and amortizing to expense over applicable time periods.


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Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
See Note 2. “Newly AdoptedAlthough there are new accounting pronouncements issued by the Financial Accounting Standards and Accounting Standards Not Yet Implemented” to ourBoard that the Company will adopt, as applicable, the Company does not believe any of these accounting pronouncements will have a material impact on its unaudited condensed consolidated financial statements for a discussionor disclosures.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Coal Pricing Risk
The Company predominantly manages its commodity price risk for its non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements (those with terms longer than one year) to the extent possible, rather than through the use of derivative instruments. As of March 31, 2023, the Company had approximately 109 million tons of U.S. thermal coal priced and committed for 2023. This includes approximately 91 million tons of PRB coal and 18 million tons of other U.S. thermal coal. The Company has the flexibility to increase volumes should demand warrant. Peabody is estimating full year 2023 thermal coal sales volumes from its Seaborne Thermal Mining segment of 14.5 million to 15.5 million tons comprised of thermal export volume of 9.0 million to 10.0 million tons and domestic volume of 5.5 million tons. Peabody is estimating full year 2023 metallurgical coal sales from its Seaborne Metallurgical Mining segment of 7.0 million to 8.0 million tons. Sales commitments in the metallurgical coal market are typically not long-term in nature, and the Company is therefore subject to fluctuations in market pricing. The Company’s sensitivity to market pricing in thermal coal markets is dependent on the duration of contracts.
As of March 31, 2023, the Company held coal derivative contracts related to a portion of its forecasted sales with an aggregate notional volume of 0.3 million tonnes. Such financial contracts may include futures, forwards and options. The notional volume is related predominately to financial derivatives entered to support the profitability of the Wambo Underground Mine as part of a strategy to extend the mine’s life. All such tonnes will settle in 2023. The Newcastle thermal coal index was $178.53 per tonne on March 31, 2023, and the Company had posted $48.8 million of variation margin for the related derivative contracts at such date. A change in the Newcastle forward curve of $100 per tonne would increase or decrease the Company’s variation margin requirement by approximately $26 million and result in comparable unrealized gains or losses.
Foreign Currency Risk
We haveThe Company has historically utilized currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. The accounting for these derivatives is discussed in Note 7.5. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. Subsequent toAs of March 31, 2023, the Effective Date, we entered into a series of currency options and, as of September 30, 2017,Company had currency options outstanding with an aggregate notional amount of approximately $450 million and $675$632.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures duringover the remaindernine-month period ending December 31, 2023. As of 2017March 31, 2023, the Company also had purchased collars with an aggregate notional amount of $350.0 million Australian dollars related to the third and fourth quarters of 2023. Assuming the first half of 2018, respectively. Assuming weCompany had no foreign currency hedging instruments in place, ourits exposure in operating costs and expenses due to a $0.05$0.10 change in the Australian dollar/U.S. dollar exchange rate is approximately $95 to $105$205 million for the next twelve months. Taking into considerationBased upon the Australian dollar/U.S. dollar exchange rate at March 31, 2023, the currency option contracts put into place subsequent tooutstanding at that date would limit the Effective Date, our netCompany’s exposure to unfavorableapproximately $167 million with respect to a $0.10 increase in the exchange rate changesand approximately $184 million with respect to a $0.10 decrease in the exchange rate for the next twelve months is approximately $70 to $80 million.months.
Other Non-Coal Trading Activities — Diesel Fuel Price Risk
Diesel Fuel and Explosives Hedges. We have historically managed price risk of the diesel fuel and explosives used in our mining activities through the use of cost pass-through contracts and from time to time, derivatives, primarily swaps. As of September 30, 2017, we no longer have any diesel fuel derivative instruments in place.
We expectThe Company expects to consume 125100 to 135110 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 ourits annual diesel fuel costs by approximately $31$25 million based on ourits expected usage.
As of March 31, 2023, the Company did not have any diesel fuel derivative instruments in place. The Company partially manages the price risk of diesel fuel through the use of cost pass-through contacts with certain customers.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of ourThe Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) ofare designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the Securities Exchange Act of 1934, as amended) as of September 30, 2017. Based upon that evaluation, oursecurities laws to be disclosed is accumulated and communicated to senior management, including its principal executive and financial officers, on a timely basis. The Company’s Chief Executive Officer and Chief Financial Officer have concluded that ourevaluated its disclosure controls and procedures were not effective(as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of September 30, 2017 because of the material weaknesses in our internal control over financial reporting described below.
All systems of internal control, no matter how well designed, have inherent limitations. Therefore, even those systems deemed to be effective can provide only reasonable assurance with respect to financial statement preparationMarch 31, 2023, and presentation. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim consolidated financial statements will not be prevented or detected on a timely basis.
Evaluation of the Internal Control over Financial Reporting
Management determined that the internal control around the reconciliation of tax basis balance sheets to deferred tax balances was not designed effectively and did not operate at a sufficient level of precision to prevent or detect a material misstatement on a timely basis.  Specifically, an immaterial misstatement related to deferred tax liabilities of a single taxpayer outside of the consolidated Australian tax paying group was identified, which resulted in the understatement of the income tax valuation allowance required to reduce the carrying value of its deferred tax assets. The Company has subsequently revised its financial statements and related disclosures to correct these errors.
This control deficiency created a reasonable possibility that a material misstatement to the annual consolidated financial statements would not be prevented or detected on a timely basis. Accordingly, management concluded that this control deficiency represents a material weakness.


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Management’s Plans for Remediation
Management has been engaged and will continue to advance remedial activities to address the material weakness described above. We believe the risk of a material weakness in subsequent periods will be mitigated by the implementation of an improved general ledger structure and a comprehensive analysis of all deferred tax positions. Additionally we have revised and enhanced the design of existingsuch controls and procedures were effective to properly apply accounting principles in this area, which includes strengthening our income tax controls with improved documentation standards, training and technical oversight.
The material weakness will not be considered fully remediated until the applicable remedial controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. We expectprovide reasonable assurance that the remediation of this material weakness will be completed prior to the end of fiscal year 2017.
Changes in Internal Control Over Financial Reporting
Other than as discussed above,desired control objectives were achieved. Additionally, there have been no changes into the Company’s internal control over financial reporting during the three months ended September 30, 2017most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, ourits internal control over financial reporting.

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PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
We areThe Company is subject to various legal and regulatory proceedings. For a description of ourits significant legal proceedings refer to Note 1. “Basis of Presentation,” Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting,” Note 5. “Discontinued Operations,” and Note 19.12. “Commitments and Contingencies” to the unaudited condensed consolidated financial statements included in Part I, Item 1. “Financial Statements” of this Quarterly Report, which information is incorporated by reference herein.
Item 1A. Risk Factors.
InThe Company operates in a rapidly changing environment that involves a number of risks. The risk factor set forth below updates the third quarter of 2017, there were no significant changes to ourcorresponding risk factors from thosefactor previously disclosed in Part I, Item 1A. “Risk Factors” in ourthe Company’s Annual Report on Form 10-K for the year ended December 31, 20162022 filed with the SEC on February 24, 2023.
Risks inherent to mining could increase the cost of operating the Company’s business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company.
The Company’s mining operations are subject to conditions that can impact the safety of its workforce, delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include:
•elevated gas levels;
•fires and explosions, including from methane gas or coal dust;
•accidental mine water discharges;
•weather, flooding and natural disasters;
•hazardous events such as roof falls and high wall or tailings dam failures;
•seismic activities, ground failures, rock bursts or structural cave-ins or slides;
•key equipment failures;
•supply chain constraints or unavailability of equipment or parts;
•variations in coal seam thickness, coal quality, the amount of rock and soil overlying coal deposits and geologic conditions impacting mine sequencing;
•delays in moving its longwall equipment;
•unexpected maintenance problems; and
•unforeseen delays in implementation of mining technologies that are new to its operations.
In this regard, on March 22, 2017,29, 2023, the Company’s Shoal Creek Mine in Exhibit 99.2Alabama experienced a fire involving void fill material utilized to our Current Reportstabilize the roof structure of the mine. Mining operations were suspended in March 2023 and it is uncertain when or if mining operations will restart. If after exploring all reasonable mine-planning steps focused on Form 8-K filedresuming mining activities at the Shoal Creek Mine the Company determines that it is unable to extract coal from all or a significant portion of the mine, the Company’s 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. The Company maintains insurance policies that provide limited coverage for losses associated with the SEC on April 11, 2017events at the Shoal Creek Mine, as well as some of the other risks referenced above, which 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 its insurance policies in ourconnection with losses associated with these events and risks.
For information regarding other factors that could affect the Company's results of operations, financial condition and liquidity, see the risk factors disclosed in Part I, Item 1A. “Risk Factors” in its Annual Report on Form 10-K/A (Amendment No. 1)10-K for the year ended December 31, 20162022 filed with the SEC on July 10, 2017. The Risk Factors described in such Forms 8-K and 10-K/A restate certain Risk Factors included in our Annual Report on Form 10-K and are incorporated by reference herein.February 24, 2023. In addition to the other information set forth in this Quarterly Report, including the information presented in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” you should carefully consider thosethe risk factors disclosed in the aforementioned filings,filing, which could materially affect the Company’s results of operations, financial condition and liquidity.

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Factors that could affect the Company’s results or an investment in the Company’s securities include, but are not limited to:
•the Company’s profitability depends upon the prices it receives for its coal;
•if a substantial number of the Company’s long-term coal supply agreements, including those with its largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, its revenue and operating profits could suffer if the Company is unable to find alternate buyers willing to purchase its coal on comparable terms to those in its contracts;
•risks inherent to mining could increase the cost of operating the Company’s business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company;
•the Company’s take-or-pay arrangements could unfavorably affect its profitability;
•the Company may not recover its investments in its mining, exploration and other assets, which may require the Company to recognize impairment charges related to those assets;
•the Company’s ability to operate effectively could be impaired if it loses key personnel or fails to attract qualified personnel;
•the Company could be negatively affected if it fails to maintain satisfactory labor relations;
•the Company could be adversely affected if it fails to appropriately provide financial assurances for its obligations;
•the Company’s mining operations are extensively regulated, which imposes significant costs on it, and future regulations and developments could increase those costs or limit its ability to produce coal;
•the Company’s operations may impact the environment or cause exposure to hazardous substances, and its properties may have environmental contamination, which could result in material liabilities to the Company;
•the Company may be unable to obtain, renew or maintain permits necessary for its operations, or the Company may be unable to obtain, renew or maintain such permits without conditions on the manner in which it runs its operations, which would reduce its production, cash flows and profitability;
•concerns about the impacts of coal combustion on global climate are increasingly leading to conditions that have affected and could continue to affect demand for the Company’s products or its securities and its ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators;
•numerous activist groups are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting the Company’s future financial results, liquidity and growth prospects;
•the Company’s trading and hedging activities do not cover certain risks and may expose it to earnings volatility and other risks;
•if the assumptions underlying the Company’s asset retirement obligations for reclamation and mine closures are materially inaccurate, its costs could be significantly greater than anticipated;
•the Company’s future success depends upon its ability to continue acquiring and developing coal reserves and resources that are economically recoverable;
•the Company faces numerous uncertainties in estimating its coal reserves and resources and inaccuracies in its estimates could result in lower than expected revenue, higher than expected costs and decreased profitability;
•joint ventures, partnerships or non-managed operations may not be successful and may not comply with the Company’s operating standards;
•the Company’s expenditures for postretirement benefit obligations could be materially higher than it has predicted if its underlying assumptions prove to be incorrect;
•inflation could result in higher costs and decreased profitability;
•the Company’s business, results of operations, financial condition and prospects could be materially and adversely affected by pandemic or other widespread illnesses and the related effects on public health;
•Peabody is exposed to risks associated with political or international conflicts such as the ongoing conflict between Russia and Ukraine;
•Peabody could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks if it sustains cyber attacks or other security breaches that disrupt its operations or result in the dissemination of proprietary or confidential information about the Company, its customers or other third-parties;
•the Company is subject to various general operating risks which may be fully or partially outside of its control;

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•the terms of the agreements and instruments governing the Company’s debt and surety bonding obligations impose restrictions that may limit its operating and financial flexibility;
•the number and quantity of viable financing and insurance alternatives available to the Company may be significantly impacted by unfavorable lending and investment policies by financial institutions and insurance companies associated with concerns about environmental impacts of coal combustion, and negative views around its efforts with respect to environmental and social matters and related governance considerations could harm the perception of the Company by a significant number of investors or result in the exclusion of its securities from consideration by those investors;
•the price of Peabody’s securities may be volatile;
•Peabody’s 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 stakeholders’ interests;
•the future payment of dividends on Peabody’s stock or future repurchases of its stock is dependent on a number of factors and cannot be assured;
•the Company may not be able to fully utilize its deferred tax assets;
•acquisitions and divestitures are a potentially important part of the Company’s long-term strategy, subject to its investment criteria, and involve a number of risks, any of which could cause the Company not to realize the anticipated benefits;
•Peabody’s 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 the Company’s 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 of this Quarterly Report on Form 10-Q.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Dividends
During the fourth quarter of 2020, the Company entered into a transaction support agreement with its surety bond providers which prohibited the payment of dividends through the earlier of December 31, 2025, or the maturity of the credit agreement unless otherwise agreed to by the parties to the agreement. Additionally, restrictive covenants in the Company’s credit facility also limited the Company’s ability to pay cash dividends. On April 14, 2023, the Company amended the existing transaction support agreement with the surety bond providers to remove the restrictions on shareholder returns, subject to a minimum liquidity threshold, and terminated the credit facility.
The declaration and payment of dividends and the amount of dividends will depend on the Company’s annual Available Free Cash Flow (AFCF). AFCF is defined as quarterly operating cash flow minus investing cash flow; distributions to noncontrolling interests; plus/minus changes to restricted cash and collateral (excluding one-time effects of the recent surety agreement amendment) and other anticipated expenditures. Peabody anticipates a regular quarterly cash dividend of $0.075 per share, but all shareholder returns remain at the Board of Director's discretion.
On April 27, 2023, the Company declared a dividend per share of $0.075 to be paid on May 31, 2023 to shareholders of record as of May 11, 2023.
Share Relinquishments
The Company routinely allows 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 its equity incentive plans. The value of common stock tendered by employees is determined based on the closing price of the Company’s common stock on the dates of the respective relinquishments.
Share Repurchase ProgramsProgram
Similar to the payment of dividends as described above, the same agreement with the Company’s surety bond providers prohibited share repurchases through the earlier of December 31, 2025, or the maturity of the credit agreement unless otherwise agreed to by the parties to the agreement. Additionally, restrictive covenants in its credit facility also limited the Company’s ability to repurchase shares. The April 14, 2023 amendment and termination of the credit facility as described above, allow share repurchases subject to the Company’s annual AFCF.

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On August 1, 2017, wethe Company announced that ourits Board of Directors authorized a share repurchase program to allow repurchases of up to $500 million of the then outstanding shares of ourits common stock and/or preferred stock (Repurchase(2017 Repurchase Program). Repurchases, which was eventually expanded to $1.5 billion during 2018. Through March 31, 2023, the Company had repurchased 41.5 million shares of its common stock under the 2017 Repurchase Program for $1,340.3 million, which included commissions paid of $0.8 million. On April 17, 2023, the Company announced that its Board of Directors authorized a new share repurchase program (2023 Repurchase Program) authorizing repurchases of up to $1.0 billion of its common stock. The 2017 Repurchase Program was superseded and replaced by the 2023 Repurchase Program.
Under the 2023 Repurchase Program, the Company may be madepurchase shares of common stock from time to time at the discretion of management through open market purchases, privately negotiated transactions, block trades, accelerated or other structured share repurchase programs, or other means. The manner, timing, pricing, and amount of any share repurchase transactions will be based on a variety of factors, including market conditions, applicable legal requirements, and alternative opportunities that the Company may have for the use or investment of capital.
Issuances of Equity Securities
In June 2021, the Company announced an at-the-market equity offering program pursuant to which the Company could offer and sell up to 12.5 million shares of its common stock. The at-the-market equity offering program was further expanded to 32.5 million shares during 2021. The shares are offered and sold pursuant to the Company’s discretion.Registration Statement on Form S-3, which was declared effective by the Securities and Exchange Commission on April 23, 2021, as supplemented by prospectus supplements dated June 4, 2021, September 17, 2021, and December 17, 2021 relating to the offer and sale of the shares. Through March 31, 2023, the Company has sold approximately 24.8 million shares for net cash proceeds of $269.8 million. No sales were made under this at-the-market equity offering program during the three months ended March 31, 2023, leaving approximately 7.7 million shares available for sale.
On March 7, 2022, the Company entered into an at-the-market equity offering program pursuant to which the Company could offer and sell shares of its common stock having an aggregate gross sales price of up of $225 million. The specific timing, priceshares are offered and sizesold pursuant to the Company’s Registration Statement on Form S-3, which was declared effective by the Securities and Exchange Commission on April 23, 2021, as supplemented by a prospectus supplement dated March 7, 2022 relating to the offer and sale 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.shares. During the three months ended September 30, 2017, we repurchasedMarch 31, 2022, the Company sold approximately 1.510.1 million shares for net proceeds of our Common Stock for $40.0$222.0 million, in connection with an underwritten secondarythereby concluding this at-the-market equity offering and made additional open-market purchases of approximately 1.0 million shares of our Common Stock for $29.2 million. Subsequent to September 30, 2017 and through October 30, 2017, we have purchased an additional 1.3 million shares of our Common Stock for $37.7 million. The purchases were made in compliance with our debt provisions that limit our ability to repurchase shares following the Plan Effective Date. See “Risk Factors — The potential payment of dividends on our stock or repurchases of our stock is dependent on a number of factors, and future payments and repurchases cannot be assured” in Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on April 11, 2017.


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Share Relinquishments
We routinely allow employees to relinquish common stock to pay estimated taxes upon the vesting of equity awards and upon the issuance of common stock related to our equity incentive plans. The value of common stock tendered by employees is determined based on the closing price of our common stock on the dates of the respective relinquishments.program.
Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended September 30, 2017:March 31, 2023:
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 (2)
(In millions)
January 1 through January 31, 2023138,407 $26.03 — $160.5 
February 1 through February 28, 2023365,946 26.19 — 160.5 
March 1 through March 31, 2023— — — 160.5 
Total504,353 26.15 —  
(1)Shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not part of the publicly announced repurchase programs.
(2)The 2017 Repurchase Program was in effect until the announcement of the 2023 Repurchase Program on April 17, 2023. The maximum dollar value available for repurchase reflects the amount available as of the month-end date for each period shown.

47

Period 
Total
Number of
Shares
Purchased (1)
 
Average
Price per
Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced
Program
 
Maximum Dollar
Value that May
Yet Be Used to
Repurchase Shares
Under the Publicly
Announced Program
(In millions)
July 1 through July 31, 2017 215
 $27.09
 —
 $500.0
August 1 through August 31, 2017 1,476,086
 27.10
 1,476,014
 460.0
September 1 through September 30, 2017 989,306
 29.53
 987,977
 430.8
Total 2,465,607
 $28.08
 2,463,991
  
(1)
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Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not part of the Repurchase Program.
Item 4. Mine Safety Disclosures.
OurPeabody’s “Safety a Way of Lifeand Sustainability Management System” has been designed to set clear and consistent expectations for safety, health and healthenvironmental stewardship across ourthe Company’s business. It aligns withto the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, safety and health risk management and assurance. WePeabody also partnerpartners with other companies and certain governmental agencies to pursue new technologies that have the potential to improve ourits safety performance and provide better safety protection for employees.
WePeabody continually monitor ourmonitors its safety performance and regulatory compliance. InformationThe information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-KSEC regulations is included in Exhibit 95 to this Quarterly Report on Form 10-Q.
Item 6. Exhibits.
See Exhibit Index at page 82 of this report.

on following pages.


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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
2.1
Order Confirming Debtors’ Second Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code on March 17, 2017 (incorporated by referenceAmendment to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed March 20, 2017)
2.2
Debtor’s Second Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code as revised March 15, 2017 (incorporated by reference to Exhibit 2.2 of the Registrant’s Current Report on Form 8-K, filed March 20, 2017)Surety
3.1
Fourth Amended Transaction Support Agreement and Restated Certificate of Incorporation of the Registrant (incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed April 3, 2017)Surety Term Sheet
3.2
Certificate of Designation of Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.2 of the Registrant’s Current Report on Form 8-K filed April 3, 2017)
3.3
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.3 of the Registrant’s Current Report on Form 8-K, filed April 3, 2017)
4.1
Specimen of stock certificate representing the Registrant’s common stock, par value $0.01 per share (incorporated by reference to Exhibit 4.13 of the Registrant’s Registration Statement on Form S-1 filed February 12, 2001)
4.2
Specimen of stock certificate representing the Registrant’s Series A Convertible Preferred Stock, $0.01 par value (incorporated by reference to Exhibit 4.2 of the Registrant’s Registration Statement on Form S-1 filed April 11, 2017)
4.3
Indenture, dated as of February 15, 2017, between the Peabody Securities Finance Corporation (merged with and into the Registrant on April 3, 2017) and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed February 15, 2017)
4.4
Warrant Agreement,, dated as of April 3, 2017, between the Registrant 14, 2023, by and American Stock Transfer & Trust Company, LLC (incorporated by reference to Exhibit 4.1among Peabody Energy Corporation, certain subsidiaries of the Registrant’s Current Report on Form 8-K, filed April 3, 2017)
4.5
First Supplemental Indenture, dated as of April 3, 2017, among the Registrant, Peabody Securities FinanceEnergy Corporation the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.3the providers of the Registrant’s Current Report on Form 8-K, filed April 3, 2017)its surety program
10.1
Sixth Amended and Restated Receivables Purchase Agreement, dated as of April 3, 2017, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K filed April 3, 2017)
10.2
Amendment No. 1 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of the Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of September 18, 2017 (incorporated (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed September 18, 2017)April 17, 2023).
12.1*31.1†
Computation of Ratio of Earnings to Combined Fixed Charges and Preference Security Dividends for the five year period ended December 31, 2016 and the nine-month period ended September 30, 2017
31.1*
Certification of periodic financial report by the Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*31.2†
Certification of periodic financial report by the Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*32.1†
Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Executive Officer.
32.2*32.2†
Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Financial Officer.


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95*95†
Mine Safety Disclosure required by Item 104 of Regulation S-K.
101*101.INSInline XBRL Instance Document - the instance document does not appear in the interactive data file because XBRL tags are embedded within the Inline XBRL document
101.SCHInline XBRL Taxonomy Extension Schema Document
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document
101.LABInline XBRL Taxonomy Extension Label Linkbase Document
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document
104Cover Page Interactive Data File (Form 10-Q for(embedded within the quarterly period ended September, 30, 2017 filed in XBRL)Inline XBRL document). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed”
*†Filed herewith.



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SIGNATURE


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PEABODY ENERGY CORPORATION
Date:November 3, 2017May 4, 2023By:/s/ AMY B. SCHWETZMARK A. SPURBECK
Amy B. SchwetzMark A. Spurbeck
Executive Vice President and Chief Financial Officer

(On behalf of the registrant and as Principal Financial Officer) 











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