Document

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended

June 30, 2019

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



	☐	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

____________________________________________

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



Delaware		13-4004153
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

(314) 342-3400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	BTU	New 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 ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

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

Large accelerated filer ☑ Accelerated filer ☐

Non-accelerated filer ☐ (Do not check if a smaller reporting company) Smaller reporting company ☐

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☑ No ☐

There were 103.6 million shares of the registrant’s common stock (par value of $0.01 per share) outstanding at August 2, 2019.

TABLE OF CONTENTS



	Page
PART I — FINANCIAL INFORMATION
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 Statements of Changes in Stockholders’ Equity	6
Notes to Unaudited Condensed Consolidated Financial Statements	7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	37
Item 3. Quantitative and Qualitative Disclosures About Market Risk	62
Item 4. Controls and Procedures	62
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	63
Item 1A. Risk Factors	63
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	64
Item 4. Mine Safety Disclosures	65
Item 6. Exhibits	65
EXHIBIT INDEX	66
SIGNATURE	67

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(Dollars in millions, except per share data)
Revenues	$	1,149.0		$	1,309.4		$	2,399.6		$	2,772.1
Costs and expenses
Operating costs and expenses (exclusive of items shown separately below)	858.2			946.5			1,806.6			2,003.7
Depreciation, depletion and amortization	165.4			163.9			337.9			333.5
Asset retirement obligation expenses	15.3			13.2			29.1			25.5
Selling and administrative expenses	38.9			44.1			75.6			81.1
Transaction costs related to business combinations and joint ventures	1.6			—			1.6			—
Other operating (income) loss:
Net (gain) loss on disposals	(0.2		)	1.6			(1.7		)	(29.0		)
Provision for North Goonyella equipment loss	—			—			24.7			—
North Goonyella insurance recovery	—			—			(125.0		)	—
Income from equity affiliates	(9.7		)	(25.2		)	(13.2		)	(47.2		)
Operating profit	79.5			165.3			264.0			404.5
Interest expense	36.0			38.3			71.8			74.6
Loss on early debt extinguishment	—			2.0			—			2.0
Interest income	(7.2		)	(7.0		)	(15.5		)	(14.2		)
Net periodic benefit costs, excluding service cost	4.8			4.6			9.7			9.1
Reorganization items, net	—			—			—			(12.8		)
Income from continuing operations before income taxes	45.9			127.4			198.0			345.8
Income tax provision	3.0			7.4			21.8			17.5
Income from continuing operations, net of income taxes	42.9			120.0			176.2			328.3
Loss from discontinued operations, net of income taxes	(3.4		)	(3.6		)	(6.8		)	(4.9		)
Net income	39.5			116.4			169.4			323.4
Less: Series A Convertible Preferred Stock dividends	—			—			—			102.5
Less: Net income attributable to noncontrolling interests	2.4			2.7			8.1			0.6
Net income attributable to common stockholders	$	37.1		$	113.7		$	161.3		$	220.3

Income from continuing operations:
Basic income per share	$	0.38		$	0.94		$	1.56		$	1.78
Diluted income per share	$	0.37		$	0.93		$	1.54		$	1.76
Net income attributable to common stockholders:
Basic income per share	$	0.35		$	0.91		$	1.50		$	1.74
Diluted income per share	$	0.34		$	0.90		$	1.48		$	1.72

See accompanying notes to unaudited condensed consolidated financial statements.

Table of Contents

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(Dollars in millions)
Net income	$	39.5		$	116.4		$	169.4		$	323.4
Postretirement plans and workers’ compensation obligations (net of $0.0 tax provisions in each period)	(2.2		)	—			(4.4		)	—
Foreign currency translation adjustment	(0.5		)	(2.2		)	(0.4		)	(3.0		)
Other comprehensive loss, net of income taxes	(2.7		)	(2.2		)	(4.8		)	(3.0		)
Comprehensive income	36.8			114.2			164.6			320.4
Less: Series A Convertible Preferred Stock dividends	—			—			—			102.5
Less: Net income attributable to noncontrolling interests	2.4			2.7			8.1			0.6
Comprehensive income attributable to common stockholders	$	34.4		$	111.5		$	156.5		$	217.3

See accompanying notes to unaudited condensed consolidated financial statements.

Table of Contents

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



	(Unaudited)
	June 30, 2019			December 31, 2018
	(Amounts in millions, except per share data)
ASSETS
Current assets
Cash and cash equivalents	$	853.0		$	981.9
Accounts receivable, net of allowance for doubtful accounts of $4.3 at June 30, 2019 and $4.4 at December 31, 2018	395.7			450.4
Inventories	322.1			280.2
Other current assets	229.0			243.1
Total current assets	1,799.8			1,955.6
Property, plant, equipment and mine development, net	4,974.8			5,207.0
Operating lease right-of-use assets	93.1			—
Investments and other assets	205.0			212.6
Deferred income taxes	48.5			48.5
Total assets	$	7,121.2		$	7,423.7

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	28.5		$	36.5
Accounts payable and accrued expenses	963.2			1,022.0
Total current liabilities	991.7			1,058.5
Long-term debt, less current portion	1,327.1			1,330.5
Deferred income taxes	9.6			9.7
Asset retirement obligations	698.9			686.4
Accrued postretirement benefit costs	520.9			547.7
Operating lease liabilities, less current portion	58.0			—
Other noncurrent liabilities	289.2			339.3
Total liabilities	3,895.4			3,972.1
Stockholders’ equity
Preferred Stock — $0.01 per share par value; 100.0 shares authorized, no shares issued or outstanding as of June 30, 2019 and December 31, 2018	—			—
Series Common Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of June 30, 2019 and December 31, 2018	—			—
Common Stock — $0.01 per share par value; 450.0 shares authorized, 139.1 shares issued and 106.2 shares outstanding as of June 30, 2019 and 137.7 shares issued and 110.4 shares outstanding as of December 31, 2018	1.4			1.4
Additional paid-in capital	3,333.7			3,304.7
Treasury stock, at cost — 32.9 and 27.3 common shares as of June 30, 2019 and December 31, 2018	(1,193.4		)	(1,025.1		)
Retained earnings	999.1			1,074.5
Accumulated other comprehensive income	35.3			40.1
Peabody Energy Corporation stockholders’ equity	3,176.1			3,395.6
Noncontrolling interests	49.7			56.0
Total stockholders’ equity	3,225.8			3,451.6
Total liabilities and stockholders’ equity	$	7,121.2		$	7,423.7

See accompanying notes to unaudited condensed consolidated financial statements.

Table of Contents

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Six Months Ended June 30,
	2019			2018
	(Dollars in millions)
Cash Flows From Operating Activities
Net income	$	169.4		$	323.4
Loss from discontinued operations, net of income taxes	6.8			4.9
Income from continuing operations, net of income taxes	176.2			328.3
Adjustments to reconcile income from continuing operations, net of income taxes to net cash provided by operating activities:
Depreciation, depletion and amortization	337.9			333.5
Noncash interest expense, net	11.1			8.1
Deferred income taxes	(0.3		)	0.5
Noncash share-based compensation	21.6			16.5
Net gain on disposals	(1.7		)	(29.0		)
Income from equity affiliates	(13.2		)	(47.2		)
Provision for North Goonyella equipment loss	24.7			—
Foreign currency option contracts	2.4			6.4
Noncash reorganization items, net	—			(12.8		)
Changes in current assets and liabilities:
Accounts receivable	20.8			104.4
Inventories	(42.5		)	0.9
Other current assets	(32.0		)	(38.2		)
Accounts payable and accrued expenses	(52.7		)	(40.1		)
Collateral arrangements	—			323.1
Asset retirement obligations	9.3			9.2
Workers’ compensation obligations	0.9			(0.6		)
Postretirement benefit obligations	(31.2		)	(3.1		)
Pension obligations	(17.9		)	(46.6		)
Other, net	(14.8		)	5.9
Net cash provided by continuing operations	398.6			919.2
Net cash used in discontinued operations	(21.6		)	(3.8		)
Net cash provided by operating activities	377.0			915.4
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	(96.8		)	(125.6		)
Changes in accrued expenses related to capital expenditures	0.2			(0.9		)
Federal coal lease expenditures	—			(0.5		)
Insurance proceeds attributable to North Goonyella equipment losses	23.2			—
Proceeds from disposal of assets, net of receivables	15.8			52.6
Amount attributable to acquisition of Shoal Creek Mine	(2.4		)	—
Contributions to joint ventures	(219.6		)	(243.8		)
Distributions from joint ventures	205.5			236.8
Advances to related parties	(4.5		)	(4.6		)
Cash receipts from Middlemount Coal Pty Ltd	14.7			69.8
Other, net	(0.1		)	(1.8		)
Net cash used in investing activities	(64.0		)	(18.0		)

See accompanying notes to unaudited condensed consolidated financial statements.

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PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)



	Six Months Ended June 30,
	2019			2018
	(Dollars in millions)
Cash Flows From Financing Activities
Repayments of long-term debt	(17.5		)	(63.5		)
Payment of debt issuance and other deferred financing costs	(0.8		)	(1.4		)
Common stock repurchases	(156.0		)	(374.5		)
Repurchase of employee common stock relinquished for tax withholding	(12.3		)	(14.5		)
Dividends paid	(229.3		)	(29.3		)
Distributions to noncontrolling interests	(14.4		)	(6.6		)
Other, net	—			0.1
Net cash used in financing activities	(430.3		)	(489.7		)
Net change in cash, cash equivalents and restricted cash	(117.3		)	407.7
Cash, cash equivalents and restricted cash at beginning of period ⁽¹⁾	1,017.4			1,070.2
Cash, cash equivalents and restricted cash at end of period ⁽²⁾	$	900.1		$	1,477.9


⁽¹⁾ The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at beginning of period”:
Cash and cash equivalents	$	981.9
Restricted cash included in “Investments and other assets”	35.5
Cash, cash equivalents and restricted cash at beginning of period	$	1,017.4

⁽²⁾ The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at end of period”:
Cash and cash equivalents	$	853.0
Restricted cash included in “Investments and other assets”	47.1
Cash, cash equivalents and restricted cash at end of period	$	900.1

See accompanying notes to unaudited condensed consolidated financial statements.

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PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(Dollars in millions, except per share data)
Series A Convertible Preferred Stock
Balance, beginning of period	$	—		$	—		$	—		$	576.0
Series A Convertible Preferred Stock conversions	—			—			—			(576.0		)
Balance, end of period	—			—			—			—
Common Stock
Balance, beginning of period	1.4			1.4			1.4			1.0
Series A Convertible Preferred Stock conversions	—			—			—			0.4
Balance, end of period	1.4			1.4			1.4			1.4
Additional paid-in capital
Balance, beginning of period	3,322.3			3,276.9			3,304.7			2,590.3
Dividend equivalent units on dividends declared	1.4			0.4			7.4			0.8
Series A Convertible Preferred Stock conversions	—			—			—			678.1
Share-based compensation for equity-classified awards	10.0			8.4			21.6			16.5
Balance, end of period	3,333.7			3,285.7			3,333.7			3,285.7
Treasury stock
Balance, beginning of period	(1,125.3		)	(351.4		)	(1,025.1		)	(175.9		)
Common stock repurchases	(57.2		)	(199.0		)	(156.0		)	(374.5		)
Repurchase of employee common stock relinquished for tax withholding	(10.9		)	(14.5		)	(12.3		)	(14.5		)
Balance, end of period	(1,193.4		)	(564.9		)	(1,193.4		)	(564.9		)
Retained earnings
Balance, beginning of period	978.3			682.3			1,074.5			613.6
Impact of adoption of Accounting Standards Update 2014-09	—			—			—			(22.5		)
Net income	37.1			113.7			161.3			322.8
Dividends declared ($0.140, $0.115, $2.120, and $0.230 per share, respectively)	(16.3		)	(14.7		)	(236.7		)	(30.1		)
Series A Convertible Preferred Stock conversions	—			—			—			(102.5		)
Balance, end of period	999.1			781.3			999.1			781.3
Accumulated other comprehensive income
Balance, beginning of period	38.0			0.6			40.1			1.4
Postretirement plans and workers' compensation obligations (net of $0.0 tax provisions in each period)	(2.2		)	—			(4.4		)	—
Foreign currency translation adjustment	(0.5		)	(2.2		)	(0.4		)	(3.0		)
Balance, end of period	35.3			(1.6		)	35.3			(1.6		)
Noncontrolling interests
Balance, beginning of period	47.4			40.7			56.0			49.4
Net income	2.4			2.7			8.1			0.6
Distributions to noncontrolling interests	(0.1		)	—			(14.4		)	(6.6		)
Balance, end of period	49.7			43.4			49.7			43.4
Total stockholders’ equity	$	3,225.8		$	3,545.3		$	3,225.8		$	3,545.3

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 a joint venture. In those cases, the Company includes its proportionate share in the assets, liabilities, revenues and expenses of the jointly controlled entities within each applicable line item of the unaudited condensed consolidated financial statements. All intercompany transactions, profits and balances have been eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements and should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. In the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation. Balance sheet information presented herein as of December 31, 2018 has been derived from the Company’s audited consolidated balance sheet at that date. The Company’s results of operations for the three and six months ended June 30, 2019 are not necessarily indicative of the results that may be expected for future quarters or for the year ending December 31, 2019.

The Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, “Reorganizations”, requires that financial statements distinguish transactions and events that are directly associated with a 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 during the bankruptcy proceedings from which the Company emerged on April 3, 2017 were recorded in “Reorganization items, net” in the unaudited condensed consolidated statements of operations. “Reorganization items, net” for the six months ended June 30, 2018 consisted of settlement gains of $12.8 million related to certain unsecured claims.

(2) Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

Newly Adopted Accounting Standards

Leases. In February 2016, the FASB issued Accounting Standards Update (ASU) 2016-02, “Leases (Topic 842),” to increase transparency and comparability among organizations by requiring the recognition of right-of-use (ROU) assets and lease liabilities on the balance sheet for leases with lease terms of more than 12 months. Most prominent among the changes in the standard is the recognition of ROU assets and lease liabilities by lessees for those leases classified as operating leases. The FASB has continued to clarify this guidance through the issuance of additional updates to ASU 2016-02.

On January 1, 2019, the Company adopted ASU 2016-02 using the modified transition approach and elected the package of practical expedients offered under ASU 2016-02, as updated, that allows it to forgo reassessment of lease classification for leases that have already commenced. The Company also elected the practical expedients to adopt ASU 2016-02 without restating comparative prior period financial information, to not recognize ROU assets and lease liabilities for operating leases with shorter than 12 months terms and to include both lease and non-lease components within lease payments. The Company has implemented the systems functionality and internal control processes necessary to comply with the new reporting requirements of ASU 2016-02.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company recognized the cumulative effect of initially applying ASU 2016-02 as an adjustment on January 1, 2019 and comparative information presented herein has not been restated. ASU 2016-02 had a material impact on the Company's consolidated balance sheet but did not have a material impact on its results of operations or its cash flows. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases upon adoption, as set forth in the table below. The Company's accounting for finance leases remained unchanged.



	Adoption of ASU 2016-02 January 1, 2019
	(Dollars in millions)
ASSETS
Operating lease right-of-use assets	$	109.3
Total assets	$	109.3

LIABILITIES
Accounts payable and accrued expenses	$	41.8
Total current liabilities	41.8
Operating lease liabilities, less current portion	67.5
Total liabilities	$	109.3

ASU 2016-02 also requires entities to disclose certain qualitative and quantitative information regarding the amount, timing, and uncertainty of cash flows arising from leases. Such disclosures are included in Note 11. “Leases.”

Leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible rights to explore for those natural resources and rights to use the land in which those natural resources are contained are excluded from the scope of ASU 2016-02. As such, the adoption of ASU 2016-02 did not impact the accounting for the coal reserve leases under which the Company mines a substantial amount of its coal production. Such leases typically require royalties to be paid as the coal is mined and sometimes require minimum annual royalties to be paid regardless of the amount of coal mined during the year.

Leases - Land Easements. In January 2018, the FASB issued ASU 2018-01 to provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under prior leasing guidance. On January 1, 2019, the Company adopted the expedient to evaluate new or modified land easements under Topic 842, and it did not have a material impact on the Company’s results of operations, financial condition, cash flows or financial statement presentation.

Accounting Standards Not Yet Implemented

Financial Instruments - Credit Losses. In June 2016, the FASB issued ASU 2016-13 related to the measurement of credit losses on financial instruments. The pronouncement replaces the incurred loss methodology to record credit losses with a methodology that reflects the expected credit losses for financial assets not accounted for at fair value with gains and losses recognized through net income. The FASB has continued to clarify this guidance through the issuance of additional updates to ASU 2016-13. This standard is effective for fiscal years beginning after December 15, 2019 (January 1, 2020 for the Company) and interim periods therein, with early adoption permitted for fiscal years, and interim periods therein, beginning after December 15, 2018. The Company is in the process of evaluating the updates and expects to adopt ASU 2016-13 along with the related updates as of January 1, 2020 with no material impact to the Company’s results of operations, financial condition, cash flows or financial statement presentation.

Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13, which amended the fair value measurement guidance by removing and modifying certain disclosure requirements, while also adding new disclosure requirements. The amendments on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements and the narrative description of measurement uncertainty should be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. All other amendments should be applied retrospectively to all periods presented upon their effective date. The amendments are effective for all companies for fiscal years, and interim periods within those years, beginning after December 15, 2019. Early adoption is permitted for all amendments. Further, a company may elect to early adopt the removal or modification of disclosures immediately and delay adoption of the new disclosure requirements until the effective date. The Company plans to adopt all disclosure requirements effective January 1, 2020.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Compensation - Retirement Benefits. In August 2018, the FASB issued ASU 2018-14 to add, remove and clarify disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. ASU 2018-14 is effective for fiscal years ending after December 15, 2020 for public companies and early adoption is permitted. The Company plans to adopt the disclosure requirements effective January 1, 2021.

(3) Acquisition of Shoal Creek Mine

On December 3, 2018, the Company completed the acquisition of the Shoal Creek metallurgical coal mine, preparation plant and supporting assets located in Alabama (Shoal Creek Mine) for a purchase price of $387.4 million. In January 2019, the Company agreed to pay an additional $2.4 million to settle a working capital adjustment. The purchase price was funded with available cash on hand and reflected customary purchase price adjustments. The acquisition expands the Company’s seaborne metallurgical mining platform.

The acquisition excluded all liabilities other than reclamation and the Company is not responsible for other liabilities arising out of or relating to the operation of the Shoal Creek Mine prior to the acquisition date, including with respect to employee benefit plans and post-employment benefits. In connection with completing the acquisition, a new collective bargaining agreement was reached with the union-represented workforce that eliminates participation in the multi-employer pension plan and replaces it with a 401(k) retirement plan.

The preliminary purchase accounting allocations were recorded in the accompanying unaudited condensed consolidated financial statements as of, and for the period subsequent to the acquisition date. The following table summarizes the preliminary estimated fair values of assets acquired and liabilities assumed that were recognized at the acquisition and control date as well as provisional fair value adjustments made through June 30, 2019:



	Preliminary Allocations			Adjustments			Updated Allocations
	(Dollars in millions)
Inventories	$	39.7		$	0.4		$	40.1
Property, plant, equipment and mine development	364.7			3.4			368.1
Current liabilities	(4.1		)	—			(4.1		)
Asset retirement obligations	(10.5		)	(3.8		)	(14.3		)
Total purchase price	$	389.8		$	—		$	389.8

Determining the fair value of assets acquired and liabilities assumed required judgment and the utilization of independent valuation experts, and included the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items. Due to the unobservable inputs to the valuation, the fair value would be considered Level 3 in the fair value hierarchy.

The adjustments to the provisional fair values result from additional information obtained about facts in existence at the acquisition and control date. Adjustments to provisional fair values are assumed to have been made as of the acquisition and control date. As a result, "Depreciation, depletion and amortization" would have been higher by $0.2 million and $1.1 million for the fourth quarter of 2018 and first quarter of 2019, respectively, than was previously reported. The accompanying unaudited condensed consolidated statements of operations reflect these adjustments in the three months ended June 30, 2019.

The Company continues to evaluate the mine plan and review coal reserve studies on the Shoal Creek Mine, the outcome of which will determine the fair value allocated to the asset retirement obligation and coal reserve assets. The valuation of the net assets acquired is expected to be finalized once those assessments and third-party valuation appraisals are completed. In connection with the acquisition, the Company recorded a contract based intangible liability of $3.5 million to reflect the fair value of a coal supply agreement. The liability was amortized to income in January 2019 and the related contract was renegotiated on market terms.

The results of Shoal Creek Mine for the three and six months ended June 30, 2019 are included in the unaudited condensed consolidated statement of operations and are reported in the Seaborne Metallurgical Mining segment.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following unaudited pro forma financial information presents the estimated combined results of operations of the Company and Shoal Creek Mine, on a pro forma basis, as though the operations of the Shoal Creek Mine had been combined with the Company’s operations as of January 1, 2018. The unaudited pro forma financial information does not necessarily reflect the results of operations that would have occurred had the operations of the Company and Shoal Creek Mine been combined during those periods or that may be attained in the future.



	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
	(Dollars in millions, except per share data)
Revenues	$	1,390.0	$	2,957.7
Income from continuing operations, net of income taxes	150.7		402.1
Basic earnings per share from continuing operations	$	1.19	$	2.36
Diluted earnings per share from continuing operations	$	1.17	$	2.33

The pro forma income from continuing operations, net of income taxes includes adjustments to operating costs to reflect the additional expense for the estimated impact of the fair value adjustment for coal inventory, a reduction in postretirement benefit costs resulting from the new collective bargaining agreement described above, and the estimated impact on depreciation, depletion and amortization for the fair value adjustment for property, plant and equipment (including coal reserve assets). On a pro forma basis, the acquisition would have had no impact on taxable income due to the Company’s federal net operating losses.

(4) Revenue Recognition

The Company accounts for revenue in accordance with ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606), which the Company adopted on January 1, 2018, using the modified retrospective approach. Refer to Note 1. “Summary of Significant Accounting Policies” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, for the Company’s policies regarding “Revenues” and “Accounts receivable, net.”

Disaggregation of Revenues

Revenue by product type and market is set forth in the following tables. With respect to its seaborne mining segments, the Company classifies as “Export” certain revenue from domestically-delivered coal under contracts in which the price is derived on a basis similar to export contracts.



	Three Months Ended June 30, 2019
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Corporate and Other ⁽¹⁾		Consolidated
	(Dollars in millions)
Thermal coal
Domestic	$	37.7	$	—	$	282.5	$	167.5	$	130.7	$	—	$	618.4
Export	182.2		—		—		—		4.3		—		186.5
Total thermal	219.9		—		282.5		167.5		135.0		—		804.9
Metallurgical coal
Export	—		290.3		—		—		—		—		290.3
Total metallurgical	—		290.3		—		—		—		—		290.3
Other	0.3		0.6		0.1		—		7.1		45.7		53.8
Revenues	$	220.2	$	290.9	$	282.6	$	167.5	$	142.1	$	45.7	$	1,149.0

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended June 30, 2018
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Corporate and Other ⁽¹⁾			Consolidated
	(Dollars in millions)
Thermal coal
Domestic	$	38.5	$	—	$	321.5	$	196.9	$	131.1	$	—		$	688.0
Export	228.7		—		—		0.6		4.3		—			233.6
Total thermal	267.2		—		321.5		197.5		135.4		—			921.6
Metallurgical coal
Export	—		417.2		—		—		—		—			417.2
Total metallurgical	—		417.2		—		—		—		—			417.2
Other	0.2		0.3		—		—		4.2		(34.1		)	(29.4		)
Revenues	$	267.4	$	417.5	$	321.5	$	197.5	$	139.6	$	(34.1	)	$	1,309.4



	Six Months Ended June 30, 2019
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Corporate and Other ⁽¹⁾		Consolidated
	(Dollars in millions)
Thermal coal
Domestic	$	76.1	$	—	$	569.8	$	346.5	$	273.4	$	—	$	1,265.8
Export	394.1		—		—		—		11.3		—		405.4
Total thermal	470.2		—		569.8		346.5		284.7		—		1,671.2
Metallurgical coal
Export	—		614.0		—		—		—		—		614.0
Total metallurgical	—		614.0		—		—		—		—		614.0
Other	1.0		1.4		0.1		0.1		13.1		98.7		114.4
Revenues	$	471.2	$	615.4	$	569.9	$	346.6	$	297.8	$	98.7	$	2,399.6



	Six Months Ended June 30, 2018
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Corporate and Other ⁽¹⁾		Consolidated
	(Dollars in millions)
Thermal coal
Domestic	$	74.6	$	—	$	710.7	$	397.8	$	261.4	$	—	$	1,444.5
Export	393.6		—		—		1.3		12.3		—		407.2
Total thermal	468.2		—		710.7		399.1		273.7		—		1,851.7
Metallurgical coal
Export	—		882.5		—		—		—		—		882.5
Total metallurgical	—		882.5		—		—		—		—		882.5
Other	0.6		1.2		0.1		0.1		9.6		26.3		37.9
Revenues	$	468.8	$	883.7	$	710.8	$	399.2	$	283.3	$	26.3	$	2,772.1

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Revenue by contract duration was as follows:



	Three Months Ended June 30, 2019
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Corporate and Other ⁽¹⁾		Consolidated
	(Dollars in millions)
One year or longer	$	150.6	$	242.7	$	269.7	$	158.2	$	132.6	$	—	$	953.8
Less than one year	69.3		47.6		12.8		9.3		2.4		—		141.4
Other ⁽²⁾	0.3		0.6		0.1		—		7.1		45.7		53.8
Revenues	$	220.2	$	290.9	$	282.6	$	167.5	$	142.1	$	45.7	$	1,149.0



	Three Months Ended June 30, 2018
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Corporate and Other ⁽¹⁾			Consolidated
	(Dollars in millions)
One year or longer	$	173.2	$	255.1	$	310.8	$	194.1	$	126.5	$	—		$	1,059.7
Less than one year	94.0		162.1		10.7		3.4		8.9		—			279.1
Other ⁽²⁾	0.2		0.3		—		—		4.2		(34.1		)	(29.4		)
Revenues	$	267.4	$	417.5	$	321.5	$	197.5	$	139.6	$	(34.1	)	$	1,309.4



	Six Months Ended June 30, 2019
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Corporate and Other ⁽¹⁾		Consolidated
	(Dollars in millions)
One year or longer	$	321.7	$	475.5	$	549.8	$	326.0	$	278.6	$	—	$	1,951.6
Less than one year	148.5		138.5		20.0		20.5		6.1		—		333.6
Other ⁽²⁾	1.0		1.4		0.1		0.1		13.1		98.7		114.4
Revenues	$	471.2	$	615.4	$	569.9	$	346.6	$	297.8	$	98.7	$	2,399.6



	Six Months Ended June 30, 2018
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining		Corporate and Other ⁽¹⁾		Consolidated
	(Dollars in millions)
One year or longer	$	350.5	$	652.6	$	654.2	$	381.7	$	253.8	$	—	$	2,292.8
Less than one year	117.7		229.9		56.5		17.4		19.9		—		441.4
Other ⁽²⁾	0.6		1.2		0.1		0.1		9.6		26.3		37.9
Revenues	$	468.8	$	883.7	$	710.8	$	399.2	$	283.3	$	26.3	$	2,772.1


⁽¹⁾	Corporate and Other revenue includes gains and losses related to mark-to-market adjustments from economic hedge activities intended to hedge future coal sales. Refer to Note 8. “Derivatives and Fair Value Measurements” for additional information regarding the economic hedge activities.


⁽²⁾	Other includes revenues from arrangements such as customer contract-related payments, royalties related to coal lease agreements, sales agency commissions, farm income and property and facility rentals, for which contract duration is not meaningful.

Committed Revenue from Contracts with Customers

The Company expects to recognize revenue subsequent to June 30, 2019 of approximately $5.4 billion related to contracts with customers in which volumes and prices per ton were fixed or reasonably estimable at June 30, 2019. Approximately 45% of such amount is expected to be recognized over the next twelve months and the remainder thereafter. Actual revenue related to such contracts may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events. This estimate of future revenue does not include any revenue related to contracts with variable prices per ton that cannot be reasonably estimated, such as the majority of seaborne metallurgical and seaborne thermal coal contracts where pricing is negotiated or settled quarterly or annually.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accounts Receivable

“Accounts receivable, net” at June 30, 2019 and December 31, 2018 consisted of the following:



	June 30, 2019		December 31, 2018
	(Dollars in millions)
Trade receivables, net	$	345.6	$	345.5
Miscellaneous receivables, net	50.1		104.9
Accounts receivable, net	$	395.7	$	450.4

Trade receivables, net presented above have been shown net of reserves of $0.1 million as of December 31, 2018. There were no reserves as of June 30, 2019. Miscellaneous receivables, net presented above have been shown net of reserves of $4.3 million as of both June 30, 2019 and December 31, 2018. Included in “Operating costs and expenses” in the unaudited condensed consolidated statements of operations was a credit of $0.1 million for the three and six months ended June 30, 2019 and a charge for doubtful trade receivables of $0.2 million for the six months ended June 30, 2018. No charges for doubtful accounts were recognized during the three months ended June 30, 2018.

The Company also records long-term customer receivables related to the reimbursement of certain post-mining costs which are included within “Investments and other assets” in the accompanying condensed consolidated balance sheets. The balance of such receivables was $11.3 million and $11.1 million as of June 30, 2019 and December 31, 2018, respectively. In connection with the adoption of ASC 606, the Company records a portion of the consideration received as “Interest income” in the accompanying unaudited condensed consolidated statements of operations, due to the embedded financing element within the related contract. Interest income related to these arrangements amounted to $2.6 million and $2.1 million during the three months ended June 30, 2019 and 2018, respectively, and $5.3 million and $4.2 million during the six months ended June 30, 2019 and 2018, respectively.

(5) Discontinued Operations

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

Summarized Results of Discontinued Operations

Results from discontinued operations were as follows during the periods presented below:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(Dollars in millions)
Loss from discontinued operations, net of income taxes	$	(3.4	)	$	(3.6	)	$	(6.8	)	$	(4.9	)

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:



	June 30, 2019		December 31, 2018
	(Dollars in millions)
Assets:
Other current assets	$	0.3	$	—
Total assets classified as discontinued operations	$	0.3	$	—

Liabilities:
Accounts payable and accrued expenses	$	54.2	$	54.0
Other noncurrent liabilities	126.5		141.1
Total liabilities classified as discontinued operations	$	180.7	$	195.1

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Patriot-Related Matters

A significant portion of the liabilities in the table above relate to Patriot. In 2012, Patriot filed voluntary petitions for relief under Chapter 11 of Title 11 of the U.S. 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-disputed issues related to Patriot’s bankruptcy. In May 2015, Patriot again filed voluntary petitions for relief under the Bankruptcy Code in the Eastern District of Virginia and subsequently initiated a process to sell some or all of its assets to qualified bidders. On October 9, 2015, Patriot’s bankruptcy court entered an order confirming Patriot’s plan of reorganization, which provided, among other things, for the sale of substantially all of Patriot’s assets to two different buyers.

Black Lung Occupational Disease Liabilities. Patriot had federal and state black lung occupational disease liabilities related to workers employed in periods prior to Patriot’s spin-off from the Company in 2007. Upon spin-off, Patriot indemnified the Company against any claim relating to these liabilities, which amounted to approximately $150 million at that time. The indemnification included any claim made by the U.S. Department of Labor (DOL) against the Company with respect to these obligations as a potentially liable operator under the Federal Coal Mine Health and Safety Act of 1969. The 2013 Agreement included Patriot’s affirmance of indemnities provided in the spin-off agreements, including the indemnity relating to such black lung liabilities; however, Patriot rejected this indemnity in its May 2015 bankruptcy.

By statute, the Company had secondary liability for the black lung liabilities related to Patriot’s workers employed by former subsidiaries of the Company. The Company’s accounting for the black lung liabilities related to Patriot is based on an interpretation of applicable statutes. Management believes that inconsistencies exist among the applicable statutes, regulations promulgated under those statutes and the DOL’s interpretative guidance. The Company has sought clarification from the DOL regarding these inconsistencies and the accounting for these liabilities could be reduced in the future depending on the DOL’s responses. Whether the Company will ultimately be required to fund certain of those obligations in the future as a result of Patriot’s May 2015 bankruptcy remains uncertain. The amount of the liability, which was determined on an actuarial basis based on the best information available to the Company, was $103.3 million and $102.7 million at June 30, 2019 and December 31, 2018, respectively. While the Company has recorded a liability, it intends to review each claim on a case-by-case basis and contest liability estimates as appropriate. The amount of the Company’s recorded liability reflects only Patriot workers employed by former subsidiaries of the Company that are presently retired, disabled or otherwise not actively employed. The Company cannot reliably estimate the potential liabilities for Patriot’s workers employed by former subsidiaries of the Company that are presently active in the workforce because of the potential for such workers to continue to work for another coal operator that is a going concern.

Combined Benefit Fund (Combined Fund). The Combined Fund was created by the Coal Act in 1992 as a multi-employer plan to provide health care benefits to a closed group of retirees who last worked prior to 1976, as well as orphaned beneficiaries of bankrupt companies who were receiving benefits as orphans prior to the passage of the Coal Act. No new retirees will be added to this group, which includes retirees formerly employed by certain Patriot subsidiaries and their predecessors. Former employers are required to contribute to the Combined Fund according to a formula.

Under the terms of the Patriot spin-off, Patriot was primarily liable to the Combined Fund for the approximately $40 million of its subsidiaries’ obligations at that time. Once Patriot ceased meeting its obligations, the Company was held responsible for these costs and, as a result, recorded “Loss from discontinued operations, net of income taxes” charges of $0.1 million during the three months ended June 30, 2019 and 2018, and $0.3 million during the six months ended June 30, 2019 and 2018. The Company made payments into the fund of $0.5 million during the three months ended June 30, 2019 and 2018, and $1.0 million and $1.1 million during the six months ended June 30, 2019 and 2018, respectively, and estimates that the annual cash cost to fund these potential Combined Fund liabilities will range between $1 million and $2 million in the near-term, with those premiums expected to decline over time because the fund is closed to new participants. The liability related to the fund was $15.7 million and $16.4 million at June 30, 2019 and December 31, 2018, respectively.

UMWA 1974 Pension Plan (UMWA Plan) Litigation. On July 16, 2015, a lawsuit was filed by the UMWA Plan, the UMWA 1974 Pension Trust (Trust) and the Trustees of the UMWA Plan and Trust (Trustees) in the United States District Court for the District of Columbia, against PEC, Peabody Holding Company, LLC, a subsidiary of the Company, and Arch Coal, Inc. (Arch). The plaintiffs sought, pursuant to the Employee Retirement Income Security Act of 1974 (ERISA) and the Multiemployer Pension Plan Amendments Act of 1980, a declaratory judgment that the defendants were obligated to arbitrate any opposition to the Trustees’ determination that the defendants had statutory withdrawal liability as a result of the 2015 Patriot bankruptcy. After a legal and arbitration process and with the approval of the U.S. Bankruptcy Court for the Eastern District of Missouri (Bankruptcy Court), on January 25, 2017, the UMWA Plan and the Company agreed to a settlement of the claim which entitled the UMWA Plan to $75 million to be paid by the Company in increments through 2021. The balance of the liability, on a discounted basis, was $23.9 million and $36.7 million at June 30, 2019 and December 31, 2018, respectively.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(6) Inventories

Inventories as of June 30, 2019 and December 31, 2018 consisted of the following:



	June 30, 2019		December 31, 2018
	(Dollars in millions)
Materials and supplies	$	123.8	$	118.1
Raw coal	74.9		53.6
Saleable coal	123.4		108.5
Total	$	322.1	$	280.2

Materials and supplies inventories presented above have been shown net of reserves of $0.8 million and $0.2 million as of June 30, 2019 and December 31, 2018, respectively.

(7) Equity Method Investments

The Company had total equity method investments of $44.0 million and $45.9 million reflected in “Investments and other assets” in the condensed consolidated balance sheets as of June 30, 2019 and December 31, 2018, respectively, related to Middlemount Coal Pty Ltd (Middlemount). Included in “Income from equity affiliates” in the unaudited condensed consolidated statements of operations was $9.7 million and $25.5 million related to Middlemount during the three months ended June 30, 2019 and 2018, respectively and $13.5 million and $47.7 million during the six months ended June 30, 2019 and 2018, respectively. Middlemount’s standalone results include (on a 50% attributable basis):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	(Dollars in millions)
Depreciation, depletion and amortization and asset retirement obligation expenses	$	3.5	$	4.2	$	7.1	$	8.1
Net interest expense	1.8		3.6		4.0		7.2
Income tax provision	4.2		6.4		5.9		11.5

The Company received cash payments from Middlemount of $14.7 million and $69.8 million during the six months ended June 30, 2019 and 2018, respectively.

(8) Derivatives and Fair Value Measurements

Derivatives

Corporate Risk Management Activities

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, or 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 debt. These risk management activities are actively monitored for compliance with the Company’s risk management policies.

As of June 30, 2019, the Company had currency options outstanding with an aggregate notional amount of $1.0 billion Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the remainder of 2019 and over the first three months of 2020. The instruments are quarterly average rate options whereby the Company is entitled to receive payment on the notional amount should the quarterly average Australian dollar-to-U.S. dollar exchange rate exceed amounts ranging from $0.74 to $0.77 over the remainder of 2019 and over the first three months of 2020.

As of June 30, 2019, the Company held coal-related financial contracts related to a portion of its forecasted sales for an aggregate notional volume of 3.2 million tonnes. Such financial contracts include futures, forwards and options. Of the aggregate notional volume, 1.7 million tonnes will settle in 2019 and the remainder will settle in 2020.

The Company had no diesel fuel or interest rate derivatives in place as of June 30, 2019.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Coal Trading Activities

On a limited basis, the Company engages in the direct and brokered trading of coal and freight-related contracts (coal trading). Except those contracts for which the Company has elected to apply a normal purchases and normal sales exception, all derivative coal trading contracts are accounted for at fair value. Coal brokering is conducted both as principal and agent in support of various coal production-related activities that may involve coal produced from the Company’s mines, coal sourcing arrangements with third-party mining companies or offtake agreements with other coal producers. The Company also provides transportation-related services, which involve both financial derivative contracts and physical contracts. Collectively, coal and freight-related hedging activities include both economic hedging and, from time to time, cash flow hedging in support of the Company’s coal trading strategy. Revenues from such transactions 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.

Offsetting and Balance Sheet Presentation

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 event of default or termination. Such netting arrangements reduce the Company’s credit exposure related to these counterparties. For classification purposes, the Company records the net fair value of all the positions with a given counterparty as a net asset or liability in the condensed consolidated balance sheets.

The Company’s coal trading assets and liabilities include financial instruments 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.

The fair value of derivatives reflected in the accompanying condensed consolidated balance sheets are set forth in the table below.



	June 30, 2019						December 31, 2018
	Asset Derivative			Liability Derivative			Asset Derivative			Liability Derivative
	(Dollars in millions)
Foreign currency option contracts	$	1.2		$	—		$	1.2		$	—
Coal contracts related to forecasted sales	34.7			(3.7		)	6.6			(23.1		)
Coal trading contracts	187.2			(168.1		)	59.7			(64.4		)
Total derivatives	223.1			(171.8		)	67.5			(87.5		)
Effect of counterparty netting	(171.8		)	171.8			(64.5		)	64.5
Variation margin (held) posted	(46.1		)	—			—			21.8
Net derivatives and margin as classified in the balance sheets	$	5.2		$	—		$	3.0		$	(1.2	)

The net amount of asset derivatives, net of margin, are included in “Other current assets” and the net amount of liability derivatives, net of margin, are included in “Accounts payable and accrued expenses” in the accompanying condensed consolidated balance sheets.

Effects of Derivatives on Measures of Financial Performance

Currently, the Company does not seek cash flow hedge accounting treatment for its currency- or coal-related derivative financial instruments and thus changes in fair value are reflected in current earnings.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The tables below show the amounts of pre-tax gains and losses related to the Company’s derivatives.



	Three Months Ended June 30, 2019
	Total (loss) gain recognized in income			(Loss) gain realized in income on derivatives			Unrealized (loss) gain recognized in income on derivatives
Financial Instrument	Total (loss) gain recognized in income			(Loss) gain realized in income on derivatives			Unrealized (loss) gain recognized in income on derivatives
	(Dollars in millions)
Foreign currency option contracts	$	(1.4	)	$	(1.1	)	$	(0.3	)
Coal contracts related to forecasted sales	49.4			27.0			22.4
Coal trading contracts	(0.3		)	(6.0		)	5.7
Total	$	47.7		$	19.9		$	27.8



	Three Months Ended June 30, 2018
	Total loss recognized in income			(Loss) gain realized in income on derivatives			Unrealized gain (loss) recognized in income on derivatives
Financial Instrument	Total loss recognized in income			(Loss) gain realized in income on derivatives			Unrealized gain (loss) recognized in income on derivatives
	(Dollars in millions)
Foreign currency option contracts	$	(2.2	)	$	(2.3	)	$	0.1
Coal contracts related to forecasted sales	(36.4		)	11.7			(48.1		)
Coal trading contracts	(1.7		)	1.1			(2.8		)
Total	$	(40.3	)	$	10.5		$	(50.8	)



	Six Months Ended June 30, 2019
	Total (loss) gain recognized in income			(Loss) gain realized in income on derivatives			Unrealized (loss) gain recognized in income on derivatives
Financial Instrument	Total (loss) gain recognized in income			(Loss) gain realized in income on derivatives			Unrealized (loss) gain recognized in income on derivatives
	(Dollars in millions)
Foreign currency option contracts	$	(2.5	)	$	(2.4	)	$	(0.1	)
Coal contracts related to forecasted sales	100.2			38.0			62.2
Coal trading contracts	(1.3		)	(10.8		)	9.5
Total	$	96.4		$	24.8		$	71.6



	Six Months Ended June 30, 2018
	Total (loss) gain recognized in income			(Loss) gain realized in income on derivatives			Unrealized loss recognized in income on derivatives
Financial Instrument	Total (loss) gain recognized in income			(Loss) gain realized in income on derivatives			Unrealized loss recognized in income on derivatives
	(Dollars in millions)
Foreign currency option contracts	$	(6.4	)	$	(4.7	)	$	(1.7	)
Coal contracts related to forecasted sales	23.3			32.8			(9.5		)
Coal trading contracts	(2.7		)	(1.7		)	(1.0		)
Total	$	14.2		$	26.4		$	(12.2	)

During the three and six months ended June 30, 2019 and 2018, gains and losses on foreign currency option contracts were included in “Operating costs and expenses,” and gains and losses on coal contracts related to forecasted sales and those related to coal trading contracts were included in “Revenues” in the accompanying unaudited condensed consolidated statements of operations.

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.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Value Measurements

The Company uses a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1 - inputs are quoted prices in active markets for the identical assets or liabilities; Level 2 - inputs are other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3 - inputs are unobservable, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.

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:



	June 30, 2019
	Level 1		Level 2			Level 3		Total
	(Dollars in millions)
Foreign currency option contracts	$	—	$	1.2		$	—	$	1.2
Coal contracts related to forecasted sales	—		41.3			—		41.3
Coal trading contracts	—		(37.3		)	—		(37.3		)
Equity securities	—		—			10.0		10.0
Total net financial assets	$	—	$	5.2		$	10.0	$	15.2

	December 31, 2018
	Level 1		Level 2			Level 3		Total
	(Dollars in millions)
Foreign currency option contracts	$	—	$	1.2		$	—	$	1.2
Coal contracts related to forecasted sales	—		(21.2		)	—		(21.2		)
Coal trading contracts	—		21.8			—		21.8
Equity securities	—		—			10.0		10.0
Total net financial assets	$	—	$	1.8		$	10.0	$	11.8

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including interest rate yield curves, exchange indices, broker/dealer quotes, published indices, issuer spreads, benchmark securities and other market quotes. In the case of certain debt securities, fair value is provided by a third-party pricing service. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:


•	Foreign currency 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.


•	Coal contracts related to forecasted sales and coal trading contracts: 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 securities are based on observed prices in an inactive market (Level 3).

Other Financial Instruments. The following methods and assumptions were used by the Company in estimating fair values for other financial instruments as of June 30, 2019 and December 31, 2018:


•	Cash and cash equivalents, restricted cash, accounts receivable, including those within the Company’s accounts receivable securitization program, notes receivable and accounts payable have carrying values which approximate fair value due to the short maturity or the liquid nature of these instruments.


•	Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available (Level 2), and otherwise on estimated borrowing rates to discount the cash flows to their present value (Level 3).

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The carrying amount and estimated fair values of the Company’s current and long-term debt as of June 30, 2019 and December 31, 2018 are summarized as follows:



	June 30, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(Dollars in millions)
Current and Long-term debt	$	1,355.6	$	1,431.0	$	1,367.0	$	1,366.2

The Company’s risk management function, which is independent of the Company’s coal trading function, is responsible for valuation policies and procedures, with oversight from executive management. Generally, the Company’s Level 3 instruments or contracts are valued using bid/ask price quotations and other market assessments obtained from multiple, independent third-party brokers or other transactional data incorporated into internally-generated discounted cash flow models. Decreases in the number of third-party brokers or market liquidity could erode the quality of market information and therefore the valuation of the Company’s market positions. The Company’s valuation techniques include basis adjustments to the foregoing price inputs for quality, such as sulfur and ash content, location differentials, expressed as port and freight costs, and credit risk. The Company’s risk management function independently validates the Company’s valuation inputs, including unobservable inputs, with third-party information and settlement prices from other sources where available. A daily process is performed to analyze market price changes and changes to the portfolio. Further periodic validation occurs at the time contracts are settled with the counterparty. These valuation techniques have been consistently applied in all periods presented, and the Company believes it has obtained the most accurate information available for the types of derivative contracts held.

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 Company had no transfers between Levels 1, 2 and 3 during the three and six months ended June 30, 2019 and 2018. The Company’s policy is to value all transfers between levels using the beginning of period valuation.

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

As of June 30, 2019, 62% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties and 38% was with counterparties that are not rated.

Performance Assurances and Collateral

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 $15.3 million and $16.7 million as of June 30, 2019 and December 31, 2018, respectively, which is reflected in “Other current assets” in the condensed consolidated balance sheets. As of June 30, 2019, the Company had posted $0.3 million in excess of initial margin requirements, while as of December 31, 2018, the Company was in receipt of $2.2 million.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. As of June 30, 2019, the Company was in receipt of $46.1 million in variation margin, while it had posted $21.8 million of net variation margin at December 31, 2018.

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 aggregate fair values, would have required no additional collateral postings to counterparties at June 30, 2019, and approximately $1.3 million at December 31, 2018. As of June 30, 2019 and December 31, 2018, the Company was not required to post collateral to counterparties for such positions.

(9) Intangible Contract Assets and Liabilities

As described in Note 2. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 and Note 3. “Acquisition of Shoal Creek Mine,” the Company has recorded intangible assets and liabilities to reflect the fair value of certain U.S. coal supply agreements as a result of differences between contract terms and estimated market terms for the same coal products, and also recorded intangible liabilities related to unutilized capacity under its port and rail take-or-pay contracts. The balances, net of accumulated amortization, and respective balance sheet classifications at June 30, 2019 and December 31, 2018, are set forth in the following tables:



	June 30, 2019
	Assets		Liabilities			Net Total
	(Dollars in millions)
Coal supply agreements	$	51.9	$	(25.5	)	$	26.4
Take-or-pay contracts	—		(45.6		)	(45.6		)
Total	$	51.9	$	(71.1	)	$	(19.2	)

Balance sheet classification:
Investments and other assets	$	51.9	$	—		$	51.9
Accounts payable and accrued expenses	—		(11.2		)	(11.2		)
Other noncurrent liabilities	—		(59.9		)	(59.9		)
Total	$	51.9	$	(71.1	)	$	(19.2	)

	December 31, 2018
	Assets		Liabilities			Net Total
	(Dollars in millions)
Coal supply agreements	$	70.9	$	(32.9	)	$	38.0
Take-or-pay contracts	—		(57.1		)	(57.1		)
Total	$	70.9	$	(90.0	)	$	(19.1	)

Balance sheet classification:
Investments and other assets	$	70.9	$	—		$	70.9
Accounts payable and accrued expenses	—		(20.3		)	(20.3		)
Other noncurrent liabilities	—		(69.7		)	(69.7		)
Total	$	70.9	$	(90.0	)	$	(19.1	)

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Amortization of the intangible assets and liabilities related to coal supply agreements occurs ratably based upon coal volumes shipped per contract and is recorded as a component of “Depreciation, depletion and amortization” in the accompanying unaudited condensed consolidated statements of operations. Such amortization amounted to $6.8 million and $25.1 million during the three months ended June 30, 2019 and 2018, respectively, and $11.6 million and $54.4 million during the six months ended June 30, 2019 and 2018, respectively. The Company anticipates net amortization of sales contracts, based upon expected shipments, to be an expense of approximately $15 million during the remaining six months of 2019, and for the years 2020 through 2023, expense of approximately $8 million, $3 million, $1 million and $1 million, respectively.

Future unutilized capacity and the amortization periods related to the take-or-pay contract intangible liabilities are based upon estimates of forecasted usage. Such amortization, which is classified as a reduction to “Operating costs and expenses” in the accompanying unaudited condensed consolidated statements of operations, amounted to $5.6 million and $7.8 million during the three months ended June 30, 2019 and 2018, respectively, and $11.2 million and $16.1 million during the six months ended June 30, 2019 and 2018, respectively. The Company anticipates net amortization of take-or-pay contract intangible liabilities to be approximately $6 million during the remaining six months of 2019, and for the years 2020 through 2023, approximately $8 million, $4 million, $3 million and $3 million, respectively, and $22 million thereafter.

(10) Property, Plant, Equipment and Mine Development

The composition of property, plant, equipment and mine development, net, as of June 30, 2019 and December 31, 2018 is set forth in the table below:



	June 30, 2019			December 31, 2018
	(Dollars in millions)
Land and coal interests	$	4,164.3		$	4,148.8
Buildings and improvements	549.1			559.3
Machinery and equipment	1,528.7			1,456.3
Less: Accumulated depreciation, depletion and amortization	(1,267.3		)	(957.4		)
Property, plant, equipment and mine development, net	$	4,974.8		$	5,207.0

(11) Leases

The Company has operating and finance leases for mining and non-mining equipment, office space and certain other facilities under various non-cancellable agreements. Historically, the majority of the Company’s leases have been accounted for as operating leases.

The Company determines if an arrangement is a lease at inception. ROU assets represent the Company's right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. For the purpose of calculating such present values, lease payments include components that vary based upon an index or rate, using the prevailing index or rate at the commencement date, and exclude components that vary based upon other factors. As most of its leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's leases may include options to extend or terminate the lease, and such options are reflected in the term when their exercise is reasonably certain. Lease expense is recognized on a straight-line basis over the lease term.

For certain equipment leases, the Company applies a portfolio approach to effectively account for the operating lease ROU assets and liabilities.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under various lease obligations. Certain lease agreements are subject to the restrictive covenants of the Company’s credit facilities and include cross-acceleration provisions, under which the lessor could require remedies including, but not limited to, immediate recovery of the present value of any remaining lease payments. The Company typically agrees to indemnify lessors for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property, if any, may be covered by insurance (subject to deductibles). Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments, and the Company assumes that no amounts could be recovered from third parties. In this regard, the Company has recorded provisions amounting to $50.7 million related to the loss of leased equipment at its North Goonyella Mine as described in Note 16. “Other Events.”

One of the Company’s operating lease agreements for underground mining equipment in Australia entered into in 2013 requires contingent rent to be paid only if and when certain coal is mined at a specified margin as defined in the agreements. There was no contingent expense related to that arrangement for the periods listed below.

The components of lease expense during the three and six months ended June 30, 2019 were as follows:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	(Dollars in millions)
Operating lease cost:
Operating lease cost	$	11.8		$	27.2
Short-term lease cost	7.4			15.7
Variable lease cost	8.5			14.5
Sublease income	(0.4		)	(0.8		)
Total operating lease cost	$	27.3		$	56.6

Finance lease cost:
Amortization of right-of-use assets	$	1.9		$	8.6
Interest on lease liabilities	0.4			0.9
Total finance lease cost	$	2.3		$	9.5

Rental expense under operating leases, including expense related to short-term operating leases, was $40.9 million and $86.3 million during the three and six months ended June 30, 2018, respectively.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Supplemental balance sheet information related to leases at June 30, 2019 was as follows:



	June 30, 2019
	(Dollars in millions)
Operating leases:
Operating lease right-of-use assets	$	93.1

Accounts payable and accrued expenses	$	(29.4	)
Operating lease liabilities, less current portion	(58.0		)
Total operating lease liabilities	$	(87.4	)

Finance leases:
Property, plant, equipment and mine development	$	96.8
Accumulated depreciation	(47.8		)
Property, plant, equipment and mine development, net	$	49.0

Current portion of long-term debt	$	24.5
Long-term debt, less current portion	—
Total finance lease liabilities	$	24.5

Weighted average remaining lease term (years)
Operating leases	4.1
Finance leases	0.7

Weighted average discount rate
Operating leases	7.4		%
Finance leases	5.9		%

Supplemental cash flow information related to leases during the three and six months ended June 30, 2019 was as follows:



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
	(Dollars in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	9.3	$	33.3
Operating cash flows for finance leases	0.4		1.2
Financing cash flows for finance leases	8.2		18.4

Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	27.3	$	27.8
Finance leases	1.4		1.4

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company's leases have remaining lease terms of 1 year to 11.8 years, some of which include options to extend the terms deemed reasonably certain of exercise. Maturities of lease liabilities were as follows:



Period Ending December 31,	Operating Leases			Finance Leases
	(Dollars in millions)
2019	$	16.8		$	17.4
2020	30.0			7.6
2021	18.4			—
2022	13.3			—
2023	12.2			—
2024 and thereafter	12.1			—
Total lease payments	102.8			25.0
Less imputed interest	(15.4		)	(0.5		)
Total lease liabilities	$	87.4		$	24.5

(12) Income Taxes

The Company’s income tax provision of $3.0 million and $7.4 million for the three months ended June 30, 2019 and 2018, respectively, included a tax benefit of $0.3 million and $0.4 million, respectively, related to the remeasurement of foreign income tax accounts. The Company’s income tax provision of $21.8 million and $17.5 million for the six months ended June 30, 2019 and 2018, respectively, included a tax benefit of $0.3 million and a tax provision of $0.1 million, respectively, related to the remeasurement of foreign income tax accounts. The Company’s effective tax rate before remeasurement for the six months ended June 30, 2019 is based on the Company’s estimated full year effective tax rate, comprised of expected statutory tax provision, offset by foreign rate differential and changes in valuation allowances.

(13) Long-term Debt

The Company’s total indebtedness as of June 30, 2019 and December 31, 2018 consisted of the following:



	June 30, 2019			December 31, 2018
	(Dollars in millions)
6.000% Senior Secured Notes due March 2022	$	500.0		$	500.0
6.375% Senior Secured Notes due March 2025	500.0			500.0
Senior Secured Term Loan due 2025, net of original issue discount	394.0			395.9
Finance lease and other obligations	24.5			40.0
Less: Debt issuance costs	(62.9		)	(68.9		)
	1,355.6			1,367.0
Less: Current portion of long-term debt	28.5			36.5
Long-term debt	$	1,327.1		$	1,330.5

6.000% and 6.375% Senior Secured Notes

On February 15, 2017, one of PEC’s subsidiaries entered into an indenture (the Indenture) with Wilmington Trust, National Association, as trustee, relating to the issuance by PEC’s subsidiary of $500.0 million aggregate principal amount of 6.000% senior secured notes due 2022 (the 2022 Notes) and $500.0 million aggregate principal amount of 6.375% senior secured notes due 2025 (the 2025 Notes and, together with the 2022 Notes, the Senior Notes). The Senior Notes were sold on February 15, 2017 in a private transaction exempt from the registration requirements of the Securities Act of 1933.

The Senior Notes were issued at par value. The Company paid aggregate debt issuance costs of $49.5 million related to the offering, which are being amortized over the respective terms of the Senior Notes. Interest payments on the Senior Notes are scheduled to occur each year on March 31 and September 30 until maturity. During the three months ended June 30, 2019 and 2018, the Company recorded interest expense of $18.6 million and $17.5 million, respectively, and during the six months ended June 30, 2019 and 2018, the Company recorded interest expense of $36.1 million and $34.9 million, respectively, related to the Senior Notes.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company may redeem the 2022 Notes during 2019, in whole or in part, at 103.0% of par, in 2020 at 101.5% of par, and in 2021 and thereafter at par. The 2025 Notes may be redeemed, in whole or in part, beginning in 2020 at 104.8% of par, in 2021 at 103.2% of par, in 2022 at 101.6% of par, and in 2023 and thereafter at par. In addition, prior to the first date on which the Senior Notes are redeemable at the redemption prices noted above, the Company may also redeem some or all of the Senior Notes at a calculated make-whole premium, plus accrued and unpaid interest.

On August 9, 2018, the Company executed an amendment to the Indenture following the solicitation of consents from the requisite majorities of holders of each series of Senior Notes. The amendment permits a category of restricted payments at any time not to exceed the sum of $650.0 million, plus an additional $150.0 million per calendar year, commencing with calendar year 2019, with unused amounts in any calendar year carrying forward to and available for restricted payments in any subsequent calendar year. The Company paid consenting Senior Note holders $10.00 in cash per $1,000 principal amount of 2022 Notes and $30.00 in cash per $1,000 principal amount of 2025 Notes, which amounted to $19.8 million in aggregate consent payments. Such consent payments were capitalized as additional debt issuance costs to be amortized over the respective terms of the Senior Notes. The Company also expensed $1.5 million of other payments associated with the amendment to “Interest expense” in the accompanying unaudited condensed consolidated statements of operations during 2018.

The Indenture contains customary conditions of default and imposes certain restrictions on the Company’s activities, including its ability to incur liens, incur debt, make investments, engage in fundamental changes such as mergers and dissolutions, dispose of assets, enter into transactions with affiliates and make certain restricted payments, such as cash dividends and share repurchases.

The Senior Notes rank senior in right of payment to any subordinated indebtedness and equally in right of payment with any senior indebtedness to the extent of the collateral securing that indebtedness. The Senior Notes are jointly and severally and fully and unconditionally guaranteed on a senior secured basis by substantially all of the Company’s material domestic subsidiaries and secured by first priority liens over (1) substantially all of the assets of the Company and the guarantors, except for certain excluded assets, (2) 100% of the capital stock of each domestic restricted subsidiary of the Company, (3) 100% of the non-voting capital stock of each first tier foreign subsidiary of the Company or a foreign subsidiary holding company and no more than 65% of the voting capital stock of each first tier foreign subsidiary of the Company or a foreign subsidiary holding company, (4) a legal charge of 65% of the voting capital stock and 100% of the non-voting capital stock of Peabody Investments (Gibraltar) Limited and (5) all intercompany debt owed to the Company or any guarantor, in each case, subject to certain exceptions. The obligations under the Senior Notes are secured on a pari passu basis by the same collateral securing the Credit Agreement (as defined below), subject to certain exceptions.

Credit Agreement

The Company entered into a credit agreement, dated as of April 3, 2017, among the Company, as borrower, Goldman Sachs Bank USA, as administrative agent, and other lenders party thereto (the Credit Agreement). The Credit Agreement originally provided for a $950.0 million senior secured term loan (the Senior Secured Term Loan), which was to mature in 2022 prior to the amendments described below.

Following the voluntary prepayments and amendments described below, the Credit Agreement provided for a $400.0 million first lien senior secured term loan, which bore interest at LIBOR plus 2.75% per annum as of June 30, 2019. During the three months ended June 30, 2019 and 2018, the Company recorded interest expense of $5.7 million and $6.6 million, respectively, and during the six months ended June 30, 2019 and 2018, the Company recorded interest expense of $11.4 million and $13.4 million, respectively, related to the Senior Secured Term Loan.

Table of Contents

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Proceeds from the Senior Secured Term Loan were received net of an original issue discount and deferred financing costs of $37.3 million that are being amortized over its term. The loan principal is payable in quarterly installments plus accrued interest through December 2024 with the remaining balance due in March 2025. The loan principal was voluntarily prepayable at 101% of the principal amount repaid if prepayment occurred prior to October 2018 (subject to certain exceptions, including prepayments made with internally generated cash) and is voluntarily prepayable at any time thereafter without premium or penalty. The Senior Secured Term Loan may require mandatory principal prepayments of up to 75% of Excess Cash Flow (as defined in the Credit Agreement) for any fiscal year if the Company’s Total Leverage Ratio (as defined in the Credit Agreement and calculated at December 31, net of any unrestricted cash) is greater than 2.00:1.00. The mandatory principal prepayment requirement changes to (i) 50% of Excess Cash Flow if the Company’s Total Leverage Ratio 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. The calculation of mandatory prepayments would be reduced commensurately by the amount of previous voluntary prepayments. In certain circumstances, the Senior Secured Term Loan requires that Excess Proceeds (as defined in the Credit Agreement) of $10.0 million or greater received from sales of Company assets be applied against the loan principal, unless such proceeds are reinvested within one year. The Senior Secured Term Loan also requires that any net insurance proceeds be applied against the loan principal, unless such proceeds are reinvested within one year.

The Credit Agreement contains customary conditions of default and imposes certain restrictions on the Company’s activities, including its ability to incur liens, incur debt, make investments, engage in fundamental changes such as mergers and dissolutions, dispose of assets, enter into transactions with affiliates, and make certain restricted payments, such as cash dividends and share repurchases. Obligations under the Credit Agreement are secured on a pari passu basis by the same collateral securing the Senior Notes.

Since entering into the Credit Agreement, the Company has repaid $555.0 million of the original $950.0 million loan principal amount on the Senior Secured Term Loan in various installments, including $546.0 million which was voluntarily prepaid. In September 2017, the Company entered into an amendment to the Credit Agreement which permitted the Company to add an incremental revolving credit facility in addition to the Company’s ability to add one or more incremental term loan facilities under the Credit Agreement. The incremental revolving credit facility and/or incremental term loan facilities can be in an aggregate principal amount of up to $350.0 million plus additional amounts so long as the Company is below Total Leverage Ratio requirements as set forth in the Credit Agreement. The amendment also made available an additional restricted payment basket that permits additional repurchases, dividends or other distributions with respect to the Company’s common and preferred stock in an aggregate amount up to $450.0 million so long as the Company’s Fixed Charge Coverage Ratio (as defined in the Credit Agreement) is at least 2.00:1.00 on a pro forma basis.

During the fourth quarter of 2017, the Company entered into the incremental revolving credit facility (the Revolver) for an aggregate commitment of $350.0 million for general corporate purposes. The Company paid aggregate debt issuance costs of $4.7 million. The Revolver matures in November 2020 and permits loans which bear interest at LIBOR plus 3.25%. The Revolver is subject to a 2.00:1.00 Total Leverage Ratio requirement (as defined in the Credit Agreement), modified to limit unrestricted cash netting to $800.0 million. Capacity under the Revolver may also be utilized for letters of credit which incur combined fees of 3.375% per annum. Unused capacity under the Revolver bears a commitment fee of 0.5% per annum. As of June 30, 2019, the Revolver had only been utilized for letters of credit amounting to $70.8 million. Such letters of credit were primarily in support of the Company’s reclamation obligations, as further described in Note 18. “Financial Instruments and Other Guarantees.” During the three months ended June 30, 2019 and 2018, the Company recorded interest expense and fees of $1.5 million and $1.3 million, respectively, and during the six months ended June 30, 2019 and 2018, the Company recorded interest expense and fees of $3.1 million and $3.1 million, respectively, related to the Revolver.

In April 2018, the Company entered into another amendment to the Credit Agreement which lowered the interest rate on the Senior Secured Term Loan to its current level of LIBOR plus 2.75% and eliminated an existing 1.0% LIBOR floor. The amendment also extended the maturity of the Senior Secured Term Loan by three years to 2025 and eliminated previous capital expenditure restriction covenants on both the Senior Secured Term Loan and the Revolver. In connection with this amendment, the Company voluntarily repaid $46.0 million of principal on the Senior Secured Term Loan.

Restricted Payments Under the Senior Notes and Credit Agreement

In addition to the $450.0 million restricted payment basket provided for under the September 2017 amendment, the Credit Agreement provides a builder basket for additional restricted payments subject to a maximum Total Leverage Ratio of 2.00:1.00 (as defined in the Credit Agreement).

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In addition to the $650.0 million restricted payment basket, plus an additional $150.0 million per calendar year, provided under the August 2018 amendment, the Indenture provides a builder basket for restricted payments that is calculated based upon the Company’s Consolidated Net Income, and is subject to a Fixed Charge Coverage Ratio of at least 2.25:1.00 (as defined in the Indenture).

Further, under both the Indenture and Credit Agreement, additional restricted payments are permitted through a $50.0 million general basket and an annual aggregate $25.0 million basket which allows dividends and common stock repurchases. The payment of dividends and purchases of common stock under this annual aggregate $25.0 million basket are permitted so long as the Company’s Total Leverage Ratio would not exceed 1.25:1.00 on a pro forma basis (as defined in the Credit Agreement and Indenture).

Copies of the Indenture documents are incorporated as Exhibits 4.2 and 4.3 to the Current Report on Form 8-K filed by the Company with the Securities and Exchange Commission (SEC) on April 3, 2017. A copy of the Credit Agreement is included as Exhibit 10.3 to the Current Report on Form 8-K filed by the Company with the SEC on April 3, 2017, and copies of the subsequent amendments referenced above are included as Exhibits 10.1 to the Current Reports on Form 8-K filed by the Company with the SEC on September 18, 2017, November 20, 2017, December 19, 2017 and April 11, 2018, and as Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by the Company with the SEC on November 1, 2018.

Finance Lease Obligations

Refer to Note 11. “Leases” for additional information associated with the Company’s finance leases, which pertain to the financing of mining equipment used in operations.

(14) Pension and Postretirement Benefit Costs

The components of net periodic pension and postretirement benefit costs, excluding the service cost for benefits earned, are included in “Net periodic benefit costs, excluding service cost” in the unaudited condensed consolidated statements of operations.

Net periodic pension cost (benefit) included the following components:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(Dollars in millions)
Service cost for benefits earned	$	0.5		$	0.5		$	1.0		$	1.1
Interest cost on projected benefit obligation	8.4			7.9			16.7			15.7
Expected return on plan assets	(7.8		)	(10.7		)	(15.6		)	(21.4		)
Net periodic pension cost (benefit)	$	1.1		$	(2.3	)	$	2.1		$	(4.6	)

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 June 30, 2019, the Company’s qualified plans were expected to be at or above the Pension Protection Act thresholds. Minimum funding standards are legislated by ERISA and are modified by pension funding stabilization provisions included in the Moving Ahead for Progress in the 21st Century Act of 2012, the Highway and Transportation Funding Act of 2014 and the Bipartisan Budget Act of 2015. The Company is not required to make any contributions to its qualified pension plans in 2019 based on minimum funding requirements; however, during the three and six months ended June 30, 2019, the Company made a discretionary contribution of $20.0 million to one of its qualified pension plans.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Net periodic postretirement benefit cost included the following components:



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
	(Dollars in millions)
Service cost for benefits earned	$	1.2		$	2.1	$	2.4		$	4.1
Interest cost on accumulated postretirement benefit obligation	6.3			7.1		12.6			14.2
Expected return on plan assets	(0.1		)	—		(0.2		)	—
Amortization of prior service credit	(2.2		)	—		(4.4		)	—
Net periodic postretirement benefit cost	$	5.2		$	9.2	$	10.4		$	18.3

In October 2018, the Company amended its postretirement health care benefit plan which reduced its accumulated postretirement benefit obligation, as further described in Note 17. “Postretirement Health Care and Life Insurance Benefits” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. The reduction in liability has been recorded with an offsetting balance in “Accumulated other comprehensive income,” net of a deferred tax provision, and is being amortized to earnings over an average remaining service period to full eligibility for participating employees.

In 2018, the Company established a Voluntary Employees Beneficiary Association (VEBA) trust to pre-fund a portion of benefits for non-represented retirees. During the three and six months ended June 30, 2019, the Company made a pre-funding contribution of $17.0 million to the VEBA.

(15) Accumulated Other Comprehensive Income

The following table sets forth the after-tax components of accumulated other comprehensive income and changes thereto recorded during the six months ended June 30, 2019:



	Foreign Currency Translation Adjustment			Prior Service Credit (Cost) Associated with Postretirement Plans			Total Accumulated Other Comprehensive Income
	(Dollars in millions)
December 31, 2018	$	(4.5	)	$	44.6		$	40.1
Reclassification from other comprehensive income to earnings	—			(4.4		)	(4.4		)
Current period change	(0.4		)	—			(0.4		)
June 30, 2019	$	(4.9	)	$	40.2		$	35.3

Postretirement health care and life insurance benefits reclassified out of “Accumulated other comprehensive income” into earnings of $2.2 million and $4.4 million during the three and six months ended June 30, 2019, respectively, are presented as “Net periodic benefit costs, excluding service cost” in the unaudited condensed consolidated statements of operations.

(16) Other Events

PRB Colorado Joint Venture with Arch

On June 18, 2019, the Company entered into a definitive implementation agreement (the Implementation Agreement) with Arch, to establish a joint venture that will combine the respective Powder River Basin and Colorado mining operations of Peabody and Arch. Pursuant to the terms of the Implementation Agreement, Peabody will hold a 66.5% economic interest in the joint venture and Arch will hold a 33.5% economic interest. The Company expects to proportionally consolidate the entity based upon its economic interest. Governance of the joint venture will be overseen by the joint venture’s board of managers, which will be comprised of Peabody and Arch representatives with voting powers proportionate with the companies’ economic interests. Peabody will manage the operations of the joint venture, subject to the supervision of the joint venture’s board of managers.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Formation of the joint venture is subject to customary closing conditions, including the termination or expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of certain other required regulatory approvals and the absence of injunctions or other legal restraints preventing the formation of the joint venture. The existing outstanding indebtedness of both Peabody and Arch limits significant transactions such as the joint venture, and accordingly, formation is subject to Peabody and Arch amending such outstanding indebtedness under agreeable terms. At such time as control over the existing operations is exchanged, the Company will account for its interest in the combined operations at fair value, which could result in a gain or loss.

North Goonyella

The Company’s North Goonyella Mine in Queensland, Australia experienced a fire in a portion of the mine during September 2018. Mining operations have been suspended since September 2018. No mine personnel were physically harmed by the September 2018 events. On November 13, 2018, the Queensland Mine Inspectorate (QMI) initiated an investigation into the events that occurred at the mine to determine the cause of the event, assess the response to it and make recommendations to reduce the possibility of future incidents and improve response. The Company is currently complying with information requests from the QMI.

During the first quarter of 2019, the Company completed segmenting of the mine into multiple zones to facilitate a phased re-ventilation and re-entry of the mine. The Company commenced re-ventilation of the first zone of the mine during the second quarter of 2019 and subsequently re-entered the area in July 2019. Following these activities, additional information about the regulatory process and physical condition of the mine continued to emerge. As a result, the Company is assessing various alternatives for accessing the coal reserves.

During the year ended December 31, 2018, the Company recorded $58.0 million in containment and idling costs related to the events at North Goonyella Mine and a provision of $66.4 million for expected equipment losses. During the three and six months ended June 30, 2019, the Company recorded an additional $28.4 million and $65.3 million, respectively, in containment and idling costs, and an additional provision of $24.7 million related to equipment losses was recorded during the six months ended June 30, 2019 as more information became available. The combined provision includes $50.7 million for the estimated cost to replace leased equipment, $23.2 million related to the cost of Company-owned equipment and $17.2 million of other charges, which represents the best estimate of potential loss based on the assessments made to date. In the event that no future mining occurs at the North Goonyella Mine, the Company may record additional charges for the remaining carrying value of the North Goonyella Mine and additional leased equipment of approximately $290 million and $5 million, respectively. Such carrying value includes approximately $30 million of longwall panel development that may be unrecoverable. Incremental exposures above the aforementioned include take-or-pay obligations and other costs associated with idling or closing the mine.

In March 2019, the Company entered into an insurance claim settlement agreement with its insurers and various re-insurers under a combined property damage and business interruption policy and recorded a $125 million insurance recovery, the maximum amount available under the policy above a $50 million deductible. The Company has collected the full amount of the recovery.

On April 30, 2019, Peabody (Bowen) Pty Ltd entered into an option exercise and release agreement with Yancoal Technology Development Pty Ltd pursuant to which Peabody (Bowen) Pty Ltd exercised an option to acquire from Yancoal Technology Development Pty Ltd the longwall mining equipment used under license at the North Goonyella Mine for $54.2 million, which was consistent with the Company’s provision for equipment losses for the related impaired assets at June 30, 2019.

Divestitures

In June 2018, Peabody entered into an agreement to sell approximately 23 million tonnes of metallurgical coal resources adjacent to its Millennium Mine to Stanmore Coal Limited (Stanmore) for approximately $22 million. The sale was completed in July 2018. During the six months ended June 30, 2019, Stanmore paid Peabody approximately $10 million, which brought the remaining receivable balance to approximately $4 million as of June 30, 2019. The remaining receivable balance, which was paid in July 2019, is included in “Accounts receivable, net” in the accompanying condensed consolidated balance sheet.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On February 6, 2018, the Company sold its 50% interest in the Red Mountain Joint Venture (RMJV) with BHP Billiton Mitsui Coal Pty Ltd (BMC) for $20.0 million and recorded a gain of $7.1 million, which is included within “Net (gain) loss on disposals” in the accompanying unaudited condensed consolidated statements of operations for the six months ended June 30, 2018. RMJV operated the coal handling and preparation plant utilized by the Company’s Millennium Mine. BMC assumed the reclamation obligations and other commitments associated with the assets of RMJV. The Millennium Mine will have continued usage of the coal handling and preparation plant and the associated rail loading facility until the end of 2019 via a coal washing take-or-pay agreement with BMC.

In January 2018, Peabody entered into an agreement to sell its share in certain surplus land assets in Queensland’s Bowen Basin to Pembroke Resources South Pty Ltd for approximately $37 million Australian dollars, net of transaction costs. The necessary approval of the Australian Foreign Investment Review Board to complete the transaction was received on March 29, 2018, satisfying all the conditions precedent to the sale, and the Company recorded a gain of $20.6 million, which is included within “Net (gain) loss on disposals” in the accompanying unaudited condensed consolidated statements of operations for the six months ended June 30, 2018.

United Wambo Joint Venture with Glencore

In 2014, the Company agreed to establish an unincorporated joint venture project with Glencore plc (Glencore), in which the Company holds a 50% interest, to combine the existing operations of the Company’s Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. Glencore will manage the operations of the joint venture. The Company expects the project to result in several operational synergies, including improved mining productivity, lower per-unit operating costs and an extended mine life. The joint venture is expected to be formed during 2019, subject to substantive contingencies for the requisite regulatory and permitting approvals. At such time as control over the existing operations is exchanged, the Company will account for its interest in the combined operations at fair value, which could result in a gain or loss.

Other At-Risk Assets

Other than the provision for North Goonyella equipment losses described above, the Company recorded no asset impairment charges during the three and six months ended June 30, 2019 or 2018. However, the Company has identified certain assets with an aggregate carrying value of $248.4 million at June 30, 2019 in its Midwestern U.S. and Western U.S. Mining Segments whose recoverability is most sensitive to coal pricing, cost pressures and customer concentration risk. The Company conducted a review of those assets for recoverability as of June 30, 2019 and determined that no further impairment charges were necessary as of that date.

(17) 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 share-based compensation awards in its potentially dilutive securities. 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.

During the periods which included the Company’s convertible preferred stock, basic and diluted EPS were computed using the two-class method, which is an earnings allocation that determines EPS for each class of common stock and participating securities according to dividends declared and participation rights in undistributed earnings. The Company’s convertible preferred stock was considered a participating security because holders were entitled to receive dividends on an if-converted basis. Diluted EPS assumes that participating securities are not executed or converted.

For all but the performance units, the potentially dilutive impact of the Company’s share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. For the performance units, their contingent features result in an assessment for any potentially dilutive common stock by using the end of the reporting period as if it were the end of the contingency period for all units granted.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The computation of diluted EPS excluded aggregate share-based compensation awards of approximately 0.7 million for both the three and six months ended June 30, 2019. No aggregate share-based compensation awards were excluded from the computation of diluted EPS for the three and six months ended June 30, 2018, because to do so would have been anti-dilutive for those periods. Because the potential dilutive impact of such share-based compensation awards is calculated under the treasury stock method, anti-dilution generally occurs when the exercise prices or unrecognized compensation cost per share of such awards are higher than the Company’s average stock price during the applicable period.

The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions, except per share data)
EPS numerator:
Income from continuing operations, net of income taxes	$	42.9		$	120.0		$	176.2		$	328.3
Less: Series A Convertible Preferred Stock dividends	—			—			—			102.5
Less: Net income attributable to noncontrolling interests	2.4			2.7			8.1			0.6
Income from continuing operations attributable to common stockholders, before allocation of earnings to participating securities	40.5			117.3			168.1			225.2
Less: Earnings allocated to participating securities	—			—			—			6.4
Income from continuing operations attributable to common stockholders, after allocation of earnings to participating securities ⁽¹⁾	40.5			117.3			168.1			218.8
Loss from discontinued operations, net of income taxes	(3.4		)	(3.6		)	(6.8		)	(4.9		)
Less: Loss from discontinued operations allocated to participating securities	—			—			—			(0.1		)
Loss from discontinued operations attributable to common stockholders, after allocation of earnings to participating securities	(3.4		)	(3.6		)	(6.8		)	(4.8		)
Net income attributable to common stockholders, after allocation of earnings to participating securities ⁽¹⁾	$	37.1		$	113.7		$	161.3		$	214.0

EPS denominator:
Weighted average shares outstanding — basic	107.0			124.5			107.7			122.7
Impact of dilutive securities	1.1			1.5			1.6			1.9
Weighted average shares outstanding — diluted ⁽²⁾	108.1			126.0			109.3			124.6

Basic EPS attributable to common stockholders:
Income from continuing operations	$	0.38		$	0.94		$	1.56		$	1.78
Loss from discontinued operations	(0.03		)	(0.03		)	(0.06		)	(0.04		)
Net income attributable to common stockholders	$	0.35		$	0.91		$	1.50		$	1.74

Diluted EPS attributable to common stockholders:
Income from continuing operations	$	0.37		$	0.93		$	1.54		$	1.76
Loss from discontinued operations	(0.03		)	(0.03		)	(0.06		)	(0.04		)
Net income attributable to common stockholders	$	0.34		$	0.90		$	1.48		$	1.72


⁽¹⁾	The reallocation adjustment for participating securities to arrive at the numerator to calculate diluted EPS was $0.1 million for the six months ended June 30, 2018.


⁽²⁾	The two-class method assumes that participating securities are not exercised or converted. As such, weighted average diluted shares outstanding excluded 4.2 million shares related to the participating securities for the six months ended June 30, 2018.

As of January 31, 2018, all 30.0 million shares of convertible preferred stock issued upon the Company’s emergence from the Chapter 11 reorganization had been converted into 59.3 million shares of common stock, which is inclusive of the shares that had been issued for the payable in-kind preferred stock dividends.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(18) Financial Instruments and Other Guarantees

In the normal course of business, the Company is a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying condensed consolidated balance sheets. At June 30, 2019, such instruments included $1,572.0 million of surety bonds and $202.2 million of letters of credit. Such financial instruments provide support for the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. The Company periodically evaluates the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. The Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in the accompanying condensed consolidated balance sheets.

The Company is required to provide various forms of financial assurance in support of its mining reclamation obligations in the jurisdictions in which it operates. Such requirements are typically established by statute or under mining permits. At June 30, 2019, the Company’s mining reclamation obligations of $762.8 million were supported by surety bonds of $1,359.9 million, as well as letters of credit issued under the Company’s receivables securitization program and Revolver amounting to $110.5 million.

Accounts Receivable Securitization

The Company entered into the Sixth Amended and Restated Receivables Purchase Agreement, as amended, dated as of April 3, 2017 (the Receivables Purchase Agreement) to extend the Company’s receivables securitization facility previously in place and expand that facility to include certain receivables from the Company’s Australian operations. The receivables securitization program (Securitization Program) is subject to certain liquidity requirements and other customary events of default set forth in the Receivables Purchase Agreement. The Securitization Program provides for up to $250.0 million in funding accounted for as a secured borrowing, limited to the availability of eligible receivables, and may be secured by a combination of collateral and the trade receivables underlying the program, from time to time. Funding capacity under the Securitization Program may also be utilized for letters of credit in support of other obligations. During 2019, the Company entered into an amendment to the Securitization Program to extend its term through April 1, 2022 and reduce program fees.

Under the terms of the Securitization Program, the Company contributes the trade receivables of its participating subsidiaries on a revolving basis to P&L Receivables, its wholly-owned, bankruptcy-remote subsidiary, which then sells the receivables to unaffiliated banks. P&L Receivables retains the ability to repurchase the receivables in certain circumstances. The assets and liabilities of P&L Receivables are consolidated with Peabody, and the Securitization Program is treated as a secured borrowing for accounting purposes, but the assets of P&L Receivables will be used first to satisfy the creditors of P&L Receivables, not Peabody’s creditors. The borrowings under the Securitization Program remain outstanding throughout the term of the agreement, subject to the Company maintaining sufficient eligible receivables, by continuing to contribute trade receivables to P&L Receivables, unless an event of default occurs.

At June 30, 2019, the Company had no outstanding borrowings and $129.9 million of letters of credit issued under the Securitization Program. The letters of credit were primarily in support of portions of the Company’s obligations for reclamation, workers’ compensation and postretirement benefits. The Company had no collateral requirement under the Securitization Program at June 30, 2019 or December 31, 2018. The Company incurred fees associated with the Securitization Program of $1.0 million and $1.9 million during the three months ended June 30, 2019 and 2018, respectively, and $2.6 million and $3.8 million during the six months ended June 30, 2019 and 2018, respectively, which have been recorded as interest expense in the accompanying unaudited condensed consolidated statements of operations.

Collateral Arrangements and Restricted Cash

From time to time, the Company is required to remit cash to certain regulatory authorities and other third parties as collateral for financial assurances associated with a variety of long-term obligations and commitments surrounding the mining, reclamation and shipping of its production. During the six months ended June 30, 2018, $363.2 million of such collateral and other restricted cash was returned to the Company, largely as the result of replacing collateral balances with third-party surety bonding in Australia.

Other

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.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(19) Commitments and Contingencies

Commitments

Unconditional Purchase Obligations

As of June 30, 2019, purchase commitments for capital expenditures were $130.8 million, all of which is obligated within the next three years, with $123.5 million obligated within the next 12 months.

There were no other material changes to the Company’s commitments from the information provided in Note 26. “Commitments and Contingencies” to the consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.

Contingencies

From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities. The Company discusses its significant legal proceedings below, including ongoing proceedings and those that impacted the Company’s results of operations for the periods presented.

Litigation Relating to Bankruptcy

Ad Hoc Committee. A group of creditors (the Ad Hoc Committee) that held certain interests in the Company's prepetition indebtedness appealed the Bankruptcy Court’s order confirming the Company’s plan of reorganization (the Plan). On December 29, 2017, the United States District Court for the Eastern District of Missouri (the District Court) entered an order dismissing the Ad Hoc Committee's appeal, and, in the alternative, affirming the order confirming the Plan. On January 26, 2018, the Ad Hoc Committee appealed the District Court's order to the United States Court of Appeals for the Eighth Circuit (the Eighth Circuit). In its appeal, the Ad Hoc Committee does not ask the Eighth Circuit to reverse the order confirming the Plan. Instead, the Ad Hoc Committee asks the Eighth Circuit to award the Ad Hoc Committee members either unspecified damages or the right to buy an unspecified amount of Company stock at a discount. Oral argument on the appeal was held April 16, 2019, and the Eighth Circuit panel reserved decision and took the case under submission. The Company does not believe the appeal is meritorious and will vigorously defend against the Ad Hoc Committee’s claims.

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 claim was made against Peabody Monto Coal Pty Ltd, a wholly-owned subsidiary, and Monto Coal 2 Pty Ltd, an equity accounted investee of Macarthur Coal Limited (Macarthur), now known as PEA-PCI. The claim, made by the minority interest holders in the joint venture, alleged that the Macarthur companies breached certain agreements by failing to develop a mine project. The claim was amended to assert that Macarthur induced the alleged breach of the Monto Coal Joint Venture Agreement. The Company acquired Macarthur and its subsidiaries in 2011. These claims, which are pending before the Supreme Court of Queensland, Australia, seek damages of up to $1.1 billion Australian dollars, plus interest and costs.

The Company asserts that the Macarthur companies were never under an obligation to develop the mine project because the project was not economically viable. The Company disputes all of the claims brought by the plaintiffs and is vigorously defending its position. The trial commenced on April 8, 2019 and is scheduled to finish in October 2019.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 brought by municipalities in California. 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 Plan because it enjoins claims that arose before the effective date of the Plan. The motion to enforce was granted on October 24, 2017, and the Bankruptcy Court ordered the plaintiffs to dismiss their lawsuits against the Company. On November 26, 2017, the plaintiffs appealed the Bankruptcy Court’s October 24, 2017 order to the District Court. On November 28, 2017, plaintiffs sought a stay pending appeal from the Bankruptcy Court, which was denied on December 8, 2017. On December 19, 2017, the plaintiffs moved the District Court for a stay pending appeal. The District Court denied the stay request on September 20, 2018, and the plaintiffs have appealed that decision to the Eighth Circuit. On March 29, 2019, the District Court affirmed the Bankruptcy Court ruling enjoining the plaintiffs from proceeding with their lawsuits against the Company. That ruling likewise is being appealed. In the underlying cases pending in California, the U.S. District Court for the Northern District of California granted plaintiffs’ motion for remand and decided the cases should be heard in state court. The defendants appealed the order granting remand to the Ninth Circuit and sought a stay of the U.S. District Court for the Northern District of California decision pending completion of the Ninth Circuit appeal. The U.S. District Court for the Northern District of California granted defendants’ request for a stay pending completion of the Ninth Circuit appeal. The plaintiffs filed a motion to dismiss part of the appeal. The parties are now litigating at the Ninth Circuit whether a state or federal court should hear these lawsuits. Regardless of whether state court or federal court is the venue, the Company believes the lawsuits against it should be dismissed under enforcement of the Plan. The Company does not believe the lawsuits are meritorious and, if the lawsuits are not dismissed, the Company intends to vigorously defend them.

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 of Wyoming with directions to order BLM to revise its environmental analysis. On November 27, 2017, the District Court of Wyoming ordered BLM to revise its environmental analysis. BLM published its draft environmental analysis on July 30, 2018. The Company, along with the National Mining Association, the Wyoming Mining Association and Arch, submitted comments on the draft environmental analysis by the comment deadline of October 4, 2018. BLM completed its final environmental analysis, prepared a finding of no significant impact, and re-affirmed its decision to issue the leases. 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.

Other

At times the Company becomes a party to other disputes, including those related to contract miner performance, claims, lawsuits, arbitration proceedings, regulatory investigations and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where the Company does business. Based on current information, the Company believes that such other pending or threatened proceedings are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

(20) Segment Information

The Company reports its results of operations through the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Midwestern U.S. Mining, Western U.S. Mining and Corporate and Other. The Company’s chief operating decision maker uses Adjusted EBITDA as the primary metric to measure the segments’ operating performance.

Adjusted EBITDA is a non-GAAP financial measure defined as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses, depreciation, depletion and amortization and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing the segments’ operating performance, as displayed in the reconciliation below. Management believes non-GAAP performance measures are used by investors to measure the Company’s operating performance and lenders to measure the Company’s ability to incur and service debt. Adjusted EBITDA is not intended to serve as an alternative to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Reportable segment results were as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(Dollars in millions)
Revenues:
Seaborne Thermal Mining	$	220.2		$	267.4		$	471.2		$	468.8
Seaborne Metallurgical Mining	290.9			417.5			615.4			883.7
Powder River Basin Mining	282.6			321.5			569.9			710.8
Midwestern U.S. Mining	167.5			197.5			346.6			399.2
Western U.S. Mining	142.1			139.6			297.8			283.3
Corporate and Other	45.7			(34.1		)	98.7			26.3
Total	$	1,149.0		$	1,309.4		$	2,399.6		$	2,772.1

Adjusted EBITDA:
Seaborne Thermal Mining	$	74.4		$	107.6		$	169.1		$	169.2
Seaborne Metallurgical Mining	57.4			158.5			143.2			324.9
Powder River Basin Mining	40.2			62.0			76.6			136.5
Midwestern U.S. Mining	30.7			42.0			64.0			73.2
Western U.S. Mining	52.4			33.9			95.0			65.9
Corporate and Other ⁽¹⁾	(27.1		)	(34.4		)	(66.0		)	(36.2		)
Total	$	228.0		$	369.6		$	481.9		$	733.5


⁽¹⁾	As described in Note 16. “Other Events,” included in the six months ended June 30, 2018, is the gain of $20.6 million recognized on the sale of certain surplus land assets in Queensland and the gain of $7.1 million recognized on the sale of the Company’s interest in the RMJV.

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PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A reconciliation of consolidated income from continuing operations, net of income taxes to Adjusted EBITDA follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(Dollars in millions)
Income from continuing operations, net of income taxes	$	42.9		$	120.0		$	176.2		$	328.3
Depreciation, depletion and amortization	165.4			163.9			337.9			333.5
Asset retirement obligation expenses	15.3			13.2			29.1			25.5
Provision for North Goonyella equipment loss	—			—			24.7			—
North Goonyella insurance recovery - equipment ⁽¹⁾	—			—			(91.1		)	—
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates	0.3			(8.4		)	0.3			(16.0		)
Interest expense	36.0			38.3			71.8			74.6
Loss on early debt extinguishment	—			2.0			—			2.0
Interest income	(7.2		)	(7.0		)	(15.5		)	(14.2		)
Reorganization items, net	—			—			—			(12.8		)
Unrealized (gains) losses on economic hedges	(22.4		)	48.1			(62.2		)	9.5
Unrealized losses (gains) on non-coal trading derivative contracts	0.3			(0.1		)	0.1			1.7
Fresh start take-or-pay contract-based intangible recognition	(5.6		)	(7.8		)	(11.2		)	(16.1		)
Income tax provision	3.0			7.4			21.8			17.5
Total Adjusted EBITDA	$	228.0		$	369.6		$	481.9		$	733.5

⁽¹⁾

As described in Note 16. “Other Events,” the Company recorded a $125.0 million insurance recovery during the six months ended June 30, 2019 related to losses incurred at its North Goonyella Mine. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the six months ended June 30, 2019 and the year ended December 31, 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the six months ended June 30, 2019.

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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” refer to Peabody Energy Corporation and its consolidated subsidiaries and affiliates, collectively, unless the context indicates otherwise. The term “Peabody” refers to Peabody Energy Corporation and not its consolidated subsidiaries and affiliates. Unless otherwise noted herein, disclosures in this Quarterly Report on Form 10-Q relate only to our continuing operations.

When used in this filing, the term “ton” refers to short or net tons, equal to 2,000 pounds (907.18 kilograms), while “tonne” refers to metric tons, equal to 2,204.62 pounds (1,000 kilograms).

Cautionary Notice Regarding Forward-Looking Statements

This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended, and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook” in this Item 2. We use words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements.

Without limiting the foregoing, all statements relating to our future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. These factors are difficult to accurately predict and may be beyond our control. Factors that could affect our results or an investment in our securities include, but are not limited to:


•	our profitability depends upon the prices we receive for our coal;


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


•	the loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues;


•	our trading and hedging activities do not cover certain risks, and may expose us to earnings volatility and other risks;


•	our operating results could be adversely affected by unfavorable economic and financial market conditions;


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


•	risks inherent to mining could increase the cost of operating our business, and events and conditions that could occur during the course of our mining operations could have a material adverse impact on us;


•	if transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal may be diminished;


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


•	take-or-pay arrangements within the coal industry could unfavorably affect our profitability;


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


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


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


•	we could be negatively affected if we fail to maintain satisfactory labor relations;


•	we could be adversely affected if we fail to appropriately provide financial assurances for our obligations;


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


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


•	we may be unable to obtain, renew or maintain permits necessary for our operations, which would reduce our production, cash flows and profitability;


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


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


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


•	we face numerous uncertainties in estimating our economically recoverable coal reserves and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability;


•	our global operations increase our exposure to risks unique to international mining and trading operations;


•	our proposed joint ventures with Arch Coal, Inc. (Arch) and Glencore plc (Glencore) may not be completed;


•	joint ventures, partnerships or non-managed operations may not be successful and may not comply with our operating standards;


•	we may undertake further repositioning plans that would require additional charges;


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


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

•

concerns about the impacts of coal combustion on global climate are increasingly leading to consequences that have and could continue to affect demand for our products or our securities, including the following: increased regulation of coal combustion in many jurisdictions; investment decisions by electricity generators that are unfavorable to coal-fueled generation units; unfavorable lending policies by lending institutions and development banks toward the financing of new overseas coal-fueled power plants; and divestment efforts affecting the institutional investment community;


•	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 our future financial results, liquidity and growth prospects;


•	we may not be able to successfully integrate the recently acquired Shoal Creek Mine or other companies, assets or properties that we may acquire in the future;


•	if we fail to establish and maintain proper internal controls for the Shoal Creek Mine, our ability to produce accurate financial statements or comply with applicable regulations could be impaired;


•	our financial performance could be adversely affected by our indebtedness;


•	despite our indebtedness, we may still be able to incur substantially more debt, including secured debt, which could further increase the risks associated with our indebtedness;


•	we may not be able to generate sufficient cash to service all of our indebtedness or other obligations;


•	the terms of our indenture governing our senior secured notes and the agreements and instruments governing our other indebtedness impose restrictions that may limit our operating and financial flexibility;


•	the number and quantity of viable financing alternatives available to us 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;


•	the price of our securities may be volatile;


•	our Common Stock is subject to dilution and may be subject to further dilution in the future;


•	there may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests;


•	the payment of dividends on our stock or repurchases of our stock is dependent on a number of factors, and future payments and repurchases cannot be assured;


•	we may not be able to fully utilize our deferred tax assets;


•	acquisitions and divestitures are a potentially important part of our long-term strategy, subject to our investment criteria, and involve a number of risks, any of which could cause us not to realize the anticipated benefits;


•	our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt;


•	diversity in interpretation and application of accounting literature in the mining industry may impact our reported financial results; and


•	other risks and factors detailed in this report, including, but not limited to, those discussed in “Legal Proceedings,” set forth in Part II, Item 1 and in “Risk Factors,” set forth in Part II, Item 1A of this Quarterly Report on Form 10-Q.

When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (SEC) filings, including, but not limited to, the more detailed discussion of these factors and other factors that could affect our results contained in Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” of our Annual Report on Form 10-K for the year ended December 31, 2018. These forward-looking statements speak only as of the date on which such statements were made, and we undertake no obligation to update these statements except as required by federal securities laws.

Overview

We are the world’s largest private-sector coal company by volume. In 2018, we produced and sold 182.1 million and 186.7 million tons of coal, respectively, from continuing operations. As of June 30, 2019, we owned interests in 23 coal mining operations located in the United States (U.S.) and Australia. We have a majority interest in 22 of those mining operations and a 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to our mining operations, we market and broker coal from other coal producers, both as principal and agent, and trade coal and freight-related contracts.

We conduct business through five operating segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Midwestern U.S. Mining and Western U.S. Mining. Refer to Note 20. “Segment Information” in the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of our Corporate and Other segment.

On June 18, 2019, we entered into a definitive implementation agreement (the Implementation Agreement) with Arch, to establish a joint venture that will combine the respective Powder River Basin and Colorado mining operations of Peabody and Arch. Pursuant to the terms of the Implementation Agreement, we will hold a 66.5% economic interest in the joint venture and Arch will hold a 33.5% economic interest. We expect to proportionally consolidate the entity based upon our economic interest. Governance of the joint venture will be overseen by the joint venture’s board of managers, which will be comprised of Peabody and Arch representatives with voting powers proportionate with the companies’ economic interests. We will manage the operations of the joint venture, subject to the supervision of the joint venture’s board of managers.

On December 3, 2018, we acquired the Shoal Creek metallurgical coal mine, preparation plant and supporting assets located in Alabama (Shoal Creek Mine) as further discussed in Note 3. “Acquisition of Shoal Creek Mine” to the accompanying unaudited condensed consolidated financial statements. Our results of operations include the Shoal Creek Mine’s results of operations for the three and six months ended June 30, 2019. The Shoal Creek Mine’s results are reflected in our Seaborne Metallurgical Mining segment.

Our North Goonyella Mine in Queensland, Australia experienced a fire in a portion of the mine during September 2018. Mining operations have been suspended since September 2018. No mine personnel were physically harmed by the September 2018 events. On November 13, 2018, the Queensland Mine Inspectorate (QMI) initiated an investigation into the events that occurred at the mine to determine the cause of the event, assess the response to it and make recommendations to reduce the possibility of future incidents and improve response. We are currently complying with information requests from the QMI.

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During the first quarter of 2019, we completed segmenting of the mine into multiple zones to facilitate a phased re-ventilation and re-entry of the mine. We commenced re-ventilation of the first zone of the mine during the second quarter of 2019 and subsequently re-entered the area in July 2019. Following these activities, additional information about the regulatory process and physical condition of the mine continued to emerge. Based on these changes, we are assessing prospective paths, timetables and costs to maximize value. Given ongoing activities, we have suspended North Goonyella guidance and intend to provide new targets around North Goonyella production timing and costs in accordance with the determined path. The company expects to complete its evaluation within the next three months.

We are targeting approximately $110 million in capital for North Goonyella Mine, including previously planned new longwall equipment. In addition, we expect cash outlays associated with leased equipment settlements.

During the year ended December 31, 2018, we recorded $58.0 million in containment and idling costs related to the events at North Goonyella Mine and a provision of $66.4 million for expected equipment losses. During the three and six months ended June 30, 2019, we recorded an additional $28.4 million and $65.3 million, respectively, in containment and idling costs, and an additional provision of $24.7 million related to equipment losses was recorded during the six months ended June 30, 2019 as more information became available. The combined provision includes $50.7 million for the estimated cost to replace leased equipment, $23.2 million related to the cost of Company-owned equipment and $17.2 million of other charges, which represents the best estimate of potential loss based on the assessments made to date.

In March 2019, we entered into an insurance claim settlement agreement with our insurers and various re-insurers under a combined property damage and business interruption policy and recorded a $125 million insurance recovery, the maximum amount available under the policy above a $50 million deductible. We have collected the full amount of the recovery.

On April 30, 2019, Peabody (Bowen) Pty Ltd entered into an option exercise and release agreement with Yancoal Technology Development Pty Ltd pursuant to which Peabody (Bowen) Pty Ltd exercised an option to acquire from Yancoal Technology Development Pty Ltd the longwall mining equipment used under license at the North Goonyella Mine for $54.2 million, which was consistent with our provision for equipment losses for the related impaired assets.

Results of Operations

Non-GAAP Financial Measures

The following discussion of our results of operations includes references to and analysis of Adjusted EBITDA, which is a financial measure not recognized in accordance with U.S. generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of our segments’ operating performance.

Also included in the following discussion of our results of operations are references to Revenues per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each mining segment. These metrics are used by management to measure each of our mining segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the mining segment level. We consider all measures reported on a per ton basis to be operating/statistical measures; however, we include reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2.

In our discussion of liquidity and capital resources, we include references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of our financial performance and our ability to generate excess cash flow from our business operations.

We believe non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2 for definitions and reconciliations to the most comparable measures under U.S. GAAP.

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Three and Six Months Ended June 30, 2019 Compared to the Three and Six Months Ended June 30, 2018

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 API 5 thermal coal, and prompt month pricing for Powder River Basin (PRB) 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended June 30, 2019 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.

The seaborne pricing included in the table below is not necessarily indicative of the pricing we realized during the three months ended June 30, 2019 due to quality differentials and the majority of our seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Our typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.

In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing we realized during the three months ended June 30, 2019 since we generally sell coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from alternative fuels such as natural gas and other coal producers may also impact our realized pricing.



	High		Low		Average		June 30, 2019
Premium HCC ⁽¹⁾	$	209.80	$	193.60	$	202.60	$	193.60
Premium PCI coal ⁽¹⁾	$	128.65	$	119.35	$	124.74	$	121.85
Newcastle index thermal coal ⁽¹⁾	$	89.34	$	68.81	$	80.12	$	68.81
API 5 thermal coal ⁽¹⁾	$	61.10	$	50.78	$	57.05	$	50.78
PRB 8,800 Btu/Lb coal ⁽²⁾	$	12.55	$	12.10	$	12.19	$	12.10
Illinois Basin 11,500 Btu/Lb coal ⁽²⁾	$	43.00	$	38.85	$	40.30	$	38.85


⁽¹⁾	Prices expressed per tonne.


⁽²⁾	Prices expressed per ton.

With respect to seaborne metallurgical coal, global steel production increased approximately 5% through the six months ended June 30, 2019 as compared to the prior year period. India imports increased approximately 7% as compared to the prior year, amid steel production growth of approximately 2% year-over-year through June 30, 2019. Steel production in China increased approximately 10% through the six months ended June 30, 2019 as compared to the prior year resulting in an approximate 22% increase in coking coal imports during the same period. China’s steel production continues to be fueled by infrastructure spending. While fundamentals are strong, China’s seaborne demand will remain dependent on the country’s import policies.

Seaborne thermal coal demand and pricing was subdued due to restrictions in China and low gas prices coupled with elevated stockpiles in Europe, despite robust demand from India and other Asian regions. Chinese thermal coal imports were flat at approximately 118 million tonnes, through the six months ended June 30, 2019, as compared to the prior year. China’s domestic production has been constrained by heightened mine safety inspections leading to a modest 3% increase in production through the six months ended June 30, 2019, as compared to the prior year period. India’s domestic production increased approximately 5% through the six months ended June 30, 2019, but was not sufficient to meet growing demand from the industrial and power sector. As a result, India’s thermal coal imports have increased by approximately 16% or 13 million tonnes year-over-year through June 30, 2019. Demand from countries comprising the Association of Southeast Asian Nations (ASEAN) increased 11 million tonnes, primarily led by Vietnam.

In the United States, overall electricity demand was down year-over-year through the six months ended June 30, 2019. This combination of lower demand, continued coal plant retirements and weak natural gas prices has negatively impacted coal generation. Through the six months ended June 30, 2019, utility consumption of PRB coal fell approximately 13% as compared to the prior year due to ongoing pressure from retirements and regional natural gas prices that continue to trade at a discount to quoted Henry Hub natural gas spot prices. In addition, continued transportation disruptions in the upper Great Plains due to heavy flooding led to reduced rail shipments and production of PRB coal, down approximately 7% year-over-year through the six months ended June 30, 2019.

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Our revenues for the three and six months ended June 30, 2019 decreased as compared to the same period in 2018 ($160.4 million and $372.5 million, respectively) primarily due to lower sales volumes and realized prices. Our Seaborne Metallurgical Mining segment was adversely impacted by the events at our North Goonyella Mine described above, as well as other production factors, partially offset by volume from our Shoal Creek Mine. Our Powder River Basin Mining and Midwestern U.S. Mining segments were adversely impacted by delays in rail shipments caused by severe flooding.

Income from continuing operations, net of income taxes for the three and six months ended June 30, 2019 decreased as compared to the same period in the prior year ($77.1 million and $152.1 million, respectively). The decrease was driven by the unfavorable revenue variances described above, as well as lower income from equity affiliates due to production issues at the Middlemount Mine (three months, $15.5 million; six months, $34.0 million), lower gains on disposals in the current year (six months, $27.3 million), a provision for equipment losses at our North Goonyella Mine (six months, $24.7 million) and bankruptcy-related claims settlement gains recorded in the prior year (six months, $12.8 million). These unfavorable variances were partially offset by reduced operating costs and expenses owing largely to the sales volume decline as well as production efficiencies and other cost improvements (three months, $88.3 million; six months, $197.1 million), an insurance recovery related to the events at our North Goonyella Mine (six months, $125.0 million) and lower selling and administrative expenses (three months, $5.2 million; six months, $5.5 million).

The decrease in net income attributable to common stockholders during the six months ended June 30, 2019 as compared to the same period in 2018 was partially offset by dividends ($102.5 million) recorded in the prior year period related to the convertible preferred stock issued in connection with our bankruptcy exit. Adjusted EBITDA for the three and six months ended June 30, 2019 reflected a year-over-year decrease of $141.6 million and $251.6 million, respectively.

As of June 30, 2019, our available liquidity was approximately $1.20 billion. Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of factors affecting our available liquidity.

Tons Sold

The following table presents tons sold by operating segment:



	Three Months Ended		Decrease				Six Months Ended		Increase (Decrease)
	June 30,		to Volumes				June 30,		to Volumes
	2019	2018	Tons		%		2019	2018	Tons		%
	(Tons in millions)						(Tons in millions)
Seaborne Thermal Mining	4.7	5.0	(0.3	)	(6	)%	9.2	8.8	0.4		5	%
Seaborne Metallurgical Mining	2.1	2.9	(0.8	)	(28	)%	4.4	5.9	(1.5	)	(25	)%
Powder River Basin Mining	25.0	26.2	(1.2	)	(5	)%	50.3	58.6	(8.3	)	(14	)%
Midwestern U.S. Mining	3.9	4.7	(0.8	)	(17	)%	8.1	9.4	(1.3	)	(14	)%
Western U.S. Mining	3.3	3.5	(0.2	)	(6	)%	7.0	7.2	(0.2	)	(3	)%
Total tons sold from mining segments	39.0	42.3	(3.3	)	(8	)%	79.0	89.9	(10.9	)	(12	)%
Corporate and Other	0.4	0.8	(0.4	)	(50	)%	0.9	1.5	(0.6	)	(40	)%
Total tons sold	39.4	43.1	(3.7	)	(9	)%	79.9	91.4	(11.5	)	(13	)%

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Supplemental Financial Data

The following table presents supplemental financial data by operating segment:



	Three Months Ended				(Decrease)					Six Months Ended				(Decrease)
	June 30,				Increase					June 30,				Increase
	2019		2018		$			%		2019		2018		$			%

Revenues per Ton - Mining Operations ⁽¹⁾
Seaborne Thermal	$	46.41	$	53.68	$	(7.27	)	(14	)%	$	51.18	$	53.57	$	(2.39	)	(4	)%
Seaborne Metallurgical	138.42		143.98		(5.56		)	(4	)%	140.45		148.58		(8.13		)	(5	)%
Powder River Basin	11.33		12.24		(0.91		)	(7	)%	11.34		12.12		(0.78		)	(6	)%
Midwestern U.S.	42.47		42.12		0.35			1	%	42.56		42.39		0.17			—	%
Western U.S.	43.73		39.87		3.86			10	%	42.66		39.40		3.26			8	%
Costs per Ton - Mining Operations ⁽¹⁾⁽²⁾
Seaborne Thermal	$	30.73	$	32.05	$	(1.32	)	(4	)%	$	32.82	$	34.23	$	(1.41	)	(4	)%
Seaborne Metallurgical ⁽³⁾	111.12		89.37		21.75			24	%	107.77		93.96		13.81			15	%
Powder River Basin	9.72		9.88		(0.16		)	(2	)%	9.82		9.79		0.03			—	%
Midwestern U.S.	34.66		33.16		1.50			5	%	34.70		34.61		0.09			—	%
Western U.S.	27.59		30.21		(2.62		)	(9	)%	29.04		30.24		(1.20		)	(4	)%
Adjusted EBITDA Margin per Ton - Mining Operations ⁽¹⁾⁽²⁾
Seaborne Thermal	$	15.68	$	21.63	$	(5.95	)	(28	)%	$	18.36	$	19.34	$	(0.98	)	(5	)%
Seaborne Metallurgical ⁽³⁾	27.30		54.61		(27.31		)	(50	)%	32.68		54.62		(21.94		)	(40	)%
Powder River Basin	1.61		2.36		(0.75		)	(32	)%	1.52		2.33		(0.81		)	(35	)%
Midwestern U.S.	7.81		8.96		(1.15		)	(13	)%	7.86		7.78		0.08			1	%
Western U.S.	16.14		9.66		6.48			67	%	13.62		9.16		4.46			49	%


⁽¹⁾	This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.

⁽²⁾

Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; provision for North Goonyella equipment loss and related insurance recovery; amortization of fresh start reporting adjustments related to take-or-pay contract-based intangibles; and certain other costs related to post-mining activities.


⁽³⁾	The events at the North Goonyella Mine resulted in additional Costs per Ton and lower Adjusted EBITDA Margin per Ton for Seaborne Metallurgical of $13.51 and $7.17 for the three and six months ended June 30, 2019, respectively.

Revenues

The following table presents revenues by reporting segment:



	Three Months Ended					(Decrease) Increase					Six Months Ended				Increase (Decrease)
	June 30,					to Revenues					June 30,				to Revenues
	2019		2018			$			%		2019		2018		$			%
	(Dollars in millions)										(Dollars in millions)
Seaborne Thermal Mining	$	220.2	$	267.4		$	(47.2	)	(18	)%	$	471.2	$	468.8	$	2.4		1	%
Seaborne Metallurgical Mining	290.9		417.5			(126.6		)	(30	)%	615.4		883.7		(268.3		)	(30	)%
Powder River Basin Mining	282.6		321.5			(38.9		)	(12	)%	569.9		710.8		(140.9		)	(20	)%
Midwestern U.S. Mining	167.5		197.5			(30.0		)	(15	)%	346.6		399.2		(52.6		)	(13	)%
Western U.S. Mining	142.1		139.6			2.5			2	%	297.8		283.3		14.5			5	%
Corporate and Other	45.7		(34.1		)	79.8			234	%	98.7		26.3		72.4			275	%
Revenues	$	1,149.0	$	1,309.4		$	(160.4	)	(12	)%	$	2,399.6	$	2,772.1	$	(372.5	)	(13	)%

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Seaborne Thermal Mining. Segment revenues decreased during the three months ended June 30, 2019 compared to the same period in the prior year due to unfavorable realized coal pricing ($28.1 million) and unfavorable volume and mix variances ($19.1 million) resulting from various mine sequencing impacts. Segment revenues increased during the six months ended June 30, 2019 compared to the same period in the prior year due to favorable volume and mix variances (0.4 million tons, $28.9 million), mostly offset by unfavorable realized coal pricing ($26.5 million).

Seaborne Metallurgical Mining. Segment revenues decreased during the three and six months ended June 30, 2019 compared to the same periods in the prior year primarily due to unfavorable volumes (three months, 0.8 million tons, $109.9 million; six months, 1.5 million tons, $244.5 million). The unfavorable volume variance resulting from the transition to highwall mining at our Millennium Mine in September 2018, a longwall move at our Metropolitan Mine and various mine sequencing impacts (three months, 0.9 million tons, $119.5 million; six months, 1.5 million tons, $198.0 million) and no current year volume from our North Goonyella Mine (three months, 0.6 million tons, $104.9 million; six months, 1.4 million tons, $277.2 million) was partially offset by volume provided by our Shoal Creek Mine, acquired in December 2018 (three months, 0.7 million tons, $114.5 million; six months, 1.4 million tons, $230.7 million). Segment revenues were further impacted by lower realized pricing (three months, $16.7 million; six months, $23.8 million).

Powder River Basin Mining. Segment revenues decreased during the three and six months ended June 30, 2019 compared to the same periods in the prior year due to lower volume primarily attributable to railroad closures and delays that resulted from severe flooding across the upper Great Plains and partially attributable to demand-based decline (three months, $20.5 million; six months, $109.6 million) and unfavorable realized pricing (three months, $18.4 million; six months, $31.3 million).

Midwestern U.S. Mining. Segment revenues decreased during the three and six months ended June 30, 2019 compared to the same periods in the prior year primarily due to lower volume (three months, $29.7 million; six months, $53.1 million) attributable to limited shipments caused by heavy rainfall throughout the Midwest and demand-based decline.

Western U.S. Mining. Segment revenues increased during the three and six months ended June 30, 2019 compared to the same periods in the prior year as favorable realized pricing, primarily from our Kayenta Mine (three months, $7.5 million; six months, $22.1 million), outpaced an unfavorable volume and mix variance (three months, $5.0 million; six months $7.6 million).

Corporate and Other. Segment revenues increased during the three and six months ended June 30, 2019 compared to the same periods in the prior year primarily due to improved results on economic hedges.

Adjusted EBITDA

The following table presents Adjusted EBITDA for each of our reporting segments:



	Three Months Ended						(Decrease) Increase					Six Months Ended						(Decrease) Increase
	June 30,						to Segment Adjusted EBITDA					June 30,						to Segment Adjusted EBITDA
	2019			2018			$			%		2019			2018			$			%
	(Dollars in millions)											(Dollars in millions)
Seaborne Thermal Mining	$	74.4		$	107.6		$	(33.2	)	(31	)%	$	169.1		$	169.2		$	(0.1	)	—	%
Seaborne Metallurgical Mining	57.4			158.5			(101.1		)	(64	)%	143.2			324.9			(181.7		)	(56	)%
Powder River Basin Mining	40.2			62.0			(21.8		)	(35	)%	76.6			136.5			(59.9		)	(44	)%
Midwestern U.S. Mining	30.7			42.0			(11.3		)	(27	)%	64.0			73.2			(9.2		)	(13	)%
Western U.S. Mining	52.4			33.9			18.5			55	%	95.0			65.9			29.1			44	%
Corporate and Other	(27.1		)	(34.4		)	7.3			21	%	(66.0		)	(36.2		)	(29.8		)	(82	)%
Adjusted EBITDA ⁽¹⁾	$	228.0		$	369.6		$	(141.6	)	(38	)%	$	481.9		$	733.5		$	(251.6	)	(34	)%


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

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Seaborne Thermal Mining. Segment Adjusted EBITDA decreased during the three months ended June 30, 2019 compared to the same period in the prior year as a result of lower realized net coal pricing ($25.9 million) and unfavorable volume variances ($11.4 million), partially offset by favorable foreign currency impacts ($6.7 million) and favorable cost performance from our thermal surface mines ($1.7 million). Segment Adjusted EBITDA decreased during the six months ended June 30, 2019 compared to the same period in the prior year as a result of lower realized net coal pricing ($24.5 million) and unfavorable mine sequencing impacts among our thermal surface mines ($10.1 million), offset by improved longwall performance at our Wambo Underground Mine ($15.4 million) and favorable foreign currency impacts ($14.5 million).

Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2019 as compared to the same periods in the prior year due to unfavorable volume variances as described above (three months, $34.2 million; six months, $110.0 million). The impact of no current year volume from our North Goonyella Mine (three months, $42.2 million; six months, $136.9 million) was offset by the volume provided by our Shoal Creek Mine (three months, $61.7 million; six months, $110.4 million). The decrease in Segment Adjusted EBITDA was further impacted by the net containment and holding costs at our North Goonyella Mine (three months, $28.4 million; six months, $31.4 million), the impact of a longwall move at our Metropolitan Mine (three months, $28.1 million; six months, $7.2 million), lower net realized pricing (three months, $15.1 million; six months, $21.4 million) and mine sequencing impacts among our metallurgical surface operations (three months, $8.6 million; six months, $21.2 million). These negative variances were partially offset by favorable foreign currency impacts (three months, $14.5 million; six months, $28.6 million).

Powder River Basin Mining. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2019 as compared to the same periods in the prior year due to higher costs for materials, services and repairs (three months, $10.3 million), the impact of lower volume (three months, $8.8 million; six months, $52.9 million) primarily attributable to railroad closures and delays that resulted from severe flooding across the upper Great Plains and lower net realized coal pricing (three months, $7.3 million; six months, $12.8 million), partially offset by lower lease expenses due to early lease buyouts (three months, $3.5 million; six months, $6.7 million).

Midwestern U.S. Mining. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2019 as compared to the same periods in the prior year primarily due to the impact of lower volume (three months, $5.8 million; six months, $7.1 million), mine sequencing impacts (three months, $3.6 million; six months, $5.8 million) and higher costs for materials, services and repairs (three months, $2.3 million), partially offset by higher net realized coal pricing (three months, $1.1 million; six months, $3.1 million).

Western U.S. Mining. Segment Adjusted EBITDA increased during the three and six months ended June 30, 2019 as compared to the same periods in the prior year primarily due to higher net realized coal pricing (three months, $6.8 million; six months, $16.4 million), lower costs for materials, services and repairs (three months, $4.4 million; six months, $13.5 million) and mine sequencing (three months, $3.9 million).

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Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:



	Three Months Ended						(Decrease) Increase					Six Months Ended						(Decrease) Increase
	June 30,						to Adjusted EBITDA					June 30,						to Adjusted EBITDA
	2019			2018			$			%		2019			2018			$			%
	(Dollars in millions)											(Dollars in millions)
Middlemount ⁽¹⁾	$	10.0		$	17.2		$	(7.2	)	(42	)%	$	13.9		$	31.8		$	(17.9	)	(56	)%
Resource management activities ⁽²⁾	1.7			0.7			1.0			143	%	3.7			21.5			(17.8		)	(83	)%
Selling and administrative expenses	(38.9		)	(44.1		)	5.2			12	%	(75.6		)	(81.1		)	5.5			7	%
Transaction costs related to business combinations and joint ventures	(1.6		)	—			(1.6		)	n.m.		(1.6		)	—			(1.6		)	n.m.
Other items, net ⁽³⁾	1.7			(8.2		)	9.9			121	%	(6.4		)	(8.4		)	2.0			24	%
Corporate and Other Adjusted EBITDA	$	(27.1	)	$	(34.4	)	$	7.3		21	%	$	(66.0	)	$	(36.2	)	$	(29.8	)	(82	)%

⁽¹⁾

Middlemount’s results are before the impact of related changes in deferred tax asset valuation allowance and reserves and 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 $9.5 million and $14.2 million during the three months ended June 30, 2019 and 2018, respectively, and $17.0 million and $26.8 million during the six months ended June 30, 2019 and 2018, respectively.


⁽²⁾	Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues.


⁽³⁾	Includes trading and brokerage activities, costs associated with post-mining activities, certain coal royalty expenses, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts and expenses related to our other commercial activities.

During the three months ended June 30, 2019, Corporate and Other Adjusted EBITDA increased as compared to the same period in the prior year primarily due to favorable results from trading and brokerage activities and lower selling and administrative expenses for outside services. These favorable results were partially offset by an unfavorable variance in the results of Middlemount due primarily to highwall production issues and transaction costs related to the proposed PRB Colorado joint venture with Arch as further described in Note 16. “Other Events” of the accompanying unaudited condensed consolidated financial statements.

During the six months ended June 30, 2019, Corporate and Other Adjusted EBITDA declined as compared to the same period in the prior year primarily due to a $20.6 million resource management gain recorded in the prior year period related to the sale of surplus land assets in Queensland’s Bowen Basin, an unfavorable variance in the results of Middlemount due primarily to highwall production issues and a $7.1 million gain recorded in the prior year period related to the sale of our 50% interest in the Red Mountain Joint Venture with BHP Billiton Mitsui Coal Pty Ltd, as further described in Note 16. “Other Events” of the accompanying unaudited condensed consolidated financial statements. These unfavorable results were partially offset by favorable results from trading and brokerage activities and lower selling and administrative expenses for outside services.

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Income From Continuing Operations, Net of Income Taxes

The following table presents income from continuing operations, net of income taxes:



	Three Months Ended						(Decrease) Increase					Six Months Ended						(Decrease) Increase
	June 30,						to Income					June 30,						to Income
	2019			2018			$			%		2019			2018			$			%
	(Dollars in millions)											(Dollars in millions)
Adjusted EBITDA ⁽¹⁾	$	228.0		$	369.6		$	(141.6	)	(38	)%	$	481.9		$	733.5		$	(251.6	)	(34	)%
Depreciation, depletion and amortization	(165.4		)	(163.9		)	(1.5		)	(1	)%	(337.9		)	(333.5		)	(4.4		)	(1	)%
Asset retirement obligation expenses	(15.3		)	(13.2		)	(2.1		)	(16	)%	(29.1		)	(25.5		)	(3.6		)	(14	)%
Provision for North Goonyella equipment loss	—			—			—			n.m.		(24.7		)	—			(24.7		)	n.m.
North Goonyella insurance recovery - equipment	—			—			—			n.m.		91.1			—			91.1			n.m.
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates	(0.3		)	8.4			(8.7		)	(104	)%	(0.3		)	16.0			(16.3		)	(102	)%
Interest expense	(36.0		)	(38.3		)	2.3			6	%	(71.8		)	(74.6		)	2.8			4	%
Loss on early debt extinguishment	—			(2.0		)	2.0			100	%	—			(2.0		)	2.0			100	%
Interest income	7.2			7.0			0.2			3	%	15.5			14.2			1.3			9	%
Reorganization items, net	—			—			—			n.m.		—			12.8			(12.8		)	(100	)%
Unrealized gains (losses) on economic hedges	22.4			(48.1		)	70.5			147	%	62.2			(9.5		)	71.7			755	%
Unrealized (losses) gains on non-coal trading derivative contracts	(0.3		)	0.1			(0.4		)	(400	)%	(0.1		)	(1.7		)	1.6			94	%
Fresh start take-or-pay contract-based intangible recognition	5.6			7.8			(2.2		)	(28	)%	11.2			16.1			(4.9		)	(30	)%
Income tax provision	(3.0		)	(7.4		)	4.4			59	%	(21.8		)	(17.5		)	(4.3		)	(25	)%
Income from continuing operations, net of income taxes	$	42.9		$	120.0		$	(77.1	)	(64	)%	$	176.2		$	328.3		$	(152.1	)	(46	)%


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

Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment:



	Three Months Ended						Increase (Decrease)					Six Months Ended						(Decrease) Increase
	June 30,						to Income					June 30,						to Income
	2019			2018			$			%		2019			2018			$			%
	(Dollars in millions)											(Dollars in millions)
Seaborne Thermal Mining	$	(22.0	)	$	(23.5	)	$	1.5		6	%	$	(45.2	)	$	(42.5	)	$	(2.7	)	(6	)%
Seaborne Metallurgical Mining	(31.1		)	(33.6		)	2.5			7	%	(71.2		)	(64.9		)	(6.3		)	(10	)%
Powder River Basin Mining	(36.0		)	(45.2		)	9.2			20	%	(72.6		)	(96.2		)	23.6			25	%
Midwestern U.S. Mining	(25.4		)	(25.9		)	0.5			2	%	(47.5		)	(55.8		)	8.3			15	%
Western U.S. Mining	(48.3		)	(33.6		)	(14.7		)	(44	)%	(97.0		)	(68.9		)	(28.1		)	(41	)%
Corporate and Other	(2.6		)	(2.1		)	(0.5		)	(24	)%	(4.4		)	(5.2		)	0.8			15	%
Total	$	(165.4	)	$	(163.9	)	$	(1.5	)	(1	)%	$	(337.9	)	$	(333.5	)	$	(4.4	)	(1	)%

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Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Seaborne Thermal Mining	$	1.97	$	1.93	$	1.89	$	1.86
Seaborne Metallurgical Mining	3.47		1.31		3.01		1.00
Powder River Basin Mining	0.80		0.81		0.81		0.81
Midwestern U.S. Mining	0.82		0.86		0.89		0.86
Western U.S. Mining	2.30		2.17		2.24		2.31

Depreciation, depletion and amortization expense increased during the three and six months ended June 30, 2019 as compared to the same periods in the prior year primarily due to the acceleration of the planned closure of the Kayenta Mine (three months, $14.8 million; six months, $27.3 million) and the acquisition the Shoal Creek Mine in the fourth quarter of 2018 (three months, $14.2 million; six months, $25.5 million), partially offset by lower amortization of the fair value of certain U.S. coal supply agreements (three months, $18.2 million; six months, $39.3 million) and decreased expense at our North Goonyella Mine after the fire due to lower sales volumes and asset impairments (three months, $6.3 million; six months, $10.4 million).

Provision for North Goonyella Equipment Loss. A provision of $24.7 million was recorded during the six months ended June 30, 2019 for expected equipment losses related to the events at our North Goonyella Mine, as discussed in Note 16. “Other Events” in the accompanying unaudited condensed consolidated financial statements. The current year provision is incremental to similar provisions recorded during 2018 and represents the best estimate of potential loss associated with these events based on assessments made to date.

North Goonyella Insurance Recovery - Equipment. During the six months ended June 30, 2019, we entered into an insurance claim settlement agreement with our insurance providers related to North Goonyella equipment losses and recorded a $125.0 million insurance recovery, as discussed in Note 16. “Other Events” in the accompanying unaudited condensed consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the six months ended June 30, 2019 and the year ended December 31, 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the six months ended June 30, 2019.

Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates. During the year ended December 31, 2018 the Company determined that a valuation allowance on Middlemount’s net deferred tax position was no longer necessary based on recent cumulative earnings and expectation of future earnings. The prior period amount consisted of the valuation allowance reduction due to income earned by Middlemount prior to the release of the valuation allowance.

Loss on Early Debt Extinguishment. The loss on early debt extinguishment recorded during the three and six months ended June 30, 2018, related to the early repayment of principal under our Senior Secured Term Loan as described in Note 13. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements.

Reorganization Items, Net. The reorganization items recorded during the six months ended June 30, 2018 were impacted by a favorable adjustment to our former bankruptcy claims accrual.

Unrealized Gains (Losses) on Economic Hedges. Unrealized gains (losses) primarily relate to mark-to-market activity from economic hedge activities intended to hedge future coal sales. For additional information, refer to Note 8. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements.

Fresh Start Take-or-Pay Contract-Based Intangible Recognition. Included in the fresh start reporting adjustments were contract-based intangible liabilities for port and rail take-or-pay contracts. During the three and six months ended June 30, 2019 and 2018, we ratably recognized these contract-based intangible liabilities. For additional details, refer to Note 9. “Intangible Contract Assets and Liabilities” to the accompanying unaudited condensed consolidated financial statements.

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Income Tax Provision. The changes in the income tax provision for the three and six months ended June 30, 2019 as compared to the prior year periods was primarily due to changes in forecasted taxable income. The tax provisions recorded in the three and six months ended June 30, 2019 and 2018 were computed using the annual effective tax rate method and were comprised primarily of the expected statutory tax provision offset by foreign rate differential and changes in valuation allowances.

Refer to Note 12. “Income Taxes” in the accompanying unaudited condensed consolidated financial statements for additional information.

Net Income Attributable to Common Stockholders

The following table presents net income attributable to common stockholders:



	Three Months Ended						(Decrease) Increase					Six Months Ended						(Decrease) Increase
	June 30,						to Income					June 30,						to Income
	2019			2018			$			%		2019			2018			$			%
	(Dollars in millions)											(Dollars in millions)
Income from continuing operations, net of income taxes	$	42.9		$	120.0		$	(77.1	)	(64	)%	$	176.2		$	328.3		$	(152.1	)	(46	)%
Loss from discontinued operations, net of income taxes	(3.4		)	(3.6		)	0.2			6	%	(6.8		)	(4.9		)	(1.9		)	(39	)%
Net income	39.5			116.4			(76.9		)	(66	)%	169.4			323.4			(154.0		)	(48	)%
Less: Series A Convertible Preferred Stock dividends	—			—			—			n.m.		—			102.5			(102.5		)	(100	)%
Less: Net income attributable to noncontrolling interests	2.4			2.7			(0.3		)	(11	)%	8.1			0.6			7.5			1,250	%
Net income attributable to common stockholders	$	37.1		$	113.7		$	(76.6	)	(67	)%	$	161.3		$	220.3		$	(59.0	)	(27	)%

Series A Convertible Preferred Stock Dividends. The convertible preferred stock dividends for the six months ended June 30, 2018 were comprised of the deemed dividends granted for all remaining shares of convertible preferred stock that were converted as of January 31, 2018.

Net Income Attributable to Noncontrolling Interests. The increase in net income attributable to noncontrolling interests for the six months ended June 30, 2019 as compared to the same period in the prior year was due to the improved results of our majority-owned mines in which there is an outside non-controlling interest.

Diluted Earnings per Share (EPS)

The following table presents diluted EPS:



	Three Months Ended						Decrease					Six Months Ended						Decrease
	June 30,						to EPS					June 30,						to EPS
	2019			2018			$			%		2019			2018			$			%
Diluted EPS attributable to common stockholders:
Income from continuing operations	$	0.37		$	0.93		$	(0.56	)	(60	)%	$	1.54		$	1.76		$	(0.22	)	(13	)%
Loss from discontinued operations	(0.03		)	(0.03		)	—			—	%	(0.06		)	(0.04		)	(0.02		)	(50	)%
Net income attributable to common stockholders	$	0.34		$	0.90		$	(0.56	)	(62	)%	$	1.48		$	1.72		$	(0.24	)	(14	)%

Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 108.1 million and 126.0 million for the three months ended June 30, 2019 and 2018, respectively, and 109.3 million and 124.6 million for the six months ended June 30, 2019 and 2018, respectively.

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Reconciliation of Non-GAAP Financial Measures

Adjusted EBITDA is defined as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses, depreciation, depletion and amortization and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of our segment’s operating performance, as displayed in the reconciliations below.



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
	(Dollars in millions)
Income from continuing operations, net of income taxes	$	42.9		$	120.0		$	176.2		$	328.3
Depreciation, depletion and amortization	165.4			163.9			337.9			333.5
Asset retirement obligation expenses	15.3			13.2			29.1			25.5
Provision for North Goonyella equipment loss	—			—			24.7			—
North Goonyella insurance recovery - equipment	—			—			(91.1		)	—
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates	0.3			(8.4		)	0.3			(16.0		)
Interest expense	36.0			38.3			71.8			74.6
Loss on early debt extinguishment	—			2.0			—			2.0
Interest income	(7.2		)	(7.0		)	(15.5		)	(14.2		)
Reorganization items, net	—			—			—			(12.8		)
Unrealized (gains) losses on economic hedges	(22.4		)	48.1			(62.2		)	9.5
Unrealized losses (gains) on non-coal trading derivative contracts	0.3			(0.1		)	0.1			1.7
Fresh start take-or-pay contract-based intangible recognition	(5.6		)	(7.8		)	(11.2		)	(16.1		)
Income tax provision	3.0			7.4			21.8			17.5
Total Adjusted EBITDA	$	228.0		$	369.6		$	481.9		$	733.5

Revenues per Ton and Adjusted EBITDA Margin per Ton are equal to revenues by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to Revenues per Ton less Adjusted EBITDA Margin per Ton, and are reconciled to operating costs and expenses as follows:



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2019			2018		2019			2018
	(Dollars in millions)
Operating costs and expenses	$	858.2		$	946.5	$	1,806.6		$	2,003.7
Unrealized (losses) gains on non-coal trading derivative contracts	(0.3		)	0.1		(0.1		)	(1.7		)
Fresh start take-or-pay contract-based intangible recognition	5.6			7.8		11.2			16.1
North Goonyella insurance recovery - cost recovery and business interruption	—			—		(33.9		)	—
Net periodic benefit costs, excluding service cost	4.8			4.6		9.7			9.1
Total Reporting Segment Costs	$	868.3		$	959.0	$	1,793.5		$	2,027.2

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The following table presents Reporting Segment Costs by reporting segment:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(Dollars in millions)
Seaborne Thermal Mining	$	145.8	$	159.8	$	302.1	$	299.6
Seaborne Metallurgical Mining	233.5		259.0		472.2		558.8
Powder River Basin Mining	242.4		259.5		493.3		574.3
Midwestern U.S. Mining	136.8		155.5		282.6		326.0
Western U.S. Mining	89.7		105.7		202.8		217.4
Corporate and Other	20.1		19.5		40.5		51.1
Total Reporting Segment Costs	$	868.3	$	959.0	$	1,793.5	$	2,027.2

The following tables present revenues, Reporting Segment Costs, Adjusted EBITDA and tons sold by mining segment:



	Three Months Ended June 30, 2019
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining
	(Amounts in millions, except per ton data)
Revenues	$	220.2	$	290.9	$	282.6	$	167.5	$	142.1
Reporting Segment Costs	145.8		233.5		242.4		136.8		89.7
Adjusted EBITDA	74.4		57.4		40.2		30.7		52.4
Tons sold	4.7		2.1		25.0		3.9		3.3

Revenues per Ton	$	46.41	$	138.42	$	11.33	$	42.47	$	43.73
Costs per Ton	30.73		111.12		9.72		34.66		27.59
Adjusted EBITDA Margin per Ton	15.68		27.30		1.61		7.81		16.14



	Three Months Ended June 30, 2018
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining
	(Amounts in millions, except per ton data)
Revenues	$	267.4	$	417.5	$	321.5	$	197.5	$	139.6
Reporting Segment Costs	159.8		259.0		259.5		155.5		105.7
Adjusted EBITDA	107.6		158.5		62.0		42.0		33.9
Tons sold	5.0		2.9		26.2		4.7		3.5

Revenues per Ton	$	53.68	$	143.98	$	12.24	$	42.12	$	39.87
Costs per Ton	32.05		89.37		9.88		33.16		30.21
Adjusted EBITDA Margin per Ton	21.63		54.61		2.36		8.96		9.66

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	Six Months Ended June 30, 2019
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining
	(Amounts in millions, except per ton data)
Revenues	$	471.2	$	615.4	$	569.9	$	346.6	$	297.8
Reporting Segment Costs	302.1		472.2		493.3		282.6		202.8
Adjusted EBITDA	169.1		143.2		76.6		64.0		95.0
Tons sold	9.2		4.4		50.3		8.1		7.0

Revenues per Ton	$	51.18	$	140.45	$	11.34	$	42.56	$	42.66
Costs per Ton	32.82		107.77		9.82		34.70		29.04
Adjusted EBITDA Margin per Ton	18.36		32.68		1.52		7.86		13.62



	Six Months Ended June 30, 2018
	Seaborne Thermal Mining		Seaborne Metallurgical Mining		Powder River Basin Mining		Midwestern U.S. Mining		Western U.S. Mining
	(Amounts in millions, except per ton data)
Revenues	$	468.8	$	883.7	$	710.8	$	399.2	$	283.3
Reporting Segment Costs	299.6		558.8		574.3		326.0		217.4
Adjusted EBITDA	169.2		324.9		136.5		73.2		65.9
Tons sold	8.8		5.9		58.6		9.4		7.2

Revenues per Ton	$	53.57	$	148.58	$	12.12	$	42.39	$	39.40
Costs per Ton	34.23		93.96		9.79		34.61		30.24
Adjusted EBITDA Margin per Ton	19.34		54.62		2.33		7.78		9.16

Free Cash Flow is defined as net cash provided by operating activities less net cash used in investing activities and excludes cash outflows related to business combinations. See the table below for a reconciliation of Free Cash Flow to its most comparable measure under U.S. GAAP.



	Six Months Ended
	June 30,
	2019			2018

Net cash provided by operating activities	$	377.0		$	915.4
Net cash used in investing activities	(64.0		)	(18.0		)
Add back: Amount attributable to acquisition of Shoal Creek Mine	2.4			—
Free Cash Flow	$	315.4		$	897.4

Outlook

As part of its normal planning and forecasting process, Peabody utilizes a broad approach to develop macroeconomic assumptions for key variables, including country-level gross domestic product, industrial production, fixed asset investment and third-party inputs, driving detailed supply and demand projections for key demand centers for coal, electricity generation and steel. Specific to the U.S., the Company evaluates individual plant needs, including expected retirements, on a plant by plant basis in developing its demand models. Supply models and cost curves concentrate on major supply regions/countries that impact the regions in which the Company operates.

Our estimates involve risks and uncertainties and are subject to change based on various factors as described more fully in the “Cautionary Notice Regarding Forward-Looking Statements” section contained within this Item 2.

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

Near-Term Outlook

Seaborne Thermal Coal. Global seaborne thermal coal pricing further eased in the second quarter of 2019 due to high coal inventories and weak liquefied natural gas pricing in the Atlantic region, as well as strong Indonesian and Russian supplies. As a result, the average 6000-specification Newcastle thermal spot coal price declined 17% in the second quarter of 2019 as compared to the first quarter average, while the API 5-spec product eased only 4% over the same period. Relative to API 2, Newcastle pricing continues to command a premium given favorable transportation advantages and sustained demand from higher-growth Asian regions. Newcastle thermal prices are currently below the 10-year average, and prompt pricing has rebounded from lows experienced late in the second quarter of 2019.

Year-to-date China imports are on par with 2018 levels amid increasing import controls and domestic safety inspections. Year-to-date Indian imports have exceeded expectations, rising approximately 13 million tonnes, compared to the prior year period, driven by strong industrial demand. At the same time, ASEAN imports increased 11 million tonnes on stronger generation and additional coal-fueled power capacity in Vietnam, Malaysia and other Southeast Asian nations.

For 2019, Peabody expects Southeast Asian nation imports to drive thermal coal demand increases. In 2018, global coal-fueled generating capacity topped 2,000 gigawatts, the highest level ever and a 62% increase since 2000, and the deployment of an additional estimated 50 gigawatts of coal-fueled generation capacity is expected in 2019, primarily in Asia.

Seaborne Metallurgical Coal. China metallurgical coal imports rose 7 million tonnes year-to-date through June 30, 2019, as compared to the prior year period on strong steel growth and stimulus measures. Pricing has also been supported by steady India import demand and limited Australian and U.S. supply growth. Longer term, Peabody continues to expect India will lead the way in metallurgical coal demand growth.

Premium HCC spot pricing averaged $203 per tonne for the second quarter of 2019 and was at $194 per tonne on June 30, 2019, down $5 per tonne (-3%) year-over-year. As of August 2, 2019, the spot price for Premium HCC was $160 per tonne. Premium PCI spot pricing averaged $125 per tonne for the second quarter of 2019 and was at $122 per tonne on June 30,2019, down $14 per tonne (-10%) year-over-year. As of August 2, 2019, the spot price for Premium PCI was $105 per tonne.

Peabody anticipates global steel demand growth of approximately 2% in 2019, with increases in India leading to an estimated 3 million to 6 million tonne increase in global metallurgical coal imports. Supply increases are largely expected to be sourced from Australia.

U.S. Thermal Coal. In the U.S., total electricity generation load declined 2% year-over-year through the six months ended June 30, 2019, in part due to fewer heating and cooling degree days in the demand-heavy months of January and June relative to the prior year. In addition, flooding across the U.S. persisted in the second quarter, impacting rail shipments. As a result, coal production moderated 6%, with coal declining to 24% of the generation mix. Gas generation increased its share of the generation mix to 35% as pricing reached a three-year low of $2.19 per mmBtu on the back of production and storage builds that have exceeded expectations.

For 2019, we estimate domestic U.S. coal demand by U.S. utilities to be negatively impacted by lower natural gas prices and further coal plant retirements. U.S. thermal exports in 2019 are expected to be partially dependent on fluctuations in seaborne thermal pricing.

Long-Term Outlook

There were no significant changes to our Long-term Outlook subsequent to December 31, 2018. 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, 2018.

Regulatory Update

Other than as described in the following section, there were no significant changes to our regulatory matters subsequent to December 31, 2018. Information regarding our regulatory matters is outlined in Part I, Item 1. “Business” in our Annual Report on Form 10-K for the year ended December 31, 2018.

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Regulatory Matters - U.S.

Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect our U.S. coal mining operations both directly and indirectly.

Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to particulate matter (PM), nitrogen dioxide, ozone and sulfur dioxide (SO₂). In recent years the United States Environmental Protection Agency (EPA) has adopted more stringent national ambient air quality standards (NAAQS) for PM, nitrogen oxide, ozone and SO₂. It is possible that these modifications as well as future modifications to NAAQS could directly or indirectly impact our mining operations in a manner that includes, but is not limited to, designating new nonattainment areas or expanding existing nonattainment areas, serving as a basis for changes in vehicle emission standards or prompting additional local control measures pursuant to state implementation plans required to address revised NAAQS.

In 2009, the EPA adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. The PM NAAQS was thereafter revised and made more stringent in 2012. In 2015, the EPA issued a final rule setting the ozone NAAQS at 70 ppb. (80 Fed. Reg. 65,292, (Oct. 25, 2015)). This final rule has been challenged in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit), however, the case had been held in abeyance pending the EPA’s review of the final rule. In August 2018, the EPA said it would continue with the rule, meaning the lawsuit was revived and oral arguments were heard in the D.C. Circuit in December 2018.

The EPA is additionally considering revisions to the 2015 PM NAAQS as part of the periodic review process required by the CAA, with any revisions to the standards projected for late 2020, the same timeframe as it contemplates possible revisions for the 2015 ozone NAAQS. More stringent PM or ozone standards would require new state implementation plans to be developed and filed with the EPA and may trigger additional control technology for mining equipment or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to the implementation for other NAAQS for nitrogen oxide and SO₂ although the EPA promulgated a final rule on March 18, 2019 (84 Fed. Reg. 9866) that retains, without revision, the existing NAAQS for SO₂ of 75 ppb averaged over an hour.

The CAA also indirectly, but significantly affects the U.S. coal industry by extensively regulating the air emissions of SO₂, nitrogen oxides, mercury, PM and other substances emitted by coal-fueled electricity generating plants, imposing more capital and operating costs on such facilities. In addition, other CAA programs may require further emission reductions to address the interstate transport of air pollution or regional haze. The air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, interstate transport rules such as the Cross-State Air Pollution Rule (CSAPR) and the CSAPR Update Rule, New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and source permitting programs, including requirements related to New Source Review.

In addition, since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions. Regulations regarding reporting requirements for underground coal mines were updated in 2016 and now include the ability to cease reporting if mines are abandoned and sealed. At present, however, the EPA does not directly regulate such emissions.

EPA Regulation of Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electricity Utility Generating Units (EGUs). On October 23, 2015, the EPA published a final rule in the Federal Register regulating greenhouse gas emissions from existing fossil fuel-fired EGUs under section 111(d) of the CAA (80 Fed. Reg. 64,662 (Oct. 23, 2015)). The rule (known as the Clean Power Plan or CPP) establishes emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs. The CPP required that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline).

Following Federal Register publication, 39 separate petitions for review of the CPP by approximately 157 entities were filed in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The petitions reflect challenges by 27 states and governmental entities, as well as by utilities, industry groups, trade associations, coal companies and other entities. The lawsuits were consolidated with the case filed by West Virginia and Texas (in which other states also joined) (D.C. Cir. No. 15-1363). On October 29, 2015, we filed a motion to intervene in the case filed by West Virginia and Texas, in support of the petitioning states. The motion was granted on January 11, 2016. Numerous states and other entities also intervened in support of the EPA.

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On February 9, 2016, the U.S. Supreme Court granted a motion to stay implementation of the CPP until the legal challenges are resolved. Thereafter, oral arguments in the case were heard in the D.C. Circuit sitting en banc. On April 28, 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance while the agency reconsidered the rule. The D.C. Circuit case has been in abeyance since, so no opinion has been issued.

In October 2017, the EPA proposed to repeal the CPP. (82 Fed. Reg. 48,035 (Oct. 16, 2017)). In August 2018, the EPA issued a proposed rule to replace the CPP, the Affordable Clean Energy (ACE) Rule. (83 Fed. Reg. 44,746 (August 31, 2018)). On June 19, 2019, the EPA issued a combined package that finalizes the CPP repeal rule as well as the replacement rule, ACE. Repeal of the Clean Power Plan; Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units; Revisions to Emission Guidelines Implementing Regulations, EPA-HQ-OAR-2017-0355.

The final ACE rule sets emissions guidelines for greenhouse gas emissions from existing EGUs based on using efficiency heat rate improvements as “Best System of Emission Reduction” measures. The EPA’s final rule also revises the CAA Section 111(d) regulations to give the states greater flexibility on the content and timing of their state plans. Proposed revisions to the regulations under the New Source Review (NSR) program that were part of the ACE proposal have now been separated, and will be issued in a separate final rule later this year.

Based on the EPA’s final rules repealing and replacing the CPP, petitioners in the D.C. Circuit matter seeking review of CPP, including Peabody, filed a motion to dismiss. In addition, it is expected new litigation will be filed regarding ACE, as well as the CPP repeal action. Petitions for judicial review of the rules must be filed in the D.C. Circuit within 60 days from the date the rules are noticed in the Federal Register. (42 U.S.C. § 7607). As of this writing, the final rules have not yet been published in the Federal Register.

Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule. On July 6, 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in other states. Following litigation in the D.C. Circuit and U.S. Supreme Court, the first phase of the nitrogen oxide and SO₂ emissions reductions required by CSAPR commenced in January 2015; further reductions of both pollutants in the second phase of CSAPR became effective in January 2017. The EPA subsequently revised CSAPR requirements for the state of Texas to remove that state from second phase requirements regarding SO₂ (82 Fed. Reg. 45,481 (Sept. 29, 2017)).

On October 26, 2016, the EPA promulgated the CSAPR Update Rule to address implementation of the 2008 ozone national air quality standards. This rule imposed further reductions in nitrogen oxides in 2017 in 22 states subject to CSAPR. Several states and utilities as well as agricultural and industry groups have filed petitions for review of the CSAPR Update Rule in the D.C. Circuit. Other states and interest groups filed to intervene on behalf of the EPA; the petitions were then consolidated. D.C. Cir. No. 16-1406. Oral argument was held in October 2018 and a decision is pending.

In the meantime, on December 6, 2018, the EPA issued a final determination that the existing CSAPR Update fully addresses the CAA’s “good neighbor” requirements for 20 states with respect to the 2008 ground-level ozone standard. The final rule determines that 2023 is an appropriate future analytic year to evaluate further good neighbor requirements. As a result, these 20 states are not expected to contribute significantly to nonattainment or interfere with maintenance of the NAAQS in any other state. With this determination, the EPA has no obligation to establish additional requirements for sources in these states to further reduce transported ozone pollution under the 2008 ozone NAAQS. In addition, the covered states do not need to submit state implementation plans (SIPs) that would establish additional requirements beyond the existing CSAPR Update. This determination has been challenged in the D.C. Circuit (No. 19-1019). Oral argument has been scheduled for September 2019.

Mercury and Air Toxic Standards (MATS). The EPA published the final MATS rule in the Federal Register on February 16, 2012. The MATS rule revised the NSPS for nitrogen oxides, SO₂ and PM for new and modified coal-fueled electricity generating plants, and imposed MACT emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. The rule provided three years for compliance with MACT standards and a possible fourth year if a state permitting agency determined that such was necessary for the installation of controls.

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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 a proposed supplemental finding in the Federal Register that consideration of costs does not alter the EPA’s previous determination regarding the control of HAPs in the MATS rule. On December 15, 2015, the D.C. Circuit issued an order providing that the rule will remain in effect while the EPA responds to the U.S. Supreme Court decision.

On April 14, 2016, the EPA issued a final supplemental finding that largely tracked its proposed finding. Several states, companies and industry groups challenged that supplemental finding in the D.C. Circuit in separate petitions for review, which were subsequently consolidated (D.C. Cir. No. 116-1127). Several states and environmental groups also filed as intervenors for the respondent EPA. Although briefing in this litigation has concluded, the case remains in abeyance.

On December 27, 2018, the EPA issued a proposed revised Supplemental Cost Finding for the MATS rule that would revoke the determination that regulating HAPs from coal-fired power plants is “appropriate and necessary” under Section 112(n)(1)(A) of the CAA. The finding was based on an EPA assessment that health and environmental benefits from the MATS rule that are not directly related to mercury pollution should not be included in the benefit portion of the analysis. In the new proposed cost-benefit analysis, the EPA found the costs “grossly outweigh” any possible benefits. The comment period for this proposed rule has now closed, and the final rule is expected in November 2019.

Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.

The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain Corps permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.

States are empowered to develop and apply “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the CWA section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.

A final rule defining the scope of waters protected under the CWA (commonly called the Waters of the United States (WOTUS Rule)), was published by the EPA and the Corps in June 2015. As a result of litigation in numerous federal courts, the 2015 rule is currently in effect in 23 states and at least part of New Mexico. The pre-2015 rule is in effect in 26 states and perhaps certain counties in New Mexico because several district courts have preliminarily enjoined the 2015 rule, and those preliminary injunctions remain in effect pending the outcome of litigation on the merits of the 2015 rule. The EPA and the Corps are still in the process of repealing the 2015 WOTUS Rule and developing a replacement rule. The agencies proposed to repeal the 2015 Rule in July 2017, but they have not yet finalized a repeal action. A final rule is expected in late summer of 2019. Further, the EPA and the Corps issued a proposed rule in December 2018 offering a replacement definition of WOTUS. The proposal would remove federal protections for streams that flow only after rain or snowfall, as well as wetlands that do not have certain surface water connections to larger waterways. A public hearing on the rule was held in late February 2019. The public comment period on the proposed rule closed on April 15, 2019. Depending on the outcome of litigation and/or rulemaking activity, the scope of CWA authority could increase, decrease, or stay the same relative to the current, pre-2015 definitions of WOTUS, which could impact our operations in some areas.

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 April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit agreed with environmental groups that the portions of the rule regulating legacy wastewater and residual combustion leachate are unlawful. The Court vacated those portions of the rule. Separately, the EPA is reconsidering the portions of the rule regulating wastewater associated with flue gas desulfurization and bottom ash transport. The EPA expects to propose revisions to the 2015 rule in mid-2019, and it hopes to finalize any changes in 2020. The effluent limitations guidelines will significantly increase costs for many coal-fired steam electric power plants.

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Resource Conservation and Recovery Act (RCRA). RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are those from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA.

Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. On December 19, 2014, the EPA announced the final rule on coal combustion residuals (CCR or coal ash). As finalized, the rule continues the exemption of CCR from regulation as a hazardous waste, but does impose new requirements at existing CCR surface impoundments and landfills that will need to be implemented over a number of different time-frames in the coming months and years, as well as at new surface impoundments and landfills. The U.S. Court of Appeals for the D.C. Circuit held that certain provisions of the EPA’s CCR rule were not sufficiently protective, and it invalidated those provisions. The EPA is also weighing changes to other aspects of its rule. The EPA expects to issue final revisions to the rule at the end of 2019 or in 2020. Generally EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous. This EPA initiative is separate from the OSMRE CCR rulemaking mentioned above.

Regulatory Matters - Australia

Mining Tenements and Environmental. In February 2019, a decision of the New South Wales Land and Environment Court (LEC) refused planning approval for a non-Peabody coal mining project (Gloucester Resources Limited v Minister for Planning). That approval was refused for other reasons but the judge in that case did discuss downstream greenhouse gas emissions resulting from the consumption of coal to be mined under the proposed project. Such emissions are often raised as a ground of objection to Australian mining projects, including Peabody mining projects. However, to date no such objections have prevented a project from being approved and there has been a subsequent LEC decision in which the approval of a coal mining project was confirmed after such emissions had been considered by the relevant authority.

Queensland Reclamation. The Environmental Protection Act 1994 (EP Act) is administered by the Department of Environment and Science which authorizes environmentally relevant activities such as mining activities relating to a mining lease through an Environmental Authority (EA). Environmental protection and reclamation activities are regulated by conditions in the EA, including the requirement for the submission of a plan of operations (PO) prior to the commencement of operations. All mining operations must be carried out in accordance with the PO which describes site activities and the progress toward environmental and rehabilitation outcomes and are updated on a regular basis or if mine plans change. The mines submit an annual return reporting on their EA compliance including reclamation performance.

As a condition of the EA, bonding requirements are calculated to determine the amount of bonding required to cover the cost of reclamation based on the extent of disturbance during the PO period.

On November 19, 2018, the Queensland government passed the Mineral and Energy Resources (Financial Provisioning) Act 2018 providing for a new financial assurance (FA) framework and new progressive rehabilitation requirements. The new FA framework creates a pooled fund covering most mines and most of the total industry liability, plus other options for providing FA if not part of the pooled fund (for example, allowing insurance bonds or cash). The percentage rate of the total rehabilitation cost payable into the pooled fund will take into account the financial strength of the holder of the EA for the mine and the project strength of the mine. The total rehabilitation cost is determined using an updated rehabilitation cost calculator, which no longer provides for discounting. The commencement date for the new FA framework is April 1, 2019 and there will be a transitional period during which the Company will move each mine in Queensland into the new FA framework.

The new progressive rehabilitation requirements will commence on or by November 1, 2019 and will require each mine, within a three-year transition period, to establish a schedule of rehabilitation milestones covering the life of the mine, and any significant changes to the timing of rehabilitation will require regulatory approval. If there is to remain an area within the mine that does not have a post-mining land use (referred to as a non-use management area or NUMA) then each such NUMA will need to pass a public interest evaluation test as part of the approval process. An example of a NUMA is the void that remains after open-cut mining activities have been completed. Under the legislation, each current mine is exempt from the requirement to justify its NUMAs to the extent that its current approvals provide for such areas. The Company is of the view that there will not be a need to seek any further regulatory approvals for any of the NUMAs at any of its Queensland mines.

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Federal Reclamation. In February 2017, the Australian Senate established a Committee of Inquiry into the rehabilitation of mining and resources projects as it relates to Commonwealth responsibilities, for example, under the Environment Protection and Biodiversity Conservation Act 1999. The Committee released their report on March 18, 2019. The Committee was unable to reach unanimous agreement on a set of recommendations. It is unclear the extent to which the report will impact policy reform at a federal government level.

Sydney Water Catchment Areas. In November 2017, the New South Wales government established an independent expert panel (Panel) to advise the Department of Planning and Environment on the impact of underground mining activities in Sydney’s water catchment areas, including at Peabody’s Metropolitan Mine. The Panel issued an initial report to the government in November 2018, which was released by the government on December 20, 2018. The initial report only concerns mining activities at two mines, Peabody’s Metropolitan Mine and a competitor’s Dendrobium Mine. A final report is currently expected to be issued in the last quarter of 2019, which will cover mining activities and effects across the catchment as a whole, with a particular focus on risks to the quantity of water available, the environmental consequences for swamps and the issue of cumulative impacts.

The Panel’s initial report acknowledges the major effort at the Metropolitan and Dendrobium Mines over the last decade to employ best practice modeling and assessment methods undertaken by suitable experts, while recommending continued rigorous monitoring and impact assessment in order to build on the knowledge base regarding mining-induced subsidence and its impacts on groundwater and surface water. The initial report endorses the government taking an incremental approach to mining approvals that provides for considering existing and emerging information and knowledge gaps. The latest extraction plans for the Metropolitan Mine are progressing on an incremental basis and Peabody continues to conduct robust monitoring, data collection and reporting and has been actively consulting with the government on Metropolitan’s approval processes and mine design to ensure that operational impacts are appropriately managed and minimized as far as possible.

On March 15, 2019, Peabody provided a submission to the Panel which included a formal response to the initial report as well as further issues for consideration as part of the Panel’s final report due to be released in the last quarter of 2019.

National Energy Guarantee (NEG). Following the outcome of the Federal Election in May 2019, the Federal Coalition Government has confirmed it will not revive the NEG policy. Instead, the Government will pursue its new energy and climate change policy, announced before the election, which includes a $2 billion Australian dollars investment in projects to bring down Australia's greenhouse gas emissions. The Climate Solutions Fund is an extension of the former Emissions Reduction Fund. The Government has confirmed that it remains committed to meeting Australia’s Paris Agreement targets but that the focus of energy policy will be on driving down electricity prices.

Liquidity and Capital Resources

Overview

Our primary source of cash is proceeds from the sale of our coal production to customers. We have also generated cash from the sale of non-strategic assets, including coal reserves and surface lands, borrowings under our credit facilities and, from time to time, the issuance of securities. Our primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, capital and operating lease payments, postretirement plans, take-or-pay obligations, post-mining retirement obligations, and selling and administrative expenses. We have also used cash for dividends and share repurchases. We believe that our capital structure allows us to satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations and cash on hand.

Any future determinations to return capital to stockholders, such as dividends or share repurchases will be at the discretion of our Board of Directors and will depend on a variety of factors, including the restrictions set forth under our debt agreements, our net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. Our ability to declare dividends or repurchase shares in the future will depend on our future financial performance, which in turn depends on the successful implementation of our strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to our industry, many of which are beyond our control.

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Liquidity

As of June 30, 2019, our available liquidity was $1,201.9 million which was comprised of cash and cash equivalents and availability under our revolver and accounts receivable securitization program as described below. As of June 30, 2019, our cash balances totaled $853.0 million, including approximately $303 million held by U.S. subsidiaries, $527 million held by Australian subsidiaries and the remaining balance held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by our foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia. Subsequent to June 30, 2019, we repatriated to the U.S. approximately $420 million previously held by foreign subsidiaries. If we repatriate foreign-held cash in the future, we do not expect restrictions or potential taxes to have a material effect on our overall liquidity.

During the six months ended June 30, 2019, we paid dividends of $229.3 million, including $200 million for a supplemental dividend, and made stock repurchases totaling $156.0 million.

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.

Debt Financing

As described in Note 13. “Long-term Debt” of the accompanying unaudited condensed consolidated financial statements, during 2017, we entered into an indenture related to the issuance of $500.0 million of 6.000% senior secured notes due March 2022 and $500.0 million of 6.375% senior secured notes due March 2025. We make semi-annual interest payments on the senior notes each March 31 and September 30 until maturity. Also during 2017, we entered into a credit agreement and related term loan under which we originally borrowed $950.0 million and have repaid $555.0 million through June 30, 2019. The term loan requires quarterly principal payments of $1.0 million and periodic interest payments, currently at LIBOR plus 2.75%, through December 2024 with the remaining balance due in March 2025.

We also entered into a revolving credit facility allowable under our credit agreement during 2017 for an aggregate commitment of $350.0 million for general corporate purposes. To date, we have only utilized this revolving credit facility for letters of credit which incur combined fees of 3.375%, while unused capacity bears a commitment fee of 0.5%. As of June 30, 2019, such letters of credit amounted to $70.8 million and were primarily in support of our reclamation obligations.

Our debt agreements impose various restrictions and limits on certain categories of payments that we may make, such as those for dividends, investments, and stock repurchases. We are also subject to customary affirmative and negative covenants. At June 30, 2019 and subsequently, we were in compliance with all such restrictions and covenants. We are currently considering alternatives for addressing our debt agreements as necessary to permit formation of the PRB Colorado joint venture with Arch described in the “Overview” section contained within this Item 2. Our ability to accomplish this objective is subject to market conditions and other factors, including financing options that may be available to us from time to time and conditions in the credit and debt capital markets generally.

Accounts Receivable Securitization Program

As described in Note 18. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, we entered into an amended accounts receivable securitization program during 2017 which currently expires in 2022. The program provides for up to $250.0 million in funding, limited to the availability of eligible receivables, accounted for as a secured borrowing. Funding capacity under the program may also be provided for letters of credit in support of other obligations. At June 30, 2019, we had no outstanding borrowings and $129.9 million of letters of credit provided under the program. The letters of credit are primarily in support of portions of our obligations for reclamation, workers’ compensation and postretirement benefits. There was no cash collateral requirement under the program at June 30, 2019.

Capital Requirements

As a result of the deferral of certain capital project spending to subsequent periods, we revised our expected 2019 capital expenditures to a range of $350 million to $375 million during the first quarter of 2019, as compared to a range of $375 million to $425 million as disclosed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2018. There were no other material changes to our capital requirements.

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Contractual Obligations

There were no material changes to our contractual obligations from the information previously provided in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2018.

Historical Cash Flows and Free Cash Flow

The following table summarizes our cash flows for the six months ended June 30, 2019 and 2018, as reported in the accompanying unaudited condensed consolidated financial statements. Free Cash Flow is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S. GAAP.



	Six Months Ended June 30,
	2019			2018
	(Dollars in millions)
Net cash provided by operating activities	$	377.0		$	915.4
Net cash used in investing activities	(64.0		)	(18.0		)
Net cash used in financing activities	(430.3		)	(489.7		)
Net change in cash, cash equivalents and restricted cash	(117.3		)	407.7
Cash, cash equivalents and restricted cash at beginning of period	1,017.4			1,070.2
Cash, cash equivalents and restricted cash at end of period	$	900.1		$	1,477.9

Net cash provided by operating activities	$	377.0		$	915.4
Net cash used in investing activities	(64.0		)	(18.0		)
Add back: Amount attributable to acquisition of Shoal Creek Mine	2.4			—
Free Cash Flow	$	315.4		$	897.4

Operating Activities. The decrease in net cash provided by operating activities for the six months ended June 30, 2019 compared to the same period in the prior year was driven by the following:


•	A year-over-year decrease in cash from our mining operations;


•	A substantial release of collateral obligations during the prior year period upon establishing our new surety bonding program in Australia ($323.1 million);


•	An unfavorable change in net cash flows associated with our working capital ($133.4 million); partially offset by


•	The receipt of insurance proceeds attributable to North Goonyella leased equipment, cost recovery and business interruption ($101.8 million)

Investing Activities. The increase in net cash used in investing activities for the six months ended June 30, 2019 compared to the same period in the prior year was driven by the following:


•	Lower cash receipts from Middlemount Coal Pty Ltd ($55.1 million); and


•	Lower proceeds from disposals of assets, net of receivables ($36.8 million); partially offset by


•	Lower additions to property, plant, equipment and mine development ($30.0 million, net of changes in accrued expenses related to capital expenditures); and


•	The receipt of insurance proceeds attributable to North Goonyella Company-owned equipment losses ($23.2 million)

Financing Activities. The decrease in net cash used in financing activities for the six months ended June 30, 2019 compared to the same period in the prior year was driven by the following:


•	Lower common stock repurchases ($218.5 million); and


•	Lower debt repayments ($46.0 million) due to a prepayment made in connection with the 2018 amendment of our Senior Secured Term Loan; partially offset by


•	Higher dividends paid ($200.0 million), primarily due to a supplemental dividend of $1.85 per share of common stock

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Off-Balance Sheet Arrangements

In the normal course of business, we are a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying condensed consolidated balance sheets. At June 30, 2019, such instruments included $1,572.0 million of surety bonds and $202.2 million of letters of credit. Such financial instruments provide support for our reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. We periodically evaluate the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. We do not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in our unaudited condensed consolidated balance sheets.

We could experience a decline in our liquidity as financial assurances associated with reclamation bonding requirements, surety bonds or other obligations are required to be collateralized by cash or letters of credit.

As described in Note 18. “Financial Instruments and Other Guarantees” in the accompanying unaudited condensed consolidated financial statements, we are required to provide various forms of financial assurance in support of our mining reclamation obligations in the jurisdictions in which we operate. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees and letters of credit, as well as self-bonding arrangements in the U.S. In connection with our emergence from the Chapter 11 reorganization, we shifted away from extensive self-bonding in the U.S. in favor of increased usage of surety bonds and similar third-party instruments, but have retained the ability to utilize self-bonding in the future, dependent upon state-by-state approval and internal cost-benefit considerations. This divergence in practice may impact our liquidity in the future due to increased collateral requirements and surety and related fees.

At June 30, 2019, we had total asset retirement obligations of $762.8 million which were backed by a combination of surety bonds and letters of credit.

Bonding requirement amounts may differ significantly from the related asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas our accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date.

Guarantees and Other Financial Instruments with Off-Balance Sheet Risk. See Note 18. “Financial Instruments and Other Guarantees” in our unaudited condensed consolidated financial statements for a discussion of our accounts receivable securitization program and guarantees and other financial instruments with off-balance sheet risk.

Critical Accounting Policies and Estimates

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

Our critical accounting policies are discussed in 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, 2018. Our critical accounting policies remain unchanged at June 30, 2019.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

See Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” to our unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Foreign Currency Risk

We have historically utilized currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. The accounting for these derivatives is discussed in Note 8. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. As of June 30, 2019, the Company had currency options outstanding with an aggregate notional amount of $1,000.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the remainder of 2019 and over the first three months of 2020. Assuming we had no foreign currency hedging instruments in place, our exposure in operating costs and expenses due to a $0.05 change in the Australian dollar/U.S. dollar exchange rate is approximately $75 to $85 million for the next twelve months. Based upon the Australian dollar/U.S. dollar exchange rate at June 30, 2019, the currency option contracts outstanding at that date would not materially limit our net exposure to a $0.05 unfavorable change in the exchange rate for the next twelve months.

Other Non-Coal Trading Activities — Diesel Fuel Price Risk

Diesel Fuel Hedges. Previously, we managed price risk of the diesel fuel used in our mining activities through the use of derivatives, primarily swaps. As of June 30, 2019, we did not have any diesel fuel derivative instruments in place. We also manage the price risk of diesel fuel through the use of cost pass-through contacts with certain customers.

We expect to consume 100 to 110 million gallons of diesel fuel during the next twelve months. A $10 per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease our annual diesel fuel costs by approximately $26 million based on our expected usage.

Item 4. Controls and Procedures.

Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including our principal executive and financial officers, on a timely basis. Our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of June 30, 2019, and concluded that such controls and procedures are effective to provide reasonable assurance that the desired control objectives were achieved.

We acquired the Shoal Creek Mine on December 3, 2018. For the three and six months ended June 30, 2019, the Shoal Creek Mine accounted for $114.5 million and $230.7 million, respectively, of our revenues and constituted $377.3 million of total assets as of June 30, 2019. We completed our review of the internal control structure of the Shoal Creek Mine and, made appropriate changes to incorporate our controls and procedures into the acquired operations. The Shoal Creek Mine will be included in our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2019.

Except as described in the preceding paragraph, there have been no changes to our internal control over financial reporting during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

We are subject to various legal and regulatory proceedings. For a description of our significant legal proceedings refer to Note 5. “Discontinued Operations” and Note 19. “Commitments and Contingencies” to the unaudited condensed consolidated financial statements included in Part I, Item 1. “Financial Statements” of this Quarterly Report, which information is incorporated by reference herein.

Item 1A. Risk Factors.

For information regarding factors that could affect the Company's results of operations, financial condition and liquidity, see the risk factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on February 27, 2019. The information below includes additional risk factors relating to our proposed PRB Colorado joint venture with Arch.

Our proposed joint ventures with Arch and Glencore may not be completed.

On June 18, 2019, we entered into a definitive implementation agreement with Arch to establish a joint venture that will combine the respective Powder River Basin and Colorado mining operations of Peabody and Arch.

The closing of our proposed joint venture with Arch is subject to various conditions to closing, including the termination or expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of certain other required regulatory approvals and the absence of injunctions or other legal restraints preventing the formation of the joint venture. These closing conditions may not be satisfied, and in that circumstance we may be unable or unwilling to complete this joint venture. If the implementation agreement is terminated by us before we complete the joint venture, under certain circumstances, we may be required to pay a termination fee to Arch of up to $40.0 million.

In 2014, we agreed to establish an unincorporated joint venture project with Glencore, in which we will hold a 50% interest, to combine the existing operations of the our Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. The closing of our proposed joint venture with Glencore is subject to substantive contingencies for the requisite regulatory and permitting approvals. These contingencies may not occur, and, as a result, we may be unable to complete this joint venture.

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

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

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

The benefits that are expected to result from the proposed joint venture will depend, in part, on our ability to realize the anticipated cost synergies in the transaction, our and Arch’s ability to successfully integrate our Powder River Basin and Colorado mining operations, and our and Arch’s ability to successfully manage the joint venture on a going-forward basis. It is not certain that we will realize these benefits at all, and if we do, it is not certain how long it will take to achieve these benefits. If, for example, we are unable to achieve the anticipated cost savings, or if there are unforeseen integration costs, or if we and Arch are unable to operate the joint venture smoothly in the future, the financial performance of the joint venture may be negatively affected.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Share Repurchase Program

Our Board of Directors has authorized a share repurchase program, as amended, to allow repurchases of up to $1.5 billion of the outstanding shares of our common stock and/or preferred stock (Repurchase Program). Repurchases may be made from time to time at the Company’s discretion. The specific timing, price and size of purchases will depend on the share price, general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time. The Repurchase Program does not have an expiration date and may be discontinued at any time. Through June 30, 2019, we have repurchased approximately 32 million shares of our common stock for $1,166.4 million, which included commissions paid of $0.6 million, leaving $334.2 million available for share repurchase under the Repurchase Program. Subsequent to June 30, 2019 and through August 2, 2019, we have purchased an additional 2.6 million shares of our common stock for $58.3 million. The purchases were made in compliance with our debt instruments. Limitations on share repurchases imposed by our debt instruments are discussed in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Share Relinquishments

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

Purchases of Equity Securities

The following table summarizes all share purchases for the three months ended June 30, 2019:



Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Dollar Value that May Yet Be Used to Repurchase Shares Under the Publicly Announced Program (In millions)
April 1 through April 30, 2019	1,599,149	$	28.12	1,201,676	$	357.3
May 1 through May 31, 2019	296,725	28.33		295,897	348.9
June 1 through June 30, 2019	626,234	23.53		626,234	334.2
Total	2,522,108	27.00		2,123,807


⁽¹⁾	Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not part of the Repurchase Program.

Dividends

During the three and six months ended June 30, 2019, the Company declared dividends per share of $0.140 and $2.120 per share, respectively. On August 7, 2019, our Board of Directors declared a dividend of $0.145 per share of Common Stock to be paid on September 11, 2019 to shareholders of record as of August 21, 2019. The declaration and payment of dividends and the amount of dividends will depend on our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by our debt covenants and other factors that our Board of Directors may deem relevant to such evaluations. Payment of dividends is subject to certain limitations, as set forth in our debt agreements. Such limitations on dividends are discussed in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Item 4. Mine Safety Disclosures.

Our “Safety a Way of Life Management System” has been designed to set clear and consistent expectations for safety and health across our business. It aligns to the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, safety and health risk management and assurance. We also partner with other companies and certain governmental agencies to pursue new technologies that have the potential to improve our safety performance and provide better safety protection for employees.

We continually monitor our safety performance and regulatory compliance. The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95 to this Quarterly Report on Form 10-Q.

Item 6. Exhibits.

See Exhibit Index at page 66 of this report.

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EXHIBIT INDEX

The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.



Exhibit No.		Description of Exhibit

2.1		Implementation Agreement, dated as of June 18, 2019, between Peabody Energy Corporation and Arch Coal, Inc. (incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K/A filed on June 19, 2019)

10.1		Fifth Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of April 3, 2019, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank. (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed April 4, 2019)

31.1†		Certification of periodic financial report by the Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2†		Certification of periodic financial report by the Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1†		Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Executive Officer

32.2†		Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Financial Officer

95†		Mine Safety Disclosure required by Item 104 of Regulation S-K

†		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:	August 8, 2019	By:	/s/ AMY B. SCHWETZ
			Amy B. Schwetz
			Executive Vice President and Chief Financial Officer (On behalf of the registrant and as Principal Financial Officer)