Arch Resources (ARCH) 10-Q 2015 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

x  Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2015

o  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: 1-13105

Arch Coal, Inc.

(Exact name of registrant as specified in its charter)

Delaware	43-0921172
(State or other jurisdiction	(I.R.S. Employer
of incorporation or organization)	Identification Number)

One CityPlace Drive, Suite 300, St. Louis, Missouri	63141
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code: (314) 994-2700

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 x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

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

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

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

At July 20, 2015 there were 212,916,357 shares of the registrant’s common stock outstanding.

TABLE OF CONTENTS

	Page
Part I FINANCIAL INFORMATION	3
Item 1. Financial Statements	3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3. Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. Controls and Procedures	38
Part II OTHER INFORMATION	38
Item 1. Legal Proceedings	38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 4. Mine Safety Disclosures	42
Item 5. Other Information	42
Item 6. Exhibits	43

2

Part I

FINANCIAL INFORMATION

Item 1.    Financial Statements.

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(Unaudited)
Revenues	$	644,462		$	713,776		$	1,321,467		$	1,449,747
Costs, expenses and other operating
Cost of sales (exclusive of items shown separately below)	566,252			622,137			1,128,574			1,308,451
Depreciation, depletion and amortization	97,372			102,464			202,246			206,887
Amortization of acquired sales contracts, net	(1,644		)	(3,239		)	(5,034		)	(6,935		)
Change in fair value of coal derivatives and coal trading activities, net	1,211			(2,992		)	2,431			(2,078		)
Asset impairment and mine closure costs	19,146			1,512			19,146			1,512
Selling, general and administrative expenses	24,268			29,931			46,873			59,067
Other operating (income) expense, net	7,403			(232		)	16,489			(8,230		)
	714,008			749,581			1,410,725			1,558,674
Loss from operations	(69,546		)	(35,805		)	(89,258		)	(108,927		)
Interest expense, net
Interest expense	(99,574		)	(97,960		)	(198,826		)	(194,431		)
Interest and investment income	962			2,036			3,335			3,879
	(98,612		)	(95,924		)	(195,491		)	(190,552		)
Nonoperating expense
Expenses related to debt restructuring	(4,016		)	—			(4,016		)	—
Loss before income taxes	(172,174		)	(131,729		)	(288,765		)	(299,479		)
Benefit from income taxes	(4,071		)	(34,869		)	(7,467		)	(78,480		)
Net loss	$	(168,103	)	$	(96,860	)	$	(281,298	)	$	(220,999	)
Losses per common share
Basic and diluted LPS	$	(0.79	)	$	(0.46	)	$	(1.32	)	$	(1.04	)
Basic and diluted weighted average shares outstanding	212,914			212,225			212,788			212,198
Dividends declared per common share	$	—		$	—		$	—		$	0.01

The accompanying notes are an integral part of the condensed consolidated financial statements.

3

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(Unaudited)
Net loss	$	(168,103	)	$	(96,860	)	$	(281,298	)	$	(220,999	)
Derivative instruments
Comprehensive income (loss) before tax	(3,199		)	1,007			1,846			778
Income tax benefit (provision)	1,153			(362		)	(664		)	(280		)
	(2,046		)	645			1,182			498
Pension, postretirement and other post-employment benefits
Comprehensive income (loss) before tax	3,474			(2,269		)	3,768			(4,116		)
Income tax benefit (provision)	(1,252		)	817			(1,357		)	1,482
	2,222			(1,452		)	2,411			(2,634		)
Available-for-sale securities
Comprehensive income (loss) before tax	68			(1,203		)	359			(3,236		)
Income tax benefit (provision)	(28		)	433			(132		)	1,165
	40			(770		)	227			(2,071		)
Total other comprehensive income (loss)	216			(1,577		)	3,820			(4,207		)
Total comprehensive loss	$	(167,887	)	$	(98,437	)	$	(277,478	)	$	(225,206	)

The accompanying notes are an integral part of the condensed consolidated financial statements.

4

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except per share data)

	June 30,			December 31,
	2015			2014
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	439,655		$	734,231
Short term investments	249,754			248,954
Restricted cash	43,563			5,678
Trade accounts receivable	204,593			211,506
Other receivables	14,948			20,511
Inventories	223,929			190,253
Prepaid royalties	9,006			11,118
Deferred income taxes	47,277			52,728
Coal derivative assets	13,358			13,257
Other current assets	50,838			54,515
Total current assets	1,296,921			1,542,751
Property, plant and equipment, net	6,341,026			6,453,458
Other assets
Prepaid royalties	52,956			66,806
Equity investments	227,788			235,842
Other noncurrent assets	117,664			130,866
Total other assets	398,408			433,514
Total assets	$	8,036,355		$	8,429,723
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	156,725		$	180,113
Accrued expenses and other current liabilities	262,958			302,396
Current maturities of debt	31,763			36,885
Total current liabilities	451,446			519,394
Long-term debt	5,114,581			5,123,485
Asset retirement obligations	409,435			398,896
Accrued pension benefits	13,580			16,260
Accrued postretirement benefits other than pension	34,176			32,668
Accrued workers’ compensation	97,489			94,291
Deferred income taxes	411,930			422,809
Other noncurrent liabilities	109,693			153,766
Total liabilities	6,642,330			6,761,569
Stockholders’ equity
Common stock, $0.01 par value, authorized 260,000 shares, issued 214,433 shares and 213,791 shares at June 30, 2015 and December 31, 2014, respectively	2,145			2,141
Paid-in capital	3,051,805			3,048,460
Treasury stock, at cost, 1,517 shares at June 30, 2015 and December 31, 2014	(53,863		)	(53,863		)
Accumulated deficit	(1,613,123		)	(1,331,825		)
Accumulated other comprehensive income	7,061			3,241
Total stockholders’ equity	1,394,025			1,668,154
Total liabilities and stockholders’ equity	$	8,036,355		$	8,429,723

The accompanying notes are an integral part of the condensed consolidated financial statements.

5

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(in thousands)

	Six Months Ended June 30,
	2015			2014
	(Unaudited)
Operating activities
Net loss	$	(281,298	)	$	(220,999	)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization	202,246			206,887
Amortization of acquired sales contracts, net	(5,034		)	(6,935		)
Amortization relating to financing activities	12,539			7,757
Prepaid royalties expensed	3,939			3,575
Employee stock-based compensation expense	3,354			5,469
Asset impairment and non-cash mine closure costs	17,242			1,512
Expenses related to debt restructuring	4,016			—
Amortization of premiums on debt securities held	1,010			—
Gains on disposals and divestitures, net	(1,325		)	(18,506		)
Deferred income taxes	(7,510		)	(78,568		)
Changes in:
Receivables	12,433			267
Inventories	(33,743		)	3,522
Accounts payable, accrued expenses and other current liabilities	(56,419		)	10,495
Income taxes, net	(37		)	(571		)
Other	3,012			7,749
Cash used in operating activities	(125,575		)	(78,346		)
Investing activities
Capital expenditures	(99,361		)	(95,746		)
Additions to prepaid royalties	(409		)	(3,341		)
Proceeds from disposals and divestitures	991			43,245
Purchases of marketable securities	(161,336		)	(168,951		)
Proceeds from sale or maturity of marketable securities and other investments	157,729			166,018
Investments in and advances to affiliates	(5,138		)	(9,501		)
Cash used in investing activities	(107,524		)	(68,276		)
Financing activities
Payments on term loan	(9,750		)	(9,750		)
Net payments on other debt	(9,826		)	(9,390		)
Expenses related to debt restructuring	(4,016		)	—
Dividends paid	—			(2,123		)
Debt financing costs	—			(1,957		)
Withdrawals (deposits) of restricted cash	(37,885		)	(1,103		)
Cash used in financing activities	(61,477		)	(24,323		)
Decrease in cash and cash equivalents	(294,576		)	(170,945		)
Cash and cash equivalents, beginning of period	734,231			911,099
Cash and cash equivalents, end of period	$	439,655		$	740,154

The accompanying notes are an integral part of the condensed consolidated financial statements.

6

Arch Coal, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

1.  Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Arch Coal, Inc. and its subsidiaries (the “Company”). The Company’s primary business is the production of thermal and metallurgical coal from surface and underground mines located throughout the United States, for sale to utility, industrial and steel producers both in the United States and around the world. The Company currently operates mining complexes in West Virginia, Maryland, Virginia, Illinois, Wyoming and Colorado.  All subsidiaries are wholly-owned. Intercompany transactions and accounts 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 for interim financial reporting and U.S. Securities and Exchange Commission regulations. In the opinion of management, all adjustments, consisting of normal, recurring accruals considered necessary for a fair presentation, have been included. Results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of results to be expected for the year ending December 31, 2015. These financial statements should be read in conjunction with the audited financial statements and related notes as of and for the year ended December 31, 2014 included in the Company’s Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission.

2.  Accounting Policies

In April 2015, the Financial Accounting Standards Board (“FASB”) issued the Accounting Standards Update No. 2015-03 (“ASU 2015-03”), Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that liability, consistent with debt discounts. Amendments in this update are effective retrospectively for fiscal years and interim periods within those years, beginning after December 15, 2015, with early adoption permitted. We expect upon adoption of this guidance that the current financial statement classification of debt issuance costs will change from total assets to long-term debt on our Condensed Consolidated Balance Sheet.

3.  Accumulated Other Comprehensive Income

The following items are included in accumulated other comprehensive income (“AOCI”):

				Pension,
				Postretirement
				and Other					Accumulated
				Post-					Other
	Derivative			Employment		Available-for-			Comprehensive
	Instruments			Benefits		Sale Securities			Income
	(In thousands)
Balance at December 31, 2014	$	2,550		$	2,860	$	(2,169	)	$	3,241
Unrealized gains (losses)	3,234			—		(2,445		)	789
Amounts reclassified from AOCI	(2,051		)	2,411		2,671			3,031
Balance at June 30, 2015	$	3,733		$	5,271	$	(1,943	)	$	7,061

7

The following amounts were reclassified out of AOCI:

	Amounts Reclassified from AOCI
	Three Months Ended June 30,						Six Months Ended June 30,						Line Item in the Condensed Consolidated
Details About AOCI Components	2015			2014			2015			2014			Statement of Operations
	(In thousands)
Derivative instruments	$	2,727		$	151		$	3,208		$	454		Revenues
	(983		)	(55		)	(1,157		)	(164		)	Benefit from income taxes
	$	1,744		$	96		$	2,051		$	290		Net of tax
Pension, postretirement and other post-employment benefits
Amortization of prior service credits (1)	$	2,083		$	2,591		$	4,167		$	5,217
Amortization of actuarial gains (losses), net (1)	(5,556		)	(321		)	(7,934		)	(1,100		)
	(3,473		)	2,270			(3,767		)	4,117
	1,251			(817		)	1,356			(1,482		)	Benefit from income taxes
	$	(2,222	)	$	1,453		$	(2,411	)	$	2,635		Net of tax
Available-for-sale securities	$	(1,430	)	$	(1,123	)	$	(4,227	)	$	(1,679	)	Interest and investment income
	549			404			1,556			604			Benefit from income taxes
	$	(881	)	$	(719	)	$	(2,671	)	$	(1,075	)	Net of tax

1 Production-related benefits and workers’ compensation costs are included in inventoriable production costs.

4.  Divestitures

During the first quarter of 2014, the Company entered into agreements to sell an operating thermal coal complex and an idled thermal coal mine in Kentucky and the Company’s ADDCAR subsidiary, which manufactures a patented highwall mining system.  The sales closed in the first quarter of 2014 for total consideration of $45.3 million.  The Company received $26.3 million in cash in the first quarter of 2014, and the remainder was paid in the second and fourth quarters of 2014.  The Company recognized a net pre-tax gain of $12.8 million from these divestitures, reflected in “other operating (income) expense, net” in the Condensed Consolidated Statements of Operations.

5.  Asset Impairment and Mine Closure Costs

During the second quarter of 2015, the Company recorded $19.1 million to “Asset impairment and mine closure costs” in the Condensed Consolidated Statements of Operations.  An impairment charge of $12.2 million relates to the portion of an advance royalty balance on a reserve base mined at the Company’s Mountain Laurel, Spruce and Briar Branch operations that will not be recouped based on latest estimates of sales volumes and pricing through the recoupment period which runs through March 2017.  Additionally, the Company recorded a $5.6 million impairment charge related to the closure of a higher cost mining complex, Cumberland River, serving the metallurgical coal markets.

8

6.  Inventories

Inventories consist of the following:

	June 30,		December 31,
	2015		2014
	(In thousands)
Coal	$	99,691	$	71,901
Repair parts and supplies	124,238		118,352
	$	223,929	$	190,253

The repair parts and supplies are stated net of an allowance for slow-moving and obsolete inventories of $6.6 million at June 30, 2015 and $6.6 million at December 31, 2014.

7.   Investments in Available-for-Sale Securities

The Company has invested in marketable debt securities, primarily highly liquid investment grade corporate bonds.  These investments are held in the custody of a major financial institution.  These securities, along with the Company’s investments in marketable equity securities, are classified as available-for-sale securities and, accordingly, the unrealized gains and losses are recorded through other comprehensive income.

The Company’s investments in available-for-sale marketable securities are as follows:

	June 30, 2015
										Balance Sheet
			Accumulated							Classification
			Gross Unrealized					Fair		Short-Term		Other
	Cost Basis		Gains		Losses			Value		Investments		Assets
	(In thousands)
Available-for-sale:
Corporate notes and bonds	$	252,877	$	—	$	(3,123	)	$	249,754	$	249,754	$	—
Equity securities	3,910		1,973		(2,852		)	3,031		—		3,031
Total Investments	$	256,787	$	1,973	$	(5,975	)	$	252,785	$	249,754	$	3,031

	December 31, 2014
										Balance Sheet
			Gross		Gross					Classification
			Unrealized		Unrealized			Fair		Short-Term		Other
	Cost Basis		Gains		Losses			Value		Investments		Assets
	(In thousands)
Available-for-sale:
Corporate notes and bonds	$	253,590	$	—	$	(4,636	)	$	248,954	$	248,954	$	—
Equity securities	3,910		4,125		(2,890		)	5,145		—		5,145
Total Investments	$	257,500	$	4,125	$	(7,526	)	$	254,099	$	248,954	$	5,145

The aggregate fair value of investments with unrealized losses that were owned for less than a year was $187.0 million and $163.0 million at June 30, 2015 and December 31, 2014, respectively. The aggregate fair value of investments with unrealized losses that were owned for over a year, and were also in a continuous unrealized loss position during that time, was $58.9 million and $86.1 million at June 30, 2015 and December 31, 2014, respectively.  The unrealized losses in the Company’s portfolio are the result of normal market fluctuations.  The Company does not currently intend to sell these investments before recovery of their amortized cost base.

The debt securities outstanding at June 30, 2015 have maturity dates ranging from the third quarter of 2015 through the fourth quarter of 2016.  The Company classifies its investments as current based on the nature of the investments and their availability to provide cash for use in current operations.

9

8.   Derivatives

Diesel fuel price risk management

The Company is exposed to price risk with respect to diesel fuel purchased for use in its operations. The Company anticipates purchasing approximately 57 to 62 million gallons of diesel fuel for use in its operations during 2015.  To protect the Company’s cash flows from increases in the price of diesel fuel for its operations, the Company uses forward physical diesel purchase contracts and purchased heating oil call options.  At June 30, 2015, the Company had protected the price of approximately 100% of its expected purchases for the remainder of the year with out-of-the-money call options with an average strike price of $3.13 per gallon.  Due to the drop in heating oil pricing in early 2015, the Company has added in 19.5 million gallons of additional call options for the second half of 2015 representing 65% of expected purchases at an average strike price of $1.92 per gallon.  Additionally, the Company has protected approximately 49%  of our expected 2016 purchases with out-of-the-money call options.  At June 30, 2015, the Company had purchased heating oil call options for approximately 66 million gallons for the purpose of managing the price risk associated with future diesel purchases.  These positions are not accounted for as hedges.

Coal price risk management positions

The Company may sell or purchase forward contracts, swaps and options in the over-the-counter coal market in order to manage its exposure to coal prices. The Company has exposure to the risk of fluctuating coal prices related to forecasted sales or purchases of coal or to the risk of changes in the fair value of a fixed price physical sales contract. Certain derivative contracts may be designated as hedges of these risks.

At June 30, 2015, the Company held derivatives for risk management purposes that are expected to settle in the following years:

(Tons in thousands)	2015	2016	Total
Coal sales	2,405	280	2,685
Coal purchases	1,208	240	1,448

The Company has also entered into a nominal quantity of natural gas put options to protect the Company from decreases in natural gas prices, which could impact coal demand.  These options are not accounted for as hedges.

Coal trading positions

The Company may sell or purchase forward contracts, swaps and options in the over-the-counter coal market for trading purposes. The Company is exposed to the risk of changes in coal prices on the value of its coal trading portfolio. The estimated future realization of the value of the trading portfolio is $1.1 million of gains during the remainder of 2015 and $1.3 million of gains in 2016.

Tabular derivatives disclosures

The Company has master netting agreements with all 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 amounts shown in the table below represent the fair value position of individual contracts, and not the net position presented in the accompanying condensed consolidated balance sheets. The fair value and location of derivatives reflected in the accompanying Condensed Consolidated Balance Sheets are as follows:

10

	June 30, 2015								December 31, 2014
Fair Value of Derivatives	Asset			Liability					Asset			Liability
(In thousands)	Derivative			Derivative					Derivative			Derivative
Derivatives Designated as Hedging Instruments
Coal	$	4,602		$	(132	)			$	6,535		$	(2,492	)
Derivatives Not Designated as Hedging Instruments
Heating oil — diesel purchases	5,444			—					300			—
Coal — held for trading purposes	85,130			(82,582		)			96,898			(93,272		)
Coal — risk management	12,551			(8,035		)			8,510			(3,688		)
Natural gas	993			—					—			—
Total	104,118			(90,617		)			105,708			(96,960		)
Total derivatives	108,720			(90,749		)			112,243			(99,452		)
Effect of counterparty netting	(89,918		)	89,918					(98,686		)	98,686
Net derivatives as classified in the balance sheets	$	18,802		$	(831	)	$	17,971	$	13,557		$	(766	)	$	12,791

Net derivatives as reflected on the balance sheets (in thousands)		June 30, 2015			December 31, 2014
Heating oil	Other current assets	$	5,444		$	300
Coal	Coal derivative assets	13,358			13,257
	Accrued expenses and other current liabilities	(831		)	(766		)
		$	17,971		$	12,791

The Company had a current liability for the obligation to post cash collateral of $0.8 million and $2.4 million at June 30, 2015 and December 31, 2014, respectively. These amounts are not included with the derivatives presented in the table above and are included in “accrued expenses and other current liabilities”, in the accompanying Condensed Consolidated Balance Sheets.

The effects of derivatives on measures of financial performance are as follows:

Derivatives used in Cash Flow Hedging Relationships (in thousands)

Three Months Ended June 30,

		Gain (Loss) Recognized in Other Comprehensive Income (Effective Portion)						Gains (Losses) Reclassified from Other Comprehensive Income into Income (Effective Portion)
		2015			2014			2015			2014
Coal sales	(1)	$	(1,163	)	$	1,870		$	4,990		$	223
Coal purchases	(2)	687			(712		)	(2,263		)	(72		)
Totals		$	(476	)	$	1,158		$	2,727		$	151

No ineffectiveness or amounts excluded from effectiveness testing relating to the Company’s cash flow hedging relationships were recognized in the results of operations in the three month periods ended June 30, 2015 and 2014.

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Derivatives Not Designated as Hedging Instruments (in thousands)

Three Months Ended June 30,

		Gain (Loss) Recognized
		2015			2014
Coal — unrealized	(3)	$	(875	)	$	147
Coal — realized	(4)	$	826		$	1,318
Natural gas — unrealized	(3)	$	(221	)	$	(267	)
Heating oil — diesel purchases	(4)	$	628		$	—
Heating oil — fuel surcharges	(4)	$	—		$	(47	)

Location in statement of operations:

(1) — Revenues

(2) — Cost of sales

(3) — Change in fair value of coal derivatives and coal trading activities, net

(4) — Other operating income, net

Derivatives used in Cash Flow Hedging Relationships (in thousands)

Six Months Ended June 30,

		Gain (Loss) Recognized in Other Comprehensive Income (Effective Portion)						Gains (Losses) Reclassified from Other Comprehensive Income into Income (Effective Portion)
		2015			2014			2015			2014
Coal sales	(1)	9,102			$	1,355		$	5,872		$	930
Coal purchases	(2)	(4,051		)	(123		)	(2,664		)	(476		)
Totals		$	5,051		$	1,232		$	3,208		$	454

No ineffectiveness or amounts excluded from effectiveness testing relating to the Company’s cash flow hedging relationships were recognized in the results of operations in the six month periods ended June 30, 2015 and 2014.

Derivatives Not Designated as Hedging Instruments (in thousands)

Six Months Ended June 30,

		Gain (Loss) Recognized
		2015			2014
Coal — unrealized	(3)	$	(1,286	)	$	(1,155	)
Coal — realized	(4)	$	1,917		$	4,197
Natural gas — unrealized	(3)	$	(62	)	$	(259	)
Heating oil — diesel purchases	(4)	$	(1,737	)	$	(2,963	)
Heating oil — fuel surcharges	(4)	$	—		$	(301	)

Location in statement of operations:

(1) — Revenues

(2) — Cost of sales

(3) — Change in fair value of coal derivatives and coal trading activities, net

(4) — Other operating income, net

Based on fair values at June 30, 2015, gains on derivative contracts designated as hedge instruments in cash flow hedges of approximately $4.2 million are expected to be reclassified from other comprehensive income into earnings during the next twelve months.

Related to its trading portfolio, the Company recognized net unrealized and realized losses of $0.1 million and $3.1 million of net unrealized and realized gains during the three months ended June 30, 2015 and 2014, respectively; and net unrealized and realized losses of $1.1 million and net unrealized and realized gains of $3.5 million during the six months ended June 30, 2015 and 2014.  Gains and losses from trading activities are included in the caption “Change in fair value of coal derivatives and coal trading activities, net” in the accompanying Condensed Consolidated Statements of Operations, and are not included in the previous tables reflecting the effects of derivatives on measures of financial performance.

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9.   Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consist of the following:

	June 30,		December 31,
	2015		2014
	(In thousands)
Payroll and employee benefits	$	50,429	$	73,362
Taxes other than income taxes	110,666		114,598
Interest	30,452		30,384
Acquired sales contracts	6,167		12,453
Workers’ compensation	17,220		16,714
Asset retirement obligations	19,210		19,222
Other	28,814		35,663
	$	262,958	$	302,396

10.  Debt and Financing Arrangements

	June 30,		December 31,
	2015		2014
	(In thousands)
Term loan due 2018 ($1.9 billion face value)	$	1,883,109	$	1,890,846
7.00% senior notes due 2019 at par	1,000,000		1,000,000
9.875% senior notes due 2019 ($375.0 million face value)	364,517		363,493
8.00% senior secured notes due 2019 at par	350,000		350,000
7.25% senior notes due 2020 at par	500,000		500,000
7.25% senior notes due 2021 at par	1,000,000		1,000,000
Other	48,718		56,031
	5,146,344		5,160,370
Less current maturities of debt	31,763		36,885
Long-term debt	$	5,114,581	$	5,123,485

Financial covenant requirements may restrict the amount of unused capacity available to the Company for borrowings and letters of credit under credit facilities.  The credit facility amendment on December 17, 2013 amended financial maintenance covenants to include only a minimum liquidity covenant of $550 million until June 2015, at which time a maximum secured leverage ratio covenant of 5.0 times trailing twelve months earnings before interest, taxes, depreciation and amortization (“EBITDA”) takes effect.   As of June 30, 2015, we are in compliance with the covenants.

At June 30, 2015, the available borrowing capacity under the Company’s lines of credit was approximately $117.7 million.

11.    Income Taxes

During the first half of 2015, the Company determined it was more likely than not that the federal and state net operating losses it expects to generate in 2015 will not be realized based on projections of future taxable income.  Accordingly, the estimated annual effective rate for the year ended December 31, 2015 includes a valuation allowance.   In applying the estimated annual effective rate to earnings for the three months ended June 30, 2015, the Company increased its valuation allowance by $59.3 million for the federal net operating losses and $3.3 million for the state net operating losses; and $104.6 million for federal net operating losses and $5.8 million for state net operating losses for the six months ended June 30, 2015.

During the first half of 2014, the Company increased its valuation allowance for the portion of the federal and state net operating losses it expected to generate in 2014.  The Company increased its valuation allowance by $38.1 million for the federal net operating losses and $3.9 million for the state net operating losses.

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12.  Fair Value Measurements

The hierarchy of fair value measurements assigns a level to fair value measurements based on the inputs used in the respective valuation techniques. The levels of the hierarchy, as defined below, give the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs.

·    Level 1 is defined as observable inputs such as quoted prices in active markets for identical assets. Level 1 assets include available-for-sale equity securities, U.S. Treasury securities, and coal futures that are submitted for clearing on the New York Mercantile Exchange.

·    Level 2 is defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. The Company’s level 2 assets and liabilities include U.S. government agency securities and commodity contracts (coal and heating oil) with fair values derived from quoted prices in over-the-counter markets or from prices received from direct broker quotes.

·    Level 3 is defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. These include the Company’s commodity option contracts (coal, natural gas and heating oil) valued using modeling techniques, such as Black-Scholes, that require the use of inputs, particularly volatility, that are rarely observable. Changes in the unobservable inputs would not have a significant impact on the reported Level 3 fair values at June 30, 2015.

The table below sets forth, by level, the Company’s financial assets and liabilities that are recorded at fair value in the accompanying condensed consolidated balance sheet:

	June 30, 2015
	Total		Level 1		Level 2		Level 3
	(In thousands)
Assets:
Investments in marketable securities	$	252,785	$	3,031	$	249,754	$	—
Derivatives	18,802		9,134		1,828		7,840
Total assets	$	271,587	$	12,165	$	251,582	$	7,840
Liabilities:
Derivatives	$	831	$	—	$	831	$	—

The Company’s contracts with its counterparties allow for the settlement of contracts in an asset position with contracts in a liability position in the event of default or termination. For classification purposes, the Company records the net fair value of all the positions with these counterparties as a net asset or liability. Each level in the table above displays the underlying contracts according to their classification in the accompanying Condensed Consolidated Balance Sheet, based on this counterparty netting.

The following table summarizes the change in the fair values of financial instruments categorized as level 3.

	Three Months Ended June 30, 2015			Six Months Ended June 30, 2015
	(In thousands)
Balance, beginning of period	$	9,270		$	3,040
Realized and unrealized losses recognized in earnings, net	(481		)	(1,828		)
Realized and unrealized gains recognized in other comprehensive income, net	(2,791		)	(1,341		)
Purchases	1,842			9,625
Issuances	—			(1,656		)
Ending balance	$	7,840		$	7,840

Net unrealized gains of $0.2 million and net unrealized losses of $1.6 million were recognized during the three and six months ended June 30, 2015, respectively, related to level 3 financial instruments held on June 30, 2015.

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Fair Value of Long-Term Debt

At June 30, 2015 and December 31, 2014, the fair value of the Company’s debt, including amounts classified as current, was $1.9 billion and $2.7 billion, respectively. Fair values are based upon observed prices in an active market, when available, or from valuation models using market information, which fall into Level 2 in the fair value hierarchy.

13.   Loss Per Common Share

The effect of options, restricted stock and restricted stock units that were excluded from the calculation of diluted weighted average shares outstanding because the exercise price or grant price of the securities exceeded the average market price of the Company’s common stock were:  9.1 million shares and 8.7 million shares of common stock for the three and six months ended June 30, 2015, respectively; and 7.0 million shares of common stock for both the three and six months ended June 30, 2014.  The weighted average share impacts of options, restricted stock and restricted stock units that were excluded from the calculation of weighted average shares due to the Company’s incurring a net loss for the three and six months ended June 30, 2015 were 1.7 million and 2.1 million, respectively; and 2.9 million and 2.2 million shares for the three and six months ended June 30, 2014, respectively.

14.  Employee Benefit Plans

The following table details the components of pension benefit costs (credits):

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Service cost	$	1		$	5,477		$	5		$	11,401
Interest cost	3,695			4,192			7,265			8,556
Expected return on plan assets	(4,467		)	(5,879		)	(10,231		)	(11,857		)
Amortization of prior service costs (credits)	—			(53		)	—			(107		)
Amortization of other actuarial losses	3,185			532			5,243			1,480
Net benefit cost	$	2,414		$	4,269		$	2,282		$	9,473

The following table details the components of other postretirement benefit costs (credits):

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Service cost	$	200		$	440		$	433		$	884
Interest cost	308			457			643			921
Amortization of prior service credits	(2,083		)	(2,501		)	(4,167		)	(5,002		)
Amortization of other actuarial losses (gains)	(599		)	(210		)	(1,055		)	(380		)
Net benefit credit	$	(2,174	)	$	(1,814	)	$	(4,146	)	$	(3,577	)

15.   Commitments and Contingencies

The Company accrues for costs related to contingencies when a loss is probable and the amount is reasonably determinable. Disclosure of contingencies is included in the financial statements when it is at least reasonably possible that a material loss or an additional material loss in excess of amounts already accrued may be incurred.

Allegheny Energy Supply (“Allegheny”), the sole customer of coal produced at the Company’s subsidiary Wolf Run Mining Company’s (“Wolf Run”) Sycamore No. 2 mine, filed a lawsuit against Wolf Run, Hunter Ridge Holdings, Inc. (“Hunter Ridge”), and ICG in state court in Allegheny County, Pennsylvania on December 28, 2006, and amended its complaint on April 23, 2007. Allegheny claimed that Wolf Run breached a coal supply contract when it declared force majeure under the contract upon idling the Sycamore No. 2 mine in the third quarter of 2006, and that Wolf Run continued to breach the contract by failing to ship in volumes referenced in the contract.  The Sycamore No. 2 mine was idled after encountering adverse geologic conditions and abandoned gas wells that were previously unidentified and unmapped.

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After extensive searching for gas wells and rehabilitation of the mine, it was re-opened in 2007, but with notice to Allegheny that it would necessarily operate at reduced volumes in order to safely and effectively avoid the many gas wells within the reserve.  The amended complaint also alleged that the production stoppages constitute a breach of the guarantee agreement by Hunter Ridge and breach of certain representations made upon entering into the contract in early 2005. Allegheny voluntarily dropped the breach of representation claims later.  Allegheny claimed that it would incur costs in excess of $100 million to purchase replacement coal over the life of the contract.  ICG, Wolf Run and Hunter Ridge answered the amended complaint on August 13, 2007, disputing all of the remaining claims.

On November 3, 2008, ICG, Wolf Run and Hunter Ridge filed an amended answer and counterclaim against the plaintiffs seeking to void the coal supply agreement due to, among other things, fraudulent inducement and conspiracy.  On September 23, 2009, Allegheny filed a second amended complaint alleging several alternative theories of liability in its effort to extend contractual liability to ICG, which was not a party to the original contract and did not exist at the time Wolf Run and Allegheny entered into the contract.  No new substantive claims were asserted.  ICG answered the second amended complaint on October 13, 2009, denying all of the new claims.  The Company’s counterclaim was dismissed on motion for summary judgment entered on May 11, 2010.  Allegheny’s claims against ICG were also dismissed by summary judgment, but the claims against Wolf Run and Hunter Ridge were not.  The court conducted a non-jury trial of this matter beginning on January 10, 2011 and concluding on February 1, 2011.

At the trial, Allegheny presented its evidence for breach of contract and claimed that it is entitled to past and future damages in the aggregate of between $228 million and $377 million.  Wolf Run and Hunter Ridge presented their defense of the claims, including evidence with respect to the existence of force majeure conditions and excuse under the contract and applicable law.  Wolf Run and Hunter Ridge presented evidence that Allegheny’s damages calculations were significantly inflated because it did not seek to determine damages as of the time of the breach and in some instances artificially assumed future nondelivery or did not take into account the apparent requirement to supply coal in the future.  On May 2, 2011, the trial court entered a Memorandum and Verdict determining that Wolf Run had breached the coal supply contract and that the performance shortfall was not excused by force majeure.  The trial court awarded total damages and interest in the amount of $104.1 million, which consisted of $13.8 million for past damages, and $90.3 million for future damages.  ICG and Allegheny filed post-verdict motions in the trial court and on August 23, 2011, the court denied the parties’ motions.  The court entered a final judgment on August 25, 2011, in the amount of $104.1 million, which included pre-judgment interest.

The parties appealed the lower court’s decision to the Superior Court of Pennsylvania.  On August 13, 2012, the Superior Court of Pennsylvania affirmed the award of past damages, but ruled that the lower court should have calculated future damages as of the date of breach, and remanded the matter back to the lower court with instructions to recalculate that portion of the award. On November 19, 2012, Allegheny filed a Petition for Allowance of Appeal with the Supreme Court of Pennsylvania and Wolf Run and Hunter Ridge filed an Answer.  On July 2, 2013, the Supreme Court of Pennsylvania denied the Petition of Allowance.  As this action finalized the past damage award, Wolf Run paid $15.6 million for the past damage amount, including interest, to Allegheny in July 2013.  Testimony on the future damage award in the lower court concluded on May 19, 2014, and post-trial briefs and responses were submitted on August 8, 2014.  The court held a hearing on this matter on November 5, 2014 and on February 16, 2015 awarded Allegheny $7.5 million plus interest for the future damages.  On April 6, 2015, the parties entered into a settlement agreement pursuant to which Wolf Run agreed to pay $15 million and both parties agreed to release and discharge the other party from any further contractual liability.  As a result, the Company accrued an additional $2.8 million for the three months ended March 31, 2015 to bring the total amount accrued up to the settlement amount.  The expense associated with the accrual is reflected in the line item “Cost of sales”.  In April 2015, the Company idled the Sycamore No. 2 mine.

In addition, the Company is a party to numerous other claims and lawsuits with respect to various matters. As of June 30, 2015 and December 31, 2014, the Company had accrued $3.7 million and $22.3 million, respectively, for all legal matters, including $3.7 million and $10.1 million, respectively, classified as current.  The ultimate resolution of any such legal matter could result in outcomes which may be materially different from amounts the Company has accrued for such matters.

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16.  Segment Information

The Company’s reportable business segments are based on the major coal producing basins in which the Company operates and may include a number of mine complexes. The Company manages its coal sales by coal basin, not by individual mining complex. Geology, coal transportation routes to customers, regulatory environments and coal quality or type are characteristic to a basin, and, accordingly, market and contract pricing have developed by coal basin. Mining operations are evaluated based on adjusted EBITDA, as well as on other non-financial measures, such as safety and environmental performance. The Company’s reportable segments are the Powder River Basin (PRB) segment, with operations in Wyoming; and the Appalachia (APP) segment, with operations primarily in West Virginia.  The “Other” category combines other operating segments and includes the Company’s coal mining operations in Colorado and Illinois.

Operating segment results for the three and six months ended June 30, 2015 and 2014 are presented below. The Company uses Adjusted EBITDA to assess the operating segments’ performance and to allocate resources.  The Company’s management believes that Adjusted EBITDA presents a useful measure of our ability to service existing debt and incur additional debt based on ongoing operations.  Corporate, Other and Eliminations includes the change in fair value of coal derivatives and coal trading activities, net; corporate overhead; land management; other support functions; and the elimination of intercompany trans-actions.

	PRB			APP			Other Operating Segments		Corporate, Other and Eliminations			Consolidated
	(in thousands)
Three Months Ended June 30, 2015
Revenues	$	342,480		$	224,298		$	77,684	$	—		$	644,462
Adjusted EBITDA	56,654			11,427			7,456		(30,209		)	45,328
Depreciation, depletion and amortization	42,711			42,203			10,834		1,624			97,372
Amortization of acquired sales contracts, net	(761		)	(883		)	—		—			(1,644		)
Capital expenditures	4,425			7,948			1,668		62,440			76,481
Three Months Ended June 30, 2014
Revenues	$	358,265		$	280,961		$	74,550	$	—		$	713,776
Adjusted EBITDA	42,546			27,040			17,463		(22,117		)	64,932
Depreciation, depletion and amortization	41,036			51,232			9,583		613			102,464
Amortization of acquired sales contracts, net	(785		)	(2,477		)	23		—			(3,239		)
Capital expenditures	6,962			11,036			2,358		60,936			81,292
Six Months Ended June 30, 2015
Revenues	$	733,686		$	447,737		$	140,044	$	—		$	1,321,467
Adjusted EBITDA	128,716			51,234			9,147		(61,997		)	127,100
Depreciation, depletion and amortization	87,072			90,930			20,889		3,355			202,246
Amortization of acquired sales contracts, net	(2,046		)	(2,988		)	—		—			(5,034		)
Capital expenditures	21,394			11,333			4,310		62,324			99,361
Six Months Ended June 30, 2014
Revenues	$	716,872		$	560,098		$	170,839	$	1,938		$	1,449,747
Adjusted EBITDA	72,365			55,467			21,595		(56,890		)	92,537
Depreciation, depletion and amortization	80,281			106,220			19,102		1,284			206,887
Amortization of acquired sales contracts, net	(1,574		)	(5,451		)	90		—			(6,935		)
Capital expenditures	9,056			19,193			3,948		63,549			95,746

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A reconciliation of adjusted EBITDA to consolidated loss before income taxes follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Adjusted EBITDA	$	45,328		$	64,932		$	127,100		$	92,537
Depreciation, depletion and amortization	(97,372		)	(102,464		)	(202,246		)	(206,887		)
Amortization of acquired sales contracts, net	1,644			3,239			5,034			6,935
Asset impairment and mine closure costs	(19,146		)	(1,512		)	(19,146		)	(1,512		)
Interest expense, net	(98,612		)	(95,924		)	(195,491		)	(190,552		)
Other nonoperating expense	$	(4,016	)	$	—		(4,016		)	—
Loss before income taxes	$	(172,174	)	$	(131,729	)	$	(288,765	)	$	(299,479	)

17.  Subsequent Events

Customer Contract Termination

On September 20, 2012, Patriot Coal Corporation (“Patriot”) filed a motion with the U.S. Bankruptcy Court for the Southern District of New York to reject a master coal sales agreement entered into on December 31, 2005 between the Company and Magnum Coal Company (“Magnum”) which was acquired by Patriot in July 2008.  The master coal sales agreement was established in order to meet obligations under a coal sales agreement with a customer who did not consent to the assignment of their contract to Magnum.  On December 18, 2012, the court accepted Patriot’s motion to reject the master coal sales agreement.  As a result of the court’s decision, the Company accrued $58.3 million, which represented the discounted cash flows of the remaining monthly buyout amounts under the underlying coal sales agreement.  Subsequent to June 30, 2015, the Company has entered into a definite agreement to terminate the contract after payment of $12.5 million of which $3.5 million will be paid upon execution of the agreement with the remaining $9.0 million to be paid on October 1, 2015.  The termination of the contract will generate an approximate $25.0 million pre-tax gain which will be recorded in the Company’s third quarter results.

Reverse Stock Split

On August 4, 2015, the Company’s common stock is expected to begin trading on the New York Stock Exchange (“NYSE”) on a split-adjusted basis following a one-for-ten reverse stock split originally announced on July 20, 2015.  Every ten shares of issued and outstanding common stock, including treasury shares, will be exchanged into one share of the Company’s common stock.  As a result of the reverse stock split, the number of outstanding shares of the Company’s common stock will be reduced from approximately 213 million to 21.3 million.  No fractional shares will be issued in connection with the reverse stock split; instead, stockholders who otherwise would have received fractional shares will receive, in lieu of such fractional shares, an amount of cash based on the volume weighted average price of the Company’s common stock for the date of the reverse stock split, which is expected to be August 3, 2015.

Debt Restructuring

On July 2, 2015, the Company launched two private debt exchange offers in an effort to de-lever the balance sheet and improve our liquidity profile.

The first offer exchanges, for each $1,000 of outstanding 7.25% Senior Notes due 2020 (the “2020 Notes”), $418.69 of new 6.25% Trust Certificates due 2021 (the “Trust Certificates”) and a $60 cash payment for holders that tendered before July 17, 2015, or a $30 cash payment for holders who tendered thereafter and before expiration of the offer (July 31, 2015, unless extended by us).  The Trust Certificates represent a fractional undivided interest in Arch Pass Through Trust, a Delaware statutory trust (the “Trust”) whose only assets will be (i) senior secured term loans due 2021 (the “New Term Loans”) issued as incremental debt under Arch’s existing credit agreement and (ii) senior secured revolving commitments (the “New Revolving Loans”). The New Revolving Loans will be transferred to the Trust by the assignment of existing revolving commitments.  The aggregate principal amount of New Term Loans and New Revolving Loans outstanding at any time may not exceed $404 million, and will be equal to the principal amount of Trust Certificates issued in the offers described herein.  In conjunction with the exchange offer, the Company has solicited consents (the “Consent

18

Solicitation”) from holders of the 2020 Notes to certain proposed amendments (the “Proposed 2020 Notes Amendments”) to the indenture governing the 2020 Notes.  The Proposed 2020 Notes Amendments modify certain restrictive covenants contained in such indenture to conform to the Company’s other indentures, including with respect to the issuance of additional secured debts.  Holders who tender their 2020 Notes are deemed to consent to the Proposed 2020 Notes Amendments, and holders may not deliver consents to the Proposed 2020 Notes Amendments without tendering their 2020 Notes in the exchange offer.  The consummation of the exchange offer is conditioned upon, among other things, and the Proposed 2020 Notes Amendments require, the receipt of consents pursuant to the Consent Solicitation from the holders of a majority in aggregate principal amount of outstanding 2020 Notes not owned by the Company or any of its affiliates.  The offer is only available to holders of 2020 Notes that are qualified institutional buyers pursuant to Rule 144A and qualified purchasers pursuant to Section 2(a)(51) of the Investment Company Act.  Holders that are therefore not eligible have been offered new 8.0% Secured Notes due 2022 (the “New 2022 Secured Notes) (which will be secured by liens on our assets ranking junior to the liens securing our credit agreement and senior to the liens securing our existing second lien notes and the new 2023 Secured Notes)  at a rate of $837.38 per $1,000 of 2020 Notes plus the same cash payment referred to above.  As of July 29, 2015, holders of $414.4 million of 2020 Notes have tendered in the offer and an additional $32.7 million have tendered in the offer for non-eligible holders.  Withdrawal rights for the offer have expired, and we have executed a supplemental indenture containing the Proposed Amendments, although the Proposed Amendments will not be operative until the offer is consummated.

The second offer exchanges Trust Certificates, New 2022 Secured Notes and 12.0% Senior Secured Second Lien Notes due 2023 (the “New 2023 Secured Notes”) for outstanding 7.00% Senior Notes due 2019 (“Old 7.00% 2019 Notes”), 9.875% Senior Notes due 2019 (“Old 9.875% 2019 Notes”) and 7.25% Senior Notes due 2021 (“Old 7.25% 2021 Notes”).  Each holder of Old Notes will have to elect (subject to the acceptance priority, allocation and proration mechanics described in the Offering Memorandum referred to below) whether it wishes to receive exchange consideration in the form of Trust Certificates, New 2022 Secured Notes or New 2023 Secured Notes in exchange for each $1,000 principal amount of Old Notes validly tendered and accepted for exchange.  The aggregate principal amount of New Securities received by tendering holders of a series of Old Notes per $1,000 principal amount tendered will be the same with respect to all holders of such series of Old Notes ($400 in the case of Old 7% 2019 Notes and Old 7.25% 2021 Notes and $450 in the case of Old 9.875% 2019 Notes, in each case if tendered at or prior to the Early Tender Time (currently August 4, 2015)), irrespective of the form of consideration elected, even though the Trust Certificates are expected to be more valuable than the New 2022 Secured Notes, which are in turn expected to be more valuable than the New 2023 Secured Notes, as a result of the different priorities of the liens securing (or underlying ) the New Securities.  The aggregate principal amount of New Securities to be issued pursuant to the Exchange Offer will be determined in accordance with the Acceptance Priority Level (as defined below), the Maximum Exchange Amount (as defined below), the tender caps referred to in the immediately succeeding sentence and certain other terms and conditions, and may also be based on when Old Notes are tendered, as described in the Offering Memorandum referred to below.  The tender caps will limit the aggregate principal amount of New Securities to be issued in the Exchange Offer to:  (i) in the case of the Trust Certificates, $404.0 million, minus the aggregate principal amount of Trust Certificates issued pursuant to the exchange offer referred to above, (ii) in the case of New 2022 Secured Notes, $200.0 million, minus the aggregate principal amount of New 2022 Secured Notes issued pursuant to the ineligible holders offer referred to above, and (iii) in the case of the New 2023 Secured Notes, $150.0 million.  The “Maximum Exchange Amount” refers to the sum of the tender caps.  The consummation of the Exchange Offer is conditioned upon, among other things, the completion of the exchange offer and consent solicitation referred to above.  As of July 29, 2015, holders of $487.2 million of Old 7.00% 2019 Notes, holders of $169.2 million of Old 9.875% 2019 Notes and holders of $398.1 million of Old 7.25% 2021 Notes have tendered in the offer.  Withdrawal rights for the exchange offer have expired.  Based on the tenders to date, the Trust would issue $404 million of Trust Certificates and we would issue $200 million of New 2022 Secured Notes and $27.1 million of New 2023 Secured Notes and we would achieve debt reduction of $870 million and reduce annual interest expense by $67.6 million.

Completion of the offers is subject to various conditions and requires execution of certain documents by the administrative agents under the existing credit agreement.  On July 28, 2015, certain unidentified term loan lenders under the credit agreement purporting to hold more than 50% of the term loans under the credit agreement delivered a letter to the term loan administrative agent directing it to refrain from executing documentation relating to the exchange offers.  In addition, the letter includes certain other assertions regarding the exchange offers and the existence of a default under the Credit Agreement.  Arch Coal has evaluated the assertions made in the letter and believes they are without merit.  While Arch Coal believes that the assertions and directions set forth above are without merit, and intends to contest them vigorously, it cannot predict what effect the assertions and direction set forth in the letter, or any future claims, might have on the exchange offers.  In particular, if the term loan administrative agent elects to follow the direction embodied in the letter, the exchange offers would not be consummated.

19

18. Supplemental Consolidating Financial Information

Pursuant to the indentures governing Arch Coal, Inc.’s senior notes, certain wholly-owned subsidiaries of the Company have fully and unconditionally guaranteed the senior notes on a joint and several basis. The following tables present condensed consolidating financial information for (i) the Company, (ii) the issuer of the senior notes, (iii) the guarantors under the senior notes, and (iv) the entities which are not guarantors under the senior notes (Arch Receivable Company, LLC and the Company’s subsidiaries outside the United States):

20

Condensed Consolidating Statements of Operations

Three Months Ended June 30, 2015

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	644,462		$	—		$	—		$	644,462
Costs, expenses and other
Cost of sales (exclusive of items shown separately below)	5,908			561,191			—			(847		)	566,252
Depreciation, depletion and amortization	1,013			96,359			—			—			97,372
Amortization of acquired sales contracts, net	—			(1,644		)	—			—			(1,644		)
Change in fair value of coal derivatives and coal trading activities, net	—			1,211			—			—			1,211
Asset impairment and mine closure costs	1,225			17,921			—			—			19,146
Selling, general and administrative expenses	17,166			6,270			1,325			(493		)	24,268
Other operating (income) expense, net	(138		)	7,483			(1,282		)	1,340			7,403
	25,174			688,791			43			—			714,008
Loss from investment in subsidiaries	(30,462		)	—			—			30,462			—
Loss from operations	(55,636		)	(44,329		)	(43		)	30,462			(69,546		)
Interest expense, net
Interest expense	(119,231		)	(6,576		)	(1,127		)	27,360			(99,574		)
Interest and investment income	6,675			20,256			1,391			(27,360		)	962
	(112,556		)	13,680			264			—			(98,612		)
Expenses related to debt restructuring	(4,016		)	—			—			—			(4,016		)
Income (loss) from continuing operations before income taxes	(172,208		)	(30,649		)	221			30,462			(172,174		)
Provision for (benefit from) income taxes	(4,105		)	—			34			—			(4,071		)
Net income (loss)	$	(168,103	)	$	(30,649	)	$	187		$	30,462		$	(168,103	)
Total comprehensive income (loss)	$	(167,887	)	$	(30,811	)	$	187		$	30,624		$	(167,887	)

21

Condensed Consolidating Statements of Operations

Three Months Ended June 30, 2014

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	713,776		$	—		$	—		$	713,776
Costs, expenses and other
Cost of sales (exclusive of items shown separately below)	3,547			619,470			—			(880		)	622,137
Depreciation, depletion and amortization	1,346			101,109			9			—			102,464
Amortization of acquired sales contracts, net	—			(3,239		)	—			—			(3,239		)
Change in fair value of coal derivatives and coal trading activities, net	—			(2,992		)	—			—			(2,992		)
Asset impairment and mine closure costs	1,512			—			—			—			1,512
Selling, general and administrative expenses	21,729			7,250			1,489			(537		)	29,931
Other operating (income) expense, net	(1,883		)	1,554			(1,320		)	1,417			(232		)
	26,251			723,152			178			—			749,581
Income from investment in subsidiaries	2,502			—			—			(2,502		)	—
Loss from operations	(23,749		)	(9,376		)	(178		)	(2,502		)	(35,805		)
Interest expense, net
Interest expense	(116,084		)	(6,565		)	(1,092		)	25,781			(97,960		)
Interest and investment income	8,125			18,341			1,351			(25,781		)	2,036
	(107,959		)	11,776			259			—			(95,924		)
Income (loss) from continuing operations before income taxes	(131,708		)	2,400			81			(2,502		)	(131,729		)
Provision for (benefit from) income taxes	(34,848		)	—			(21		)	—			(34,869		)
Net loss	$	(96,860	)	$	2,400		$	102		$	(2,502	)	$	(96,860	)
Total comprehensive income (loss)	$	(98,437	)	$	1,647		$	102		$	(1,749	)	$	(98,437	)

22

Condensed Consolidating Statements of Operations

Six Months Ended June 30, 2015

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	1,321,467		$	—		$	—		$	1,321,467
Costs, expenses and other
Cost of sales (exclusive of items shown separately below)	13,378			1,116,877			—			(1,681		)	1,128,574
Depreciation, depletion and amortization	2,073			200,171			2			—			202,246
Amortization of acquired sales contracts, net	—			(5,034		)	—			—			(5,034		)
Change in fair value of coal derivatives and coal trading activities, net	—			2,431			—			—			2,431
Asset impairment and mine closure costs	1,225			17,921			—			—			19,146
Selling, general and administrative expenses	32,605			12,514			2,773			(1,019		)	46,873
Other operating (income) expense, net	3,562			12,760			(2,533		)	2,700			16,489
	52,843			1,357,640			242			—			1,410,725
Loss from investment in subsidiaries	(9,413		)	—			—			9,413			—
Loss from operations	(62,256		)	(36,173		)	(242		)	9,413			(89,258		)
Interest expense, net
Interest expense	(237,286		)	(13,340		)	(2,402		)	54,202			(198,826		)
Interest and investment income	14,747			40,030			2,760			(54,202		)	3,335
	(222,539		)	26,690			358			—			(195,491		)
Expenses related to debt restructuring	(4,016		)	—			—			—			(4,016		)
Income (loss) from continuing operations before income taxes	(288,811		)	(9,483		)	116			9,413			(288,765		)
Provision for (benefit from) income taxes	(7,513		)	—			46			—			(7,467		)
Net income (loss)	$	(281,298	)	$	(9,483	)	$	70		$	9,413		$	(281,298	)
Total comprehensive income (loss)	$	(277,478	)	$	(6,405	)	$	70		$	6,335		$	(277,478	)

23

Condensed Consolidating Statements of Operations

Six Months Ended June 30, 2014

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	1,449,747		$	—		$	—		$	1,449,747
Costs, expenses and other
Cost of sales (exclusive of items shown separately below)	6,937			1,303,246			—			(1,732		)	1,308,451
Depreciation, depletion and amortization	2,818			204,051			18			—			206,887
Amortization of acquired sales contracts, net	—			(6,935		)	—			—			(6,935		)
Change in fair value of coal derivatives and coal trading activities, net	—			(2,078		)	—			—			(2,078		)
Asset impairment and mine closure costs	1,512			—			—			—			1,512
Selling, general and administrative expenses	41,673			15,115			3,292			(1,013		)	59,067
Other operating (income) expense, net	(290		)	(7,929		)	(2,756		)	2,745			(8,230		)
	52,650			1,505,470			554			—			1,558,674
Loss from investment in subsidiaries	(32,844		)	—			—			32,844			—
Loss from operations	(85,494		)	(55,723		)	(554		)	32,844			(108,927		)
Interest expense, net
Interest expense	(229,739		)	(12,890		)	(2,142		)	50,340			(194,431		)
Interest and investment income	15,726			35,993			2,500			(50,340		)	3,879
	(214,013		)	23,103			358			—			(190,552		)
Loss from continuing operations before income taxes	(299,507		)	(32,620		)	(196		)	32,844			(299,479		)
Provision for (benefit from) income taxes	(78,508		)	—			28			—			(78,480		)
Net loss	$	(220,999	)	$	(32,620	)	$	(224	)	$	32,844		$	(220,999	)
Total comprehensive loss	$	(225,206	)	$	(34,779	)	$	(224	)	$	35,003		$	(225,206	)

24

Condensed Consolidating Balance Sheets

June 30, 2015

	Parent/Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Cash and cash equivalents	$	367,668	$	60,568	$	11,419	$	—		$	439,655
Short term investments	249,754		—		—		—			249,754
Restricted cash	—		—		43,563		—			43,563
Receivables	9,525		10,352		204,002		(4,338		)	219,541
Inventories	—		223,929		—		—			223,929
Other	80,295		39,160		1,024		—			120,479
Total current assets	707,242		334,009		260,008		(4,338		)	1,296,921
Property, plant and equipment, net	9,211		6,331,424		—		391			6,341,026
Investment in subsidiaries	7,448,526		—		—		(7,448,526		)	—
Intercompany receivables	—		2,164,803		—		(2,164,803		)	—
Note receivable from Arch Western	675,000		—		—		(675,000		)	—
Other	119,670		277,555		1,183		—			398,408
Total other assets	8,243,196		2,442,358		1,183		(10,288,329		)	398,408
Total assets	$	8,959,649	$	9,107,791	$	261,191	$	(10,292,276	)	$	8,036,355
Liabilities and Stockholders’ Equity
Accounts payable	$	12,096	$	144,588	$	41	$	—		$	156,725
Accrued expenses and other current liabilities	59,336		207,265		695		(4,338		)	262,958
Current maturities of debt	21,651		10,112		—		—			31,763
Total current liabilities	93,083		361,965		736		(4,338		)	451,446
Long-term debt	5,078,125		36,456		—		—			5,114,581
Intercompany payables	1,930,704		—		234,099		(2,164,803		)	—
Note payable to Arch Coal	—		675,000		—		(675,000		)	—
Asset retirement obligations	1,018		408,417		—		—			409,435
Accrued pension benefits	5,023		8,557		—		—			13,580
Accrued postretirement benefits other than pension	4,298		29,878		—		—			34,176
Accrued workers’ compensation	10,714		86,775		—		—			97,489
Deferred income taxes	411,930		—		—		—			411,930
Other noncurrent liabilities	31,120		78,332		241		—			109,693
Total liabilities	7,566,015		1,685,380		235,076		(2,844,141		)	6,642,330
Stockholders’ equity	1,393,634		7,422,411		26,115		(7,448,135		)	1,394,025
Total liabilities and stockholders’ equity	$	8,959,649	$	9,107,791	$	261,191	$	(10,292,276	)	$	8,036,355

25

Condensed Consolidating Balance Sheets

December 31, 2014

	Parent/Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Cash and cash equivalents	$	572,185	$	150,358	$	11,688	$	—		$	734,231
Short term investments	248,954		—		—		—			248,954
Restricted cash	—		—		5,678		—			5,678
Receivables	9,656		15,933		211,043		(4,615		)	232,017
Inventories	—		190,253		—		—			190,253
Other	89,211		41,455		952		—			131,618
Total current assets	920,006		397,999		229,361		(4,615		)	1,542,751
Property, plant and equipment, net	10,470		6,442,623		2		363			6,453,458
Investment in subsidiaries	7,464,221		—		—		(7,464,221		)	—
Intercompany receivables	—		2,021,110		—		(2,021,110		)	—
Note receivable from Arch Western	675,000		—		—		(675,000		)	—
Other	131,884		300,058		1,572		—			433,514
Total other assets	8,271,105		2,321,168		1,572		(10,160,331		)	433,514
Total assets	$	9,201,581	$	9,161,790	$	230,935	$	(10,164,583	)	$	8,429,723
Liabilities and Stockholders’ Equity
Accounts payable	$	23,394	$	156,664	$	55	$	—		$	180,113
Accrued expenses and other current liabilities	85,899		220,017		1,095		(4,615		)	302,396
Current maturities of debt	27,625		9,260		—		—			36,885
Total current liabilities	136,918		385,941		1,150		(4,615		)	519,394
Long-term debt	5,084,839		38,646		—		—			5,123,485
Intercompany payables	1,817,755		—		203,355		(2,021,110		)	—
Note payable to Arch Coal	—		675,000		—		(675,000		)	—
Asset retirement obligations	981		397,915		—		—			398,896
Accrued pension benefits	5,967		10,293		—		—			16,260
Accrued postretirement benefits other than pension	4,430		28,238		—		—			32,668
Accrued workers’ compensation	9,172		85,119		—		—			94,291
Deferred income taxes	422,809		—		—		—			422,809
Other noncurrent liabilities	50,919		102,461		386		—			153,766
Total liabilities	7,533,790		1,723,613		204,891		(2,700,725		)	6,761,569
Stockholders’ equity	1,667,791		7,438,177		26,044		(7,463,858		)	1,668,154
Total liabilities and stockholders’ equity	$	9,201,581	$	9,161,790	$	230,935	$	(10,164,583	)	$	8,429,723

26

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2015

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash provided by (used in) operating activities	$	(295,792	)	$	163,345		$	6,872		$	—	$	(125,575	)
Investing Activities
Capital expenditures	(815		)	(98,546		)	—			—		(99,361		)
Additions to prepaid royalties	—			(409		)	—			—		(409		)
Proceeds from disposals and divestitures	—			991			—			—		991
Purchases of marketable securities	(161,336		)	—			—			—		(161,336		)
Proceeds from sale or maturity of marketable securities and other investments	157,729			—			—			—		157,729
Investments in and advances to affiliates	(788		)	(4,350		)	—			—		(5,138		)
Cash used in investing activities	(5,210		)	(102,314		)	—			—		(107,524		)
Financing Activities
Payments on term loan	(9,750		)	—			—			—		(9,750		)
Net payments on other debt	(5,973		)	(3,853		)	—			—		(9,826		)
Expenses related to debt restructuring	(4,016		)	—			—			—		(4,016		)
Withdrawals (deposits) of restricted cash	—			—			(37,885		)	—		(37,885		)
Transactions with affiliates, net	116,224			(146,968		)	30,744			—		—
Cash provided by (used in) financing activities	96,485			(150,821		)	(7,141		)	—		(61,477		)
Decrease in cash and cash equivalents	(204,517		)	(89,790		)	(269		)	—		(294,576		)
Cash and cash equivalents, beginning of period	572,185			150,358			11,688			—		734,231
Cash and cash equivalents, end of period	$	367,668		$	60,568		$	11,419		$	—	$	439,655

27

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2014

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash provided by (used in) operating activities	$	(268,382	)	$	196,505		$	(6,469	)	$	—	$	(78,346	)
Investing Activities
Capital expenditures	(660		)	(95,086		)	—			—		(95,746		)
Additions to prepaid royalties	—			(3,341		)	—			—		(3,341		)
Proceeds from disposals and divestitures	39,132			4,113			—			—		43,245
Purchases of short term investments	(168,951		)	—			—			—		(168,951		)
Proceeds from sales of short term investments	166,018			—			—			—		166,018
Investments in and advances to affiliates	(1,581		)	(7,920		)	—			—		(9,501		)
Cash provided by (used in) investing activities	33,958			(102,234		)	—			—		(68,276		)
Financing Activities
Payments on term loan	(9,750		)	—			—			—		(9,750		)
Debt financing costs	(1,957		)	—			—			—		(1,957		)
Net payments on other debt	(7,547		)	(1,843		)	—			—		(9,390		)
Dividends paid	(2,123		)	—			—			—		(2,123		)
Change in restricted cash	—			—			(1,103		)	—		(1,103		)
Transactions with affiliates, net	84,719			(92,486		)	7,767			—		—
Cash provided by (used in) financing activities	63,342			(94,329		)	6,664			—		(24,323		)
Increase (decrease) in cash and cash equivalents	(171,082		)	(58		)	195			—		(170,945		)
Cash and cash equivalents, beginning of period	799,333			100,418			11,348			—		911,099
Cash and cash equivalents, end of period	$	628,251		$	100,360		$	11,543		$	—	$	740,154

28

Item 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Overview

Our results during the second quarter of 2015, when compared to the second quarter of 2014, were impacted by continued weakness in both thermal and metallurgical coal markets.

Lower shipment volumes of domestic thermal coal in all segments was driven by low natural gas pricing, and implementation of the Mercury Air Toxics rule, MATS, in the current quarter.  Natural gas pricing during the second quarter of 2015 declined sufficiently for it to compete economically with coal as an electric generation fuel more widely than in the second quarter of 2014.  This led to reduced generator demand for thermal coal and increasing coal stockpiles.  Furthermore, some generators closed coal fueled facilities to comply with the MATS regulation.  Although the closed coal fueled  plants were generally older, smaller, and less utilized than the remaining fleet, the closures do have a negative impact on demand.

Pricing for our metallurgical products continues to be pressured by ongoing global oversupply and strengthening of the U.S. dollar.  Slowing economic growth in China and globally has slowed demand growth, and supply rationalization has been slow to take effect.  The relative strength of the U.S. dollar benefits our foreign competitors in the global metallurgical market as much of their input costs are in their local currencies.  We sold 1.6 million tons of metallurgical coal during the second quarter of 2015 compared to 1.7 million tons during the second quarter of 2014, and 3.1 million tons of metallurgical coal during the first half of 2015 compared to 3.3 million tons during the first half of 2014.

Higher pricing in the Powder River Basin, lower diesel fuel pricing, and other cost reductions partially offset these unfavorable trends.

See further information regarding committed sales in Item 3. “Quantitative and Qualitative Disclosures About Market Risk.”

Regional Performance

The following table shows results by operating segment for the three and six months ended June 30, 2015 and compares it with the information for the three and six months ended June 30, 2014.  The “other” category represents the results of our other bituminous thermal operations: our West Elk mining complex in Colorado and our Viper mining complex in Illinois.

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Powder River Basin
Tons sold (in thousands)	25,544			26,928			54,015			52,594
Coal sales per ton sold	$	13.24		$	12.79		$	13.37		$	12.76
Cost per ton sold	$	12.66		$	12.61		$	12.58		$	12.80
Operating margin per ton sold	$	0.58		$	0.18		$	0.79		$	(0.04	)
Adjusted EBITDA (in thousands)	$	56,654		$	42,546		$	128,716		$	72,365
Appalachia
Tons sold (in thousands)	3,102			3,687			6,120			7,276
Coal sales per ton sold	$	65.83		$	69.36		$	65.53		$	68.54
Cost per ton sold	$	76.46		$	76.25		$	72.56		$	78.49
Operating loss per ton sold	$	(10.63	)	$	(6.89	)	$	(7.03	)	$	(9.95	)
Adjusted EBITDA (in thousands)	$	11,427		$	27,040		$	51,234		$	55,467
Other
Tons sold (in thousands)	1,927			2,048			3,546			4,150
Coal sales per ton sold	$	30.37		$	31.34		$	31.76		$	29.97
Cost per ton sold	$	25.77		$	24.51		$	28.25		25.85
Operating margin per ton sold	$	4.60		$	6.83		$	3.51		$	4.12
Adjusted EBITDA (in thousands)	$	7,456		$	17,463		$	9,147		$	21,595

This table reflects numbers reported under a basis that differs from U.S. GAAP.  See the “Reconciliation of Non-GAAP measurements” for explanation and reconciliation of these amounts to the nearest GAAP figures.    Other companies may calculate these per ton amounts differently, and our calculation may not be comparable to other similarly titled measures.

29

Powder River Basin — Adjusted EBITDA increased approximately 33% in the second quarter and 78% in the first half of 2015 when compared to the second quarter and first half of 2014.  Pricing improved in the current year periods primarily due to the annual roll off and replacement of sales orders for 2015 occurring at a time of relatively favorable pricing following the harsh winter last year.  Shipment volume decreased and cost per ton sold increased slightly in the second quarter of 2015 when compared to the second quarter of 2014.  Low natural gas pricing and increased generator coal stockpiles compared to last year led to reduced generator demand in the second quarter of 2015.  Unit costs are higher in the second quarter of 2015 due to the decreased volume partially offset by lower diesel fuel pricing.  For the first half of 2015, shipment volume and cost per ton sold were favorable to the first half of 2014 due to strong carryover business from the prior year contributing to relatively robust demand in the first quarter of 2015 and lower diesel fuel pricing.  Our strategy of protecting against oil price spikes while preserving downside price participation has allowed us to benefit from the decrease in oil pricing in the current periods versus the prior year periods.  See further information regarding diesel fuel hedging strategies in Item 3. “Quantitative and Qualitative Disclosures About Market Risk.”

Appalachia — Adjusted EBITDA decreased approximately 58% in the second quarter and 8% in the first half of 2015 when compared to the second quarter and first half of 2014.  Shipment volume and coal sales per ton sold both declined in the current year periods versus the prior year. Coal sales volumes decreased in the second quarter and first half of 2015 when compared to the second quarter and first half of 2014, due to the sale of one complex in the first quarter of  2014 and the idling of two complexes impacting the comparative periods.  Pricing declined in the second quarter and first half of 2015 compared to the second quarter and first half of 2014 across all major quality specifications.  Low natural gas prices in the current year period negatively impacted regional demand and pricing for thermal coal.  Oversupply in the Asian metallurgical coal market, the strengthening US dollar, and low dry bulk shipping rates led to Australian competition in the Atlantic metallurgical coal market, further depressing metallurgical pricing in the second quarter of  2015.  Unit cost increased slightly  in the current quarter but decreased significantly in the first half of 2015 compared to the prior year periods.  The cost increase in the second quarter of  2015 is due to the timing of two longwall moves in the quarter, while the cost decrease of the first half of 2015 is related to the longer term shift in production to lower cost operations, particularly the Leer complex.  Adjusted EBITDA in the first half of 2014 includes gains from the sale of a thermal coal complex and idled thermal coal mine in Kentucky ($15.6 million).  The Sycamore No. 2 Mine was idled early in the second quarter of  2015.  See PART II, OTHER INFOMATION, Item 1, Legal Proceedings, Allegheny Energy Contract Matter for further discussion on the idling of the Sycamore No. 2 Mine.

Other — Adjusted EBITDA decreased approximately 57% in the second quarter and 58% in the first half of 2015 when compared to the second quarter and first half of 2014.  Sales volume declined in the current  year periods as a result of lower natural gas pricing, and unit cost increased due to the volume reduction.  Pricing decreased in the second quarter of 2015 when compared to the second quarter of 2014 due to the ongoing market weakness.  Pricing increased in the first half of 2015 when compared to the first half of 2014 due to a favorable mix of customer shipments in the first quarter of 2015.

Results of Operations

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Revenues.  Our revenues consist of coal sales.  The following table summarizes information about our coal sales during the three months ended June 30, 2015 and compares it with the information for the three months ended June 30, 2014:

	Three Months Ended June 30,
	2015		2014		(Decrease) / Increase
	(In thousands)
Coal sales	$	644,462	$	713,776	$	(69,314	)
Tons sold	30,573		32,663		(2,090		)

On a consolidated basis, coal sales decreased in the second quarter of 2015 from the second quarter of 2014, primarily due to the reduction in Appalachian volume and pricing of approximately $57 million, and secondarily due to reduced Powder River Basin volume of approximately $18 million.  Increased Powder River Basin pricing partially offset these impacts.  See discussion in “Regional Performance” for further information about regional results.

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Costs, expenses and other.  The following table summarizes costs, expenses and other components of operating income for the three months ended June 30, 2015 and compares it with the information for the three months ended June 30, 2014:

	Three Months Ended June 30,						(Increase) Decrease
	2015			2014			in Net Loss
	(In thousands)
Cost of sales (exclusive of items shown separately below)	$	566,252		$	622,137		$	55,885
Depreciation, depletion and amortization	97,372			102,464			5,092
Amortization of acquired sales contracts, net	(1,644		)	(3,239		)	(1,595		)
Change in fair value of coal derivatives and coal trading activities, net	1,211			(2,992		)	(4,203		)
Asset impairment and mine closure costs	19,146			1,512			(17,634		)
Selling, general and administrative expenses	24,268			29,931			5,663
Other operating (income) expense, net	7,403			(232		)	(7,635		)
Total costs, expenses and other	$	714,008		$	749,581		$	35,573

Cost of sales.  Our cost of sales decreased in the second quarter of 2015 from the second quarter of 2014, due to lower diesel fuel costs (a decrease of approximately $20 million), savings associated with two idled Appalachian complexes (approximately $17 million), lower transportation costs on reduced export sales volumes (approximately $6 million), lower sales sensitive costs (approximately $6 million), and other savings associated with cost control efforts primarily in Appalachia.  See discussion in “Regional Performance” for further information about regional results.

Depreciation, depletion and amortization.  When compared with the second quarter of 2014, depreciation, depletion and amortization costs decreased in 2015 due to reduced depreciation primarily in Appalachia related to mine idlings and ongoing low levels of capital expenditures.

Asset impairment and mine closure costs.  Impairment costs in the second quarter of 2015 include a prepaid coal royalty no longer expected to be recovered of approximately $12 million, and assets associated with idled Appalachia operations of approximately $5 million.  See Note 5, “Asset Impairment and Mine Closure Costs” to the condensed consolidated financial statements for further discussion.

Selling, general and administrative expenses. Total selling, general and administrative expenses decreased when compared with the second quarter of 2014, due to lower compensation expense, lower contractor services, and lower legal costs.

Other operating (income) expense, net.  Other operating expense for the three months ended June 30, of 2015 includes increased cost for liquidated damages on logistics contracts of approximately $4 million.  Additionally, other operating income in the prior year quarter benefited from a net gain on sale of various property, plant, and equipment of approximately $4 million.

Nonoperating Expense.  Nonoperating expenses in the second quarter of 2015 are related to our debt restructuring activities.  See further information regarding debt restructuring in Note 17, “Subsequent Events” to the condensed consolidated financial statements.

	Three Months Ended June 30,				Increase
	2015		2014		in Net Loss
	(In thousands)
Nonoperating expense	$	4,016	$	—	$	(4,016	)

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Benefit from income taxes.   The following table summarizes our benefit from income taxes for the three months ended June 30, 2015 and compares it with the information for the three months ended June 30, 2014:

	Three Months Ended June 30,						Increase
	2015			2014			in Net Loss
	(In thousands)
Benefit from income taxes	$	(4,071	)	$	(34,869	)	$	(30,798	)

The income tax benefit rate of 2.4% in the second quarter of 2015 decreased from 26.5% in the second quarter of 2014 due to an increase in the percentage of calculated tax benefit subject to a valuation allowance.  See further discussion in Note 11, “Income Taxes”, to the condensed consolidated financial statements.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Revenues.  Our revenues consist of coal sales.  The following table summarizes information about our coal sales during the six months ended June 30, 2015 and compares it with the information for the six months ended June 30, 2014:

	Six Months Ended June 30,
	2015		2014		(Decrease) / Increase
			(In thousands)
Coal sales	$	1,321,467	$	1,447,809	$	(126,342	)
Tons sold	63,682		64,020		(338		)

On a consolidated basis, coal sales decreased in the first half of 2015 from the first half of 2014, primarily due to the impact of the reduction in export volume of approximately $110 million, and secondarily due to reduced domestic sales from Appalachia and our Other operating segments of approximately $65 million.  Increased volume and pricing of Powder River Basin domestic sales offset these impacts by approximately $49 million.  See discussion in “Regional Performance” for further information about regional results.

Costs, expenses and other.  The following table summarizes costs, expenses and other components of operating income for the six months ended June 30, 2015 and compares it with the information for the six months ended June 30, 2014:

	Six Months Ended June 30,						(Increase) Decrease
	2015			2014			in Net Loss
	(In thousands)
Cost of sales (exclusive of items shown separately below)	$	1,128,574		$	1,308,451		$	179,877
Depreciation, depletion and amortization	202,246			206,887			4,641
Amortization of acquired sales contracts, net	(5,034		)	(6,935		)	(1,901		)
Change in fair value of coal derivatives and coal trading activities, net	2,431			(2,078		)	(4,509		)
Asset impairment and mine closure costs	19,146			1,512			(17,634		)
Selling, general and administrative expenses	46,873			59,067			12,194
Other operating (income) expense, net	16,489			(8,230		)	(24,719		)
Total costs, expenses and other	$	1,410,725		$	1,558,674		$	147,949

Cost of sales.  Our cost of sales decreased in the first half of 2015 from the first half of 2014, due to lower transportation costs on lower export sales volumes (a decrease of approximately $70 million), lower diesel fuel costs (approximately $44 million), savings associated with one sold and two idled Appalachian complexes (approximately $49 million), and other savings associated with cost control efforts primarily in Appalachia.  See discussion in “Regional Performance” for further information about regional results.

Depreciation, depletion and amortization.  When compared with the first half of 2014, depreciation, depletion and amortization costs decreased in 2015 due to reduced depreciation in Appalachia related to mine idlings and ongoing low levels of capital expenditures.  The decrease was partially offset by increased depletion and depreciation in the Powder River Basin.

Asset impairment and mine closure costs.  Please see the discussion in the comparison of results for the three month periods ended June 30, 2015 and 2014.  See Note 5, “Asset Impairment and Mine Closure Costs” to the condensed consolidated financial statements for further discussion.

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Selling, general and administrative expenses. Total selling, general and administrative expenses decreased when compared with the first half of 2014, due to lower compensation expenses, lower contractor services costs, and lower legal costs.

Other operating (income) expense, net.  Other operating expense for the first half of 2015 includes increased cost for liquidated damages on logistics contracts of approximately $4 million.  Additionally, the first half of 2014 reflects the benefit from a net gain on sale of operations of approximately $13 million, and a net gain on sale of various property, plant, and equipment of approximately $6 million.

Nonoperating Expense.  Please see the discussion in the comparison of results for the three month periods ended June 30, 2015 and 2014.  See further information regarding debt restructuring in Note 17, “Subsequent Events” to the condensed consolidated financial statements.

	Six Months Ended June 30,				Increase
	2015		2014		in Net Loss
	(In thousands)
Nonoperating expense	$	4,016	$	—	$	(4,016	)

Benefit from income taxes.   The following table summarizes our benefit from income taxes for the six months ended June 30, and compares it with the information for the six months ended June 30, 2014:

	Six Months Ended June 30,						Increase
	2015			2014			in Net Loss
	(In thousands)
Benefit from income taxes	$	(7,467	)	$	(78,480	)	$	(71,013	)

The income tax benefit rate of 2.6% in the first half of 2015 decreased from 26.2% in the first half of 2014 due to an increase in the percentage of calculated tax benefit subject to a valuation allowance.  See further discussion in Note 11, “Income Taxes”, to the condensed consolidated financial statements.

Reconciliation of NON-GAAP measures

Segment coal sales per ton sold

Segment coal sales per ton sold are calculated as the segment’s coal sales revenues divided by segment tons sold.  The segments’ sales per tons sold are adjusted for transportation costs, and may be adjusted for other items that, due to accounting rules, are classified in “other operating (income) expense, net” on the statement of operations, but relate to price protection on the sale of coal. Segment sales per ton sold is not a measure of financial performance in accordance with generally accepted accounting principles.  We believe segment sales per ton sold better reflects our revenue for the quality of coal sold and our operating results by including all income from coal sales. The adjustments made to arrive at these measures are significant in understanding and assessing our financial condition.  Therefore, segment coal sales revenues should not be considered in isolation, nor as an alternative to coal sales revenues under generally accepted accounting principles.

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	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Reported segment coal sales revenues	$	600,854		$	664,481		$	1,235,757		$	1,294,434
Coal risk management derivative settlements classified in “other (income) expense, net”	(648		)	(1,318		)	(1,619		)	(4,197		)
Transportation costs	44,256			50,613			87,329			157,573
Coal sales	644,462			713,776			1,321,467			1,447,810
Other revenues	$	—		$	—		$	—		$	1,938
	$	644,462		$	713,776		$	1,321,467		$	1,449,747

Segment cost per ton sold

Segment costs per ton sold are calculated as the segment’s cost of tons sold divided by segment tons sold.  The segments’ cost of tons sold are adjusted for transportation costs, and may be adjusted for other items that, due to accounting rules, are classified in “other (income) expense, net” on the statement of operations, but relate directly to the costs incurred to produce coal. Segment cost of tons sold is not a measure of financial performance in accordance with generally accepted accounting principles.  We believe segment cost of tons sold better reflects our controllable costs and our operating results by including all costs incurred to produce coal. The adjustments made to arrive at these measures are significant in understanding and assessing our financial condition.  Therefore, segment cost of tons sold should not be considered in isolation, nor as an alternative to cost of sales under generally accepted accounting principles.

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Reported segment cost of tons sold	$	610,165		$	671,130		$	1,222,923		$	1,351,427
Diesel fuel risk management derivative settlements classified in “other (income) expense, net”	(986		)	(1,684		)	(2,210		)	(3,563		)
Transportation costs	44,256			50,613			87,329			157,573
Depreciation, depletion and amortization in reported segment cost of tons sold presented on separate line on statement of operations	(103,143		)	(101,851		)	(206,286		)	(205,603		)
Other (other operating segments, operating overhead, etc.)	15,960			3,929			26,818			8,617
Cost of sales	$	566,252		$	622,137		$	1,128,574		$	1,308,451

Segment Adjusted EBITDA to Net Income

The discussion in “Results of Operations” includes references to our Adjusted EBITDA. Adjusted EBITDA is defined as net income attributable to the Company before the effect of net interest expense, income taxes, depreciation, depletion and amortization and the amortization of acquired sales contracts. Adjusted EBITDA may also be adjusted for items that may not reflect the trend of future results. We believe that Adjusted EBITDA presents a useful measure of our ability to service and incur debt based on ongoing operations. Investors should be aware that our presentation of Adjusted EBITDA may not be comparable to similarly titled measures used by other companies. The table below shows how we calculate Adjusted EBITDA.

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	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Reported Segment Adjusted EBITDA	$	75,537		$	87,049		$	189,097		$	149,427
Corporate and other	(30,209		)	(22,117		)	(61,997		)	(56,890		)
Adjusted EBITDA	45,328			64,932			127,100			92,537
Income tax benefit	4,071			34,869			7,467			78,480
Interest expense, net	(98,612		)	(95,924		)	(195,491		)	(190,552		)
Depreciation, depletion and amortization	(97,372		)	(102,464		)	(202,246		)	(206,887		)
Amortization of acquired sales contracts, net	1,644			3,239			5,034			6,935
Asset impairment costs	(19,146		)	(1,512		)	(19,146		)	(1,512		)
Other nonoperating expenses	(4,016		)	—			(4,016		)	—
Net loss	$	(168,103	)	$	(96,860	)	$	(281,298	)	$	(220,999	)

Corporate and other includes primarily selling, general and administrative expenses, income from our equity investments, certain actuarial adjustments, and certain changes in the fair value of coal derivatives and coal trading activities.  Corporate and other adjusted EBITDA decreased $8.1 million in the second quarter 2015 when compared to the second quarter 2014 due to increases in certain actuarial costs of $6.6 million, a $4.2 million negative impact from changes in the fair value of coal derivatives and coal trading activities versus the prior year quarter, and $3.0 million in reduced gains from sale of property plant and equipment not associated with reporting segments, partially offset by $5.7 million of reduced expenses recorded in the Statement of Operations line item “Selling, general and administrative expenses”.  The first half of 2015 decreased $5.1 million due to increases in certain actuarial costs of $7.9 million, a $4.5 million negative impact from changes in the fair value of coal derivatives and coal trading activities versus the prior year quarter, and $3.0 million in reduced gains from sale of property plant and equipment not associated with reporting segments, partially offset by $12.2 million of reduced expenses recorded in the Statement of Operations line item “Selling, general and administrative expenses”.

Liquidity and Capital Resources

Our primary sources of cash are coal sales to customers, availability under our credit facilities and other financing arrangements, and debt and equity offerings related to significant transactions or refinancing activity. Excluding significant investing activity, we generally satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations, cash on hand or borrowings under our lines of credit. Such plans are subject to change based on our cash needs.  During the market down cycle our focus is preserving liquidity and prudently managing costs, including capital expenditures.  In addition, we regularly evaluate our capital structure and may make debt purchases for cash and /or exchanges for debt or equity from time to time through tender offers, open market purchases, private transactions, or otherwise, or seek to raise additional debt or equity, depending on market conditions and covenant restrictions.

We have no meaningful maturities of debt until 2018, and financial maintenance covenants in our capital structure pertain only to our $250 million revolver.  As of June 30, 2015, covenants under the revolver are a senior secured leverage ratio covenant of  5.0 times trailing twelve months EBITDA, and minimum liquidity covenant of $550 million.  We were in compliance with the covenants at June 30, 2015.  We had liquidity of $812.2 million at June 30, 2015, with $689.4 million of that in cash and liquid securities.  We have no borrowings outstanding under our revolving credit agreement at June 30, 2015.

On July 2, 2015 we launched two private debt exchange offers in an effort to de-lever the balance sheet and improve our liquidity profile.  See further information regarding debt restructuring in Note 17, “Subsequent Events” to the condensed consolidated financial statements.

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The following is a summary of cash provided by or used in each of the indicated types of activities during the six months ended June 30,  2015 and 2014:

	Six Months Ended June 30,
	2015			2014
	(In thousands)
Cash provided by (used in):
Operating activities	$	(125,575	)	$	(78,346	)
Investing activities	(107,524		)	(68,276		)
Financing activities	(61,477		)	(24,323		)

Cash used in operating activities during the first half of 2015 increased to $125.6 million compared to cash used in operating activities of $78.3 million in the first half months of 2014.  The increase was driven by increased use of cash in working capital, particularly inventory and payables. The increase was partially offset by increased Adjusted EBITDA resulting from improved shipment volumes and pricing in the Powder River Basin, improved productivity in Appalachia, and lower diesel fuel pricing.

We used $107.5 million of cash in investing activities during the first half 2015 compared to using $68.3 million of cash in the first half 2014, as proceeds from disposals and divestitures decreased $42.3 million.  The divestitures of a Kentucky operation, idled assets, and our ADDCAR subsidiary are reflected in 2014 with no significant divestitures in 2015. Capital expenditures increased approximately $3.6 million primarily related to equipment lease buyouts at our Powder River Basin operations.

Cash used in financing activities increased $37.2 million in the first half of 2015, compared to the first half of 2014, as restricted cash increased $36.8 million and debt restructuring costs of $4.0 million were incurred.  These uses of cash were partially offset by the benefit from the elimination of the dividend on our common stock of $2.1 million, and approximately $2.0 million in debt financing costs incurred in the prior year quarter.

Ratio of Earnings to Fixed Charges

The following table sets forth our ratios of earnings to combined fixed charges and preference dividends for the periods indicated:

	Six Months Ended June 30,
	2015	2014
Ratio of earnings to combined fixed charges and preference dividends(1)	N/A	N/A	(2)

(1)Earnings consist of income from continuing operations before income taxes and are adjusted to include only distributed income from affiliates accounted for on the equity method and fixed charges (excluding capitalized interest). Fixed charges consist of interest incurred on indebtedness, the portion of operating lease rentals deemed representative of the interest factor and the amortization of debt expense.

(2)Total losses for the ratio calculation round to $69.4 million and total fixed charges were $203.8 million for the six months ended June 30, 2015.  Total losses for the ratio calculation were $95.5 million and total fixed charges were $200.2 million for the six months ended June 30, 2014.

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

We manage our commodity price risk for our non-trading, thermal coal sales through the use of long-term coal supply agreements, and to a limited extent, through the use of derivative instruments.  Sales commitments in the metallurgical coal market are typically not long-term in nature, and we are therefore subject to fluctuations in market pricing.

Our sales commitments for 2015 and 2016 were as follows as of July 20, 2015:

	2015			2016
	Tons	$ per ton		Tons	$ per ton
	(in millions)			(in millions)
Powder River Basin
Committed, Priced	105.5	$	13.32	52.0	$	13.99
Committed, Unpriced	1.6			14.3
Appalachia
Committed, Priced Thermal	5.6	$	55.69	2.0	$	58.04
Committed, Unpriced Thermal	—			—
Committed, Priced Metallurgical	5.2	$	77.20	0.7	$	82.45
Committed, Unpriced Metallurgical	0.4			0.6
Other Bituminous
Committed, Priced	6.7	$	32.24	3.0	$	34.85
Committed, Unpriced	0.2			—

We are also exposed to commodity price risk in our coal trading activities, which represents the potential future loss that could be caused by an adverse change in the market value of coal. Our coal trading portfolio included forward, swap and put and call option contracts at June 30, 2015. The estimated future realization of the value of the trading portfolio is $1.1 million of gains in the remainder of 2015 and $1.3 million of gains in 2016.

We monitor and manage market price risk for our trading activities with a variety of tools, including Value at Risk (VaR), position limits, management alerts for mark to market monitoring and loss limits, scenario analysis, sensitivity analysis and review of daily changes in market dynamics. Management believes that presenting high, low, end of year and average VaR is the best available method to give investors insight into the level of commodity risk of our trading positions. Illiquid positions, such as long-dated trades that are not quoted by brokers or exchanges, are not included in VaR.

VaR is a statistical one-tail confidence interval and down side risk estimate that relies on recent history to estimate how the value of the portfolio of positions will change if markets behave in the same way as they have in the recent past. The level of confidence is 95%.   The time across which these possible value changes are being estimated is through the end of the next business day. A closed-form delta-neutral method used throughout the finance and energy sectors is employed to calculate this VaR. VaR is back tested to verify its usefulness.

On average, portfolio value should not fall more than VaR on 95 out of 100 business days. Conversely, portfolio value declines of more than VaR should be expected, on average, 5 out of 100 business days. When more value than VaR is lost due to market price changes, VaR is not representative of how much value beyond VaR will be lost.

While presenting VaR will provide a similar framework for discussing risk across companies, VaR estimates from two independent sources are rarely calculated in the same way. Without a thorough understanding of how each VaR model was calculated, it would be difficult to compare two different VaR calculations from different sources.

During the six months ended June 30, 2015, VaR for our coal trading positions that are recorded at fair value through earnings ranged from under $0.1 million to $0.8 million. The linear mean of each daily VaR was $0.3 million. The final VaR at June 30, 2015 was $0.2 million.

We are exposed to fluctuations in the fair value of coal derivatives that we enter into to manage the price risk related to future coal sales, but for which we do not elect hedge accounting. Gains or losses on these derivative instruments would be largely offset in the pricing of the physical coal sale.  During the six months ended June 30, 2015, VaR for our risk management positions that are recorded at fair value through earnings ranged from $0.1 million to $0.3 million. The linear mean of each daily VaR was $0.2 million. The final VaR at June 30, 2015 was $0.2 million.

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We are also exposed to the risk of fluctuations in cash flows related to our purchase of diesel fuel. We expect to use approximately 57 to 62 million gallons of diesel fuel for use in our operations during 2015. We enter into forward physical purchase contracts, as well as purchased heating oil options, to reduce volatility in the price of diesel fuel for our operations.  At June 30, 2015, we had protected the price of approximately 100% of its expected purchases for the remainder of the year with out-of-the-money call options with an average strike price of $3.13 per gallon.  Due to the drop in heating oil pricing, we have layered in 19.5 million gallons of at-the-money call options for the second half of 2015 representing 65% of expected purchases at an average strike price of $1.92 per gallon.  Additionally, we have protected approximately 49% of our expected 2016 purchases with out-of-the-money call options.  At June 30, 2015, we had purchased heating oil call options for approximately 66 million gallons for the purpose of managing the price risk associated with future diesel purchases.  A $0.25 per gallon decrease in the price of heating oil would not result in an increase in our expense related to the heating oil derivatives.

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At June 30, 2015, of our $5.1 billion principal amount of debt outstanding, approximately $1.9 billion of outstanding borrowings have interest rates that fluctuate based on changes in the market rates. An increase in the interest rates related to these borrowings of 25 basis points would not result in an annualized increase in interest expense based on interest rates in effect at June 30, 2015, because our term loan has a minimum interest rate that exceeds the current market rates.

Item 4.  Controls and Procedures.

We performed an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2015.  Based on that evaluation, our management, including our chief executive officer and chief financial officer, concluded that the disclosure controls and procedures were effective as of such date. There were no changes in our internal control over financial reporting during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II
OTHER INFORMATION

Item 1.  Legal Proceedings.

In addition to the following matters, we are involved in various claims and legal actions arising in the ordinary course of business, including employee injury claims.  After conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity.  Also, as a result of historical acquisitions or dispositions by us or other companies in our industry, we may time to time be subject to claims or legal actions, including in respect of certain employee or retiree health or pension benefits.

Permit Litigation Matters

Surface mines at our Mingo Logan and Coal-Mac mining operations were identified in an existing lawsuit brought by the Ohio Valley Environmental Coalition (OVEC) in the U.S. District Court for the Southern District of West Virginia as having been granted Clean Water Act § 404 permits by the Army Corps of Engineers (Corps), allegedly in violation of the Clean Water Act and the National Environmental Policy Act.  The lawsuit, brought by OVEC in September 2005, originally was filed against the Corps for permits it had issued to four subsidiaries of a company unrelated to us or our operating subsidiaries.  The suit claimed that the Corps had issued permits to the subsidiaries of the unrelated company that did not comply with the National Environmental Policy Act and violated the Clean Water Act.

The court ruled on the claims associated with those four permits in orders of March 23 and June 13, 2007.  In the first of those orders, the court rescinded the four permits, finding that the Corps had inadequately assessed the likely impact of valley fills on headwater streams and had relied on inadequate or unproven mitigation to offset those impacts.  In the second order, the court entered a declaratory judgment that discharges of sediment from the valley fills into sediment control ponds constructed in-stream to control that sediment must themselves be permitted under a different provision of the Clean Water Act, § 402, and meet the effluent limits imposed on discharges from these ponds.  Both of the district court rulings were appealed to the U.S. Court of Appeals for the Fourth Circuit.

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Before the court entered its first order, the plaintiffs were permitted to amend their complaint to challenge the Coal-Mac and Mingo Logan permits.  Plaintiffs sought preliminary injunctions against both operations, but later reached agreements with our operating subsidiaries that have allowed mining to progress in limited areas while the district court’s rulings were on appeal.  The claims against Coal-Mac were thereafter dismissed.

In February 2009, the Fourth Circuit reversed the District Court.  The Fourth Circuit held that the Corps’ jurisdiction under Section 404 of the Clean Water Act is limited to the narrow issue of the filling of jurisdictional waters.  The court also held that the Corps’ findings of no significant impact under the National Environmental Policy Act and no significant degradation under the Clean Water Act are entitled to deference.  Such findings entitle the Corps to avoid preparing an environmental impact statement, the absence of which was one issue on appeal.  These holdings also validated the type of mitigation projects proposed by our operations to minimize impacts and comply with the relevant statutes.  Finally, the Fourth Circuit found that stream segments, together with the sediment ponds to which they connect, are unitary “waste treatment systems,” not “waters of the United States,” and that the Corps had not exceeded its authority in permitting them.

OVEC sought rehearing before the entire appellate court, which was denied in May 2009, and the decision was given legal effect in June 2009.  An appeal to the U.S. Supreme Court was then filed in August 2009.  On August 3, 2010 OVEC withdrew its appeal.

Mingo Logan filed a motion for summary judgment with the district court in July 2009, asking that judgment be entered in its favor because no outstanding legal issues remained for decision as a result of the Fourth Circuit’s February 2009 decision.  By a series of motions, the United States obtained extensions and stays of the obligation to respond to the motion in the wake of its letters to the Corps dated September 3 and October 16, 2009 (discussed below).  By order dated April 22, 2010, the District Court stayed the case as to Mingo Logan for the shorter of either six months or the completion of the U.S. Environmental Protection Agency’s (EPA) proposed action to deny Mingo Logan the right to use its Corps’ permit (as discussed below).

On October 15, 2010, the United States moved to extend the existing stay for an additional 120 days (until February 22, 2011) while the EPA Administrator reviewed the “Recommended Determination” issued by the EPA Region 3.  By Memorandum Opinion and Order dated November 2, 2010, the court granted the United States’ motion.  On January 13, 2011, the EPA issued its “Final Determination” to withdraw the specification of two of the three watersheds as a disposal site for dredged or fill material approved under the current Section 404 permit.  The court was notified of the Final Determination and by order dated March 21, 2011 stayed further proceedings in the case until further order of the court, in light of the challenge to the EPA’s “Final Determination” then pending in federal court in Washington, DC.

In a Memorandum and Opinion and separate Order, each dated March 23, 2012, the federal court granted Mingo Logan’s motion for summary judgment, vacated EPA’s Final Determination and found valid and in full force Mingo Logan’s Section 404 permit.  As described more fully below, EPA appealed that order to the United States Court of Appeals for the DC circuit and by Opinion of the Court dated April 23, 2013, the court reversed the lower court’s order and remanded the matter to the district court for further proceedings.

On April 5, 2012, Mingo Logan moved to lift the stay referenced above.  On June 5, 2012, the Court entered an order lifting the stay and allowing the case to proceed on Mingo Logan’s Motion for Summary Judgment.  Shortly thereafter, OVEC filed a motion for leave to file a seventh amended and supplemental complaint seeking to update existing counts and raising two new claims (one, to enforce EPA’s “Final Determination” and, the other, that the Corps’ refusal to prepare a Supplemental Environmental Impact Statement violates the APA and NEPA).  By Memorandum, Opinion and Order dated July 25, 2012; the Court granted OVEC’s motion and directed the Clerk to file OVEC’s Seventh Amended and Supplemental Complaint.  Mingo Logan filed its Motion for Summary Judgment on August 31, 2012, along with its Answer to the Seventh Amended and Supplemental Complaint and the matter remains pending before the Court.

EPA Actions Related to Water Discharges from the Spruce Permit

By letter of September 3, 2009, the EPA asked the Corps of Engineers to suspend, revoke or modify the existing permit it issued in January 2007 to Mingo Logan under Section 404 of the Clean Water Act, claiming that “new information and circumstances have arisen which justify reconsideration of the permit.”  By letter of September 30, 2009, the Corps of Engineers advised the EPA that it would not reconsider its decision to issue the permit.  By letter of October 16, 2009, the EPA advised the Corps that it has “reason to believe” that the Mingo Logan mine will have “unacceptable adverse impacts to fish and wildlife resources” and that it intends to issue a public notice of a proposed determination to restrict or prohibit discharges

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of fill material that already are approved by the Corps’ permit.  By federal register publication dated April 2, 2010, the EPA issued its “Proposed Determination to Prohibit, Restrict or Deny the Specification, or the Use for Specification of an Area as a Disposal Site:  Spruce No. 1 Surface Mine, Logan County, WV” pursuant to Section 404(c) of the Clean Water Act, the EPA accepted written comments on its proposed action (sometimes known as a “veto proceeding”), through June 4, 2010 and conducted a public hearing, as well, on May 18, 2010.  We submitted comments on the action during this period.  On September 24, 2010, the EPA Region 3 issued a “Recommended Determination” to the EPA Administrator recommending that the EPA prohibit the placement of fill material in two of the three watersheds for which filling is approved under the current Section 404 permit.  Mingo Logan, along with the Corps, West Virginia DEP and the mineral owner, engaged in a consultation with the EPA as required by the regulations, to discuss “corrective action” to address the “unacceptable adverse effects” identified.  On January 13, 2011, the EPA issued its “Final Determination” pursuant to Section 404(c) of the Clean Water Act to withdraw the specification of two of the three watersheds approved in the current Section 404 permit as a disposal site for dredged or fill material.  By separate action, Mingo Logan sued the EPA on April 2, 2010 in federal court in Washington, D.C. seeking a ruling that the EPA has no authority under the Clean Water Act to veto a previously issued permit (Mingo Logan Coal Company, Inc. v. USEPA, No. 1:10-cv-00541(D.D.C.)).  The EPA moved to dismiss that action, and we responded to that motion.

Pursuant to a scheduling order for summary disposition of the case, motions and cross-motions for summary judgment by both parties were filed.  On November 30, 2011, the court heard arguments from the parties limited only to the threshold issue of whether the EPA had the authority under Section 404(c) of the Clean Water Act to withdraw the specification of the disposal site after the Corps had already issued a permit under Section 404(a).  The court deferred consideration of the remaining issue (i.e. whether the EPA’s “Final Determination” is otherwise lawful) until after consideration of the threshold issue.  On March 23, 2012, the court entered an Order and a Memorandum Opinion granting Mingo Logan’s motion for summary judgment, denying the EPA’s cross-motion for summary judgment, vacating the Final Determination and ordering that Mingo Logan’s Section 404 permit remains valid and in full force.

On May 11, 2012, the EPA filed a notice of appeal to the United States Court of Appeals for the District of Columbia Circuit.  The court heard oral arguments on March 14, 2013.  By opinion of the court filed on April 23, 2013, the court reversed the district court on the threshold issue and remanded the matter to the district court to address the merits of our APA challenge to the Final Determination.  On June 6, 2013, Mingo Logan filed a Petition for Rehearing En Banc and by Order filed July 25, 2013, the court denied the petition.

On November 13, 2013, Mingo Logan filed a Petition for Writ of Certiorari with the Supreme Court of the United States seeking review of the DC Circuit’s decision.  On March 24, 2014, the Supreme Court denied Mingo Logan’s Petition for Writ of Certiorari and remanded the matter to the federal district court for the District of Columbia for further consideration on the merits of the Final Determination.  On September 30, 2014, the court entered an opinion and order denying Mingo Logan’s motion for summary judgment and granting the government’s motion for summary judgment.  The court upheld the Final Determination finding that EPA’s decision to withdraw the specifications for filling in Oldhouse Branch and Pigeonroost Branch under Mingo Logan’s Section 404 permit was not arbitrary and capricious.  On November 11, 2014, Mingo Logan filed a notice of appeal to the United States Court of Appeals for the District of Columbia Circuit Court.  On June 12, 2015, Mingo Logan filed its opening brief with the court.

Allegheny Energy Contract Matter

Allegheny Energy Supply (“Allegheny”), the sole customer of coal produced at our subsidiary Wolf Run Mining Company’s (“Wolf Run”) Sycamore No. 2 mine, filed a lawsuit against Wolf Run, Hunter Ridge Holdings, Inc. (“Hunter Ridge”), and ICG in state court in Allegheny County, Pennsylvania on December 28, 2006, and amended its complaint on April 23, 2007. Allegheny claimed that Wolf Run breached a coal supply contract when it declared force majeure under the contract upon idling the Sycamore No. 2 mine in the third quarter of 2006, and that Wolf Run continued to breach the contract by failing to ship in volumes referenced in the contract.  The Sycamore No. 2 mine was idled after encountering adverse geologic conditions and abandoned gas wells that were previously unidentified and unmapped.

After extensive searching for gas wells and rehabilitation of the mine, it was re-opened in 2007, but with notice to Allegheny that it would necessarily operate at reduced volumes in order to safely and effectively avoid the many gas wells within the reserve.  The amended complaint also alleged that the production stoppages constitute a breach of the guarantee agreement by Hunter Ridge and breach of certain representations made upon entering into the contract in early 2005.  Allegheny voluntarily dropped the breach of representation claims later.  Allegheny claimed that it would incur costs in excess of $100 million to purchase replacement coal over the life of the contract.  ICG, Wolf Run and Hunter Ridge answered the amended complaint on August 13, 2007, disputing all of the remaining claims.

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On November 3, 2008, ICG, Wolf Run and Hunter Ridge filed an amended answer and counterclaim against the plaintiffs seeking to void the coal supply agreement due to, among other things, fraudulent inducement and conspiracy.  On September 23, 2009, Allegheny filed a second amended complaint alleging several alternative theories of liability in its effort to extend contractual liability to ICG, which was not a party to the original contract and did not exist at the time Wolf Run and Allegheny entered into the contract.  No new substantive claims were asserted.  ICG answered the second amended complaint on October 13, 2009, denying all of the new claims.  The Company’s counterclaim was dismissed on motion for summary judgment entered on May 11, 2010.  Allegheny’s claims against ICG were also dismissed by summary judgment, but the claims against Wolf Run and Hunter Ridge were not.  The court conducted a non-jury trial of this matter beginning on January 10, 2011 and concluding on February 1, 2011.

At the trial, Allegheny presented its evidence for breach of contract and claimed that it is entitled to past and future damages in the aggregate of between $228 million and $377 million.  Wolf Run and Hunter Ridge presented their defense of the claims, including evidence with respect to the existence of force majeure conditions and excuse under the contract and applicable law.  Wolf Run and Hunter Ridge presented evidence that Allegheny’s damages calculations were significantly inflated because it did not seek to determine damages as of the time of the breach and in some instances artificially assumed future nondelivery or did not take into account the apparent requirement to supply coal in the future.  On May 2, 2011, the trial court entered a Memorandum and Verdict determining that Wolf Run had breached the coal supply contract and that the performance shortfall was not excused by force majeure.  The trial court awarded total damages and interest in the amount of $104.1 million, which consisted of $13.8 million for past damages, and $90.3 million for future damages.  ICG and Allegheny filed post-verdict motions in the trial court and on August 23, 2011, the court denied the parties’ motions.  The court entered a final judgment on August 25, 2011, in the amount of $104.1 million, which included pre-judgment interest.

The parties appealed the lower court’s decision to the Superior Court of Pennsylvania.  On August 13, 2012, the Superior Court of Pennsylvania affirmed the award of past damages, but ruled that the lower court should have calculated future damages as of the date of breach, and remanded the matter back to the lower court with instructions to recalculate that portion of the award. On November 19, 2012, Allegheny filed a Petition for Allowance of Appeal with the Supreme Court of Pennsylvania and Wolf Run and Hunter Ridge filed an Answer.  On July 2, 2013, the Supreme Court of Pennsylvania denied the Petition of Allowance.  As this action finalized the past damage award, Wolf Run paid $15.6 million for the past damage amount, including interest, to Allegheny in July 2013.   Testimony on the future damage award in the lower court concluded on May 19, 2014, and post-trial briefs and responses were submitted on August 8, 2014.  The court held a hearing on this matter on November 5, 2014 and on February 16, 2015 awarded Allegheny $7.5 million plus interest for the future damages.  On April 6, 2015, the parties entered into a settlement agreement pursuant to which Wolf Run agreed to pay $15 million and both parties agreed to release and discharge the other party from any further contractual liability.

UMWA 1974 Pension Plan et al. v Peabody Energy and Arch

On July 16, 2015, the UMWA 1974 Pension Plan (“Plan”) and its Trustees filed a Complaint for Declaratory Judgment against Peabody Energy Corporation, Peabody Holding Company, LLC and Arch, in the U.S. District Court in Washington D.C., seeking an order from the court requiring the defendants to submit to arbitration to determine their responsibility for pension withdrawal liability (triggered by Patriot Coal Corporation’s (“Patriot”) recent bankruptcy filing) for Plan participants of Patriot who formerly worked for Peabody and Arch subsidiaries.  In the alternative, the complaint asks the court to declare that Peabody and Arch are liable for Patriot’s withdrawal liability.   With respect to Arch, plaintiffs allege that Arch engaged in actions to avoid and evade pension fund withdrawal liability when it sold subsidiaries that were signatory to UMWA agreements, to Magnum Coal Company (“Magnum”) in 2005, in violation of ERISA law.  Patriot subsequently purchased Magnum in 2008.  We believe there is no basis in the law to support any claim that Arch is responsible for Patriot’s withdrawal liability and we plan to vigorously defend this complaint.

Item 1A.  Risk Factors.

The risk factors set forth below are updates to the certain risk factors previously disclosed in Part I, Item IA. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014.

A loss or reduction in our ability to self-bond could have a material adverse effect on our business and results of operations.

Federal and state laws require us to obtain surety bonds or post letters of credit to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal

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leases and other obligations. The costs of surety bonds have fluctuated in recent years while the market terms of such bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. We use self-bonding to secure performance of certain obligations in Wyoming. Self-bonding commits us to pay directly for reclamation costs rather than obtaining a traditional surety bond. As of December 31, 2014, we have self-bonded an aggregate of approximately $458.5 million. The Land Quality Division of the Wyoming Department of Environmental Quality periodically re-evaluates the amount of the bond, so the current amount is subject to increase.

There can be no assurance that the amount of our self-bonding obligations will not be increased or that we will continue to qualify to self-bond. To the extent we are unable to maintain our current level of self-bonding, due to legislative or regulatory changes or changes in our financial condition, our costs would increase and it could have a material adverse effect on our financial condition and results of operations.

Under certain circumstances, we could be responsible for certain retiree medical benefits assumed by Magnum Coal Company.

On December 31, 2005, Arch entered into a purchase and sale agreement with Magnum to sell certain assets. On July 23, 2008, Patriot acquired Magnum. On May 12, 2015, Patriot and certain of its wholly owned subsidiaries (“Debtors”), including Magnum, filed voluntary petitions for reorganization under Chapter 11 of the U.S. Code in the U.S. Bankruptcy Court for the Eastern District of Virginia. Subsequently, on July 16, 2015, Debtors filed a motion with the court seeking authorization to reject their collective bargaining agreements and modify certain union-related retiree benefits. Should Debtors’ motion be approved, or if they are otherwise incapable of paying retiree medical benefits pursuant to Section 9711 of the Coal Industry Retiree Health Benefit Act of 1992 to a certain subset of retirees, we could become responsible for certain of their retiree medical obligations for retirees of Magnum who retired prior to October 1, 1994. We do not have the necessary information to perform an actuarial estimate of the cost of such benefits.

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

In September 2006, our board of directors authorized a share repurchase program for the purchase of up to 14,000,000 shares of our common stock. There is no expiration date on the current authorization, and we have not made any decisions to suspend or cancel purchases under the program. As of June 30, 2015, there were 10,925,800 shares of our common stock available for purchase under this program. We did not purchase any shares of our common stock under this program during the quarter ended June 30, 2015. Based on the closing price of our common stock as reported on the New York Stock Exchange on July 20, 2015, the approximate dollar value of our common stock that may yet be purchased under this program was $2.5 million.

Item 4.  Mine Safety Disclosures.

The statement concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Quarterly Report on Form 10-Q for the period ended June 30, 2015.

Item 5.  Other Information.

On July 30, 2015, we entered into retention agreements (collectively, the “Retention Agreements”) with each of our executive officers.  Subject to the conditions set forth in each Retention Agreement, each executive officer who is party to a Retention Agreement is eligible to receive quarterly cash retention payments for up to a total of 27 months, beginning in August 2015, if his or her employment continues.  Each of the first eight quarterly payments will be valued at 9.375% of the total possible retention award, and the final quarterly payment will be valued at 25% of the total possible retention award.  Information regarding the total possible retention awards for which our named executive officers are eligible pursuant to their respective Retention Agreements is set forth below.  If an executive’s employment is terminated for any reason other by us without cause or by the executive for good reason, any unpaid retention payments pursuant to the applicable Retention Agreement would be forfeited.  This description of the Retention Agreements does not purport to be complete and is qualified in its entirety by reference to the full text of the form of Retention Agreement which is filed as Exhibit 10.2 hereto and incorporated herein by reference.

Named Executive Officer	Total Possible Retention Award
John W. Eaves, Chairman and Chief Executive Officer	Two times base salary
John T. Drexler, Senior Vice President and Chief Financial Officer	Two times base salary
Paul A. Lang, President and Chief Operating Officer	Two times base salary
Kenneth D. Cochran, Senior Vice President - Operations	1.5 times base salary
Robert G. Jones, Senior Vice President - Law, General Counsel and Secretary	1.5 times base salary

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Item 6.  Exhibits.

10.1	Form of Lock-Up and Support Agreement, dated as of July 1, 2015, by and among Arch Coal, Inc. and certain holders of Arch Coal, Inc. 7.25% Senior Notes due 2020 signatory thereto.
10.2	Form of Retention Agreement*
12.1	Computation of ratio of earnings to combined fixed charges and preference dividends.
31.1	Rule 13a-14(a)/15d-14(a) Certification of John W. Eaves.
31.2	Rule 13a-14(a)/15d-14(a) Certification of John T. Drexler.
32.1	Section 1350 Certification of John W. Eaves.
32.2	Section 1350 Certification of John T. Drexler.
95.0	Mine Safety Disclosure Exhibit.
101.0	Interactive Data File (Form 10-Q for the three and six months ended June 30, 2015 filed in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”

* Denotes management contract or compensatory plan arrangement.

Signatures

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.

Arch Coal, Inc.
By:	/s/ John T. Drexler
	John T. Drexler
	Senior Vice President and Chief Financial Officer
	(On behalf of the registrant and as Principal
	Financial Officer)
	July 31, 2015

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