Edgar Filing: ARCH COAL INC

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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 March 31, 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 April 20, 2015 there were 212,662,307 shares of the registrant’s common stock outstanding.

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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		24
Item 3. Quantitative and Qualitative Disclosures About Market Risk		30
Item 4. Controls and Procedures		31
Part II OTHER INFORMATION		31
Item 1. Legal Proceedings		31
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		35
Item 4. Mine Safety Disclosures		35
Item 6. Exhibits		35

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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 March 31,
	2015			2014
	(Unaudited)
Revenues	$	677,005		$	735,971
Costs, expenses and other operating
Cost of sales (exclusive of items shown separately below)	562,322			686,314
Depreciation, depletion and amortization	104,874			104,423
Amortization of acquired sales contracts, net	(3,390		)	(3,696		)
Change in fair value of coal derivatives and coal trading activities, net	1,220			914
Selling, general and administrative expenses	22,605			29,136
Other operating (income) expense, net	9,086			(7,998		)
	696,717			809,093

Loss from operations	(19,712		)	(73,122		)
Interest expense, net
Interest expense	(99,252		)	(96,471		)
Interest and investment income	2,373			1,843
	(96,879		)	(94,628		)

Loss before income taxes	(116,591		)	(167,750		)
Benefit from income taxes	(3,396		)	(43,611		)
Net loss	$	(113,195	)	$	(124,139	)

Losses per common share

Basic and diluted LPS - Net loss	$	(0.53	)	$	(0.59	)

Basic and diluted weighted average shares outstanding	212,660			212,171

Dividends declared per common share	$	—		$	0.01

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

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Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

	Three Months Ended March 31,
	2015			2014
	(Unaudited)
Net loss	$	(113,195	)	$	(124,139	)

Derivative instruments
Comprehensive income (loss) before tax	5,045			(229		)
Income tax benefit (provision)	(1,817		)	82
	3,228			(147		)
Pension, postretirement and other post-employment benefits
Comprehensive income (loss) before tax	294			(1,847		)
Income tax benefit (provision)	(105		)	665
	189			(1,182		)
Available-for-sale securities
Comprehensive income (loss) before tax	291			(2,033		)
Income tax benefit (provision)	(104		)	732
	187			(1,301		)

Total other comprehensive income (loss)	3,604			(2,630		)
Total comprehensive loss	$	(109,591	)	$	(126,769	)

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

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Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except per share data)

	March 31,			December 31,
	2015			2014
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	689,972		$	734,231
Short term investments	249,518			248,954
Trade accounts receivable	198,314			211,506
Other receivables	15,435			20,511
Inventories	240,113			190,253
Prepaid royalties	12,841			11,118
Deferred income taxes	50,414			52,728
Coal derivative assets	14,777			13,257
Other current assets	59,605			60,193
Total current assets	1,530,989			1,542,751
Property, plant and equipment, net	6,371,335			6,453,458
Other assets
Prepaid royalties	63,622			66,806
Equity investments	225,030			235,842
Other noncurrent assets	123,964			130,866
Total other assets	412,616			433,514
Total assets	$	8,314,940		$	8,429,723
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	167,480		$	180,113
Accrued expenses and other current liabilities	321,503			302,396
Current maturities of debt	34,368			36,885
Total current liabilities	523,351			519,394
Long-term debt	5,117,982			5,123,485
Asset retirement obligations	404,844			398,896
Accrued pension benefits	14,436			16,260
Accrued postretirement benefits other than pension	34,453			32,668
Accrued workers’ compensation	98,683			94,291
Deferred income taxes	419,064			422,809
Other noncurrent liabilities	141,804			153,766
Total liabilities	6,754,617			6,761,569
Stockholders’ equity
Common stock, $0.01 par value, authorized 260,000 shares, issued 214,179 shares and 213,791 shares at March 31, 2015 and December 31, 2014, respectively	2,145			2,141
Paid-in capital	3,050,216			3,048,460
Treasury stock, at cost, 1,517 shares at March 31, 2015 and December 31, 2014	(53,863		)	(53,863		)
Accumulated deficit	(1,445,020		)	(1,331,825		)
Accumulated other comprehensive income	6,845			3,241
Total stockholders’ equity	1,560,323			1,668,154
Total liabilities and stockholders’ equity	$	8,314,940		$	8,429,723

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

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Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(in thousands)

	Three Months Ended March 31,
	2015			2014
	(Unaudited)
Operating activities
Net loss	$	(113,195	)	$	(124,139	)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization	104,874			104,423
Amortization of acquired sales contracts, net	(3,390		)	(3,696		)
Amortization relating to financing activities	6,219			3,236
Prepaid royalties expensed	1,674			1,803
Employee stock-based compensation expense	1,760			2,333
Gains on disposals and divestitures, net	(46		)	(15,129		)
Deferred income taxes	(3,433		)	(43,698		)
Changes in:
Receivables	18,252			(27,245		)
Inventories	(49,860		)	7,441
Accounts payable, accrued expenses and other current liabilities	7,186			43,989
Income taxes, net	40			(115		)
Other	25,646			10,522
Cash used in operating activities	(4,273		)	(40,275		)
Investing activities
Capital expenditures	(22,880		)	(14,454		)
Additions to prepaid royalties	(213		)	(591		)
Proceeds from disposals and divestitures	46			28,195
Purchases of marketable securities	(101,793		)	(119,176		)
Proceeds from sale or maturity of marketable securities and other investments	99,914			117,681
Investments in and advances to affiliates	(1,843		)	(3,242		)
Cash provided by (used in) investing activities	(26,769		)	8,413
Financing activities
Payments on term loan	(4,875		)	(4,875		)
Net payments on other debt	(4,810		)	(4,521		)
Dividends paid	—			(2,123		)
Debt financing costs	—			(1,957		)
Withdrawals (deposits) of restricted cash	(3,532		)	—
Cash used in financing activities	(13,217		)	(13,476		)
Increase (decrease) in cash and cash equivalents	(44,259		)	(45,338		)
Cash and cash equivalents, beginning of period	734,231			911,099
Cash and cash equivalents, end of period	$	689,972		$	865,761

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

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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 months ended March 31, 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

There is no new accounting guidance that is expected to have a significant impact on the Company’s financial statements.

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)	3,535			—		(1,603		)	1,932
Amounts reclassified from AOCI	(307		)	189		1,790			1,672
Balance at March 31, 2015	$	5,778		$	3,049	$	(1,982	)	$	6,845

The following amounts were reclassified out of AOCI:

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	Amounts Reclassified from AOCI
	Three Months Ended March 31,						Line Item in the Condensed Consolidated
Details About AOCI Components	2015			2014			Statement of Operations
	(In thousands)
Derivative instruments	$	481		$	303		Revenues
	(174		)	(109		)	Benefit from income taxes
	$	307		$	194		Net of tax

Pension, postretirement and other post-employment benefits
Amortization of prior service credits (1)	$	2,084		$	2,626
Amortization of actuarial gains (losses), net (1)	(2,378		)	(779		)
	(294		)	1,847
	105			(665		)	Benefit from income taxes
	$	(189	)	$	1,182		Net of tax

Available-for-sale securities	$	(2,797	)	$	(556	)	Interest and investment income
	1,007			200			Benefit from income taxes
	$	(1,790	)	$	(356	)	Net of tax

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

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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 $13.8 million from these divestitures, reflected in “other operating (income) expense, net” in the condensed consolidated statement of operations.

5. Inventories

Inventories consist of the following:

	March 31,		December 31,
	2015		2014
	(In thousands)
Coal	$	117,180	$	71,901
Repair parts and supplies	122,933		118,352
	$	240,113	$	190,253

The repair parts and supplies are stated net of an allowance for slow-moving and obsolete inventories of $6.8 million at March 31, 2015 and $6.6 million at December 31, 2014.

6. 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:

	March 31, 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	$	252,673	$	2	$	(3,157	)	$	249,518	$	249,518	$	—
Equity securities	3,910		2,875		(2,830		)	3,955		—		3,955
Total Investments	$	256,583	$	2,877	$	(5,987	)	$	253,473	$	249,518	$	3,955

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	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 $177.3 million and $163.0 million at March 31, 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 $64.4 million and $86.1 million at March 31, 2015 and December 31, 2014, respectively. The unrealized losses in our portfolio are the result of normal market fluctuations. We do not currently intend to sell these investments before recovery of their amortized cost base.

The debt securities outstanding at March 31, 2015 have maturity dates ranging from the second quarter of 2015 through the third 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.

7. 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 67 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 March 31, 2015, the Company had protected the price of approximately 86% 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, the Company has layered in 19.5 million gallons of at-the-money call options for the second half of 2015 representing 60% of expected purchases at an average strike price of $1.92 per gallon. Additionally, the Company has protected approximately 37% of our expected 2016 purchases with out-of-the-money call options. At March 31, 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 March 31, 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	3,595	280	3,875
Coal purchases	1,672	60	1,732

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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 $0.3 million of losses during the remainder of 2015 and $1.4 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:

	March 31, 2015								December 31, 2014
Fair Value of Derivatives	Asset			Liability					Asset			Liability
(In thousands)	Derivative			Derivative					Derivative			Derivative
Derivatives Designated as Hedging Instruments
Coal	$	6,896		$	(107	)			$	6,535		$	(2,492	)

Derivatives Not Designated as Hedging Instruments
Heating oil — diesel purchases	4,079			—					300			—
Coal — held for trading purposes	126,397			(125,204		)			96,898			(93,272		)
Coal — risk management	16,484			(11,094		)			8,510			(3,688		)
Natural gas	1,148			(753		)			—			—
Total	148,108			(137,051		)			105,708			(96,960		)
Total derivatives	155,004			(137,158		)			112,243			(99,452		)
Effect of counterparty netting	(136,148		)	136,148					(98,686		)	98,686
Net derivatives as classified in the balance sheets	$	18,856		$	(1,010	)	$	17,846	$	13,557		$	(766	)	$	12,791

		March 31, 2015			December 31, 2014
Net derivatives as reflected on the balance sheets (in thousands)
Heating oil	Other current assets	$	4,079		$	300
Coal	Coal derivative assets	14,777			13,257
	Accrued expenses and other current liabilities	(1,010		)	(766		)
		$	17,846		$	12,791

The Company had a current liability for the obligation to post cash collateral of $0.7 million and $2.4 million at March 31, 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.

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

Derivatives used in Cash Flow Hedging Relationships (in thousands)

Three Months Ended March 31,

		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)	$	10,265		$	(515	)	$	882		$	706
Coal purchases	(2)	(4,738		)	589			(401		)	(404		)
Totals		$	5,527		$	74		$	481		$	302

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 March 31, 2015 and 2014.

Derivatives Not Designated as Hedging Instruments (in thousands)

Three Months Ended March 31,

		Gain (Loss) Recognized
		2015			2014
Coal — unrealized	(3)	$	(411	)	$	(1,302	)
Coal — realized	(4)	$	1,091		$	2,879
Natural gas — unrealized	(3)	$	159		$	8
Heating oil — diesel purchases	(4)	$	(2,365	)	$	(2,963	)
Heating oil — fuel surcharges	(4)	$	—		$	(254	)

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 March 31, 2015, gains on derivative contracts designated as hedge instruments in cash flow hedges of approximately $6.3 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 $1.0 million and $0.4 million of net unrealized and realized gains during the three months ended March 31, 2015 and 2014, respectively. 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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8. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consist of the following:

	March 31,		December 31,
	2015		2014
	(In thousands)
Payroll and employee benefits	$	49,039	$	73,362
Taxes other than income taxes	111,362		114,598
Interest	77,375		30,384
Acquired sales contracts	11,635		12,453
Workers’ compensation	15,586		16,714
Asset retirement obligations	19,215		19,222
Other	37,291		35,663
	$	321,503	$	302,396

9. Debt and Financing Arrangements

	March 31,		December 31,
	2015		2014
	(In thousands)
Term loan due 2018 ($1.9 billion face value)	$	1,886,971	$	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)	363,997		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	51,382		56,031
	5,152,350		5,160,370
Less current maturities of debt	34,368		36,885
Long-term debt	$	5,117,982	$	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 test until June, 2015, at which time a maximum secured leverage ratio test takes effect.

At March 31, 2015, the available borrowing capacity under the Company’s lines of credit was approximately $179.4 million.

10. Income taxes

During the first quarter 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 March 31, 2015, the Company increased its valuation allowance by $45.3 million for the federal net operating losses and $2.6 million for the state net operating losses.

During the first quarter 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 $21.6 million for the federal net operating losses and $2.2 million for the state net operating losses.

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11. 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 March 31, 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:

	March 31, 2015
	Total		Level 1		Level 2		Level 3
	(In thousands)
Assets:
Investments in marketable securities	$	253,473	$	3,955	$	249,518	$	—
Derivatives	18,856		7,130		2,456		9,270
Total assets	$	272,329	$	11,085	$	251,974	$	9,270
Liabilities:
Derivatives	$	1,010	$	—	$	1,010	$	—

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 March 31, 2015
	(In thousands)
Balance, beginning of period	$	3,040
Realized and unrealized losses recognized in earnings, net	(1,347		)
Realized and unrealized gains recognized in other comprehensive income, net	1,450
Purchases	7,783
Issuances	(1,656		)
Ending balance	$	9,270

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Net unrealized gains of $0.1 million were recognized during the three months ended March 31, 2015 related to level 3 financial instruments held on March 31, 2015.

Fair Value of Long-Term Debt

At March 31, 2015 and December 31, 2014, the fair value of the Company’s debt, including amounts classified as current, was $2.4 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.

12. Loss Per Common Share

The effect of options, restricted stock and restricted stock units equaling 8.3 million shares and 6.9 million shares of common stock were excluded from the calculation of diluted weighted average shares outstanding for the three months ended March 31, 2015 and March 31, 2014, respectively, because the exercise price or grant price of the securities exceeded the average market price of the Company’s common stock for these periods. 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 months ended March 31, 2015 and March 31, 2014 were 2.5 million and 0.8 million, respectively.

13. Employee Benefit Plans

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

	Three Months Ended March 31,
	2015			2014
	(In thousands)
Service cost	$	4		$	5,924
Interest cost	3,570			4,364
Expected return on plan assets	(5,764		)	(5,978		)
Amortization of prior service costs (credits)	—			(54		)
Amortization of other actuarial losses	2,058			948
Net benefit cost	$	(132	)	$	5,204

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

	Three Months Ended March 31,
	2015			2014
	(In thousands)
Service cost	$	233		$	444
Interest cost	335			464
Amortization of prior service credits	(2,084		)	(2,501		)
Amortization of other actuarial losses (gains)	(456		)	(170		)
Net benefit credit	$	(1,972	)	$	(1,763	)

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14. 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.

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

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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, the Company idled the Sycamore No. 2 mine, the impact of which will be recorded in the second quarter.

In addition, the Company is a party to numerous other claims and lawsuits with respect to various matters. As of March 31, 2015 and December 31, 2014, the Company had accrued $17.3 million and $22.3 million, respectively, for all legal matters, including $17.3 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.

15. 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 months ended March 31, 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 March 31, 2015
Revenues	$	391,206		$	223,439		$	62,360	$	—		$	677,005
Adjusted EBITDA	72,062			39,807			1,691		(31,788		)	81,772
Depreciation, depletion and amortization	44,361			48,727			10,055		1,731			104,874
Amortization of acquired sales contracts, net	(1,285		)	(2,105		)	—		—			(3,390		)
Capital expenditures	16,969			3,385			2,642		(116		)	22,880

Three Months Ended March 31, 2014
Revenues	$	358,607		$	279,137		$	98,227	$	—		$	735,971
Adjusted EBITDA	29,819			28,427			4,132		(34,773		)	27,605
Depreciation, depletion and amortization	39,245			54,988			9,519		671			104,423
Amortization of acquired sales contracts, net	(789		)	(2,974		)	67		—			(3,696		)
Capital expenditures	2,094			8,156			1,801		2,403			14,454

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

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	Three Months Ended March 31,
	2015			2014
	(In thousands)
Adjusted EBITDA	$	81,772		$	27,605
Depreciation, depletion and amortization	(104,874		)	(104,423		)
Amortization of acquired sales contracts, net	3,390			3,696
Interest expense, net	(96,879		)	(94,628		)
Loss before income taxes	$	(116,591	)	$	(167,750	)

16. 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):

Condensed Consolidating Statements of Operations

Three Months Ended March 31, 2015

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	677,005		$	—		$	—		$	677,005
Costs, expenses and other
Cost of sales (exclusive of items shown separately below)	7,470			555,686			—			(834		)	562,322
Depreciation, depletion and amortization	1,060			103,812			2			—			104,874
Amortization of acquired sales contracts, net	—			(3,390		)	—			—			(3,390		)
Change in fair value of coal derivatives and coal trading activities, net	—			1,220			—			—			1,220
Asset impairment and mine closure costs	—			—			—			—			—
Selling, general and administrative expenses	15,439			6,243			1,448			(525		)	22,605
Other operating (income) expense, net	3,700			5,278			(1,251		)	1,359			9,086
	27,669			668,849			199			—			696,717
Income from investment in subsidiaries	21,050			—			—			(21,050		)	—
Income (Loss) from operations	(6,619		)	8,156			(199		)	(21,050		)	(19,712		)
Interest expense, net
Interest expense	(118,056		)	(6,763		)	(1,275		)	26,842			(99,252		)
Interest and investment income	8,072			19,774			1,369			(26,842		)	2,373
	(109,984		)	13,011			94			—			(96,879		)

Income (loss) from continuing operations before income taxes	(116,603		)	21,167			(105		)	(21,050		)	(116,591		)
Provision for (benefit from) income taxes	(3,408		)	—			12			—			(3,396		)
Net income (loss)	$	(113,195	)	$	21,167		$	(117	)	$	(21,050	)	$	(113,195	)
Total comprehensive income (loss)	$	(109,591	)	$	24,407		$	(117	)	$	(24,290	)	$	(109,591	)

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Condensed Consolidating Statements of Operations

Three Months Ended March 31, 2014

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	735,971		$	—		$	—		$	735,971
Costs, expenses and other
Cost of sales (exclusive of items shown separately below)	3,389			683,775			—			(850		)	686,314
Depreciation, depletion and amortization	1,472			102,942			9			—			104,423
Amortization of acquired sales contracts, net	—			(3,696		)	—			—			(3,696		)
Change in fair value of coal derivatives and coal trading activities, net	—			914			—			—			914
Asset impairment and mine closure costs	—			—			—			—			—
Selling, general and administrative expenses	19,944			7,865			1,803			(476		)	29,136
Other operating (income) expense, net	1,593			(9,480		)	(1,437		)	1,326			(7,998		)
	26,398			782,320			375			—			809,093
Loss from investment in subsidiaries	(35,347		)	—			—			35,347			—
Loss from operations	(61,745		)	(46,349		)	(375		)	35,347			(73,122		)
Interest expense, net
Interest expense	(113,655		)	(6,324		)	(1,050		)	24,558			(96,471		)
Interest and investment income	7,601			17,651			1,149			(24,558		)	1,843
	(106,054		)	11,327			99			—			(94,628		)

Income (loss) from continuing operations before income taxes	(167,799		)	(35,022		)	(276		)	35,347			(167,750		)
Provision for (benefit from) income taxes	(43,660		)	—			49			—			(43,611		)
Net loss	$	(124,139	)	$	(35,022	)	$	(325	)	$	35,347		$	(124,139	)
Total comprehensive loss	$	(126,769	)	$	(36,428	)	$	(325	)	$	36,753		$	(126,769	)

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Condensed Consolidating Balance Sheets

March 31, 2015

	Parent/Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Cash and cash equivalents	$	577,832	$	100,430	$	11,710	$	—		$	689,972
Short term investments	249,518		—		—		—			249,518
Receivables	10,184		10,894		197,321		(4,650		)	213,749
Inventories	—		240,113		—		—			240,113
Other	82,714		44,828		10,095		—			137,637
Total current assets	920,248		396,265		219,126		(4,650		)	1,530,989

Property, plant and equipment, net	9,860		6,361,096		—		379			6,371,335

Investment in subsidiaries	7,487,172		—		—		(7,487,172		)	—
Intercompany receivables	—		2,139,722		—		(2,139,722		)	—
Note receivable from Arch Western	675,000		—		—		(675,000		)	—
Other	125,994		285,227		1,395		—			412,616
Total other assets	8,288,166		2,424,949		1,395		(10,301,894		)	412,616
Total assets	$	9,218,274	$	9,182,310	$	220,521	$	(10,306,165	)	$	8,314,940

Liabilities and Stockholders’ Equity
Accounts payable	$	12,377	$	155,080	$	23	$	—		$	167,480
Accrued expenses and other current liabilities	117,096		208,275		782		(4,650		)	321,503
Current maturities of debt	24,645		9,723		—		—			34,368
Total current liabilities	154,118		373,078		805		(4,650		)	523,351
Long-term debt	5,081,468		36,514		—		—			5,117,982
Intercompany payables	1,946,138		—		193,584		(2,139,722		)	—
Note payable to Arch Coal	—		675,000		—		(675,000		)	—
Asset retirement obligations	1,000		403,844		—		—			404,844
Accrued pension benefits	5,323		9,113		—		—			14,436
Accrued postretirement benefits other than pension	4,643		29,810		—		—			34,453
Accrued workers’ compensation	10,046		88,637		—		—			98,683
Deferred income taxes	419,064		—		—		—			419,064
Other noncurrent liabilities	36,530		105,069		205		—			141,804
Total liabilities	7,658,330		1,721,065		194,594		(2,819,372		)	6,754,617
Stockholders’ equity	1,559,944		7,461,245		25,927		(7,486,793		)	1,560,323
Total liabilities and stockholders’ equity	$	9,218,274	$	9,182,310	$	220,521	$	(10,306,165	)	$	8,314,940

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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
Receivables	9,656		15,933		211,043		(4,615		)	232,017
Inventories	—		190,253		—		—			190,253
Other	89,211		41,455		6,630		—			137,296
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

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Condensed Consolidating Statements of Cash Flows

Three Months Ended March 31, 2015

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash provided by (used in) operating activities	$	(114,542	)	$	96,944		$	13,325		$	—	$	(4,273	)
Investing Activities
Capital expenditures	(450		)	(22,430		)	—			—		(22,880		)
Additions to prepaid royalties	—			(213		)	—			—		(213		)
Proceeds from disposals and divestitures	—			46			—			—		46
Purchases of marketable securities	(101,793		)	—			—			—		(101,793		)
Proceeds from sale or maturity of marketable securities and other investments	99,914			—			—			—		99,914
Investments in and advances to affiliates	—			(1,843		)	—			—		(1,843		)
Cash used in investing activities	(2,329		)	(24,440		)	—			—		(26,769		)
Financing Activities
Payments on term loan	(4,875		)	—			—			—		(4,875		)
Net payments on other debt	(2,751		)	(2,059		)	—			—		(4,810		)
Debt financing costs	—			—			—			—		—
Dividends paid	—			—			—			—		—
Withdrawals (deposits) of restricted cash	—			—			(3,532		)	—		(3,532		)
Transactions with affiliates, net	130,144			(120,373		)	(9,771		)	—		—
Cash provided by (used in) financing activities	122,518			(122,432		)	(13,303		)	—		(13,217		)
Increase (decrease) in cash and cash equivalents	5,647			(49,928		)	22			—		(44,259		)
Cash and cash equivalents, beginning of period	572,185			150,358			11,688			—		734,231
Cash and cash equivalents, end of period	$	577,832		$	100,430		$	11,710		$	—	$	689,972

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Condensed Consolidating Statements of Cash Flows

Three Months Ended March 31, 2014

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash provided by (used in) operating activities	$	(150,338	)	$	142,978		$	(32,915	)	$	—	$	(40,275	)
Investing Activities
Capital expenditures	(492		)	(13,962		)	—			—		(14,454		)
Additions to prepaid royalties	—			(591		)	—			—		(591		)
Proceeds from disposals and divestitures	26,319			1,876			—			—		28,195
Purchases of short term investments	(119,176		)	—			—			—		(119,176		)
Proceeds from sales of short term investments	117,681			—			—			—		117,681
Investments in and advances to affiliates	(1,016		)	(2,226		)	—			—		(3,242		)
Cash provided by (used in) investing activities	23,316			(14,903		)	—			—		8,413
Financing Activities
Contributions from parent	—			—			—			—		—
Payments on term loan	(4,875		)	—			—			—		(4,875		)
Debt financing costs	(1,957		)	—			—			—		(1,957		)
Net payments on other debt	(4,521		)	—			—			—		(4,521		)
Dividends paid	(2,123		)	—			—			—		(2,123		)
Transactions with affiliates, net	95,067			(128,140		)	33,073			—		—
Cash provided by (used in) financing activities	81,591			(128,140		)	33,073			—		(13,476		)
Increase (decrease) in cash and cash equivalents	(45,431		)	(65		)	158			—		(45,338		)
Cash and cash equivalents, beginning of period	799,333			100,418			11,348			—		911,099
Cash and cash equivalents, end of period	$	753,902		$	100,353		$	11,506		$	—	$	865,761

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

Overview

Our results during the first quarter of 2015 were improved compared to the first quarter of 2014 despite continued weakness in coal markets. The improvement in results was attributable to higher shipment volumes in the Powder River Basin as railroad service improved; higher pricing in the Powder River Basin due to sales commitments made in periods when market pricing was more favorable; and improved cost performance in our Powder River Basin and Appalachian segments. These favorable trends were offset by the impact of weak metallurgical markets, which led to lower sales volumes and pricing in our Appalachian segment and by low natural gas pricing, which pressured thermal coal sales volumes and prices.

We sold 1.5 million tons of metallurgical coal during the first quarter of 2015 compared to 1.6 million tons during the first quarter of 2014.

Seaborne coal markets remain challenged, as oversupply continues to pressure global prices for metallurgical and thermal coals. We have limited our forward exposure to the export market at this time, but we have maintained our ability to increase export shipments should fundamentals improve.

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 months ended March 31, 2015 and compares it with the information for the three months ended March 31, 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 March 31,
	2015			2014
Powder River Basin
Tons sold (in thousands)	28,471			25,666
Coal sales per ton sold	$	13.48		$	12.73
Cost per ton sold	$	12.52		$	12.98
Operating margin per ton sold	$	0.96		$	(0.25	)
Adjusted EBITDA (in thousands)	$	72,062		$	29,819
Appalachia
Tons sold (in thousands)	3,018			3,589
Coal sales per ton sold	$	65.23		$	67.70
Cost per ton sold	$	68.55		$	80.80
Operating loss per ton sold	$	(3.32	)	$	(13.10	)
Adjusted EBITDA (in thousands)	$	39,807		$	28,427
Other
Tons sold (in thousands)	1,619			2,102
Coal sales per ton sold	$	33.42		$	28.64
Cost per ton sold	$	31.21		$	27.17
Operating margin per ton sold	$	2.21		$	1.47
Adjusted EBITDA (in thousands)	$	1,691		$	4,132

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.

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Powder River Basin — Adjusted EBITDA increased over 140% in the first quarter of 2015 when compared to the first quarter of 2014 due to increased shipment volumes, higher pricing, and lower costs. Railroad service has rebounded from the lows reached in the prior year quarter when extreme weather, derailments, and competing commodities led to significant disruptions in coal haulage from the Powder River Basin. Pricing improved in the current year quarter 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. Unit costs are lower due to the increased volume 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 this quarter versus the prior year quarter. See further information regarding diesel fuel hedging strategies in Item 3. “Quantitative and Qualitative Disclosures About Market Risk.”

Appalachia — Adjusted EBITDA increased 40% in the first quarter of 2015 when compared with the first quarter of 2014 primarily due to a 15% reduction in cost per ton sold, resulting from a shift in production to lower cost operations, particularly at the Leer mine. Coal sales volumes decreased in the first quarter of 2015 when compared to the first quarter of 2014, primarily due to the sale and idling of two complexes impacting the comparative periods. Pricing declined in the first quarter of 2015 compared to the first quarter of 2014 across all major quality specifications, but the decline was most pronounced in the metallurgical products. The price declines were partially offset by a shift in sales mix to a greater percentage of metallurgical sales, and a shift to higher quality products within metallurgical sales. Unit cost declined in the current quarter compared to the prior year quarter primarily due to the shift in production discussed above, idling of a higher cost production source discussed above, and lower fuel pricing. Adjusted EBITDA in the first quarter of 2014 includes gains from the sale of a thermal coal complex and idled thermal coal mine in Kentucky ($16.6 million).

Other — Adjusted EBITDA decreased almost 60% due to a 23% reduction in sales volume as a result of lower natural gas pricing and a weakened export thermal market. Pricing increased in the current year quarter due to the mix of customer shipments offset by an increase in operating cost due primarily to lower production volume.

Results of Operations

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

Revenues. Our revenues consist of coal sales and revenues from our ADDCAR subsidiary prior to its disposition in the first quarter of 2014.

Coal sales. The following table summarizes information about our coal sales during the three months ended March 31, 2015 and compares it with the information for the three months ended March 31, 2014:

	Three Months Ended March 31,
	2015		2014		(Decrease) / Increase
	(In thousands)
Coal sales	$	677,005	$	734,033	$	(57,028	)
Tons sold	33,108		31,357		1,751

On a consolidated basis, coal sales decreased in the first quarter of 2015 from the first quarter of 2014, primarily due to the impact of the reduction in export volume of approximately $89 million, and secondarily due to reduced domestic thermal sales from Appalachia and our Other operating segments of approximately $25 million. Increased volume and pricing of Powder River Basin domestic sales offset these impacts by approximately $56 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 three months ended March 31, 2015 and compares it with the information for the three months ended March 31, 2014:

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	Three Months Ended March 31,						(Increase) Decrease
	2015			2014			in Net Loss
	(In thousands)
Cost of sales (exclusive of items shown separately below)	$	562,322		$	686,314		$	123,992
Depreciation, depletion and amortization	104,874			104,423			(451		)
Amortization of acquired sales contracts, net	(3,390		)	(3,696		)	(306		)
Change in fair value of coal derivatives and coal trading activities, net	1,220			914			(306		)
Selling, general and administrative expenses	22,605			29,136			6,531
Other operating (income) expense, net	9,086			(7,998		)	(17,084		)
Total costs, expenses and other	$	696,717		$	809,093		$	112,376

Cost of sales. Our cost of sales decreased in the first quarter of 2015 from the first quarter of 2014, due to lower transportation costs on lower export sales volumes (a decrease of approximately $64 million), lower diesel fuel costs (approximately $24 million), and savings associated with sold and idled Appalachian complexes (approximately $18 million and $15 million, respectively). See discussion in “Regional Performance” for further information about regional results.

Depreciation, depletion and amortization. When compared with the first quarter of 2014, depreciation, depletion and amortization costs increased in 2015 due to higher depletion associated with the increase in Powder River Basin volume. The increase was partially offset by reduction in depreciation and amortization related to mine idlings and dispositions in Appalachia.

Selling, general and administrative expenses. Total selling, general and administrative expenses decreased when compared with the first quarter of 2014, due to lower bonus plan accruals and lower benefit costs.

Other operating (income) expense, net. Other operating income, net was a net loss during the first quarter of 2015 compared to net income in the first quarter of 2014. The prior year quarter reflects the benefit from a net gain on sale of operations of approximately $14 million.

Benefit from income taxes. The following table summarizes our benefit from income taxes for the three months ended March 31, 2015 and compares it with the information for the three months ended March 31, 2014:

	Three Months Ended March 31,						Increase
	2015			2014			in Net Loss
	(In thousands)
Benefit from income taxes	$	(3,396	)	$	(43,611	)	$	(40,215	)

The income tax benefit rate of 2.9% in the first quarter of 2015 decreased from 26.0% in the first quarter of 2014 due to an increase in the percentage of calculated tax benefit subject to a valuation allowance. See further discussion in Note 10, “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

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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.

	Three Months Ended March 31,
	2015			2014
	(In thousands)

Reported segment coal sales revenues	$	634,903		$	629,953
Coal risk management derivative settlements classified in “other (income) expense, net”	(971		)	(2,879		)
Transportation costs	43,073			106,959
Coal sales	677,005			734,033
Other revenues	$	—		$	1,938
	$	677,005		$	735,971

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 March 31,
	2015			2014
	(In thousands)

Reported segment cost of tons sold	$	612,758		$	680,296
Diesel fuel risk management derivative settlements classified in “other (income) expense, net”	(1,224		)	(1,879		)
Transportation costs	43,073			106,959
Depreciation, depletion and amortization in reported segment cost of tons sold presented on separate line on statement of operations	(103,143		)	(103,751		)
Other (other operating segments, operating overhead, etc.)	10,858			4,689
Cost of sales	$	562,322		$	686,314

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 March 31,
	2015			2014
	(In thousands)
Reported Segment Adjusted EBITDA	$	113,560		$	62,378
Corporate and other	(31,788		)	(34,773		)
Adjusted EBITDA	81,772			27,605
Income tax benefit	3,396			43,611
Interest expense, net	(96,879		)	(94,628		)
Depreciation, depletion and amortization	(104,874		)	(104,423		)
Amortization of acquired sales contracts, net	3,390			3,696
Net loss	$	(113,195	)	$	(124,139	)

Corporate and other includes primarily selling, general and administrative expenses, asset impairment charges, income from our equity investments and certain changes in the fair value of coal derivatives and coal trading activities. Corporate and other adjusted EBITDA increased $3.0 million in the first quarter 2015 when compared to the first quarter 2014 due to $6.5 million of reduced expenses recorded in the Statement of Operations line item “Selling, general and administrative expenses”, which is primarily the result of management initiatives to reduce costs, and an increase of $3.1 million in miscellaneous expenses recorded in the line item “Other operating (income) expense, net”.

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 we have suspended or eliminated most financial maintenance covenants that pertain only to our $250 million revolver until June of 2015, when a relaxed, senior secured leverage ratio covenant becomes effective. Until then, only a minimum liquidity covenant of $550 million remains in place. We had liquidity of $1.12 billion at March 31, 2015, with $939.5 million of that in cash and liquid securities. We have no borrowings outstanding under our revolving credit agreement at March 31, 2015.

The following is a summary of cash provided by or used in each of the indicated types of activities during the three months ended March 31, 2015 and 2014:

	Three Months Ended March 31,
	2015			2014
	(In thousands)
Cash provided by (used in):
Operating activities	$	(4,273	)	$	(40,275	)
Investing activities	(26,769		)	8,413
Financing activities	(13,217		)	(13,476		)

Cash used in operating activities during the first three months of 2015 declined to $4.3 million compared to cash used in operating activities of $40.3 million in the first three months of 2014. The improvement was driven by the increase in our Adjusted EBITDA resulting from improved shipment volumes and pricing in the Powder River Basin, improved productivity in Appalachia and lower diesel fuel pricing.

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We used $26.8 million of cash in investing activities during the three months ended 2015 compared to generating $8.4 million of cash in the three months ended 2014, as proceeds from disposals and divestitures decreased $28.1 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 $8.6 million primarily related to lease buyouts at our Powder River Basin operations.

Cash used in financing activities declined $0.3 million in the three months ended March 31, 2015, as the benefit from the elimination of the dividend on our common stock, and approximately $2.0 million in debt financing costs incurred in the prior year quarter were offset by a $3.5 million increase in restricted cash in the current 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:

	Three Months Ended March 31,
	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 $0.0 million and total fixed charges were $102.1 million for the three months ended March 31, 2015. Total losses for the ratio calculation were $65.8 million and total fixed charges were $99.3 million for the three months ended March 31, 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 April 21, 2015:

	2015			2016
	Tons	$ per ton		Tons	$ per ton
	(in millions)			(in millions)
Powder River Basin
Committed, Priced	105.0	$	13.34	43.8	$	14.39
Committed, Unpriced	2.8			15.5
Appalachia
Committed, Priced Thermal	5.3	$	56.87	2.0	$	57.97
Committed, Unpriced Thermal	—			—
Committed, Priced Metallurgical	4.4	$	78.27	0.7	$	82.69
Committed, Unpriced Metallurgical	0.5			0.6
Other Bituminous
Committed, Priced	6.0	$	33.60	2.8	$	34.61
Committed, Unpriced	0.5			—

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 March 31, 2015. The estimated future realization of the value of the trading portfolio is $0.3 million of losses in the remainder of 2015 and $1.4 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 three months ended March 31, 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 $0.4 million. The final VaR at March 31, 2015 was $0.4 million.

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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 three months ended March 31, 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 $0.3 million. The final VaR at March 31, 2015 was $0.1 million.

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 67 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 March 31, 2015, we had protected the price of approximately 86% 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 60% of expected purchases at an average strike price of $1.92 per gallon. Additionally, we have protected approximately 37% of our expected 2016 purchases with out-of-the-money call options. At March 31, 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 March 31, 2015, of our $5.2 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 March 31, 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 March 31, 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.

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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.

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.

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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 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

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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 where it is currently pending.

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.

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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.

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 March 31, 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 March 31, 2015. Based on the closing price of our common stock as reported on the New York Stock Exchange on April 20, 2015, the approximate dollar value of our common stock that may yet be purchased under this program was $11.6 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 March 31, 2015.

Item 6. Exhibits.

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 months ended March 31, 2015 filed in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”

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.

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	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)

		April 30, 2015