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 June 30, 2012

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

For the transition period from to .

Commission file number: 1-13105

Arch Coal, Inc.

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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

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

Large accelerated filer x		Accelerated filer o

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

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

At July 31, 2012 there were 212,268,960 shares of the registrant’s common stock outstanding.

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		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	27
	Item 3. Quantitative and Qualitative Disclosures About Market Risk	36
	Item 4. Controls and Procedures	38
Part II OTHER INFORMATION		38
	Item 1. Legal Proceedings	38
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	41
	Item 4. Mine Safety Disclosures	41
	Item 6. Exhibits	42

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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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
				(Unaudited)

Revenues	$	1,063,538		$	985,528		$	2,103,189		$	1,858,466

Costs, expenses and other
Cost of sales	881,259			715,590			1,732,130			1,369,274
Depreciation, depletion and amortization	132,868			97,236			272,834			180,773
Amortization of acquired sales contracts, net	(4,451		)	1,262			(18,468		)	7,206
Mine closure and asset impairment costs	525,762			—			525,762			—
Goodwill impairment	115,791			—			115,791			—
Selling, general and administrative expenses	35,178			29,040			66,039			59,474
Change in fair value of coal derivatives and coal trading activities, net	(32,054		)	2,672			(35,667		)	888
Acquisition and transition costs related to ICG	—			48,666			—			48,666
Other operating income, net	(1,831		)	(4,292		)	(20,329		)	(5,407		)
	1,652,522			890,174			2,638,092			1,660,874

Income (loss) from operations	(588,984		)	95,354			(534,903		)	197,592
Interest expense, net:
Interest expense	(78,728		)	(42,249		)	(153,500		)	(76,829		)
Interest income	1,088			755			2,109			1,501
	(77,640		)	(41,494		)	(151,391		)	(75,328		)
Other nonoperating expense
Bridge financing costs related to ICG	—			(49,490		)	—			(49,490		)
Net loss resulting from early retirement and refinancing of debt	(19,042		)	(250		)	(19,042		)	(250		)
	(19,042		)	(49,740		)	(19,042		)	(49,740		)
Income (loss) before income taxes	(685,666		)	4,120			(705,336		)	72,524
Provision for (benefit from) income taxes	(250,242		)	(2,510		)	(271,321		)	10,020
Net income (loss)	(435,424		)	6,630			(434,015		)	62,504
Less: Net income attributable to noncontrolling interest	(65		)	(318		)	(268		)	(591		)
Net income (loss) attributable to Arch Coal, Inc.	$	(435,489	)	$	6,312		$	(434,283	)	$	61,913

Earnings per common share
Basic earnings (loss) per common share	$	(2.05	)	$	0.04		$	(2.05	)	$	0.37
Diluted earnings (loss) per common share	$	(2.05	)	$	0.04		$	(2.05	)	$	0.37
Weighted average shares outstanding
Basic	212,048			174,244			211,868			168,442
Diluted	212,048			175,272			211,868			169,554

Dividends declared per common share	$	0.03		$	0.11		$	0.14		$	0.21

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

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
				(unaudited)

Net income (loss)	$	(435,424	)	$	6,630		$	(434,015	)	$	62,504
Other comprehensive income (loss), net of income taxes:
Pension, postretirement and other post-employment benefits	(3,584		)	293			(3,121		)	866
Unrealized gains (losses) on available-for-sale securities	62			(1,434		)	314			(687		)
Unrealized gains and losses on derivatives, net of reclassifications into net income:
Unrealized gains (losses) on derivatives	991			(3,127		)	2,751			6,374
Reclassifications of (gains) losses into net income	(518		)	(4,360		)	4,307			(6,484		)
Total other comprehensive income (loss)	(3,049		)	(8,628		)	4,251			69
Total comprehensive income (loss)	$	(438,473	)	$	(1,998	)	$	(429,764	)	$	62,573

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)

	June 30,			December 31,
	2012			2011
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	512,527		$	138,149
Restricted cash	5,740			10,322
Trade accounts receivable	327,402			380,595
Other receivables	70,103			88,584
Inventories	455,091			377,490
Prepaid royalties	11,214			21,944
Deferred income taxes	65,531			42,051
Coal derivative assets	53,351			13,335
Other	67,568			110,304
Total current assets	1,568,527			1,182,774

Property, plant and equipment, net	7,397,131			7,949,150

Other assets
Prepaid royalties	89,441			86,626
Goodwill	480,312			596,103
Equity investments	235,299			225,605
Other	183,228			173,701
Total other assets	988,280			1,082,035
Total assets	$	9,953,938		$	10,213,959

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	316,669		$	383,782
Coal derivative liabilities	7,090			7,828
Accrued expenses and other current liabilities	360,793			348,207
Current maturities of debt and short-term borrowings	111,260			280,851
Total current liabilities	795,812			1,020,668
Long-term debt	4,464,351			3,762,297
Asset retirement obligations	424,289			446,784
Accrued pension benefits	49,040			48,244
Accrued postretirement benefits other than pension	42,028			42,309
Accrued workers’ compensation	82,372			71,948
Deferred income taxes	730,495			976,753
Other noncurrent liabilities	223,131			255,382
Total liabilities	6,811,518			6,624,385

Redeemable noncontrolling interest	17,500			11,534

Stockholders’ Equity
Common stock, $0.01 par value, authorized 260,000 shares, issued 213,768 and 213,183 shares at June 30, 2012 and December 31, 2011, respectively	2,138			2,136
Paid-in capital	3,022,014			3,015,349
Treasury stock, at cost	(53,848		)	(53,848		)
Retained earnings	158,374			622,353
Accumulated other comprehensive loss	(3,758		)	(7,950		)
Total stockholders’ equity	3,124,920			3,578,040
Total liabilities and stockholders’ equity	$	9,953,938		$	10,213,959

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)

	Six Months Ended June 30,
	2012			2011
	(Unaudited)
Operating activities
Net income (loss)	$	(434,015	)	$	62,504
Adjustments to reconcile to cash provided by operating activities:
Depreciation, depletion and amortization	272,834			180,773
Amortization of acquired sales contracts, net	(18,468		)	7,206
Bridge financing costs related to ICG	—			49,490
Net loss resulting from early retirement of debt and refinancing activities	19,042			250
Noncash mine closure and asset impairment costs	501,942			7,316
Goodwill impairment	115,791			—
Prepaid royalties expensed	16,551			19,491
Employee stock-based compensation expense	7,014			7,071
Amortization relating to financing activities	8,948			5,093
Changes in:
Receivables	52,291			(25,329		)
Inventories	(80,199		)	(31,476		)
Coal derivative assets and liabilities	(37,985		)	4,902
Accounts payable, accrued expenses and other current liabilities	(64,965		)	8,912
Income taxes, net	22,869			(15,186		)
Deferred income taxes	(272,094		)	18,177
Other	(14,248		)	15,006

Cash provided by operating activities	95,308			314,200

Investing activities
Acquisition of ICG, net of cash acquired	—			(2,910,380		)
Change in restricted cash	4,582			(74,814		)
Capital expenditures	(202,073		)	(107,725		)
Proceeds from dispositions of property, plant and equipment	22,551			1,411
Purchases of investments and advances to affiliates	(9,292		)	(38,059		)
Additions to prepaid royalties	(8,634		)	(25,212		)

Cash used in investing activities	(192,866		)	(3,154,779		)

Financing activities
Proceeds from the issuance of senior notes	—			2,000,000
Proceeds from term note	1,386,000			—
Proceeds from the issuance of common stock, net	—			1,249,407
Payments to retire debt	(452,654		)	(307,984		)
Change in restricted cash	—			(260,663		)
Net increase (decrease) in borrowings under lines of credit and commercial paper program	(391,300		)	303,096
Net payments on other debt	(11,164		)	(8,845		)
Debt financing costs	(34,381		)	(112,334		)
Dividends paid	(29,696		)	(34,192		)
Issuance of common stock under incentive plans	5,131			846

Cash provided by financing activities	471,936			2,829,331

Increase (decrease) in cash and cash equivalents	374,378			(11,248		)
Cash and cash equivalents, beginning of period	138,149			93,593

Cash and cash equivalents, end of period	$	512,527		$	82,345

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 and controlled entities (the “Company”). The Company’s primary business is the production of steam and metallurgical coal from surface and underground mines located throughout the United States, for sale to utility, industrial and export markets. On June 15, 2011, the Company acquired International Coal Group, Inc. (“ICG”). The Company currently operates 18 mining complexes in West Virginia, Kentucky, Maryland, Virginia, Illinois, Wyoming, Colorado and Utah. All subsidiaries (except as noted below) are wholly-owned. Intercompany transactions and accounts have been eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial reporting and U.S. Securities and Exchange Commission regulations. In the opinion of management, all adjustments, consisting of normal, recurring accruals considered necessary for a fair presentation, have been included. Results of operations for the three and six month periods ended June 30, 2012 are not necessarily indicative of results to be expected for the year ending December 31, 2012. 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, 2011 included in the Company’s Annual Report on Form 10-K/A filed with the U.S. Securities and Exchange Commission.

The Company owned a 99% membership interest and acted as the managing member in Arch Western Resources, LLC (“Arch Western”) a joint venture with Delta Housing, Inc., a subsidiary of BP p.l.c, Arch Western operates coal mines in Wyoming, Colorado and Utah. On April 9, 2012, Delta Housing, Inc. exercised their contractual right to require us to purchase their membership interests in Arch Western. The negotiated purchase amount of $17.5 million was paid on July 2, 2012.

2. Accounting Policies

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

3. Debt

	June 30,		December 31,
	2012		2011
	(In thousands)
Indebtedness to banks under credit facilities	90,000		481,300
Term loan ($1.4 billion face value) due 2018	1,386,292		—
6.75% senior notes ($450.0 million face value) due 2013	—		450,971
8.75% senior notes ($600.0 million face value) due 2016	589,963		588,974
7.00% senior notes due in 2019 at par	1,000,000		1,000,000
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	9,356		21,903
	4,575,611		4,043,148
Less current maturities of debt and short-term borrowings	111,260		280,851
Long-term debt	$	4,464,351	$	3,762,297

The current maturities of debt include contractual maturities, as well as amounts borrowed that are supported by credit facilities that have a term of less than one year and amounts borrowed under credit facilities with terms longer than one year that the Company does not intend to refinance on a long-term basis, based on cash projections and management’s plans.

On May 16, 2012, the Company entered into an amendment to its senior secured revolving credit facility that amended certain financial maintenance covenants, suspending the Company’s compliance with the debt-to-EBITDA ratio, easing other financial covenants through September 2014 and adding defined minimum EBITDA targets. The maximum borrowing capacity of the revolving credit facility was reduced from $2 billion to $600 million. In conjunction with the amendment, the Company borrowed $1.4 billion under a six-year secured term loan facility, issued at a 1% discount. The term loan contains no financial maintenance covenants, is prepayable and is secured by the same assets as borrowings under the revolving credit facility. Quarterly principal payments of $3.5 million are due beginning in September 2012, plus interest at a rate of the greater of Libor or 1.25%, plus 450 basis points. The

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proceeds of the term loan were used to retire all outstanding borrowings under the revolving credit facility and the outstanding $450.0 million principal amount of 6 ¾% Senior Notes due 2013 issued by Arch Western Finance, LLC (“Arch Western Finance”), the Company’s indirect subsidiary.

On May 16, 2012, Arch Western Finance accepted for purchase an aggregate of approximately $304.0 million principal amount of its 6 ¾% Senior Notes due 2013 in an initial settlement pursuant to the terms of its tender offer and consent solicitation, which commenced on May 1, 2012, and called for redemption all of the remaining notes outstanding after the completion of the tender offer. The consideration for each $1,000 of principal purchased under the tender offer and consent solicitation was $1,002.50, for a total purchase consideration of $304.8 million. On May 30, 2012, the remaining notes with an outstanding principal amount of $146.0 million were redeemed at par value.

The Company incurred financing costs of $27.4 million in conjunction with the term loan, which have been deferred on the balance sheet. The Company wrote off $17.3 million of the $24.8 million of financing costs that had previously been deferred relating to the reduction in capacity of the senior secured revolving credit facility and $1.1 million related to the redemption of the 6 ¾% Senior Notes due 2013, offset by the $0.8 million of unamortized issue premium on the notes. The write-off of deferred financing fees, along with other transaction fees associated with these transactions is reflected in “Loss on extinguishment and refinancing of debt” in the condensed consolidated statements of operations.

At June 30, 2012, cash on hand was $512.5 million and availability was $345.0 million under our lines of credit.

4. Mine Closure and Asset Impairment Costs

An extreme downturn in demand for thermal coal resulted in the Company announcing on June 21, 2012 the closing of four mining complexes and the temporary idling of a fifth complex, all acquired with ICG, as well as cutbacks in production at other Appalachia mines. These actions resulted in a total workforce reduction of approximately 750 positions. The operations had ceased production prior to June 30, 2012, and will incur minimal ongoing annual maintenance costs customary with idling operations. The terms of customer contracts will be fulfilled by other operations.

The following costs are reflected in the line “Mine closure and asset impairment costs” on the condensed consolidated statements of operations for the three and six months ended June 30, 2012:

Parts and supplies inventory writedown	$	2,598
Impairment of property, plant and equipment	95,641
Impairment of coal properties and deferred development costs	403,279
Royalty obligations	11,546
Employee termination benefits	12,274
Pension, postretirement and occupational disease curtailment charge, net (see notes 11 and 12)	424
	$	525,762

The fair value of the closed or idled operations’ property, plant and equipment of approximately $51 million was based on the analysis of the marketability of thermal coal properties in the current market environment and our ability to redeploy equipment to other facilities.

The majority of the employee termination benefits will be paid in the third quarter of 2012. The royalty obligations represent minimum payments on various leases and will be paid over the remaining term of the leases, through 2016.

The announcement of the closures triggered an actuarial curtailment under the Company’s sponsored pension, post-retirement medical and black lung benefit programs. Certain employees were informed that they would be terminated effective August 21, 2012, which will trigger the recognition of the remaining pension plan curtailment impact in the third quarter of 2012, a curtailment benefit of $2.2 million.

5. Goodwill

A significant drop in the Company’s stock price during the second quarter of 2012, combined with continuing weak demand for thermal coal during the quarter and the Company’s resulting production cuts, indicated that the fair value of the Company’s goodwill could be less than its carrying value. Accordingly, the Company has performed the first step of the two-step goodwill impairment test as of June 30, 2012. The fair values of the reporting units are determined using a discounted cash flow (“DCF”) technique. A number of significant assumptions and estimates are involved in the application of the DCF analysis to forecast operating cash flows, including the discount rate and projections of sales volumes, selling prices and costs to produce.

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The value of the Company’s Black Thunder reporting unit in the Powder River Basin, where $115.8 million of goodwill had been allocated, is sensitive to thermal market demand. The further weakening in thermal coal markets in the second quarter significantly impacted the projected demand for and pricing of coal produced at Black Thunder. In step one of the goodwill impairment testing, the fair value of the Black Thunder reporting unit did not exceed its carrying value, primarily due to the impact of lower demand on near term sales volumes and pricing. The second step of the test requires that we determine the fair value of Black Thunder’s goodwill. This will involve determining the value of Black Thunder’s assets and liabilities. Based on initial estimates of the fair values of the assets and liabilities and the deficit of the fair value when compared to the related book values, we recorded a preliminary write-off of the entire $115.8 million of goodwill allocated to the Black Thunder reporting unit during the second quarter of 2012.

The goodwill amounts allocated to certain reporting units in the Company’s Appalachia segment are particularly sensitive to volatility in the demand for metallurgical coal. Should metallurgical coal markets weaken, affecting the volumes and pricing of metallurgical coal from the Company’s operations, it could cause the fair value of the reporting units to be less than their carrying value, requiring us to perform step 2 of the test for impairment.

6. Equity Investments and Membership Interests in Joint Ventures

The Company accounts for its investments and membership interests in joint ventures under the equity method of accounting if the Company has the ability to exercise significant influence, but not control, over the entity. Below are the equity method investments reflected in the condensed consolidated balance sheets:

	Knight Hawk			DKRW			Dominion			Tenaska		Millennium			Tongue
	Holdings,			Advanced			Terminal			Trailblazer		Bulk			River
In thousands	LLC			Fuels, LLC			Associates			Partners, LLC		Terminals, LLC			Railroad, LLC		Total

Balance at December 31, 2011	$	135,225		$	19,715		$	16,086		$	15,266	$	26,324		$	12,989	$	225,605
Investments in affiliates	—			—			—			—		—			—		—
Advances to (distributions from) affiliates, net	(1,801		)	—			2,150			—		4,842			675		5,866
Equity in comprehensive income (loss)	9,641			(1,551		)	(2,374		)	—		(1,888		)	—		3,828

Balance at June 30, 2012	$	143,065		$	18,164		$	15,862		$	15,266	$	29,278		$	13,664	$	235,299

Notes receivable from investees:
Balance at December 31, 2011	$	—		$	30,751		$	—		$	5,059	$	—		$	—	$	35,810
Balance at June 30, 2012	$	—		$	34,817		$	—		$	5,047	$	—		$	—	$	39,864

The Company may be required to make future contingent payments of up to $73.0 million related to development financing for certain of its equity investees. The Company’s obligation to make these payments, as well as the timing of any payments required, is contingent upon a number of factors, including project development progress, receipt of permits and construction financing.

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 73 to 78 million gallons of diesel fuel for use in its operations during 2012. 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, as well as heating oil swaps and purchased call options. At June 30, 2012, the Company had protected the price of approximately 80% of its expected purchases for the remainder of fiscal year 2012 and 50% of its 2013 purchases. At June 30, 2012, the Company had purchased heating oil call options for approximately 71 million gallons for the purpose of managing the price risk associated with future diesel purchases.

During the first quarter of 2012, the Company determined the effectiveness of the heating oil options could not be established as of December 31, 2011 and on an ongoing basis. As a result, the amount remaining in accumulated other comprehensive income of $8.2 million, or $5.2 net of income taxes, was recorded in earnings, in the “other income, net” line on the condensed consolidated statement of income.

The Company also purchased heating oil call options to hedge the fuel surcharges on its barge and rail shipments that cover increases in diesel fuel prices. These positions reduce the Company’s risk of cash flow fluctuations related to these surcharges but the

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positions are not accounted for as hedges. At June 30, 2012, the Company held purchased call options for approximately 18.0 million gallons for the purpose of managing the fluctuations in cash flows associated with fuel surcharges on future shipments.

Coal risk management positions

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

At June 30, 2012, the Company held derivatives for risk management purposes that are expected to settle in the following years :

(Tons in thousands)	2012	2013	2014	2015
Coal sales	3,821	3,517	3,240	720
Coal purchases	1,168	420	720	—

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 $0.6 million of gains in the remainder of 2012 and $2.1 million of losses in 2013.

Tabular derivatives disclosures

The Company’s contracts with certain of 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. 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 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:

	June 30, 2012								December 31, 2011
Fair Value of Derivatives	Asset			Liability					Asset			Liability
(In thousands)	Derivative			Derivative					Derivative			Derivative
Derivatives Designated as Hedging Instruments
Heating oil — diesel purchases	$	—		$	—				$	8,997		$	—
Coal	5,156			(1,284		)			1,109			—
Total	5,156			(1,284		)			10,106			—
Derivatives Not Designated as Hedging Instruments
Heating oil — diesel purchases	5,534			—					—			—
Heating oil — fuel surcharges	1,310			—					1,797			—
Coal — held for trading purposes	37,492			(38,921		)			15,505			(19,927		)
Coal — risk management	56,125			(12,307		)			14,855			(6,035		)
Total	100,461			(51,228		)			32,157			(25,962		)
Total derivatives	105,617			(52,512		)			42,263			(25,962		)
Effect of counterparty netting	(45,422		)	45,422					(18,134		)	18,134
Net derivatives as classified in the balance sheets	$	60,195		$	(7,090	)	$	53,105	$	24,129		$	(7,828	)	$	16,301

		June 30,			December 31,
		2012			2011
Net derivatives as reflected on the balance sheets
Heating oil	Other current assets	$	6,844		$	10,794
Coal	Coal derivative assets	53,351			13,335
	Coal derivative liabilities	(7,090		)	(7,828		)
		$	53,105		$	16,301

The Company had a current liability for the obligation to post cash collateral of $25.2 million at June 30, 2012 and a current asset for the right to reclaim cash collateral of $12.4 million at December 31, 2011. These amounts are not included with the derivatives presented in the table above and are included in “accrued expenses and other current liabilities” and “other current assets”, respectively, in the accompanying condensed consolidated balance sheets.

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The effects of derivatives on measures of financial performance are as follows for the three month periods ended June 30:

Derivatives used in Cash Flow Hedging Relationships (in thousands)

							Gains (Losses) Reclassified
	Gain (Loss) Recognized in OCI						from OCI into Income
	(Effective Portion)						(Effective Portion)
	2012			2011			2012		2011
Heating oil — diesel purchases	$	—		$	(6,337	)	$	—	$	6,654	(2)
Coal sales	2,231			1,344			809		237		(1)
Coal purchases	(742		)	97			—		—		(2)
Totals	$	1,489		$	(4,896	)	$	809	$	6,891

No ineffectiveness or amounts excluded from effectiveness testing relating to the Company’s cash flow hedging relationships were recognized in the results of operations in the three month periods ended June 30, 2012 and 2011.

Derivatives Not Designated as Hedging Instruments (in thousands)

	Gain (Loss) Recognized
	2012			2011
Coal — unrealized	$	27,446		$	(374	)(3)
Coal — realized	8,671			147		(4)
Heating oil — diesel purchases	(22,509		)	—		(4)
Heating oil — fuel surcharges	$	(2,599	)	$	—	(4)

Location in Statement of Income:

(1) — Revenues

(2) — Cost of sales

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

(4) — Other operating income, net

The effects of derivatives on measures of financial performance are as follows for the six month periods ended June 30:

Derivatives used in Cash Flow Hedging Relationships (in thousands)

							Gains (Losses) Reclassified from
	Gain (Loss) Recognized in OCI						OCI into Income
	(Effective Portion)						(Effective Portion)
	2012			2011			2012		2011
Heating oil — diesel purchases	$	—		$	7,921		$	—	$	9,824	(2)
Coal sales	4,724			2,750			1,010		324		(1)
Coal purchases	(944		)	(779		)	—		—		(2)
Totals	$	3,780		$	9,892		$	1,010	$	10,148

Derivatives Not Designated as Hedging Instruments (in thousands)

	Gain (Loss) Recognized
	2012			2011
Coal — unrealized	$	34,998		$	(1,419	)(3)
Coal — realized	11,829			147		(4)
Heating oil — diesel purchases	(22,086		)	—		(4)
Heating oil — fuel surcharges	$	(2,232	)	$	—	(4)

Location in Statement of Income:

(1) — Revenues

(2) — Cost of sales

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

(4) — Other operating income, net

The Company recognized net unrealized and realized gains of 4.6 million and $2.3 million during the three months ended June 30, 2012 and 2011, respectively, related to its trading portfolio. The Company recognized net unrealized and realized gains of $0.7 million $0.5 million during the six months ended June 30, 2012 and 2011, respectively, related to its trading portfolio, which are included in the caption “Change in fair value of coal derivatives and coal trading activities, net” in the accompanying condensed consolidated

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statements of operations, and are not included in the previous tables reflecting the effects of derivatives on measures of financial performance.

Based on fair values at June 30, 2012, gains on derivative contracts designated as hedge instruments in cash flow hedges of approximately $4.0 million are expected to be reclassified from other comprehensive income into earnings during the next twelve months.

8. Inventories

Inventories consist of the following:

	June 30,		December 31,
	2012		2011
	(In thousands)
Coal	$	267,600	$	206,517
Repair parts and supplies	178,626		163,527
Work-in-process	8,865		7,446
	$	455,091	$	377,490

The repair parts and supplies are stated net of an allowance for slow-moving and obsolete inventories of $11.3 million at June 30, 2012, and $13.1 million at December 31, 2011.

9. Fair Value Measurements

The hierarchy of fair value measurements prioritizes the inputs to valuation techniques used to measure fair value. 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 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 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 and heating oil) valued using modeling techniques, such as Black-Scholes, that require the use of inputs, particularly volatility, that are rarely observable. Changes in the unobservable inputs would not have a significant impact on the reported Level 3 fair values at June 30, 2012.

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:

	Fair Value at June 30, 2012
	Total		Level 1		Level 2		Level 3
	(In thousands)
Assets:
Investments in equity securities	$	8,035	$	8,035	$	—	$	—
Derivatives	60,195		51,701		1,650		6,844
Total assets	$	68,230	$	59,736	$	1,650	$	6,844
Liabilities:
Derivatives	$	7,090	$	—	$	5,355	$	1,735

The Company’s contracts with certain of 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.

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	Three Months Ended			Six Months Ended
	June 30, 2012			June 30, 2012

Balance, beginning of period	$	13,241		6,211
Realized and unrealized losses recognized in earnings, net	(14,092		)	(11,596	)
Realized and unrealized losses recognized in other comprehensive income, net	—			—
Purchases	6,468			11,729
Issuances	—			—
Settlements	(508		)	(1,235	)

Ending balance	$	5,109		5,109

Net unrealized losses during the three and six month periods ended June 30, 2012 related to level 3 financial instruments held on June 30, 2012 were $12.4 million and $9.6 million, respectively.

Fair Value of Long-Term Debt

At both June 30, 2012 and December 31, 2011, the fair value of the Company’s debt, including amounts classified as current, was $4.2 billion. Fair values are based upon observed prices in an active market when available or from valuation models using market information.

10. Stock-Based Compensation and Other Incentive Plans

During the six months ended June 30, 2012, the Company granted options to purchase approximately1.3 million shares of common stock with a weighted average exercise price of $13.46 per share and a weighted average grant-date fair value of $5.31 per share. The options’ fair value was determined using the Black-Scholes option pricing model, using a weighted average risk-free rate of .759%, a weighted average dividend yield of 2.95% and a weighted average volatility of 60.48%. The options’ expected life is 4.5 years and the options vest ratably over three years, and provide for the continuation of vesting after retirement for recipients that meet certain criteria. The expense for these options will be recognized through the date that the employee first becomes eligible to retire and is no longer required to provide service to earn all or part of the award.

The Company has a long-term incentive program that allows for the award of performance units. The total number of units earned by a participant is based on financial and operational performance measures, and may be paid out in cash or in shares of the Company’s common stock. The Company recognizes compensation expense over the three-year term of the grant. Amounts accrued and unpaid for all grants under the plan totaled $8.6 million and $9.6 million as of June 30, 2012 and December 31, 2011, respectively.

11. Workers’ Compensation Expense

The following table details the components of workers’ compensation expense:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Service cost	$	71		$	246		$	1,039		$	439
Interest cost	399			304			1,079			558
Net amortization	(851		)	(160		)	(574		)	(261		)
Curtailments	1,933			—			1,933			—
Total occupational disease	1,552			390			3,477			736
Traumatic injury claims and assessments	6,423			3,324			11,599			5,649
Total workers’ compensation expense	$	7,975		$	3,714		$	15,076		$	6,385

12. Employee Benefit Plans

The following table details the components of pension benefit costs:

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	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Service cost	$	7,310		$	3,926		$	14,906		$	8,245
Interest cost	4,092			3,996			8,072			8,127
Curtailments	324			—			324			—
Expected return on plan assets	(5,477		)	(5,438		)	(11,015		)	(10,906		)
Amortization of prior service cost (credit)	(37		)	(142		)	(73		)	(95		)
Amortization of other actuarial losses	4,200			2,234			7,771			4,374
Net benefit cost	$	10,412		$	4,576		$	19,985		$	9,745

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Service cost	$	539		$	518		$	1,088		$	923
Interest cost	520			529			1,011			1,027
Curtailments	(1,837		)	—			(1,837		)	—
Amortization of prior service credits	(2,876		)	(546		)	(5,871		)	(1,137		)
Amortization of other actuarial gains	(171		)	(952		)	(261		)	(1,550		)
Net benefit cost (credit)	$	(3,825	)	$	(450	)	$	(5,870	)	$	(737	)

13. Earnings per Common Share

The following table provides the basis for earnings per share calculations by reconciling basic and diluted weighted average shares outstanding:

	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
	(In thousands)
Weighted average shares outstanding:
Basic weighted average shares outstanding	212,048	174,244	211,868	168,442
Effect of common stock equivalents under incentive plans	—	1,028	—	1,112
Diluted weighted average shares outstanding	212,048	175,272	211,868	169,554

The weighted effect of restricted stock, restricted stock units and options for 5.3 million and 1.1 million shares of common stock for the three month periods ended June 30, 2012 and 2011, respectively, and 4.5 million and 1.7 million shares for the six month periods ending June 30, 2012 and 2011, respectively, were excluded from the calculation of diluted weighted average shares outstanding because the effect would have been antidilutive. An additional weighted effect of 40,000 and 130,000 shares for the three and six month periods ending June 30, 2012, respectively, were excluded from the calculation of diluted weighted average shares outstanding because the Company incurred a loss for those periods.

14. Guarantees

The Company has agreed to continue to provide surety bonds and letters of credit for obligations, primarily reclamation, of Magnum Coal Company (“Magnum”) related to the properties the Company sold to Magnum on December 31, 2005. Patriot Coal Corporation (“Patriot Coal”) acquired Magnum in July 2008. The surety bonding amounts are mandated by the state and are not directly related to the estimated cost to reclaim the properties. At June 30, 2012, the Company had $35.3 million of surety bonds remaining related to properties sold to Magnum, however Patriot Coal has posted letters of credit of $16.7 million in the Company’s favor.

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Magnum would have acquired a contract to supply coal through 2017 to a customer that had not consented to the contract’s assignment from the Company to Magnum. The Company has committed to purchase coal from Magnum to supply to the customer at the same price the customer is charged for the sale. Under the coal supply contract, as amended, Magnum has the ability to buy out of its monthly obligations under the contract at prices that are predetermined for the remainder of the agreement. Additionally, a predecessor of the Company entered into a guarantee for the delivery of coal under a contract assigned to Magnum. If Magnum is unable to supply the coal for these coal sales contracts or pay the buy out amount if elected, and if the guarantee is enforceable, then the Company may be required to fulfill Magnum’s delivery or payment obligations. The maximum financial impact to the Company if required to fulfill Magnum’s obligations over the term of these contracts would be approximately $70.0 million as of June 30, 2012.

On July 9, 2012 Patriot Coal filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code, in order to undertake a comprehensive financial restructuring. Patriot has the expectation of continuing to serve customers, after receiving a commitment of debtor-in-possession financing. At this time, the Company does not believe that it is probable that it would have to purchase replacement coal, and, accordingly, no losses have been recorded in the consolidated financial statements as of June 30, 2012.

15. Contingencies

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. ICG’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 $228.0 million and $377.0 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 non-delivery 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. 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. Wolf Run and Hunter Ridge have filed an appeal bond in the amount of $124.9 million. Briefing is complete and oral argument was held on May 16, 2012. The matter is pending a decision by the Court.

As of June 30, 2012 and December 31, 2011, the Company had accrued $111.4 million and $108.3 million, respectively, for this lawsuit, including interest. The ultimate resolution of this matter could result in an outcome which may be materially different than what the Company has accrued.

In addition, the Company is a party to numerous claims and lawsuits with respect to various matters. The Company provides for costs related to contingencies when a loss is probable and the amount is reasonably determinable. After conferring with counsel, it is the opinion of management that the ultimate resolution of pending claims, other than as noted above, will not have a material adverse effect on the consolidated financial condition, results of operations or liquidity of the Company.

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16. Segment Information

The Company has three reportable business segments, which are based on the major coal producing basins in which the Company operates. Each of these reportable business segments includes a number of mine complexes. The Company manages its coal sales by coal basin, not by individual mine complex. Geology, coal transportation routes to customers, regulatory environments and coal quality are characteristic to a basin. Accordingly, market and contract pricing have developed by coal basin. Mine operations are evaluated based on their per-ton operating costs (defined as including all mining costs but excluding pass-through transportation expenses), 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; the Western Bituminous (WBIT) segment, with operations in Utah, Colorado and southern Wyoming; the Appalachia (APP) segment, with operations in West Virginia, Kentucky, Maryland and Virginia. The Appalachia segment includes the acquired ICG operations in Appalachia, as well as the Company’s previous Central Appalachia segment. The “Other” operating segment represents primarily the Company’s Illinois operations and ADDCAR subsidiary, which manufactures and sells its patented highwall mining system.

Operating segment results for the three and six month periods ended June 30, 2012 and 2011 are presented below. Results for the reportable segments include all direct costs of mining, including all depreciation, depletion and amortization related to the mining operations, even if the assets are not recorded at the operating segment level. See discussion of segment assets below. 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 transactions.

The asset amounts below represent an allocation of assets consistent with the Company’s incentive compensation plans. The amounts in Corporate, Other and Eliminations represent primarily corporate assets (cash, receivables, investments, plant, property and equipment) as well as unassigned coal reserves, above-market acquired sales contracts and other unassigned assets. Goodwill is allocated to the respective reporting units, even though it may not be reflected in the subsidiaries’ financial statements.

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									Other			Corporate,
									Operating			Other and
	PRB			APP			WBIT		Segments			Eliminations			Consolidated
	(in thousands)
Three months ended June 30, 2012
Revenues	$	322,512		$	504,309		$	199,552	$	37,165		$	—		$	1,063,538
Income (loss) from operations	22,747			(493,093		)	13,779		1,291			(133,708		)	(588,984		)
Depreciation, depletion and amortization	37,131			73,176			18,454		3,423			684			132,868
Amortization of acquired sales contracts, net	31			(4,859		)	—		377			—			(4,451		)
Mine closure and asset impairment costs	—			525,916			179		(227		)	(106		)	525,762
Capital expenditures	5,793			78,102			14,114		(1,131		)	11,924			108,802

Three months ended June 30, 2011
Revenues	$	391,413		$	400,795		$	189,154	$	4,169		$	(3	)	$	985,528
Income from operations	35,615			87,961			43,673		113			(72,008		)	95,354
Depreciation, depletion and amortization	41,165			33,091			22,099		536			345			97,236
Amortization of acquired sales contracts, net	5,603			(4,206		)	—		(135		)	—			1,262
Capital expenditures	15,647			29,288			10,115		4,373			9,591			69,014

Six months ended June 30, 2012
Revenues	$	723,689		$	973,367		$	344,111	$	62,022		$	—		$	2,103,189
Income (loss) from operations	55,290			(477,258		)	45,020		(2,459		)	(155,496		)	(534,903		)
Depreciation, depletion and amortization	78,354			149,193			37,054		7,110			1,123			272,834
Amortization of acquired sales contracts, net	(785		)	(17,947		)	—		264			—			(18,468		)
Mine closure and asset impairment costs	—			525,916			179		(227		)	(106		)	525,762
Total assets	2,044,743			3,870,734			715,362		580,272			2,742,827			9,953,938
Capital expenditures	9,779			144,405			29,251		4,513			14,125			202,073

Six months ended June 30, 2011
Revenues	$	784,526		$	725,181		$	344,593	$	4,166		$	—		$	1,858,466
Income from operations	82,489			142,356			70,564		705			(98,522		)	197,592
Depreciation, depletion and amortization	82,856			54,107			42,628		357			825			180,773
Amortization of acquired sales contracts, net	11,547			(4,206		)	—		(135		)	—			7,206
Total assets	2,231,636			4,694,368			674,765		562,291			2,093,488			10,256,548
Capital expenditures	18,485			46,590			21,892		4,373			16,385			107,725

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A reconciliation of segment income from operations to consolidated income before income taxes follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Income (loss) from operations	$	(588,984	)	$	95,354		$	(534,903	)	$	197,592
Interest expense	(78,728		)	(42,249		)	(153,500		)	(76,829		)
Interest income	1,088			755			2,109			1,501
Other nonoperating expenses	(19,042		)	(49,740		)	(19,042		)	(49,740		)
Income (loss) before income taxes	$	(685,666	)	$	4,120		$	(705,336	)	$	72,524

17. Supplemental Condensed 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 Western Resources, LLC and its subsidiaries, Arch Receivable Company, LLC and the Company’s subsidiaries outside the U.S.):

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Condensed Consolidating Statements of Operations

Three Months Ended June 30, 2012

				Guarantor			Non- Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	558,400		$	505,138		$	—		$	1,063,538

Costs, expenses and other
Cost of sales	2,288			458,214			442,387			(21,630		)	881,259
Depreciation, depletion and amortization	1,345			93,254			38,270			(1		)	132,868
Amortization of acquired sales contracts, net	—			(4,482		)	31			—			(4,451		)
Mine closure and asset impairment costs	—			525,690			72			—			525,762
Goodwill impairment	—			115,791			—			—			115,791
Selling, general and administrative expenses	21,774			2,700			12,392			(1,688		)	35,178
Change in fair value of coal derivatives and coal trading activities, net	—			(32,054		)	—			—			(32,054		)
Other operating (income) expense, net	6,472			(35,930		)	4,308			23,319			(1,831		)

	31,879			1,123,183			497,460			—			1,652,522

Income from investment in subsidiaries	(553,007		)	—			—			553,007			—

Income (loss) from operations	(584,886		)	(564,783		)	7,678			553,007			(588,984		)
Interest expense, net:
Interest expense	(89,740		)	(1,198		)	(8,809		)	21,019			(78,728		)
Interest income	6,309			159			15,639			(21,019		)	1,088
	(83,431		)	(1,039		)	6,830			—			(77,640		)

Other non-operating expense
Bridge financing costs related to ICG	—			—			—			—			—
Net loss resulting from early retirement of ICG debt	(17,349		)	—			(1,693		)	—			(19,042		)
	(17,349		)	—			(1,693		)	—			(19,042		)

Income (loss) before income taxes	(685,666		)	(565,822		)	12,815			553,007			(685,666		)
Benefit from income taxes	(250,242		)	—			—			—			(250,242		)

Net income (loss)	(435,424		)	(565,822		)	12,815			553,007			(435,424		)
Less: Net income attributable to noncontrolling interest	(65		)	—			—			—			(65		)

Net income (loss) attributable to Arch Coal, Inc.	$	(435,489	)	$	(565,822	)	$	12,815		$	553,007		$	(435,489	)

Total comprehensive income (loss)	$	(434,624	)	$	(570,256	)	$	13,400		$	553,007		$	(438,473	)

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Condensed Consolidating Statements of Operations

Six Months Ended June 30, 2012

				Guarantor			Non- Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	1,057,129		$	1,046,060		$	—		$	2,103,189

Costs, expenses and other
Cost of sales	5,258			883,216			890,442			(46,786		)	1,732,130
Depreciation, depletion and amortization	2,560			193,267			77,009			(2		)	272,834
Amortization of acquired sales contracts, net	—			(17,683		)	(785		)	—			(18,468		)
Mine closure and asset impairment costs	—			525,690			72			—			525,762
Goodwill impairment	—			115,791			—			—			115,791
Selling, general and administrative expenses	40,418			4,686			24,437			(3,502		)	66,039
Change in fair value of coal derivatives and coal trading activities, net	—			(35,667		)	—			—			(35,667		)
Other operating (income) expense, net	3,360			(73,629		)	(350		)	50,290			(20,329		)

	51,596			1,595,671			990,825			—			2,638,092

Income from investment in subsidiaries	(475,692		)	—			—			475,692			—

Income (loss) from operations	(527,288		)	(538,542		)	55,235			475,692			(534,903		)
Interest expense, net:
Interest expense	(171,837		)	(2,377		)	(20,152		)	40,866			(153,500		)
Interest income	11,138			405			31,432			(40,866		)	2,109
	(160,699		)	(1,972		)	11,280			—			(151,391		)

Other non-operating expense
Bridge financing costs related to ICG	—			—			—			—			—
Net loss resulting from early retirement of debt	(17,349		)	—			(1,693		)	—			(19,042		)
	(17,349		)	—			(1,693		)	—			(19,042		)

Income (loss) before income taxes	(705,336		)	(540,514		)	64,822			475,692			(705,336		)
Benefit from income taxes	(272,902		)	—			1,581			—			(271,321		)

Net income (loss)	(432,434		)	(540,514		)	63,241			475,692			(434,015		)
Less: Net income attributable to noncontrolling interest	(268		)	—			—			—			(268		)

Net income (loss) attributable to Arch Coal, Inc.	$	(432,702	)	$	(540,514	)	$	63,241		$	475,692		$	(434,283	)

Total comprehensive income (loss)	$	(430,676	)	$	(543,015	)	$	68,235		$	475,692		$	(429,764	)

Table of Contents

Condensed Consolidating Statements of Operations

Three Months Ended June 30, 2011

				Guarantor			Non- Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	419,895		$	565,633		$	—		$	985,528

Costs, expenses and other
Cost of sales	4,940			288,172			447,707			(25,229		)	715,590
Depreciation, depletion and amortization	659			56,062			40,516			(1		)	97,236
Amortization of acquired sales contracts, net	—			(4,340		)	5,602			—			1,262
Mine closure and asset impairment costs	—			—			—			—			—
Goodwill impairment	—			—			—			—			—
Selling, general and administrative expenses	18,600			3,171			9,104			(1,835		)	29,040
Change in fair value of coal derivatives and coal trading activities, net	—			2,672			—			—			2,672
Acquisition and transition costs related to ICG	48,666			—			—			—			48,666
Other operating (income) expense, net	(4,831		)	(29,248		)	2,722			27,065			(4,292		)

	68,034			316,489			505,651			—			890,174

Income from investment in subsidiaries	165,368			—			—			(165,368		)	—

Income from operations	97,334			103,406			59,982			(165,368		)	95,354
Interest expense, net:
Interest expense	(48,033		)	(2,135		)	(10,962		)	18,881			(42,249		)
Interest income	4,309			136			15,191			(18,881		)	755
	(43,724		)	(1,999		)	4,229			—			(41,494		)

Other non-operating expense
Bridge financing costs related to ICG	(49,490		)	—			—			—			(49,490		)
Net loss resulting from early retirement of debt	—			(250		)	—			—			(250		)
	(49,490		)	(250		)	—			—			(49,740		)

Income before income taxes	4,120			101,157			64,211			(165,368		)	4,120
Benefit from income taxes	(2,510		)	—			—			—			(2,510		)

Net income	6,630			101,157			64,211			(165,368		)	6,630
Less: Net income attributable to noncontrolling interest	(318		)	—			—			—			(318		)

Net income attributable to Arch Coal, Inc.	$	6,312		$	101,157		$	64,211		$	(165,368	)	$	6,312

Total comprehensive income (loss)	$	20		$	102,245		$	61,105		$	(165,368	)	$	(1,998	)

Table of Contents

Condensed Consolidating Statements of Operations

Six Months Ended June 30, 2011

				Guarantor			Non- Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)

Revenue	$	—		$	758,429		$	1,100,037		$	—		$	1,858,466

Costs, expenses and other
Cost of sales	8,219			540,057			871,030			(50,032		)	1,369,274
Depreciation, depletion and amortization	1,331			99,341			80,101			—			180,773
Amortization of acquired sales contracts, net	—			(4,340		)	11,546			—			7,206
Mine closure and asset impairment costs	—			—			—			—			—
Goodwill impairment	—			—			—			—			—
Selling, general and administrative expenses	38,936			5,053			19,017			(3,532		)	59,474
Change in fair value of coal derivatives and coal trading activities, net	—			888			—			—			888
Acquisition and transition costs related to ICG	48,666			—			—			—			48,666
Other operating (income) expense, net	(9,398		)	(56,702		)	7,129			53,564			(5,407		)

	87,754			584,297			988,823			—			1,660,874

Income from investment in subsidiaries	290,370			—			—			(290,370		)	—

Income from operations	202,616			174,132			111,214			(290,370		)	197,592
Interest expense, net:
Interest expense	(88,654		)	(2,849		)	(21,944		)	36,618			(76,829		)
Interest income	8,052			432			29,635			(36,618		)	1,501
	(80,602		)	(2,417		)	7,691			—			(75,328		)

Other non-operating expense
Bridge financing costs related to ICG	(49,490		)	—			—			—			(49,490		)
Net loss resulting from early retirement of debt	—			(250		)	—			—			(250		)
	(49,490		)	(250		)	—			—			(49,740		)

Income before income taxes	72,524			171,465			118,905			(290,370		)	72,524
Provision for income taxes	10,020			—			—			—			10,020

Net income	62,504			171,465			118,905			(290,370		)	62,504
Less: Net income attributable to noncontrolling interest	(591		)	—			—			—			(591		)

Net income attributable to Arch Coal, Inc.	$	61,913		$	171,465		$	118,905		$	(290,370	)	$	61,913

Total comprehensive income	$	66,392		$	172,495		$	114,056		$	(290,370	)	$	62,573

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Condensed Consolidating Balance Sheets

June 30, 2012

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Assets
Cash and cash equivalents	$	400,698		$	360		$	111,469		$	—		$	512,527
Restricted cash	5,740			—			—			—			5,740
Receivables	47,525			23,006			330,188			(3,214		)	397,505
Inventories	—			232,126			222,965			—			455,091
Other	96,561			88,695			12,408			—			197,664
Total current assets	550,524			344,187			677,030			(3,214		)	1,568,527

Property, plant and equipment, net	29,658			5,891,377			1,476,096			—			7,397,131

Investment in subsidiaries	8,337,749			—			—			(8,337,749		)	—
Intercompany receivables	(1,195,860		)	(212,975		)	1,408,835			—			—
Note receivable from Arch Western	675,000			—			—			(675,000		)	—
Other	189,359			783,012			15,909			—			988,280
Total other assets	8,006,248			570,037			1,424,744			(9,012,749		)	988,280
Total assets	$	8,586,430		$	6,805,601		$	3,577,870		$	(9,015,963	)	$	9,953,938

Liabilities and Stockholders’ Equity
Accounts payable	$	29,584		$	157,281		$	129,804		$	—		$	316,669
Accrued expenses and other current liabilities	64,302			157,977			148,818			(3,214		)	367,883
Current maturities of debt and short-term borrowings	20,100			860			90,300			—			111,260
Total current liabilities	113,986			316,118			368,922			(3,214		)	795,812
Long-term debt	4,462,255			2,396			(300		)				4,464,351
Note payable to Arch Coal	—			—			675,000			(675,000		)	—
Asset retirement obligations	776			153,423			270,090			—			424,289
Accrued pension benefits	22,737			3,781			22,522			—			49,040
Accrued postretirement benefits other than pension	12,697			6,272			23,059			—			42,028
Accrued workers’ compensation	27,675			47,780			6,917			—			82,372
Deferred income taxes	653,534			76,961			—			—			730,495
Other noncurrent liabilities	150,350			41,016			31,765			—			223,131
Total liabilities	5,444,010			647,747			1,397,975			(678,214		)	6,811,518
Redeemable noncontrolling interest	17,500			—			—			—			17,500
Stockholders’ equity	3,124,920			6,157,854			2,179,895			(8,337,749		)	3,124,920
Total liabilities and stockholders’ equity	$	8,586,430		$	6,805,601		$	3,577,870		$	(9,015,963	)	$	9,953,938

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Condensed Consolidating Balance Sheets

December 31, 2011

				Guarantor		Non-Guarantor
	Parent/Issuer			Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Cash and cash equivalents	$	61,375		$	332	$	76,442	$	—		$	138,149
Restricted cash	10,322			—		—		—			10,322
Receivables	65,187			22,037		383,572		(1,617		)	469,179
Inventories	—			207,050		170,440		—			377,490
Other	81,732			83,122		22,780		—			187,634
Total current assets	218,616			312,541		653,234		(1,617		)	1,182,774
Property, plant and equipment, net	21,241			6,403,658		1,524,251		—			7,949,150

Investment in subsidiaries	8,805,731			—		—		(8,805,731		)	—
Intercompany receivables	(1,457,864		)	7,010		1,450,854		—			—
Note receivable from Arch Western	225,000			—		—		(225,000		)	—
Other	184,266			884,613		13,156		—			1,082,035
Total other assets	7,757,133			891,623		1,464,010		(9,030,731		)	1,082,035
Total assets	$	7,996,990		$	7,607,822	$	3,641,495	$	(9,032,348	)	$	10,213,959

Liabilities and Stockholders’ Equity
Accounts payable	$	25,409		$	175,196	$	183,177	$	—		$	383,782
Accrued expenses and other current liabilities	75,133			115,685		166,834		(1,617		)	356,035
Current maturities of debt and short-term borrowings	172,564			1,987		106,300		—			280,851
Total current liabilities	273,106			292,868		456,311		(1,617		)	1,020,668
Long-term debt	3,308,674			2,652		450,971					3,762,297
Note payable to Arch Coal	—			—		225,000		(225,000		)	—
Asset retirement obligations	877			140,861		305,046		—			446,784
Accrued pension benefits	19,198			4,203		24,843		—			48,244
Accrued postretirement benefits other than pension	13,843			6,271		22,195		—			42,309
Accrued workers’ compensation	17,272			48,111		6,565		—			71,948
Deferred income taxes	621,483			355,270		—		—			976,753
Other noncurrent liabilities	152,963			64,795		37,624		—			255,382
Total liabilities	4,407,416			915,031		1,528,555		(226,617		)	6,624,385
Redeemable noncontrolling interest	11,534			—		—		—			11,534
Stockholders’ equity	3,578,040			6,692,791		2,112,940		(8,805,731		)	3,578,040
Total liabilities and stockholders’ equity	$	7,996,990		$	7,607,822	$	3,641,495	$	(9,032,348	)	$	10,213,959

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Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2012

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)

Cash provided by (used in) operating activities	$	(139,288	)	$	221,019		$	13,577		$	—		$	95,308
Investing Activities
Change in restricted cash	4,582			—			—			—			4,582
Capital expenditures	(3,973		)	(160,423		)	(37,677		)	—			(202,073		)
Proceeds from dispositions of property, plant and equipment	—			985			21,566			—			22,551
Purchases of investments and advances to affiliates	(3,683		)	(6,992		)	—			1,383			(9,292		)
Additions to prepaid royalties	—			(5,187		)	(3,447		)	—			(8,634		)
Cash used in investing activities	(3,074		)	(171,617		)	(19,558		)	1,383			(192,866		)
Financing Activities
Contributions from parent	—			1,383						(1,383		)	—
Proceeds from term note	1,386,000			—			—			—			1,386,000
Payments to retire debt	—			(1,383		)	(451,271		)	—			(452,654		)
Net decrease in borrowings under lines of credit and commercial paper program	(391,300		)	—			—			—			(391,300		)
Net payments on other debt	(11,164		)	—			—			—			(11,164		)
Debt financing costs	(34,335		)	—			(46		)	—			(34,381		)
Dividends paid	(29,696		)	—			—			—			(29,696		)
Issuance of common stock under incentive plans	5,131			—			—			—			5,131
Transactions with affiliates, net	(442,951		)	(49,374		)	492,325			—			—
Cash provided by (used in) financing activities	481,685			(49,374		)	41,008			(1,383		)	471,936
Increase in cash and cash equivalents	339,323			28			35,027			—			374,378
Cash and cash equivalents, beginning of period	61,375			332			76,442			—			138,149
Cash and cash equivalents, end of period	$	400,698		$	360		$	111,469		$	—		$	512,527

Table of Contents

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2011

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)

Cash provided by (used in) operating activities	$	(109,358	)	$	278,596		$	144,962		$	—		$	314,200
Investing Activities
Acquisition of ICG, net of cash acquired	(2,910,380		)	—			—			—			(2,910,380		)
Change in restricted cash	(74,814		)	—			—			—			(74,814		)
Capital expenditures	(2,459		)	(65,927		)	(39,339		)	—			(107,725		)
Proceeds from dispositions of property, plant and equipment	—			1,315			96			—			1,411
Purchases of investments and advances to affiliates	(725,938		)	(27,058		)	—			714,937			(38,059		)
Additions to prepaid royalties	—			(21,440		)	(3,772		)	—			(25,212		)
Cash used in investing activities	(3,713,591		)	(113,110		)	(43,015		)	714,937			(3,154,779		)
Financing Activities
Proceeds from the issuance of senior notes	2,000,000			—			—			—			2,000,000
Proceeds from the issuance of common stock, net	1,249,407			—			—			—			1,249,407
Contributions from parent	—			714,937			—			(714,937		)	—
Payments to retire debt	—			(307,984		)	—			—			(307,984		)
Change in restricted cash	—			(260,663		)	—			—			(260,663		)
Net (increase) decrease in borrowings under lines of credit and commercial paper program	360,000			—			(56,904		)	—			303,096
Net payments on other debt	(8,845		)	—			—			—			(8,845		)
Debt financing costs	(112,326		)	—			(8		)	—			(112,334		)
Dividends paid	(34,192		)	—			—			—			(34,192		)
Issuance of common stock under incentive plans	846			—			—			—			846
Transactions with affiliates, net	363,696			(309,706		)	(53,990		)	—			—
Cash provided by (used in) financing activities	3,818,586			(163,416		)	(110,902		)	(714,937		)	2,829,331
Increase (decrease) in cash and cash equivalents	(4,363		)	2,070			(8,955		)	—			(11,248		)
Cash and cash equivalents, beginning of period	13,713			64			79,816			—			93,593
Cash and cash equivalents, end of period	$	9,350		$	2,134		$	70,861		$	—		$	82,345

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

Weakness in the U.S. thermal coal markets continued to impact our results in the second quarter of 2012, resulting from an increased build in power generator coal stockpiles year to date. U.S. coal consumption for power generation declined 75 million tons through the first half of 2012, and could decline by more than 100 million tons for the full year. Contributing to domestic thermal market weakness during the first half of 2012 was increased substitution of gas for coal at power generators, driven by decade-low natural gas prices, and unseasonably warm weather in the winter of 2012.

We expect that thermal coal exports will somewhat offset the weakness in domestic markets. We have increased export volumes over 2011 levels in the first half of 2012, exporting 7 million tons. China and India remain on pace to surpass record coal import levels set in 2011, although we believe a softening of the pace will occur in the second half of 2012.

Metallurgical coal demand has been affected by weakening in the global and U.S. steel mill capacity utilization, due to slowing economic growth, particularly from the uncertainty in Europe resulting from the sovereign debt crisis, which is affecting consumer demand and reducing steel production and raw material consumption.

In response to these market conditions, we curtailed our production expectations for 2012 and we have taken steps to increase operational efficiency and productivity. In total, we expect to reduce annual volumes by approximately 25 million tons in 2012 compared to originally planned levels. In the Powder River Basin, we have idled three draglines, with one being redeployed into reclamation efforts, limited railcar loadings from the West loadout at the Black Thunder mine, and reduced labor costs through scheduling changes and attrition. In Appalachia, we closed five higher-cost thermal operations and further curtailed production at other thermal mines. We are also taking steps to control costs by eliminating discretionary spending, reducing headcount and consolidating operations. We are controlling capital spending at thermal coal mines and controlling maintenance capital, but we are proceeding with metallurgical coal development projects, namely the Leer mine (previously known as the Tygart mine) in Appalachia, and supporting efforts to expand our coal exporting network.

More recently, domestic thermal coal demand trends have been more favorable. The summer weather has been hot in much of the U.S. and natural gas prices have risen. In addition, increased domestic supply reductions have occurred. Mine Safety and Health Administration data released to date suggests that second quarter 2012 U.S. coal production totaled approximately 241 million tons, a decline of 26 million tons versus the first quarter.

Results of Operations

Items Affecting Comparability of Results

The comparability of our operating results between the three and six months ended June 30, 2012 and 2011 is affected by the acquisition of ICG on June 15, 2011. Coal sales revenues attributed to acquired ICG operations were $272.4 million in the second quarter of 2012 and $510.6 million in the first half of 2012, compared with $48.4 million in 2011.

Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011

Summary. Our results during the second quarter of 2012 when compared to the second quarter of 2011 were impacted substantially by our mine closures and production cutbacks in response to weak market conditions.

Revenues. Our revenues consist of coal sales and revenues from our ADDCAR subsidiary acquired with ICG. The following table summarizes information about coal sales during the three months ended June 30, 2012 and compares it with the information for the three months ended June 30, 2011:

Table of Contents

	Three Months Ended June 30,				Increase (Decrease)
	2012		2011		Amount			%
	(Amounts in thousands, except per ton data and percentages)

Coal sales	$	1,048,221	$	985,087	$	63,134		6.4	%
Tons sold	31,514		37,126		(5,612		)	(15.1	)%
Coal sales realization per ton sold	$	33.26	$	26.53	$	6.73		25.4	%

Coal sales increased in the second quarter of 2012 from the second quarter of 2011, due to an increase in the overall average price per ton sold. Higher pricing was partially the result of an increase in export shipments, some of which are priced on a delivered basis, increasing the sales price, but also increasing our transportation costs (see cost of sales discussion below). In addition, an increase in higher-priced metallurgical coal sales volumes from the contribution of the ICG operations, as well as the impact of changes in regional mix improved our average coal sales realizations. These factors were offset by the impact of lower thermal coal demand in all operating segments. We have provided more information about the tons sold and the coal sales realizations per ton by operating segment under the heading “Operating segment results”.

Costs, expenses and other. The following table summarizes costs, expenses and other components of operating income for the three months ended June 30, 2012 and compares it with the information for the three months ended June 30, 2011:

	Three Months Ended June 30,						Increase (Decrease) in Net Income
	2012			2011			Amount			%
	(Amounts in thousands, except percentages)
Cost of sales	$	881,259		$	715,590		$	(165,669	)	(23.2	)%
Depreciation, depletion and amortization	132,868			97,236			(35,632		)	(36.6	)%
Amortization of acquired sales contracts, net	(4,451		)	1,262			5,713			452.7	%
Mine closure and asset impairment costs	525,762			—			(525,762		)
Goodwill impairment	115,791			—			(115,791		)
Selling, general and administrative expenses	35,178			29,040			(6,138		)	(21.1	)%
Change in fair value of coal derivatives and coal trading activities, net	(32,054		)	2,672			34,726
Acquisition and transition costs related to ICG	—			48,666			48,666			100.0	%
Other operating income, net	(1,831		)	(4,292		)	(2,461		)	57.3	%
	$	1,652,522		$	890,174		$	(762,348	)	(85.6	)%

Cost of coal sales. Our cost of sales increased in the second quarter of 2012 from the second quarter of 2011 primarily from an increase in transportation costs as a result of the increase in export shipments and the impact of the acquisition of the ICG operations. We have provided more information about the performance and profitability of our operating segments under the heading “Operating segment results”.

Depreciation, depletion and amortization. When compared with the second quarter of 2011, higher depreciation, depletion and amortization costs in 2012 resulted primarily from the acquired ICG operations, partially offset by the impact of lower depreciation and amortization on assets amortized or depleted on the basis of tons produced, processed, or sold.

Amortization of acquired sales contracts, net. The fair values of acquired sales contracts are amortized over the tons of coal shipped during the term of the contracts. In the second quarter of 2011, amortization income related to the contracts we acquired with the ICG operations was offset by amortization expense related to contracts we acquired in 2009 with the Jacobs Ranch operations in the PRB.

Mine closure and asset impairment costs. The following costs are reflected in the line “Mine closure and asset impairment costs” for the three months ended June 30, 2012 relating to the closed Appalachia operations:

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	In millions
Parts and supplies inventory writedown	$	2.6
Impairment of property, plant and equipment	95.6
Impairment of coal properties and deferred development costs	403.3
Royalty obligations	11.6
Employee termination benefits	12.3
Pension, postretirement and occupational disease curtailment charge, net	0.4
	$	525.8

The majority of the employee termination costs will be paid in the third quarter. The operations had ceased production prior to June 30, 2012, and will incur minimal ongoing annual maintenance costs customary with idling operations. The terms of customer contracts will be fulfilled by other operations.

Goodwill Impairment. We recorded a preliminary write-off of our goodwill related to our Black Thunder mining complex during the second quarter of 2012 due to expectations of lower thermal coal demand and its impact on near-term sales volumes and pricing. The write-off will not be final until an allocation of fair value to individual and assets and liabilities is complete. See further discussion in Note 5 to the condensed consolidated financial statements in “Part I, Item 1. Financial Statements” of this Form 10-Q. Further weakening of coal markets, particularly metallurgical coal volumes and pricing could affect the value of goodwill allocated to complexes in Appalachia.

Selling, general and administrative expenses. Selling, general and administrative expenses increased compared with the second quarter of 2011. Our growth in the Appalachia operating region and through sales offices in Singapore and London has resulted in an increase in salary and benefit costs, travel costs, and other professional service fees. In addition, the change in our net obligation under the deferred compensation plan resulted in an increase in expense of $2.1 million. These were partially offset by a decrease in incentive compensation costs of $1.2 million.

Change in fair value of coal derivatives and coal trading activities, net. The gains reflected in the second quarter of 2012 relate primarily to API-2 positions entered into to manage price risk on physical export sales into Europe. These positions are not accounted for as hedges, so the change in the positions’ fair value prior to settlement is reflected in the results of operations.

Other operating income, net. When compared with the three months ended June 30, 2011, other operating income, net decreased in the three months ended June 30, 2012 primarily due to the following:

	In millions
Coal derivative settlements — risk management, non-hedges	$	8.5
Unrealized mark to market losses on diesel risk management program	(14.7		)
Commercial related income, net	3.4
Income from equity method investees	(1.8		)

We enter into derivative positions to manage price risk with respect to future coal sales and diesel purchases. Because we do not apply hedge accounting to these positions, the gains and losses from these activities may not be tied to the underlying activity in the statement of operations as if they qualified for hedge accounting.

Operating segment results. The following table shows results by operating segment for three months ended June 30, 2012 and compares it with the information for the three months ended June 30, 2011:

	Three Months Ended June 30,				Increase (Decrease)
	2012		2011		$			%
Powder River Basin
Tons sold (in thousands)	21,833		28,042		(6,209		)	(22.1	)%
Coal sales realization per ton sold(1)	$	13.65	$	13.70	$	(0.05	)	(0.4	)%
Operating margin per ton sold(2)	$	0.94	$	1.24	$	(0.30	)	(24.2	)%
Adjusted EBITDA(3) (in thousands)	$	59,564	$	82,248	$	(22,684	)	(27.6	)%
Appalachia
Tons sold (in thousands)	5,202		4,269		933			21.9	%
Coal sales realization per ton sold(1)	$	85.45	$	86.94	$	(1.49	)	(1.7	)%
Operating margin per ton sold(2)	$	4.53	$	21.73	$	(17.20	)	(79.2	)%
Adjusted EBITDA(3) (in thousands)	$	135,961	$	123,653	$	12,308		10.0	%
Western Bituminous
Tons sold (in thousands)	3,985		4,722		(737		)	(15.6	)%
Coal sales realization per ton sold(1)	$	33.35	$	35.59	$	(2.24	)	(6.3	)%
Operating margin per ton sold(2)	$	4.47	$	9.16	$	(4.69	)	(51.2	)%
Adjusted EBITDA(3) (in thousands)	$	36,589	$	65,772	$	(29,183	)	(44.4	)%

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(1) Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. In the second quarter of 2012, transportation costs per ton were $1.12 for the Powder River Basin, $12.37 for Appalachia and $17.77 for the Western Bituminous region. In the second quarter of 2011, transportation costs per ton were $0.26 for the Powder River Basin, $6.95 for Appalachia and $4.47 for the Western Bituminous region.

(2) Operating margin per ton sold is calculated as coal sales revenues less cost of coal sales, depreciation, depletion and amortization and sales contract amortization divided by tons sold.

(3) 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. Segment Adjusted EBITDA is reconciled to net income at the end of this “Results of Operations” section.

Powder River Basin — Segment Adjusted EBITDA decreased in the second quarter of 2012 when compared to the second quarter of 2011 primarily due to the lower sales volumes in the Powder River Basin from our production cutbacks in response to the market conditions discussed previously. Per-ton costs were higher due to the lower production levels and higher diesel costs, which offset the impact of lower overall spending. Our total production costs were down in the second quarter of 2012 due to the redeployment of employees and equipment to significant reclamation activities performed during the quarter, reducing the number of contractors, and lower maintenance costs resulting from the idling of equipment. We expect this current cycle of reclamation to be largely completed in the third quarter.

Appalachia — Segment Adjusted EBITDA increased slightly from the second quarter of 2011 primarily as a result of an increase in the volumes and pricing of metallurgical-quality coal sold. We sold 1.9 million tons of metallurgical-quality coal in the second quarter of 2012 compared to 1.7 million tons in the second quarter of 2011. The volume contributions from the acquired ICG operations were partially offset by the impact of unfavorable market conditions, and the related production cutbacks and mine closings. Per-ton realizations in the second quarter of 2012 were slightly lower due to a lower percentage of metallurgical coal sales volumes in relation to total sales volumes. In addition, higher per-ton costs were impacted by higher cost production from operations acquired from ICG, lower production levels at other operations, and inflation in labor and commodity costs. Mine closure and asset impairment costs are excluded from the per-ton costs and operating margins above.

Western Bituminous —Segment Adjusted EBITDA decreased from the second quarter of 2011 due to lower sales volumes, due to weaker demand in the region. Longwall moves during the quarter were extended in response to market conditions. The Skyline mine will recommence longwall mining in October and the Dugout mine will begin mining its final longwall panel of the current seam in August. Future production decisions will be based on market conditions.

Net interest expense. The increase in interest expense during the second quarter of 2012 when compared with the second quarter of 2011 is the result of the ICG acquisition financing in 2011 and the refinancing transactions in the second quarter of 2012, discussed in the “Liquidity” section.

Other nonoperating expense. Amounts reported as nonoperating consist of expenses resulting from financing activities, other than interest costs. During the second quarter of 2012, nonoperating expense consists of the net loss resulting from the early retirement of $450.0 million principal amount of our subsidiary’s 6 ¾% Senior Notes due 2013. During 2011, nonoperating expense represents financing related costs of the ICG acquisition, including the cost to maintain a bridge financing facility, which was not utilized. See further description of financing activities in “Liquidity”.

Income taxes. Our effective income tax rate is sensitive to changes in and the relationship between annual profitability and the deduction for percentage depletion. The income tax benefit in the second quarter of 2012

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reflects our pretax loss combined with percentage depletion deductions, offset by an increase in our valuation allowance against state tax loss carryforwards of approximately $8.0 million.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Summary. Our results during first half of 2012 when compared to the first half of 2011 were impacted substantially by our production cutbacks and mine closures in response to weak market conditions and the impact of the ICG acquisition.

Revenues. Our revenues consist of coal sales and revenues from our ADDCAR subsidiary acquired with ICG. The following table summarizes information about coal sales during the six months ended June 30, 2012 and compares it with the information for the six months ended June 30, 2011:

	Six Months Ended June 30,				Increase (Decrease)
	2012		2011		Amount			%
	(Amounts in thousands, except per ton data and percentages)
Coal sales	$	2,085,361	$	1,858,466	$	226,895		12.2	%
Tons sold	67,174		73,734		(6,560		)	(8.9	)%
Coal sales realization per ton sold	$	31.04	$	25.21	$	5.84		23.2	%

Coal sales increased in the first half of 2012 from the first half of 2011, due to an increase in the overall average price per ton sold, the result of improved pricing on metallurgical-quality coal sold and the increase in export sales, as well as the contribution from the ICG operations, including higher-priced metallurgical coal sales volumes, as well as the impact of changes in regional mix on our average coal sales realization. These factors were offset by lower thermal coal demand in all operating segments. We have provided more information about the tons sold and the coal sales realizations per ton by operating segment under the heading “Operating segment results”.

Costs, expenses and other. The following table summarizes costs, expenses and other components of operating income for the six months ended June 30, 2012 and compares it with the information for the six months ended June 30, 2011:

	Six Months Ended June 30,						Increase (Decrease) in Net Income
	2012			2011			Amount			%
	(Amounts in thousands, except percentages)
Cost of sales	$	1,732,130		$	1,369,274		$	(362,856	)	(26.5	)%
Depreciation, depletion and amortization	272,834			180,773			(92,061		)	(50.9	)%
Amortization of acquired sales contracts, net	(18,468		)	7,206			25,674			356.3	%
Mine closure and asset impairment costs	525,762			—			(525,762		)
Goodwill impairment	115,791			—			(115,791		)
Selling, general and administrative expenses	66,039			59,474			(6,565		)	(11.0	)%
Change in fair value of coal derivatives and coal trading activities, net	(35,667		)	888			36,555
Acquisition and transition costs related to ICG	—			48,666			48,666			100.0	%

Other operating income, net	(20,329		)	(5,407		)	14,922			(276.0	)%
	$	2,638,092		$	1,660,874		$	(977,218	)	(58.8	)%

Cost of coal sales. Our cost of sales increased in the first half of 2012 from the first half of 2011 primarily from the impact of the acquisition of the ICG operations and an increase in transportation costs as a result of the increase in export shipments. We have provided more information about the performance and profitability of our operating segments under the heading “Operating segment results”.

Depreciation, depletion and amortization. When compared with the first half of 2011, higher depreciation, depletion and amortization costs in 2012 resulted primarily from the acquired ICG operations, partially offset by the impact of lower depreciation and amortization on assets amortized or depleted on the basis of tons produced, processed, or sold.

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Amortization of acquired sales contracts, net. The fair values of acquired sales contracts are amortized over the tons of coal shipped during the term of the contracts. In the first half of 2011, amortization expense related to contracts we acquired in 2009 with the Jacobs Ranch operations in the PRB was offset by amortization income related to the contracts we acquired with the ICG operations.

Mine closure and asset impairment costs and goodwill impairment. These items are discussed in the results of operations for the three months ended June 30, 2012.

Selling, general and administrative expenses. Selling, general and administrative expenses were essentially flat when compared with the first half of 2011. Our growth in 2012 has resulted in an increase in salary and benefit costs, travel costs, and other professional service fees. These were offset by a decrease in incentive compensation costs of $3.8 million.

Change in fair value of coal derivatives and coal trading activities, net. The gains reflected in the first half of 2012 relate primarily to API-2 positions entered into to manage price risk on physical export sales into Europe. These positions are not accounted for as hedges, so the change in the positions’ fair value prior to settlement is reflected in the results of operations.

Other operating income, net. When compared with the six months ended June 30, 2011, other operating income, net increased in the six months ended June 30, 2012 primarily due to the following:

	In millions
Gain on sale of non-core assets	$	11.6
Coal derivative settlements — risk management, non-hedges	11.7
Unrealized mark to market losses on diesel risk management program	(14.4		)
Commercial related income, net	4.5
Income from equity method investees	(1.8		)

Operating segment results. The following table shows results by operating segment for six months ended June 30, 2012 and compares it with the information for the six months ended June 30, 2011:

	Six Months Ended June 30,				Increase (Decrease)
	2012		2011		$			%
Powder River Basin
Tons sold (in thousands)	49,048		56,872		(7,824		)	(13.8	)%
Coal sales realization per ton sold(1)	$	13.77	$	13.60	$	0.17		1.3	%
Operating margin per ton sold(2)	$	1.05	$	1.42	$	(0.37	)	(26.1	)%
Adjusted EBITDA(3) (in thousands)	$	133,747	$	175,964	$	(42,217	)	(24.0	)%
Appalachia
Tons sold (in thousands)	9,867		7,860		2,007			25.5	%
Coal sales realization per ton sold(1)	$	86.98	$	84.20	$	2.78		3.3	%
Operating margin per ton sold(2)	$	3.53	$	19.12	$	(15.59	)	(81.5	)%
Adjusted EBITDA(3) (in thousands)	$	219,201	$	201,639	$	17,562		8.7	%
Western Bituminous
Tons sold (in thousands)	7,246		8,908		(1,662		)	(18.7	)%
Coal sales realization per ton sold(1)	$	35.27	$	35.25	$	0.02		0.1	%
Operating margin per ton sold(2)	$	6.86	$	7.84	$	(0.98	)	(12.5	)%
Adjusted EBITDA(3) (in thousands)	$	87,409	$	113,192	$	(25,783	)	(22.8	)%

(1) Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. In 2012, transportation costs per ton were $0.98 for the Powder River Basin, $12.34 for Appalachia and $12.93 for the Western Bituminous region. In 2011, transportation costs per ton were $0.19 for the Powder River Basin, $8.06 for Appalachia and $6.39 for the Western Bituminous region.

(2) Operating margin per ton sold is calculated as coal sales revenues less cost of coal sales, depreciation, depletion and amortization and sales contract amortization divided by tons sold.

Powder River Basin — Segment Adjusted EBITDA decreased in the first half of 2012 when compared to the first half of 2011, due to the lower sales volumes in the Powder River Basin from the production cutbacks in

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response to market conditions. Per-ton costs were also higher due to the lower production levels, which offset the impact of slightly higher per-ton selling prices.

Appalachia — Segment Adjusted EBITDA increased slightly from the first half of 2011 primarily as a result of an increase in the volumes and pricing of metallurgical-quality coal sold. We sold 3.5 million tons of metallurgical-quality coal in the first half of 2012 compared to 3.1 million tons in the first half of 2011. The volume contributions from the acquired ICG operations were offset by the impact of unfavorable market conditions. The benefit from higher per-ton realizations, net of sales sensitive costs, in the first half of 2012 was offset by the impacts of lower production levels and the extended longwall move at the Mountain Laurel complex in the first quarter of 2012, which resulted in an increase in our average per-ton production costs. Mine closure and asset impairment costs are excluded from the per-ton costs and operating margins above.

Western Bituminous — Segment Adjusted EBITDA decreased from the second quarter of 2011 due to lower sales volumes, due to weaker demand in the region. Longwall moves during the quarter were extended in response to market conditions. The Skyline mine will recommence longwall mining in October and the Dugout mine will begin mining its final longwall panel of the current seam in August. Future production decisions will be based on market conditions.

Reconciliation of Segment Adjusted EBITDA to Net Income

The discussion in “Results of Operations” includes references to our Adjusted EBITDA results. 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.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Reported Segment Adjusted EBITDA	$	232,114		$	271,673		$	440,357		$	490,795
Corporate and other(1)	(51,193		)	(23,836		)	(79,609		)	(51,512		)
Adjusted EBITDA	180,921			247,837			360,748			439,283
Depreciation, depletion and amortization	(132,868		)	(97,236		)	(272,834		)	(180,773		)
Amortization of acquired sales contracts, net	4,451			(1,262		)	18,468			(7,206		)
Acquisition and transition costs	—			(54,303		)	—			(54,303		)
Mine closure and asset impairment costs	(525,762		)	—			(525,762		)	—
Goodwill impairment	(115,791		)	—			(115,791		)	—
Other nonoperating expenses	(19,042		)	(49,740		)	(19,042		)	(49,740		)
Net interest expense	(77,640		)	(41,494		)	(151,391		)	(75,328		)
(Provision for) benefit from income taxes	250,242			2,510			271,321			(10,020		)
Net income (loss) attributable to Arch Coal	$	(435,489	)	$	6,312		$	(434,283	)	$	61,913

(1) Corporate and other Adjusted EBITDA includes primarily selling, general and administrative expenses, income from our equity investments, certain changes in fair value of coal derivatives and coal trading activities, and net gains on asset sales.

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Liquidity and Capital Resources

Our primary sources of cash are coal sales to customers, borrowings under our credit facilities and other financing arrangements, and debt and equity offerings related to significant transactions. Excluding any significant mineral reserve acquisitions, we generally satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations or borrowings under our lines of credit. The borrowings under these arrangements are classified as current if the underlying credit facilities expire within one year or if, based on cash projections and management plans, we do not have the intent to replace them on a long-term basis. Such plans are subject to change based on our cash needs.

On May 16, 2012, we entered into an amendment to our senior secured revolving credit facility that amended certain financial maintenance covenants, suspending our compliance with the debt-to-EBITDA ratio, easing other financial covenants through September 2014 and adding defined minimum EBITDA targets. The maximum borrowing capacity of the revolving credit facility was reduced from $2 billion to $600 million. In conjunction with the amendment, we borrowed $1.4 billion under a six-year secured term loan facility, issued at a 1% discount. The term loan contains no financial maintenance covenants, is prepayable and is secured by the same assets as borrowings under the revolving credit facility. Quarterly principal payments of $3.5 million are due beginning in September 2012, plus interest at a rate of the greater of Libor or 1.25%, plus 450 basis points. The proceeds of the term loan were used to retire all outstanding borrowings under the revolving credit facility and the outstanding $450.0 million principal amount of 6 ¾% Senior Notes due 2013 issued by Arch Western Finance, LLC (“Arch Western Finance”), the Company’s indirect subsidiary.

On May 16, 2012, Arch Western Finance accepted for purchase an aggregate of approximately $304.0 million aggregate principal amount of its 6 ¾% Senior Notes due 2013 in an initial settlement pursuant to the terms of its tender offer and consent solicitation, which commenced on May 1, 2012, and called for redemption all of the remaining notes outstanding after the completion of the tender offer. The consideration for each $1,000 of principal purchased under the tender offer and consent solicitation was $1,002.50, for a total purchase consideration of $304.8 million. On May 30, 2012, the remaining notes with an outstanding principal amount of $146.0 million were redeemed at par value.

We believe that cash generated from operations, cash on hand and borrowings under our credit facilities or other financing arrangements will be sufficient to meet working capital requirements and anticipated capital expenditures. As a result of the refinancing activities discussed previously, we have no significant debt maturities until 2016. Our ability to satisfy debt service obligations, to fund planned capital expenditures, to make acquisitions, to repurchase our common shares and to pay dividends will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.

At June 30, 2012, we had cash on hand of $512.5 million and availability of approximately $345.0 million under our lines of credit.

	June 30,	December 31,
	2012	2011
	(In thousands)
Indebtedness to banks under credit facilities	90,000	481,300
Term loan ($1.4 billion face value) due 2018	1,386,292	0
6.75% senior notes ($450.0 million face value) due July 1, 2013	—	450,971
8.75% senior notes ($600.0 million face value) due August 1, 2016	589,963	588,974
7.00% senior notes due June 15, 2019 at par	1,000,000	1,000,000
7.25% senior notes due October 1, 2020 at par	500,000	500,000
7.25% senior notes due June 15, 2021 at par	1,000,000	1,000,000
Other	9,356	21,903
	4,575,611	4,043,148
Less current maturities of debt and short-term borrowings	111,260	280,851
Long-term debt	4,464,351	$	3,762,297

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The Company’s average borrowing level under lines of credit and short term borrowings was approximately $297 million and $131 million for the three months ended June 30, 2012 and 2011, respectively and approximately $375 million and $100 million for the six months ended June 30, 2012 and 2011, respectively.

The following is a summary of cash provided by or used in each of the indicated types of activities during the six months ended June 30, 2012 and 2011.

	Six Months Ended June 30,
	2012			2011
	(Dollars in thousands)
Cash provided by (used in):
Operating activities	$	95,308		$	314,200
Investing activities	(192,866		)	(3,154,779		)
Financing activities	471,936			2,829,331

Cash provided by operating activities decreased in the first six months of 2012 compared to 2011, driven by lower operating income as well as an increase in inventories as a result of the weak market conditions.

We used less cash in investing activities in the first six months of 2012 compared to the amount used in 2011, primarily due to the acquisition of ICG in 2011, as well as a decrease in investments and prepaid royalties in 2012 . This was offset by an increase during the six months ended June 30, 2012 in capital expenditures of approximately $94 million when compared with 2011. We spent approximately $93 million during the first half 2012 on the development of the Leer mine. We have been able to reduce capital spending by deploying equipment from our idled operations into active ones, and into development projects like the Leer mine.

Cash provided by financing activities was approximately $472 million in the first six months of 2012, compared to approximately $2.8 billion in 2011. In 2011, the proceeds from the issuance of $2 million in senior notes in 2011 and an increase in shares outstanding as a result of the shares issued in 2011were used to finance the ICG acquisition. In 2012, the proceeds from the $1.4 billion term loan received in conjunction with the refinancing discussed previously were used, in part to retire the remaining outstanding senior secured notes due in 2013 and outstanding borrowings under lines of credit.

Ratio of Earnings to Fixed Charges

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

	Six Months Ended June 30,
	2012		2011
Ratio of earnings to combined fixed charges and preference dividends(1)	N/A	(2)	1.61	x

(1) Earnings consist of income from 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 ratio calculation were $547.0 million and total fixed charges were $165.6 million for the six months ended June 30, 2012

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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 the fluctuations in the market pricing. We expect to sell a total of approximately 7.5 million tons of metallurgical coal in 2012.

At June 30, 2012, our commitments for 2012 and 2013 are as follows:

	2012			2013
	Tons	$ per ton		Tons	$ per ton

Powder River Basin
Committed, Priced	101.3	$	13.92	60.6	$	14.47
Committed, Unpriced	2.0			12.6

Western Bituminous
Committed, Priced	14.3	$	35.5	10.4	$	39.55
Committed, Unpriced	0.5			—

Appalachia
Committed, Priced Thermal	10.3	$	67.44	4.3	$	64.01
Committed, Unpriced Thermal	0.3			0.3
Committed, Priced Metallurgical	6.6	$	121.90	0.2	$	112.95
Committed, Unpriced Metallurgical	0.4			0.2

Illinois Basin
Committed, Priced	2.3	$	41.62	1.8	$	44.15

We are exposed to commodity price risk in our coal trading activities, which represents the potential future loss that could be caused by an adverse change in the market value of coal. Our coal trading portfolio included forward, swap and put and call option contracts at June 30, 2012. The estimated future realization of the value of the trading portfolio is $0.6 million of gains in the remainder of 2012 and $2.1 million of losses in 2013.

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. 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. 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 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.

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During the six months ended June 30, 2012, VaR for our coal trading positions that are recorded at fair value through earnings ranged from under $0.1 million to $1.0 million. The linear mean of each daily VaR was $0.5 million. The final VaR at June 30, 2012 was less than $0.1 million.

We are exposed to fluctuations in the fair value of coal derivatives that we enter into to manage the price risk related to future coal sales, but for which we do not elect hedge accounting. Any gains or losses on these derivative instruments would be offset in the pricing of the physical coal sale. During the six months ended June 30, 2012, VaR for our risk management positions that are recorded at fair value through earnings ranged from under $1.5 million to $4.2 million. The linear mean of each daily VaR was $2.8 million. The final VaR at June 30, 2012 was $2.8 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 73 million to 78 million gallons of diesel fuel annually in our operations. We enter into forward physical purchase contracts, as well as purchased heating oil options, to reduce volatility in the price of diesel fuel for our operations. At June 30, 2012 the Company had protected the price of approximately 80% of its expected purchases for remainder of fiscal year 2012 and approximately 50% of our purchases for 2013, mostly through the use of the derivative instruments noted above. The heating oil options do not qualify for hedge accounting. A $0.25 per gallon decrease in the price of heating oil would not result in an increase in our expense related to the heating oil derivatives.

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At June 30, 2012, of our $4.1 billion principal amount of debt outstanding, approximately $1.5 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 result in an annualized increase in interest expense of $3.8 million, based on borrowing levels at June 30, 2012.

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Item 4. Controls and Procedures.

We performed an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2012. 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.

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.

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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 (the “EPA”) proposed action to deny Mingo Logan the right to use its Corps’ permit (as discussed below). The stay currently remains in effect.

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 has been 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” currently pending in federal court in Washington, DC. As described more fully below, the federal court in Washington, DC, by Memorandum and Opinion and separate Order, each dated March 23, 2012, 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. 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.

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.

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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 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, EPA filed a notice of appeal to the United States Court of Appeals for the District of Columbia Circuit. The Court entered a briefing schedule and the matter is pending the parties’ briefs.

Allegheny Energy Contract Matter

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

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

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. 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. Wolf Run and Hunter Ridge have filed an appeal bond in the amount of $124.9 million. Briefing is complete and oral argument was held on May 16, 2012. The matter is pending a decision by the Court.

Saratoga Class Action Matter

On January 7, 2008, Saratoga Advantage Trust (“Saratoga”) filed a class action lawsuit in the U.S. District Court for the Southern District of West Virginia against ICG and certain of its officers and directors seeking unspecified damages. The complaint asserts claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, based on alleged false and misleading statements in the registration statements filed in connection with ICG’s November 2005 reorganization and December 2005 public offering of common stock. In addition, the complaint challenges other of ICG’s public statements regarding its operating condition and safety record. On July 6, 2009, Saratoga filed an amended complaint asserting

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essentially the same claims but seeking to add an individual co-plaintiff. ICG has filed a motion to dismiss the amended complaint. In June 2011, ICG agreed to settle this matter for a total of $1.375 million. On August 1, 2011, the court issued its order preliminarily approving settlement and conducted a settlement fairness hearing on November 14, 2011. The matter is pending Court approval.

ICG Hazard

The Sierra Club, on December 3, 2010, filed a Notice of Intent (“NOI”) to sue ICG Hazard, LLC (“Hazard”) alleging violations of the Clean Water Act and the Surface Mining Control and Reclamation Act of 1977 at Hazard’s Thunder Ridge surface mine. The NOI, which was supplemented by a revised filing on February 24, 2011, claims that Hazard is discharging selenium and contributing to conductivity levels in the receiving streams in violation of state and federal regulations. On May 24, 2011, the Sierra Club sued Hazard in U.S. District Court for the Eastern District of Kentucky under the Citizens Suit provisions of the Clean Water Act and the Surface Mining Control and Reclamation Act seeking civil penalties, injunctive relief and attorneys’ fees. On February 17, 2012, ICG Hazard filed a motion for summary judgment. Also on February 17, 2012, the Sierra Club filed a competing motion for summary judgment. The matter is pending before the Court.

Kentucky Energy and Environment Cabinet

On December 3, 2010, the Kentucky Energy and Environment Cabinet (“Cabinet”) filed suit against Hazard, ICG Knott County, LLC, ICG East Kentucky, LLC and Powell Mountain Energy, LLC (collectively, “KY Operations”) alleging that the KY Operations failed to comply with the terms and conditions of the Kentucky Pollutant Discharge Elimination System (“KPDES”) permits issued by the Cabinet’s Division of Water to the KY Operations. Among the claims lodged by the Cabinet were allegations that contract water monitoring laboratories retained by the KY Operations did not adhere to the practices and procedures required for conducting KPDES monitoring, the contract laboratories failed to properly document and maintain records of the monitoring and the KY Operations submitted quarterly Discharge Monitoring Reports that sometimes contained inaccurate, incomplete and erroneous information. The KY Operations and the Cabinet entered a proposed Consent Judgment contemporaneously with the filing of the complaint that, if approved by the Franklin County (KY) Circuit Court, will require the KY Operations to pay a monetary penalty of $0.4 million, to prepare and implement a Corrective Action Plan that corrects the deficiencies in the respective KPDES monitoring programs, to identify the responsible corporate officers for each KPDES permit and to provide specific detailed information in support of the Discharge Monitoring Reports to be filed for the fourth quarter 2010 and first quarter 2011. Final resolution of this matter is pending approval by the court. On February 11, 2011, the court entered an order allowing certain anti-mining groups to intervene in the action to contest the validity of the Consent Judgment. The hearing on the entry of the Consent Judgment was held beginning August 30, 2011 and the matter is pending a decision from the court.

By letter dated June 28, 2011, Appalachian Voices, Inc., Waterkeeper Alliance, Inc., Kentuckians for the Commonwealth, Inc., Kentucky Riverkeeper, Inc., Ms. Pat Banks, Ms. Lanny Evans, Mr. Thomas H. Bonny, and Mr. Winston Merrill Combs (collectively, “Appalachian Voices”) filed a NOI to sue the KY Operations for alleged violations of the Clean Water Act. The NOI claims that ICG has violated and continues to violate effluent standards or limitations under the Clean Water Act in reference to KPDES Coal General Permit. The NOI also alleges a lack of diligent prosecution related to the lawsuit filed by the Kentucky Energy and Environment Cabinet (as referenced and described above). On October 25, 2011, Appalachian Voices sued the KY Operations in U.S. District Court for the Eastern District of Kentucky under the Citizens Suit provisions of the Clean Water Act seeking civil penalties, injunctive relief and attorneys’ fees.

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

In September 2006, our board of directors authorized a share repurchase program for the purchase of up to 14,000,000 shares of our common stock. There is no expiration date on the current authorization, and we have not made any decisions to suspend or cancel purchases under the program. As of June 30, 2012, there were 10,925,800 shares of our common stock available for purchase under this program. We did not purchase any shares of our common stock under this program during the quarter ended June 30, 2012. Based on the closing price of our common stock as reported on the New York Stock Exchange on July 31, 2012, the approximate dollar value of our common stock that may yet be purchased under this program was $78.8 million.

Item 4. Mine Safety Disclosures

The statement concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Quarterly Report on Form 10-Q for the period ended June 30, 2012.

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Item 6. Exhibits.

The following is a list of exhibits filed as part of this Quarterly Report on Form 10-Q:

4.1		Seventh Supplemental Indenture Governing 8.750% Senior Notes Due 2016.
4.2		Fifth Supplemental Indenture Governing 7¼% Senior Notes Due 2020.
4.3		Third Supplemental Indenture dated July 2, 2012.
4.4		Eighth Supplemental Indenture Governing 8.750% Senior Notes Due 2016.
4.5		Sixth Supplemental Indenture Governing 7¼% Senior Notes Due 2020.
4.6		Fourth Supplemental Indenture dated July 31, 2012.
10.1		First Amendment to Amended and Restated Credit Agreement, dated as of May 16, 2012, by and among Arch Coal, Inc., and each of the Guarantors, Lenders and PNC Bank, National Association, as administrative agent, party thereto (incorporated herein by reference to Exhibit 10.1 to the issuer’s Current Report on Form 8-K filed May 17, 2012).
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 Eaves.
31.2		Rule 13a-14(a)/15d-14(a) Certification of John T. Drexler.
32.1		Section 1350 Certification of John Eaves.
32.2		Section 1350 Certification of John T. Drexler.
95		Mine Safety Disclosure Exhibit
101		Interactive Data File

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Arch Coal, Inc.


	By:	/s/ John T. Drexler
		John T. Drexler
		Senior Vice President and Chief Financial Officer (On behalf of registrant and as Principal Financial Officer)

		August 9, 2012