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, 2014

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, 2014 there were 212,279,999 shares of the registrant’s common stock outstanding.

Table of Contents

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,
	2014			2013			2014			2013
	(Unaudited)
Revenues	$	713,776		$	766,332		$	1,449,747		$	1,503,702
Costs, expenses and other operating
Cost of sales (exclusive of items shown separately below)	622,137			656,198			1,308,451			1,305,941
Depreciation, depletion and amortization	102,464			111,085			206,887			221,278
Amortization of acquired sales contracts, net	(3,239		)	(2,209		)	(6,935		)	(5,019		)
Change in fair value of coal derivatives and coal trading activities, net	(2,992		)	(9,008		)	(2,078		)	(7,700		)
Asset impairment costs	1,512			20,482			1,512			20,482
Selling, general and administrative expenses	29,931			34,302			59,067			67,511
Other operating income, net	(232		)	(8,239		)	(8,230		)	(11,081		)
	749,581			802,611			1,558,674			1,591,412

Loss from operations	(35,805		)	(36,279		)	(108,927		)	(87,710		)
Interest expense, net
Interest expense	(97,960		)	(94,756		)	(194,431		)	(189,830		)
Interest and investment income	2,036			1,216			3,879			4,052
	(95,924		)	(93,540		)	(190,552		)	(185,778		)

Loss from continuing operations before income taxes	(131,729		)	(129,819		)	(299,479		)	(273,488		)
Benefit from income taxes	(34,869		)	(49,468		)	(78,480		)	(108,821		)
Loss from continuing operations	(96,860		)	(80,351		)	(220,999		)	(164,667		)
Income from discontinued operations, net of tax	—			8,145			—			22,412
Net loss	$	(96,860	)	$	(72,206	)	$	(220,999	)	$	(142,255	)

Losses per common share
Basic and diluted LPS - Loss from continuing operations	$	(0.46	)	$	(0.38	)	$	(1.04	)	$	(0.78	)

Basic and diluted LPS - Net loss	$	(0.46	)	$	(0.34	)	$	(1.04	)	$	(0.67	)

Basic and diluted weighted average shares outstanding	212,225			212,082			212,198			212,072

Dividends declared per common share	$	—		$	0.03		$	0.01		$	0.06

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

Table of Contents

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(Unaudited)
Net loss	$	(96,860	)	$	(72,206	)	$	(220,999	)	$	(142,255	)

Derivative instruments
Comprehensive income (loss) before tax	1,007			(391		)	778			(1,570		)
Income tax benefit (provision)	(362		)	143			(280		)	568
	645			(248		)	498			(1,002		)
Pension, postretirement and other post-employment benefits
Comprehensive income (loss) before tax	(2,269		)	1,750			(4,116		)	3,704
Income tax benefit (provision)	817			(630		)	1,482			(1,333		)
	(1,452		)	1,120			(2,634		)	2,371
Available-for-sale securities
Comprehensive income (loss) before tax	(1,203		)	4,959			(3,236		)	6,512
Income tax benefit (provision)	433			(1,788		)	1,165			(2,347		)
	(770		)	3,171			(2,071		)	4,165

Total other comprehensive income (loss)	(1,577		)	4,043			(4,207		)	5,534
Total comprehensive loss	$	(98,437	)	$	(68,163	)	$	(225,206	)	$	(136,721	)

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

Table of Contents

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except per share data)

	June 30,			December 31,
	2014			2013
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	740,154		$	911,099
Short term investments	248,647			248,414
Trade accounts receivable	203,782			198,020
Other receivables	35,369			31,553
Inventories	228,726			264,161
Prepaid royalties	7,932			8,083
Deferred income taxes	48,786			49,144
Coal derivative assets	14,122			14,851
Other current assets	54,270			56,746
Total current assets	1,581,788			1,782,071
Property, plant and equipment, net	6,603,458			6,734,286
Other assets
Prepaid royalties	87,494			87,577
Equity investments	229,514			221,456
Other noncurrent assets	153,854			164,803
Total other assets	470,862			473,836
Total assets	$	8,656,108		$	8,990,193
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	160,209		$	176,142
Accrued expenses and other current liabilities	294,317			278,587
Current maturities of debt	27,266			33,493
Total current liabilities	481,792			488,222
Long-term debt	5,116,353			5,118,002
Asset retirement obligations	395,813			402,713
Accrued pension benefits	13,925			7,111
Accrued postretirement benefits other than pension	38,034			39,255
Accrued workers’ compensation	74,083			78,062
Deferred income taxes	332,207			413,546
Other noncurrent liabilities	172,512			190,033
Total liabilities	6,624,719			6,736,944
Stockholders’ equity
Common stock, $0.01 par value, authorized 260,000 shares, issued 213,792 shares at both June 30, 2014 and December 31, 2013.	2,141			2,141
Paid-in capital	3,044,082			3,038,613
Treasury stock, at cost	(53,848		)	(53,848		)
Accumulated deficit	(994,471		)	(771,349		)
Accumulated other comprehensive income	33,485			37,692
Total stockholders’ equity	2,031,389			2,253,249
Total liabilities and stockholders’ equity	$	8,656,108		$	8,990,193

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

Table of Contents

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(in thousands)

	Six Months Ended June 30,
	2014			2013
	(Unaudited)
Operating activities
Net loss	$	(220,999	)	$	(142,255	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation, depletion and amortization	206,887			237,668
Amortization of acquired sales contracts, net	(6,935		)	(5,019		)
Amortization relating to financing activities	7,757			12,346
Prepaid royalties expensed	3,575			9,251
Employee stock-based compensation expense	5,469			5,804
Asset impairment costs	1,512			20,482
Gains on disposals and divestitures, net	(18,506		)	(2,819		)
Deferred income taxes	(78,568		)	(102,172		)
Changes in:
Receivables	267			(3,909		)
Inventories	3,522			8,771
Accounts payable, accrued expenses and other current liabilities	10,495			(4,062		)
Income taxes, net	(571		)	(29		)
Other	7,749			17,988
Cash provided by (used in) operating activities	(78,346		)	52,045
Investing activities
Capital expenditures	(95,746		)	(169,064		)
Payments of minimum royalties	(3,341		)	(10,162		)
Proceeds from sale-leaseback transactions	—			5,080
Proceeds from disposals and divestitures	43,245			34,919
Purchases of short term investments	(168,951		)	(61,870		)
Proceeds from sales of short term investments	166,018			47,097
Investments in and advances to affiliates	(9,501		)	(8,142		)
Change in restricted cash	—			2,368
Cash used in investing activities	(68,276		)	(159,774		)
Financing activities
Payments on term loan	(9,750		)	(8,250		)
Net payments on other debt	(9,390		)	(11,703		)
Debt financing costs	(1,957		)	—
Dividends paid	(2,123		)	(12,735		)
Change in restricted cash	(1,103		)	—
Cash used in financing activities	(24,323		)	(32,688		)
Decrease in cash and cash equivalents	(170,945		)	(140,417		)
Cash and cash equivalents, beginning of period	911,099			784,622
Cash and cash equivalents, end of period	$	740,154		$	644,205

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

Table of Contents

Arch Coal, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

1. Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Arch Coal, Inc. and its subsidiaries (the “Company”). The Company’s primary business is the production of thermal and metallurgical coal from surface and underground mines located throughout the United States, for sale to utility, industrial and steel producers both in the United States and around the world. The Company currently operates mining complexes in West Virginia, Illinois, Wyoming and Colorado. All subsidiaries are wholly-owned. Intercompany transactions and accounts have been eliminated in consolidation.

The Company completed the sale of Canyon Fuel Company, LLC (“Canyon Fuel”) on August 16, 2013. The results of Canyon Fuel have been segregated from continuing operations and are reflected, net of tax, as discontinued operations in the condensed consolidated statements of operations for the three and six months ended June 30, 2013.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial reporting and U.S. Securities and Exchange Commission regulations. In the opinion of management, all adjustments, consisting of normal, recurring accruals considered necessary for a fair presentation, have been included. Results of operations for the three and six months ended June 30, 2014 are not necessarily indicative of results to be expected for the year ending December 31, 2014. 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, 2013 included in the Company’s Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission.

2. Accounting Policies

In May 2014, the FASB issued comprehensive authoritative guidance for the recognition and presentation of revenue from contracts with customers. The revenue recognition model is based on changes in contract assets (right to receive consideration) and liabilities (obligations to provide a good or perform a service). The guidance also requires comprehensive quantitative and qualitative disclosures intended to enable financial statement users to understand the nature, timing and uncertainty of revenue and the related cash flows. This guidance will be effective for the Company in the first fiscal quarter of 2017, with early adoption not permitted. The Company is currently assessing the impact the guidance will have upon adoption, but expects no significant changes to its existing revenue recognition policies.

3. Accumulated Other Comprehensive Income

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

				Pension,
				Postretirement
				and Other						Accumulated
				Post-						Other
	Derivative			Employment			Available-for-			Comprehensive
	Instruments			Benefits			Sale Securities			Loss
	(In thousands)
Balance at December 31, 2013	$	565		$	31,112		$	6,015		$	37,692
Unrealized gains (losses)	788			—			(3,146		)	(2,358		)
Amounts reclassified from AOCI	(290		)	(2,634		)	1,075			(1,849		)
Balance at June 30, 2014	$	1,063		$	28,478		$	3,944		$	33,485

The following amounts were reclassified out of AOCI:

Table of Contents

	Amounts Reclassified from AOCI												Line Item in the
	Three Months Ended June 30,						Six Months Ended June 30,						Condensed Consolidated
Details About AOCI	2014			2013			2014			2013			Statement of Operations
	(In thousands)
Derivative instruments	$	151		$	542		$	454		$	1,401		Revenues
	(55		)	(196		)	(164		)	(505		)	Benefit from income taxes
	$	96		$	346		$	290		$	896		Net of tax

Pension, postretirement and other post-employment benefits
Amortization of prior service credits (1)	$	2,591		$	2,673		$	5,217		$	5,581
Amortization of actuarial gains (losses), net (1)	(321		)	(4,423		)	(1,100		)	(9,285		)
	2,270			(1,750		)	4,116			(3,704		)
	(817		)	630			(1,482		)	1,333			Benefit from income taxes
	$	1,453		$	(1,120	)	$	2,634		$	(2,371	)	Net of tax

Available-for-sale securities (2)	$	(1,123	)	$	(250	)	$	(1,679	)	$	(309	)	Interest and investment income
	404			90			604			111			Benefit from income taxes
	$	(719	)	$	(160	)	$	(1,075	)	$	(198	)	Net of tax

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

2 The gains and losses on sales of available-for-sale-securities are determined on a specific identification basis.

Table of Contents

4. Divestitures

During the first quarter of 2014, the Company entered into agreements to sell an operating thermal coal complex and an idled thermal coal mine in Kentucky and the Company’s ADDCAR subsidiary, which manufactures a patented highwall mining system. The sales closed during the first quarter of 2014 for total consideration of $45.3 million. The Company has received $34.2 million in cash, and the remaining $11.0 million is payable on December 31, 2014. The Company recognized a net pre-tax gain of $12.8 million from these divestitures, reflected in “other operating income, net” in the condensed consolidated statement of operations.

The following table summarizes the assets and liabilities of the divested operations reflected in the December 31, 2013 consolidated balance sheet (in thousands):

Inventories	$	33,283
Other current assets	1,032
Net property, plant & equipment	104,587
Other noncurrent assets	139
Accounts payable and accrued expenses	13,005
Other noncurrent liabilities	24,276

The following table summarizes the results of Canyon Fuel, reflected as discontinued operations in the condensed consolidated statement of operations through the date of disposition:

	Three Months Ended June 30, 2013		Six Months Ended June 30, 2013
	(in thousands)
Total revenues	$	85,107	$	173,239
Income from discontinued operations before income taxes	$	9,748	$	28,737
Less: income tax expense	1,603		6,325
Income from discontinued operations	$	8,145	$	22,412
Basic and diluted earnings per common share from discontinued operations	$	0.04	$	0.11

5. Inventories

Inventories consist of the following:

	June 30,		December 31
	2014		2013
	(In thousands)
Coal	$	101,195	$	117,531
Repair parts and supplies	127,531		137,497
Work-in-process	—		9,133
	$	228,726	$	264,161

The repair parts and supplies are stated net of an allowance for slow-moving and obsolete inventories of $8.7 million at June 30, 2014 and $8.4 million at December 31, 2013.

6. Investments in Available-for-Sale Securities

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

Table of Contents

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

	June 30, 2014
										Balance Sheet
			Gross		Gross					Classification
			Unrealized		Unrealized			Fair		Short-Term		Other
	Cost Basis		Gains		Losses			Value		Investments		Assets
	(In thousands)
Available-for-sale:
Corporate notes and bonds	$	251,038	$	—	$	(2,391	)	$	248,647	$	248,647	$	—
Equity securities	5,420		11,245		(2,701		)	13,964		—		13,964
Total Investments	$	256,458	$	11,245	$	(5,092	)	$	262,611	$	248,647	$	13,964

	December 31, 2013
										Balance Sheet
			Gross		Gross					Classification
			Unrealized		Unrealized			Fair		Short-Term		Other
	Cost Basis		Gains		Losses			Value		Investments		Assets
	(In thousands)
Available-for-sale:
U.S. government and agency securities	$	65,002	$	11	$	(75	)	$	64,938	$	64,938	$	—
Corporate notes and bonds	184,773		7		(1,304		)	183,476		183,476		—
Equity securities	5,271		13,660		(2,902		)	16,029		—		16,029
Total Investments	$	255,046	$	13,678	$	(4,281	)	$	264,443	$	248,414	$	16,029

The aggregate fair value of investments with unrealized losses that were owned for less than a year was $242.5 million and $164.3 million at June 30, 2014 and December 31, 2013, respectively. The aggregate fair value of investments with unrealized losses that were owned for over a year, and were also in a continuous unrealized loss position during that time, was $6.5 million and $48.7 million at June 30, 2014 and December 31, 2013, respectively.

The debt securities outstanding at June 30, 2014 have maturity dates ranging from the third quarter of 2014 through the fourth quarter of 2015. The Company classifies its investments as current based on the nature of the investments and their availability to provide cash for use in current operations.

7. Derivatives

Diesel fuel price risk management

The Company is exposed to price risk with respect to diesel fuel purchased for use in its operations. The Company anticipates purchasing approximately 57 to 67 million gallons of diesel fuel for use in its operations during 2014. To protect the Company’s cash flows from increases in the price of diesel fuel for its operations, the Company uses forward physical diesel purchase contracts and purchased heating oil call options. At June 30, 2014, the Company had protected the price of approximately 88% of its expected purchases for the remainder of 2014 and 80% of its expected 2015 purchases through the third quarter. At June 30, 2014, the Company had purchased heating oil call options for approximately 70 million gallons for the purpose of managing the price risk associated with future diesel purchases.

The Company has also purchased heating oil call options to manage the price risk associated with fuel surcharges on its barge and rail shipments, which cover increases in diesel fuel prices for the respective carriers. At June 30, 2014, the Company held heating oil call options for 3.4 million gallons that will settle ratably through February 2015 for the purpose of managing the fluctuations in cash flows associated with fuel surcharges on future shipments.

These positions reduce the Company’s risk of cash flow fluctuations related to these surcharges but the positions are not accounted for as hedges.

Table of Contents

Coal price risk management positions

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

At June 30, 2014, the Company held derivatives for risk management purposes that are expected to settle in the following years:

(Tons in thousands)	2014	2015	Total
Coal sales	2,504	2,380	4,884
Coal purchases	1,308	360	1,668

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

Coal trading positions

The Company may sell or purchase forward contracts, swaps and options in the over-the-counter coal market for trading purposes. The Company is exposed to the risk of changes in coal prices on the value of its coal trading portfolio. The estimated future realization of the value of the trading portfolio is $6.3 million of gains during the remainder of 2014 and $2.9 million of gains in 2015.

Tabular derivatives disclosures

The Company has master netting agreements with all of its counterparties which allow for the settlement of contracts in an asset position with contracts in a liability position in the event of default or termination. Such netting arrangements reduce the Company’s credit exposure related to these counterparties. For classification purposes, the Company records the net fair value of all the positions with a given counterparty as a net asset or liability in the condensed consolidated balance sheets. The amounts shown in the table below represent the fair value position of individual contracts, and not the net position presented in the accompanying condensed consolidated balance sheets. The fair value and location of derivatives reflected in the accompanying condensed consolidated balance sheets are as follows:

	June 30, 2014								December 31, 2013
Fair Value of Derivatives	Asset			Liability					Asset			Liability
(In thousands)	Derivative			Derivative					Derivative			Derivative
Derivatives Designated as Hedging Instruments
Coal	$	1,770		$	(360	)			$	909		$	(26	)

Derivatives Not Designated as Hedging Instruments
Heating oil — diesel purchases	4,250			—					4,681			—
Heating oil — fuel surcharges	104			—					422			—
Coal — held for trading purposes	72,881			(63,749		)			55,327			(45,763		)
Coal — risk management	4,952			(1,715		)			6,342			(1,950		)
Natural gas	343			—					—			—
Total	82,530			(65,464		)			66,772			(47,713		)
Total derivatives	84,300			(65,824		)			67,681			(47,739		)
Effect of counterparty netting	(65,824		)	65,824					(47,727		)	47,727
Net derivatives as classified in the balance sheets	$	18,476		$	—		$	18,476	$	19,954		$	(12	)	$	19,942

Table of Contents

		June 30, 2014		December 31, 2013
Net derivatives as reflected on the balance sheets
Heating oil	Other current assets	$	4,354	$	5,103
Coal	Coal derivative assets	14,122		14,851
	Accrued expenses and other current liabilities	—		(12		)
		$	18,476	$	19,942

The Company had a current liability for the obligation to post cash collateral of $1.9 million at June 30, 2014 and a current asset for the right to reclaim cash collateral of $2.2 million at December 31, 2013. 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.

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

Derivatives used in Cash Flow Hedging Relationships (in thousands)

Three Months Ended June 30,

	Gain (Loss) Recognized in Other Comprehensive Income(Effective Portion)						Gains (Losses) Reclassified from Other Comprehensive Income into Income (Effective Portion)
	2014			2013			2014			2013
Coal sales(1)	$	1,870		$	(648	)	$	223		$	690
Coal purchases(2)	(712		)	613			(72		)	(148		)
Totals	$	1,158		$	(35	)	$	151		$	542

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, 2014 and 2013.

Derivatives Not Designated as Hedging Instruments (in thousands)

Three Months Ended June 30,

	Gain (Loss) Recognized
	2014			2013
Coal — unrealized(3)	$	147		$	4,109
Coal — realized(4)	$	1,318		$	6,579
Natural gas — unrealized(3)	$	(267	)	$	—
Heating oil — diesel purchases(4)	$	—		$	(5,211	)
Heating oil — fuel surcharges(4)	$	(47	)	$	(30	)

Location in statement of operations:

(1) — Revenues

(2) — Cost of sales

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

(4) — Other operating income, net

Derivatives used in Cash Flow Hedging Relationships (in thousands)

Six Months Ended June 30,

	Gain (Loss) Recognized in Other Comprehensive Income(Effective Portion)						Gains (Losses) Reclassified from Other Comprehensive Income into Income (Effective Portion)
	2014			2013			2014			2013
Coal sales(1)	$	1,355		$	(824	)	$	930		$	1,911
Coal purchases(2)	(123		)	431			(476		)	(510		)
Totals	$	1,232		$	(393	)	$	454		$	1,401

Table of Contents

Derivatives Not Designated as Hedging Instruments (in thousands)

Six Months Ended June 30,

	Gain (Loss) Recognized
	2014			2013
Coal — unrealized(3)	$	(1,155	)	$	5,579
Coal — realized(4)	$	4,197		$	15,796
Natural gas — unrealized(3)	$	(259	)	$	—
Heating oil — diesel purchases(4)	$	(2,963	)	$	(9,472	)
Heating oil — fuel surcharges(4)	$	(301	)	$	(595	)

Location in statement of operations:

(1) — Revenues

(2) — Cost of sales

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

(4) — Other operating income, net

Based on fair values at June 30, 2014, gains on derivative contracts designated as hedge instruments in cash flow hedges of approximately $0.8 million are expected to be reclassified from other comprehensive income into earnings during the next twelve months.

Related to its trading portfolio, the Company recognized net unrealized and realized gains of $3.1 million and $4.9 million during the three months ended June 30, 2014 and 2013, respectively; and net unrealized and realized gains of $3.5 million and $2.1 million during the six months ended June 30, 2014 and 2013. Gains and losses from trading activities are included in the caption “Change in fair value of coal derivatives and coal trading activities, net” in the accompanying condensed consolidated statements of operations, and are not included in the previous tables reflecting the effects of derivatives on measures of financial performance.

Table of Contents

8. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consist of the following:

	June 30,		December 31,
	2014		2013
	(In thousands)
Payroll and employee benefits	$	62,486	$	67,621
Taxes other than income taxes	116,176		114,664
Interest	32,765		18,528
Acquired sales contracts	13,468		14,373
Workers’ compensation	17,783		12,434
Asset retirement obligations	22,682		24,940
Other	28,957		26,027
	$	294,317	$	278,587

9. Debt and Financing Arrangements

	June 30,		December 31,
	2014		2013
	(In thousands)
Term loan due 2018 ($1.92 billion and $1.93 billion face value, respectively)	$	1,898,697	$	1,906,975
7.00% senior notes due 2019 at par	1,000,000		1,000,000
9.875% senior notes due 2019 ($375.0 million face value)	362,867		362,358
8.00% senior secured notes due 2019 at par	350,000		350,000
7.25% senior notes due 2020 at par	500,000		500,000
7.25% senior notes due 2021 at par	1,000,000		1,000,000
Other	32,055		32,162
	5,143,619		5,151,495
Less current maturities of debt	27,266		33,493
Long-term debt	$	5,116,353	$	5,118,002

At June 30, 2014, the available borrowing capacity under the Company’s lines of credit was approximately $248.4 million.

10. Income taxes

During the first quarter of 2014, the Company determined it was more likely than not that a portion of the federal and state net operating losses it expects to generate in 2014 will not be realized based on projections of future taxable income. Accordingly, the estimated annual effective rate for the year ended December 31, 2014 includes a valuation allowance for that portion. In applying the estimated annual effective rate to earnings, the Company increased its valuation allowance by $18.3 million for the three months ended June 30, 2014 and $42.1 million for the six months ended June 30, 2014 relating to federal and state net operating losses.

11. Fair Value Measurements

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

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

· Level 2 is defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that

Table of Contents

are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. The Company’s level 2 assets and liabilities include U.S. government agency securities and commodity contracts (coal and heating oil) with fair values derived from quoted prices in over-the-counter markets or from prices received from direct broker quotes.

· Level 3 is defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. These include the Company’s commodity option contracts (coal, natural gas and heating oil) valued using modeling techniques, such as Black-Scholes, that require the use of inputs, particularly volatility, that are rarely observable. Changes in the unobservable inputs would not have a significant impact on the reported Level 3 fair values at June 30, 2014.

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

	June 30, 2014
	Total		Level 1		Level 2			Level 3
	(In thousands)
Assets:
Investments in marketable securities	$	262,611	$	13,964	$	248,647		$	—
Derivatives	18,476		12,653		(214		)	6,037
Total assets	$	281,087	$	26,617	$	248,433		$	6,037

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

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

	Three Months Ended June 30, 2014		Six Months Ended June 30, 2014
	(In thousands)
Balance, beginning of period	$	3,977	$	4,946
Realized and unrealized losses recognized in earnings, net	205		(2,720		)
Purchases	1,855		3,811
Ending balance	$	6,037	$	6,037

Net unrealized gains of $0.5 million and losses of $1.6 million were recognized during the three and six months ended June 30, 2014, respectively, related to level 3 financial instruments held on June 30, 2014.

Fair Value of Long-Term Debt

At June 30, 2014 and December 31, 2013, the fair value of the Company’s debt, including amounts classified as current, was $4.5 billion and $4.6 billion, respectively. Fair values are based upon observed prices in an active market, when available, or from valuation models using market information, which fall into Level 2 in the fair value hierarchy.

12. Loss Per Common Share

The effect of options, restricted stock and restricted stock units equaling 7.0 million shares of common stock were excluded from the calculation of diluted weighted average shares outstanding for the three and six months ended June 30, 2014 and 7.0 million and 8.4 million shares for the three and six months ended June 30, 2013, respectively, because the exercise price or grant price of the securities exceeded the average market price of the Company’s common stock for these periods. The weighted average share impacts of options, restricted stock and restricted stock units that were excluded from the calculation of weighted average shares due to the Company’s incurring a net loss for the three and six months ended June 30, 2014 were 2.9 million and 2.2 million, respectively. The weighted average share impacts of options, restricted stock and restricted stock units that were excluded from the calculation of weighted average shares due to the Company’s incurring a net loss for the three and six months ended June 30, 2013 were not significant.

Table of Contents

13. Employee Benefit Plans

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Service cost	$	5,477		$	6,790		$	11,401		$	14,490
Interest cost	4,192			3,876			8,556			7,802
Expected return on plan assets	(5,879		)	(6,036		)	(11,857		)	(11,842		)
Amortization of prior service costs (credits)	(53		)	57			(107		)	(101		)
Amortization of other actuarial losses	532			4,264			1,480			8,815
Net benefit cost	$	4,269		$	8,951		$	9,473		$	19,164

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Service cost	$	440		$	538		$	884		$	1,094
Interest cost	457			415			921			846
Amortization of prior service credits	(2,501		)	(2,730		)	(5,002		)	(5,480		)
Amortization of other actuarial losses (gains)	(210		)	(75		)	(380		)	2
Net benefit credit	$	(1,814	)	$	(1,852	)	$	(3,577	)	$	(3,538	)

14. Commitments and Contingencies

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

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

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

On November 3, 2008, ICG, Wolf Run and Hunter Ridge filed an amended answer and counterclaim against the plaintiffs seeking to void the coal supply agreement due to, among other things, fraudulent inducement and conspiracy. On September 23, 2009, Allegheny filed a second amended complaint alleging several alternative theories of liability in its effort to extend contractual liability to ICG, which was not a party to the original contract and did not exist at the time Wolf Run and Allegheny entered into the contract. No new substantive claims were asserted. ICG answered the second amended complaint

Table of Contents

on October 13, 2009, denying all of the new claims. The Company’s counterclaim was dismissed on motion for summary judgment entered on May 11, 2010. Allegheny’s claims against ICG were also dismissed by summary judgment, but the claims against Wolf Run and Hunter Ridge were not. The court conducted a non-jury trial of this matter beginning on January 10, 2011 and concluding on February 1, 2011.

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

The parties appealed the lower court’s decision to the Superior Court of Pennsylvania. On August 13, 2012, the Superior Court of Pennsylvania affirmed the award of past damages, but ruled that the lower court should have calculated future damages as of the date of breach, and remanded the matter back to the lower court with instructions to recalculate that portion of the award. On November 19, 2012, Allegheny filed a Petition for Allowance of Appeal with the Supreme Court of Pennsylvania and Wolf Run and Hunter Ridge filed an Answer. On July 2, 2013, the Supreme Court of Pennsylvania denied the Petition of Allowance. As this action finalized the past damage award, Wolf Run paid $15.6 million for the past damage amount, including interest, to Allegheny in July 2013. Testimony on the future damage award in the lower court concluded on May 19, 2014, and post-trial briefs are due August 8, 2014.

In addition, the Company is a party to numerous other claims and lawsuits with respect to various matters. As of June 30, 2014 and December 31, 2013, the Company had accrued $23.9 million and $30.4 million, respectively, for all legal matters, including $10.9 million and $11.7 million, respectively, classified as current. The ultimate resolution of any such legal matter could result in outcomes which may be materially different from amounts the Company has accrued for such matters.

15. Segment Information

The Company’s reportable business segments are based on the major coal producing basins in which the Company operates and may include a number of mine complexes. The Company manages its coal sales by coal basin, not by individual mining complex. Geology, coal transportation routes to customers, regulatory environments and coal quality or type are characteristic to a basin, and, accordingly, market and contract pricing have developed by coal basin. Mining operations are evaluated based on 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; and the Appalachia (APP) segment, with operations primarily in West Virginia. The “Other” category combines other operating segments and includes the Company’s coal mining operations in Colorado and Illinois and its ADDCAR subsidiary, which the Company sold in the first quarter of 2014.

Operating segment results for the three and six months ended June 30, 2014 and 2013 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. These reportable segments results do not reflect impairment charges, since those are not reflected in the operating income reviewed by management. Corporate, Other and Eliminations includes these charges, as well as 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 operating segment results and capital expenditures reflect only those from continuing operations, and exclude the results of Canyon Fuel, since they are classified as discontinued operations in the condensed consolidated statements of operations for the three and six months ended June 30, 2013. Because the condensed consolidated statement of cash flows includes cash flows from discontinued operations, capital expenditures from discontinued operations are included in “Corporate, Other and Eliminations” below.

The asset amounts below represent an allocation of assets consistent with the basis used for the Company’s incentive compensation plans. The amounts in Corporate, Other and Eliminations represent primarily corporate assets (cash, receivables,

Table of Contents

investments, plant, property and equipment) as well as unassigned coal reserves, above-market acquired sales contracts and other unassigned assets.

	PRB			APP			Other Operating Segments		Corporate, Other and Eliminations			Consolidated
	(in thousands)
Three Months Ended June 30, 2014
Revenues	$	358,265		$	280,961		$	74,550	$	—		$	713,776
Income (loss) from operations	5,103			(18,274		)	14,955		(37,589		)	(35,805		)
Depreciation, depletion and amortization	41,036			51,232			9,583		613			102,464
Amortization of acquired sales contracts, net	(785		)	(2,477		)	23		—			(3,239		)
Capital expenditures	6,962			11,037			2,358		60,935			81,292

Three Months Ended June 30, 2013
Revenues	$	353,425		$	337,678		$	75,229	$	—		$	766,332
Income (loss) from operations	16,755			(5,220		)	12,924		(60,738		)	(36,279		)
Depreciation, depletion and amortization	42,147			56,006			11,057		1,875			111,085
Amortization of acquired sales contracts, net	(941		)	(2,812		)	1,544		—			(2,209		)
Capital expenditures	1,819			43,470			4,771		64,482			114,542

Six Months Ended June 30, 2014
Revenues	$	716,872		$	560,098		172,777		$	—		$	1,449,747
Income (loss) from operations	204			(44,002		)	16,728		(81,857		)	(108,927		)
Depreciation, depletion and amortization	80,281			106,220			19,102		1,284			206,887
Amortization of acquired sales contracts, net	(1,574		)	(5,451		)	90		—			(6,935		)
Capital expenditures	9,056			19,193			4,159		63,338			95,746

Six Months Ended June 30, 2013
Revenues	$	715,371		$	620,296		$	168,035	$	—		$	1,503,702
Income (loss) from operations	32,272			(32,336		)	20,308		(107,954		)	(87,710		)
Depreciation, depletion and amortization	84,374			111,337			22,361		3,206			221,278
Amortization of acquired sales contracts, net	(2,140		)	(5,284		)	2,405		—			(5,019		)
Capital expenditures	3,976			92,767			5,266		67,055			169,064

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Loss from operations	$	(35,805	)	$	(36,279	)	$	(108,927	)	$	(87,710	)
Interest expense	(97,960		)	(94,756		)	(194,431		)	(189,830		)
Interest and investment income	2,036			1,216			3,879			4,052
Loss from continuing operations before income taxes	$	(131,729	)	$	(129,819	)	$	(299,479	)	$	(273,488	)

16. Supplemental Consolidating Financial Information

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

Table of Contents

Condensed Consolidating Statements of Operations

Three Months Ended June 30, 2014

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

Income (loss) from continuing operations before income taxes	(131,708		)	2,400			81			(2,502		)	(131,729		)
Benefit from income taxes	(34,848		)	—			(21		)	—			(34,869		)
Net loss	$	(96,860	)	$	2,400		$	102		$	(2,502	)	$	(96,860	)
Total comprehensive income (loss)	$	(98,437	)	$	1,647		$	102		$	(1,749	)	$	(98,437	)

Table of Contents

Condensed Consolidating Statements of Operations

Three Months Ended June 30, 2013

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	766,332		$	—		$	—		$	766,332
Costs, expenses and other
Cost of sales (exclusive of items shown separately below)	1,829			654,369			—			—			656,198
Depreciation, depletion and amortization	1,475			109,601			9			—			111,085
Amortization of acquired sales contracts, net	—			(2,209		)	—			—			(2,209		)
Change in fair value of coal derivatives and coal trading activities, net	—			(9,008		)	—			—			(9,008		)
Asset impairment costs	20,482			—			—			—			20,482
Selling, general and administrative expenses	22,205			10,729			1,368			—			34,302
Other operating income, net	(1,101		)	(7,041		)	(97		)	—			(8,239		)
	44,890			756,441			1,280			—			802,611
Income from investment in subsidiaries	26,961			—			—			(26,961		)	—
Income (loss) from operations	(17,929		)	9,891			(1,280		)	(26,961		)	(36,279		)
Interest expense, net
Interest expense	(110,946		)	(5,825		)	(1,059		)	23,074			(94,756		)
Interest and investment income	7,201			15,566			1,523			(23,074		)	1,216
	(103,745		)	9,741			464			—			(93,540		)

Income (loss) from continuing operations before income taxes	(121,674		)	19,632			(816		)	(26,961		)	(129,819		)
Benefit from income taxes	(49,468		)	—			—			—			(49,468		)
Income (loss) from continuing operations	(72,206		)	19,632			(816		)	(26,961		)	(80,351		)
Income from discontinued operations, net of tax	—			8,145			—			—			8,145
Net income (loss)	$	(72,206	)	$	27,777		$	(816	)	$	(26,961	)	$	(72,206	)
Total comprehensive income (loss)	$	(68,163	)	$	28,123		$	(816	)	$	(27,307	)	$	(68,163	)

Table of Contents

Condensed Consolidating Statements of Operations

Six Months Ended June 30, 2014

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

Loss from continuing operations before income taxes	(299,507		)	(32,620		)	(196		)	32,844			(299,479		)
Provision for (benefit from) income taxes	(78,508		)	—			28			—			(78,480		)
Net loss	$	(220,999	)	$	(32,620	)	$	(224	)	$	32,844		$	(220,999	)
Total comprehensive loss	$	(225,206	)	$	(34,779	)	$	(224	)	$	35,003		$	(225,206	)

Table of Contents

Condensed Consolidating Statements of Operations

Six Months Ended June 30, 2013

	Parent/Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	1,503,702		$	—		$	—		$	1,503,702
Costs, expenses and other
Cost of sales (exclusive of items shown separately below)	4,712			1,301,229			—			—			1,305,941
Depreciation, depletion and amortization	2,880			218,380			18			—			221,278
Amortization of acquired sales contracts, net	—			(5,019		)	—			—			(5,019		)
Change in fair value of coal derivatives and coal trading activities, net	—			(7,700		)	—			—			(7,700		)
Asset impairment costs	20,482			—			—			—			20,482
Selling, general and administrative expenses	43,903			20,763			2,845			—			67,511
Other operating income, net	(7,009		)	(2,963		)	(1,109		)	—			(11,081		)
	64,968			1,524,690			1,754			—			1,591,412
Income from investment in subsidiaries	19,492			—			—			(19,492		)	—
Income (loss) from operations	(45,476		)	(20,988		)	(1,754		)	(19,492		)	(87,710		)
Interest expense, net
Interest expense	(221,761		)	(12,130		)	(2,100		)	46,161			(189,830		)
Interest and investment income	16,161			30,998			3,054			(46,161		)	4,052
	(205,600		)	18,868			954			—			(185,778		)

Loss from continuing operations before income taxes	(251,076		)	(2,120		)	(800		)	(19,492		)	(273,488		)
Benefit from income taxes	(108,821		)	—			—			—			(108,821		)
Loss from continuing operations	(142,255		)	(2,120		)	(800		)	(19,492		)	(164,667		)
Income from discontinued operations, net of tax	—			22,412			—			—			22,412
Net income (loss)	$	(142,255	)	$	20,292		$	(800	)	$	(19,492	)	$	(142,255	)
Total comprehensive income (loss)	$	(136,721	)	$	20,202		$	(800	)	$	(19,402	)	$	(136,721	)

Table of Contents

Condensed Consolidating Balance Sheets

June 30, 2014

	Parent/Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Cash and cash equivalents	$	628,251	$	100,360	$	11,543	$	—		$	740,154
Short term investments	248,647		—		—		—			248,647
Receivables	26,284		14,060		203,416		(4,609		)	239,151
Inventories	—		228,726		—		—			228,726
Other	85,461		38,039		1,610		—			125,110
Total current assets	988,643		381,185		216,569		(4,609		)	1,581,788

Property, plant and equipment, net	16,663		6,586,776		19		—			6,603,458

Investment in subsidiaries	7,643,340		—		—		(7,643,340		)	—
Intercompany receivables	—		2,009,804		—		(2,009,804		)	—
Note receivable from Arch Western	675,000		—		—		(675,000		)	—
Other	152,974		317,772		116		—			470,862
Total other assets	8,471,314		2,327,576		116		(10,328,144		)	470,862
Total assets	$	9,476,620	$	9,295,537	$	216,704	$	(10,332,753	)	$	8,656,108

Liabilities and Stockholders’ Equity
Accounts payable	$	13,286	$	146,871	$	52	$	—		$	160,209
Accrued expenses and other current liabilities	70,523		227,552		851		(4,609		)	294,317
Current maturities of debt	22,011		5,255		—		—			27,266
Total current liabilities	105,820		379,678		903		(4,609		)	481,792
Long-term debt	5,092,064		24,289		—		—			5,116,353
Intercompany payables	1,820,942		—		188,862		(2,009,804		)	—
Note payable to Arch Coal	—		675,000		—		(675,000		)	—
Asset retirement obligations	1,037		394,776		—		—			395,813
Accrued pension benefits	2,869		11,056		—		—			13,925
Accrued postretirement benefits other than pension	4,374		33,660		—		—			38,034
Accrued workers’ compensation	27,214		46,869		—		—			74,083
Deferred income taxes	332,207		—		—		—			332,207
Other noncurrent liabilities	58,704		113,525		283		—			172,512
Total liabilities	7,445,231		1,678,853		190,048		(2,689,413		)	6,624,719
Stockholders’ equity	2,031,389		7,616,684		26,656		(7,643,340		)	2,031,389
Total liabilities and stockholders’ equity	$	9,476,620	$	9,295,537	$	216,704	$	(10,332,753	)	$	8,656,108

Table of Contents

Condensed Consolidating Balance Sheets

December 31, 2013

	Parent/Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Cash and cash equivalents	$	799,333	$	100,418		$	11,348	$	—		$	911,099
Short term investments	248,414		—			—		—			248,414
Receivables	14,177		23,018			197,015		(4,637		)	229,573
Inventories	—		264,161			—		—			264,161
Other	84,401		43,617			806		—			128,824
Total current assets	1,146,325		431,214			209,169		(4,637		)	1,782,071

Property, plant and equipment, net	24,851		6,709,398			37		—			6,734,286

Investment in subsidiaries	7,709,201		—			—		(7,709,201		)	—
Intercompany receivables	—		1,921,331			—		(1,921,331		)	—
Note receivable from Arch Western	675,000		—			—		(675,000		)	—
Other	162,287		311,463			86		—			473,836
Total other assets	8,546,488		2,232,794			86		(10,305,532		)	473,836
Total assets	$	9,717,664	$	9,373,406		$	209,292	$	(10,310,169	)	$	8,990,193

Liabilities and Stockholders’ Equity
Accounts payable	$	17,781	$	158,224		$	137	$	—		$	176,142
Accrued expenses and other current liabilities	53,779		228,664			781		(4,637		)	278,587
Current maturities of debt	28,882		4,611			—		—			33,493
Total current liabilities	100,442		391,499			918		(4,637		)	488,222
Long-term debt	5,099,833		18,169			—		—			5,118,002
Intercompany payables	1,740,236		—			181,095		(1,921,331		)	—
Note payable to Arch Coal	—		675,000			—		(675,000		)	—
Asset retirement obligations	1,095		401,618			—		—			402,713
Accrued pension benefits	7,797		(686		)	—		—			7,111
Accrued postretirement benefits other than pension	12,079		27,176			—		—			39,255
Accrued workers’ compensation	21,546		56,516			—		—			78,062
Deferred income taxes	413,546		—			—		—			413,546
Other noncurrent liabilities	67,841		121,794			398		—			190,033
Total liabilities	7,464,415		1,691,086			182,411		(2,600,968		)	6,736,944
Stockholders’ equity	2,253,249		7,682,320			26,881		(7,709,201		)	2,253,249
Total liabilities and stockholders’ equity	$	9,717,664	$	9,373,406		$	209,292	$	(10,310,169	)	$	8,990,193

Table of Contents

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2014

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

Table of Contents

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2013

	Parent/Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash provided by (used in) operating activities	$	(217,517	)	$	287,055		$	(17,493	)	$	—		$	52,045
Investing Activities
Capital expenditures	(1,511		)	(167,553		)	—			—			(169,064		)
Payments of minimum royalties	—			(10,162		)	—			—			(10,162		)
Proceeds from sale-leaseback transactions	—			5,080			—			—			5,080
Proceeds from disposals and divestitures	—			34,919			—			—			34,919
Purchases of short term investments	(61,870		)	—			—			—			(61,870		)
Proceeds from sales of short term investments	47,097			—			—			—			47,097
Investments in and advances to affiliates	(3,012		)	(5,385		)	—			255			(8,142		)
Change in restricted cash	2,368			—			—			—			2,368
Cash provided by (used in) investing activities	(16,928		)	(143,101		)	—			255			(159,774		)
Financing Activities
Contributions from parent	—			255			—			(255		)	—
Payments on term loan	(8,250		)	—			—			—			(8,250		)
Net payments on other debt	(11,448		)	(255		)	—			—			(11,703		)
Dividends paid	(12,735		)	—			—			—			(12,735		)
Transactions with affiliates, net	127,370			(143,975		)	16,605			—			—
Cash provided by (used in) financing activities	94,937			(143,975		)	16,605			(255		)	(32,688		)
Decrease in cash and cash equivalents	(139,508		)	(21		)	(888		)	—			(140,417		)
Cash and cash equivalents, beginning of period	671,313			100,468			12,841			—			784,622
Cash and cash equivalents, end of period	$	531,805		$	100,447		$	11,953		$	—		$	644,205

Table of Contents

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

Overview

Our results during the second quarter of 2014, when compared to the second quarter of 2013, were impacted by the continuing weakness in coal markets, particularly for metallurgical coal, and rail issues in the Powder River Basin.

Seaborne coal markets remain challenged, as oversupply continues to pressure global prices for metallurgical and thermal coals, and we expect the seaborne markets to remain weak throughout 2014. We have limited our forward exposure to the export market at this time, but we are positioned to increase export shipments should fundamentals improve.

Due to the weak markets, we sold 1.7 million tons of metallurgical coal in the second quarter of 2014 compared to 2.1 million tons in the second quarter of 2013, and 3.3 million tons of metallurgical coal during the first half of 2014 compared to 3.8 million tons during the first half of 2013.

Power generation levels in the U.S. increased marginally for the first half of the year, benefiting from cold winter weather, offset by a milder to-date spring and summer. Weather-related delays and rail service disruptions have impacted deliveries, particularly to plants sourced from the Powder River Basin. But demand increased compared with the prior year, resulting in higher prices for new firm sales commitments in the Powder River Basin. At the same time, the lack of sustained summer heat, a slower-growing economy, and waning natural gas prices have recently been pressuring the Powder River Basin market. See further information regarding committed sales in Item 3. “Quantitative and Qualitative Disclosures About Market Risk.”

In the face of weak coal markets, management has chosen to concentrate metallurgical coal production at our lowest-cost and highest-margin operations and announced the idling of a higher-cost mining complex in Appalachia in July 2014. We have retained the option to restart production should metallurgical coal markets strengthen. In addition, we continue to focus on capital spending reductions, cost containment and efficiency efforts, and working capital and liquidity management to preserve liquidity and prepare the company to capitalize on opportunities when coal markets recover.

Regional Performance

The following table shows results by operating segment for the three and six months ended June 30, 2014 and compares it with the information for the three and six months ended June 30, 2013. The “other” category represents the results of our other bituminous thermal operations: our West Elk mining complex in Colorado and our Viper mining complex in Illinois.

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Powder River Basin
Tons sold (in thousands)	26,928			27,131			52,594			53,743
Coal sales per ton sold	$	12.79		$	12.56		$	12.76		$	12.62
Cost per ton sold	$	12.61		$	12.02		$	12.80		$	12.13
Operating margin (loss) per ton sold	$	0.18		$	0.54		$	(0.04	)	$	0.49
Adjusted EBITDA (in thousands)	$	45,354		$	57,961		$	78,912		$	114,505
Appalachia
Tons sold (in thousands)	3,687			4,042			7,276			7,429
Coal sales per ton sold	$	69.36		$	74.18		$	68.54		$	74.44
Cost per ton sold	$	76.25		$	79.56		$	78.49		$	81.35
Operating loss per ton sold	$	(6.89	)	$	(5.38	)	$	(9.95	)	$	(6.91	)
Adjusted EBITDA (in thousands)	$	30,481		$	47,974		$	56,767		$	73,716
Other
Tons sold (in thousands)	2,048			1,780			4,150			3,706
Coal sales per ton sold	$	31.34		$	35.69		$	29.97		$	33.97
Cost per ton sold	$	24.51		$	28.40		$	25.85		28.79
Operating margin per ton sold	$	6.83		$	7.29		$	4.12		$	5.18
Adjusted EBITDA (in thousands)	$	24,561		$	24,490		$	37,756		$	44,115

Table of Contents

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

Powder River Basin — Adjusted EBITDA decreased 22% in the second quarter and 31% in the first half of 2014 when compared to the respective periods in 2013 due to lower shipment volumes and higher costs, primarily repairs and maintenance spending. These costs were incurred in anticipation of higher shipment volume levels to meet expected higher demand in the region; however, ongoing rail performance issues have impacted shipments out of the region. Pricing has improved in the region, which partially offset the impact of the lower shipment levels.

Appalachia — Adjusted EBITDA decreased in the second quarter and first half of 2014 when compared to the respective periods in 2013, due primarily to the weak metallurgical coal markets, which resulted in a decrease in metallurgical coal sales volumes and lower average coal pricing. Thermal coal sales volumes, however, increased in the first half of 2014 when compared to 2013 levels. Thermal coal pricing was lower in the first half of 2014 than in the prior year. The startup of the longwall at the low-cost Leer mining complex, lower depreciation, depletion and amortization costs, and lower sales-sensitive costs contributed to lower per-ton costs in the second quarter and first half of 2014 when compared to the respective periods in 2013. The shift of production to the Leer mining complex offset the impact of longwall geological issues elsewhere in the region, which should improve in the third quarter of 2014. Adjusted EBITDA in the first half of 2014 also benefited from the sale of a thermal coal complex and idled thermal coal mine in Kentucky in the first quarter ($15.6 million). See Note 4 to the condensed consolidated financial statement for further discussion.

Other — Operating margin per ton and Adjusted EBITDA were impacted by lower average per-ton pricing in the second quarter and the first half of 2014 when compared to the respective periods in 2013 due to a decrease in export pricing and the roll-off of long-term contracts, which resulted in a decrease in per-ton realizations. Lower per-ton pricing was partially offset by an improvement in per-ton costs, the result of higher sales volumes and cost control efforts.

Results of Operations

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

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

Coal sales. The following table summarizes information about our coal sales during the three months ended June 30, 2014 and compares it with the information for the three months ended June 30, 2013:

	Three Months Ended June 30,
	2014		2013		Decrease
	(In thousands)
Coal sales	$	713,776	$	761,604	$	(47,828	)
Tons sold	32,663		32,953		(290		)

On a consolidated basis, coal sales decreased in the second quarter of 2014 from the second quarter of 2013, due to the impact of lower sales volumes (a decrease of approximately $6 million) and the impact of lower average per-ton pricing (a decrease of approximately $42 million). Average pricing decreased from $23.11 to $21.85 per ton due mainly to declines in metallurgical coal sales and the impact of changes in the regional mix, as sales volumes decreased in regions with higher pricing. See discussion in “Regional Performance” for further information about regional results.

Costs, expenses and other. The following table summarizes costs, expenses and other components of operating income for the three months ended June 30, 2014 and compares it with the information for the three months ended June 30, 2013:

Table of Contents

	Three Months Ended June 30,						(Increase) Decrease
	2014			2013			in Net Loss
	(In thousands)
Cost of sales (exclusive of items shown separately below)	$	622,137		$	656,198		$	34,061
Depreciation, depletion and amortization	102,464			111,085			8,621
Amortization of acquired sales contracts, net	(3,239		)	(2,209		)	1,030
Change in fair value of coal derivatives and coal trading activities, net	(2,992		)	(9,008		)	(6,016		)
Asset impairment costs	1,512			20,482			18,970
Selling, general and administrative expenses	29,931			34,302			4,371
Other operating income, net	(232		)	(8,239		)	(8,007		)
Total costs, expenses and other	$	749,581		$	802,611		$	53,030

Cost of sales. Our cost of sales decreased in the second quarter of 2014 from the second quarter of 2013, due to lower sales volumes (a decrease of approximately $5 million) and average per-ton costs (a decrease of approximately $13 million). Lower average per-ton costs were the result of a decrease in sales volumes from higher-cost regions. See discussion in “Regional Performance” for further information about regional results. In addition, the disposition of ADDCAR in the first quarter of 2014 resulted in a decrease of $3.7 million in cost of sales. Transportation costs decreased approximately $13 million in the second quarter of 2014 from the second quarter of 2013, primarily due to decreased export shipments.

Depreciation, depletion and amortization. When compared with the second quarter of 2013, depreciation, depletion and amortization costs decreased in 2014 primarily due to mine idlings and dispositions in Appalachia and lower production and capital spending levels in other regions.

Asset Impairment costs. In the second quarter of 2013, we impaired an investment in a clean coal power plant project and a related receivable balance.

Selling, general and administrative expenses. Total selling, general and administrative expenses decreased when compared with the second quarter of 2013, due to decreases in legal and professional fees ($2.3 million), salary and benefit related costs ($1.7 million), and other decreases in discretionary spending.

Other operating income, net. When compared with the second quarter of 2013, other operating income, net decreased during the second quarter of 2014, primarily due to costs of $10.4 million in the second quarter of 2014 related to export shortfalls under throughput arrangements (an increase of $8.8 million from the second quarter of 2013) and a decrease in settlement gains of $5.3 million on derivatives used to manage coal price risk. These were partially offset by a decrease in unrealized losses on derivatives in our diesel purchase risk management of $5.2 million and an increase in gains on asset sales of $1.2 million.

Benefit from income taxes. The following table summarizes our benefit from income taxes for the three months ended June 30, 2014 and compares it with the information for the three months ended June 30, 2013:

	Three Months Ended June 30,						Increase
	2014			2013			in Net Loss
	(In thousands)
Benefit from income taxes	$	(34,869	)	$	(49,468	)	$	(14,599	)

The income tax benefit rate of 26% in the second quarter of 2014 decreased from 38% in the second quarter of 2013 due to the establishment of a valuation allowance totaling approximately $18 million relating to 2014 federal and state net operating loss carryforwards. See further discussion in Note 10 to the condensed consolidated financial statements.

Income from discontinued operations, net of tax The results of our Canyon Fuel subsidiary prior to its disposal are segregated from continuing operations. See further information in Note 4 to the condensed consolidated financial statements.

Table of Contents

	Three Months Ended June 30,				Increase
	2014		2013		in Net Loss
	(In thousands)
Income from discontinued operations, net of tax	$	—	$	8,145	$	(8,145	)

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

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

Coal sales. The following table summarizes information about our coal sales during the six months ended June 30, 2014 and compares it with the information for the six months ended June 30, 2013:

	Six Months Ended June 30,
	2014		2013		Decrease
	(In thousands)
Coal sales	$	1,447,809	$	1,498,090	$	(50,281	)
Tons sold	64,020		64,878		(858		)

Coal sales decreased slightly in the first half of 2014 from the first half of 2013 on a consolidated basis, primarily due to the impact of lower sales volumes (a decrease of approximately $19 million) and the impact of lower average per-ton pricing (a decrease of approximately $31 million). Average pricing decreased from $23.09 to $22.61 per ton, primarily due to declines in metallurgical coal sales, partially offset by improvements in Powder River Basin pricing. See discussion in “Regional Performance” for further information about regional results.

Costs, expenses and other. The following table summarizes costs, expenses and other components of operating income for the six months ended June 30, 2014 and compares it with the information for the six months ended June 30, 2013:

	Six Months Ended June 30,						(Increase) Decrease
	2014			2013			in Net Loss
	(In thousands)
Cost of sales (exclusive of items shown separately below)	$	1,308,451		$	1,305,941		$	(2,510	)
Depreciation, depletion and amortization	206,887			221,278			14,391
Amortization of acquired sales contracts, net	(6,935		)	(5,019		)	1,916
Change in fair value of coal derivatives and coal trading activities, net	(2,078		)	(7,700		)	(5,622		)
Asset impairment costs	1,512			20,482			18,970
Selling, general and administrative expenses	59,067			67,511			8,444
Other operating income, net	(8,230		)	(11,081		)	(2,851		)
Total costs, expenses and other	$	1,558,674		$	1,591,412		$	32,738

Cost of sales. Our cost of sales remained flat in the first half of 2014 from the first half of 2013, as the impact of lower sales volumes were offset by higher average per-ton costs. Higher average per-ton costs resulted in an increase in cost of sales of approximately $16 million. See discussion in “Regional Performance” for further information about regional cost results.

Depreciation, depletion and amortization. When compared with the first half of 2013, depreciation, depletion and amortization costs decreased in 2014 primarily due to mine idlings and dispositions in Appalachia and lower production and capital spending levels in other regions.

Asset impairment costs. Please see the discussion in comparison of results for the three months periods ended June30, 2014 and 2013.

Table of Contents

Selling, general and administrative expenses. Total selling, general and administrative expenses decreased when compared with the first half of 2013, due generally to decreases in legal and professional fees ($4.3 million), salary and benefit related costs ($4.0 million), and other decreases in discretionary spending.

Other operating income, net. When compared with the first half of 2013, other operating income, net decreased during the first half of 2014, primarily as a result of costs of $22.9 million in the first half of 2014 related to export shortfalls under throughput arrangements (an increase of $10.9 million from the first half of 2013), a decrease in realized gains of $11.6 million on derivatives used to manage coal price risk, and a decrease in contract settlement gains of $4.1 million. These were offset by the an increase in gains on asset disposals of $15.7 million, primarily from the divestitures of mining operations in the Appalachia region and our ADDCAR subsidiary in the first quarter of 2014, and a decrease in unrealized losses of $6.8 million on derivatives used in our diesel purchase risk management program.

Benefit from income taxes. The following table summarizes our benefit from income taxes for the six months ended June 30, 2014 and compares it with the information for the six months ended June 30, 2013:

	Six Months Ended June 30,						Increase
	2014			2013			in Net Loss
	(In thousands)
Benefit from income taxes	$	(78,480	)	$	(108,821	)	$	(30,341	)

The income tax benefit rate of 26% in the first half of 2014 decreased from 40% in the first half of 2013 due to the establishment of a valuation allowance totaling approximately $42 million relating to 2014 federal and state net operating loss carryforwards. See further discussion in Note 10 to the condensed consolidated financial statements.

	Six Months Ended June 30,				Increase
	2014		2013		in Net Loss
	(In thousands)
Income from discontinued operations, net of tax	$	—	$	22,412	$	(22,412	)

Reconciliation of NON-GAAP measures

Segment coal sales per ton sold

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)

Reported segment coal sales revenues	$	664,481		$	704,215		$	1,294,434		$	1,357,102
Coal risk management derivative settlements classified in “other income”	(1,318		)	(6,579		)	(4,197		)	(15,796		)
Transportation costs	50,613			63,968			157,573			156,784
Coal sales	$	713,776		$	761,604		$	1,447,810		$	1,498,090

Table of Contents

Segment cost per ton sold

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)

Reported segment cost of tons sold	$	671,130		$	698,440		$	1,351,427		$	1,363,116
Diesel fuel risk management derivative settlements classified in “other income”	(1,684		)	(3,584		)	(3,563		)	(8,246		)
Transportation costs	50,613			63,968			157,573			156,784
Depreciation, depletion and amortization in reported segment cost of tons sold presented on separate line on statement of operations	(101,851		)	(108,780		)	(205,603		)	(217,215		)
Other (other operating segments, operating overhead, etc.)	3,929			6,154			8,617			11,502
Cost of sales	$	622,137		$	656,198		$	1,308,451		$	1,305,941

Segment Adjusted EBITDA to Net Income

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Reported Segment Adjusted EBITDA	$	100,396		$	130,425		$	173,435		$	232,336
EBITDA from discontinued operations	—			17,471			—			45,148
Corporate and other (1)	(35,464		)	(37,346		)	(80,898		)	(83,305		)
Adjusted EBITDA	64,932			110,550			92,537			194,179
Income tax benefit	34,869			49,468			78,480			108,821
Interest expense, net	(95,924		)	(93,540		)	(190,552		)	(185,778		)
Depreciation, depletion and amortization	(102,464		)	(111,085		)	(206,887		)	(221,278		)
Amortization of acquired sales contracts, net	3,239			2,209			6,935			5,019
Asset impairment costs	(1,512		)	(20,482		)	(1,512		)	(20,482		)
Interest, depreciation, depletion and amortization classified as discontinued operations	—			(9,326		)	—			(22,736		)
Net loss	$	(96,860	)	$	(72,206	)	$	(220,999	)	$	(142,255	)

(1) Corporate and other includes primarily selling, general and administrative expenses, certain asset impairments, income from our equity investments and certain changes in the fair value of coal derivatives and coal trading activities.

Liquidity and Capital Resources

Our primary sources of cash are coal sales to customers, availability under our credit facilities and other financing arrangements, and debt and equity offerings related to significant transactions or refinancing activity. Excluding significant investing activity, we generally satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations, cash on hand or borrowings under our lines of credit. Such plans are subject to change based on our cash needs. During the market down cycle our focus is preserving liquidity and prudently managing costs, including capital expenditures.

Table of Contents

We have no meaningful maturities of debt until 2018, and we have suspended or eliminated most financial maintenance covenants that pertain only to our $250 million revolver until June of 2015, when a relaxed, senior secured leverage ratio covenant becomes effective. Until then, only a minimum liquidity covenant of $550 million remains in place. We had liquidity of nearly $1.25 billion at June 30, 2014, with $989 million of that in cash and liquid securities. We have no borrowings outstanding under our revolving credit agreement at June 30, 2014.

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, 2014 and 2013:

	Six Months Ended June 30,
	2014			2013
	(In thousands)
Cash provided by (used in):
Operating activities	$	(78,346	)	$	52,045
Investing activities	(68,276		)	(159,774		)
Financing activities	(24,323		)	(32,688		)

We used cash in operating activities during the first half of 2014 compared to generating cash from operations in the first half of 2013, driven by the decrease in our operating profitability resulting from weak coal market conditions and shipping issues in the Powder River Basin.

We used $91.5 million less cash in investing activities during the first half of 2014 compared to the first half of 2013. Capital expenditures and additions to prepaid royalties decreased approximately $73.3 million and $6.8 million, respectively, during the first half of 2014 when compared to the first half of 2013. Cash conservation efforts and the start up of the Leer mining complex longwall in the first quarter of 2014 were responsible for the decrease in capital expenditures. The divestitures of a Kentucky operation and idled assets and our ADDCAR subsidiary contributed to an increase of $8.3 million in proceeds from asset sales and divestitures over the first half of 2013. We will receive additional consideration of $11 million by the end of 2014 relating to the ADDCAR divestiture. Compared with the six months ended June 30, 2013, we invested net $11.8 million less in short term investments in the six months ended June 30, 2014.

Cash used in financing activities was approximately $8 million less in the six months ended June 30, 2014, primarily due to the decrease in the dividend rate. The decrease in the dividend rate in the first quarter of 2014 from $0.03 per quarter to $0.01 per annum reduced dividends paid from $12.7 million during the six months ended June 30, 2013 to $2.1 million during the six months ended June 30, 2014.

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,
	2014	2013
Ratio of earnings to combined fixed charges and preference dividends(1)	N/A	N/A	(2)

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

(2) Total losses for the ratio calculation were $95.5 million and total fixed charges were $200.2 million for the six months ended June 30, 2014. Total losses for the ratio calculation were $80.3 million and total fixed charges were $202.7 million for the six months ended June 30, 2013.

Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Our sales commitments were as follows as of July 25, 2014:

	2014			2015
	Tons	$ per ton		Tons	$ per ton
	(in millions)			(in millions)
Powder River Basin
Committed, Priced	109.8	$	13.00	74.9	$	13.72
Committed, Unpriced	3.6			9.7
Appalachia
Committed, Priced Thermal	7.3	$	57.72	3.4	$	56.71
Committed, Unpriced Thermal	0.2			—
Committed, Priced Metallurgical	6.0	$	82.44	1.6	$	85.53
Committed, Unpriced Metallurgical	0.2			0.3
Other Bituminous
Committed, Priced	7.6	$	31.00	3.3	$	36.32
Committed, Unpriced	0.2			—

We are also exposed to commodity price risk in our coal trading activities, which represents the potential future loss that could be caused by an adverse change in the market value of coal. Our coal trading portfolio included forward, swap and put and call option contracts at June 30, 2014. The estimated future realization of the value of the trading portfolio is $6.3 million of gains in the remainder of 2014 and $2.9 million of gains in 2015.

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

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

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

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

During the six months ended June 30, 2014, VaR for our coal trading positions that are recorded at fair value through earnings ranged from under $0.1 million to $0.8 million. The linear mean of each daily VaR was $0.3 million. The final VaR at June 30, 2014 was $0.4 million.

We are exposed to fluctuations in the fair value of coal derivatives that we enter into to manage the price risk related to future coal sales, but for which we do not elect hedge accounting. Gains or losses on these derivative instruments would be largely offset in the pricing of the physical coal sale. During the six months ended June 30, 2014 VaR for our risk management positions that are recorded at fair value through earnings ranged from $0.1 million to $0.5 million. The linear mean of each daily VaR was $0.3 million. The final VaR at June 30, 2014 was $0.2 million.

Table of Contents

We are also exposed to the risk of fluctuations in cash flows related to our purchase of diesel fuel. We expect to use approximately 57 to 67 million gallons of diesel fuel for use in our operations during 2014. 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, 2014, we had protected the price of approximately 88% of our expected purchases for the remainder of 2014 and 80% of our 2015 purchases through the third quarter. At June 30, 2014, we had purchased heating oil call options for approximately 70 million gallons for the purpose of managing the price risk associated with future diesel purchases. We also purchase heating oil call options to manage the price risk associated with fuel surcharges on barge and rail shipments, which cover increases in diesel fuel prices. At June 30, 2014, we held purchased call options for approximately 3.4 million gallons for the purpose of managing the fluctuations in cash flows associated with fuel surcharges on future shipments. These positions reduce our risk of cash flow fluctuations related to these surcharges but the positions are not accounted for as hedges. 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, 2014, of our $5.1 billion principal amount of debt outstanding, approximately $1.9 billion of outstanding borrowings have interest rates that fluctuate based on changes in the market rates. An increase in the interest rates related to these borrowings of 25 basis points would not result in an annualized increase in interest expense based on interest rates in effect at June 30, 2014, because our term loan has a minimum interest rate that exceeds the current market rates.

Item 4. Controls and Procedures.

We performed an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2014. 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.

Table of Contents

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

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

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

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

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

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

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

EPA Actions Related to Water Discharges from the Spruce Permit

By letter of September 3, 2009, the EPA asked the Corps of Engineers to suspend, revoke or modify the existing permit it issued in January 2007 to Mingo Logan under Section 404 of the Clean Water Act, claiming that “new information and circumstances have arisen which justify reconsideration of the permit.” By letter of September 30, 2009, the Corps of Engineers advised the EPA that it would not reconsider its decision to issue the permit. By letter of October 16, 2009, the EPA advised the Corps that it has “reason to believe” that the Mingo Logan mine will have “unacceptable adverse impacts to fish and wildlife resources” and that it intends to issue a public notice of a proposed determination to restrict or prohibit discharges of fill material that already are approved by the Corps’ permit. By federal register publication dated April 2, 2010, the EPA

Table of Contents

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

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

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

On November 13, 2013, Mingo Logan filed a Petition for Writ of Certiorari with the Supreme Court of the United States seeking review of the DC Circuit’s decision. On March 24, 2014, the Supreme Court denied Mingo Logan’s Petition for Writ of Certiorari. The matter has been remanded to the federal district court for the District of Columbia where it is pending further proceedings on the merits of the Final Determination.

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.

Table of Contents

Allegheny entered into the contract. No new substantive claims were asserted. ICG answered the second amended complaint on October 13, 2009, denying all of the new claims. The Company’s counterclaim was dismissed on motion for summary judgment entered on May 11, 2010. Allegheny’s claims against ICG were also dismissed by summary judgment, but the claims against Wolf Run and Hunter Ridge were not. The court conducted a non-jury trial of this matter beginning on January 10, 2011 and concluding on February 1, 2011.

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, 2014, 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, 2014. Based on the closing price of our common stock as reported on the New York Stock Exchange on July 31, 2014, the approximate dollar value of our common stock that may yet be purchased under this program was $32.4 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, 2014.

Item 6. Exhibits.

12.1		Computation of ratio of earnings to combined fixed charges and preference dividends.
31.1		Rule 13a-14(a)/15d-14(a) Certification of John W. Eaves.
31.2		Rule 13a-14(a)/15d-14(a) Certification of John T. Drexler.
32.1		Section 1350 Certification of John W. Eaves.
32.2		Section 1350 Certification of John T. Drexler.
95.0		Mine Safety Disclosure Exhibit.
101.0		Interactive Data File (Form 10-Q for the six months ended June 30, 2014 filed in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”

		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		34
Item 4. Controls and Procedures		35
Part II OTHER INFORMATION		35
Item 1. Legal Proceedings		35
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		38
Item 4. Mine Safety Disclosures		38
Item 6. Exhibits		38

	Arch Coal, Inc.


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

		August 8, 2014