Arch Resources (ARCH) 10-Q 2011 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2011

oTransition 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

(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 £ No x

At November 7, 2011 there were 211,618,197 shares of the registrant’s common stock outstanding.

Table of Contents

	Page
Part I FINANCIAL INFORMATION	3
Item 1. Financial Statements	3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3. Quantitative and Qualitative Disclosures About Market Risk	39
Item 4. Controls and Procedures	41
Part II OTHER INFORMATION	41
Item 1. Legal Proceedings	41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3. Defaults Upon Senior Securities	45
Item 4. Reserved	45
Item 5. Other Information	45
Item 6. Exhibits	47

2

Part I

FINANCIAL INFORMATION

Item 1.      Financial Statements.

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Statements of Income

(in thousands, except per share data)

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
	(unaudited)
REVENUES	$	1,198,673		$	874,705		$	3,057,139		$	2,350,874
COSTS, EXPENSES AND OTHER
Cost of sales	952,850			651,853			2,322,124			1,773,464
Depreciation, depletion and amortization	123,026			92,857			301,746			269,135
Amortization of acquired sales contracts, net	(12,186		)	10,038			(4,753		)	26,005
Selling, general and administrative expenses	33,276			26,999			92,750			89,509
Change in fair value of coal derivatives and coal trading activities, net	8,360			1,832			9,248			12,296
Acquisition and transition costs related to ICG	4,694			—			53,360			—
Gain on Knight Hawk transaction	—			—			—			(41,577		)
Other operating income, net	(3,613		)	(7,221		)	(9,019		)	(15,004		)
	1,106,407			776,358			2,765,456			2,113,828
Income from operations	92,266			98,347			291,683			237,046
Interest expense, net:
Interest expense	(77,694		)	(37,698		)	(154,523		)	(107,906		)
Interest income	840			927			2,341			1,888
	(76,854		)	(36,771		)	(152,182		)	(106,018		)
Other non-operating expense:
Bridge financing costs related to ICG	—			—			(49,490		)	—
Net loss resulting from early retirement of debt	(1,708		)	(6,776		)	(1,958		)	(6,776		)
	(1,708		)	(6,776		)	(51,448		)	(6,776		)
Income before income taxes	13,704			54,800			88,053			124,252
Provision for (benefit from) income taxes	(5,583		)	7,941			5,103			12,889
Net income	19,287			46,859			82,950			111,363
Less: Net income attributable to noncontrolling interest	(231		)	(181		)	(822		)	(325		)
Net income attributable to Arch Coal, Inc.	$	19,056		$	46,678		$	82,128		$	111,038
EARNINGS PER COMMON SHARE
Basic earnings per common share	$	0.09		$	0.29		$	0.45		$	0.68
Diluted earnings per common share	$	0.09		$	0.29		$	0.45		$	0.68
Basic weighted average shares outstanding	211,337			162,391			182,898			162,384
Diluted weighted average shares outstanding	211,974			163,174			183,850			163,128
Dividends declared per common share	$	0.11		$	0.10		$	0.32		$	0.29

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

3

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except per share data)

	September 30,			December 31,
	2011			2010
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	158,509		$	93,593
Restricted cash	21,428			—
Trade accounts receivable	342,721			208,060
Other receivables	83,579			44,260
Inventories	346,331			235,616
Prepaid royalties	29,163			33,932
Deferred income taxes	15,795			—
Coal derivative assets	2,595			15,191
Other	107,462			104,262
Total current assets	1,107,583			734,914
Property, plant and equipment, net	7,703,280			3,308,892
Other assets:
Prepaid royalties	96,869			66,525
Goodwill	539,963			114,963
Deferred income taxes	9,217			361,556
Equity investments	224,684			177,451
Other	173,665			116,468
Total other assets	1,044,398			836,963
Total assets	$	9,855,261		$	4,880,769
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	293,446		$	198,216
Coal derivative liabilities	5,824			4,947
Deferred income taxes	—			7,775
Accrued expenses and other current liabilities	379,707			245,411
Current maturities of debt and short-term borrowings	47,156			70,997
Total current liabilities	726,133			527,346
Long-term debt	3,841,330			1,538,744
Asset retirement obligations	415,877			334,257
Accrued pension benefits	16,235			49,154
Accrued postretirement benefits other than pension	88,820			37,793
Accrued workers’ compensation	64,421			35,290
Deferred income taxes	880,487			—
Other noncurrent liabilities	277,490			110,234
Total liabilities	6,310,793			2,632,818
Redeemable noncontrolling interest	11,261			10,444
Stockholders’ equity:
Common stock, $0.01 par value, authorized 260,000 shares, issued 213,099 shares and 164,117 shares, respectively	2,135			1,645
Paid-in capital	3,012,628			1,734,709
Treasury stock, 1,512 shares at September 30, 2011 and December 31, 2010, at cost	(53,848		)	(53,848		)
Retained earnings	586,067			561,418
Accumulated other comprehensive loss	(13,775		)	(6,417		)
Total stockholders’ equity	3,533,207			2,237,507
Total liabilities and stockholders’ equity	$	9,855,261		$	4,880,769

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

4

Arch Coal, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(in thousands)

	Nine Months Ended September 30
	2011			2010
	(unaudited)
OPERATING ACTIVITIES
Net income	$	82,950		$	111,363
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	301,746			269,135
Amortization of acquired sales contracts, net	(4,753		)	26,005
Bridge financing costs related to ICG	49,490			—
Net loss resulting from early retirement of debt	1,958			6,776
Write down of assets acquired from ICG	7,316			—
Prepaid royalties expensed	26,880			26,190
Employee stock-based compensation expense	9,019			9,640
Amortization relating to financing activities	9,854			6,630
Gain on Knight Hawk transaction	—			(41,577		)
Changes in:
Receivables	(35,874		)	(48,718		)
Inventories	(23,716		)	21,818
Coal derivative assets and liabilities	15,199			14,116
Accounts payable, accrued expenses and other current liabilities	3,742			20,879
Income taxes, net	(21,971		)	(1,923		)
Deferred income taxes	23,572			(7,561		)
Other	25,955			43,907
Cash provided by operating activities	471,367			456,680
INVESTING ACTIVITIES
Acquisition of ICG, net of cash acquired	(2,894,339		)	—
Increase in restricted cash	(5,939		)	—
Capital expenditures	(215,899		)	(221,583		)
Proceeds from dispositions of property, plant and equipment	25,133			252
Purchases of investments and advances to affiliates	(56,827		)	(16,740		)
Additions to prepaid royalties	(26,135		)	(23,715		)
Cash used in investing activities	(3,174,006		)	(261,786		)
FINANCING ACTIVITIES
Proceeds from the issuance of senior notes	2,000,000			500,000
Proceeds from the issuance of common stock, net	1,267,776			—
Payments to retire debt	(604,096		)	(505,627		)
Net increase (decrease) in borrowings under lines of credit and commercial paper program	283,096			(118,337		)
Net payments on other debt	(8,792		)	(9,794		)
Debt financing costs	(114,587		)	(12,630		)
Dividends paid	(57,470		)	(47,121		)
Issuance of common stock under incentive plans	1,628			339
Contribution from noncontrolling interest	—			891
Cash provided by (used in) financing activities	2,767,555			(192,279		)
Increase in cash and cash equivalents	64,916			2,615
Cash and cash equivalents, beginning of period	93,593			61,138
Cash and cash equivalents, end of period	$	158,509		$	63,753

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

5

Arch Coal, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

1. Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Arch Coal, Inc. and its subsidiaries and controlled entities (the “Company”). The Company’s primary business is the production of steam and metallurgical coal from surface and underground mines located throughout the United States, for sale to utility, industrial and export markets. On June 15, 2011, the Company acquired International Coal Group, Inc. (“ICG”), as described in Note 3, “Business Combinations”.  The Company operates 23 mining complexes in West Virginia, Kentucky, Maryland, Virginia, Illinois, Wyoming, Colorado and Utah. All subsidiaries (except as noted below) are wholly-owned. Intercompany transactions and accounts have been eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial reporting and U.S. Securities and Exchange Commission regulations. In the opinion of management, all adjustments, consisting of normal, recurring accruals considered necessary for a fair presentation, have been included. Results of operations for the three and nine month periods ended September 30, 2011 are not necessarily indicative of results to be expected for the year ending December 31, 2011. 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, 2010 included in the Company’s Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission.

The Company owns a 99% membership interest in a joint venture named Arch Western Resources, LLC (“Arch Western”) which operates coal mines in Wyoming, Colorado and Utah. The Company also acts as the managing member of Arch Western.

2. Accounting Policies

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

3. Business Combination

On June 15, 2011, the Company completed its acquisition of ICG, a leading coal producer, operating 12 mining complexes in Appalachia and one complex in the Illinois Basin.  In addition, one mine is currently under development in Appalachia.  The Company acquired all of ICG’s outstanding shares of common stock for $3.1 billion. To finance the acquisition, the Company received net proceeds of $1.25 billion from the sale of 48.0 million shares of its common stock and issued $2.0 billion in aggregate principal amount of senior unsecured notes.  See Note 4, “Equity Offering” and Note 5, “Debt and Financing Arrangements” for further information about these transactions.

The Company has not finalized the determination of the fair values of the assets acquired and liabilities assumed in the acquisition.  The following table summarizes the consideration paid for ICG and the estimated amounts of assets acquired and liabilities assumed that were recognized at the acquisition date:

6

	(In millions)
Consideration paid, net of cash acquired	$	2,894.4
Recognized amounts of net tangible and intangible assets acquired and liabilities assumed:
Restricted cash	15.5
Receivables	114.2
Inventories	87.0
Net property, plant and equipment, including mineral rights	4,510.6
Goodwill	425.0
Other assets	49.2
Accounts payable	(82.6		)
Other accrued expenses and current liabilities	(61.5		)
Debt	(604.8		)
Litigation accrual	(106.0		)
Accrued postretirement benefits	(47.7		)
Asset retirement obligation	(80.4		)
Coal supply agreements, net	(98.8		)
Deferred income taxes, net	(1,189.9		)
Other	(35.4		)
Net tangible and intangible assets acquired	$	2,894.4

During the third quarter of 2011, the following adjustments were made to the purchase price and the provisional fair values:

	(In millions)
Inventories	9.5
Net property, plant and equipment, including mineral rights	(5.8		)
Coal supply agreements, net	(21.2		)
Other	1.5
Purchase price adjustment — cash received	$	(16.0	)

The adjustments to the provisional fair values result from additional information obtained about facts in existence at the acquisition date.  Adjustments to provisional fair values are assumed to have been made as of the acquisition date.  As a result, cost of sales for the second quarter of 2011 would have been $5.6 million higher than was previously reported. The results in the condensed consolidated statements of income reflect this adjustment as if it had been recorded originally in the second quarter of 2011.

The Company’s efforts to value the assets acquired and liabilities assumed are ongoing.    Notably, the valuation report that will support the fair value of the fixed assets, coal reserves and goodwill acquired has not yet been completed.  The estimated assigned value of goodwill in the table above represents the present value of the estimated synergies from the acquisition. The fair values above could change substantially when the valuation report is received.

Any goodwill related to the acquisition is not expected to be deductible for tax purposes.  The allocation of goodwill to reporting units will not be completed until the valuation process is completed.

The revenues and income before income taxes related to the acquired operations that have been included in the consolidated statements of income for the three months ended September 30, 2011 were $295.6 million and $34.9 million, respectively.  The revenues and income before income taxes related to the acquired operations that have been included in the consolidated statements of income since the date of acquisition were $343.6 million and $43.6 million, respectively.

The following unaudited pro forma information has been prepared for illustrative purposes and assumes that the business combination occurred on January 1, 2010.  The unaudited pro forma results have been prepared based upon ICG’s historical results and estimates of the ongoing effects of the transactions that the Company believes are reasonable and supportable.  The results are not necessarily reflective of the consolidated results of operations had the acquisition actually occurred on January 1, 2010, nor are they indicative of future operating results.

7

The unaudited supplemental pro forma financial information of the combined entity follows:

	Three Months Ended September 30				Nine Months Ended September 30
	2011		2010		2011		2010
	(In millions)
Total revenues
As reported	$	1,198.7	$	874.7	$	3,057.1	$	2,350.9
Pro forma	$	1,198.7	$	1,176.9	$	3,596.8	$	3,212.6
Income (loss) before income taxes
As reported	$	13.7	$	54.8	$	88.1	$	124.3
Pro forma	$	22.3	$	47.5	$	72.6	$	(66.9	)

The pro forma income before income taxes includes adjustments to operating costs to reflect the new basis in assets acquired and interest expense to reflect the debt incurred to finance the acquisition.  In addition, the following pre-tax costs and expenses reflected in the income before income taxes for the three and nine month periods ended September 30, 2011 reported in the condensed consolidated statement of income are reflected in the pro forma results as of January 1, 2010.

	Three Months Ended September 30, 2011		Nine Months Ended September 30, 2011
	(In thousands)
Costs of completing the acquisition - Arch	$	1,717	$	29,569
Costs of completing the acquisition - ICG	—		23,503
Severance costs	2,977		16,475
Write off of acquired assets	—		7,316
Bridge financing fees	—		49,490
	$	4,694	$	126,353

Severance costs represent both change in control payments to executives and severance for employees terminated after the acquisition.  The acquired asset write-off relates to a preparation plant and loadout of an acquired ICG mining operation.  The acquired operation has been combined with an existing operation of the Company, and will utilize an existing facility.

Anticipated synergies are not reflected in the pro forma results.

In conjunction with the acquisition, the Company has $21.4 million of restricted cash at September 30, 2011 to provide collateral for ICG letters of credit until they can be eliminated or replaced and to fund change in control payments for executives and the board of directors.

4.  Equity Offering

On June 8, 2011, the Company sold 48 million shares of its common stock at a public offering price of $27.00 per share.  The $1.25 billion in net proceeds from the issuance were used to finance the acquisition of ICG.  On July 8, 2011, the Company issued an additional 0.7 million shares of its common stock under the same terms and conditions to cover underwriters’ over-allotments for net proceeds of $18.4 million.

8

5.  Debt

	September 30,2011		December 31,2010
	(In thousands)
Commercial paper	$	—	$	56,904
Indebtedness to banks under credit facilities	340,000		—
6.75% senior notes ($450.0 million face value) due July 1, 2013	451,132		451,618
8.75% senior notes ($600.0 million face value) due August 1, 2016	588,496		587,126
7.00% senior notes due June 15, 2019 at par	1,000,000		—
7.25% senior notes due October 1, 2020 at par	500,000		500,000
7.25% senior notes due June 15, 2021 at par	1,000,000		—
Other	8,858		14,093
	3,888,486		1,609,741
Less current maturities of debt and short-term borrowings	47,156		70,997
Long-term debt	$	3,841,330	$	1,538,744

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

2019 and 2021 Senior Notes

On June 14, 2011, the Company entered into an indenture in conjunction with the issuance of the 7.00% senior notes due 2019 (“2019 Notes”) and the 7.25% senior notes due 2021 (“2021 Notes”) as discussed in Note 3, “Business Combinations.” Interest is payable on the 2019 Notes and 2021 Notes on June 15 and December 15 of each year, commencing December 15, 2011.

At any time prior to June 15, 2014, the Company may redeem up to 35% of the aggregate principal amount of each of the 2019 Notes and 2021 Notes, plus accrued and unpaid interest, with the net proceeds from certain equity offerings. The Company may redeem the 2019 Notes prior to June 15, 2015 and the 2021 Notes prior to June 15, 2016 at the respective make-whole prices set forth in the indenture. On or after June 15, 2015, the Company may redeem the 2019 Notes for cash at redemption prices, reflected as a percentage of the principal amount, of: 103.5% from June 15, 2015 through June 14, 2016; 101.75% from June 15, 2016 through June 14, 2017; and 100% beginning on June 15, 2017.  On or after June 15, 2016, the Company may redeem the 2021 Notes for cash at redemption prices, reflected as a percentage of the principal amount, of: 103.625% from June 15, 2016 through June 14, 2017; 102.417% from June 15, 2017 through June 14, 2018; 101.208% from June 15, 2018 through June 14, 2019 and 100% beginning on June 15, 2019. In each case, accrued and unpaid interest at the redemption date is due upon redemption. Upon a change in control, the Company is required to make a tender offer for both series of notes at a price of 101% of the principal amount.

The 2019 Notes and 2021 Notes are guaranteed by substantially all of the Company’s subsidiaries, including the newly acquired subsidiaries of ICG and excluding Arch Western, its subsidiaries and Arch Receivable Company, LLC and the Company’s subsidiaries outside the U.S. The Company incurred financing fees of $44.2 million related to the issuance of these notes.

The Company and the guarantor subsidiaries entered into a registration rights agreement (the “Registration Rights Agreement”) in connection with the issuance and sale of the 2019 Notes and 2021 Notes. Pursuant to the Registration Rights Agreement, the Company and the guarantor subsidiaries agreed to file a registration statement with the Securities and Exchange Commission to register an exchange offer pursuant to which the Company will offer to exchange a like aggregate principal amount of senior notes identical in all material respects to the 2019 Notes and 2021 Notes, except for terms relating to additional interest and transfer restrictions, for any or all of the outstanding 2019 Notes and 2021 Notes. Pursuant to the Registration Rights Agreement, the Company must use commercially reasonable efforts to cause the registration statement to become effective as soon as practicable and to complete the exchange offer no later than June 13, 2012. Should those events not occur within the specified time frame, the applicable interest rates on the 2019 Notes and the 2021 Notes shall be increased by one-quarter of one percent per annum for the first 90 days following the occurrence of such failure.  Such interest rate will increase by an additional one-quarter of one percent per annum thereafter at the end of each subsequent 90-day period up to a maximum aggregate increase of one percent per annum. Once any of the required events occur, the interest rates will revert to the rate specified in the indenture governing the 2019 Notes and 2021 Notes.

ICG Debt

Upon the closing of the ICG acquisition, the Company gave a 30-day redemption notice to the Trustee of ICG’s 9.125% senior notes and legally discharged its obligation under the 9.125% senior notes by depositing $260.7 million with the Trustee to redeem the debt. On July 14, 2011, all of the outstanding 9.125% senior notes were redeemed at an aggregate price of $251.4 million, including the required make-whole premium, plus accrued interest of $5.2 million, and the remainder of the deposit was returned to the Company.

9

At the acquisition date, ICG’s 4.00% convertible senior notes with a fair value of $298.5 million and 9.00% convertible senior notes with a fair value of $1.7 million (“convertible notes”) became convertible into cash, pursuant to the amended indentures governing the convertible notes, at a calculated conversion rate of $2,614.6848 for each $1,000 in principal amount surrendered for conversion for the 4.00% convertible notes and $2,392.73414 for the 9.00% convertible notes for conversions occurring prior to August 17, 2011.

Other ICG debt, with a fair value of approximately $54.0 million at the acquisition date, consisted mainly of equipment notes and insurance notes payable.

The Company recognized net losses of $1.7 million and $2.0 million during the three and nine months ended September 30, 2011, respectively on the early extinguishment of ICG’s debt, including the conversions of the 4.00% and 9.00% convertible notes described above. The remaining amounts outstanding under the convertible notes and other ICG debt is included in “other” in the debt table above.

Credit Facilities and Commercial Paper

On June 14, 2011, the Company amended and restated its secured credit facility to allow for up to $2.0 billion in borrowings.   Borrowings under this credit facility bear interest at a floating rate based on LIBOR determined by reference to the Company’s leverage ratio, as calculated in accordance with the credit agreement.  The credit facility has a five-year term that expires on June 14, 2016 and is secured by substantially all of the Company’s assets as well as its ownership interests in substantially all of its subsidiaries, excluding its ownership interests in Arch Western and its subsidiaries. Commitment fees of 0.50% per annum are payable on the average unused daily balance of the revolving credit facility. The Company paid and deferred $20.7 million in financing fees related to the amendment of this agreement.  Financial covenant requirements may restrict the amount of unused capacity available to the Company for borrowings and letters of credit.

On June 14, 2011, the Company terminated its commercial paper placement program and the supporting credit facility.

Availability

As of September 30, 2011 the Company had $300.0 million of borrowings outstanding under the amended and restated secured credit facility and $40.0 million of borrowings outstanding under its accounts receivable securitization program.  As of September 30, 2011, the Company had availability of approximately $1.0 billion under all lines of credit, as limited by customary financial covenants that may limit the Company’s total debt based on defined earnings measurements.   The Company also had outstanding letters of credit of $141.0 million as of September 30, 2011.

6. Acquired Sales Contracts

Coal supply agreements (sales contracts) acquired in a business combination are capitalized at their fair value and amortized over the tons of coal shipped during the term of the contract. The fair value of a sales contract is determined by discounting the cash flows attributable to the difference between the contract price and the prevailing forward prices for the tons under contract at the date of acquisition. Below are the acquired sales contracts reflected in the condensed consolidated balance sheets:

	September 30, 2011						December 31, 2010
	Assets			Liabilities			Assets			Liabilities
	(In thousands)						(In thousands)
Acquired fair value	$	145,213		$	170,341		$	114,453		$	40,654
Accumulated amortization	(105,845		)	(42,877		)	(82,376		)	(14,613		)
Total	$	39,368		$	127,464		$	32,077		$	26,041
Net total				$	88,096		$	6,036
Balance Sheet classification:
Other current	$	23,474		$	58,049		$	25,063		$	5,615
Other noncurrent	$	15,894		$	69,415		$	7,014		$	20,426

Above-market contracts with a fair value of $30.8 million and below-market contracts with a fair value of $129.7 million were acquired from ICG. Of these amounts, $13.7 million and $52.3 million were classified as current assets and current liabilities, respectively, at September 30, 2011.  See Note 3, “Business Combinations” for discussion of purchase price adjustments.

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The Company anticipates amortization income of all acquired sales contracts, based upon the fair value assigned to acquired ICG sales contracts and expected shipments in the next five years, to be approximately $29 million for the remainder of 2011, $20 million in 2012, $7 million in 2013, $8 million in 2014, $13 million in 2015 and $8 million in 2016.

7. Equity Investments and Membership Interests in Joint Ventures

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

	Knight Hawk			DKRW			DTA			Tenaska			Millennium			Tongue River		Total
	(In thousands)
Balance at December 31, 2010	$	131,250		$	21,961		$	14,472		$	9,768		$	—		$	—	$	177,451
Investments in affiliates	—			—			—			5,500			25,000			12,989		43,489
Advances to (distributions from) affiliates, net	(11,450		)	—			4,394			—			1,900			—		(5,156		)
Equity in comprehensive income (loss)	15,807			(1,631		)	(3,713		)	(2		)	(1,561		)	—		8,900
Balance at September 30, 2011	$	135,607		$	20,330		$	15,153		$	15,266		$	25,339		$	12,989	$	224,684
Notes receivable from investees:
Balance at December 31, 2010	$	1,700		$	18,100		$	—		$	4,100		$	—		$	—	$	23,900
Balance at September 30, 2011	—			28,417			—			4,777			—			—		33,194

In July 2011, the Company purchased a 33% membership interest in the Tongue River Holding Company, LLC (“Tongue River”) joint venture.  Tongue River will construct and develop a railway line near Miles City, Montana and the Company’s Otter Creek reserves.  The Company has the right, upon completion of the railway line or under other prescribed circumstances, to require the other investors to purchase all of the Company’s units in the venture at an amount equal to the capital contributions made by the Company at that time, less any distributions received.

In January 2011, the Company purchased a 38% ownership interest in Millennium Bulk Terminals-Longview, LLC (“Millennium”), the owner of a brownfield bulk commodity terminal on the Columbia River near Longview, Washington, for $25.0 million, plus additional future consideration upon the completion of certain project milestones. Millennium continues to work on obtaining the required approvals and necessary permits to complete dredging and other upgrades to enable coal, alumina and cementitious material shipments through the terminal. The Company will control 38% of the terminal’s throughput and storage capacity, in order to facilitate export shipments of coal off the west coast of the United States.

The Company may be required to make future contingent payments of up to $70.9 million related to development financing for certain of its equity investees. The Company’s obligation to make these payments, as well as the timing of any payments required, is contingent upon a number of factors, including project development progress, receipt of permits and construction financing.

8. Derivatives

The Company generally utilizes derivative financial instruments to manage exposures to commodity prices. Additionally, the Company may hold certain coal derivative financial instruments for trading purposes.

All derivative financial instruments are recognized in the balance sheet at fair value. In a fair value hedge, the Company hedges the risk of changes in the fair value of a firm commitment, typically a fixed-price coal sales contract. Changes in both the hedged firm commitment and the fair value of a derivative used as a hedge instrument in a fair value hedge are recorded in earnings. In a cash flow hedge, the Company hedges the risk of changes in future cash flows related to a forecasted purchase or sale. Changes in the fair value of the derivative instrument used as a hedge instrument in a cash flow hedge are recorded in other comprehensive income. Amounts in other comprehensive income are reclassified to earnings when the hedged transaction affects earnings and are classified in a manner consistent with the transaction being hedged. The Company formally documents the relationships between hedging instruments and the respective hedged items, as well as its risk management objectives for hedge transactions.

The Company evaluates the effectiveness of its hedging relationships both at the hedge’s inception and on an ongoing basis. Any ineffective portion of the change in fair value of a derivative instrument used as a hedge instrument in a fair value or cash flow hedge is recognized immediately in earnings. The ineffective portion is based on the extent to which exact offset is not achieved between the change in fair value of the hedge instrument and the cumulative change in expected future cash flows on the hedged transaction from inception of the hedge in a cash flow hedge or the change in the fair value of the firm commitment in a fair value hedge.

11

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 90 to 100 million gallons of diesel fuel for use in its operations during 2012. To reduce the volatility in the price of diesel fuel for its operations, the Company uses forward physical diesel purchase contracts, as well as heating oil swaps and purchased call options. At September 30, 2011, the Company had protected the price of approximately 70% of its expected purchases for the remainder of fiscal year 2011 and 55% for fiscal year 2012.

At September 30, 2011, the Company held heating oil swaps and purchased call options for approximately 68 million gallons for the purpose of managing the price risk associated with future diesel purchases. Since the changes in the price of heating oil highly correlate to changes in the price of the hedged diesel fuel purchases, the heating oil swaps and purchased call options qualify for cash flow hedge accounting.

The Company also purchased call options to hedge the fuel surcharges on its barge and rail shipments that cover increases in diesel fuel prices.  These positions reduce the Company’s risk of cash flow fluctuations related to these surcharges but the positions are not accounted for as hedges.  At September 30, 2011, Company held purchased call options for approximately 19.1 million gallons for the purpose of managing the fluctuations in cash flows associated with fuel surcharges on future shipments.

Coal risk management positions

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

At September 30, 2011, the Company held derivatives for risk management purposes totaling 0.5 million tons of coal sales and 0.5 million tons of coal purchases that are expected to settle during the remainder of 2011, 1.7 million tons of coal sales and 0.2 million tons of coal purchases that are expected to settle in 2012, 0.7 million tons of coal sales that are expected to settle in 2013, 1.4 million tons of coal sales that are expected to settle in 2014 and 0.7 million tons of coal sales that are expected to settle in 2015.

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 $2.4 million of gains for the remainder of 2011, $0.9 million of losses in 2012 and $1.0 million of losses in 2013.

Tabular derivatives disclosures

The Company’s contracts with certain of its counterparties to 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, regardless of 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:

12

Fair Value of Derivatives

(in thousands)

	September 30, 2011								December 31, 2010
	AssetDerivative			LiabilityDerivative					AssetDerivative			LiabilityDerivative
Derivatives Designated as Hedging Instruments
Heating oil — diesel purchases	$	9,352		$	—				$	13,475		$	—
Coal	2,708			(1,270		)			2,009			(2,350		)
Total	12,060			(1,270		)			15,484			(2,350		)
Derivatives Not Designated as Hedging Instruments
Heating oil — fuel surcharges	2,202			—					—			—
Coal — held for trading purposes	10,862			(10,365		)			34,445			(24,087		)
Coal	1,812			(6,976		)			1,139			(912		)
Total	14,876			(17,341		)			35,584			(24,999		)
Total derivatives	26,936			(18,611		)			51,068			(27,349		)
Effect of counterparty netting	(12,787		)	12,787					(22,402		)	22,402
Net derivatives as classified in the balance sheets	$	14,149		$	(5,824	)	$	8,325	$	28,666		$	(4,947	)	$	23,719

Net derivatives as reflected on the balance sheets

		September 30, 2011			December 31, 2010
Heating oil	Other current assets	$	11,554		$	13,475
Coal	Coal derivative assets	2,595			15,191
	Coal derivative liabilities	(5,824		)	(4,947		)
		$	8,325		$	23,719

The Company had a current asset for the right to reclaim cash collateral of $10.7 million and $10.3 million at September 30, 2011 and December 31, 2010, respectively. These amounts are not included with the derivatives presented in the table above and are included in “other current assets” in the accompanying condensed consolidated balance sheets.

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

Three Months Ended September 30

(in thousands)

Derivatives used inCash Flow Hedging	Gain (Loss)Recognized in OCI(Effective Portion)						Gains (Losses)Reclassified fromOCI into Income(Effective Portion)						Gain (Loss)Recognized inIncome (IneffectivePortion and AmountExcluded fromEffectiveness Testing)
Relationships	2011			2010			2011			2010			2011		2010
Heating oil — diesel purchases	$	(6,386	)	$	3,052		$	5,122	(2)	$	93	(2)	$	—	$	—
Coal sales	1,820			1,500			466		(1)	(226		)(1)	—		—
Coal purchases	(1,274		)	(2,535		)	—		(2)	(866		)(2)	—		—
Totals	$	(5,840	)	$	2,017		$	5,588		$	(999	)	$	—	$	—

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Derivatives Not Designated as	Gain (Loss)
Hedging Instruments	2011			2010
Coal — unrealized	$	(6,131	)(3)	$	(993	)(3)
Coal — realized	$	166	(4)	$	1,079	(4)
Heating oil — fuel surcharges — unrealized	$	(2,501	)(4)	$	—	(4)

Location in Statement of Income:

(1)Revenues

(2)Cost of sales

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

(4)Other operating income, net

During the three months ended September 30, 2011 and 2010, the Company recognized net unrealized and realized losses of $2.2 million and $0.8 million, respectively, related to its trading portfolio (including derivative and non-derivative contracts). These balances are included in the caption “Change in fair value of coal derivatives and coal trading activities, net” in the accompanying condensed consolidated statements of income and are not included in the previous table.

Nine Months Ended September 30

(in thousands)

Derivatives used inCash Flow Hedging	Gain (Loss)Recognized in OCI(Effective Portion)						Gains (Losses)Reclassified fromOCI into Income(Effective Portion)						Gain (Loss)Recognized inIncome (IneffectivePortion and AmountExcluded fromEffectiveness Testing)
Relationships	2011			2010			2011			2010			2011		2010
Heating oil — diesel purchases	$	1,535		$	(5,508	)	$	14,946	(2)	$	(211	)(2)	$	—	$	—
Coal sales	4,570			(6,138		)	790		(1)	(1,556		)(1)	—		—
Coal purchases	(2,053		)	5,534			—		(2)	(1,202		)(2)	—		—
Totals	$	4,052		$	(6,112	)	$	15,736		$	(2,969	)	$	—	$	—

Derivatives Not Designated as	Gain (Loss)
Hedging Instruments	2011			2010
Coal — unrealized	$	(7,550	)(3)	$	(9,381	)(3)
Coal — realized	$	313	(4)	$	3,931	(4)
Heating oil — fuel surcharges — unrealized	$	(2,501	)(4)	$	—	(4)

Location in Statement of Income:

(1)Revenues

(2)Cost of sales

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

(4)Other operating income, net

During the nine months ended September 30, 2011 and 2010, the Company recognized net unrealized and realized losses of $1.7 million and $2.9 million, respectively, related to its trading portfolio (including derivative and non-derivative contracts). These balances are included in the caption “Change in fair value of coal derivatives and coal trading activities, net” in the accompanying condensed consolidated statements of income and are not included in the previous table.

During the next twelve months, based on fair values at September 30, 2011, gains on derivative contracts designated as hedge instruments in cash flow hedges of approximately $9.3 million are expected to be reclassified from other comprehensive income into earnings.

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9. Inventories

Inventories consist of the following:

	September 30, 2011		December 31, 2010
	(In thousands)
Coal	$	180,988	$	115,647
Repair parts and supplies, net of allowance	165,343		119,969
	$	346,331	$	235,616

The repair parts and supplies are stated net of an allowance for slow-moving and obsolete inventories of $13.4 million at September 30, 2011, and $12.7 million at December 31, 2010.

10. Fair Value Measurements

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

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

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

·Level 3 is defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. These include the Company’s commodity option contracts (primarily coal and heating oil) valued using modeling techniques, such as Black-Scholes, that require the use of inputs, particularly volatility, that are rarely observable.

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

	Fair Value at September 30, 2011
	Total		Level 1		Level 2			Level 3
	(In thousands)
Assets:
Investments in equity securities	$	5,351	$	5,351	$	—		$	—
Derivatives	14,149		1,018		2,695			10,436
Total assets	$	19,500	$	6,369	$	2,695		$	10,436
Liabilities:
Derivatives	$	5,824	$	—	$	(415	)	$	6,239

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

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

	Three Months Ended September 30, 2011			Nine Months Ended September 30, 2011
	(In thousands)
Balance, beginning of period	$	10,474		$	9,183
Realized and unrealized losses recognized in earnings, net	(8,016		)	(15,140		)
Realized and unrealized losses recognized in other comprehensive income, net	(6,702		)	(3,227		)
Purchases	9,935			20,407
Issuances	—			(2,160		)
Settlements	(1,494		)	(4,866		)
Balance, end of period	$	4,197		$	4,197

Net unrealized losses during the three and nine month periods ended September 30, 2011 related to level 3 financial instruments held on September 30, 2011 were $11.7 million and $14.7 million, respectively.

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Fair Value of Long-Term Debt

At September 30, 2011 and December 31, 2010, the fair value of the Company’s senior notes and other long-term debt, including amounts classified as current, was $3.9 billion and $1.7 billion, respectively. Fair values are based upon observed prices in an active market when available or from valuation models using market information.

11. Stock-Based Compensation and Other Incentive Plans

During the nine months ended September 30, 2011, the Company granted options to purchase approximately 0.7 million shares of common stock with a weighted average exercise price of $32.18 per share and a weighted average grant-date fair value of $14.18 per share. The options’ fair value was determined using the Black-Scholes option pricing model, using a weighted average risk-free rate of 1.92%, a weighted average dividend yield of 1.25% and a weighted average volatility of 57.43%. The options’ expected life is 4.5 years and the options vest ratably over three years. The options provide for the continuation of vesting after retirement for recipients that meet certain criteria. The expense for these options will be recognized through the date that the employee first becomes eligible to retire and is no longer required to provide service to earn all or part of the award. The Company also granted 130,950 shares of restricted stock during the nine months ended September 30, 2011 at a weighted average grant-date fair value of $31.30 per share. The restricted stock vests after three years.

The Company has a long-term incentive program (“LTI plan”) that allows for the award of performance units. The total number of units earned by a participant is based on financial and operational performance measures, and may be paid out in cash or in shares of the Company’s common stock. The Company recognizes compensation expense over the three-year term of the grant. Amounts unpaid for all grants under the LTI plan totaled $10.0 million and $6.4 million as of September 30, 2011 and December 31, 2010, respectively.

The Company recognized compensation expense from all stock-based and LTI plans of $3.4 million for the three months ended September 30, 2011 and 2010, respectively. The Company recognized compensation expense from all stock-based and LTI plans of $12.6 million and $12.3 million for the nine months ended September 30, 2011 and 2010, respectively. These expenses are primarily included in selling, general and administrative expenses in the accompanying condensed consolidated statements of income.

12. Workers’ Compensation Expense

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

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
	(In thousands)						(In thousands)
Self-insured occupational disease benefits:
Service cost	$	807		$	182		$	1,246		$	545
Interest cost	619			169			1,177			507
Net amortization	(109		)	(465		)	(370		)	(1,395		)
Total occupational disease	1,317			(114		)	2,053			(343		)
Traumatic injury claims and assessments	5,207			2,642			10,856			6,562
Total workers’ compensation expense	$	6,524		$	2,528		$	12,909		$	6,219

13. Employee Benefit Plans

The following table details the components of pension benefit costs:

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
	(In thousands)						(In thousands)
Service cost	$	4,122		$	3,967		$	12,367		$	11,902
Interest cost	4,063			3,955			12,190			11,866
Expected return on plan assets	(5,453		)	(4,848		)	(16,359		)	(14,544		)
Amortization of prior service cost (credit)	(47		)	44			(142		)	130
Amortization of other actuarial losses	2,187			1,782			6,561			5,348
Net benefit cost	$	4,872		$	4,900		$	14,617		$	14,702

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

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
	(In thousands)						(In thousands)
Service cost	$	1,493		$	378		$	2,416		$	1,132
Interest cost	1,125			520			2,152			1,562
Amortization of prior service credits	(636		)	(591		)	(1,773		)	(1,773		)
Amortization of other actuarial gains	(775		)	(729		)	(2,325		)	(2,188		)
Net benefit cost (credit)	$	1,207		$	(422	)	$	470		$	(1,267	)

14. Comprehensive Income

Comprehensive income consists of net income and other comprehensive income. Other comprehensive income items are transactions recorded in stockholders’ equity during the year, excluding net income and transactions with stockholders.

The following table presents the components of comprehensive income:

	Three Months Ended September 30					Nine Months Ended September 30
	2011			2010		2011			2010
	(In thousands)					(In thousands)
Net income attributable to Arch Coal, Inc.	$	19,056		$	46,678	$	82,128		$	111,038
Other comprehensive income, net of income taxes:
Pension, postretirement and other post-employment benefits, reclassifications into net income	388			28		1,254			84
Unrealized gains (losses) on available-for-sale securities	(569		)	738		(1,256		)	(178		)
Unrealized gains and losses on derivatives, net of reclassifications into net income:
Unrealized gains (losses) on derivatives	(3,671		)	1,200		2,703			(3,889		)
Reclassifications of (gains) losses into net income	(3,575		)	639		(10,059		)	1,856
Total comprehensive income	$	11,629		$	49,283	$	74,770		$	108,911

15. Earnings per Common Share

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

	Three Months Ended September 30		Nine Months Ended September 30
	2011	2010	2011	2010
	(In thousands)		(In thousands)
Weighted average shares outstanding:
Basic weighted average shares outstanding	211,337	162,391	182,898	162,384
Effect of common stock equivalents under incentive plans	637	783	952	744
Diluted weighted average shares outstanding	211,974	163,174	183,850	163,128

The effect of options to purchase 3.0 million and 3.4 million shares of common stock were excluded from the calculation of diluted weighted average shares outstanding for the three month periods ended September 30, 2011 and 2010, respectively, because the exercise price of these options exceeded the average market price of the Company’s common stock for these periods.  The effect of options to purchase 2.1 million and 2.7 million shares of common stock were excluded from the calculation of diluted weighted average shares outstanding for the nine month periods ended September 30, 2011 and 2010, respectively, because the exercise price of these options exceeded the average market price of the Company’s common stock for these periods.

16. Guarantees

The Company has agreed to continue to provide surety bonds and letters of credit for the reclamation and retiree healthcare obligations of Magnum Coal Company (“Magnum”) related to the properties the Company sold to Magnum on December 31, 2005. Patriot Coal Corporation (“Patriot”) acquired Magnum in July 2008. The purchase agreement requires Magnum to reimburse the Company for costs related to the surety bonds and letters of credit and to use commercially reasonable efforts to replace the obligations.  If the surety bonds and letters of credit related to the reclamation obligations are not replaced by Magnum within a specified period of time, Magnum must post a letter of credit in favor of the Company in the amounts of the reclamation obligations. As of September 30, 2011, Patriot has replaced $48.9 million of the surety bonds and has posted letters of credit of $32.7 million in the Company’s favor.  At September 30, 2011, the Company had $38.5 million of surety bonds remaining related to properties sold to

17

Magnum. The surety bonding amounts are mandated by the state and are not directly related to the estimated cost to reclaim the properties.

Magnum also acquired certain coal supply contracts with customers who have not consented to the contracts’ assignment from the Company to Magnum. The Company has committed to purchase coal from Magnum to sell to those customers at the same price it is charging the customers for the sale. In addition, certain contracts were assigned to Magnum, but the Company has guaranteed Magnum’s performance under the contracts. The longest of the coal supply contracts extends to the year 2017. If Magnum is unable to supply the coal for these coal sales contracts then the Company would be required to purchase coal on the open market or supply contracts from its existing operations. At market prices effective at September 30, 2011, the cost of purchasing 10.3 million tons of coal to supply the contracts that have not been assigned over their duration would exceed the sales price under the contracts by approximately $264.3 million, and the cost of purchasing 0.9 million tons of coal to supply the assigned and guaranteed contracts over their duration would exceed the sales price under the contracts by approximately $19.5 million. As the Company does not believe that it is probable that it would have to purchase replacement coal, no losses have been recorded in the consolidated financial statements as of September 30, 2011. However, if the Company would have to perform under these guarantees, it could potentially have a material adverse effect on the business, results of operations and financial condition of the Company.

In connection with the Company’s acquisition of the coal operations of Atlantic Richfield Company (ARCO) and the simultaneous combination of the acquired ARCO operations and the Company’s Wyoming operations into the Arch Western joint venture, the Company agreed to indemnify the other member of Arch Western against certain tax liabilities in the event that such liabilities arise prior to June 1, 2013 as a result of certain actions taken, including the sale or other disposition of certain properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch Western or the reduction under certain circumstances of indebtedness incurred by Arch Western in connection with the acquisition. If the Company were to become liable, the maximum amount of potential future tax payments is $22.3 million at September 30, 2011, which is not recorded as a liability in the Company’s condensed consolidated financial statements. Since the indemnification is dependent upon the initiation of activities within the Company’s control and the Company does not intend to initiate such activities, it is remote that the Company will become liable for any obligation related to this indemnification. However, if such indemnification obligation were to arise, it could potentially have a material adverse effect on the business, results of operations and financial condition of the Company.

17. Contingencies

On June 15, 2011, the Company acquired ICG and its subsidiaries.  The following matters relate to certain claims and legal actions involving ICG and/or its subsidiaries.

Allegheny Energy Supply (“Allegheny”), the sole customer of coal produced at the Company’s subsidiary Wolf Run Mining Company’s (“Wolf Run”) Sycamore No. 2 mine, filed a lawsuit against Wolf Run, Hunter Ridge Holdings, Inc. (“Hunter Ridge”), and ICG in state court in Allegheny County, Pennsylvania on December 28, 2006, and amended its complaint on April 23, 2007. Allegheny claimed that Wolf Run breached a coal supply contract when it declared force majeure under the contract upon idling the Sycamore No. 2 mine in the third quarter of 2006, and that Wolf Run continued to breach the contract by failing to ship in volumes referenced in the contract. The Sycamore No. 2 mine was idled after encountering adverse geologic conditions and abandoned gas wells that were previously unidentified and unmapped. After extensive searching for gas wells and rehabilitation of the mine, it was re-opened in 2007, but with notice to Allegheny that it would necessarily operate at reduced volumes in order to safely and effectively avoid the many gas wells within the reserve. The amended complaint also alleged that the production stoppages constitute a breach of the guarantee agreement by Hunter Ridge and breach of certain representations made upon entering into the contract in early 2005. Allegheny voluntarily dropped the breach of representation claims later. Allegheny claimed that it would incur costs in excess of $100 million to purchase replacement coal over the life of the contract. ICG, Wolf Run and Hunter Ridge answered the amended complaint on August 13, 2007, disputing all of the remaining claims.

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

against ICG were also dismissed by summary judgment, but the claims against Wolf Run and Hunter Ridge were not. The court conducted a non-jury trial of this matter beginning on January 10, 2011 and concluding on February 1, 2011. At the trial, Allegheny presented its evidence for breach of contract and claimed that it is entitled to past and future damages in the aggregate of between $228.0 million and $377.0 million. Wolf Run and Hunter Ridge presented their defense of the claims, including evidence with respect to the existence of force majeure conditions and excuse under the contract and applicable law. Wolf Run and Hunter Ridge presented evidence that Allegheny’s damages calculations were significantly inflated because it did not seek to determine damages as of the time of the breach and in some instances artificially assumed future non-delivery or did not take into account the apparent requirement to

18

supply coal in the future. On May 2, 2011, the trial court entered a Memorandum and Verdict determining that Wolf Run had breached the coal supply contract and that the performance shortfall was not excused by force majeure. ICG and Allegheny filed post-verdict motions in the trial court and on August 23, 2011, the court denied the parties’ motions.  The court entered a final judgment on August 25, 2011, in the amount of $104.1 million, which included pre-judgment interest.  The parties appealed the lower court’s decision to the Superior Court of Pennsylvania.  Wolf Run and Hunter Ridge have filed an appeal bond in the amount of $124.9 million.  Briefing is scheduled to begin on October 24, 2011, to be completed in early 2012.

As of September 30, 2011, the Company has accrued $106.7 million for this lawsuit, including $1.8 million of interest recognized post-acquisition.  The ultimate resolution of this matter could result in an outcome which may be materially different than what the Company has accrued.

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

18. Segment Information

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

Operating segment results for the three and nine months ended September 30, 2011 and 2010 are presented below. Results for the reportable segments include all direct costs of mining, including all depreciation, depletion and amortization related to the mining operations, even if the assets are not recorded at the operating segment level. See discussion of segment assets below. Corporate, Other and Eliminations includes the change in fair value of coal derivatives and coal trading activities, net; corporate overhead; land management; other support functions; and the elimination of intercompany transactions.

The asset amounts below represent an allocation of assets used in the segments’ cash-generating activities. The amounts in Corporate, Other and Eliminations represent primarily corporate assets (cash, receivables, investments, plant, property and equipment) as well as unassigned coal reserves, above-market acquired sales contracts and other unassigned assets.

19

	PRB		APP			WBIT		OtherOperatingSegments			Corporate,Other andEliminations			Consolidated
	(In thousands)
Three months ended September 30, 2011
Revenues	$	394,012	$	611,403		$	168,795	$	24,463		$	—		$	1,198,673
Income (loss) from operations	38,630		77,511			24,653		(1,713		)	(46,815		)	92,266
Depreciation, depletion and amortization	42,676		59,576			19,125		3,781			(2,132		)	123,026
Amortization of acquired sales contracts, net	3,802		(16,022		)	—		34			—			(12,186		)
Capital expenditures	20,937		62,121			16,111		4,705			4,300			108,174
Three months ended September 30, 2010
Revenues	$	440,439	$	296,227		$	138,039	$	—		$	—		$	874,705
Income from operations	51,787		55,664			14,816		—			(23,920		)	98,347
Depreciation, depletion and amortization	49,005		24,435			18,940		—			477			92,857
Amortization of acquired sales contracts, net	10,038		—			—		—			—			10,038
Capital expenditures	8,164		16,910			20,703		—			3,848			49,625
Nine Months ended September 30, 2011
Revenues	$	1,178,537	$	1,336,581		$	513,388	$	28,633		$	—		$	3,057,139
Income (loss) from operations	121,119		224,561			95,218		(1,814		)	(147,401		)	291,683
Total assets	2,240,458		5,159,710			667,658		222,014			1,565,421			9,855,261
Depreciation, depletion and amortization	125,532		108,904			61,753		4,386			1,171			301,746
Amortization of acquired sales contracts, net	15,349		(20,145		)	—		43			—			(4,753		)
Capital expenditures	39,422		108,711			38,003		9,078			20,685			215,899
Nine months ended September 30, 2010
Revenues	$	1,170,353	$	777,619		$	402,902	$	—		$	—		$	2,350,874
Income from operations	101,525		147,336			41,122		—			(52,937		)	237,046
Total assets	2,304,277		701,670			677,968		—			1,150,871			4,834,786
Depreciation, depletion and amortization	138,059		72,190			57,700		—			1,186			269,135
Amortization of acquired sales contracts, net	26,005		—			—		—			—			26,005
Capital expenditures	12,614		41,519			54,507		—			112,943			221,583

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

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
	(In thousands)						(In thousands)
Income from operations	$	92,266		$	98,347		$	291,683		$	237,046
Interest expense	(77,694		)	(37,698		)	(154,523		)	(107,906		)
Interest income	840			927			2,341			1,888
Bridge financing costs related to ICG	—			—			(49,490		)	—
Net loss resulting from early retirement of debt	(1,708		)	(6,776		)	(1,958		)	(6,776		)
Income before income taxes	$	13,704		$	54,800		$	88,053		$	124,252

19. Supplemental Condensed Consolidating Financial Information

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

20

Condensed Consolidating Statements of Income

Three Months Ended September 30, 2011

(unaudited)

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	651,326		$	547,347		$	—		$	1,198,673
Costs, expenses and other
Cost of sales	7,442			522,636			448,680			(25,908		)	952,850
Depreciation, depletion and amortization	718			83,775			38,533			—			123,026
Amortization of acquired sales contracts, net	—			(15,989		)	3,803			—			(12,186		)
Selling, general and administrative expenses	20,263			5,058			9,751			(1,796		)	33,276
Change in fair value of coal derivatives and coal trading activities, net	—			8,360			—			—			8,360
Acquisition and transition costs related to ICG	4,694			—			—			—			4,694
Other operating (income) expense, net	(6,063		)	(30,509		)	5,255			27,704			(3,613		)
	27,054			573,331			506,022			—			1,106,407
Income from investment in subsidiaries	121,210			—			—			(121,210		)	—
Income from operations	94,156			77,995			41,325			(121,210		)	92,266
Interest expense, net:
Interest expense	(84,045		)	(942		)	(10,657		)	17,950			(77,694		)
Interest income	3,593			108			15,089			(17,950		)	840
	(80,452		)	(834		)	4,432			—			(76,854		)
Other non-operating expense
Net loss resulting from early retirement of debt	—			(1,708		)	—			—			(1,708		)
	—			(1,708		)	—			—			(1,708		)
Income before income taxes	13,704			75,453			45,757			(121,210		)	13,704
Benefit from income taxes	(5,583		)	—			—			—			(5,583		)
Net income	19,287			75,453			45,757			(121,210		)	19,287
Less: Net income attributable to noncontrolling interest	(231		)	—			—			—			(231		)
Net income attributable to Arch Coal	$	19,056		$	75,453		$	45,757		$	(121,210	)	$	19,056

21

Condensed Consolidating Statements of Income

Three Months Ended September 30, 2010

(unaudited)

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	324,507		$	550,198		$	—		$	874,705
Costs, expenses and other
Cost of sales	3,578			229,731			445,814			(27,270		)	651,853
Depreciation, depletion and amortization	794			52,302			39,761			—			92,857
Amortization of acquired sales contracts, net	—			—			10,038			—			10,038
Selling, general and administrative expenses	18,245			1,858			8,818			(1,922		)	26,999
Change in fair value of coal derivatives and coal trading activities, net	—			1,832			—			—			1,832
Other operating (income) expense, net	(3,346		)	(35,107		)	2,040			29,192			(7,221		)
	19,271			250,616			506,471			—			776,358
Income from investment in subsidiaries	108,974			—			—			(108,974		)	—
Income from operations	89,703			73,891			43,727			(108,974		)	98,347
Interest expense, net:
Interest expense	(38,041		)	(745		)	(16,738		)	17,826			(37,698		)
Interest income	3,138			119			15,496			(17,826		)	927
	(34,903		)	(626		)	(1,242		)	—			(36,771		)
Other non-operating expense
Net loss resulting from early retirement of debt	—			—			(6,776		)	—			(6,776		)
	—			—			(6,776		)	—			(6,776		)
Income before income taxes	54,800			73,265			35,709			(108,974		)	54,800
Provision for income taxes	7,941						—			—			7,941
Net income	46,859			73,265			35,709			(108,974		)	46,859
Less: Net income attributable to noncontrolling interest	(181		)	—			—			—			(181		)
Net income attributable to Arch Coal	$	46,678		$	73,265		$	35,709		$	(108,974	)	$	46,678

22

Condensed Consolidating Statements of Income

Nine Months Ended September 30, 2011

(unaudited)

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	1,409,755		$	1,647,384		$	—		$	3,057,139
Costs, expenses and other
Cost of sales	15,661			1,062,692			1,319,711			(75,940		)	2,322,124
Depreciation, depletion and amortization	2,050			181,059			118,637			—			301,746
Amortization of acquired sales contracts, net	—			(20,102		)	15,349			—			(4,753		)
Selling, general and administrative expenses	59,198			10,112			28,768			(5,328		)	92,750
Change in fair value of coal derivatives and coal trading activities, net	—			9,248			—			—			9,248
Acquisition and transition costs related to ICG	53,360			—			—			—			53,360
Other operating (income) expense, net	(15,461		)	(87,210		)	12,384			81,268			(9,019		)
	114,808			1,155,799			1,494,849			—			2,765,456
Income from investment in subsidiaries	413,406			—			—			(413,406		)	—
Income from operations	298,598			253,956			152,535			(413,406		)	291,683
Interest expense, net:
Interest expense	(172,700		)	(3,793		)	(32,599		)	54,569			(154,523		)
Interest income	11,645			540			44,725			(54,569		)	2,341
	(161,055		)	(3,253		)	12,126			—			(152,182		)
Other non-operating expense
Bridge financing costs related to ICG	(49,490		)	—			—			—			(49,490		)
Net loss resulting from early retirement of debt	—			(1,958		)	—			—			(1,958		)
	(49,490		)	(1,958		)	—			—			(51,448		)
Income before income taxes	88,053			248,745			164,661			(413,406		)	88,053
Provision for income taxes	5,103			—			—			—			5,103
Net income	82,950			248,745			164,661			(413,406		)	82,950
Less: Net income attributable to noncontrolling interest	(822		)	—			—			—			(822		)
Net income attributable to Arch Coal	$	82,128		$	248,745		$	164,661		$	(413,406	)	$	82,128

23

Condensed Consolidating Statements of Income

Nine Months Ended September 30, 2010

(unaudited)

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	—		$	846,351		$	1,504,523		$	—		$	2,350,874
Costs, expenses and other
Cost of sales	8,554			591,692			1,239,893			(66,675		)	1,773,464
Depreciation, depletion and amortization	2,270			142,961			123,904			—			269,135
Amortization of acquired sales contracts, net	—			—			26,005			—			26,005
Selling, general and administrative expenses	60,139			5,500			29,226			(5,356		)	89,509
Change in fair value of coal derivatives and coal trading activities, net	—			12,296			—			—			12,296
Gain on Knight Hawk transaction	—			(41,577		)	—			—			(41,577		)
Other operating (income) expense, net	(8,124		)	(84,031		)	5,120			72,031			(15,004		)
	62,839			626,841			1,424,148			—			2,113,828
Income from investment in subsidiaries	282,794			—			—			(282,794		)	—
Income from operations	219,955			219,510			80,375			(282,794		)	237,046
Interest expense, net:
Interest expense	(102,996		)	(2,104		)	(53,241		)	50,435			(107,906		)
Interest income	7,293			283			44,747			(50,435		)	1,888
	(95,703		)	(1,821		)	(8,494		)	—			(106,018		)
Other non-operating expense
Net loss resulting from early retirement of debt	—			—			(6,776		)	—			(6,776		)
	—			—			(6,776		)	—			(6,776		)
Income before income taxes	124,252			217,689			65,105			(282,794		)	124,252
Provision for income taxes	12,889			—			—			—			12,889
Net income	111,363			217,689			65,105			(282,794		)	111,363
Less: Net income attributable to noncontrolling interest	(325		)	—			—			—			(325		)
Net income attributable to Arch Coal	$	111,038		$	217,689		$	65,105		$	(282,794	)	$	111,038

24

Condensed Consolidating Balance Sheets

September 30, 2011

(unaudited)

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Cash and cash equivalents	$	57,778		$	280		$	100,451	$	—		$	158,509
Restricted cash	21,428			—			—		—			21,428
Receivables	63,111			130,884			233,855		(1,550		)	426,300
Inventories	—			173,564			172,767		—			346,331
Other	35,413			102,729			16,873		—			155,015
Total current assets	177,730			407,457			523,946		(1,550		)	1,107,583
Property, plant and equipment, net	13,685			6,234,786			1,454,809		—			7,703,280
Investment in subsidiaries	8,632,002			—			—		(8,632,002		)	—
Intercompany receivables	(2,243,557		)	813,061			1,430,496		—			—
Note receivable from Arch Western	225,000			—			—		(225,000		)	—
Other	456,885			574,038			13,475		—			1,044,398
Total other assets	7,070,330			1,387,099			1,443,971		(8,857,002		)	1,044,398
Total assets	$	7,261,745		$	8,029,342		$	3,422,726	$	(8,858,552	)	$	9,855,261
Liabilities and Stockholders’ Equity
Accounts payable	$	33,646		$	151,826		$	107,974	$	—		$	293,446
Accrued expenses and other current liabilities	108,442			132,785			145,854		(1,550		)	385,531
Current maturities of debt and short-term borrowings	4,357			2,799			40,000		—			47,156
Total current liabilities	146,445			287,410			293,828		(1,550		)	726,133
Long-term debt	3,388,496			1,702			451,132					3,841,330
Note payable to Arch Coal	—			—			225,000		(225,000		)	—
Asset retirement obligations	548			107,002			308,327		—			415,877
Accrued pension benefits	7,057			(489		)	9,667		—			16,235
Accrued postretirement benefits other than pension	15,276			50,241			23,303		—			88,820
Accrued workers’ compensation	14,866			42,850			6,705		—			64,421
Deferred income taxes	(4,162		)	884,649			—		—			880,487
Other noncurrent liabilities	148,751			75,565			53,174		—			277,490
Total liabilities	3,717,277			1,448,930			1,371,136		(226,550		)	6,310,793
Redeemable noncontrolling interest	11,261			—			—		—			11,261
Stockholders’ equity	3,533,207			6,580,412			2,051,590		(8,632,002		)	3,533,207
Total liabilities and stockholders’ equity	$	7,261,745		$	8,029,342		$	3,422,726	$	(8,858,552	)	$	9,855,261

25

Condensed Consolidating Balance Sheets

December 31, 2010

(unaudited)

	Parent/Issuer			GuarantorSubsidiaries		Non-GuarantorSubsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Cash and cash equivalents	$	13,713		$	64	$	79,816	$	—		$	93,593
Receivables	31,458			12,740		210,075		(1,953		)	252,320
Inventories	—			85,196		150,420		—			235,616
Other	29,575			102,375		21,435		—			153,385
Total current assets	74,746			200,375		461,746		(1,953		)	734,914
Property, plant and equipment, net	9,817			1,800,578		1,498,497		—			3,308,892
Investment in subsidiaries	4,555,233			—		—		(4,555,233		)	—
Intercompany receivables	(1,807,902		)	508,624		1,299,278		—			—
Note receivable from Arch Western	225,000			—		—		(225,000		)	—
Other	481,345			344,698		10,920		—			836,963
Total other assets	3,453,676			853,322		1,310,198		(4,780,233		)	836,963
Total assets	$	3,538,239		$	2,854,275	$	3,270,441	$	(4,782,186	)	$	4,880,769
Liabilities and Stockholders’ Equity
Accounts payable	$	10,753		$	65,793	$	121,670	$	—		$	198,216
Accrued expenses and other current liabilities	75,746			31,123		153,217		(1,953		)	258,133
Current maturities of debt and short-term borrowings	14,093			—		56,904		—			70,997
Total current liabilities	100,592			96,916		331,791		(1,953		)	527,346
Long-term debt	1,087,126			—		451,618		—			1,538,744
Note payable to Arch Coal	—			—		225,000		(225,000		)	—
Asset retirement obligations	873			32,029		301,355		—			334,257
Accrued pension benefits	20,843			4,407		23,904		—			49,154
Accrued postretirement benefits other than pension	14,284			—		23,509		—			37,793
Accrued workers’ compensation	15,383			13,805		6,102		—			35,290
Other noncurrent liabilities	51,187			22,135		36,912		—			110,234
Total liabilities	1,290,288			169,292		1,400,191		(226,953		)	2,632,818
Redeemable noncontrolling interest	10,444			—		—		—			10,444
Stockholders’ equity	2,237,507			2,684,983		1,870,250		(4,555,233		)	2,237,507
Total liabilities and stockholders’ equity	$	3,538,239		$	2,854,275	$	3,270,441	$	(4,782,186	)	$	4,880,769

26

Condensed Consolidating Statements of Cash Flows

Nine Months Ended September 30, 2011

(unaudited)

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash provided by (used in) operating activities	$	(444,664	)	$	613,179		$	302,852		$	—		$	471,367
Investing Activities
Acquisition of ICG, net of cash acquired	(2,894,339		)	—			—			—			(2,894,339		)
Increase in restricted cash	(5,939		)	—			—			—			(5,939		)
Capital expenditures	(5,137		)	(135,640		)	(75,122		)	—			(215,899		)
Proceeds from dispositions of property, plant and equipment	—			25,010			123			—			25,133
Purchases of investments and advances to affiliates	(777,341		)	(29,872		)	—			750,386			(56,827		)
Additions to prepaid royalties	—			(22,163		)	(3,972		)	—			(26,135		)
Cash used in investing activities	(3,682,756		)	(162,665		)	(78,971		)	750,386			(3,174,006		)
Financing Activities
Proceeds from the issuance of senior notes	2,000,000			—			—			—			2,000,000
Proceeds from the issuance of common stock, net	1,267,776			—			—			—			1,267,776
Contributions from parent	—			750,386			—			(750,386		)	—
Payments to retire debt	—			(604,096		)	—			—			(604,096		)
Net increase (decrease) in borrowings under lines of credit and commercial paper program	340,000			—			(56,904		)	—			283,096
Net payments on other debt	(8,792		)	—			—			—			(8,792		)
Debt financing costs	(114,563		)	—			(24		)	—			(114,587		)
Dividends paid	(57,470		)	—			—			—			(57,470		)
Issuance of common stock under incentive plans	1,628			—			—			—			1,628
Transactions with affiliates, net	742,906			(596,588		)	(146,318		)	—			—
Cash provided by (used in) financing activities	4,171,485			(450,298		)	(203,246		)	(750,386		)	2,767,555
Increase in cash and cash equivalents	44,065			216			20,635			—			64,916
Cash and cash equivalents, beginning of period	13,713			64			79,816			—			93,593
Cash and cash equivalents, end of period	$	57,778		$	280		$	100,451		$	—		$	158,509

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Condensed Consolidating Statements of Cash Flows

Nine Months Ended September 30, 2010

(unaudited)

				Guarantor			Non-Guarantor
	Parent/Issuer			Subsidiaries			Subsidiaries			Consolidated
	(In thousands)
Cash provided by (used in) operating activities	$	(224,066	)	$	404,836		$	275,910		$	456,680
Investing Activities
Capital expenditures	(3,942		)	(141,825		)	(75,816		)	(221,583		)
Proceeds from dispositions of property, plant and equipment	—			178			74			252
Purchases of investments and advances to affiliates	(12,671		)	(4,069		)	—			(16,740		)
Additions to prepaid royalties	—			(20,880		)	(2,835		)	(23,715		)
Cash used in investing activities	(16,613		)	(166,596		)	(78,577		)	(261,786		)
Financing Activities
Proceeds from the issuance of senior notes	500,000			—			—			500,000
Payments to retire debt	—			—			(505,627		)	(505,627		)
Net increase (decrease) in borrowings under lines of credit and commercial paper program	(120,000		)	—			1,663			(118,337		)
Net payments on other debt	(9,794		)	—			—			(9,794		)
Debt financing costs	(11,901		)	—			(729		)	(12,630		)
Dividends paid	(47,121		)	—			—			(47,121		)
Issuance of common stock under incentive plans	339			—			—			339
Contribution from noncontrolling interest	—			—			891			891
Transactions with affiliates, net	(123,309		)	(238,252		)	361,561			—
Cash provided by (used in) financing activities	188,214			(238,252		)	(142,241		)	(192,279		)
Increase (decrease) in cash and cash equivalents	(52,465		)	(12		)	55,092			2,615
Cash and cash equivalents, beginning of period	54,255			64			6,819			61,138
Cash and cash equivalents, end of period	$	1,790		$	52		$	61,911		$	63,753

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

This document contains “forward-looking statements” — that is, statements related to future, not past, events. In this context, forward-looking statements often address our expected future business and financial performance, and often contain words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” or “will.” Forward-looking statements by their nature address matters that are, to different degrees, uncertain. For us, particular uncertainties arise from changes in the demand for our coal by the domestic electric generation industry; from legislation and regulations relating to the Clean Air Act and other environmental initiatives; from operational, geological, permit, labor and weather-related factors; from fluctuations in the amount of cash we generate from operations; from future integration of acquired businesses; and from numerous other matters of national, regional and global scale, including those of a political, economic, business, competitive or regulatory nature. These uncertainties may cause our actual future results to be materially different than those expressed in our forward-looking statements. We do not undertake to update our forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law. For a description of some of the risks and uncertainties that may affect our future results, see “Risk Factors” in Part II of this Form 10-Q, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010 and in the Quarterly Reports on Form 10-Q that we have filed during interim periods.

Overview

Arch Coal is one of the world’s largest coal producers by volume. We sell the majority of our coal as steam coal to power plants and industrial facilities. We also sell metallurgical coal used in steel production, a market that we expanded into further with the acquisition of International Coal Group, Inc. (ICG) in June 2011. On June 15, we acquired ICG’s 1.1 billion ton, predominantly underground reserve base, of which nearly 30% is metallurgical-quality coal; twelve mining complexes and one development project in Appalachia, and one mining complex in Illinois.  The acquisition of ICG adds low-cost, high-quality metallurgical coal to our product mix and creates substantial synergies with our existing operations, including blending opportunities, combining operations and reducing selling, general and administrative costs.

Growth in global coal demand combined with coal supply constraints in many traditional coal exporting countries have benefited coal markets in 2011. Global steel utilization has rebounded from recessionary levels, remaining strong in the third quarter of 2011.  We expect metallurgical coal demand to increase in coming years to meet the increasing steel demand for infrastructure in both developing economies, such as China and Brazil, and mature economies, particularly Japan, where significant rebuilding will be necessary after the earthquake and tsunami.

As in metallurgical coal markets, U.S. steam coal is also migrating offshore to meet the continuing growth in global coal demand to fuel electricity generation.  In response to global steam coal demand, we have expanded our seaborne sales and have shipped steam coal to Europe, South America, and Asia.  Each of our operating segments is participating in the expansion of seaborne shipments, utilizing ports on the East and West Coasts as well through the Gulf of Mexico.

U.S. coal consumption has declined in 2011 due to strong contributions from other fuel sources, including higher hydroelectric power in the western U.S. and increased natural gas generation in the eastern part of the country.  U.S. coal production in the first nine months of 2011 remained essentially flat versus the same period a year ago, according to MSHA data and company estimates.  U.S. stockpile levels have declined approximately 30% from peak levels reached in November 2009.  We estimate nationwide stockpiles reflected 55 days of supply at September 30, 2011, in line with the five-year average. We believe, however, that PRB-served power plant stockpiles were at below-normal levels, partly due to shipment disruptions in the region. Flooding of the Missouri and Mississippi rivers disrupted shipments in the Powder River Basin and the Illinois Basin during the second and third quarters of 2011, resulting in a loss of shipments from our PRB operations.

We encountered geologic issues encountered in the last panel of the seam we are currently mining at our Mountain Laurel mining complex, and experienced 45 days of lost longwall production there during the third quarter of 2011.

On November 3, 2011, we announced that we would be scaling back production at our Dugout Canyon mine in Utah, in response to weakness in demand for coal from that region.  We plan to suspend longwall operations at the end of the current panel in the first half of 2012.  The next potential longwall panel at Dugout Canyon has been developed and future decisions about production will be based on market conditions for Western Bituminous coal.

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Results of Operations

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Summary.  Our results during the third quarter of 2011 when compared to the third quarter of 2010 were impacted positively by the contribution from the acquired ICG operations and the impact of higher average sales realizations as a result of improved market conditions, but these factors were offset by the impact of lower volumes from our Mountain Laurel complex and the Powder River Basin.

Revenues.  The following table summarizes information about coal sales during the three months ended September 30, 2011 and compares it with the information for the three months ended September 30, 2010:

	Three Months Ended September 30				Increase (Decrease)
	2011		2010		Amount			%
	(Amounts in thousands, except per ton data and percentages)
Coal sales	$	1,198,673	$	874,705	$	323,968		37.0	%
Tons sold	40,301		44,173		(3,872		)	(8.8	)%
Coal sales realization per ton sold	$	29.74	$	19.80	$	9.94		50.2	%

Coal sales increased in the third quarter of 2011 from the third quarter of 2010, primarily due to an increase in the overall average price per ton sold, the result of improved pricing on metallurgical-quality coal sold, the contribution from the ICG operations, including higher-priced metallurgical coal sales tons, and higher steam pricing in all regions, as well as the impact of changes in regional mix on our average coal sales realization.  The contribution from the acquired ICG operations was $295.6 million of coal sales revenues for the third quarter of 2011.  Overall sales volumes decreased as lower sales volumes in the Powder River Basin offset the increases in the Appalachia and Western Bituminous regions.  We have provided more information about the tons sold and the coal sales realizations per ton by operating segment under the heading “Operating segment results”.

Costs, expenses and other.  The following table summarizes costs, expenses and other components of operating income for the three months ended September 30, 2011 and compares it with the information for the three months ended September 30, 2010:

	Three Months Ended September 30						Increase (Decrease)in Net Income
	2011			2010			$			%
	(Amounts in thousands, except percentages)
Cost of coal sales	$	952,850		$	651,853		$	(300,997	)	(46.2	)%
Depreciation, depletion and amortization	123,026			92,857			(30,169		)	(32.5	)
Amortization of acquired sales contracts, net	(12,186		)	10,038			22,224			221.4
Selling, general and administrative expenses	33,276			26,999			(6,277		)	(23.2	)
Change in fair value of coal derivatives and coal trading activities, net	8,360			1,832			(6,528		)	(356.3	)
Acquisition and transition costs related to ICG	4,694			—			(4,694		)	N/A
Other operating income, net	(3,613		)	(7,221		)	(3,608		)	50.0
	$	1,106,407		$	776,358		$	(330,049	)	(42.5	)%

Cost of coal sales.  Our cost of coal sales increased in 2011 from 2010 primarily due to the acquisition of the ICG operations, an increase in transportation costs as a result of the increase in export shipments, and an increase in sales-sensitive costs.  We have provided more information about the performance and profitability of our operating segments under the heading “Operating segment results”.

Depreciation, depletion and amortization.  When compared with 2010, higher depreciation, depletion and amortization costs in 2011 resulted primarily from the acquisition of the ICG operations.

Amortization of acquired sales contracts, net.   The fair values of acquired sales contracts are amortized over the tons of coal shipped during the term of the contracts. In 2011, amortization expense related to contracts we acquired in 2009 with the Jacobs Ranch operations in the PRB was offset by amortization income related to the contracts we acquired with the ICG operations. We estimate that net amortization income will be approximately $29 million in the fourth quarter of 2011, based on preliminary estimates of contract values and shipment levels, and we expect the amounts to drop off substantially in future years.  These estimates could change substantially once the final contract valuations are completed.

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Selling, general and administrative expenses.  The increase in selling, general and administrative expenses in the third quarter of 2011 when compared with the third quarter of 2010 is due primarily to higher compensation-related costs from an increase in headcount and an increase in fees for professional services, which were partially offset by a decrease in costs related to our deferred compensation plan due to improved investment performance.

Change in fair value of coal derivatives and coal trading activities, net.  Net (gains) losses relate to the net impact of our coal trading activities and the change in fair value of other coal derivatives that have not been designated as hedge instruments in a hedging relationship. In 2011, decreasing coal prices resulted in unrealized losses on coal purchase contracts.

Acquisition and transition costs related to ICG.  Expenses incurred during the quarter include severance costs of $3.0 million.

Other operating income, net.  When compared with 2010, other operating income, net decreased in 2011 due to an increase in commercial-related expenses and a decrease in net income from equity method investees of $0.9 million, which offset $3.9 million of net operating income generated by acquired ICG operations, primarily royalties and ash disposal income.

Operating segment results.  The following table shows results by operating segment for the three months ended September 30, 2011 and compares it with the information for the three months ended September 30, 2010:

	Three Months Ended September 30				Increase (Decrease)
	2011		2010		$			%
Powder River Basin
Tons sold (in thousands)	28,813		36,129		(7,316		)	(20.3	)%
Coal sales realization per ton sold(1)	$	13.62	$	12.12	$	1.50		12.4	%
Operating margin per ton sold(2)	$	1.32	$	1.41	$	(0.09	)	(6.4	)%
Adjusted EBITDA(3) (in thousands)	$	83,131	$	111,729	$	(28,598	)	(25.6	)%
Appalachia
Tons sold (in thousands)	6,696		4,020		2,676			66.6	%
Coal sales realization per ton sold(1)	$	84.32	$	69.29	$	15.03		21.7	%
Operating margin per ton sold(2)	$	11.18	$	13.34	$	(2.16	)	(16.3	)%
Adjusted EBITDA(3) (in thousands)	$	113,973	$	77,368	36,605			47.3	%
Western Bituminous
Tons sold (in thousands)	4,233		4,024		209			5.19	%
Coal sales realization per ton sold(1)	$	36.09	$	34.16	$	1.93		5.6	%
Operating margin per ton sold(2)	$	5.80	$	3.61	$	2.19		60.7	%
Adjusted EBITDA(3) (in thousands)	$	43,778	$	33,756	$	10,022		29.7	%

(1)	Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. For the three months ended September 30, 2011, transportation costs per ton were $0.06 for the Powder River Basin, $6.99 for Appalachia, and $3.79 for the Western Bituminous region. For the three months ended September 30, 2010, transportation costs per ton were $0.07 for the Powder River Basin, $4.40 for Appalachia and $0.15 for the Western Bituminous region.
(2)	Operating margin per ton sold is calculated as coal sales revenues less cost of coal sales and depreciation, depletion and amortization divided by tons sold.
(3)	Adjusted EBITDA is defined as net income attributable to the Company before the effect of net interest expense, income taxes, depreciation, depletion and amortization and the amortization of acquired sales contracts. Adjusted EBITDA is also adjusted for costs related to acquisitions and financing transactions. Segment Adjusted EBITDA is reconciled to net income at the end of this “Results of Operations” section.

Powder River Basin — The decrease in Segment Adjusted EBITDA in the third quarter of 2011 when compared with the third quarter of 2010 is the result of lower sales volumes and higher production costs, partially offset by the impact of higher average coal sales realizations, which reflected the improved coal markets.  The lower sales volumes were primarily the

31

result of the flooding in the Midwest, but the third quarter of 2010 was also a record production quarter for us in the PRB.  Higher per-ton production costs were the result lower production volumes and higher diesel prices and sales-sensitive costs.

Appalachia — Segment Adjusted EBITDA in the third quarter of 2011 was higher than in 2010, primarily due to an increase in the volumes and pricing of metallurgical-quality coal sold. We sold approximately 2.1 million tons of metallurgical-quality coal in 2011 compared to 1.4 million tons in 2010. The volumes contributed by the acquired ICG operations were partially offset by lower volumes from the Mountain Laurel mine as a result of the geologic issues in the third quarter.  The benefit from higher per-ton realizations in 2011, net of sales sensitive costs, and the acquisition of ICG was offset in part by the impacts of the Mountain Laurel longwall outage, and an increase in production at higher cost mines on our average per-ton production costs.

Western Bituminous — The improvement in Segment Adjusted EBITDA in 2011 reflects higher sales volumes and improved pricing resulting from increased export shipments from our Colorado operations.  Effective cost control in the region and slightly higher production levels reduced our per-ton operating costs, which also contributed to the improved results in 2011.

Net interest expense.  The following table summarizes our net interest expense for the three months ended September 30, 2011 and compares it with the information for the three months ended September 30, 2010:

	Three Months Ended September 30						Increase (Decrease)in Net Income
	2011			2010			$			%
	(Amounts in thousands, except percentages)
Interest expense	$	(77,694	)	$	(37,698	)	$	(39,996	)	(106.1	)%
Interest income	840			927			(87		)	(9.4	)%
	$	(76,854	)	$	(36,771	)	$	(40,083	)	(109.0	)%

The increase in interest expense during 2011 when compared with 2010 is the result of the ICG acquisition financing.  See further discussion in “Liquidity and Capital Resources.”

Income taxes.  Our effective income tax rate is sensitive to changes in and the relationship between annual profitability and the deduction for percentage depletion. The following table summarizes our income taxes for three months ended September 30, 2011 and compares it with the information for the three months ended September 30, 2010:

	Three Months Ended September 30					Increasein Net Income
	2011			2010		$		%
	(Amounts in thousands, except percentages)
Provision for (benefit from) income taxes	$	(5,583	)	$	7,941	$	13,524	170.3	%

Nine Months ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Summary.  Our results during the first nine months of 2011 when compared to the first nine months of 2010 were impacted positively by the contribution from the acquired ICG operations and higher average sales realizations as a result of improved market conditions, but these factors were offset by the acquisition, transition and financing costs necessary to complete the acquisition, as well as the impact of lower volumes from our Mountain Laurel complex and the Powder River Basin.

Revenues.  The following table summarizes information about coal sales during the nine months ended September 30, 2011 and compares it with the information for the nine months ended September 30, 2010:

	Nine Months Ended September 30				Increase (Decrease)
	2011		2010		Amount			%
	(Amounts in thousands, except per ton data and percentages)
Coal sales	$	3,057,139	$	2,350,874	$	706,265		30.0	%
Tons sold	114,034		120,319		(6,285		)	(5.2	)%
Coal sales realization per ton sold	$	26.81	$	19.54	$	7.27		37.2	%

Coal sales increased in the first nine months of 2011 from the first nine months of 2010, due to an increase in the overall average price per ton sold, primarily from the effect of an increase in the volumes and pricing of metallurgical-quality coal

32

sold, higher steam pricing in all regions and the impact of changes in regional mix on our average coal sales realization, in addition to the contribution from the ICG operations acquired.  Overall sales volume decreased slightly as lower sales volumes in the Powder River Basin offset the increases in the Appalachia and Western Bituminous regions.  We have provided more information about the tons sold and the coal sales realizations per ton by operating segment under the heading “Operating segment results”.

Costs, expenses and other.  The following table summarizes costs, expenses and other components of operating income for the nine months ended September 30, 2011 and compares it with the information for the nine months ended September 30, 2010:

	Nine Months Ended September 30						Increase (Decrease)in Net Income
	2011			2010			$			%
	(Amounts in thousands, except percentages)
Cost of coal sales	$	2,322,124		$	1,773,464		$	(548,660	)	(30.9	)%
Depreciation, depletion and amortization	301,746			269,135			(32,611		)	(12.1	)%
Amortization of acquired sales contracts, net	(4,753		)	26,005			30,758			118.3	%
Selling, general and administrative expenses	92,750			89,509			(3,241		)	(3.6	)%
Change in fair value of coal derivatives and coal trading activities, net	9,248			12,296			3,048			24.8	%
Acquisition and transition costs related to ICG	53,360			—			(53,360		)	N/A
Gain on Knight Hawk transaction	—			(41,577		)	(41,577		)	(100.0	)%
Other operating income, net	(9,019		)	(15,004		)	(5,985		)	(39.9	)%
	$	2,765,456		$	2,113,828		$	(651,628	)	(30.8	)%

Cost of coal sales.  Our cost of coal sales increased in 2011 from 2010 primarily due to the acquisition of the ICG operations, an increase in transportation costs as a result of the increase in export shipments, and an increase in sales-sensitive costs.  We have provided more information about the performance and profitability of our operating segments under the heading “Operating segment results”.

Depreciation, depletion and amortization.  When compared with 2010, higher depreciation, depletion and amortization costs in 2011 resulted primarily from the acquired ICG operations, offset by the impact of lower depreciation and amortization on assets amortized or depleted on the basis of tons produced.

Amortization of acquired sales contracts, net.  The fair values of acquired sales contracts are amortized over the tons of coal shipped during the term of the contracts.  In 2011, amortization expense related to contracts we acquired in 2009 with the Jacobs Ranch operations in the PRB was offset by amortization income related to the contracts we acquired with the ICG operations. We estimate that net amortization income will be approximately $29 million in the fourth quarter of 2011, based on preliminary estimates of contract values and shipment levels, though we expect the amounts to drop off substantially in future years. These estimates could change substantially once the final contract valuations are completed.

Selling, general and administrative expenses.  The increase in selling, general and administrative expenses in 2011 is due primarily to higher compensation-related costs from an increase in headcount and an increase in professional services fees.  These increases were partially offset by a decrease in charitable contributions related to a payment to the Arch Coal Foundation of $5.0 million in 2010 and a decrease in costs related to our deferred compensation plan due to improved investment performance.

Change in fair value of coal derivatives and coal trading activities, net.  Net (gains) losses relate to the net impact of our coal trading activities and the change in fair value of other coal derivatives that have not been designated as hedge instruments in a hedging relationship. In 2010, rising coal prices resulted in unrealized losses on positions held to manage risk, but that were not designated in a hedge relationship.

Acquisition and transition costs related to ICG.  Expenses represent costs to complete the acquisition of $29.5 million, severance costs of $16.5 million and the write off of the $7.3 million value of a preparation plant and loadout of an acquired ICG mining operation that has been combined with an existing operation of the Company, and utilizes an existing facility.

Gain on Knight Hawk transaction. Represents the gain recognized on our exchange of Illinois Basin reserves in 2010 for an additional ownership interest in Knight Hawk, an equity method investee operating in the Illinois Basin.

Other operating income, net.  When compared with 2010, other operating income, net decreased in 2011 due to an increase in commercial-related expenses in 2011, partially offset by $5.3 million of other income generated by acquired ICG

33

operations, primarily royalties and ash disposal income, and an increase in net income from equity method investees of $0.8 million.

Operating segment results.  The following table shows results by operating segment for the nine months ended September 30, 2011 and compares it with the information for the nine months ended September 30, 2010:

	Nine Months Ended September 30				Increase (Decrease)
	2011		2010		$			%
Powder River Basin
Tons sold (in thousands)	85,684		97,725		(12,041		)	(12.3	)%
Coal sales realization per ton sold(1)	$	13.61	$	11.90	$	1.71		14.4	%
Operating margin per ton sold(2)	$	1.39	$	1.02	$	0.37		36.3	%
Adjusted EBITDA(3) (in thousands)	$	259,094	$	263,911	$	(4,871	)	(1.8	)%
Appalachia
Tons sold (in thousands)	14,556		10,445		4,111			39.4	%
Coal sales realization per ton sold(1)	$	84.25	$	69.12	$	15.13		21.9	%
Operating margin per ton sold(2)	$	15.60	$	13.56	$	2.04		15.0	%
Adjusted EBITDA(3) (in thousands)	$	315,610	$	208,908	$	106,702		51.1	%
Western Bituminous
Tons sold (in thousands)	13,141		12,149		992			8.2	%
Coal sales realization per ton sold(1)	$	35.47	$	33.01	$	2.46		7.5	%
Operating margin per ton sold(2)	$	7.18	$	3.10	$	4.08		131.6	%
Adjusted EBITDA(3) (in thousands)	$	156,970	$	98,822	$	58,148		58.8	%

(1)	Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. For the nine months ended September 30, 2011, transportation costs per ton were $0.15 for the Powder River Basin, $7.57 for Appalachia and $3.54 for the Western Bituminous region. For the nine months ended September 30, 2010, transportation costs per ton were $0.08 for the Powder River Basin, $5.33 for Appalachia and $0.15 for the Western Bituminous region.
(2)	Operating margin per ton sold is calculated as coal sales revenues less cost of coal sales and depreciation, depletion and amortization divided by tons sold.
(3)	Adjusted EBITDA is defined as net income attributable to the Company before the effect of net interest expense, income taxes, depreciation, depletion and amortization and the amortization of acquired sales contracts. Adjusted EBITDA is also adjusted for costs related to acquisitions and financing transactions. Segment Adjusted EBITDA is reconciled to net income at the end of this “Results of Operations” section.

Powder River Basin —Segment Adjusted EBITDA was slightly lower in 2011 when compared to 2010,  primarily the result of the decrease in sales volumes in the Powder River Basin in 2011 when compared with 2010, due to the flooding in the Midwest and a market-driven approach to sales commitments earlier in the year , as well as higher per-ton production costs.  Higher production costs reflected an increase in labor, maintenance and diesel costs and an increase in sales-sensitive costs, due to the increased realizations, as well as the lower production volumes.   Higher average coal sales realizations, reflecting the improved coal markets partially offset the impact of the lower volumes and higher per-ton costs

Appalachia — Segment Adjusted EBITDA increased from 2010 primarily from an increase in the volumes and pricing of metallurgical-quality coal sold and the acquisition of ICG.  The contribution from acquired ICG and other Arch mines made up the volume impact from the geology issues at the Mountain Laurel mine.  We sold 5.3 million tons of metallurgical-quality coal in 2011 compared to 3.8 million tons in 2010.  The benefit from higher per-ton realizations in 2011, net of sales sensitive costs, drove the improvement in our operating margins over 2010, partially offset by the impacts of the Mountain Laurel geology issues, and an increase in production at higher cost mines on our average per-ton production costs.

Western Bituminous — Improved Segment Adjusted EBITDA reflects higher sales volumes and improved pricing resulting from increased export shipments for coal from our Colorado operations.  Effective cost control in the region and slightly higher production levels reduced our per-ton operating costs, which also contributed to the improved results in 2011, when compared with the first nine months of 2010, when two outages affected production at the Dugout Canyon mine.

34

Net interest expense.  The following table summarizes our net interest expense for the nine months ended September 30, 2011 and compares it with the information for the nine months ended September 30, 2010:

	Nine Months Ended September 30						Increase (Decrease) in Net Income
	2011			2010			$			%
	(Amounts in thousands, except percentages)
Interest expense	$	(154,523	)	$	(107,906	)	$	(46,617	)	(43.2	)%
Interest income	2,341			1,888			453			24.0	%
	$	(152,182	)	$	(106,018	)	$	(46,164	)	(43.5	)%

The increase in interest expense during 2011 when compared with 2010 is the result of the ICG acquisition financing.  See further discussion in “Liquidity and Capital Resources.”

Other non-operating expense.  The following table summarizes other non-operating expenses for the nine months ended September 30, 2011 and compares them with the information for the nine months ended September 30, 2010:

	Nine Months Ended September 30					Decreasein Net Income
	2011			2010		$
	(Amounts in thousands, except percentages)
Bridge financing costs related to ICG	$	(49,490	)	$	—	$	(49,490	)
Net loss resulting from early retirement of ICG debt	(1,958		)	—		(1,958		)
	$	(51,448	)	$	—	$	(51,448	)

Other non-operating expenses during the third quarter of 2011 represent financing-related costs of the ICG acquisition, including the cost to maintain a bridge financing facility, which was not used.

Income taxes.  Our effective income tax rate is sensitive to changes in and the relationship between annual profitability and the deduction for percentage depletion. The following table summarizes our income taxes for nine months ended September 30, 2011 and compares it with the information for the nine months ended September 30, 2010:

	Nine Months Ended September 30				Increase in Net Income
	2011		2010		$		%
	(Amounts in thousands, except percentages)
Provision for income taxes	$	5,103	$	12,889	$	7,786	60.4	%

Reconciliation of Segment Adjusted EBITDA to Net Income

The discussion in “Results of Operations” includes references to our Adjusted EBITDA results. Adjusted EBITDA is defined as net income attributable to the Company before the effect of net interest expense, income taxes, depreciation, depletion and amortization and the amortization of acquired sales contracts. Adjusted EBITDA is also adjusted for costs related to acquisitions and financing transactions. 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 reconcile Adjusted EBITDA to net income attributable to Arch Coal.

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
Reported Segment Adjusted EBITDA	$	240,882		$	222,853		$	731,674		$	571,641
Corporate and other (1)	(29,423		)	(21,792		)	(80,935		)	(39,780		)
Adjusted EBITDA	211,459			201,061			650,739			531,861
Depreciation, depletion and amortization	(123,026		)	(92,857		)	(301,746		)	(269,135		)
Amortization of acquired sales contracts, net	12,186			(10,038		)	4,753			(26,005		)
Interest expense	(77,694		)	(37,698		)	(154,523		)	(107,906		)
Interest income	840			927			2,341			1,888
Acquisition and transition costs (2)	(8,584		)	—			(62,885		)	—
Bridge financing costs related to ICG	—			—			(49,490		)	—
Net loss resulting from early retirement of debt	(1,708		)	(6,776		)	(1,958		)	(6,776		)
(Provision for) benefit from income taxes	5,583			(7,941		)	(5,103		)	(12,889		)
Net income attributable to Arch Coal	$	19,056		$	46,678		$	82,128		$	111,038

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(1)

Corporate and other Adjusted EBITDA includes primarily selling, general and administrative expenses, income from our equity investments, change in fair value of coal derivatives and coal trading activities, net.

(2)

Includes acquisition and transition costs as reflected on the condensed consolidated statements of income and the pre-tax impact on cost of sales of inventory written up to fair value in the ICG acquisition. Adjustments made to the provisional fair value of inventories during the third quarter of 2011 are reflected in the accompanying results assuming the adjustments were made as of the ICG acquisition date.

Liquidity and capital resources

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

We believe that cash generated from operations and borrowings under our credit facilities or other financing arrangements will be sufficient to meet working capital requirements, anticipated capital expenditures and scheduled debt payments for at least the next several years. We manage our exposure to changing commodity prices for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements. We enter into fixed price, fixed volume supply contracts with terms greater than one year with customers with whom we have historically had limited collection issues. Our ability to satisfy debt service obligations, to fund planned capital expenditures, to make acquisitions, to repurchase our common shares and to pay dividends will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.

In June 2011, we issued equity and debt securities to finance the ICG acquisition.  On June 8, 2011, we sold 48 million shares of our common stock at a public offering price of $27.00 per share pursuant to an automatically effective shelf registration statement on Form S-3, a prospectus previously filed and a related prospectus supplement filed in June 2011.  On July 8, 2011, we issued an additional 0.7 million shares of our common stock under the same terms and conditions to cover underwriters’ over-allotments for net proceeds of $18.4 million.  On June 14, 2011, we issued $1.0 billion in aggregate principal amount of 7.0% senior unsecured notes due in 2019 at par and $1.0 billion in aggregate principal amount of 7.25% senior unsecured notes due in 2021 at par.  We secured bridge financing to ensure that funds would be available to us, if needed, to close the transaction.  While we did not draw on the line of credit, we incurred bridge financing costs of $49.9 million related to the bridge financing.

Our indebtedness consisted of the following:

	September 30, 2011		December 31, 2010
	(In thousands)
Commercial paper	$	—	$	56,904
Indebtedness to banks under credit facilities	340,000		—
6.75% senior notes ($450.0 million face value) due July 1, 2013	451,132		451,618
8.75% senior notes ($600.0 million face value) due August 1, 2016	588,496		587,126
7.00% senior notes due June 15, 2019 at par	1,000,000		—
7.25% senior notes due October 1, 2020 at par	500,000		500,000
7.25% senior notes due June 15, 2021 at par	1,000,000		—
Other	8,858		14,093
	3,888,486		1,609,741
Less current maturities of debt and short-term borrowings	47,156		70,997
Long-term debt	$	3,841,330	$	1,538,744

2019 and 2021 Senior Notes

Interest is payable on the 2019 Notes and 2021 Notes on June 15 and December 15 of each year, commencing December 15, 2011.  At any time prior to June 15, 2014, we may redeem up to 35% of the aggregate principal amount of each of the 2019 Notes

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and 2021 Notes, plus accrued and unpaid interest, with the net proceeds from certain equity offerings. We may redeem the 2019 Notes prior to June 15, 2015 and the 2021 Notes prior to June 15, 2016 at the respective make-whole prices set forth in the indenture. On or after June 15, 2015, we may redeem the 2019 Notes for cash at redemption prices, reflected as a percentage of the principal amount, of: 103.5% from June 15, 2015 through June 14, 2016; 101.75% from June 15, 2016 through June 14, 2017; and 100% beginning on June 15, 2017.  On or after June 15, 2016, we may redeem the 2021 Notes for cash at redemption prices, reflected as a percentage of the principal amount, of: 103.625% from June 15, 2016 through June 14, 2017; 102.417% from June 15, 2017 through June 14, 2018; 101.208% from June 15, 2018 through June 14, 2019; and 100% beginning on June 15, 2019. In each case, accrued and unpaid interest at the redemption date is due upon redemption. Upon a change in control, we are required to make a tender offer for both series of notes at a price of 101% of the principal amount.

The 2019 Notes and 2021 Notes are guaranteed by substantially all of our subsidiaries, including the newly acquired subsidiaries of ICG and excluding Arch Western, its subsidiaries and Arch Receivable Company, LLC and the Company’s subsidiaries outside the U.S. We incurred financing fees of $44.2 million related to the issuance of these notes.

We entered into a registration rights agreement (the “Registration Rights Agreement”) in connection with the issuance and sale of the 2019 Notes and 2021 Notes. Pursuant to the Registration Rights Agreement, we agreed to file a registration statement with the Securities and Exchange Commission to register an exchange offer pursuant to which the Company will offer to exchange a like aggregate principal amount of senior notes identical in all material respects to the 2019 Notes and 2021 Notes, except for terms relating to additional interest and transfer restrictions, for any or all of the outstanding 2019 Notes and 2021 Notes. Pursuant to the Registration Rights Agreement, we must use commercially reasonable efforts to cause the registration statement to become effective as soon as practicable and to complete the exchange offer no later than June 13, 2012. Should we fail to meet these obligations within the specified time frame, the applicable interest rates on the 2019 Notes and the 2021 Notes shall be increased by one-quarter of one percent per annum for the first 90 days following the occurrence of such failure. Such interest rates will increase by an additional one-quarter of one percent per annum thereafter at the end of each subsequent 90- day period up to a maximum aggregate increase of one percent per annum. Once any of the required events occur, the interest rates will revert to the rate specified in the indenture governing the 2019 Notes and 2021 Notes.

ICG Debt

Upon the closing of the acquisition, we gave our 30-day redemption notice to the Trustee of ICG’s 9.125% senior notes and legally discharged our obligation under the 9.125% senior notes by depositing $260.7 million with the Trustee to redeem the debt. On July 14, 2011, all of the outstanding 9.125% senior notes were redeemed at an aggregate price of $251.4 million, including the required make-whole premium, plus accrued interest of $5.2 million, and the remainder of the deposit was returned to us.

At the acquisition date, ICG’s 4.00% convertible senior notes with a fair value of $298.5 million and 9.00% convertible senior notes with a fair value of $1.7 million (“convertible notes”) became convertible into cash, pursuant to the amended indentures governing the convertible notes, at a calculated conversion rate of $2,614.6848 for each $1,000 in principal amount surrendered for conversion for the 4.00% convertible notes and $2,392.73414 for the 9.00% convertible notes for conversions occurring prior to August 17, 2011.

Other ICG debt, with a fair value of approximately $54.0 million at the acquisition date, consisted mainly of equipment notes and insurance notes payable.

We recognized net losses of $1.7 million and $2.0 million during the three and nine months ended September 30, 2011, respectively, on the early extinguishment of ICG’s debt, including the conversions of the 4.00% and 9.00% convertible notes described above. The remaining amounts outstanding of under the convertible notes and other ICG debt is included in “other” in the debt table above.

Credit Facilities

On June 14, 2011, we amended and restated our secured credit facility to allow for up to $2.0 billion in borrowings. Borrowings under this credit facility bear interest at a floating rate based on a LIBOR determined by reference to our leverage ratio, as calculated in accordance with the credit agreement.  The credit facility has a five-year term that expires on June 14, 2016 and is secured by substantially all of our assets as well as our ownership interests in substantially all of our subsidiaries, excluding our ownership interests in Arch Western and its subsidiaries. Commitment fees of 0.50% per annum are payable on the average unused daily balance of the revolving credit facility. We paid and deferred $20.7 million in financing fees related to the amendment of this agreement.

On June 14, 2011, we terminated our commercial paper placement program and the supporting credit facility.

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Availability

As of September 30, 2011 we had $300.0 million of borrowings outstanding under the amended and restated secured credit facility and $40.0 million of borrowings outstanding under our accounts receivable securitization program.  As of September 30, 2011, we had availability of approximately $1.0 billion under all lines of credit, as limited by customary financial covenants that may limit our total debt based on defined earnings measurements.  We also had outstanding letters of credit of $141 million as of September 30, 2011.

We have filed a universal shelf registration statement on Form S-3 with the SEC that allows us to offer and sell from time to time an unlimited amount of unsecured debt securities consisting of notes, debentures and other debt securities, common stock, preferred stock, warrants and/or units. Related proceeds could be used for general corporate purposes, including repayment of other debt, capital expenditures, possible acquisitions and any other purposes that may be stated in any related prospectus supplement.

The following is a summary of cash provided by or used in each of the indicated types of activities:

	Nine Months Ended September 30,
	2011			2010
	(Dollars in thousands)
Cash provided by (used in):
Operating activities	$	471,367		$	456,680
Investing activities	(3,174,006		)	(261,786		)
Financing activities	2,767,555			(192,279		)

Cash provided by operating activities increased in the first nine months of 2011 compared to the first nine months of 2010.  The increase is primarily due to higher operating income, partially offset by a build in coal inventories.

We used approximately $2.9 billion more cash in investing activities in the first nine months of 2011 compared to the amount used in the first nine months of 2010, due to the acquisition of ICG. These transactions are discussed previously in this section.

Cash provided by financing activities was $2.8 billion in the first nine months of 2011, compared to the cash used in financing activities during the first nine months of 2010 of $192.3 million. The change is a result of the proceeds from ICG acquisition financing transactions.  We paid financing costs of $114.6 million in conjunction with these transactions.  We also paid dividends of $57.5 million in the nine months ended September 30, 2011 and $47.1 million in the nine months ended September 30, 2010.

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:

	Nine Months Ended September 30
	2011		2010
Ratio of earnings to combined fixed charges and preference dividends	1.45	x	2.10	x

Critical Accounting Policies

For a description of our critical accounting policies, see “Critical Accounting Policies” under Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010. There have been no significant changes to our critical accounting policies during the three months ended September 30, 2011.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, and to a limited extent, through the use of derivative instruments. Our commitments for the full year 2011, 2012 and 2013 are as follows:

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	2011			2012			2013
	Tons	Price		Tons	Price		Tons	Price
Powder River Basin
Committed, Priced	117.5	$	13.60	93.3	$	14.49	42.7	$	14.91
Committed, Unpriced	0.5			8.4			11.5
Appalachia
Committed, Priced (Coking/PCI)	7.6	$	120.55	1.0	$	144.67	—	—
Committed, Priced (Thermal)	12.6	$	66.56	8.2	$	71.01	4.2	$	65.81
Western Bituminous Region
Committed, Priced	17.8	$	35.61	12.3	$	38.94	11.3	$	39.05

We are exposed to commodity price risk in our coal trading activities, which represents the potential future loss that could be caused by an adverse change in the market value of coal. Our coal trading portfolio included forward, swap and put and call option contracts at September 30, 2011.  The estimated future realization of the value of the trading portfolio is $2.4 million of gains for the remainder of 2011, $0.9 million of losses in 2012 and $1.0 million of losses in 2013.

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

VaR is a statistical one-tail confidence interval and down side risk estimate that relies on recent history to estimate how the value of the portfolio of positions will change if markets behave in the same way as they have in the recent past. While presenting VaR will provide a similar framework for discussing risk across companies, VaR estimates from two independent sources are rarely calculated in the same way. Without a thorough understanding of how each VaR model was calculated, it would be difficult to compare two different VaR calculations from different sources. The level of confidence is 95%. The time across which these possible value changes are being estimated is through the end of the next business day. A closed-form delta-neutral method used throughout the finance and energy sectors is employed to calculate this VaR. VaR is back tested to verify usefulness.

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

During the nine months ended September 30, 2011, VaR ranged from $0.7 million to $2.1 million. The linear mean of each daily VaR was $1.3 million. The final VaR at September 30, 2011 was $0.9 million.

We are also exposed to the risk of fluctuations in cash flows related to our purchase of diesel fuel. We expect to purchase approximately 90 to 100 million gallons of diesel fuel in our operations in 2012. We enter into forward physical purchase contracts, as well as heating oil swaps and options, to reduce volatility in the price of diesel fuel for our operations. At September 30, 2011, we had protected the price of approximately 70% of its remaining expected purchases for fiscal year 2011 and 55% for fiscal year 2012, mostly through the use of derivative instruments. Since the changes in the price of heating oil are highly correlated to changes in the price of the hedged diesel fuel purchases, the heating oil swaps and purchased call options qualify for cash flow hedge accounting. Accordingly, changes in the fair value of the derivatives are recorded through other comprehensive income, with any ineffectiveness recognized immediately in income. We have also purchased call options to hedge the fuel surcharges on our barge and rail shipments that cover increases in diesel fuel prices.  These positions reduce our risk of cash flow fluctuations related to these surcharges, but the positions are not accounted for as hedges.  At September 30, 2011, we held purchased call options for approximately 19.1 million gallons for the purpose of managing the fluctuations in cash flows associated with fuel surcharges on future shipments.

At September 30, 2011, a $0.25 per gallon decrease in the price of heating oil would result in an approximate $0.2 million increase in our expense related to the heating oil derivatives, which, if realized, would be offset by a decrease in the cost of our physical diesel purchases or fuel surcharges.

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We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At September 30, 2011, of our principal amount of debt outstanding, $340.0 million of outstanding borrowings have interest rates that fluctuate based on changes in the market rates. A one percentage point increase in the interest rates related to these borrowings would result in an annualized increase in interest expense of $3.4 million.

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 September 30, 2011. 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.

On June 15, 2011, we completed our acquisition of ICG.  While management does not expect significant changes to our financial reporting processes and related internal controls as a result of the ICG acquisition, it will take time for us to fully complete the integration of ICG’s information systems and personnel with ours.  Integration efforts are continuing as of September 30, 2011.

There have not been any other significant 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

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

As described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, surface mines at our Mingo Logan and Coal-Mac mining operations were identified in an existing lawsuit brought by the Ohio Valley Environmental Coalition (OVEC) in the U.S. District Court for the Southern District of West Virginia as having been granted Clean Water Act § 404 permits by the Army Corps of Engineers (“Corps”), allegedly in violation of the Clean Water Act and the National Environmental Policy Act.

The lawsuit, brought by OVEC in September 2005, originally was filed against the Corps for permits it had issued to four subsidiaries of a company unrelated to us or our operating subsidiaries. The suit claimed that the Corps had issued permits to the subsidiaries of the unrelated company that did not comply with the National Environmental Policy Act and violated the Clean Water Act.

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

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

In February 2009, the Fourth Circuit reversed the District Court. The Fourth Circuit held that the Corps’ jurisdiction under Section 404 of the Clean Water Act is limited to the narrow issue of the filling of jurisdictional waters. The court also held that the Corps’ findings of no significant impact under the National Environmental Policy Act and no significant degradation under the

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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.

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

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

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 reviews the “Recommended Determination” issued by the EPA Region 3. By Memorandum Opinion and Order dated November 2, 2010, the court granted the United States’ motion. On January 13, 2011, the EPA issued its “Final Determination” to withdraw the specification of two of the three watersheds as a disposal site for dredged or fill material approved under the current Section 404 permit. The court has been notified of the Final Determination and by order dated March 21, 2011 stayed further proceedings in the case until further order of the court, in light of the challenge to the EPA’s “Final Determination” currently pending in federal court in Washington, DC (as described below).

Additional information can be obtained from the U.S. District Court for the Southern District of West Virginia.

EPA Actions related to water discharges from the Spruce Permit

As described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, by letter of September 3, 2009, the EPA asked the Corps of Engineers to suspend, revoke or modify the existing permit it issued in January 2007 to Mingo Logan under Section 404 of the Clean Water Act, claiming that “new information and circumstances have arisen which justify reconsideration of the permit.” By letter of September 30, 2009, the Corps of Engineers advised the EPA that it would not reconsider its decision to issue the permit. By letter of October 16, 2009, the EPA advised the Corps that it has “reason to believe” that the Mingo Logan mine will have “unacceptable adverse impacts to fish and wildlife resources” and that it intends to issue a public notice of a proposed determination to restrict or prohibit discharges of fill material that already are approved by the Corps’ permit. By federal register publication dated April 2, 2010, the EPA issued its “Proposed Determination to Prohibit, Restrict or Deny the Specification, or the Use for Specification of an Area as a Disposal Site: Spruce No. 1 Surface Mine, Logan County, WV” pursuant to Section 404(c) of the Clean Water Act, the EPA accepted written comments on its proposed action (sometimes known as a “veto proceeding”), through June 4, 2010 and conducted a public hearing, as well, on May 18, 2010. We submitted comments on the action during this period. On September 24, 2010, the EPA Region 3 issued a “Recommended Determination” to the EPA Administrator recommending that the EPA prohibit the placement of fill material in two of the three watersheds for which filling is approved under the current Section 404 permit. Mingo Logan, along with the Corps, West Virginia DEP and the mineral owner, engaged in a consultation with the EPA as required by the regulations, to discuss “corrective action” to address the “unacceptable adverse effects” identified. On January 13, 2011, the EPA issued its “Final Determination” pursuant to Section 404(c) of the Clean Water Act to withdraw the specification of two of the three watersheds approved in the current Section 404 permit as a disposal site for dredged or fill material. By separate action, Mingo Logan sued the EPA on April 2, 2010 in federal court in Washington, D.C. seeking a ruling that the EPA has no authority under the Clean Water Act to veto a previously issued permit (Mingo Logan Coal Company, Inc. v. USEPA, No. 1:10-cv-00541(D.D.C.)). The EPA moved to dismiss that action, and we responded to that motion. The court has been notified of the “Final Determination” and on February 23, 2011 entered a scheduling order for summary disposition of the case.

Clean Water Act Request for Information

As described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, in January 2008, we received a request from the EPA for certain information related to compliance with effluent limitations and water quality standards under Section 308 of the Clean Water Act applicable to our eastern mining complexes located in West Virginia, Virginia and Kentucky. The request focuses on our compliance with water quality standards and effluent limitations at numerous outfalls as identified in the various NPDES permits applicable to our eastern mining complexes for the period beginning on January 1, 2003 through

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January 1, 2008. The compliance reporting mechanism is contained in Discharge Monitoring Reports which are required to be prepared and submitted quarterly to state environmental agencies and contain detailed monthly compliance data. In July 2008, the EPA referred the request to the U.S. Department of Justice. We negotiated a compromise with the Department of Justice, the EPA, the West Virginia Department of Environmental Protection and Kentucky Energy and Environment Cabinet to fully and finally resolve the issues identified in the EPA’s Section 308 Request for Information. The compromise is contained in a consent decree which includes certain elements of injunctive relief and a penalty in the amount of $4 million. The consent decree must be approved by the U.S. District Court for the Southern District of West Virginia before it becomes effective.

Litigation Matters Related to International Coal Group, Inc.

On June 15, 2011, we acquired International Coal Group, Inc. (“ICG”) and its subsidiaries.  The following matters related to certain claims and legal actions involving ICG and/or its subsidiaries.

As described in ICG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, on August 23, 2006, a survivor of the Sago mine accident, Randal McCloy, filed a complaint in the Kanawha Circuit Court in Kanawha County, West Virginia. The claims brought by Randal McCloy and his family against ICG and certain of its subsidiaries, and against W.L. Ross & Co., and Wilbur L. Ross, Jr., individually, were dismissed on February 14, 2008, after the parties reached a confidential settlement. Sixteen other complaints were filed in Kanawha Circuit Court by the representatives of many of the miners who died in the Sago mine accident, and several of these plaintiffs have filed amended complaints to expand the group of defendants in the cases. The complaints allege various causes of action against ICG and its subsidiary, Wolf Run Mining Company, one of its shareholders, W.L. Ross & Co., and Wilbur L. Ross, Jr., individually, related to the accident and seek compensatory and punitive damages. In addition, the plaintiffs also allege causes of action against other third parties, including claims against the manufacturer of Omega block seals used to seal the area where the explosion occurred and against the manufacturer of self-contained self-rescuer (“SCSR”) devices worn by the miners at the Sago mine. Some of these third parties have been dismissed from the actions upon settlement. The amended complaints add other of ICG’s subsidiaries to the cases, including ICG, Inc., ICG, LLC and Hunter Ridge Coal Company, unnamed parent, subsidiary and affiliate companies of ICG, W.L. Ross & Co., and Wilbur L. Ross, Jr., and other third parties, including a provider of electrical services and a supplier of components used in the SCSR devices. In addition to the dismissal of the McCloy claim, ICG previously settled and dismissed five other actions. These settlements required the release of ICG, its subsidiaries, W.L. Ross & Co., and Wilbur L. Ross, Jr. The court scheduled the matter for trial on all remaining claims beginning on April 16, 2012, and ordered the parties to mediate.  The parties recently engaged in mediation and reached a confidential settlement on all remaining claims.  This settlement is subject to court approval.

As described in ICG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, Allegheny Energy Supply (“Allegheny”), the sole customer of coal produced at our subsidiary Wolf Run Mining Company’s (“Wolf Run”) Sycamore No. 2 mine, filed a lawsuit against Wolf Run, Hunter Ridge Holdings, Inc. (“Hunter Ridge”), and ICG in state court in Allegheny County, Pennsylvania on December 28, 2006, and amended its complaint on April 23, 2007. Allegheny claimed that Wolf Run breached a coal supply contract when it declared force majeure under the contract upon idling the Sycamore No. 2 mine in the third quarter of 2006, and that Wolf Run continued to breach the contract by failing to ship in volumes referenced in the contract. The Sycamore No. 2 mine was idled after encountering adverse geologic conditions and abandoned gas wells that were previously unidentified and unmapped. After extensive searching for gas wells and rehabilitation of the mine, it was re-opened in 2007, but with notice to Allegheny that it would necessarily operate at reduced volumes in order to safely and effectively avoid the many gas wells within the reserve. The amended complaint also alleged that the production stoppages constitute a breach of the guarantee agreement by Hunter Ridge and breach of certain representations made upon entering into the contract in early 2005. Allegheny voluntarily dropped the breach of representation claims later. Allegheny claimed that it would incur costs in excess of $100 million to purchase replacement coal over the life of the contract. ICG, Wolf Run and Hunter Ridge answered the amended complaint on August 13, 2007, disputing all of the remaining claims.

On November 3, 2008, ICG, Wolf Run and Hunter Ridge filed an amended answer and counterclaim against the plaintiffs seeking to void the coal supply agreement due to, among other things, fraudulent inducement and conspiracy. On September 23, 2009, Allegheny filed a second amended complaint alleging several alternative theories of liability in its effort to extend contractual liability to ICG, which was not a party to the original contract and did not exist at the time Wolf Run and Allegheny entered into the contract. No new substantive claims were asserted. ICG answered the second amended complaint on October 13, 2009, denying all of the new claims. The Company’s counterclaim was dismissed on motion for summary judgment entered on May 11, 2010. Allegheny’s claims against ICG were also dismissed by summary judgment, but the claims against Wolf Run and Hunter Ridge were not. The court conducted a non-jury trial of this matter beginning on January 10, 2011 and concluding on February 1, 2011. At the trial, Allegheny presented its evidence for breach of contract and claimed that it is entitled to past and future damages in the aggregate of between $228 million and $377 million. Wolf Run and Hunter Ridge presented their defense of the claims, including evidence with respect to the existence of force majeure conditions and excuse under the contract and applicable law. Wolf Run and Hunter Ridge presented evidence that Allegheny’s damages calculations were significantly inflated

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because it did not seek to determine damages as of the time of the breach and in some instances artificially assumed future non-delivery or did not take into account the apparent requirement to supply coal in the future. On May 2, 2011, the trial court entered a Memorandum and Verdict determining that Wolf Run had breached the coal supply contract and that the performance shortfall was not excused by force majeure. The trial court awarded total damages and interest in the amount of $104.1 million. ICG and Allegheny filed post-verdict motions in the trial court and on August 23, 2011, the court denied the parties’ motions.  The court entered a final judgment on August 25, 2011, in the amount of $104.1 million, which included pre-judgment interest.  The parties appealed the lower court’s decision to the Superior Court of Pennsylvania.  Wolf Run and Hunter Ridge have filed an appeal bond in the amount of $124.9 million.  Briefing is scheduled to begin on October 24, 2011, to be completed in early 2012.

As described in ICG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, on January 7, 2008, Saratoga Advantage Trust (“Saratoga”) filed a class action lawsuit in the U.S. District Court for the Southern District of West Virginia against ICG and certain of its officers and directors seeking unspecified damages. The complaint asserts claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, based on alleged false and misleading statements in the registration statements filed in connection with ICG’s November 2005 reorganization and December 2005 public offering of common stock. In addition, the complaint challenges other of ICG’s public statements regarding its operating condition and safety record. On July 6, 2009, Saratoga filed an amended complaint asserting essentially the same claims but seeking to add an individual co-plaintiff. ICG has filed a motion to dismiss the amended complaint.  In June 2011, ICG agreed to settle this matter for a total of $1.375 million.  On August 1, 2011, the court issued its order preliminarily approving settlement and scheduled a settlement fairness hearing on November 14, 2011.

As described in ICG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, on June 11, 2010, the West Virginia Department of Environmental Protection (“WVDEP”) filed suit against ICG Eastern, LLC (“ICG Eastern”) alleging violations of the West Virginia Water Pollution Control/National Pollutant Discharge Elimination System (“WVNPDES”) and Surface Mine Permits for ICG Eastern’s Birch River surface mine. The WVDEP alleges that ICG Eastern has failed to fully comply with the effluent limits for aluminum, manganese, pH, iron and selenium contained in its WVNPDES permit. The complaint further alleges that violations of the WVNPDES permit effluent limits have caused violations of water quality standards for the same parameters in the streams receiving the discharges from this mine. The WVDEP also alleges that violations of the effluent limits in the WVNPDES permits are also violations of the regulations governing surface mining in West Virginia. ICG Eastern and the WVDEP executed a settlement agreement that will require ICG Eastern to pay a monetary penalty of $0.2 million and accept the imposition of a compliance schedule related to selenium and other water quality parameters. The settlement agreement was submitted to the Webster County Circuit Court on December 30, 2010, was made available for public comment by the WVDEP and was thereafter entered by the court on April 18, 2011. The settlement agreement resolves all of the WVDEP’s claims in the suit.  In a supplemental consent decree, WVDEP and ICG negotiated and agreed to a resolution related to certain alleged selenium effluent limit violations beginning after April 5, 2010 which were reserved from the original consent decree due to both administrative appeal board and state circuit court stays. The supplemental consent decree is currently pending before the court on a joint motion by WVDEP and ICG to enter the supplemental consent decree.

As described in ICG’s Annual Report on Form 10-K for the period ended December 31, 2010, the Sierra Club, on December 3, 2010, filed a Notice of Intent (“NOI”) to sue ICG Hazard, LLC (“Hazard”) alleging violations of the Clean Water Act and the Surface Mining Control and Reclamation Act of 1977 at Hazard’s Thunder Ridge surface mine. The NOI, which was supplemented by a revised filing on February 24, 2011, claims that Hazard is discharging selenium and contributing to conductivity levels in the receiving streams in violation of state and federal regulations.  On May 24, 2011, the Sierra Club sued Hazard in U.S. District Court for the Eastern District of Kentucky under the Citizens Suit provisions of the Clean Water Act and the Surface Mining Control and Reclamation Act seeking civil penalties, injunctive relief and attorneys’ fees.

As described in ICG’s Annual Report on Form 10-K for the period ended December 31, 2010, on December 3, 2010, the Kentucky Energy and Environment Cabinet (“Cabinet”) filed suit against Hazard, ICG Knott County, LLC, ICG East Kentucky, LLC and Powell Mountain Energy, LLC (collectively, “KY Operations”) alleging that the KY Operations failed to comply with the terms and conditions of the Kentucky Pollutant Discharge Elimination System (“KPDES”) permits issued by the Cabinet’s Division of Water to the KY Operations. Among the claims lodged by the Cabinet were allegations that contract water monitoring laboratories retained by the KY Operations did not adhere to the practices and procedures required for conducting KPDES monitoring, the contract laboratories failed to properly document and maintain records of the monitoring and the KY Operations submitted quarterly Discharge Monitoring Reports that sometimes contained inaccurate, incomplete and erroneous information. The KY Operations and the Cabinet entered a proposed Consent Judgment contemporaneously with the filing of the complaint that, if approved by the Franklin County (KY) Circuit Court, will require the KY Operations to pay a monetary penalty of $0.4 million, to prepare and implement a Corrective Action Plan that corrects the deficiencies in the respective KPDES monitoring programs, to identify the responsible corporate officers for each KPDES permit and to provide specific detailed information in support of the Discharge Monitoring Reports to be filed for the fourth quarter 2010 and first quarter 2011. Final resolution of this matter is pending approval by the court. On February 11, 2011, the court entered an order allowing certain anti-mining groups to

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intervene in the action to contest the validity of the Consent Judgment. The hearing on the entry of the Consent Judgment was held beginning August 30, 2011 and the matter is pending a decision from the court.

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

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, which could materially affect our business, financial condition or future results.  The risks described in our Annual Report on Form 10-K, as well as below, are not the only risks facing our Company.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

We may not be able to fully integrate the operations of ICG into our existing operations.

We believe that the acquisition of ICG will result in various benefits or synergies, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Arch Coal and ICG can be integrated in an efficient and effective manner. In addition, the combined company may experience unanticipated issues, expenses and liabilities.

It is possible that the integration process could take longer than anticipated or cost more than anticipated and could result in the loss of valuable employees, the disruption of each company’s ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect our ability to achieve the anticipated benefits and synergies of the merger. The integration process is subject to a number of uncertainties, and no assurance can be given that the anticipated benefits will be realized or, if realized, the timing or cost of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results and prospects, and may cause the combined company’s stock price to decline.

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 September 30, 2011, 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 September 30, 2011. Based on the closing price of our common stock as reported on the New York Stock Exchange on November 7, 2011, the approximate dollar value of our common stock that may yet be purchased under this program was $197.4 million.

Item 3.  Defaults Upon Senior Securities.

None

Item 4.  Reserved.

Item 5.  Other Information.

Mine Safety and Health Administration Safety Data

We believe that Arch Coal is one of the safest coal mining companies in the world.  Safety is a core value at Arch Coal and at our subsidiary operations.  We have in place a comprehensive safety program that includes extensive health & safety training for all employees, site inspections, emergency response preparedness, crisis communications training, incident investigation, regulatory compliance training and process auditing, as well as an open dialogue between all levels of employees.  The goals of our

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processes are to eliminate exposure to hazards in the workplace, ensure that we comply with all mine safety regulations, and support regulatory and industry efforts to improve the health and safety of our employees along with the industry as a whole.

Under the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act, each operator of a coal or other mine is required to include certain mine safety results in its periodic reports filed with the Securities and Exchange Commission.  The operation of our mines is subject to regulation by the federal Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”).  Below we present the following items regarding certain mine safety and health matters, broken down by mining complex owned and operated by Arch Coal or our subsidiaries, for the three-month period ended September 30, 2011:

·            Section 104 Citations:  Total number of violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA;

·            Section 104(b) Orders:  Total number of orders issued under section 104(b) of the Mine Act;

·            Section 104(d) Citations/Orders:  Total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under Section 104(d) of the Mine Act;

·            Section 107(a) Orders:  Total number of imminent danger orders issued under section 107(a) of the Mine Act; and

·            Total Dollar Value of Proposed MSHA Assessments:  Total dollar value of proposed assessments from MSHA under the Mine Act.

Mining complex(1)	Section 104 Citations	Section 104(b) Orders	Section 104(d) Citations/Orders	Section 107(a) Orders	Total Dollar Value of Proposed MSHA Assessments (in thousands)(2)
Power River Basin:
Black Thunder	—	—	—	—	$	—
Coal Creek	—	—	—	—		—
Western Bituminous:
Arch of Wyoming	1	—	—	—		0.2
Dugout Canyon	4	—	—	1		17.2
Skyline	4	—	—	—		0.1
Sufco	4	—	—	—		—
West Elk	11	—	—	—		29.7
Appalachia:
Beckley	34	1	—	—		29.5
Buckhannon	22	—	—	—		3.8
Coal-Mac	4	—	—	—		5.1
Cumberland River	23	—	2	—		12.8
East Kentucky	4	—	—	—		0.6
Eastern	3	—	—	—		1.0
Flint Ridge	7	—	2	—		42.5
Hazard	20	—	—	—		13.5
Knott County	29	1	1	—		10.0
Lone Mountain	31	—	—	—		21.3
Mountain Laurel	33	—	1	—		53.5
Patriot Mining	—	—	—	—		—
Powell Mountain	9	—	—	—		7.3
Raven	30	—	—	—		2.7
Sentinel	28	—	—	—		17.5
Tygart Valley	—	—	—	—		—
Upshur	—	—	—	—		0.2
Vindex Energy	12	—	1	—		2.7
Illinois:
Viper	24	—	1	—		88.3
Arch Coal Terminal	—	—	—	—		0.2
ADDCAR	—	—	—	—	$	—

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(1)   MSHA assigns an identification number to each coal mine and may or may not assign separate identification numbers to related facilities such as preparation plants.  We are providing the information in this table by mining complex rather than MSHA identification number because we believe this format will be more useful to investors than providing information based on MSHA identification numbers.  For descriptions of each of these mining operations please refer to the descriptions under Item 1. Business, in Part I of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

(2)   Amounts included under the heading “Total Dollar Value of Proposed MSHA Assessments” are the total dollar amounts for proposed assessments received from MSHA on or before October 24, 2011, for citations and orders occurring during the three-month period ended September 30, 2011.

For the three-month period ended September 30, 2011, none of our mining complexes received written notice from MSHA of (i) a flagrant violation under section 110(b)(2) of the Mine Act; (ii) a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under section 104(e) of the Mine Act; or (iii) the potential to have such a pattern.  Our Mountain Laurel mining complexes experienced one mining-related fatality during the three-month period ended September 30, 2011.

As of September 30, 2011, we had a total of 254 matters pending before the Federal Mine Safety and Health Review Commission.  This includes legal actions that were initiated prior to the three-month period ended September 30, 2011 and which do not necessarily relate to the citations, orders or proposed assessments issued by MSHA during such three-month period.

In evaluating the above information regarding mine safety and health, investors should take into account factors such as: (i) the number of citations and orders will vary depending on the size of a coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can be contested and appealed, and in that process are often reduced in severity and amount, and are sometimes dismissed.

Item 6.    Exhibits.

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

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 Steven F. Leer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of John T. Drexler.
32.1	Section 1350 Certification of Steven F. Leer.
32.2	Section 1350 Certification of John T. Drexler.
101	Interactive Data File

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Signatures

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

Arch Coal, Inc.
By:
	John T. Drexler
	Senior Vice President and Chief Financial Officer
	November  9, 2011

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