|
x
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
Delaware
|
|
51-0337383
|
(State or other jurisdiction of
incorporation or organization)
|
|
(I.R.S. Employer
Identification No.)
|
Class
|
|
Shares outstanding as of October 19, 2011
|
Common stock, $0.01 par value
|
|
226,821,506
|
|
TABLE OF CONTENTS
|
||
|
|
Page
|
PART I FINANCIAL INFORMATION
|
|
|
|
|
|
ITEM 1.
|
Condensed Financial Statements
|
|
|
||
|
||
|
||
|
||
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||
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ITEM 2.
|
||
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ITEM 3.
|
||
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ITEM 4.
|
||
|
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|
PART II OTHER INFORMATION
|
|
|
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|
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ITEM 1.
|
||
|
|
|
Risk Factors
|
||
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|
ITEM 5.
|
||
|
|
|
ITEM 6.
|
ITEM 1.
|
CONDENSED FINANCIAL STATEMENTS
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
September 30,
|
|
September 30,
|
||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||
Sales—Outside
|
$
|
1,421,689
|
|
|
$
|
1,260,499
|
|
|
$
|
4,293,167
|
|
|
$
|
3,650,129
|
|
Sales—Gas Royalty Interests
|
17,083
|
|
|
18,131
|
|
|
52,191
|
|
|
46,621
|
|
||||
Sales—Purchased Gas
|
1,155
|
|
|
3,524
|
|
|
3,297
|
|
|
8,280
|
|
||||
Freight—Outside
|
59,871
|
|
|
37,269
|
|
|
156,311
|
|
|
96,544
|
|
||||
Other Income
|
21,931
|
|
|
29,870
|
|
|
70,068
|
|
|
77,126
|
|
||||
Total Revenue and Other Income
|
1,521,729
|
|
|
1,349,293
|
|
|
4,575,034
|
|
|
3,878,700
|
|
||||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)
|
879,268
|
|
|
850,819
|
|
|
2,620,376
|
|
|
2,436,452
|
|
||||
Transaction and Financing Fees
|
14,907
|
|
|
337
|
|
|
14,907
|
|
|
64,415
|
|
||||
Loss on Debt Extinguishment
|
—
|
|
|
—
|
|
|
16,090
|
|
|
—
|
|
||||
Gas Royalty Interests Costs
|
15,409
|
|
|
16,408
|
|
|
46,582
|
|
|
40,133
|
|
||||
Purchased Gas Costs
|
398
|
|
|
3,333
|
|
|
2,850
|
|
|
6,980
|
|
||||
Freight Expense
|
59,871
|
|
|
37,269
|
|
|
156,122
|
|
|
96,544
|
|
||||
Selling, General and Administrative Expenses
|
46,692
|
|
|
38,722
|
|
|
130,311
|
|
|
107,897
|
|
||||
Depreciation, Depletion and Amortization
|
159,750
|
|
|
161,429
|
|
|
466,612
|
|
|
413,379
|
|
||||
Abandonment of Long-Lived Assets
|
338
|
|
|
—
|
|
|
115,817
|
|
|
—
|
|
||||
Interest Expense
|
58,884
|
|
|
66,430
|
|
|
189,963
|
|
|
139,613
|
|
||||
Taxes Other Than Income
|
85,790
|
|
|
83,406
|
|
|
265,121
|
|
|
243,831
|
|
||||
Total Costs
|
1,321,307
|
|
|
1,258,153
|
|
|
4,024,751
|
|
|
3,549,244
|
|
||||
Earnings Before Income Taxes
|
200,422
|
|
|
91,140
|
|
|
550,283
|
|
|
329,456
|
|
||||
Income Taxes
|
33,093
|
|
|
15,757
|
|
|
113,421
|
|
|
75,291
|
|
||||
Net Income
|
167,329
|
|
|
75,383
|
|
|
436,862
|
|
|
254,165
|
|
||||
Less: Net Income Attributable to Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,845
|
)
|
||||
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
$
|
167,329
|
|
|
$
|
75,383
|
|
|
$
|
436,862
|
|
|
$
|
242,320
|
|
Earnings Per Share:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.74
|
|
|
$
|
0.33
|
|
|
$
|
1.93
|
|
|
$
|
1.15
|
|
Dilutive
|
$
|
0.73
|
|
|
$
|
0.33
|
|
|
$
|
1.91
|
|
|
$
|
1.13
|
|
Weighted Average Number of Common Shares Outstanding:
|
|
|
|
|
|
|
|
||||||||
Basic
|
226,744,011
|
|
|
225,781,539
|
|
|
226,582,226
|
|
|
211,235,893
|
|
||||
Dilutive
|
229,163,537
|
|
|
228,092,299
|
|
|
229,002,863
|
|
|
213,638,176
|
|
||||
Dividends Paid Per Share
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.30
|
|
|
$
|
0.30
|
|
|
(Unaudited)
|
|
|
||||
|
September 30,
2011 |
|
December 31,
2010 |
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and Cash Equivalents
|
$
|
472,523
|
|
|
$
|
32,794
|
|
Accounts and Notes Receivable:
|
|
|
|
||||
Trade
|
503,076
|
|
|
252,530
|
|
||
Other Receivables
|
331,614
|
|
|
21,589
|
|
||
Accounts Receivable—Securitized
|
—
|
|
|
200,000
|
|
||
Inventories
|
241,691
|
|
|
258,538
|
|
||
Deferred Income Taxes
|
157,247
|
|
|
174,171
|
|
||
Recoverable Income Taxes
|
11,504
|
|
|
32,528
|
|
||
Prepaid Expenses
|
184,263
|
|
|
142,856
|
|
||
Total Current Assets
|
1,901,918
|
|
|
1,115,006
|
|
||
Property, Plant and Equipment:
|
|
|
|
||||
Property, Plant and Equipment
|
13,837,263
|
|
|
14,951,358
|
|
||
Less—Accumulated Depreciation, Depletion and Amortization
|
4,766,163
|
|
|
4,822,107
|
|
||
Total Property, Plant and Equipment—Net
|
9,071,100
|
|
|
10,129,251
|
|
||
Other Assets:
|
|
|
|
||||
Deferred Income Taxes
|
458,858
|
|
|
484,846
|
|
||
Restricted Cash
|
20,291
|
|
|
20,291
|
|
||
Investment in Affiliates
|
175,818
|
|
|
93,509
|
|
||
Other
|
535,063
|
|
|
227,707
|
|
||
Total Other Assets
|
1,190,030
|
|
|
826,353
|
|
||
TOTAL ASSETS
|
$
|
12,163,048
|
|
|
$
|
12,070,610
|
|
|
(Unaudited)
|
|
|
||||
|
September 30,
2011 |
|
December 31,
2010 |
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Accounts Payable
|
$
|
448,667
|
|
|
$
|
354,011
|
|
Short-Term Notes Payable
|
—
|
|
|
284,000
|
|
||
Current Portion of Long-Term Debt
|
20,306
|
|
|
24,783
|
|
||
Borrowings Under Securitization Facility
|
—
|
|
|
200,000
|
|
||
Other Accrued Liabilities
|
833,939
|
|
|
801,991
|
|
||
Total Current Liabilities
|
1,302,912
|
|
|
1,664,785
|
|
||
Long-Term Debt:
|
|
|
|
||||
Long-Term Debt
|
3,123,434
|
|
|
3,128,736
|
|
||
Capital Lease Obligations
|
55,298
|
|
|
57,402
|
|
||
Total Long-Term Debt
|
3,178,732
|
|
|
3,186,138
|
|
||
Deferred Credits and Other Liabilities:
|
|
|
|
||||
Postretirement Benefits Other Than Pensions
|
3,094,164
|
|
|
3,077,390
|
|
||
Pneumoconiosis Benefits
|
177,162
|
|
|
173,616
|
|
||
Mine Closing
|
401,049
|
|
|
393,754
|
|
||
Gas Well Closing
|
118,525
|
|
|
130,978
|
|
||
Workers’ Compensation
|
149,827
|
|
|
148,314
|
|
||
Salary Retirement
|
114,543
|
|
|
161,173
|
|
||
Reclamation
|
39,513
|
|
|
53,839
|
|
||
Other
|
159,878
|
|
|
144,610
|
|
||
Total Deferred Credits and Other Liabilities
|
4,254,661
|
|
|
4,283,674
|
|
||
TOTAL LIABILITIES
|
8,736,305
|
|
|
9,134,597
|
|
||
Stockholders’ Equity:
|
|
|
|
||||
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 227,289,426 Issued and 226,781,351 Outstanding at September 30, 2011; 227,289,426 Issued and 226,162,133 Outstanding at December 31, 2010
|
2,273
|
|
|
2,273
|
|
||
Capital in Excess of Par Value
|
2,219,783
|
|
|
2,178,604
|
|
||
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding
|
—
|
|
|
—
|
|
||
Retained Earnings
|
2,025,794
|
|
|
1,680,597
|
|
||
Accumulated Other Comprehensive Loss
|
(800,896
|
)
|
|
(874,338
|
)
|
||
Common Stock in Treasury, at Cost—508,075 Shares at September 30, 2011 and 1,127,293 Shares at December 31, 2010
|
(20,211
|
)
|
|
(42,659
|
)
|
||
Total CONSOL Energy Inc. Stockholders’ Equity
|
3,426,743
|
|
|
2,944,477
|
|
||
Noncontrolling Interest
|
—
|
|
|
(8,464
|
)
|
||
TOTAL EQUITY
|
3,426,743
|
|
|
2,936,013
|
|
||
TOTAL LIABILITIES AND EQUITY
|
$
|
12,163,048
|
|
|
$
|
12,070,610
|
|
|
Common
Stock
|
|
Capital in
Excess
of Par
Value
|
|
Retained
Earnings
(Deficit)
|
|
Accumulated
Other
Comprehensive
Income
(Loss)
|
|
Common
Stock in
Treasury
|
|
Total
CONSOL
Energy Inc.
Stockholders’
Equity
|
|
Non-
Controlling
Interest
|
|
Total
Equity
|
||||||||||||||||
Balance at December 31, 2010
|
$
|
2,273
|
|
|
$
|
2,178,604
|
|
|
$
|
1,680,597
|
|
|
$
|
(874,338
|
)
|
|
$
|
(42,659
|
)
|
|
$
|
2,944,477
|
|
|
$
|
(8,464
|
)
|
|
$
|
2,936,013
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net Income
|
—
|
|
|
—
|
|
|
436,862
|
|
|
—
|
|
|
—
|
|
|
436,862
|
|
|
—
|
|
|
436,862
|
|
||||||||
Treasury Rate Lock (Net of $59 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
|
—
|
|
|
(96
|
)
|
|
—
|
|
|
(96
|
)
|
||||||||
Gas Cash Flow Hedge (Net of $22,767 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
35,702
|
|
|
—
|
|
|
35,702
|
|
|
—
|
|
|
35,702
|
|
||||||||
Actuarially Determined Long-Term Liability Adjustments (Net of $23,547 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
37,836
|
|
|
—
|
|
|
37,836
|
|
|
—
|
|
|
37,836
|
|
||||||||
Comprehensive Income (Loss)
|
—
|
|
|
—
|
|
|
436,862
|
|
|
73,442
|
|
|
—
|
|
|
510,304
|
|
|
—
|
|
|
510,304
|
|
||||||||
Issuance of Treasury Stock
|
—
|
|
|
—
|
|
|
(23,693
|
)
|
|
—
|
|
|
22,448
|
|
|
(1,245
|
)
|
|
—
|
|
|
(1,245
|
)
|
||||||||
Tax Benefit From Stock-Based Compensation
|
—
|
|
|
4,096
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,096
|
|
|
—
|
|
|
4,096
|
|
||||||||
Amortization of Stock-Based Compensation Awards
|
—
|
|
|
37,083
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37,083
|
|
|
—
|
|
|
37,083
|
|
||||||||
Net Change in Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,464
|
|
|
8,464
|
|
||||||||
Dividends ($0.30 per share)
|
—
|
|
|
—
|
|
|
(67,972
|
)
|
|
—
|
|
|
—
|
|
|
(67,972
|
)
|
|
—
|
|
|
(67,972
|
)
|
||||||||
Balance at September 30, 2011
|
$
|
2,273
|
|
|
$
|
2,219,783
|
|
|
$
|
2,025,794
|
|
|
$
|
(800,896
|
)
|
|
$
|
(20,211
|
)
|
|
$
|
3,426,743
|
|
|
$
|
—
|
|
|
$
|
3,426,743
|
|
|
Nine Months Ended
|
||||||
|
September 30,
|
||||||
|
2011
|
|
2010
|
||||
Operating Activities:
|
|
|
|
||||
Net Income
|
$
|
436,862
|
|
|
$
|
254,165
|
|
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
|
|
|
|
||||
Depreciation, Depletion and Amortization
|
466,612
|
|
|
413,379
|
|
||
Abandonment of Long-Lived Assets
|
115,817
|
|
|
—
|
|
||
Stock-Based Compensation
|
37,083
|
|
|
33,580
|
|
||
Loss (Gain) on Sale of Assets
|
9,993
|
|
|
(8,475
|
)
|
||
Loss on Debt Extinguishment
|
16,090
|
|
|
—
|
|
||
Amortization of Mineral Leases
|
4,149
|
|
|
3,890
|
|
||
Deferred Income Taxes
|
120
|
|
|
3,372
|
|
||
Equity in Earnings of Affiliates
|
(19,989
|
)
|
|
(15,595
|
)
|
||
Changes in Operating Assets:
|
|
|
|
||||
Accounts and Notes Receivable
|
(50,212
|
)
|
|
(66,840
|
)
|
||
Inventories
|
16,264
|
|
|
45,126
|
|
||
Prepaid Expenses
|
(611
|
)
|
|
(26,216
|
)
|
||
Changes in Other Assets
|
16,446
|
|
|
23,764
|
|
||
Changes in Operating Liabilities:
|
|
|
|
||||
Accounts Payable
|
98,320
|
|
|
63,168
|
|
||
Other Operating Liabilities
|
66,589
|
|
|
109,371
|
|
||
Changes in Other Liabilities
|
29,432
|
|
|
14,051
|
|
||
Other
|
9,439
|
|
|
32,190
|
|
||
Net Cash Provided by Operating Activities
|
1,252,404
|
|
|
878,930
|
|
||
Investing Activities:
|
|
|
|
||||
Capital Expenditures
|
(997,463
|
)
|
|
(821,908
|
)
|
||
Acquisition of Dominion Exploration and Production Business
|
—
|
|
|
(3,474,199
|
)
|
||
Purchase of CNX Gas Noncontrolling Interest
|
—
|
|
|
(991,034
|
)
|
||
Proceeds from Sales of Assets
|
695,291
|
|
|
24,944
|
|
||
Distributions from Equity Affiliates
|
70,860
|
|
|
6,867
|
|
||
Net Cash Used in Investing Activities
|
(231,312
|
)
|
|
(5,255,330
|
)
|
||
Financing Activities:
|
|
|
|
||||
Payments on Short-Term Borrowings
|
(284,000
|
)
|
|
(258,950
|
)
|
||
Payments on Miscellaneous Borrowings
|
(9,320
|
)
|
|
(8,564
|
)
|
||
(Payments on) Proceeds from Securitization Facility
|
(200,000
|
)
|
|
150,000
|
|
||
Payments on Long-Term Notes, Including Redemption Premium
|
(265,785
|
)
|
|
—
|
|
||
Proceeds from Issuance of Long-Term Notes
|
250,000
|
|
|
2,750,000
|
|
||
Tax Benefit from Stock-Based Compensation
|
5,034
|
|
|
9,926
|
|
||
Dividends Paid
|
(67,972
|
)
|
|
(63,276
|
)
|
||
Proceeds from Issuance of Common Stock
|
—
|
|
|
1,828,862
|
|
||
Issuance of Treasury Stock
|
6,219
|
|
|
2,601
|
|
||
Debt Issuance and Financing Fees
|
(15,539
|
)
|
|
(84,224
|
)
|
||
Net Cash (Used In) Provided By Financing Activities
|
(581,363
|
)
|
|
4,326,375
|
|
||
Net Increase (Decrease) in Cash and Cash Equivalents
|
439,729
|
|
|
(50,025
|
)
|
||
Cash and Cash Equivalents at Beginning of Period
|
32,794
|
|
|
65,607
|
|
||
Cash and Cash Equivalents at End of Period
|
$
|
472,523
|
|
|
$
|
15,582
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||
|
September 30,
|
|
September 30,
|
||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||
Anti-Dilutive Options
|
1,154,051
|
|
|
819,189
|
|
|
1,154,051
|
|
|
819,189
|
|
Anti-Dilutive Restricted Stock Units
|
—
|
|
|
—
|
|
|
—
|
|
|
1,960
|
|
Anti-Dilutive Performance Share Units
|
21,675
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,175,726
|
|
|
819,189
|
|
|
1,154,051
|
|
|
821,149
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||
|
September 30,
|
|
September 30,
|
||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||
Options
|
72,254
|
|
|
23,562
|
|
|
311,003
|
|
|
146,555
|
|
Restricted Stock Units
|
20,589
|
|
|
35,355
|
|
|
424,958
|
|
|
340,699
|
|
Performance Share Units
|
—
|
|
|
—
|
|
|
40,752
|
|
|
109,955
|
|
|
92,843
|
|
|
58,917
|
|
|
776,713
|
|
|
597,209
|
|
|
Three Month Ended
|
|
Nine Months Ended
|
||||||||||||
|
September 30,
|
|
September 30,
|
||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||
Net income attributable to CONSOL Energy Inc. shareholders
|
$
|
167,329
|
|
|
$
|
75,383
|
|
|
$
|
436,862
|
|
|
$
|
242,320
|
|
Weighted average shares of common stock outstanding:
|
|
|
|
|
|
|
|
||||||||
Basic
|
226,744,011
|
|
|
225,781,539
|
|
|
226,582,226
|
|
|
211,235,893
|
|
||||
Effect of stock-based compensation awards
|
2,419,526
|
|
|
2,310,760
|
|
|
2,420,637
|
|
|
2,402,283
|
|
||||
Dilutive
|
229,163,537
|
|
|
228,092,299
|
|
|
229,002,863
|
|
|
213,638,176
|
|
||||
Earnings per share:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.74
|
|
|
$
|
0.33
|
|
|
$
|
1.93
|
|
|
$
|
1.15
|
|
Dilutive
|
$
|
0.73
|
|
|
$
|
0.33
|
|
|
$
|
1.91
|
|
|
$
|
1.13
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
September 30,
|
|
September 30,
|
||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||
Total Revenue and Other Income
|
$
|
1,502,660
|
|
|
$
|
1,341,784
|
|
|
$
|
4,531,696
|
|
|
$
|
3,862,000
|
|
Earnings Before Income Taxes
|
$
|
195,882
|
|
|
$
|
89,936
|
|
|
$
|
538,152
|
|
|
$
|
327,324
|
|
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
$
|
163,822
|
|
|
$
|
74,458
|
|
|
$
|
427,491
|
|
|
$
|
240,683
|
|
Basic Earnings Per Share
|
$
|
0.72
|
|
|
$
|
0.33
|
|
|
$
|
1.89
|
|
|
$
|
1.14
|
|
Dilutive Earnings Per Share
|
$
|
0.71
|
|
|
$
|
0.33
|
|
|
$
|
1.87
|
|
|
$
|
1.12
|
|
|
Three Months
|
|
Nine Months
|
||||
|
Ended
|
|
Ended
|
||||
|
September 30,
|
|
September 30,
|
||||
|
2010
|
|
2010
|
||||
Total Revenue and Other Income
|
$
|
1,349,293
|
|
|
$
|
3,945,687
|
|
Earnings Before Income Taxes
|
$
|
91,140
|
|
|
$
|
275,748
|
|
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
$
|
75,383
|
|
|
$
|
210,299
|
|
Basic Earnings Per Share
|
$
|
0.33
|
|
|
$
|
0.93
|
|
Dilutive Earnings Per Share
|
$
|
0.33
|
|
|
$
|
0.92
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||||||||||||||||||||||
|
Three Months Ended
|
|
Nine Months Ended
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||||||||||||||
|
September 30,
|
|
September 30,
|
|
September 30,
|
|
September 30,
|
||||||||||||||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||||||||||
Service cost
|
$
|
4,364
|
|
|
$
|
3,644
|
|
|
$
|
13,093
|
|
|
$
|
10,857
|
|
|
$
|
3,419
|
|
|
$
|
3,303
|
|
|
$
|
10,258
|
|
|
$
|
9,843
|
|
Interest cost
|
9,436
|
|
|
9,311
|
|
|
28,308
|
|
|
27,908
|
|
|
44,935
|
|
|
40,725
|
|
|
134,804
|
|
|
122,091
|
|
||||||||
Expected return on plan assets
|
(9,631
|
)
|
|
(9,262
|
)
|
|
(28,892
|
)
|
|
(27,786
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Amortization of prior service cost (credits)
|
(167
|
)
|
|
(184
|
)
|
|
(500
|
)
|
|
(551
|
)
|
|
(11,599
|
)
|
|
(11,604
|
)
|
|
(34,798
|
)
|
|
(34,811
|
)
|
||||||||
Recognized net actuarial loss
|
9,526
|
|
|
7,968
|
|
|
28,577
|
|
|
23,903
|
|
|
26,341
|
|
|
17,537
|
|
|
79,023
|
|
|
52,609
|
|
||||||||
Net periodic benefit cost
|
$
|
13,528
|
|
|
$
|
11,477
|
|
|
$
|
40,586
|
|
|
$
|
34,331
|
|
|
$
|
63,096
|
|
|
$
|
49,961
|
|
|
$
|
189,287
|
|
|
$
|
149,732
|
|
|
CWP
|
|
Workers’ Compensation
|
||||||||||||||||||||||||||||
|
Three Months Ended
|
|
Nine Months Ended
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||||||||||||||
|
September 30,
|
|
September 30,
|
|
September 30,
|
|
September 30,
|
||||||||||||||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||||||||||
Service cost
|
$
|
1,155
|
|
|
$
|
1,040
|
|
|
$
|
3,465
|
|
|
$
|
4,027
|
|
|
$
|
4,468
|
|
|
$
|
6,754
|
|
|
$
|
13,404
|
|
|
$
|
20,262
|
|
Interest cost
|
2,332
|
|
|
2,681
|
|
|
6,997
|
|
|
8,108
|
|
|
2,059
|
|
|
2,289
|
|
|
6,178
|
|
|
6,867
|
|
||||||||
Amortization of actuarial gain
|
(5,477
|
)
|
|
(5,777
|
)
|
|
(16,432
|
)
|
|
(16,536
|
)
|
|
(977
|
)
|
|
(768
|
)
|
|
(2,930
|
)
|
|
(2,304
|
)
|
||||||||
State administrative fees and insurance bond premiums
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,459
|
|
|
2,020
|
|
|
4,667
|
|
|
6,238
|
|
||||||||
Legal and administrative costs
|
750
|
|
|
750
|
|
|
2,250
|
|
|
2,250
|
|
|
719
|
|
|
785
|
|
|
2,156
|
|
|
2,354
|
|
||||||||
Net periodic (benefit) cost
|
$
|
(1,240
|
)
|
|
$
|
(1,306
|
)
|
|
$
|
(3,720
|
)
|
|
$
|
(2,151
|
)
|
|
$
|
7,728
|
|
|
$
|
11,080
|
|
|
$
|
23,475
|
|
|
$
|
33,417
|
|
|
For the Nine Months Ended September 30,
|
||||||||||||
|
2011
|
|
2010
|
||||||||||
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
||||||
Statutory U.S. federal income tax rate
|
$
|
192,599
|
|
|
35.0
|
%
|
|
$
|
115,310
|
|
|
35.0
|
%
|
Excess tax depletion
|
(76,561
|
)
|
|
(13.9
|
)
|
|
(49,852
|
)
|
|
(15.1
|
)
|
||
Effect of domestic production activities
|
(10,038
|
)
|
|
(1.8
|
)
|
|
(4,916
|
)
|
|
(1.5
|
)
|
||
Effect of federal tax accrual to tax return
|
(10,249
|
)
|
|
(1.9
|
)
|
|
3,163
|
|
|
1.0
|
|
||
IRS and state tax examination settlements
|
(5,187
|
)
|
|
(0.9
|
)
|
|
—
|
|
|
—
|
|
||
Net effect of state income taxes
|
16,088
|
|
|
2.9
|
|
|
9,220
|
|
|
2.8
|
|
||
Other
|
6,769
|
|
|
1.2
|
|
|
2,366
|
|
|
0.7
|
|
||
Income Tax Expense / Effective Rate
|
$
|
113,421
|
|
|
20.6
|
%
|
|
$
|
75,291
|
|
|
22.9
|
%
|
|
September 30,
2011 |
|
December 31,
2010 |
||||
Coal
|
$
|
90,914
|
|
|
$
|
108,694
|
|
Merchandise for resale
|
42,140
|
|
|
50,120
|
|
||
Supplies
|
108,637
|
|
|
99,724
|
|
||
Total Inventories
|
$
|
241,691
|
|
|
$
|
258,538
|
|
|
September 30,
2011 |
|
December 31,
2010 |
||||
Coal & other plant and equipment
|
$
|
5,094,572
|
|
|
$
|
5,100,085
|
|
Proven gas properties
|
1,507,682
|
|
|
1,662,605
|
|
||
Coal properties and surface lands
|
1,307,829
|
|
|
1,292,701
|
|
||
Unproven gas properties
|
1,280,354
|
|
|
2,206,399
|
|
||
Intangible drilling cost
|
1,234,529
|
|
|
1,116,884
|
|
||
Gas gathering equipment
|
925,668
|
|
|
941,772
|
|
||
Airshafts
|
660,324
|
|
|
662,315
|
|
||
Leased coal lands
|
540,051
|
|
|
536,603
|
|
||
Mine development
|
437,385
|
|
|
587,518
|
|
||
Coal advance mining royalties
|
395,362
|
|
|
389,379
|
|
||
Gas wells and related equipment
|
374,571
|
|
|
367,448
|
|
||
Other gas assets
|
74,981
|
|
|
84,571
|
|
||
Gas advance royalties
|
3,955
|
|
|
3,078
|
|
||
Total property, plant and equipment
|
13,837,263
|
|
|
14,951,358
|
|
||
Less Accumulated depreciation, depletion and amortization
|
4,766,163
|
|
|
4,822,107
|
|
||
Total Net Property, Plant and Equipment
|
$
|
9,071,100
|
|
|
$
|
10,129,251
|
|
|
September 30,
2011 |
|
December 31,
2010 |
||||
Debt:
|
|
|
|
||||
Senior notes due April 2017 at 8.00%, issued at par value
|
$
|
1,500,000
|
|
|
$
|
1,500,000
|
|
Senior notes due April 2020 at 8.25%, issued at par value
|
1,250,000
|
|
|
1,250,000
|
|
||
Senior notes due March 2021 at 6.375%, issued at par value
|
250,000
|
|
|
—
|
|
||
Senior secured notes due March 2012 at 7.875% (par value of $250,000 less unamortized discount of $242 at December 31, 2010)
|
—
|
|
|
249,758
|
|
||
Baltimore Port Facility revenue bonds in series due September 2025 at 5.75%
|
102,865
|
|
|
102,865
|
|
||
Advance royalty commitments (7.56% weighted average interest rate for September 30, 2011 and December 31, 2010)
|
32,211
|
|
|
32,211
|
|
||
Note Due December 2012 at 4.28%
|
—
|
|
|
10,438
|
|
||
Other long-term notes maturing at various dates through 2031
|
76
|
|
|
93
|
|
||
|
3,135,152
|
|
|
3,145,365
|
|
||
Less amounts due in one year
|
11,718
|
|
|
16,629
|
|
||
Long-Term Debt
|
$
|
3,123,434
|
|
|
$
|
3,128,736
|
|
|
Amount of Commitment
Expiration Per Period
|
||||||||||||||||||
|
Total
Amounts
Committed
|
|
Less Than
1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
Beyond
5 Years
|
||||||||||
Letters of Credit:
|
|
|
|
|
|
|
|
|
|
||||||||||
Employee-Related
|
$
|
197,947
|
|
|
$
|
90,573
|
|
|
$
|
107,374
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Environmental
|
56,994
|
|
|
55,266
|
|
|
1,728
|
|
|
—
|
|
|
—
|
|
|||||
Gas
|
70,213
|
|
|
14,913
|
|
|
55,300
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
10,305
|
|
|
164
|
|
|
10,141
|
|
|
—
|
|
|
—
|
|
|||||
Total Letters of Credit
|
335,459
|
|
|
160,916
|
|
|
174,543
|
|
|
—
|
|
|
—
|
|
|||||
Surety Bonds:
|
|
|
|
|
|
|
|
|
|
||||||||||
Employee-Related
|
204,895
|
|
|
204,895
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Environmental
|
434,621
|
|
|
434,251
|
|
|
370
|
|
|
—
|
|
|
—
|
|
|||||
Gas
|
9,872
|
|
|
9,806
|
|
|
65
|
|
|
—
|
|
|
1
|
|
|||||
Other
|
17,456
|
|
|
17,456
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total Surety Bonds
|
666,844
|
|
|
666,408
|
|
|
435
|
|
|
—
|
|
|
1
|
|
|||||
Guarantees:
|
|
|
|
|
|
|
|
|
|
||||||||||
Coal
|
73,462
|
|
|
44,994
|
|
|
22,968
|
|
|
1,000
|
|
|
4,500
|
|
|||||
Gas
|
105,346
|
|
|
52,239
|
|
|
22,485
|
|
|
—
|
|
|
30,622
|
|
|||||
Other
|
374,311
|
|
|
72,335
|
|
|
120,230
|
|
|
72,514
|
|
|
109,232
|
|
|||||
Total Guarantees
|
553,119
|
|
|
169,568
|
|
|
165,683
|
|
|
73,514
|
|
|
144,354
|
|
|||||
Total Commitments
|
$
|
1,555,422
|
|
|
$
|
996,892
|
|
|
$
|
340,661
|
|
|
$
|
73,514
|
|
|
$
|
144,355
|
|
Obligations Due
|
Amount
|
||
Less than 1 year
|
$
|
228,316
|
|
1 - 3 years
|
343,911
|
|
|
3 - 5 years
|
388,838
|
|
|
More than 5 years
|
1,855,746
|
|
|
Total Purchase Obligations
|
$
|
2,816,811
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
September 30,
|
|
September 30,
|
||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||
Major equipment purchases
|
$
|
12,889
|
|
|
$
|
10,687
|
|
|
$
|
30,066
|
|
|
$
|
37,835
|
|
Firm transportation expense
|
15,225
|
|
|
9,021
|
|
|
43,359
|
|
|
25,124
|
|
||||
Gas drilling obligations
|
24,423
|
|
|
5,934
|
|
|
74,587
|
|
|
6,564
|
|
||||
Other
|
65
|
|
|
265
|
|
|
256
|
|
|
597
|
|
||||
Total costs related to purchase obligations
|
$
|
52,602
|
|
|
$
|
25,907
|
|
|
$
|
148,268
|
|
|
$
|
70,120
|
|
Derivative in Cash Flow Hedging Relationship
|
Amount of
Gain
Recognized
in OCI on
Derivative
2011
|
|
Location of
Gain
Reclassified
from
Accumulated
OCI into
Income
|
|
Amount of
Gain
Reclassified
from
Accumulated
OCI into
Income
2011
|
|
Location of
Gain
Recognized in
Income on
Derivative
|
|
Amount of
Gain Recognized
in Income on
Derivative
2011
|
||||||
Natural Gas Price Swaps
|
$
|
59,953
|
|
|
Outside Sales
|
|
$
|
20,974
|
|
|
Outside Sales
|
|
$
|
333
|
|
Total
|
$
|
59,953
|
|
|
|
|
$
|
20,974
|
|
|
|
|
$
|
333
|
|
Derivative in Cash Flow Hedging Relationship
|
Amount of
Gain Recognized in OCI on Derivative 2011 |
|
Location of
Gain Reclassified from Accumulated OCI into Income |
|
Amount of
Gain Reclassified from Accumulated OCI into Income 2011 |
|
Location of
Gain Recognized in Income on Derivative |
|
Amount of
Gain Recognized in Income on Derivative 2011 |
||||||
Natural Gas Price Swaps
|
$
|
92,718
|
|
|
Outside Sales
|
|
$
|
56,719
|
|
|
Outside Sales
|
|
$
|
297
|
|
Total
|
$
|
92,718
|
|
|
|
|
$
|
56,719
|
|
|
|
|
$
|
297
|
|
Derivative in Cash Flow Hedging Relationship
|
Amount of
Gain
Recognized
in OCI on
Derivative
2010
|
|
Location of
Gain
Reclassified
from
Accumulated
OCI into
Income
|
|
Amount of
Gain
Reclassified
from
Accumulated
OCI into
Income
2010
|
|
Location of
(Loss) Recognized
in Income on
Derivative
|
|
Amount of
(Loss) Recognized
in Income on
Derivative
2010
|
||||||
Natural Gas Price Swaps
|
$
|
43,367
|
|
|
Outside Sales
|
|
$
|
40,711
|
|
|
Outside Sales
|
|
$
|
(98
|
)
|
Total
|
$
|
43,367
|
|
|
|
|
$
|
40,711
|
|
|
|
|
$
|
(98
|
)
|
Derivative in Cash Flow Hedging Relationship
|
Amount of
Gain
Recognized
in OCI on
Derivative
2010
|
|
Location of
Gain
Reclassified
from
Accumulated
OCI into
Income
|
|
Amount of
Gain
Reclassified
from
Accumulated
OCI into
Income
2010
|
|
Location of
Gain
Recognized in
Income on
Derivative
|
|
Amount of
Gain
Recognized
in Income on
Derivative
2010
|
||||||
Natural Gas Price Swaps
|
$
|
132,895
|
|
|
Outside Sales
|
|
$
|
138,645
|
|
|
Outside Sales
|
|
$
|
50
|
|
Total
|
$
|
132,895
|
|
|
|
|
$
|
138,645
|
|
|
|
|
$
|
50
|
|
|
Treasury
Rate
Lock
|
|
Change in
Fair Value
of Cash Flow
Hedges
|
|
Adjustments
for Actuarially
Determined
Liabilities
|
|
Accumulated
Other
Comprehensive
Loss
|
||||||||
Balance at December 31, 2010
|
$
|
96
|
|
|
$
|
46,087
|
|
|
$
|
(920,521
|
)
|
|
$
|
(874,338
|
)
|
Net increase in value of cash flow hedge
|
—
|
|
|
92,718
|
|
|
—
|
|
|
92,718
|
|
||||
Reclassification of cash flow hedges from other comprehensive income to earnings
|
—
|
|
|
(57,016
|
)
|
|
—
|
|
|
(57,016
|
)
|
||||
Current period change
|
(96
|
)
|
|
—
|
|
|
37,836
|
|
|
37,740
|
|
||||
Balance at September 30, 2011
|
$
|
—
|
|
|
$
|
81,789
|
|
|
$
|
(882,685
|
)
|
|
$
|
(800,896
|
)
|
|
Fair Value Measurements at September 30, 2011
|
|
Fair Value Measurements at December 31, 2010
|
||||||||||||||||||||
Description
|
Quoted Prices in
Active Markets
for Identical
Liabilities
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Quoted Prices in
Active Markets
for Identical
Liabilities
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
||||||||||||
Gas Cash Flow Hedges
|
$
|
—
|
|
|
$
|
135,004
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
76,240
|
|
|
$
|
—
|
|
|
September 30, 2011
|
|
December 31, 2010
|
||||||||||||
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
Cash and cash equivalents
|
$
|
472,523
|
|
|
$
|
472,523
|
|
|
$
|
32,794
|
|
|
$
|
32,794
|
|
Restricted cash
|
$
|
20,291
|
|
|
$
|
20,291
|
|
|
$
|
20,291
|
|
|
$
|
20,291
|
|
Short-term notes payable
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(284,000
|
)
|
|
$
|
(284,000
|
)
|
Borrowings under Securitization Facility
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(200,000
|
)
|
|
$
|
(200,000
|
)
|
Long-term debt
|
$
|
(3,135,152
|
)
|
|
$
|
(3,282,549
|
)
|
|
$
|
(3,145,365
|
)
|
|
$
|
(3,341,406
|
)
|
|
Steam
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total Coal
|
|
Coalbed
Methane
|
|
Marcellus
Shale
|
|
Conventional
Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
All
Other
|
|
Corporate,
Adjustments
&
Eliminations
|
|
Consolidated
|
|
||||||||||||||||||||||||||
Sales—outside
|
$
|
732,135
|
|
|
$
|
307,969
|
|
|
$
|
83,065
|
|
|
$
|
12,593
|
|
|
$
|
1,135,762
|
|
|
$
|
116,954
|
|
|
$
|
39,036
|
|
|
$
|
38,974
|
|
|
$
|
3,410
|
|
|
$
|
198,374
|
|
|
$
|
87,553
|
|
|
$
|
—
|
|
|
$
|
1,421,689
|
|
|
Sales—purchased gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,155
|
|
|
1,155
|
|
|
—
|
|
|
—
|
|
|
1,155
|
|
|
|||||||||||||
Sales—gas royalty interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,083
|
|
|
17,083
|
|
|
—
|
|
|
—
|
|
|
17,083
|
|
|
|||||||||||||
Freight—outside
|
—
|
|
|
—
|
|
|
—
|
|
|
59,871
|
|
|
59,871
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
59,871
|
|
|
|||||||||||||
Intersegment transfers
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
726
|
|
|
726
|
|
|
49,668
|
|
|
(50,394
|
)
|
|
—
|
|
|
|||||||||||||
Total Sales and Freight
|
$
|
732,135
|
|
|
$
|
307,969
|
|
|
$
|
83,065
|
|
|
$
|
72,464
|
|
|
$
|
1,195,633
|
|
|
$
|
116,954
|
|
|
$
|
39,036
|
|
|
$
|
38,974
|
|
|
$
|
22,374
|
|
|
$
|
217,338
|
|
|
$
|
137,221
|
|
|
$
|
(50,394
|
)
|
|
$
|
1,499,798
|
|
|
Earnings (Loss) Before Income Taxes
|
$
|
83,505
|
|
|
$
|
200,742
|
|
|
$
|
24,091
|
|
|
$
|
(40,061
|
)
|
|
$
|
268,277
|
|
|
$
|
39,522
|
|
|
$
|
11,723
|
|
|
$
|
(8,602
|
)
|
|
$
|
(42,074
|
)
|
|
$
|
569
|
|
|
$
|
9,561
|
|
|
$
|
(77,985
|
)
|
|
$
|
200,422
|
|
(A)
|
Segment assets
|
|
|
|
|
|
|
|
|
$
|
5,131,432
|
|
|
|
|
|
|
|
|
|
|
$
|
5,959,480
|
|
|
$
|
329,207
|
|
|
$
|
742,929
|
|
|
$
|
12,163,048
|
|
(B)
|
||||||||||||||||
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
$
|
96,797
|
|
|
|
|
|
|
|
|
|
|
$
|
58,131
|
|
|
$
|
4,822
|
|
|
$
|
—
|
|
|
$
|
159,750
|
|
|
||||||||||||||||
Capital expenditures
|
|
|
|
|
|
|
|
|
$
|
182,588
|
|
|
|
|
|
|
|
|
|
|
$
|
215,830
|
|
|
$
|
13,604
|
|
|
$
|
—
|
|
|
$
|
412,022
|
|
|
(A)
|
Includes equity in earnings of unconsolidated affiliates of $
4,842
, $
693
and $
3,142
for Coal, Gas and All Other, respectively.
|
(B)
|
Includes investments in unconsolidated equity affiliates of $
33,037
, $
91,853
and $
50,928
for Coal, Gas and All Other, respectively.
|
|
Steam
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total
Coal
|
|
Coalbed
Methane
|
|
Marcellus
Shale
|
|
Conventional
Gas
|
|
Other
Gas
|
|
Total Gas
|
|
All
Other
|
|
Corporate,
Adjustments
&
Eliminations
|
|
Consolidated
|
|
||||||||||||||||||||||||||
Sales—outside
|
$
|
740,612
|
|
|
$
|
215,394
|
|
|
$
|
22,208
|
|
|
$
|
3,337
|
|
|
$
|
981,551
|
|
|
$
|
140,801
|
|
|
$
|
15,572
|
|
|
$
|
45,254
|
|
|
$
|
1,975
|
|
|
$
|
203,602
|
|
|
$
|
75,346
|
|
|
$
|
—
|
|
|
$
|
1,260,499
|
|
|
Sales—purchased gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,524
|
|
|
3,524
|
|
|
—
|
|
|
—
|
|
|
3,524
|
|
|
|||||||||||||
Sales—gas royalty interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,131
|
|
|
18,131
|
|
|
—
|
|
|
—
|
|
|
18,131
|
|
|
|||||||||||||
Freight—outside
|
—
|
|
|
—
|
|
|
—
|
|
|
37,269
|
|
|
37,269
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37,269
|
|
|
|||||||||||||
Intersegment transfers
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
852
|
|
|
852
|
|
|
42,359
|
|
|
(43,211
|
)
|
|
—
|
|
|
|||||||||||||
Total Sales and Freight
|
$
|
740,612
|
|
|
$
|
215,394
|
|
|
$
|
22,208
|
|
|
$
|
40,606
|
|
|
$
|
1,018,820
|
|
|
$
|
140,801
|
|
|
$
|
15,572
|
|
|
$
|
45,254
|
|
|
$
|
24,482
|
|
|
$
|
226,109
|
|
|
$
|
117,705
|
|
|
$
|
(43,211
|
)
|
|
$
|
1,319,423
|
|
|
Earnings (Loss) Before Income Taxes
|
$
|
68,497
|
|
|
$
|
135,171
|
|
|
$
|
11,599
|
|
|
$
|
(96,684
|
)
|
|
$
|
118,583
|
|
|
$
|
59,259
|
|
|
$
|
2,591
|
|
|
$
|
(2,389
|
)
|
|
$
|
(23,938
|
)
|
|
$
|
35,523
|
|
|
$
|
8,853
|
|
|
$
|
(71,819
|
)
|
|
$
|
91,140
|
|
(C)
|
Segment assets
|
|
|
|
|
|
|
|
|
$
|
4,948,966
|
|
|
|
|
|
|
|
|
|
|
$
|
5,868,941
|
|
|
$
|
324,638
|
|
|
$
|
579,213
|
|
|
$
|
11,721,758
|
|
(D)
|
||||||||||||||||
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
$
|
98,101
|
|
|
|
|
|
|
|
|
|
|
$
|
58,909
|
|
|
$
|
4,419
|
|
|
$
|
—
|
|
|
$
|
161,429
|
|
|
||||||||||||||||
Capital expenditures
|
|
|
|
|
|
|
|
|
$
|
132,847
|
|
|
|
|
|
|
|
|
|
|
$
|
102,235
|
|
|
$
|
7,735
|
|
|
$
|
—
|
|
|
$
|
242,817
|
|
|
(C)
|
Includes equity in earnings of unconsolidated affiliates of $
4,142
,
$785
and $
1,976
for Coal, Gas and All Other, respectively.
|
(D)
|
Includes investments in unconsolidated equity affiliates of $
20,472
, $
24,651
and $
47,138
for Coal, Gas and All Other, respectively.
|
|
Steam
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total Coal
|
|
Coalbed
Methane
|
|
Marcellus
Shale
|
|
Conventional
Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
All
Other
|
|
Corporate,
Adjustments
&
Eliminations
|
|
Consolidated
|
|
||||||||||||||||||||||||||
Sales—outside
|
$
|
2,315,467
|
|
|
$
|
824,035
|
|
|
$
|
278,986
|
|
|
$
|
59,465
|
|
|
$
|
3,477,953
|
|
|
$
|
346,713
|
|
|
$
|
88,316
|
|
|
$
|
119,899
|
|
|
$
|
8,696
|
|
|
$
|
563,624
|
|
|
$
|
251,590
|
|
|
$
|
—
|
|
|
$
|
4,293,167
|
|
|
Sales—purchased gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,297
|
|
|
3,297
|
|
|
—
|
|
|
—
|
|
|
3,297
|
|
|
|||||||||||||
Sales—gas royalty interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52,191
|
|
|
52,191
|
|
|
—
|
|
|
—
|
|
|
52,191
|
|
|
|||||||||||||
Freight—outside
|
—
|
|
|
—
|
|
|
—
|
|
|
156,311
|
|
|
156,311
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
156,311
|
|
|
|||||||||||||
Intersegment transfers
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,648
|
|
|
2,648
|
|
|
158,307
|
|
|
(160,955
|
)
|
|
—
|
|
|
|||||||||||||
Total Sales and Freight
|
$
|
2,315,467
|
|
|
$
|
824,035
|
|
|
$
|
278,986
|
|
|
$
|
215,776
|
|
|
$
|
3,634,264
|
|
|
$
|
346,713
|
|
|
$
|
88,316
|
|
|
$
|
119,899
|
|
|
$
|
66,832
|
|
|
$
|
621,760
|
|
|
$
|
409,897
|
|
|
$
|
(160,955
|
)
|
|
$
|
4,504,966
|
|
|
Earnings (Loss) Before Income Taxes
|
$
|
372,653
|
|
|
$
|
524,855
|
|
|
$
|
111,012
|
|
|
$
|
(289,401
|
)
|
|
$
|
719,119
|
|
|
$
|
119,092
|
|
|
$
|
24,605
|
|
|
$
|
(14,434
|
)
|
|
$
|
(76,272
|
)
|
|
$
|
52,991
|
|
|
$
|
12,134
|
|
|
$
|
(233,961
|
)
|
|
$
|
550,283
|
|
(E)
|
Segment assets
|
|
|
|
|
|
|
|
|
$
|
5,131,432
|
|
|
|
|
|
|
|
|
|
|
$
|
5,959,480
|
|
|
$
|
329,207
|
|
|
$
|
742,929
|
|
|
$
|
12,163,048
|
|
(F)
|
||||||||||||||||
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
$
|
293,793
|
|
|
|
|
|
|
|
|
|
|
$
|
159,109
|
|
|
$
|
13,710
|
|
|
$
|
—
|
|
|
$
|
466,612
|
|
|
||||||||||||||||
Capital expenditures
|
|
|
|
|
|
|
|
|
$
|
435,818
|
|
|
|
|
|
|
|
|
|
|
$
|
535,067
|
|
|
$
|
26,578
|
|
|
$
|
—
|
|
|
$
|
997,463
|
|
|
(F)
|
Includes investments in unconsolidated equity affiliates of
$33,037
,
$91,853
and
$50,928
for Coal, Gas and All Other, respectively.
|
|
Steam
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total Coal
|
|
Coalbed
Methane
|
|
Marcellus
Shale
|
|
Conventional
Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
All
Other
|
|
Corporate,
Adjustments
&
Eliminations
|
|
Consolidated
|
|
||||||||||||||||||||||||||
Sales—outside
|
$
|
2,202,931
|
|
|
$
|
490,996
|
|
|
$
|
135,230
|
|
|
$
|
32,498
|
|
|
$
|
2,861,655
|
|
|
$
|
451,149
|
|
|
$
|
33,956
|
|
|
$
|
78,005
|
|
|
$
|
5,068
|
|
|
$
|
568,178
|
|
|
$
|
220,296
|
|
|
$
|
—
|
|
|
$
|
3,650,129
|
|
|
Sales—purchased gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,280
|
|
|
8,280
|
|
|
—
|
|
|
—
|
|
|
8,280
|
|
|
|||||||||||||
Sales—gas royalty interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,621
|
|
|
46,621
|
|
|
—
|
|
|
—
|
|
|
46,621
|
|
|
|||||||||||||
Freight—outside
|
—
|
|
|
—
|
|
|
—
|
|
|
96,544
|
|
|
96,544
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
96,544
|
|
|
|||||||||||||
Intersegment transfers
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,413
|
|
|
2,413
|
|
|
129,529
|
|
|
(131,942
|
)
|
|
—
|
|
|
|||||||||||||
Total Sales and Freight
|
$
|
2,202,931
|
|
|
$
|
490,996
|
|
|
$
|
135,230
|
|
|
$
|
129,042
|
|
|
$
|
2,958,199
|
|
|
$
|
451,149
|
|
|
$
|
33,956
|
|
|
$
|
78,005
|
|
|
$
|
62,382
|
|
|
$
|
625,492
|
|
|
$
|
349,825
|
|
|
$
|
(131,942
|
)
|
|
$
|
3,801,574
|
|
|
Earnings (Loss) Before Income Taxes
|
$
|
316,228
|
|
|
$
|
268,547
|
|
|
$
|
70,563
|
|
|
$
|
(306,170
|
)
|
|
$
|
349,168
|
|
|
$
|
211,179
|
|
|
$
|
4,953
|
|
|
$
|
998
|
|
|
$
|
(53,729
|
)
|
|
$
|
163,401
|
|
|
$
|
18,477
|
|
|
$
|
(201,590
|
)
|
|
$
|
329,456
|
|
(G)
|
Segment assets
|
|
|
|
|
|
|
|
|
$
|
4,948,966
|
|
|
|
|
|
|
|
|
|
|
$
|
5,868,941
|
|
|
$
|
324,638
|
|
|
$
|
579,213
|
|
|
$
|
11,721,758
|
|
(H)
|
||||||||||||||||
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
$
|
259,849
|
|
|
|
|
|
|
|
|
|
|
$
|
139,954
|
|
|
$
|
13,576
|
|
|
$
|
—
|
|
|
$
|
413,379
|
|
|
||||||||||||||||
Capital expenditures
|
|
|
|
|
|
|
|
|
$
|
517,515
|
|
|
|
|
|
|
|
|
|
|
$
|
3,766,694
|
|
|
$
|
11,898
|
|
|
$
|
—
|
|
|
$
|
4,296,107
|
|
|
(H)
|
Includes investments in unconsolidated equity affiliates of
$20,472
,
$24,651
and
$47,138
for Coal, Gas and All Other, respectively.
|
|
For the Three Months Ended September 30,
|
|
For the Nine Months Ended September 30,
|
||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||
Segment Earnings Before Income Taxes for total reportable business segments
|
$
|
268,846
|
|
|
$
|
154,106
|
|
|
$
|
772,110
|
|
|
$
|
512,569
|
|
Segment Earnings Before Income Taxes for all other businesses
|
9,561
|
|
|
8,853
|
|
|
12,134
|
|
|
18,477
|
|
||||
Interest income (expense), net and other non-operating activity (I)
|
(61,167
|
)
|
|
(69,819
|
)
|
|
(197,792
|
)
|
|
(139,092
|
)
|
||||
Transaction and Financing Fees (I)
|
(14,907
|
)
|
|
(334
|
)
|
|
(14,907
|
)
|
|
(61,084
|
)
|
||||
Evaluation fees for non-core asset dispositions (I)
|
(1,911
|
)
|
|
(1,788
|
)
|
|
(5,172
|
)
|
|
(1,788
|
)
|
||||
Loss on debt extinguishment
|
—
|
|
|
—
|
|
|
(16,090
|
)
|
|
—
|
|
||||
Operating lease cease-use
|
—
|
|
|
122
|
|
|
—
|
|
|
374
|
|
||||
Earnings Before Income Taxes
|
$
|
200,422
|
|
|
$
|
91,140
|
|
|
$
|
550,283
|
|
|
$
|
329,456
|
|
Total Assets:
|
September 30,
|
||||||
2011
|
|
2010
|
|||||
Segment assets for total reportable business segments
|
$
|
11,090,912
|
|
|
$
|
10,817,907
|
|
Segment assets for all other businesses
|
329,207
|
|
|
324,638
|
|
||
Items excluded from segment assets:
|
|
|
|
||||
Cash and other investments (I)
|
64,436
|
|
|
14,996
|
|
||
Recoverable income taxes
|
11,504
|
|
|
27,907
|
|
||
Deferred tax assets
|
616,105
|
|
|
482,836
|
|
||
Bond issuance costs
|
50,884
|
|
|
53,474
|
|
||
Total Consolidated Assets
|
$
|
12,163,048
|
|
|
$
|
11,721,758
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
199,100
|
|
|
$
|
1,163,339
|
|
|
$
|
60,873
|
|
|
$
|
(1,623
|
)
|
|
$
|
1,421,689
|
|
Sales—Purchased Gas
|
—
|
|
|
1,155
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,155
|
|
||||||
Sales—Gas Royalty Interests
|
—
|
|
|
17,083
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,083
|
|
||||||
Freight—Outside
|
—
|
|
|
—
|
|
|
59,871
|
|
|
—
|
|
|
—
|
|
|
59,871
|
|
||||||
Other Income (including equity earnings)
|
232,472
|
|
|
(13,788
|
)
|
|
33,414
|
|
|
1,412
|
|
|
(231,579
|
)
|
|
21,931
|
|
||||||
Total Revenue and Other Income
|
232,472
|
|
|
203,550
|
|
|
1,256,624
|
|
|
62,285
|
|
|
(233,202
|
)
|
|
1,521,729
|
|
||||||
Cost of Goods Sold and Other Operating Charges
|
23,375
|
|
|
91,376
|
|
|
682,055
|
|
|
58,401
|
|
|
24,061
|
|
|
879,268
|
|
||||||
Purchased Gas Costs
|
—
|
|
|
398
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
398
|
|
||||||
Transaction and Financing Fees
|
14,907
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,907
|
|
||||||
Gas Royalty Interests’ Costs
|
—
|
|
|
15,420
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
15,409
|
|
||||||
Related Party Activity
|
2,653
|
|
|
—
|
|
|
(8,346
|
)
|
|
478
|
|
|
5,215
|
|
|
—
|
|
||||||
Freight Expense
|
—
|
|
|
—
|
|
|
59,871
|
|
|
—
|
|
|
—
|
|
|
59,871
|
|
||||||
Selling, General and Administrative Expense
|
—
|
|
|
28,266
|
|
|
43,627
|
|
|
472
|
|
|
(25,673
|
)
|
|
46,692
|
|
||||||
Depreciation, Depletion and Amortization
|
3,301
|
|
|
58,131
|
|
|
97,745
|
|
|
573
|
|
|
—
|
|
|
159,750
|
|
||||||
Abandonment of Long- Lived Assets
|
—
|
|
|
—
|
|
|
338
|
|
|
—
|
|
|
—
|
|
|
338
|
|
||||||
Interest Expense
|
58,421
|
|
|
2,332
|
|
|
(1,784
|
)
|
|
13
|
|
|
(98
|
)
|
|
58,884
|
|
||||||
Taxes Other Than Income
|
1,805
|
|
|
7,154
|
|
|
76,137
|
|
|
694
|
|
|
—
|
|
|
85,790
|
|
||||||
Total Costs
|
104,462
|
|
|
203,077
|
|
|
949,643
|
|
|
60,631
|
|
|
3,494
|
|
|
1,321,307
|
|
||||||
Earnings (Loss) Before Income Taxes
|
128,010
|
|
|
473
|
|
|
306,981
|
|
|
1,654
|
|
|
(236,696
|
)
|
|
200,422
|
|
||||||
Income Tax Expense (Benefit)
|
(39,319
|
)
|
|
(2,440
|
)
|
|
74,226
|
|
|
626
|
|
|
—
|
|
|
33,093
|
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
167,329
|
|
|
$
|
2,913
|
|
|
$
|
232,755
|
|
|
$
|
1,028
|
|
|
$
|
(236,696
|
)
|
|
$
|
167,329
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash and Cash Equivalents
|
$
|
61,738
|
|
|
$
|
408,723
|
|
|
$
|
1,700
|
|
|
$
|
362
|
|
|
$
|
—
|
|
|
$
|
472,523
|
|
Accounts and Notes Receivable:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Trade
|
—
|
|
|
62,629
|
|
|
609
|
|
|
439,838
|
|
|
—
|
|
|
503,076
|
|
||||||
Securitized
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Other
|
4,209
|
|
|
313,695
|
|
|
10,162
|
|
|
3,548
|
|
|
—
|
|
|
331,614
|
|
||||||
Inventories
|
—
|
|
|
6,481
|
|
|
193,071
|
|
|
42,139
|
|
|
—
|
|
|
241,691
|
|
||||||
Recoverable Income Taxes
|
(9,031
|
)
|
|
40,451
|
|
|
(19,916
|
)
|
|
—
|
|
|
—
|
|
|
11,504
|
|
||||||
Deferred Income Taxes
|
173,522
|
|
|
(16,275
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
157,247
|
|
||||||
Prepaid Expenses
|
21,128
|
|
|
98,802
|
|
|
61,562
|
|
|
2,771
|
|
|
—
|
|
|
184,263
|
|
||||||
Total Current Assets
|
251,566
|
|
|
914,506
|
|
|
247,188
|
|
|
488,658
|
|
|
—
|
|
|
1,901,918
|
|
||||||
Property, Plant and Equipment:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Property, Plant and Equipment
|
191,015
|
|
|
5,355,103
|
|
|
8,266,417
|
|
|
24,728
|
|
|
—
|
|
|
13,837,263
|
|
||||||
Less-Accumulated Depreciation, Depletion and Amortization
|
106,605
|
|
|
731,781
|
|
|
3,910,824
|
|
|
16,953
|
|
|
—
|
|
|
4,766,163
|
|
||||||
Property, Plant and Equipment-Net
|
84,410
|
|
|
4,623,322
|
|
|
4,355,593
|
|
|
7,775
|
|
|
—
|
|
|
9,071,100
|
|
||||||
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Deferred Income Taxes
|
907,287
|
|
|
(448,429
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
458,858
|
|
||||||
Investment in Affiliates
|
8,718,375
|
|
|
91,853
|
|
|
890,705
|
|
|
—
|
|
|
(9,525,115
|
)
|
|
175,818
|
|
||||||
Restricted Cash
|
20,291
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,291
|
|
||||||
Other
|
136,489
|
|
|
353,794
|
|
|
34,487
|
|
|
10,293
|
|
|
—
|
|
|
535,063
|
|
||||||
Total Other Assets
|
9,782,442
|
|
|
(2,782
|
)
|
|
925,192
|
|
|
10,293
|
|
|
(9,525,115
|
)
|
|
1,190,030
|
|
||||||
Total Assets
|
$
|
10,118,418
|
|
|
$
|
5,535,046
|
|
|
$
|
5,527,973
|
|
|
$
|
506,726
|
|
|
$
|
(9,525,115
|
)
|
|
$
|
12,163,048
|
|
Liabilities and Stockholders’ Equity:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Accounts Payable
|
$
|
120,557
|
|
|
$
|
184,771
|
|
|
$
|
132,130
|
|
|
$
|
11,209
|
|
|
$
|
—
|
|
|
$
|
448,667
|
|
Accounts Payable (Recoverable)—Related Parties
|
2,800,011
|
|
|
4,255
|
|
|
(3,164,631
|
)
|
|
360,365
|
|
|
—
|
|
|
—
|
|
||||||
Current Portion Long-Term Debt
|
779
|
|
|
5,244
|
|
|
13,514
|
|
|
769
|
|
|
—
|
|
|
20,306
|
|
||||||
Other Accrued Liabilities
|
534,450
|
|
|
54,223
|
|
|
233,440
|
|
|
11,826
|
|
|
—
|
|
|
833,939
|
|
||||||
Total Current Liabilities
|
3,455,797
|
|
|
248,493
|
|
|
(2,785,547
|
)
|
|
384,169
|
|
|
—
|
|
|
1,302,912
|
|
||||||
Long-Term Debt:
|
3,000,932
|
|
|
50,565
|
|
|
125,835
|
|
|
1,400
|
|
|
—
|
|
|
3,178,732
|
|
||||||
Deferred Credits and Other Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Postretirement Benefits Other Than Pensions
|
—
|
|
|
—
|
|
|
3,094,164
|
|
|
—
|
|
|
—
|
|
|
3,094,164
|
|
||||||
Pneumoconiosis Benefits
|
—
|
|
|
—
|
|
|
177,162
|
|
|
—
|
|
|
—
|
|
|
177,162
|
|
||||||
Mine Closing
|
—
|
|
|
—
|
|
|
401,049
|
|
|
—
|
|
|
—
|
|
|
401,049
|
|
||||||
Gas Well Closing
|
—
|
|
|
63,094
|
|
|
55,431
|
|
|
—
|
|
|
—
|
|
|
118,525
|
|
||||||
Workers’ Compensation
|
—
|
|
|
—
|
|
|
149,651
|
|
|
176
|
|
|
—
|
|
|
149,827
|
|
||||||
Salary Retirement
|
114,543
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
114,543
|
|
||||||
Reclamation
|
—
|
|
|
—
|
|
|
39,513
|
|
|
—
|
|
|
—
|
|
|
39,513
|
|
||||||
Other
|
120,403
|
|
|
22,984
|
|
|
16,487
|
|
|
4
|
|
|
—
|
|
|
159,878
|
|
||||||
Total Deferred Credits and Other Liabilities
|
234,946
|
|
|
86,078
|
|
|
3,933,457
|
|
|
180
|
|
|
—
|
|
|
4,254,661
|
|
||||||
Total CONSOL Energy Inc. Stockholders’ Equity
|
3,426,743
|
|
|
5,149,910
|
|
|
4,254,228
|
|
|
120,977
|
|
|
(9,525,115
|
)
|
|
3,426,743
|
|
||||||
Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Liabilities and Stockholders’ Equity
|
$
|
10,118,418
|
|
|
$
|
5,535,046
|
|
|
$
|
5,527,973
|
|
|
$
|
506,726
|
|
|
$
|
(9,525,115
|
)
|
|
$
|
12,163,048
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
204,454
|
|
|
$
|
1,010,530
|
|
|
$
|
47,981
|
|
|
$
|
(2,466
|
)
|
|
$
|
1,260,499
|
|
Sales—Purchased Gas
|
—
|
|
|
3,524
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,524
|
|
||||||
Sales—Gas Royalty Interests
|
—
|
|
|
18,131
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,131
|
|
||||||
Freight—Outside
|
—
|
|
|
—
|
|
|
37,269
|
|
|
—
|
|
|
—
|
|
|
37,269
|
|
||||||
Other Income (including equity earnings)
|
121,067
|
|
|
1,642
|
|
|
18,548
|
|
|
8,455
|
|
|
(119,842
|
)
|
|
29,870
|
|
||||||
Total Revenue and Other Income
|
121,067
|
|
|
227,751
|
|
|
1,066,347
|
|
|
56,436
|
|
|
(122,308
|
)
|
|
1,349,293
|
|
||||||
Cost of Goods Sold and Other Operating Charges
|
25,292
|
|
|
76,093
|
|
|
685,015
|
|
|
47,339
|
|
|
17,080
|
|
|
850,819
|
|
||||||
Purchased Gas Costs
|
—
|
|
|
3,333
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,333
|
|
||||||
Transaction and Financing Fees
|
333
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
337
|
|
||||||
Gas Royalty Interests’ Costs
|
—
|
|
|
16,424
|
|
|
—
|
|
|
—
|
|
|
(16
|
)
|
|
16,408
|
|
||||||
Related Party Activity
|
(11,119
|
)
|
|
—
|
|
|
(5,428
|
)
|
|
490
|
|
|
16,057
|
|
|
—
|
|
||||||
Freight Expense
|
—
|
|
|
—
|
|
|
37,269
|
|
|
—
|
|
|
—
|
|
|
37,269
|
|
||||||
Selling, General and Administrative Expense
|
—
|
|
|
25,375
|
|
|
34,230
|
|
|
342
|
|
|
(21,225
|
)
|
|
38,722
|
|
||||||
Depreciation, Depletion and Amortization
|
2,548
|
|
|
58,909
|
|
|
99,310
|
|
|
662
|
|
|
—
|
|
|
161,429
|
|
||||||
Interest Expense
|
61,789
|
|
|
2,154
|
|
|
2,574
|
|
|
6
|
|
|
(93
|
)
|
|
66,430
|
|
||||||
Taxes Other Than Income
|
2,352
|
|
|
10,031
|
|
|
70,366
|
|
|
657
|
|
|
—
|
|
|
83,406
|
|
||||||
Total Costs
|
81,195
|
|
|
192,321
|
|
|
923,338
|
|
|
49,496
|
|
|
11,803
|
|
|
1,258,153
|
|
||||||
Earnings (Loss) Before Income Taxes
|
39,872
|
|
|
35,430
|
|
|
143,009
|
|
|
6,940
|
|
|
(134,111
|
)
|
|
91,140
|
|
||||||
Income Tax Expense (Benefit)
|
(35,511
|
)
|
|
14,097
|
|
|
34,545
|
|
|
2,626
|
|
|
—
|
|
|
15,757
|
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
75,383
|
|
|
$
|
21,333
|
|
|
$
|
108,464
|
|
|
$
|
4,314
|
|
|
$
|
(134,111
|
)
|
|
$
|
75,383
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash and Cash Equivalents
|
$
|
11,382
|
|
|
$
|
16,559
|
|
|
$
|
3,235
|
|
|
$
|
1,618
|
|
|
$
|
—
|
|
|
$
|
32,794
|
|
Accounts and Notes Receivable:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Trade
|
—
|
|
|
65,197
|
|
|
646
|
|
|
186,687
|
|
|
—
|
|
|
252,530
|
|
||||||
Securitized
|
200,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
200,000
|
|
||||||
Other
|
4,635
|
|
|
3,361
|
|
|
10,915
|
|
|
2,678
|
|
|
—
|
|
|
21,589
|
|
||||||
Inventories
|
—
|
|
|
4,456
|
|
|
203,962
|
|
|
50,120
|
|
|
—
|
|
|
258,538
|
|
||||||
Recoverable Income Taxes
|
(3,189
|
)
|
|
35,717
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32,528
|
|
||||||
Deferred Income Taxes
|
173,211
|
|
|
960
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
174,171
|
|
||||||
Prepaid Expenses
|
35,297
|
|
|
57,907
|
|
|
39,309
|
|
|
10,343
|
|
|
—
|
|
|
142,856
|
|
||||||
Total Current Assets
|
421,336
|
|
|
184,157
|
|
|
258,067
|
|
|
251,446
|
|
|
—
|
|
|
1,115,006
|
|
||||||
Property, Plant and Equipment:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Property, Plant and Equipment
|
166,884
|
|
|
6,336,121
|
|
|
8,422,235
|
|
|
26,118
|
|
|
—
|
|
|
14,951,358
|
|
||||||
Less-Accumulated Depreciation, Depletion and Amortization
|
91,952
|
|
|
628,506
|
|
|
4,083,693
|
|
|
17,956
|
|
|
—
|
|
|
4,822,107
|
|
||||||
Property, Plant and Equipment-Net
|
74,932
|
|
|
5,707,615
|
|
|
4,338,542
|
|
|
8,162
|
|
|
—
|
|
|
10,129,251
|
|
||||||
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Deferred Income Taxes
|
902,188
|
|
|
(417,342
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
484,846
|
|
||||||
Investment in Affiliates
|
7,833,948
|
|
|
23,569
|
|
|
943,674
|
|
|
11,087
|
|
|
(8,718,769
|
)
|
|
93,509
|
|
||||||
Restricted Cash
|
20,291
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,291
|
|
||||||
Other
|
118,149
|
|
|
37,268
|
|
|
61,532
|
|
|
10,758
|
|
|
—
|
|
|
227,707
|
|
||||||
Total Other Assets
|
8,874,576
|
|
|
(356,505
|
)
|
|
1,005,206
|
|
|
21,845
|
|
|
(8,718,769
|
)
|
|
826,353
|
|
||||||
Total Assets
|
$
|
9,370,844
|
|
|
$
|
5,535,267
|
|
|
$
|
5,601,815
|
|
|
$
|
281,453
|
|
|
$
|
(8,718,769
|
)
|
|
$
|
12,070,610
|
|
Liabilities and Stockholders’ Equity:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Accounts Payable
|
$
|
130,063
|
|
|
$
|
101,944
|
|
|
$
|
113,036
|
|
|
$
|
8,968
|
|
|
$
|
—
|
|
|
$
|
354,011
|
|
Accounts Payable (Recoverable)-Related Parties
|
2,363,108
|
|
|
30,302
|
|
|
(2,543,991
|
)
|
|
150,581
|
|
|
—
|
|
|
—
|
|
||||||
Short-Term Notes Payable
|
155,000
|
|
|
129,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
284,000
|
|
||||||
Current Portion of Long-Term Debt
|
758
|
|
|
9,851
|
|
|
13,589
|
|
|
585
|
|
|
—
|
|
|
24,783
|
|
||||||
Borrowings under Securitization Facility
|
200,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
200,000
|
|
||||||
Other Accrued Liabilities
|
302,788
|
|
|
59,960
|
|
|
425,735
|
|
|
13,508
|
|
|
—
|
|
|
801,991
|
|
||||||
Total Current Liabilities
|
3,151,717
|
|
|
331,057
|
|
|
(1,991,631
|
)
|
|
173,642
|
|
|
—
|
|
|
1,664,785
|
|
||||||
Long-Term Debt:
|
3,000,702
|
|
|
58,905
|
|
|
125,627
|
|
|
904
|
|
|
—
|
|
|
3,186,138
|
|
||||||
Deferred Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Postretirement Benefits Other Than Pensions
|
—
|
|
|
—
|
|
|
3,077,390
|
|
|
—
|
|
|
—
|
|
|
3,077,390
|
|
||||||
Pneumoconiosis Benefits
|
—
|
|
|
—
|
|
|
173,616
|
|
|
—
|
|
|
—
|
|
|
173,616
|
|
||||||
Mine Closing
|
—
|
|
|
—
|
|
|
393,754
|
|
|
—
|
|
|
—
|
|
|
393,754
|
|
||||||
Gas Well Closing
|
—
|
|
|
60,027
|
|
|
70,951
|
|
|
—
|
|
|
—
|
|
|
130,978
|
|
||||||
Workers’ Compensation
|
—
|
|
|
—
|
|
|
148,265
|
|
|
49
|
|
|
—
|
|
|
148,314
|
|
||||||
Salary Retirement
|
161,173
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
161,173
|
|
||||||
Reclamation
|
—
|
|
|
—
|
|
|
53,839
|
|
|
—
|
|
|
—
|
|
|
53,839
|
|
||||||
Other
|
112,775
|
|
|
25,483
|
|
|
6,352
|
|
|
—
|
|
|
—
|
|
|
144,610
|
|
||||||
Total Deferred Credits and Other Liabilities
|
273,948
|
|
|
85,510
|
|
|
3,924,167
|
|
|
49
|
|
|
—
|
|
|
4,283,674
|
|
||||||
Total CONSOL Energy Inc. Stockholders’ Equity
|
2,944,477
|
|
|
5,068,259
|
|
|
3,543,652
|
|
|
106,858
|
|
|
(8,718,769
|
)
|
|
2,944,477
|
|
||||||
Noncontrolling Interest
|
—
|
|
|
(8,464
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,464
|
)
|
||||||
Total Liabilities and Stockholders’ Equity
|
$
|
9,370,844
|
|
|
$
|
5,535,267
|
|
|
$
|
5,601,815
|
|
|
$
|
281,453
|
|
|
$
|
(8,718,769
|
)
|
|
$
|
12,070,610
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
566,272
|
|
|
$
|
3,559,954
|
|
|
$
|
171,027
|
|
|
$
|
(4,086
|
)
|
|
$
|
4,293,167
|
|
Sales—Purchased Gas
|
—
|
|
|
3,297
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,297
|
|
||||||
Sales—Gas Royalty Interests
|
—
|
|
|
52,191
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52,191
|
|
||||||
Freight—Outside
|
—
|
|
|
—
|
|
|
156,311
|
|
|
—
|
|
|
—
|
|
|
156,311
|
|
||||||
Other Income (including equity earnings)
|
629,116
|
|
|
(9,473
|
)
|
|
55,051
|
|
|
20,008
|
|
|
(624,634
|
)
|
|
70,068
|
|
||||||
Total Revenue and Other Income
|
629,116
|
|
|
612,287
|
|
|
3,771,316
|
|
|
191,035
|
|
|
(628,720
|
)
|
|
4,575,034
|
|
||||||
Cost of Goods Sold and Other Operating Charges
|
86,775
|
|
|
238,158
|
|
|
2,059,011
|
|
|
166,106
|
|
|
70,326
|
|
|
2,620,376
|
|
||||||
Purchased Gas Costs
|
—
|
|
|
2,850
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,850
|
|
||||||
Transaction and Financing Fees
|
14,907
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,907
|
|
||||||
Loss on Debt Extinguishment
|
16,090
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16,090
|
|
||||||
Gas Royalty Interests’ Costs
|
—
|
|
|
46,620
|
|
|
—
|
|
|
—
|
|
|
(38
|
)
|
|
46,582
|
|
||||||
Related Party Activity
|
117
|
|
|
—
|
|
|
(21,083
|
)
|
|
1,479
|
|
|
19,487
|
|
|
—
|
|
||||||
Freight Expense
|
—
|
|
|
—
|
|
|
156,122
|
|
|
—
|
|
|
—
|
|
|
156,122
|
|
||||||
Selling, General and Administrative Expense
|
—
|
|
|
82,053
|
|
|
121,562
|
|
|
1,072
|
|
|
(74,376
|
)
|
|
130,311
|
|
||||||
Depreciation, Depletion and Amortization
|
8,665
|
|
|
159,109
|
|
|
297,017
|
|
|
1,821
|
|
|
—
|
|
|
466,612
|
|
||||||
Abandonment of Long-Lived Assets
|
—
|
|
|
—
|
|
|
115,817
|
|
|
—
|
|
|
—
|
|
|
115,817
|
|
||||||
Interest Expense
|
178,849
|
|
|
7,564
|
|
|
3,799
|
|
|
40
|
|
|
(289
|
)
|
|
189,963
|
|
||||||
Taxes Other Than Income
|
5,191
|
|
|
23,230
|
|
|
234,411
|
|
|
2,289
|
|
|
—
|
|
|
265,121
|
|
||||||
Total Costs
|
310,594
|
|
|
559,584
|
|
|
2,966,656
|
|
|
172,807
|
|
|
15,110
|
|
|
4,024,751
|
|
||||||
Earnings (Loss) Before Income Taxes
|
318,522
|
|
|
52,703
|
|
|
804,660
|
|
|
18,228
|
|
|
(643,830
|
)
|
|
550,283
|
|
||||||
Income Tax Expense (Benefit)
|
(118,340
|
)
|
|
18,029
|
|
|
206,837
|
|
|
6,895
|
|
|
—
|
|
|
113,421
|
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
436,862
|
|
|
$
|
34,674
|
|
|
$
|
597,823
|
|
|
$
|
11,333
|
|
|
$
|
(643,830
|
)
|
|
$
|
436,862
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
570,591
|
|
|
$
|
2,939,338
|
|
|
$
|
145,151
|
|
|
$
|
(4,951
|
)
|
|
$
|
3,650,129
|
|
Sales—Purchased Gas
|
—
|
|
|
8,280
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,280
|
|
||||||
Sales—Gas Royalty Interests
|
—
|
|
|
46,621
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,621
|
|
||||||
Freight—Outside
|
—
|
|
|
—
|
|
|
96,544
|
|
|
—
|
|
|
—
|
|
|
96,544
|
|
||||||
Other Income (including equity earnings)
|
399,464
|
|
|
3,066
|
|
|
41,033
|
|
|
22,704
|
|
|
(389,141
|
)
|
|
77,126
|
|
||||||
Total Revenue and Other Income
|
399,464
|
|
|
628,558
|
|
|
3,076,915
|
|
|
167,855
|
|
|
(394,092
|
)
|
|
3,878,700
|
|
||||||
Cost of Goods Sold and Other Operating Charges
|
68,014
|
|
|
184,209
|
|
|
1,998,686
|
|
|
138,730
|
|
|
46,813
|
|
|
2,436,452
|
|
||||||
Purchased Gas Costs
|
—
|
|
|
6,980
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,980
|
|
||||||
Transaction and Financing Fees
|
61,083
|
|
|
3,330
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
64,415
|
|
||||||
Gas Royalty Interests’ Costs
|
—
|
|
|
40,182
|
|
|
—
|
|
|
—
|
|
|
(49
|
)
|
|
40,133
|
|
||||||
Related Party Activity
|
(12,357
|
)
|
|
—
|
|
|
(10,293
|
)
|
|
1,458
|
|
|
21,192
|
|
|
—
|
|
||||||
Freight Expense
|
—
|
|
|
—
|
|
|
96,544
|
|
|
—
|
|
|
—
|
|
|
96,544
|
|
||||||
Selling, General and Administrative Expense
|
—
|
|
|
63,067
|
|
|
95,595
|
|
|
982
|
|
|
(51,747
|
)
|
|
107,897
|
|
||||||
Depreciation, Depletion and Amortization
|
8,377
|
|
|
139,954
|
|
|
263,046
|
|
|
2,002
|
|
|
—
|
|
|
413,379
|
|
||||||
Interest Expense
|
125,787
|
|
|
6,177
|
|
|
7,909
|
|
|
16
|
|
|
(276
|
)
|
|
139,613
|
|
||||||
Taxes Other Than Income
|
7,755
|
|
|
21,534
|
|
|
212,404
|
|
|
2,138
|
|
|
—
|
|
|
243,831
|
|
||||||
Total Costs
|
258,659
|
|
|
465,433
|
|
|
2,663,893
|
|
|
145,326
|
|
|
15,933
|
|
|
3,549,244
|
|
||||||
Earnings (Loss) Before Income Taxes
|
140,805
|
|
|
163,125
|
|
|
413,022
|
|
|
22,529
|
|
|
(410,025
|
)
|
|
329,456
|
|
||||||
Income Tax Expense (Benefit)
|
(101,515
|
)
|
|
62,672
|
|
|
105,611
|
|
|
8,523
|
|
|
—
|
|
|
75,291
|
|
||||||
Net Income (Loss)
|
$
|
242,320
|
|
|
$
|
100,453
|
|
|
$
|
307,411
|
|
|
$
|
14,006
|
|
|
$
|
(410,025
|
)
|
|
$
|
254,165
|
|
Less: Net Income Attributable to Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,845
|
)
|
|
(11,845
|
)
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
242,320
|
|
|
$
|
100,453
|
|
|
$
|
307,411
|
|
|
$
|
14,006
|
|
|
$
|
(421,870
|
)
|
|
$
|
242,320
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other Subsidiary Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Cash Provided by (Used in) Operating Activities
|
$
|
515,622
|
|
|
$
|
313,221
|
|
|
$
|
425,702
|
|
|
$
|
(2,141
|
)
|
|
$
|
—
|
|
|
$
|
1,252,404
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Capital Expenditures
|
$
|
(26,578
|
)
|
|
$
|
(535,068
|
)
|
|
$
|
(435,817
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(997,463
|
)
|
Distributions from Equity Affiliates
|
—
|
|
|
66,590
|
|
|
4,270
|
|
|
—
|
|
|
—
|
|
|
70,860
|
|
||||||
Other Investing Activities
|
10
|
|
|
688,505
|
|
|
5,304
|
|
|
1,472
|
|
|
—
|
|
|
695,291
|
|
||||||
Net Cash (Used in) Provided by Investing Activities
|
$
|
(26,568
|
)
|
|
$
|
220,027
|
|
|
$
|
(426,243
|
)
|
|
$
|
1,472
|
|
|
$
|
—
|
|
|
$
|
(231,312
|
)
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Dividends Paid
|
$
|
(67,972
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(67,972
|
)
|
Payments on Short-Term Borrowings
|
(155,000
|
)
|
|
(129,000
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(284,000
|
)
|
||||||
Payments on Securitization Facility
|
(200,000
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(200,000
|
)
|
||||||
Payments on Long-Term Notes, including redemption premium
|
(265,785
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(265,785
|
)
|
||||||
Proceeds from Long-Term Notes
|
250,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
250,000
|
|
||||||
Debt Issuance and Financing Fees
|
(10,499
|
)
|
|
(5,040
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15,539
|
)
|
||||||
Other Financing Activities
|
10,559
|
|
|
(7,044
|
)
|
|
(994
|
)
|
|
(588
|
)
|
|
—
|
|
|
1,933
|
|
||||||
Net Cash (Used in) Provided by Financing Activities
|
$
|
(438,697
|
)
|
|
$
|
(141,084
|
)
|
|
$
|
(994
|
)
|
|
$
|
(588
|
)
|
|
$
|
—
|
|
|
$
|
(581,363
|
)
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other Subsidiary Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Cash (Used in) Provided by Operating Activities
|
$
|
(3,373,370
|
)
|
|
$
|
267,894
|
|
|
$
|
3,983,670
|
|
|
$
|
736
|
|
|
$
|
—
|
|
|
$
|
878,930
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Capital Expenditures
|
$
|
—
|
|
|
$
|
(292,495
|
)
|
|
$
|
(529,413
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(821,908
|
)
|
Distributions from Equity Affiliates
|
—
|
|
|
—
|
|
|
6,867
|
|
|
—
|
|
|
—
|
|
|
6,867
|
|
||||||
Acquisition of Dominion Exploration and Production Business
|
—
|
|
|
—
|
|
|
(3,474,199
|
)
|
|
—
|
|
|
—
|
|
|
(3,474,199
|
)
|
||||||
Purchase of CNX Gas Noncontrolling Interest
|
(991,034
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(991,034
|
)
|
||||||
Other Investing Activities
|
—
|
|
|
48
|
|
|
24,896
|
|
|
—
|
|
|
—
|
|
|
24,944
|
|
||||||
Net Cash Used in Investing Activities
|
$
|
(991,034
|
)
|
|
$
|
(292,447
|
)
|
|
$
|
(3,971,849
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(5,255,330
|
)
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Dividends Paid
|
$
|
(63,276
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(63,276
|
)
|
(Payments on) Proceeds from Short-Term Borrowings
|
(279,000
|
)
|
|
20,050
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(258,950
|
)
|
||||||
Proceeds from Securitization Facility
|
150,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150,000
|
|
||||||
Proceeds from Long-Term Notes
|
2,750,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,750,000
|
|
||||||
Proceeds from Issuance of Common Stock
|
1,828,862
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,828,862
|
|
||||||
Debt Issuance and Financing Fees
|
(92,998
|
)
|
|
8,774
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(84,224
|
)
|
||||||
Other Financing Activities
|
12,051
|
|
|
4,524
|
|
|
(12,230
|
)
|
|
(382
|
)
|
|
—
|
|
|
3,963
|
|
||||||
Net Cash Provided by (Used in) Financing Activities
|
$
|
4,305,639
|
|
|
$
|
33,348
|
|
|
$
|
(12,230
|
)
|
|
$
|
(382
|
)
|
|
$
|
—
|
|
|
$
|
4,326,375
|
|
ITEM 2.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
COAL DIVISION GUIDANCE
|
||||||||||||
(Tons in millions)
|
||||||||||||
|
|
|
|
|
|
|
|
|
||||
|
|
4Q 2011
|
|
2011
|
|
2012
|
|
2013
|
||||
Estimated Coal Sales
|
|
14.7-15.3
|
|
|
62.0-62.6
|
|
|
59.5-61.5
|
|
|
60.5-62.5
|
|
Estimated Low-Vol Met Sales
|
|
1.0-1.2
|
|
|
5.3-5.5
|
|
|
4.5-5.0
|
|
|
4.5-5.0
|
|
Tonnage - Firm
|
|
0.7
|
|
|
5.0
|
|
|
1.1
|
|
|
0.2
|
|
Tonnage - Open
|
|
0.3-0.5
|
|
|
0.3-0.5
|
|
|
3.4-3.9
|
|
|
4.3-4.8
|
|
Average Price - Sold (firm)
|
|
$199.72
|
|
$192.92
|
|
$185.48
|
|
$91.74
|
||||
Price - Estimated (for open tonnage)
|
|
$210-$220
|
|
|
$210-$220
|
|
|
$180-$190
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
||||
Estimated High-Vol Met Sales
|
|
1.5
|
|
|
5.1
|
|
|
5.0
|
|
|
5.0
|
|
Tonnage - Firm
|
|
1.2
|
|
|
4.8
|
|
|
1.2
|
|
|
0.2
|
|
Tonnage - Open
|
|
0.3
|
|
|
0.3
|
|
|
3.8
|
|
|
4.8
|
|
Average Price - Sold (firm)
|
|
$75.01
|
|
$79.40
|
|
$81.96
|
|
$90.20
|
||||
Price - Estimated (for open tonnage)
|
|
$74-$80
|
|
|
$74-$80
|
|
|
$70-$75
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
||||
Estimated Thermal Sales
|
|
approx. 12.4
|
|
|
approx. 52.0
|
|
|
approx. 50.5
|
|
|
approx. 51.0
|
|
Tonnage - Firm
|
|
12.4
|
|
|
52.0
|
|
|
41.9
|
|
|
21.3
|
|
Tonnage - Open
|
|
—
|
|
|
—
|
|
|
N/A
|
|
|
N/A
|
|
Average Price - Sold (firm)
|
|
$58.47
|
|
$58.77
|
|
$62.37
|
|
$61.87
|
||||
Price - Estimated (for open tonnage)
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
•
|
On October 27, 2011, CONSOL Energy's Board of Directors increased the regular annual dividend by 25%, or $0.10 per share, to $0.50 per share.
|
•
|
On October 21, 2011, CONSOL Energy, through its subsidiary, CNX Gas Company LLC, completed a sale to Hess Ohio Developments, LLC (Hess) of 50% of its nearly 200,000 Utica Shale acres in Ohio for consideration of approximately $594 million, of which $60 million was paid at closing. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to pay approximately $534 million in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. CONSOL Energy and Hess anticipate commencing initial drilling operations in the fourth quarter of 2011.
|
•
|
On September 30, 2011, CNX Gas Company LLC (CNX Gas) completed a sale to Noble Energy, Inc. (Noble) of 50% of the Company's undivided interest in certain Marcellus Shale oil and gas properties in West Virginia and Pennsylvania covering approximately 628,000 acres and 50% of the Company's undivided interest in certain of its existing Marcellus Shale wells and related leases. On September 30, 2011, cash proceeds of $519 million were received from Noble. In addition to the cash proceeds, a one year note receivable due on September 30, 2012 in the amount of $312 million and a two year note receivable due on September 30, 2013 in the amount of $296 million have been recorded. As part of the transaction, CONSOL Energy also received a commitment from Noble to pay one-third of the Company's working interest share of certain drilling and completion costs, up to approximately $2.1 billion with certain restrictions.
|
•
|
On September 30 2011, CNX Gas and Noble formed CONE Gathering LLC (CONE), a joint venture established to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CONSOL Energy contributed its existing Marcellus Shale gathering infrastructure which had a net book value of $133 million and Noble contributed cash of approximately $73 million. On September 30, 2011, CONE made a cash distribution to CONSOL Energy in the amount of $73 million.
|
•
|
On September 21, 2011, CONSOL Energy entered into an agreement with Antero Resources Appalachian Corp. (Antero), pursuant to which CONSOL Energy assigned to Antero overriding royalty interests (ORRI) of approximately 7% in 115,647 net acres of Marcellus Shale located in nine counties in southwestern Pennsylvania and north central West Virginia, in exchange for $193 million. The transaction became effective as of July 1, 2011.
|
•
|
CONSOL Energy incurred costs of approximately $15 million in the three months ended September 30, 2011 related to the solicitation of consents from the holders of CONSOL's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020 and 6.375% Senior Notes due 2021. The consents allowed an amendment of the indentures for each of those notes, clarifying that the transactions contemplated by the August 2011 Asset Acquisition Agreements with Noble Energy and Hess Energy were permissible under those indentures.
|
•
|
In June 2011, the Bituminous Coal Operators Association (BCOA) and the United Mine Workers of America (UMWA) reached a new collective bargaining agreement which will run from July 1, 2011 to December 31, 2016. That agreement, National Bituminous Coal Wage Agreement of 2011 (2011 NBCWA) covers approximately 2,900 employees of CONSOL Energy subsidiaries. The 2011 NBCWA is the successor agreement to the 2007 NBCWA that was set to expire on December 31, 2011. Key elements of the new agreement include the following items:
|
a.
|
A wage increase of $1.00 per hour effective July 1, 2011, and an additional $1.00 per hour increase each January 1
st
throughout the contract term.
|
b.
|
Contributions to the 1974 Pension Plan, a multi-employer plan, will continue at the current rate of $5.50 per hour throughout the contract term. New inexperienced miners hired after December 31, 2011 will not participate in the 1974 Pension Plan, but will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the UMWA Cash Deferred Savings Plan (CDSP), which is a 401(k) Plan. UMWA represented employees with over 20 years of experience will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the CDSP beginning January 1, 2012. All current UMWA represented employees will be given the opportunity to opt-out of future participation in the 1974 Pension Plan and instead participate in the CDSP.
|
c.
|
A $1.50 per hour contribution starting January 1, 2012 to a new defined contribution plan to provide retiree bonus payments to eligible retirees in 2014, 2015 and 2016.
|
d.
|
An increased contribution from $0.50 per hour to $1.10 per hour effective January 1, 2012 to the 1993 Benefit Plan, which is a defined contribution plan providing health benefits to certain retirees.
|
e.
|
Various other changes related to absenteeism, contribution to various UMWA benefit funds, eligibility for various vacation days and sick days.
|
•
|
On October 24, 2011, certain subsidiaries of CONSOL Energy received notice from the trustees of the UMWA 1974 Pension Plan ("the Plan") stating that the Plan is considered to be in “seriously endangered” status for the plan year beginning July 1, 2011. The status of the plan is due to the funded percentage and projected funding deficiency. As a result, the Pension Protection Act requires the Plan to adopt a funding improvement plan no later than May 25, 2012, to improve the funded status of the Plan, which may include increased contributions to the Plan from employers in the future. Because CONSOL Energy's subsidiaries are parties to the NBCWA which establishes their contribution obligations through December 31, 2016, such subsidiaries' contributions to the Plan will not increase as a consequence of any funding improvement plan adopted by the Plan to address the Plan's seriously endangered status.
|
•
|
In June 2011, CONSOL Energy management decided to permanently idle its Mine 84 underground facility. This facility had been on idle status since March 2009. Various options for the facility were explored, such as selling and operating with continuous miners, but management decided it was in the best interest of the Company to abandon the underground workings of this facility and reallocate resources into more profitable coal operations and Marcellus Shale drilling operations. The Company redeployed all of the movable equipment from the mine that could be used at other locations. The abandonment of this underground facility resulted in a $115 million charge to pre-tax earnings in June 2011. See Note 8—Property, Plant and Equipment in the Notes to the Consolidated Financial Statements of this Form 10-Q for additional disclosure. The Company expects the closure of Mine 84 to result in pre-tax cash savings of $18 million per year.
|
•
|
In April 2011, CNX Gas entered into an amendment of its senior secured credit agreement which increases the availability under the agreement from $700 million to $1.0 billion, decreases the interest rate and extends the term from May 6, 2014 to April 12, 2016. The amended credit agreement continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries.
|
•
|
In April 2011, CONSOL Energy amended and extended its existing $1.5 billion senior secured credit agreement, which decreases the interest rate and extends the term from May 7, 2014 to April 12, 2016. The amended agreement continues to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries.
|
•
|
On March 9, 2011, CONSOL Energy issued $250 million of 6.375% senior notes due March 2021. The Notes are guaranteed by substantially all of the Company's existing and future wholly owned domestic restricted subsidiaries. The Company issued the Notes with the intention of using the net proceeds to repay its outstanding 7.875% senior secured notes due March 1, 2012, on or before their maturity. On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing the notes. By using the proceeds of the $250 million, 6.375% senior notes due March 2021 to affect this redemption, the Company effectively extended the maturity of the $250 million of long-term indebtedness nine years at a lower interest rate. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million, for a total redemption cost of approximately $268 million. The loss on extinguishment of debt was approximately $16 million, which primarily represents the interest that would have been paid on these notes if they had been held to maturity.
|
•
|
Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include (i) increased prices for commodities such as diesel fuel and synthetic rubber that we use in our operations and (ii) continued scrutiny of existing safety regulations and the development of new safety regulations.
|
•
|
Federal and state environmental regulators are reviewing our operations more closely and more strictly interpreting
|
•
|
Federal and state regulators have proposed regulations which, if adopted, would adversely impact our business. These proposed regulations could require significant changes in the manner in which we operate and/or would increase the cost of our operations. For example, the Department of Interior, Office of Surface Mining Reclamation and Enforcement (OSM) is currently preparing an environmental impact statement relating to OSM's consideration of five alternatives for amending its coal mining stream protection rules. All of the alternatives, except the no action alternative, could make it more costly to mine our coal and/or could eliminate the ability to mine some of our coal. Further, other regulations would make it more expensive for our customers to operate their businesses, possibly inducing them to move to alternative fuel sources. For example, the EPA has issued a proposed rule that would regulate coal combustion residuals from coal fired electric generating facilities under the federal Resource Conservation and Recovery Act (RCRA) as either a hazardous waste under Subtitle C of RCRA or as a non-hazardous waste under Subtitle D of RCRA. If final rules are adopted consistent with either of the proposed alternatives, the cost of handling and disposal of coal combustion residuals could increase making it more expensive to generate electricity from coal. Another example is the Cross-State Air Pollution Rule (CSAPR) that was finalized by the EPA on July 6, 2011. CSAPR replaces the Clean Air Interstate Rule and regulates the amount of SO
2
and NO
x
that power plants in 23 eastern states can emit in order to meet clean air requirements in downwind states. Some older coal fired power plants may be retired or have operation time reduced rather than install additional expensive emission controls which could reduce the amount of coal consumed.
|
•
|
On April 19, 2011, the Pennsylvania Department of Environmental Protection announced its intent to not renew permits for publicly owned treatment works (POTW) that treat municipal wastewater to accept wastewater from Marcellus Shale operators. They called on operators to cease delivering wastewater to the POTWs by May 19, 2011. CONSOL Energy has implemented a re-cycle and re-use process of its Marcellus derived water for fracing operations, and will only safely dispose of Marcellus wastewater in regulated, underground injection control wells.
|
•
|
CONSOL Energy continues to explore potential sales of non-core assets.
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Average Sales Price per ton sold
|
$
|
76.60
|
|
|
$
|
63.71
|
|
|
$
|
12.89
|
|
|
20.2
|
%
|
Average Costs per ton sold
|
55.91
|
|
|
49.98
|
|
|
5.93
|
|
|
11.9
|
%
|
|||
Margin
|
$
|
20.69
|
|
|
$
|
13.73
|
|
|
$
|
6.96
|
|
|
50.7
|
%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Average Sales Price per thousand cubic feet sold
|
$
|
4.92
|
|
|
$
|
5.72
|
|
|
$
|
(0.80
|
)
|
|
(14.0
|
)%
|
Average Costs per thousand cubic feet sold
|
3.93
|
|
|
4.08
|
|
|
(0.15
|
)
|
|
(3.7
|
)%
|
|||
Margin
|
$
|
0.99
|
|
|
$
|
1.64
|
|
|
$
|
(0.65
|
)
|
|
(39.6
|
)%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Employee wages and related expenses
|
$
|
21
|
|
|
$
|
19
|
|
|
$
|
2
|
|
|
10.5
|
%
|
Advertising and promotion
|
3
|
|
|
1
|
|
|
2
|
|
|
200.0
|
%
|
|||
Contributions
|
3
|
|
|
1
|
|
|
2
|
|
|
200.0
|
%
|
|||
Consulting and professional services
|
7
|
|
|
6
|
|
|
1
|
|
|
16.7
|
%
|
|||
Miscellaneous
|
13
|
|
|
12
|
|
|
1
|
|
|
8.3
|
%
|
|||
Total Company Selling, General and Administrative Expenses
|
$
|
47
|
|
|
$
|
39
|
|
|
$
|
8
|
|
|
20.5
|
%
|
•
|
Employee wages and related expenses increased $2 million which was primarily attributable to additional hiring of support staff in the period-to-period comparison.
|
•
|
Advertising and promotion expense increased $2 million in the period-to-period comparison due to additional campaigns initiated in the 2011 period.
|
•
|
Contributions expense increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Consulting and professional services increased $1 million due to various corporate projects that occurred throughout both periods, none of which were individually material.
|
•
|
Miscellaneous selling, general and administrative expenses increased $1 million primarily due to various corporate projects that occurred throughout both periods, none of which were individually material.
|
|
For the Three Months Ended
|
|
Difference to Three Months Ended
|
||||||||||||||||||||||||||||||||||||
|
September 30, 2011
|
|
September 30, 2010
|
||||||||||||||||||||||||||||||||||||
|
Steam
Coal
|
|
High
Vol
Met
Coal
|
|
Low
Vol
Met
Coal
|
|
Other
Coal
|
|
Total
Coal
|
|
Steam
Coal
|
|
High
Vol
Met
Coal
|
|
Low
Vol
Met
Coal
|
|
Other
Coal
|
|
Total
Coal
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced Coal
|
$
|
732
|
|
|
$
|
82
|
|
|
$
|
308
|
|
|
$
|
9
|
|
|
$
|
1,131
|
|
|
$
|
(9
|
)
|
|
$
|
60
|
|
|
$
|
93
|
|
|
$
|
6
|
|
|
$
|
150
|
|
Purchased Coal
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
||||||||||
Total Outside Sales
|
732
|
|
|
82
|
|
|
308
|
|
|
14
|
|
|
1,136
|
|
|
(9
|
)
|
|
60
|
|
|
93
|
|
|
9
|
|
|
153
|
|
||||||||||
Freight Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
60
|
|
|
60
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
22
|
|
||||||||||
Other Income
|
2
|
|
|
3
|
|
|
—
|
|
|
24
|
|
|
29
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
9
|
|
||||||||||
Total Revenue and Other Income
|
734
|
|
|
85
|
|
|
308
|
|
|
98
|
|
|
1,225
|
|
|
(8
|
)
|
|
60
|
|
|
93
|
|
|
39
|
|
|
184
|
|
||||||||||
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Total operating costs
|
478
|
|
|
43
|
|
|
81
|
|
|
47
|
|
|
649
|
|
|
(40
|
)
|
|
33
|
|
|
20
|
|
|
12
|
|
|
25
|
|
||||||||||
Total provisions
|
54
|
|
|
6
|
|
|
9
|
|
|
11
|
|
|
80
|
|
|
3
|
|
|
5
|
|
|
2
|
|
|
(27
|
)
|
|
(17
|
)
|
||||||||||
Total administrative & other costs
|
43
|
|
|
5
|
|
|
8
|
|
|
17
|
|
|
73
|
|
|
8
|
|
|
4
|
|
|
3
|
|
|
(7
|
)
|
|
8
|
|
||||||||||
Depreciation, depletion and amortization
|
75
|
|
|
7
|
|
|
9
|
|
|
4
|
|
|
95
|
|
|
5
|
|
|
5
|
|
|
3
|
|
|
(17
|
)
|
|
(4
|
)
|
||||||||||
Total Costs and Expenses
|
650
|
|
|
61
|
|
|
107
|
|
|
79
|
|
|
897
|
|
|
(24
|
)
|
|
47
|
|
|
28
|
|
|
(39
|
)
|
|
12
|
|
||||||||||
Freight Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
60
|
|
|
60
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
22
|
|
||||||||||
Total Costs
|
650
|
|
|
61
|
|
|
107
|
|
|
139
|
|
|
957
|
|
|
(24
|
)
|
|
47
|
|
|
28
|
|
|
(17
|
)
|
|
34
|
|
||||||||||
Earnings (Loss) Before Income Taxes
|
$
|
84
|
|
|
$
|
24
|
|
|
$
|
201
|
|
|
$
|
(41
|
)
|
|
$
|
268
|
|
|
$
|
16
|
|
|
$
|
13
|
|
|
$
|
65
|
|
|
$
|
56
|
|
|
$
|
150
|
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced Steam Tons Sold (in millions)
|
12.2
|
|
|
13.7
|
|
|
(1.5
|
)
|
|
(10.9
|
)%
|
|||
Average Sales Price Per Steam Ton Sold
|
$
|
60.18
|
|
|
$
|
54.02
|
|
|
$
|
6.16
|
|
|
11.4
|
%
|
Average Operating Costs Per Steam Ton Sold
|
$
|
39.21
|
|
|
$
|
37.82
|
|
|
$
|
1.39
|
|
|
3.7
|
%
|
Average Provision Costs Per Steam Ton Sold
|
$
|
4.49
|
|
|
$
|
3.74
|
|
|
$
|
0.75
|
|
|
20.1
|
%
|
Average Selling, Administrative and Other Costs Per Steam Ton Sold
|
$
|
3.52
|
|
|
$
|
2.51
|
|
|
$
|
1.01
|
|
|
40.2
|
%
|
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold
|
$
|
6.21
|
|
|
$
|
5.07
|
|
|
$
|
1.14
|
|
|
22.5
|
%
|
Total Average Costs Per Steam Ton Sold
|
$
|
53.43
|
|
|
$
|
49.14
|
|
|
$
|
4.29
|
|
|
8.7
|
%
|
Margin Per Steam Ton Sold
|
$
|
6.75
|
|
|
$
|
4.88
|
|
|
$
|
1.87
|
|
|
38.3
|
%
|
•
|
Average operating costs per steam ton sold increased due to fewer tons sold. Fixed costs are allocated over less tons, resulting in higher unit costs.
|
•
|
Labor and related benefits average costs per ton sold were impaired, although total dollars expensed for these items were improved slightly. Average costs per ton sold were impacted by the 1.5 million ton reduction in sales tons. Labor benefit costs were impacted by the Tax Relief and Health Care Act of 2006 authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land trust fund to cover orphan retirees which remain in the Combined Fund, the 1992 Benefit Plan and the 1993 Plan. The additional federal funding eliminated the 2011 funding of orphan retirees by participating active employers of the plans, resulting in lower expense in the period-to-period comparison. The additional federal funding does not impact the amount of contributions required to be paid for our assigned retirees. Also, we may be required to make additional payments in the future to these plans in the event that the federal contributions are not sufficient to cover the benefits. This improvement was offset by higher contributions made to the 1974 Pension Trust (the Trust), which is a multi-employer pension plan. Contributions to the Trust were negotiated under the National Bituminous Coal Wage Agreement. Contributions are based on a rate per hour worked by members of the United Mine Workers of America (UMWA). The contribution rate has increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Reductions were also offset, in part, by additional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the new collective bargaining agreement, in the period-to-period comparison.
|
•
|
Average operating supplies & maintenance cost per ton sold increased due to higher fuel costs, additional roof control costs, additional maintenance and equipment overhaul costs. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced in the current period.
|
•
|
Production taxes average cost per ton sold increased due to the $6.16 per ton higher average sales price.
|
•
|
Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs have also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.
|
•
|
These increases in average operating costs per ton for steam coal were offset, in part, by lower contract mining fees. Fewer contractors were retained to mine our reserves in the period-to-period comparison without a corresponding reduction in total steam coal sold which has resulted in lower average unit costs per ton sold.
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced High Vol Met Tons Sold (in millions)
|
1.0
|
|
|
0.3
|
|
|
0.7
|
|
|
233.3
|
%
|
|||
Average Sales Price Per High Vol Met Ton Sold
|
$
|
82.21
|
|
|
$
|
65.38
|
|
|
$
|
16.83
|
|
|
25.7
|
%
|
Average Operating Costs Per High Vol Met Ton Sold
|
$
|
45.02
|
|
|
$
|
30.02
|
|
|
$
|
15.00
|
|
|
50.0
|
%
|
Average Provision Costs Per High Vol Met Ton Sold
|
$
|
5.34
|
|
|
$
|
2.75
|
|
|
$
|
2.59
|
|
|
94.2
|
%
|
Average Selling, Administrative and Other Costs Per High Vol Met Ton Sold
|
$
|
4.39
|
|
|
$
|
1.94
|
|
|
$
|
2.45
|
|
|
126.3
|
%
|
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Sold
|
$
|
7.22
|
|
|
$
|
4.72
|
|
|
$
|
2.50
|
|
|
53.0
|
%
|
Total Average Costs Per High Vol Met Ton Sold
|
$
|
61.97
|
|
|
$
|
39.43
|
|
|
$
|
22.54
|
|
|
57.2
|
%
|
Margin Per High Vol Met Ton Sold
|
$
|
20.24
|
|
|
$
|
25.95
|
|
|
$
|
(5.71
|
)
|
|
(22.0
|
%)
|
•
|
Average operating costs per unit primarily changed due to the mix of mines shipping high volatile metallurgical coal. The increased cost structure of high volatile metallurgical coal is due to more Central Appalachian mines shipping high vol tons. Central Appalachian mines shipping high volatile metallurgical tons have higher cost structures than the Northern Appalachian mines included in the prior period.
|
•
|
Labor and related benefits increased due to higher employee counts, higher non-union benefit rates and higher contributions per hour worked to the 1974 Pension Trust (Trust). Higher non-union benefit rates for active employees were related to the continued increase in healthcare costs. Higher contributions made to the Trust were discussed in the steam coal segment. These increases were offset by lower overall contributions to certain multiemployer benefit plans such as the 1992 Fund, the 1993 Fund and the Combined Fund, which were also discussed in the steam coal segment. Labor and related benefits also increased due to the impact of the wage increase of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the new collective bargaining agreement, in the period-to-period comparison. Increased labor and related benefit costs per unit sold were offset, in part, by additional volumes of high volatile metallurgical tons sold in the period-to-period comparison.
|
•
|
Average operating supplies & maintenance costs per ton sold increased due to additional maintenance and equipment overhaul costs and additional roof control costs. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers. Roof control costs also increased
|
•
|
Production taxes average cost per ton sold increased due to the $16.83 per ton higher average sales price.
|
•
|
In-transit charges average cost per ton sold increased primarily due to the increased cost of moving coal from the mine to the preparation plant for processing. This increase is primarily related to the Central Appalachian mines now shipping high volatile metallurgical coal.
|
•
|
Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.
|
•
|
Average preparation plant costs per ton sold increased due to additional maintenance projects completed at our preparation plants in the period-to-period comparison.
|
•
|
Average royalty costs per ton sold were lower in the period-to-period comparison due to fewer tons being mined from coal tracts that have a royalty, offset, in part, by higher average sales prices.
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced Low Vol Met Tons Sold (in millions)
|
1.5
|
|
|
1.3
|
|
|
0.2
|
|
|
15.4
|
%
|
|||
Average Sales Price Per Low Vol Met Ton Sold
|
$
|
207.21
|
|
|
$
|
165.22
|
|
|
$
|
41.99
|
|
|
25.4
|
%
|
Average Operating Costs Per Low Vol Met Ton Sold
|
$
|
54.12
|
|
|
$
|
47.99
|
|
|
$
|
6.13
|
|
|
12.8
|
%
|
Average Provision Costs Per Low Vol Met Ton Sold
|
$
|
6.69
|
|
|
$
|
5.29
|
|
|
$
|
1.40
|
|
|
26.5
|
%
|
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold
|
$
|
5.05
|
|
|
$
|
3.61
|
|
|
$
|
1.44
|
|
|
39.9
|
%
|
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold
|
$
|
6.28
|
|
|
$
|
4.65
|
|
|
$
|
1.63
|
|
|
35.1
|
%
|
Total Average Costs Per Low Vol Met Ton Sold
|
$
|
72.14
|
|
|
$
|
61.54
|
|
|
$
|
10.60
|
|
|
17.2
|
%
|
Margin Per Low Vol Met Ton Sold
|
$
|
135.07
|
|
|
$
|
103.68
|
|
|
$
|
31.39
|
|
|
30.3
|
%
|
•
|
Costs associated with the sales price of coal sold, such as royalties and production related taxes, increased due to the higher average sales prices received for low volatile metallurgical coal in the period-to-period comparison.
|
•
|
Average preparation plant costs per ton sold increased due to additional maintenance projects completed and increased fuel costs at our preparation plant in the period-to-period comparison.
|
•
|
Labor and related benefits increased in the period-to-period comparison due to additional employees, increased hours worked and increased non-union benefit rates for active employees which were related to the continued increase in healthcare costs.
|
|
|
For the Three Months Ended September 30,
|
||||||||||
|
|
2011
|
|
2010
|
|
Variance
|
||||||
Closed and idle mine cost
|
|
$
|
23
|
|
|
$
|
71
|
|
|
$
|
(48
|
)
|
Litigation expense
|
|
2
|
|
|
3
|
|
|
(1
|
)
|
|||
Freight expense
|
|
60
|
|
|
38
|
|
|
22
|
|
|||
Purchased coal
|
|
11
|
|
|
2
|
|
|
9
|
|
|||
Other
|
|
43
|
|
|
42
|
|
|
1
|
|
|||
Total other coal segment costs
|
|
$
|
139
|
|
|
$
|
156
|
|
|
$
|
(17
|
)
|
•
|
Closed and idle mine costs decreased approximately $48 million for the three months ended September 30, 2011 compared to the three months ended September 30, 2010. The decrease was the result of a $29 million increase in the Fola reclamation liability in the 2010 period as a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans. Also, closed and idle mine costs decreased $14 million as the result of the change in mine plan at Mine 84 in the 2010 period. Due to the mine plan change, a portion of the previously developed area of the mine was abandoned. Closed and idle mine costs decreased $5 million due to other changes in the operational status of various other mines, between idled and operating, throughout both periods, none of which were individually material.
|
•
|
Litigation expense decreased $1 million for the three months ended September 30, 2011 compared to the three months ended September 30, 2010 related to various legal settlements, none of which were individually material.
|
•
|
Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset in freight revenue. Freight expense increased $22 million primarily due to the 0.6 million ton increase in export tons in the period-to-period comparison.
|
•
|
Purchased coal costs increased approximately $9 million in the period-to-period comparison primarily due to the increased volumes of coal purchased to supply various coal sales contracts.
|
•
|
Other expenses related to the coal segment increased $1 million in the period-to-period comparison due to various miscellaneous transactions, none of which were individually material.
|
|
For the Three Months Ended
|
|
Difference to Three Months Ended
|
||||||||||||||||||||||||||||||||||||
|
September 30, 2011
|
|
September 30, 2010
|
||||||||||||||||||||||||||||||||||||
|
CBM
|
|
Conven-
tional
|
|
Marcellus
|
|
Other
Gas
|
|
Total
Gas
|
|
CBM
|
|
Conven-
tional
|
|
Marcellus
|
|
Other
Gas
|
|
Total
Gas
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced
|
$
|
116
|
|
|
$
|
39
|
|
|
$
|
39
|
|
|
$
|
3
|
|
|
$
|
197
|
|
|
$
|
(24
|
)
|
|
$
|
(6
|
)
|
|
$
|
23
|
|
|
$
|
2
|
|
|
$
|
(5
|
)
|
Related Party
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||||||||
Total Outside Sales
|
118
|
|
|
39
|
|
|
39
|
|
|
3
|
|
|
199
|
|
|
(25
|
)
|
|
(6
|
)
|
|
23
|
|
|
2
|
|
|
(6
|
)
|
||||||||||
Gas Royalty Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||||||
Purchased Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||||||
Other Income
|
—
|
|
|
—
|
|
|
—
|
|
|
(14
|
)
|
|
(14
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16
|
)
|
|
(16
|
)
|
||||||||||
Total Revenue and Other Income
|
118
|
|
|
39
|
|
|
39
|
|
|
7
|
|
|
203
|
|
|
(25
|
)
|
|
(6
|
)
|
|
23
|
|
|
(18
|
)
|
|
(26
|
)
|
||||||||||
Lifting
|
13
|
|
|
17
|
|
|
6
|
|
|
1
|
|
|
37
|
|
|
(1
|
)
|
|
4
|
|
|
5
|
|
|
—
|
|
|
8
|
|
||||||||||
Gathering
|
25
|
|
|
8
|
|
|
3
|
|
|
—
|
|
|
36
|
|
|
1
|
|
|
3
|
|
|
(1
|
)
|
|
(1
|
)
|
|
2
|
|
||||||||||
General & Administration
|
15
|
|
|
8
|
|
|
4
|
|
|
1
|
|
|
28
|
|
|
(2
|
)
|
|
1
|
|
|
1
|
|
|
4
|
|
|
4
|
|
||||||||||
Depreciation, Depletion and Amortization
|
26
|
|
|
15
|
|
|
15
|
|
|
2
|
|
|
58
|
|
|
(3
|
)
|
|
(8
|
)
|
|
10
|
|
|
(1
|
)
|
|
(2
|
)
|
||||||||||
Gas Royalty Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
16
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
||||||||||
Purchased Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
(3
|
)
|
||||||||||
Exploration and Other Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
||||||||||
Other Corporate Expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
||||||||||
Interest Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||||
Total Cost
|
79
|
|
|
48
|
|
|
28
|
|
|
48
|
|
|
203
|
|
|
(5
|
)
|
|
—
|
|
|
15
|
|
|
(1
|
)
|
|
9
|
|
||||||||||
Earnings Before Noncontrolling Interest and Income Tax
|
39
|
|
|
(9
|
)
|
|
11
|
|
|
(41
|
)
|
|
—
|
|
|
(20
|
)
|
|
(6
|
)
|
|
8
|
|
|
(17
|
)
|
|
(35
|
)
|
||||||||||
Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||||
Earnings Before Income Tax
|
$
|
39
|
|
|
$
|
(9
|
)
|
|
$
|
11
|
|
|
$
|
(41
|
)
|
|
$
|
—
|
|
|
$
|
(20
|
)
|
|
$
|
(6
|
)
|
|
$
|
8
|
|
|
$
|
(17
|
)
|
|
$
|
(35
|
)
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas CBM sales volumes (in billion cubic feet)
|
23.3
|
|
|
23.0
|
|
|
0.3
|
|
|
1.3
|
%
|
|||
Average CBM sales price per thousand cubic feet sold
|
$
|
5.04
|
|
|
$
|
6.16
|
|
|
$
|
(1.12
|
)
|
|
(18.2
|
)%
|
Average CBM lifting costs per thousand cubic feet sold
|
$
|
0.54
|
|
|
$
|
0.59
|
|
|
$
|
(0.05
|
)
|
|
(8.5
|
)%
|
Average CBM gathering costs per thousand cubic feet sold
|
$
|
1.06
|
|
|
$
|
1.06
|
|
|
$
|
—
|
|
|
—
|
%
|
Average CBM general & administrative costs per thousand cubic feet sold
|
$
|
0.66
|
|
|
$
|
0.70
|
|
|
$
|
(0.04
|
)
|
|
(5.7
|
)%
|
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
1.10
|
|
|
$
|
1.23
|
|
|
$
|
(0.13
|
)
|
|
(10.6
|
)%
|
Total Average CBM costs per thousand cubic feet sold
|
$
|
3.36
|
|
|
$
|
3.58
|
|
|
$
|
(0.22
|
)
|
|
(6.1
|
)%
|
Average Margin for CBM
|
$
|
1.68
|
|
|
$
|
2.58
|
|
|
$
|
(0.90
|
)
|
|
(34.9
|
)%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas Conventional sales volumes (in billion cubic feet)
|
7.8
|
|
|
9.1
|
|
|
(1.3
|
)
|
|
(14.3
|
)%
|
|||
Average Conventional sales price per thousand cubic feet sold
|
$
|
4.98
|
|
|
$
|
5.00
|
|
|
$
|
(0.02
|
)
|
|
(0.4
|
)%
|
Average Conventional lifting costs per thousand cubic feet sold
|
$
|
2.19
|
|
|
$
|
1.37
|
|
|
$
|
0.82
|
|
|
59.9
|
%
|
Average Conventional gathering costs per thousand cubic feet sold
|
$
|
1.00
|
|
|
$
|
0.60
|
|
|
$
|
0.40
|
|
|
66.7
|
%
|
Average Conventional general & administrative costs per thousand cubic feet sold
|
$
|
0.93
|
|
|
$
|
0.80
|
|
|
$
|
0.13
|
|
|
16.3
|
%
|
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
1.96
|
|
|
$
|
2.49
|
|
|
$
|
(0.53
|
)
|
|
(21.3
|
)%
|
Total Average Conventional costs per thousand cubic feet sold
|
$
|
6.08
|
|
|
$
|
5.26
|
|
|
$
|
0.82
|
|
|
15.6
|
%
|
Average Margin for Conventional
|
$
|
(1.10
|
)
|
|
$
|
(0.26
|
)
|
|
$
|
(0.84
|
)
|
|
323.1
|
%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas Marcellus sales volumes (in billion cubic feet)
|
8.7
|
|
|
3.3
|
|
|
5.4
|
|
|
163.6
|
%
|
|||
Average Marcellus sales price per thousand cubic feet sold
|
$
|
4.48
|
|
|
$
|
4.66
|
|
|
$
|
(0.18
|
)
|
|
(3.9
|
)%
|
Average Marcellus lifting costs per thousand cubic feet sold
|
$
|
0.70
|
|
|
$
|
0.41
|
|
|
$
|
0.29
|
|
|
70.7
|
%
|
Average Marcellus gathering costs per thousand cubic feet sold
|
$
|
0.29
|
|
|
$
|
1.03
|
|
|
$
|
(0.74
|
)
|
|
(71.8
|
)%
|
Average Marcellus general & administrative costs per thousand cubic feet sold
|
$
|
0.53
|
|
|
$
|
0.73
|
|
|
$
|
(0.20
|
)
|
|
(27.4
|
)%
|
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
1.73
|
|
|
$
|
1.71
|
|
|
$
|
0.02
|
|
|
1.2
|
%
|
Total Average Marcellus costs per thousand cubic feet sold
|
$
|
3.25
|
|
|
$
|
3.88
|
|
|
$
|
(0.63
|
)
|
|
(16.2
|
)%
|
Average Margin for Marcellus
|
$
|
1.23
|
|
|
$
|
0.78
|
|
|
$
|
0.45
|
|
|
57.7
|
%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas Royalty Interest Sales Volumes (in billion cubic feet)
|
3.9
|
|
|
4.1
|
|
|
(0.2
|
)
|
|
(4.9
|
)%
|
|||
Average Sales Price Per thousand cubic feet
|
$
|
4.34
|
|
|
$
|
4.43
|
|
|
$
|
(0.09
|
)
|
|
(2.0
|
)%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Sales Volumes (in billion cubic feet)
|
0.3
|
|
|
0.6
|
|
|
(0.3
|
)
|
|
(50.0
|
)%
|
|||
Average Sales Price Per thousand cubic feet
|
$
|
4.43
|
|
|
$
|
5.54
|
|
|
$
|
(1.11
|
)
|
|
(20.0
|
)%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas Royalty Interest Sales Volumes (in billion cubic feet)
|
3.9
|
|
|
4.1
|
|
|
(0.2
|
)
|
|
(4.9
|
)%
|
|||
Average Cost Per thousand cubic feet sold
|
$
|
3.92
|
|
|
$
|
4.01
|
|
|
$
|
(0.09
|
)
|
|
(2.2
|
)%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Volumes (in billion cubic feet)
|
0.2
|
|
|
0.6
|
|
|
(0.4
|
)
|
|
(66.7
|
)%
|
|||
Average Cost Per thousand cubic feet sold
|
$
|
1.62
|
|
|
$
|
5.49
|
|
|
$
|
(3.87
|
)
|
|
(70.5
|
)%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Dry Hole and Lease Expiration Costs
|
$
|
6
|
|
|
$
|
12
|
|
|
$
|
(6
|
)
|
|
(50.0
|
)%
|
Exploration
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
%
|
|||
Total Exploration and Other Costs
|
$
|
6
|
|
|
$
|
12
|
|
|
$
|
(6
|
)
|
|
(50.0
|
)%
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Short-term incentive compensation
|
$
|
6
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
200.0
|
%
|
Unutilized firm transportation
|
5
|
|
|
1
|
|
|
4
|
|
|
400.0
|
%
|
|||
Contract buyout
|
3
|
|
|
—
|
|
|
3
|
|
|
100.0
|
%
|
|||
Stock-based compensation
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
%
|
|||
Other
|
2
|
|
|
6
|
|
|
(4
|
)
|
|
(66.7
|
)%
|
|||
Total Other Corporate Expenses
|
$
|
20
|
|
|
$
|
13
|
|
|
$
|
7
|
|
|
53.8
|
%
|
•
|
The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2011 period and an increased allocation of expense from CONSOL Energy as the result of exceeding corporate targets.
|
•
|
Unutilized firm transportation represents excess pipeline transportation capacity that the gas division obtained to enable gas production to flow on an uninterrupted basis as the gas operations continue to increase sales volumes.
|
•
|
Contract buyout represents the cancellation of a drilling arrangement with a third-party well driller.
|
•
|
Stock-based compensation expense remained consistent in the period-to-period comparison.
|
•
|
Other corporate related expense decreased $4 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Sales—Outside
|
$
|
88
|
|
|
$
|
75
|
|
|
$
|
13
|
|
|
17.3
|
%
|
Other Income
|
7
|
|
|
5
|
|
|
2
|
|
|
40.0
|
%
|
|||
Total Revenue
|
95
|
|
|
80
|
|
|
15
|
|
|
18.8
|
%
|
|||
Cost of Goods Sold and Other Charges
|
98
|
|
|
72
|
|
|
26
|
|
|
36.1
|
%
|
|||
Depreciation, Depletion & Amortization
|
5
|
|
|
4
|
|
|
1
|
|
|
25.0
|
%
|
|||
Taxes Other Than Income Tax
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
%
|
|||
Interest Expense
|
57
|
|
|
64
|
|
|
(7
|
)
|
|
(10.9
|
)%
|
|||
Total Costs
|
163
|
|
|
143
|
|
|
20
|
|
|
14.0
|
%
|
|||
Loss Before Income Tax
|
(68
|
)
|
|
(63
|
)
|
|
(5
|
)
|
|
(7.9
|
)%
|
|||
Income Tax
|
33
|
|
|
16
|
|
|
17
|
|
|
106.3
|
%
|
|||
Net Loss
|
$
|
(101
|
)
|
|
$
|
(79
|
)
|
|
$
|
(22
|
)
|
|
(27.8
|
)%
|
|
|
For the Three Months Ended September 30,
|
||||||||||
|
|
2011
|
|
2010
|
|
Variance
|
||||||
Transaction and financing fees
|
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
15
|
|
Interest expense
|
|
57
|
|
|
64
|
|
|
(7
|
)
|
|||
Bank fees
|
|
6
|
|
|
7
|
|
|
(1
|
)
|
|||
Evaluation fees for non-core asset dispositions
|
|
2
|
|
|
2
|
|
|
—
|
|
|||
Other
|
|
2
|
|
|
3
|
|
|
(1
|
)
|
|||
|
|
$
|
82
|
|
|
$
|
76
|
|
|
$
|
6
|
|
•
|
Transaction and financing fees of $15 million incurred in the three months ended September 30, 2011 related to the solicitation of consents of the long-term bonds needed in order to clarify the indentures that relate to joint arrangements with respect to CONSOL Energy's oil and gas properties.
|
•
|
Interest expense decreased $7 million in the period-to-period comparison primarily due to uncertain tax position adjustments related to the closure of federal income tax audits and lower borrowings on the revolving credit facility.
|
•
|
Bank fees decreased $1 million due to less borrowings on the revolving credit facility in the period-to-period comparison.
|
•
|
Evaluation fees for non-core asset dispositions remained consistent in the period-to-period comparison.
|
•
|
Other corporate items decreased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Three Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Total Company Earnings Before Income Tax
|
$
|
200
|
|
|
$
|
91
|
|
|
$
|
109
|
|
|
119.8
|
%
|
Income Tax Expense
|
$
|
33
|
|
|
$
|
16
|
|
|
$
|
17
|
|
|
106.3
|
%
|
Effective Income Tax Rate
|
16.5
|
%
|
|
17.3
|
%
|
|
(0.8
|
)%
|
|
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Average Sales Price per ton sold
|
$
|
72.48
|
|
|
$
|
61.42
|
|
|
$
|
11.06
|
|
|
18.0
|
%
|
Average Costs per ton sold
|
51.39
|
|
|
47.44
|
|
|
3.95
|
|
|
8.3
|
%
|
|||
Margin
|
$
|
21.09
|
|
|
$
|
13.98
|
|
|
$
|
7.11
|
|
|
50.9
|
%
|
•
|
Depreciation, depletion and amortization increased due to additional assets placed into service after the 2010 period,
|
•
|
Operating supplies and maintenance costs per ton sold were higher due to additional roof control costs, additional maintenance costs and equipment overhaul costs,
|
•
|
Higher costs associated with the increased sales price of coal sold, such as royalties and production related taxes,
|
•
|
Increased actuarial expenses related to other post employment benefits and pension related to employees retiring sooner than originally anticipated and average claim costs being higher than originally anticipated, and
|
•
|
Increased labor and labor related charges as a result of additional employees, increased overtime hours worked and the impact of the $1.50 per hour worked UMWA contract wage increases, $0.50 per hour worked related to the prior UMWA contract and $1.00 per hour worked related to the new UMWA contract.
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Average Sales Price per thousand cubic feet sold
|
$
|
4.97
|
|
|
$
|
6.22
|
|
|
$
|
(1.25
|
)
|
|
(20.1
|
)%
|
Average Costs per thousand cubic feet sold
|
3.86
|
|
|
3.88
|
|
|
(0.02
|
)
|
|
(0.5
|
)%
|
|||
Margin
|
$
|
1.11
|
|
|
$
|
2.34
|
|
|
$
|
(1.23
|
)
|
|
(52.6
|
)%
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Employee wages and related expenses
|
$
|
60
|
|
|
$
|
52
|
|
|
$
|
8
|
|
|
15.4
|
%
|
Advertising and promotion
|
7
|
|
|
2
|
|
|
5
|
|
|
250.0
|
%
|
|||
Contributions
|
5
|
|
|
3
|
|
|
2
|
|
|
66.7
|
%
|
|||
Commissions
|
11
|
|
|
10
|
|
|
1
|
|
|
10.0
|
%
|
|||
Consulting and professional services
|
20
|
|
|
19
|
|
|
1
|
|
|
5.3
|
%
|
|||
Miscellaneous
|
27
|
|
|
22
|
|
|
5
|
|
|
22.7
|
%
|
|||
Total Company Selling, General and Administrative Expenses
|
$
|
130
|
|
|
$
|
108
|
|
|
$
|
22
|
|
|
20.4
|
%
|
•
|
Employee wages and related expenses increased $8 million which was primarily attributable to the support staff retained in the Dominion Acquisition and additional hiring of support staff in the period-to-period comparison.
|
•
|
Advertising and promotion expense increased $5 million in the period-to-period comparison due to additional campaigns initiated in the 2011 period.
|
•
|
Contributions expense increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Commission expense increased $1 million due to the increase in average sales price and additional tons sold for which a third party was owed a commission in the period-to-period comparison.
|
•
|
Consulting and professional services increased $1 million due to various transactions that occurred throughout both
|
•
|
Miscellaneous selling, general and administrative expenses increased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Nine Months Ended
|
|
Difference to Nine Months Ended
|
||||||||||||||||||||||||||||||||||||
|
September 30, 2011
|
|
September 30, 2010
|
||||||||||||||||||||||||||||||||||||
|
Steam
Coal
|
|
High
Vol
Met
Coal
|
|
Low
Vol
Met
Coal
|
|
Other
Coal
|
|
Total
Coal
|
|
Steam
Coal
|
|
High
Vol
Met
Coal
|
|
Low
Vol
Met
Coal
|
|
Other
Coal
|
|
Total
Coal
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced Coal
|
$
|
2,315
|
|
|
$
|
278
|
|
|
$
|
824
|
|
|
$
|
23
|
|
|
$
|
3,440
|
|
|
$
|
112
|
|
|
$
|
143
|
|
|
$
|
333
|
|
|
$
|
16
|
|
|
$
|
604
|
|
Purchased Coal
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
12
|
|
||||||||||
Total Outside Sales
|
2,315
|
|
|
278
|
|
|
824
|
|
|
61
|
|
|
3,478
|
|
|
112
|
|
|
143
|
|
|
333
|
|
|
28
|
|
|
616
|
|
||||||||||
Freight Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
156
|
|
|
156
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
59
|
|
||||||||||
Other Income
|
5
|
|
|
9
|
|
|
—
|
|
|
52
|
|
|
66
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
11
|
|
|
14
|
|
||||||||||
Total Revenue and Other Income
|
2,320
|
|
|
287
|
|
|
824
|
|
|
269
|
|
|
3,700
|
|
|
112
|
|
|
146
|
|
|
333
|
|
|
98
|
|
|
689
|
|
||||||||||
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Total operating costs
|
1,429
|
|
|
126
|
|
|
223
|
|
|
170
|
|
|
1,948
|
|
|
(8
|
)
|
|
73
|
|
|
50
|
|
|
10
|
|
|
125
|
|
||||||||||
Total provisions
|
165
|
|
|
15
|
|
|
28
|
|
|
44
|
|
|
252
|
|
|
16
|
|
|
9
|
|
|
8
|
|
|
(69
|
)
|
|
(36
|
)
|
||||||||||
Total administrative & other costs
|
127
|
|
|
13
|
|
|
21
|
|
|
63
|
|
|
224
|
|
|
19
|
|
|
9
|
|
|
7
|
|
|
(6
|
)
|
|
29
|
|
||||||||||
Depreciation, depletion and amortization
|
226
|
|
|
22
|
|
|
27
|
|
|
126
|
|
|
401
|
|
|
28
|
|
|
14
|
|
|
12
|
|
|
88
|
|
|
142
|
|
||||||||||
Total Costs and Expenses
|
1,947
|
|
|
176
|
|
|
299
|
|
|
403
|
|
|
2,825
|
|
|
55
|
|
|
105
|
|
|
77
|
|
|
23
|
|
|
260
|
|
||||||||||
Freight Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
156
|
|
|
156
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
59
|
|
||||||||||
Total Costs
|
1,947
|
|
|
176
|
|
|
299
|
|
|
559
|
|
|
2,981
|
|
|
55
|
|
|
105
|
|
|
77
|
|
|
82
|
|
|
319
|
|
||||||||||
Earnings (Loss) Before Income Taxes
|
$
|
373
|
|
|
$
|
111
|
|
|
$
|
525
|
|
|
$
|
(290
|
)
|
|
$
|
719
|
|
|
$
|
57
|
|
|
$
|
41
|
|
|
$
|
256
|
|
|
$
|
16
|
|
|
$
|
370
|
|
|
For the Nine Months Ended June 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced Steam Tons Sold (in millions)
|
39.3
|
|
|
40.7
|
|
|
(1.4
|
)
|
|
(3.4
|
)%
|
|||
Average Sales Price Per Steam Ton Sold
|
$
|
58.88
|
|
|
$
|
54.09
|
|
|
$
|
4.79
|
|
|
8.9
|
%
|
Average Operating Costs Per Steam Ton Sold
|
$
|
36.33
|
|
|
$
|
35.29
|
|
|
$
|
1.04
|
|
|
2.9
|
%
|
Average Provision Costs Per Steam Ton Sold
|
$
|
4.21
|
|
|
$
|
3.66
|
|
|
$
|
0.55
|
|
|
15.0
|
%
|
Average Selling, Administrative and Other Costs Per Steam Ton Sold
|
$
|
3.23
|
|
|
$
|
2.65
|
|
|
$
|
0.58
|
|
|
21.9
|
%
|
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold
|
$
|
5.76
|
|
|
$
|
4.85
|
|
|
$
|
0.91
|
|
|
18.8
|
%
|
Total Average Costs Per Steam Ton Sold
|
$
|
49.53
|
|
|
$
|
46.45
|
|
|
$
|
3.08
|
|
|
6.6
|
%
|
Margin Per Steam Ton Sold
|
$
|
9.35
|
|
|
$
|
7.64
|
|
|
$
|
1.71
|
|
|
22.4
|
%
|
•
|
Average operating supplies & maintenance costs per ton sold increased due to additional maintenance and equipment overhaul costs and additional roof control costs. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers.
|
•
|
Average preparation costs per ton sold increased due to additional maintenance projects completed at our preparation plants in the period-to-period comparison.
|
•
|
Labor and related benefits were impaired on a cost per ton sold basis due to higher costs and lower volumes sold. Higher benefit costs were due primarily to contributions made to the 1974 Pension Trust (the Trust), which is a multiemployer pension plan. Contributions to the Trust were negotiated under the National Bituminous Coal Wage Agreement. Contributions are based on a rate per hour worked by members of the United Mine Workers of America (UMWA). The contribution rate increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Additional employees in the period-to-period comparison also contributed to higher labor costs. Non-union benefit rates for active employees also increased as a result of continued increases in healthcare costs. Labor and related benefits also increased due to additional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the new collective bargaining agreement, in the period-to-period comparison. These increases were offset, in part, as a result of the Tax Relief and Health Care Act of 2006 authorizing
|
•
|
Production taxes average cost per ton sold increased primarily due to the $4.79 per ton higher average sales price.
|
•
|
Average operating costs per steam ton sold increased due to lower tons sold as fixed costs were allocated over less tons; therefore, unit cost increased.
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced High Vol Met Tons Sold (in millions)
|
3.5
|
|
|
1.8
|
|
|
1.7
|
|
|
94.4
|
%
|
|||
Average Sales Price Per High Vol Met Ton Sold
|
$
|
78.75
|
|
|
$
|
73.65
|
|
|
$
|
5.10
|
|
|
6.9
|
%
|
Average Operating Costs Per High Vol Met Ton Sold
|
$
|
35.98
|
|
|
$
|
28.89
|
|
|
$
|
7.09
|
|
|
24.5
|
%
|
Average Provision Costs Per High Vol Met Ton Sold
|
$
|
4.15
|
|
|
$
|
3.08
|
|
|
$
|
1.07
|
|
|
34.7
|
%
|
Average Selling, Administrative and Other Costs Per High Vol Met Ton Sold
|
$
|
3.63
|
|
|
$
|
2.26
|
|
|
$
|
1.37
|
|
|
60.6
|
%
|
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Sold
|
$
|
6.25
|
|
|
$
|
4.24
|
|
|
$
|
2.01
|
|
|
47.4
|
%
|
Total Average Costs Per High Vol Met Ton Sold
|
$
|
50.01
|
|
|
$
|
38.47
|
|
|
$
|
11.54
|
|
|
30.0
|
%
|
Margin Per High Vol Met Ton Sold
|
$
|
28.74
|
|
|
$
|
35.18
|
|
|
$
|
(6.44
|
)
|
|
(18.3
|
%)
|
•
|
Average operating costs per ton sold increased due to the mix of mines selling coal on the high volatile metallurgical coal market. As higher cost structure mines sell coal in the high volatile metallurgical market, average operating costs per ton sold increase. Previously, this segment only included lower cost structure mines.
|
•
|
Labor and related benefits increased due to higher employee counts, higher non-union benefit rates and higher contributions per hour worked to the 1974 Pension Trust (Trust). Labor and related benefits increased due to additional employees in the period-to-period comparison. Higher labor and related costs were also due to higher non-union benefit rates for active employees related to the continued increase in healthcare costs. Higher contributions made to the Trust were discussed in the steam coal segment. Labor and related benefits also increased due to additional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the new collective bargaining agreement, in the period-to-period comparison. These increases were offset by lower overall contributions to certain multiemployer benefit plans such as the 1992 Fund, the 1993 Fund and the Combined Fund, which were also discussed in the steam coal segment. Increased labor and related benefit costs per unit sold were also offset, in part, by additional volumes of high volatile metallurgical tons sold in the period-to-period comparison.
|
•
|
Average operating supplies & maintenance costs per ton sold increased due to additional maintenance and equipment overhaul costs and additional roof control costs. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison.
|
•
|
Average coal preparation costs per ton sold increased due to additional maintenance projects that have been completed
|
•
|
Production taxes average cost per ton sold increased due to the $5.10 per ton higher average sales price.
|
•
|
In-transit charges average cost per ton sold increased primarily due to the increased cost of moving coal from the mine to the preparation plant for processing. This increase is primarily related to the mix of mines now shipping high volatile metallurgical coal.
|
•
|
Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.
|
•
|
Average operating costs per ton sold decreased due to higher tons sold. Therefore, fixed costs were allocated over more tons; therefore, unit costs decreased.
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced Low Vol Met Tons Sold (in millions)
|
4.3
|
|
|
3.5
|
|
|
0.8
|
|
|
22.9
|
%
|
|||
Average Sales Price Per Low Vol Met Ton Sold
|
$
|
191.84
|
|
|
$
|
140.27
|
|
|
$
|
51.57
|
|
|
36.8
|
%
|
Average Operating Costs Per Low Vol Met Ton Sold
|
$
|
51.84
|
|
|
$
|
49.44
|
|
|
$
|
2.40
|
|
|
4.9
|
%
|
Average Provision Costs Per Low Vol Met Ton Sold
|
$
|
6.63
|
|
|
$
|
5.80
|
|
|
$
|
0.83
|
|
|
14.3
|
%
|
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold
|
$
|
4.88
|
|
|
$
|
3.96
|
|
|
$
|
0.92
|
|
|
23.2
|
%
|
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold
|
$
|
6.30
|
|
|
$
|
4.35
|
|
|
$
|
1.95
|
|
|
44.8
|
%
|
Total Average Costs Per Low Vol Met Ton Sold
|
$
|
69.65
|
|
|
$
|
63.55
|
|
|
$
|
6.10
|
|
|
9.6
|
%
|
Margin Per Low Vol Met Ton Sold
|
$
|
122.19
|
|
|
$
|
76.72
|
|
|
$
|
45.47
|
|
|
59.3
|
%
|
•
|
Average operating supplies and maintenance costs per ton sold increased due to additional roof control costs, additional ventilation costs of coalbed methane gas and additional equipment overhaul costs. Additional roof control costs resulted from changes in roof support strategy, such as types of roof support used and quantity of support put into place. The roof control strategy was changed to improve the safety of the mine and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison. Additional costs were incurred in the 2011 period to increase the number of bore holes that were placed ahead of mining to ventilate the coalbed methane gas from the mine. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period.
|
•
|
Costs associated with the sales price of coal sold, such as royalties and production related taxes, increased due to the higher average sales prices received for low volatile metallurgical coal in the period-to-period comparison.
|
|
|
For the Nine Months Ended September 30,
|
||||||||||
|
|
2011
|
|
2010
|
|
Variance
|
||||||
Abandonment of long-lived assets
|
|
$
|
116
|
|
|
$
|
—
|
|
|
$
|
116
|
|
Freight expense
|
|
156
|
|
|
97
|
|
|
59
|
|
|||
Purchased Coal
|
|
59
|
|
|
30
|
|
|
29
|
|
|||
Coal contract buyout
|
|
5
|
|
|
—
|
|
|
5
|
|
|||
Closed and idle mines
|
|
80
|
|
|
184
|
|
|
(104
|
)
|
|||
Litigation expense
|
|
—
|
|
|
35
|
|
|
(35
|
)
|
|||
Other
|
|
143
|
|
|
131
|
|
|
12
|
|
|||
Total other coal segment costs
|
|
$
|
559
|
|
|
$
|
477
|
|
|
$
|
82
|
|
•
|
Abandonment of long-lived assets was $116 million for the nine months ended September 30, 2011 as a result of the decision to permanently idle Mine 84.
|
•
|
Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset in freight revenue. The increase was primarily due to the 2.7 million ton increase in export tons in the period-to-period comparison.
|
•
|
Purchased coal costs increased approximately $29 million in the period-to-period comparison primarily due to differences in the quality of coal purchased, increases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.
|
•
|
Coal contract buyout costs increased $5 million as a result of a lower priced coal sales contract being bought out in order to sell the tons on a higher priced contract in a future period.
|
•
|
Closed and idle mine costs decreased approximately $104 million in the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. In the 2010 period, as a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia was increased $82 million. Also in the 2010 period, closed and idle mine costs increased approximately $14 million as the result of the change in mine plan at Mine 84. As a result of the mine plan change, a portion of the previously developed area of the mine was abandoned. In addition, $8 million of reduced expenses were recognized in closed and idle mine costs for various changes in the operational status of other mines, between idled and operating, throughout both periods, none of which were individually material
|
•
|
Litigation expense of $25 million was recognized in the nine months ended September 30, 2010 related to an anticipated legal settlement related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries. Litigation expense was also recognized in the nine months ended September 30, 2010 related to a settlement that included the sale of Jones Fork which resulted in a loss of $10 million.
|
•
|
Other expenses related to the coal segment were $12 million higher for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. The increase was related to a $5 million charge for an additional liability due to Pennsylvania stream remediation and $7 million of the increase was related to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Nine Months Ended
|
|
Difference to Nine Months Ended
|
||||||||||||||||||||||||||||||||||||
|
September 30, 2011
|
|
September 30, 2010
|
||||||||||||||||||||||||||||||||||||
|
CBM
|
|
Conven-
tional
|
|
Marcellus
|
|
Other
Gas
|
|
Total
Gas
|
|
CBM
|
|
Conven-
tional
|
|
Marcellus
|
|
Other
Gas
|
|
Total
Gas
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced
|
$
|
345
|
|
|
$
|
120
|
|
|
$
|
88
|
|
|
$
|
9
|
|
|
$
|
562
|
|
|
$
|
(104
|
)
|
|
$
|
42
|
|
|
$
|
54
|
|
|
$
|
4
|
|
|
$
|
(4
|
)
|
Related Party
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||||||||
Total Outside Sales
|
349
|
|
|
120
|
|
|
88
|
|
|
9
|
|
|
566
|
|
|
(105
|
)
|
|
42
|
|
|
54
|
|
|
4
|
|
|
(5
|
)
|
||||||||||
Gas Royalty Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
52
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
||||||||||
Purchased Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
(5
|
)
|
||||||||||
Other Income
|
—
|
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
(12
|
)
|
||||||||||
Total Revenue and Other Income
|
349
|
|
|
120
|
|
|
88
|
|
|
55
|
|
|
612
|
|
|
(105
|
)
|
|
42
|
|
|
54
|
|
|
(8
|
)
|
|
(17
|
)
|
||||||||||
Lifting
|
38
|
|
|
43
|
|
|
12
|
|
|
2
|
|
|
95
|
|
|
(1
|
)
|
|
25
|
|
|
9
|
|
|
1
|
|
|
34
|
|
||||||||||
Gathering
|
71
|
|
|
20
|
|
|
10
|
|
|
2
|
|
|
103
|
|
|
(3
|
)
|
|
12
|
|
|
2
|
|
|
—
|
|
|
11
|
|
||||||||||
General & Administration
|
46
|
|
|
23
|
|
|
12
|
|
|
1
|
|
|
82
|
|
|
(1
|
)
|
|
11
|
|
|
7
|
|
|
2
|
|
|
19
|
|
||||||||||
Depreciation, Depletion and Amortization
|
75
|
|
|
48
|
|
|
29
|
|
|
7
|
|
|
159
|
|
|
(8
|
)
|
|
9
|
|
|
16
|
|
|
2
|
|
|
19
|
|
||||||||||
Gas Royalty Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
47
|
|
|
47
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
||||||||||
Purchased Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
||||||||||
Exploration and Other Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
(11
|
)
|
||||||||||
Other Corporate Expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
49
|
|
|
49
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
9
|
|
||||||||||
Interest Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||||||||
Total Cost
|
230
|
|
|
134
|
|
|
63
|
|
|
128
|
|
|
555
|
|
|
(13
|
)
|
|
57
|
|
|
34
|
|
|
6
|
|
|
84
|
|
||||||||||
Earnings Before Noncontrolling Interest and Income Tax
|
119
|
|
|
(14
|
)
|
|
25
|
|
|
(73
|
)
|
|
57
|
|
|
(92
|
)
|
|
(15
|
)
|
|
20
|
|
|
(14
|
)
|
|
(101
|
)
|
||||||||||
Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
9
|
|
||||||||||
Earnings Before Income Tax
|
$
|
119
|
|
|
$
|
(14
|
)
|
|
$
|
25
|
|
|
$
|
(77
|
)
|
|
$
|
53
|
|
|
$
|
(92
|
)
|
|
$
|
(15
|
)
|
|
$
|
20
|
|
|
$
|
(23
|
)
|
|
$
|
(110
|
)
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas CBM sales volumes (in billion cubic feet)
|
68.6
|
|
|
67.7
|
|
|
0.9
|
|
|
1.3
|
%
|
|||
Average CBM sales price per thousand cubic feet sold
|
$
|
5.09
|
|
|
$
|
6.70
|
|
|
$
|
(1.61
|
)
|
|
(24.0
|
)%
|
Average CBM lifting costs per thousand cubic feet sold
|
$
|
0.56
|
|
|
$
|
0.57
|
|
|
$
|
(0.01
|
)
|
|
(1.8
|
)%
|
Average CBM gathering costs per thousand cubic feet sold
|
$
|
1.04
|
|
|
$
|
1.09
|
|
|
$
|
(0.05
|
)
|
|
(4.6
|
)%
|
Average CBM general & administrative costs per thousand cubic feet sold
|
$
|
0.67
|
|
|
$
|
0.69
|
|
|
$
|
(0.02
|
)
|
|
(2.9
|
)%
|
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
1.09
|
|
|
$
|
1.23
|
|
|
$
|
(0.14
|
)
|
|
(11.4
|
)%
|
Total Average CBM costs per thousand cubic feet sold
|
$
|
3.36
|
|
|
$
|
3.58
|
|
|
$
|
(0.22
|
)
|
|
(6.1
|
)%
|
Average Margin for CBM
|
$
|
1.73
|
|
|
$
|
3.12
|
|
|
$
|
(1.39
|
)
|
|
(44.6
|
)%
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas Conventional sales volumes (in billion cubic feet)
|
24.0
|
|
|
15.9
|
|
|
8.1
|
|
|
50.9
|
%
|
|||
Average Conventional sales price per thousand cubic feet sold
|
$
|
5.00
|
|
|
$
|
4.91
|
|
|
$
|
0.09
|
|
|
1.8
|
%
|
Average Conventional lifting costs per thousand cubic feet sold
|
$
|
1.79
|
|
|
$
|
1.12
|
|
|
$
|
0.67
|
|
|
59.8
|
%
|
Average Conventional gathering costs per thousand cubic feet sold
|
$
|
0.84
|
|
|
$
|
0.54
|
|
|
$
|
0.30
|
|
|
55.6
|
%
|
Average Conventional general & administrative costs per thousand cubic feet sold
|
$
|
0.97
|
|
|
$
|
0.74
|
|
|
$
|
0.23
|
|
|
31.1
|
%
|
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
2.00
|
|
|
$
|
2.45
|
|
|
$
|
(0.45
|
)
|
|
(18.4
|
)%
|
Total Average Conventional costs per thousand cubic feet sold
|
$
|
5.60
|
|
|
$
|
4.85
|
|
|
$
|
0.75
|
|
|
15.5
|
%
|
Average Margin for Conventional
|
$
|
(0.60
|
)
|
|
$
|
0.06
|
|
|
$
|
(0.66
|
)
|
|
(1,100.0
|
)%
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas Marcellus sales volumes (in billion cubic feet)
|
19.7
|
|
|
7.1
|
|
|
12.6
|
|
|
177.5
|
%
|
|||
Average Marcellus sales price per thousand cubic feet sold
|
$
|
4.48
|
|
|
$
|
4.79
|
|
|
$
|
(0.31
|
)
|
|
(6.5
|
)%
|
Average Marcellus lifting costs per thousand cubic feet sold
|
$
|
0.63
|
|
|
$
|
0.47
|
|
|
$
|
0.16
|
|
|
34.0
|
%
|
Average Marcellus gathering costs per thousand cubic feet sold
|
$
|
0.49
|
|
|
$
|
1.07
|
|
|
$
|
(0.58
|
)
|
|
(54.2
|
)%
|
Average Marcellus general & administrative costs per thousand cubic feet sold
|
$
|
0.63
|
|
|
$
|
0.67
|
|
|
$
|
(0.04
|
)
|
|
(6.0
|
)%
|
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
1.48
|
|
|
$
|
1.88
|
|
|
$
|
(0.40
|
)
|
|
(21.3
|
)%
|
Total Average Marcellus costs per thousand cubic feet sold
|
$
|
3.23
|
|
|
$
|
4.09
|
|
|
$
|
(0.86
|
)
|
|
(21.0
|
)%
|
Average Margin for Marcellus
|
$
|
1.25
|
|
|
$
|
0.70
|
|
|
$
|
0.55
|
|
|
78.6
|
%
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas Royalty Interest Sales Volumes (in billion cubic feet)
|
12.2
|
|
|
9.9
|
|
|
2.3
|
|
|
23.2
|
%
|
|||
Average Sales Price Per thousand cubic feet
|
$
|
4.27
|
|
|
$
|
4.69
|
|
|
$
|
(0.42
|
)
|
|
(9.0
|
)%
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Sales Volumes (in billion cubic feet)
|
0.7
|
|
|
1.5
|
|
|
(0.8
|
)
|
|
(53.3
|
)%
|
|||
Average Sales Price Per thousand cubic feet
|
$
|
4.50
|
|
|
$
|
5.65
|
|
|
$
|
(1.15
|
)
|
|
(20.4
|
)%
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas Royalty Interest Sales Volumes (in billion cubic feet)
|
12.2
|
|
|
9.9
|
|
|
2.3
|
|
|
23.2
|
%
|
|||
Average Cost Per thousand cubic feet sold
|
$
|
3.81
|
|
|
$
|
4.05
|
|
|
$
|
(0.24
|
)
|
|
(5.9
|
)%
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Dry Hole and Lease Expiration Costs (including settlement)
|
$
|
7
|
|
|
$
|
18
|
|
|
$
|
(11
|
)
|
|
(61.1
|
)%
|
Exploration
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
%
|
|||
Total Exploration and Other Costs
|
$
|
10
|
|
|
$
|
21
|
|
|
$
|
(11
|
)
|
|
(52.4
|
)%
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Unutilized firm transportation
|
$
|
11
|
|
|
$
|
1
|
|
|
$
|
10
|
|
|
1,000.0
|
%
|
Short-term incentive compensation
|
19
|
|
|
14
|
|
|
5
|
|
|
35.7
|
%
|
|||
Contract buyout
|
3
|
|
|
—
|
|
|
3
|
|
|
100.0
|
%
|
|||
Stock-based compensation
|
13
|
|
|
11
|
|
|
2
|
|
|
18.2
|
%
|
|||
Bank fees
|
5
|
|
|
3
|
|
|
2
|
|
|
66.7
|
%
|
|||
Variable interest earnings
|
(4
|
)
|
|
4
|
|
|
(8
|
)
|
|
(200.0
|
)%
|
|||
Legal fees
|
—
|
|
|
3
|
|
|
(3
|
)
|
|
(100.0
|
)%
|
|||
Other
|
2
|
|
|
4
|
|
|
(2
|
)
|
|
(50.0
|
)%
|
|||
Total Other Corporate Expenses
|
$
|
49
|
|
|
$
|
40
|
|
|
$
|
9
|
|
|
22.5
|
%
|
•
|
Unutilized firm transportation represents pipeline transportation capacity that the gas segment has obtained to enable gas production to flow uninterrupted as the gas operations continue to increase sales volumes.
|
•
|
The short-term incentive compensation program is designed to increase compensation to eligible employees when
|
•
|
Contract buyout represents the cancellation of a drilling arrangement with a third party well driller.
|
•
|
Stock-based compensation was higher in the period-to-period comparison primarily due to the increased allocation from CONSOL Energy as a result of the Dominion Acquisition as well as an increase in total CONSOL Energy stock-based compensation expense. Stock-based compensation costs are allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.
|
•
|
Bank fees were higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas segment. In April 2011, the facility was amended to allow $1 billion of borrowings and was extended to April 12, 2016.
|
•
|
Variable interest earnings are related to various adjustments a third party entity has reflected in its financial statements. CONSOL Energy holds no ownership interest and during the 2011 period de-consolidated the impact of this third party due to the cancellation of the drilling arrangement. Based on analysis, during the time CONSOL Energy guaranteed the bank loans the entity held, it was determined that CONOL Energy was the primary beneficiary. Therefore, the entity was fully consolidated and the earnings impact is fully reversed in the non-controlling interest line discussed below.
|
•
|
Legal fees for the 2010 period were related to the special committee formed during the CNX Gas take-in transaction and also represent legal fees related to the shareholder litigation related to this transaction.
|
•
|
Other corporate related expense decreased $2 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Sales—Outside
|
$
|
252
|
|
|
$
|
220
|
|
|
$
|
32
|
|
|
14.5
|
%
|
Other Income
|
14
|
|
|
22
|
|
|
(8
|
)
|
|
(36.4
|
)%
|
|||
Total Revenue
|
266
|
|
|
242
|
|
|
24
|
|
|
9.9
|
%
|
|||
Cost of Goods Sold and Other Charges
|
282
|
|
|
269
|
|
|
13
|
|
|
4.8
|
%
|
|||
Depreciation, Depletion & Amortization
|
14
|
|
|
14
|
|
|
—
|
|
|
—
|
%
|
|||
Taxes Other Than Income Tax
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
%
|
|||
Interest Expense
|
183
|
|
|
134
|
|
|
49
|
|
|
36.6
|
%
|
|||
Total Costs
|
488
|
|
|
426
|
|
|
62
|
|
|
14.6
|
%
|
|||
Loss Before Income Tax
|
(222
|
)
|
|
(184
|
)
|
|
(38
|
)
|
|
(20.7
|
)%
|
|||
Income Tax
|
113
|
|
|
75
|
|
|
38
|
|
|
50.7
|
%
|
|||
Net Loss
|
$
|
(335
|
)
|
|
$
|
(259
|
)
|
|
$
|
(76
|
)
|
|
(29.3
|
)%
|
|
|
For the Nine Months Ended September 30,
|
||||||||||
|
|
2011
|
|
2010
|
|
Variance
|
||||||
Interest expense
|
|
$
|
183
|
|
|
$
|
134
|
|
|
$
|
49
|
|
Loss on extinguishment of debt
|
|
16
|
|
|
—
|
|
|
16
|
|
|||
Evaluation fees for non-core asset dispositions
|
|
5
|
|
|
2
|
|
|
3
|
|
|||
Transaction and financing fees
|
|
15
|
|
|
61
|
|
|
(46
|
)
|
|||
Bank fees
|
|
16
|
|
|
13
|
|
|
3
|
|
|||
Other
|
|
14
|
|
|
11
|
|
|
3
|
|
|||
|
|
$
|
249
|
|
|
$
|
221
|
|
|
$
|
28
|
|
•
|
Interest expense increased $49 million primarily due to interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition in April 2010.
|
•
|
On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million for a total redemption cost of $268 million. The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held to maturity.
|
•
|
Evaluation fees for non-core asset dispositions increased $3 million in the period-to-period comparison due to various corporate initiatives that began in the 2010 period.
|
•
|
Transaction and financing fees of $61 million incurred in the nine months ended September 30, 2010 primarily related to the Dominion Acquisition, as well as the equity and debt issuance that raised approximately $4.6 billion. Transaction and financing fees of $15 million incurred in the nine months ended September 30, 2011 related to the solicitation of consents of the long-term bonds needed in order to clarify the indentures that relate to joint arrangements with respect to its oil and gas properties.
|
•
|
Bank fees increased $3 million in the period-to-period comparison due to the refinancing and extension of the previous $1.0 billion credit facility to $1.5 billion on May 7, 2010.
|
•
|
Other corporate items increased $3 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Total Company Earnings Before Income Tax
|
$
|
550
|
|
|
$
|
329
|
|
|
$
|
221
|
|
|
67.2
|
%
|
Income Tax Expense
|
$
|
113
|
|
|
$
|
75
|
|
|
$
|
38
|
|
|
50.7
|
%
|
Effective Income Tax Rate
|
20.6
|
%
|
|
22.9
|
%
|
|
(2.3
|
)%
|
|
|
|
For the Nine Months Ended September 30,
|
||||||||||
|
2011
|
|
2010
|
|
Change
|
||||||
Cash flows from operating activities
|
$
|
1,252
|
|
|
$
|
879
|
|
|
$
|
373
|
|
Cash used in investing activities
|
$
|
(231
|
)
|
|
$
|
(5,255
|
)
|
|
$
|
5,024
|
|
Cash (used in) provided by financing activities
|
$
|
(581
|
)
|
|
$
|
4,326
|
|
|
$
|
(4,907
|
)
|
•
|
Operating cash flow increased $183 million in 2011 due to higher net income attributable to CONSOL Energy shareholders in the period-to-period comparison. The 2011 net income included an approximately $75 million reduction due to the abandonment of Mine 84 which is discussed further in Note 8—Property, Plant and Equipment, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q. This reduction did not have a corresponding reduction to cash flows from operating activities because it was primarily related to the write-down of assets remaining at Mine 84 at the time of the abandonment, not cash obligations.
|
•
|
Operating cash flows increased $35 million in 2011 compared to the prior year due to differences in accrued income tax liabilities. The decrease in accrued income taxes in 2011 was $4 million compared to a decrease in accrued income taxes in the 2010 period of $39 million.
|
•
|
Operating cash flows increased due to various other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years, none of which were individually material.
|
•
|
On April 30, 2010, CONSOL Energy paid $3.474 billion for the Dominion Acquisition. See Note 2—Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.
|
•
|
On May 28, 2010, CONSOL Energy paid $991 million to acquire the shares of CNX Gas common stock and vested stock options which it did not previously own.
|
•
|
On September 30, 2011, CONSOL Energy received net proceeds of $519 million related to the Noble transaction. See Note 2—Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.
|
•
|
On September 30, 2011, CONSOL Energy received a $67 million cash distribution from CONE Gathering LLC. See Note 2—Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.
|
•
|
Total capital expenditures increased $176 million to $997 million in the nine months ended September 30, 2011 compared to $822 million in the nine months ended September 30, 2010. Capital expenditures for the gas segment increased $243 million due to the additional drilling in the period-to-period comparison. The increased gas segment capital was primarily due to the increased Marcellus Shale drilling. Capital expenditures for coal and other activities decreased $67 million in the period-to-period comparison. Face extension projects at various locations were lower by $83 million as a result of the majority of these projects being completed during the 2010 period, $13 million was incurred in the 2010 period as a result of a longwall shield lease buyout, and the 2011 period was lower by approximately $29 million related to the Buchanan Reverse Osmosis (RO) system which was primarily completed before January 1, 2011 and an approximate $18 million decrease in 2011 related to various other equipment expenditures throughout both periods. These reductions in coal and other capital were offset, in part by an approximate $61 million increase in expenditures related primarily to the ongoing development of the BMX Mine which is scheduled to go on-line in 2014, and a $15 million increase in 2011 related to the construction of the Northern West Virginia RO system.
|
•
|
Proceeds of $2.75 billion were received on April 1, 2010 in connection with the issuance of $1.5 billion of 8.00% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020.
|
•
|
In 2010, proceeds of $1.83 billion were received in connection with the issuance of 44.3 million shares of common stock which was completed on March 31, 2010.
|
•
|
In 2011, CONSOL Energy repaid $200 million of borrowings under the accounts receivable securitization facility. In 2010, CONSOL Energy received proceeds of $150 million under this facility.
|
•
|
In 2011, CONSOL Energy paid $266 million, including a make-whole provision, to redeem the 7.875% notes that were due in March 2012.
|
•
|
In 2011, CONSOL Energy paid $15 million related to the solicitation of consents from the holders of CONSOL Energy's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020, and 6.375% Senior Notes due 2021. See Note 10—Long-Term Debt, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.
|
•
|
In 2011, CONSOL Energy paid outstanding borrowings of $155 million under the revolving credit facility. In 2010, CONSOL Energy paid $279 million under this facility.
|
•
|
Dividends of $68 million were paid in 2011 compared to $63 million in 2010. The increase was due to the 44.3 million additional shares issued on March 31, 2010.
|
•
|
In 2011, proceeds of $250 million were received in connection with the issuance of $250 million of 6.375% senior unsecured notes due in March 2021.
|
•
|
In 2011, CNX Gas, a wholly-owned subsidiary, paid outstanding borrowings of $129 million under its revolving credit facility compared to receiving $20 million in 2010.
|
|
Payments due by Year
|
||||||||||||||||||
|
Less Than
1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than
5 Years
|
|
Total
|
||||||||||
Purchase Order Firm Commitments
|
$
|
174,979
|
|
|
$
|
129,553
|
|
|
$
|
7,094
|
|
|
$
|
—
|
|
|
$
|
311,626
|
|
Gas Firm Transportation
|
49,937
|
|
|
136,358
|
|
|
130,444
|
|
|
466,646
|
|
|
783,385
|
|
|||||
CONE Gathering Commitments
|
3,400
|
|
|
78,000
|
|
|
251,300
|
|
|
1,389,100
|
|
|
1,721,800
|
|
|||||
Long-Term Debt
|
11,718
|
|
|
6,517
|
|
|
5,173
|
|
|
3,111,744
|
|
|
3,135,152
|
|
|||||
Interest on Long-Term Debt
|
244,977
|
|
|
490,743
|
|
|
491,730
|
|
|
667,328
|
|
|
1,894,778
|
|
|||||
Capital (Finance) Lease Obligations
|
8,588
|
|
|
13,845
|
|
|
10,226
|
|
|
31,227
|
|
|
63,886
|
|
|||||
Interest on Capital (Finance) Lease Obligations
|
4,275
|
|
|
6,925
|
|
|
5,374
|
|
|
6,279
|
|
|
22,853
|
|
|||||
Operating Lease Obligations
|
89,379
|
|
|
143,291
|
|
|
102,069
|
|
|
130,724
|
|
|
465,463
|
|
|||||
Long-Term Liabilities—Employee Related (a)
|
230,132
|
|
|
484,762
|
|
|
521,037
|
|
|
2,444,423
|
|
|
3,680,354
|
|
|||||
Other Long-Term Liabilities (b)
|
393,548
|
|
|
137,498
|
|
|
73,573
|
|
|
410,486
|
|
|
1,015,105
|
|
|||||
Total Contractual Obligations (c)
|
$
|
1,210,933
|
|
|
$
|
1,627,492
|
|
|
$
|
1,598,020
|
|
|
$
|
8,657,957
|
|
|
$
|
13,094,402
|
|
(a)
|
Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2011 contributions are expected to approximate $
71.7
million.
|
(b)
|
Other long-term liabilities include mine reclamation and closure and other long-term liability costs.
|
(c)
|
The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
|
•
|
An aggregate principal amount of $
1.5
billion
of
8.00%
senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.
|
•
|
An aggregate principal amount of $
1.25
billion
of
8.25%
senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.
|
•
|
An aggregate principal amount of $
250
million
of
6.375%
notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.
|
•
|
An aggregate principal amount of $
103
million
of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at
5.75%
per annum and mature in September 2025. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year.
|
•
|
$
32
million
in advance royalty commitments with an average interest rate of
7.56%
per annum.
|
•
|
An aggregate principal amount of $
64
million
of capital leases with a weighted average interest rate of
6.46%
per annum.
|
Declaration Date
|
|
Amount Per Share
|
|
Record Date
|
|
Payment Date
|
||
October 27, 2011
|
|
$
|
0.125
|
|
|
November 11, 2011
|
|
November 25, 2011
|
July 29, 2011
|
|
$
|
0.100
|
|
|
August 10, 2011
|
|
August 22, 2011
|
April 29, 2011
|
|
$
|
0.100
|
|
|
May 13, 2011
|
|
May 24, 2011
|
January 28, 2011
|
|
$
|
0.100
|
|
|
February 8, 2011
|
|
February 18, 2011
|
•
|
deterioration in economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;
|
•
|
an extended decline in prices we receive for our coal and gas affecting our operating results and cash flows;
|
•
|
our customers extending existing contracts or entering into new long-term contracts for coal;
|
•
|
our reliance on major customers;
|
•
|
our inability to collect payments from customers if their creditworthiness declines;
|
•
|
the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our coal and gas to market;
|
•
|
a loss of our competitive position because of the competitive nature of the coal and gas industries, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;
|
•
|
our inability to maintain satisfactory labor relations;
|
•
|
coal users switching to other fuels in order to comply with various environmental standards related to coal combustion emissions;
|
•
|
the impact of potential, as well as any adopted regulations relating to greenhouse gas emissions on the demand for coal and natural gas, as well as the impact of any adopted regulations on our coal mining operations due to the venting of coalbed methane which occurs during mining;
|
•
|
foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;
|
•
|
the risks inherent in coal and gas operations being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, explosions, accidents and weather conditions which could impact financial results;
|
•
|
our focus on new gas development projects and exploration for gas in areas where we have little or no proven gas reserves;
|
•
|
decreases in the availability of, or increases in, the price of commodities and services used in our mining and gas operations, as well as our exposure under “take or pay” contracts we entered into with well service providers to obtain services which if not used could impact our cost of production;
|
•
|
obtaining and renewing governmental permits and approvals for our coal and gas operations;
|
•
|
the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous substances and wastes generated during our coal and gas operations;
|
•
|
the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut down a mine or well;
|
•
|
the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current coal and gas operations;
|
•
|
the effects of mine closing, reclamation, gas well closing and certain other liabilities;
|
•
|
uncertainties in estimating our economically recoverable coal and gas reserves;
|
•
|
costs associated with perfecting title for coal or gas rights on some of our properties;
|
•
|
the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities Exchange Act of 1934;
|
•
|
the impacts of various asbestos litigation claims;
|
•
|
increased exposure to employee related long-term liabilities;
|
•
|
increased exposure to multi-employer pension plan liabilities;
|
•
|
minimum funding requirements by the Pension Protection Act of 2006 (the Pension Act) coupled with the significant investment and plan asset losses suffered during the recent economic decline has exposed us to making additional required cash contributions to fund the pension benefit plans which we sponsor and the multi-employer pension benefit plans in which we participate;
|
•
|
lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan exceeding total service and interest cost in a plan year;
|
•
|
acquisitions and joint ventures that we recently have completed or entered into or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies or other benefits (including joint venture partners paying carry obligations), integrating the acquisitions and unanticipated changes that could affect assumptions we may have made and divestitures we anticipate may not occur or produce anticipated proceeds;
|
•
|
the anti-takeover effects of our rights plan could prevent a change of control;
|
•
|
increased exposure on our financial performance due to the degree we are leveraged;
|
•
|
replacing our natural gas reserves, which if not replaced, will cause our gas reserves and gas production to decline;
|
•
|
our ability to acquire water supplies needed for gas drilling, or our ability to dispose of water used or removed from strata
|
•
|
our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;
|
•
|
other factors discussed in our 2010 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.
|
ITEM 3.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
For the Three Months Ended
|
|
|
||||||||||||||||
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Total Year
|
||||||||||
2011 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Mcf
|
13,035,790
|
|
|
23,069,925
|
|
|
23,948,795
|
|
|
23,948,795
|
|
|
84,003,305
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
5.56
|
|
|
$
|
5.14
|
|
|
$
|
5.12
|
|
|
$
|
5.18
|
|
|
$
|
5.21
|
|
2012 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Mcf
|
19,108,632
|
|
|
19,108,632
|
|
|
19,318,617
|
|
|
19,318,617
|
|
|
76,854,498
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
5.25
|
|
|
$
|
5.25
|
|
|
$
|
5.25
|
|
|
$
|
5.25
|
|
|
$
|
5.25
|
|
2013 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Mcf
|
11,585,912
|
|
|
11,714,644
|
|
|
11,843,376
|
|
|
11,843,376
|
|
|
46,987,308
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
5.19
|
|
|
$
|
5.19
|
|
|
$
|
5.19
|
|
|
$
|
5.19
|
|
|
$
|
5.19
|
|
2014 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Mcf
|
9,921,990
|
|
|
10,032,234
|
|
|
10,142,478
|
|
|
10,142,478
|
|
|
40,239,180
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
5.34
|
|
|
$
|
5.34
|
|
|
$
|
5.34
|
|
|
$
|
5.34
|
|
|
$
|
5.34
|
|
ITEM 4.
|
CONTROLS AND PROCEDURES
|
ITEM 1.
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LEGAL PROCEEDINGS
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ITEM 1A.
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RISK FACTORS
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•
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variations in thickness of the layer, or seam, of coal;
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•
|
amounts of rock and other natural materials intruding into the coal seam and other geological conditions that could affect the stability of the roof and the side walls of the mine;
|
•
|
equipment failures or repairs;
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•
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fires, explosions or other accidents;
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•
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weather conditions; and
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•
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security breaches or terroristic acts.
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•
|
unexpected drilling conditions;
|
•
|
title problems;
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•
|
pressure or irregularities in geologic formations;
|
•
|
equipment failures or repairs;
|
•
|
fires, explosions or other accidents;
|
•
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adverse weather conditions;
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•
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reductions in natural gas prices;
|
•
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security breaches or terroristic acts;
|
•
|
pipeline ruptures;
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•
|
surface spillage of, or contamination of groundwater by, fracturing fluids used in hydraulic fracturing operations; and
|
•
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unavailability or high cost of drilling rigs, other field services and equipment.
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•
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uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of expansion and acquisition opportunities;
|
•
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the potential loss of key customers, management and employees of an acquired business;
|
•
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the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition opportunity;
|
•
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problems that could arise from the integration of the acquired business;
|
•
|
unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion of the acquisition opportunity; and
|
•
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we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.
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ITEM 5.
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OTHER INFORMATION
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Name of Mine or Mining Complex(1)(2)
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Mine Act
Section 104
Significant &
Substantial
Citations(3)
|
|
Mine Act
Section
104(b)
Orders(4)
|
|
Mine Act
Section
104(d)
Citations &
Orders(5)
|
|
Total Dollar
Value of
Proposed
MSHA
Assessments(6)
(in thousands)
|
|
Number of
Legal Actions
Pending Before
the Federal
Mine Safety and
Health Review
Commission(7)
|
||||||
Amvest - Fola Complex
|
19
|
|
|
—
|
|
|
—
|
|
|
$
|
20
|
|
|
16
|
|
Bailey
|
8
|
|
|
—
|
|
|
—
|
|
|
$
|
28
|
|
|
9
|
|
Blacksville #2
|
56
|
|
|
—
|
|
|
1
|
|
|
$
|
226
|
|
|
11
|
|
Buchanan
|
47
|
|
|
—
|
|
|
—
|
|
|
$
|
720
|
|
|
23
|
|
Enlow Fork
|
9
|
|
|
—
|
|
|
—
|
|
|
$
|
33
|
|
|
5
|
|
Loveridge
|
77
|
|
|
2
|
|
|
2
|
|
|
$
|
459
|
|
|
7
|
|
McElroy
|
83
|
|
|
—
|
|
|
4
|
|
|
$
|
436
|
|
|
16
|
|
Miller Creek Complex
|
34
|
|
|
—
|
|
|
—
|
|
|
$
|
30
|
|
|
4
|
|
Robinson Run
|
26
|
|
|
—
|
|
|
—
|
|
|
$
|
175
|
|
|
15
|
|
Shoemaker
|
72
|
|
|
—
|
|
|
—
|
|
|
$
|
172
|
|
|
9
|
|
Other (Keystone Plant)
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
(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 the table by mining complex rather than MSHA identification number because that is how we manage and operate our coal mining business.
|
(2)
|
We have not included currently closed or idled mines in the above table. Our closed and/or idled mines received one Mine Act section 104 Significant & Substantial citations in the three months ended
September 30, 2011
. Total proposed assessments were $102 in the three months ending
September 30, 2011
. There were 13 legal actions in total pending before the Federal Mine Safety and Health Review Commission as of September 30, 2011 for our closed and/or idle mines. These actions may have been initiated in prior quarters.
|
(3)
|
Mine Act section 104(a) significant and substantial citations are for alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to or will result in an injury or illness of a reasonably serious nature.
|
(4)
|
Mine Act section 104(b) orders are for alleged failure to totally abate the subject matter of a Mine Act section 104(a) citation within the period specified in the citation.
|
(5)
|
Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
|
(6)
|
Includes proposed MSHA assessments received during the three months ended
September 30, 2011
for all alleged violations. MSHA assessments are not necessarily made in the same period as the citation occurs.
|
(7)
|
Includes all legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for each of our mining complexes. These actions may have been initiated in prior quarters. All of the legal actions were initiated by us to contest citations, orders, or proposed assessments issued by MSHA, and if we are successful, may result in the reduction or dismissal of those citations, orders or assessments.
|
Name of Mine or Mining Complex(1)(2)
|
Mine Act
Section 104
Significant &
Substantial
Citations(3)
|
|
Mine Act
Section
104(b)
Orders(4)
|
|
Mine Act
Section
104(d)
Citations &
Orders(5)
|
|
Total Dollar
Value of
Proposed
MSHA
Assessments(6)
(in thousands)
|
|
Number of
Legal Actions
Pending Before
the Federal
Mine Safety and
Health Review
Commission(7)
|
||||||
Amvest - Fola Complex
|
50
|
|
|
—
|
|
|
1
|
|
|
$
|
83
|
|
|
16
|
|
Bailey
|
34
|
|
|
—
|
|
|
—
|
|
|
$
|
216
|
|
|
9
|
|
Blacksville #2
|
155
|
|
|
—
|
|
|
4
|
|
|
$
|
705
|
|
|
11
|
|
Buchanan
|
118
|
|
|
—
|
|
|
—
|
|
|
$
|
1,029
|
|
|
23
|
|
Enlow Fork
|
32
|
|
|
—
|
|
|
—
|
|
|
$
|
59
|
|
|
5
|
|
Loveridge
|
220
|
|
|
3
|
|
|
10
|
|
|
$
|
1,007
|
|
|
7
|
|
McElroy
|
232
|
|
|
—
|
|
|
7
|
|
|
$
|
871
|
|
|
16
|
|
Miller Creek Complex
|
88
|
|
|
—
|
|
|
—
|
|
|
$
|
72
|
|
|
4
|
|
Robinson Run
|
110
|
|
|
—
|
|
|
2
|
|
|
$
|
778
|
|
|
15
|
|
Shoemaker
|
178
|
|
|
—
|
|
|
2
|
|
|
$
|
517
|
|
|
9
|
|
Other (Keystone Plant)
|
1
|
|
|
—
|
|
|
—
|
|
|
$
|
5
|
|
|
—
|
|
(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 the table by mining complex rather than MSHA identification number because that is how we manage and operate our coal mining business.
|
(2)
|
We have not included currently closed or idled mines in the above table. Our closed and/or idled mines received six Mine Act section 104 Significant & Substantial citations in the nine months ended
September 30, 2011
. Total proposed assessments were $136 in the nine months ending
September 30, 2011
. There were 13 legal actions in total pending before the Federal Mine Safety and Health Review Commission as of September 30, 2011 for our closed and/or idle mines. These actions may have been initiated in prior quarters.
|
(3)
|
Mine Act section 104(a) significant and substantial citations are for alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to or will result in an injury or illness of a reasonably serious nature.
|
(4)
|
Mine Act section 104(b) orders are for alleged failure to totally abate the subject matter of a Mine Act section 104(a) citation within the period specified in the citation.
|
(5)
|
Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
|
(6)
|
Includes proposed MSHA assessments received during the nine months ended
September 30, 2011
for all alleged violations. MSHA assessments are not necessarily made in the same period as the citation occurs.
|
(7)
|
Includes all legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for each of our mining complexes. These actions may have been initiated in prior quarters. All of the legal actions were initiated by us to contest citations, orders, or proposed assessments issued by MSHA, and if we are successful, may result in the reduction or dismissal of those citations, orders or assessments.
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ITEM 6.
|
EXHIBITS
|
2.1
|
|
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Asset Acquisition Agreement dated August 17, 2011 between CNX Gas Company LLC and Noble Energy, Inc. (including Annex I (Definitions) thereto), incorporated by reference to Exhibit 2.1 to Form 8-K filed on August 18, 2011. Schedules and Exhibits to the Asset Acquisition Agreement identified in the Table of Contents to the Asset Acquisition Agreement are not being filed but will be furnished supplementally to the Securities and Exchange Commission upon request.
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2.2
|
|
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Joint Development Agreement by and among CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011. Schedules and Exhibits to the Joint Development Agreement identified in the Table of Contents to the Joint Development Agreement are not being filed but will be furnished supplementally to the Securities and Exchange Commission upon request.
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4.1
|
|
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Supplemental Indenture No. 3 dated as of August 24, 2011 to Indenture dated as of April 1, 2010 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.1 to Form 8-K filed on August 29, 2011.*
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4.2
|
|
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Supplemental Indenture No. 3 dated as of August 24, 2011 to Indenture dated as of April 1, 2010 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.250% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 to Form 8-K filed on August 29, 2011.
|
4.3
|
|
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Supplemental Indenture No. 1 dated as of August 24, 2011 to Indenture dated as of March 9, 2011 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 6.375% Senior Notes due 2021, incorporated by reference to Exhibit 4.3 to Form 8-K filed on August 29, 2011.
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10.2
|
|
|
Closing Agreement by and between CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011.
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10.3
|
|
|
Amendment to CONSOL Energy Inc. Supplemental Retirement Plan dated October 17, 2011.
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31.1
|
|
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Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
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31.2
|
|
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Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
32.1
|
|
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Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
32.2
|
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
101
|
|
|
Interactive Data File (Form 10-Q for the quarterly period ended September 30, 2011 furnished in XBRL)
|
|
CONSOL ENERGY INC.
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||
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|
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|
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By:
|
|
/
S
/ J. B
RETT
H
ARVEY
|
|
|
|
J. Brett Harvey
|
|
|
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Chairman of the Board and Chief Executive Officer
(Duly Authorized Officer and Principal Executive Officer)
|
|
|
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By:
|
|
/
S
/ W
ILLIAM
J. L
YONS
|
|
|
|
William J. Lyons
|
|
|
|
Chief Financial Officer and Executive Vice President
(Duly Authorized Officer and Principal Financial and
Accounting Officer)
|
1.1
|
Defined Terms......................................................................................................1
|
1.2
|
References and Rules of Construction.................................................................
1
|
ARTICLE II SCOPE; PARTICIPATING INTERESTS; OPERATIONS........................................
|
2
|
2.1
|
Scope...................................................................................................................
2
|
2.2
|
Participating Interests.......................................................................................... 2
|
2.3
|
Operations; Development Area........................................................................... 2
|
2.4
|
Operating Agreements......................................................................................... 3
|
2.5
|
Operator............................................................................................................... 5
|
2.6
|
Liability of Operator............................................................................................ 6
|
2.7
|
Rentals, Shut-in Well Payments and Royalties................................................... 7
|
2.8
|
Insurance............................................................................................................. 7
|
2.9
|
Reports................................................................................................................ 8
|
2.10
|
Marketing.......................................................................................................... 9
|
2.11
|
Development Services; Overhead Rates; and Marketing Fees......................... 13
|
2.12
|
Contracts; Use of Affiliates............................................................................... 13
|
2.13
|
Non-Solicitation................................................................................................ 14
|
2.14
|
Conflict of Interest Policy.................................................................................. 14
|
2.15
|
Secondment....................................................................................................... 14
|
3.1
|
Joint Development Committee.......................................................................... 14
|
3.2
|
Development Plan............................................................................................. 17
|
3.3
|
Annual Plan and Budgets.................................................................................. 18
|
3.4
|
AFEs.................................................................................................................. 22
|
3.5
|
Non-Consent Years............................................................................................ 22
|
ARTICLE IV TRANSFER RESTRICTIONS...............................................................................
|
24
|
4.1
|
Restrictions on Transfer..................................................................................... 24
|
4.2
|
Documentation for Transfers............................................................................. 25
|
4.3
|
Maintenance of Uniform Interest...................................................................... 26
|
4.4
|
Right of First Offer............................................................................................ 26
|
ARTICLE V AREA OF MUTUAL INTEREST............................................................................
|
27
|
5.1
|
Creation of Area of Mutual Interest.................................................................. 27
|
5.2
|
Acquisition of Fill-In Interests for Drilling Units in the Development Area.... 27
|
5.3
|
Acquisition of Option Interests in the Development Area................................ 28
|
5.4
|
Exceptions......................................................................................................... 29
|
ARTICLE VI TAXES....................................................................................................................
|
31
|
6.1
|
Tax Partnership.................................................................................................. 31
|
6.2
|
Tax Information................................................................................................. 31
|
6.3
|
Responsibility for Taxes.................................................................................... 31
|
ARTICLE VII CERTAIN PAYMENT OBLIGATIONS................................................................
|
32
|
7.1
|
Payment of Development Costs and Carried Costs.......................................... 32
|
7.2
|
Payment Procedures.......................................................................................... 32
|
7.3
|
Carried Costs Balance Payment........................................................................ 33
|
7.4
|
Post Closing Cash Payments............................................................................. 33
|
7.5
|
Certain Order of Payments................................................................................ 33
|
7.6
|
Total Cost Sharing Payments............................................................................ 34
|
ARTICLE VIII DEFAULTS..........................................................................................................
|
34
|
8.1
|
Defaults............................................................................................................. 34
|
8.2
|
Certain Automatic Remedies for a Default....................................................... 35
|
8.3
|
Certain Other Remedies for a Default............................................................... 36
|
8.4
|
Cumulative and Additional Remedies............................................................... 36
|
ARTICLE IX LAND AND GEOSCIENCE DATA; DISCLAIMERS..........................................
|
37
|
9.1
|
Land and Geoscience Data................................................................................ 37
|
9.2
|
Disclaimers........................................................................................................ 37
|
ARTICLE X TERM.......................................................................................................................
|
38
|
10.1
|
Termination....................................................................................................... 38
|
10.2
|
Effect of Termination........................................................................................ 38
|
ARTICLE XI MISCELLANEOUS...............................................................................................
|
38
|
11.1
|
Relationship of the Parties................................................................................. 38
|
11.2
|
Notices............................................................................................................... 39
|
11.3
|
Expenses............................................................................................................ 41
|
11.4
|
Waivers; Rights Cumulative.............................................................................. 41
|
11.5
|
Entire Agreement; Conflicts.............................................................................. 41
|
11.6
|
Amendment....................................................................................................... 42
|
11.7
|
Governing Law; Disputes.................................................................................. 42
|
11.8
|
Publicity.............................................................................................................43
|
11.9
|
Parties in Interest............................................................................................... 43
|
11.10
|
Successors and Permitted Assigns..................................................................... 43
|
11.11
|
Preparation of Agreement.................................................................................. 43
|
11.12
|
Severability........................................................................................................ 44
|
11.13
|
Counterparts...................................................................................................... 44
|
11.14
|
Excluded Assets................................................................................................. 44
|
Party
|
Participating Interest
|
CONSOL
|
50%
|
Noble
|
50%
|
(vi)
|
as requested by a Party, copies of current geological and geophysical maps, seismic sections and shot point location maps;
|
(ix)
|
copies of written notices provided by any Third Party regarding violations or potential violations of applicable Law (including any applicable health, safety or environmental Laws);
|
(xi)
|
as requested by a Party, copies of any material correspondence between such operator and any Governmental Authority;
|
(xii)
|
copies of all title opinions, including drill site title opinions and division order title opinions;
|
(i)
|
a forecast of the number of active rigs, the drilling days from spud to rig release including the expected time from rig release to first production, including estimates for stimulation/completion days and a forecast of all relevant capital and operational costs related to the foregoing;
|
(iii)
|
a forecast of future production in four categories: (A) wells already on stream, (B) wells stimulated but not on stream, (C) wells drilled but not stimulated, and (D) wells to be drilled (wells on stream shall be forecasted on an individual performance basis (individual decline analysis) and all other wells shall be forecasted on an area basis based on expected performance for the relevant locations (pro-forma curves)).
|
1.
|
McDowell Wells
. The wells in McDowell county, West Virginia, that are more particularly described on
Annex I
(the “
McDowell Wells
”) shall be deemed to be deleted from
Exhibit B
to the Acquisition Agreement and shall be deemed to be Excluded Assets for purposes of the Acquisition Agreement. Further, in respect of the McDowell Wells, the amount of the Producing Properties Cash Payment shall be reduced by the amount set forth on
Schedule I
.
|
2.
|
Adjustments to Closing Cash Payments
. The Parties agree that
Section 3.2(b)(vi)
of the Acquisition Agreement shall be replaced with the following:
|
3.
|
Additional Wells; Additional Well Costs
. The Parties acknowledge (a) that, in addition to the Wells listed on
Exhibit B
to the Acquisition Agreement, Noble will be acquiring an interest in certain additional wells that have been drilled and completed, such wells being set forth on
Annex II
, and wells that have been spudded but not completed (the “
Additional Wells
”) and (b) that CONSOL has incurred prior to the Effective Time and paid certain Property Expenses and other costs and expenses attributable to the interest that Noble is acquiring in such Additional Wells (the “
Additional Well Costs
”). The Parties hereby agree that, in respect of the Additional Wells and the Additional Well Costs, a new
Section 3.2(a)(vi)
shall be added to the Acquisition Agreement, which shall read as follows:
|
4.
|
Additional and Excluded Leases and Fee Interests
. The Leases listed on
Annex III-1
as “Additional Unscheduled Leases” (the “
Additional Unscheduled Leases
”) shall be deemed to be added to
Part 1
(Non-Producing Leases)
of
Exhibit A
to the Acquisition Agreement and
|
5.
|
Net Acres and Leases
. With respect to each of the Leases listed on
Annex IV
(the “
Revised Scheduled Leases
”), the Conveyed Interests may only contain the Net Acres set forth for such Lease on
Annex IV
(which is less than the Net Acres set forth for such Lease on
Exhibit A
and
Schedule 1.1
to the Acquisition Agreement). For purposes of Closing, CONSOL agrees to assume that each Revised Scheduled Lease contains only the Net Acres set forth for such Revised Scheduled Lease on
Annex IV
and, as a result of such assumption, the Parties agree that (a) Net Acres for each Revised Scheduled Lease as listed on
Exhibit A
and
Schedule 1.1
to the Acquisition Agreement shall be deemed to be replaced with the corresponding Net Acres set forth on
Annex IV
, (b) Allocated Value for each Revised Scheduled Lease as listed on
Schedule 1.1
to the Acquisition Agreement shall be deemed to be replaced with the corresponding Allocated Value set forth on
Annex IV
, and (c) the First Cash Payment, the Second Cash Payment, the Third Cash Payment and the Carried Cost Obligation shall each be decreased by the amounts set forth on
Schedule I
. Notwithstanding the foregoing, following the Closing and prior to the Title Defect Claim Date, if CONSOL is able to establish (either pursuant to the Parties mutual agreement or pursuant to the title dispute resolution procedures set forth in
Section 5.3(j)
of the Acquisition Agreement, which shall apply
mutatis mutandis
) that any Revised Scheduled Lease contains a greater number of Net Acres than the Net Acres set forth for such Revised Scheduled Lease on
Annex IV
, then with respect to any such Revised Schedule Lease, the Parties agree that, in lieu of treating such additional Net Acres as a Title Benefit under the terms of the Acquisition Agreement, the Parties will increase (a) the amount of each of the First Cash Payment, the Second Cash Payment, the Third Cash Payment by one-third of one-half of the Allocated Value associated with the additional Net Acres attributable to such Revised Scheduled Lease (provided that if Noble made any of the foregoing cash payments prior to the date that CONSOL is able to establish that any Revised Scheduled Lease contains a greater number of Net Acres than the Net Acres set forth for such Revised Scheduled Lease on
Annex IV
, then within 5 Business Days after such Net Acres amount is established Noble shall pay to the applicable Cost Reconciliation Account the amount it would have been required to pay in connection with the payment of such prior cash payment(s) if such greater Net Acres had been established prior to the date of such payments(s)) and (b) the Carried Cost Obligation by one-half of the Allocated Value associated with the additional Net Acres attributable to such Revised Scheduled Lease.
|
6.
|
Duplicate Leases
. With respect to each of the Leases listed on
Annex V
(the “
Duplicate Leases
”), the Parties agree that (a) each Duplicative Lease is reflected more than once on
Exhibit A
to the Acquisition Agreement, (b) all references on
Exhibit A
and
Schedule 1.1
to the Acquisition Agreement to the Duplicate Leases shall be deemed to be deleted and the
|
7.
|
Minimum Net Acres
. The Parties agree that, in respect of the Additional Unscheduled Leases, the Additional Production Leases, the Excluded Leases, the Duplicate Leases, the Revised Scheduled Leases, the Hard Consent Assets and the Preferential Purchase Right Assets,
Schedule 1.2
to the Acquisition Agreement shall be replaced
Schedule 1.2
attached hereto as
Annex VI
.
|
8.
|
Conveyed Interests
. The Parties agree that
Section 2.1(a)(i)
of the Acquisition Agreement shall be replaced with the following:
|
9.
|
Retained Interests
. The Parties agree that the definition of “Retained Interests” that is used in the Acquisition Agreement shall be replaced with the following definition:
|
10.
|
Additional Interests
. The term “Additional Interests” as defined in the Acquisition Agreement and the Development Agreement shall be deemed to exclude any Leases in the Development Area that have been acquired since April 29, 2011 by CONSOL from any of its Affiliates.
|
11.
|
Indemnity Provisions
. The Parties agree that
Section 13.12
of the Acquisition Agreement shall be removed from the Acquisition Agreement and given no force or effect.
|
12.
|
Well No. 015903
. The Parties acknowledge that the Lease referenced in
Exhibit B
to the Acquisition Agreement for Well No. 015903 (API # 3712927880) is “MAWC TR 25 BOWMAN #4” (and not “MAWC TR 7 BOWMAN #4”) and that such reference will be corrected in the Assignment that is executed at Closing.
|
13.
|
Environmental Defects
. The Parties acknowledge that Noble did not deliver an Environmental Defect Notice on or prior to the Environmental Defect Claim Date and, at Closing, no adjustments will be made to the Closing Cash Payment in respect of any alleged Environmental Defects.
|
14.
|
Pre-Closing Title Defects
. The Parties acknowledge that Noble did not deliver a Title Defect Notice on or prior to Closing and, at Closing, no adjustments will be made to the Closing Cash Payment in respect of any alleged Title Defects.
|
15.
|
Consent Schedule
. The following Consents shall be deemed to be added to
Schedule 7.4
of the Acquisition Agreement:
|
Lease Number / Reference
|
Agreement Name
|
Agreement Date
|
County
|
State
|
LW-1334
|
Lease
|
2/1/1935
|
Greene
|
PA
|
L208654
|
Oil and Gas Lease
|
10/22/2008
|
Westmoreland
|
PA
|
L210136
|
Paid-Up Lease
|
6/2/2010
|
Westmoreland
|
PA
|
Reference Number
|
Agreement Name
|
Parties
|
Agreement Date
|
County
|
State
|
|
Oil & Gas Sublease Agreement (as amended)
|
NiSource Energy Ventures, LLC, Columbia Gas Transmission, LLC and CONSOL
|
7/27/2009
|
Greene (PA), Washington (PA) and Marshall (WV)
|
PA
WV
|
Lease Number / Reference
|
Agreement Name
|
Agreement Date
|
County
|
State
|
3,032
|
Operating Agreement
|
6/19/2009
|
Washington
|
PA
|
316,374
|
Operating Agreement
|
8/3/1982
|
Upshur
|
WV
|
Lease Number / Reference
|
Agreement Name
|
Agreement Date
|
County
|
State
|
311,776
|
Farmout Agreement
|
7/14/2003
|
Braxton
|
WV
|
16.
|
Material Contracts Schedule
. The following Contracts shall be deemed to be added to
Schedule 7.8
of the Acquisition Agreement:
|
Reference Number
|
Agreement Name
|
Parties
|
Agreement Date
|
County
|
State
|
|
Oil & Gas Sublease Agreement (as amended)
|
NiSource Energy Ventures, LLC, Columbia Gas Transmission, LLC and CONSOL
|
7/27/2009
|
Greene (PA), Washington (PA) and Marshall (WV)
|
PA
WV
|
17.
|
Preferential Purchase Right Schedule
. The following Preferential Purchase Right shall be deemed to be removed from
Schedule 7.10
of the Acquisition Agreement:
|
Number / Reference
|
Agreement Name
|
Agreement Date
|
County
|
State
|
3,032
|
Operating Agreement
|
6/19/2009
|
Washington
|
PA
|
316,374
|
Operating Agreement
|
8/3/1982
|
Upshur
|
WV
|
Number / Reference
|
Agreement Name
|
Agreement Date
|
County
|
State
|
72,666
|
Deed
|
8/7/2008
|
Washington
|
PA
|
268,021
|
General Warranty Deed
|
2/24/1994
|
Washington
|
PA
|
623,235
|
Deed
|
4/9/1968
|
Marshall
|
WV
|
623,236
|
Deed
|
4/10/1968
|
Marshall
|
WV
|
623,237
|
Deed
|
8/3/1968
|
Marshall
|
WV
|
625,272
|
General Warranty Deed
|
11/17/2004
|
Marshall
|
WV
|
702,057
|
Deed
|
3/31/1951
|
Ohio
|
WV
|
Number / Reference
|
Agreement Name
|
Agreement Date
|
County
|
State
|
625,388
|
Option to Purchase
|
7/10/2008
|
Marshall
|
WV
|
Number / Reference
|
Agreement Name
|
Agreement Date
|
County
|
State
|
311,776
|
Farmout Agreement
|
7/14/2003
|
Braxton
|
WV
|
Number / Reference
|
Agreement Name
|
Agreement Date
|
County
|
State
|
OPAG094
|
Basic Agreement
|
4/1/1977
|
Allegheny, Bedford, Blair, Cambria, Centre, Clinton, Fayette, Greene, Somerset, Washington & Westmoreland
|
PA
|
18.
|
Hard/Soft Consents
.
CONSOL has not obtained those Consents set forth on
Annex VII
. The Consents listed on
Annex VII
that are marked with a “” in the column entitled “Hard Consent” are referred to herein as the “
Hard Consents
,
” and the remaining Consents listed on
Annex VII
are referred to herein as the “
Soft Consents.
”
|
19.
|
Preferential Purchase Rights
.
The Preferential Purchase Rights listed on
Annex VIII
have either (a) not been waived by the appropriate party and the period for exercising such Preferential Purchase Right has not lapsed (the “
Outstanding Preferential Purchase Rights
”) or (b) been exercised by the appropriate party (the “
Exercised Preferential Purchase Rights
”). The Exercised Preferential Purchase Rights are marked with a “” in the column entitled “Exercised” on
Annex VIII
.
|
20.
|
Sublease Agreement
. With respect to that certain Oil & Gas Sublease Agreement, dated July
|
21.
|
Gathering Contracts
. With respect to the Gathering Contracts, certain agreements of the Parties are set forth on
Schedule II
.
|
22.
|
Rights-of-Way
. The rights-of-way exhibit that is attached as
Exhibit C
to the Acquisition Agreement shall be replaced with the rights-of-way exhibits attached to the counterparts of the New Assignment
.
|
23.
|
Excluded Assets
. The Parties agree that the definition of “Excluded Assets” shall include all SCADA and similar control equipment and network communication towers and Federal Communication Commission licenses.
|
24.
|
Assignment and Bill of Sale
. At Closing, in lieu of executing the form of Assignment attached to the Acquisition Agreement, the Parties shall execute the form of Assignment and Bill of Sale and form of Mineral Interest Deed attached hereto as
Annex X-1
and
Annex X-2
(collectively, the “
New Assignment
”) and all references in the Acquisition Agreement to the “Assignment” shall hereafter be deemed to refer to the New Assignment.
|
25.
|
Development Agreement
. At Closing, in lieu of executing the form of Development Agreement (including Exhibits) attached to the Acquisition Agreement, the Parties shall execute the form of Development Agreement (including Exhibits) attached hereto as
Annex XI
(collectively, the “
New Development Agreement
”) and all references in the Acquisition Agreement to the “Development Agreement” shall hereafter be deemed to refer to the New Development Agreement.
|
26.
|
Development Plan and Annual Plan and Budget
. The Parties agree to, and to cause their representatives on the Joint Development Committee (as defined in the New Development Agreement) use their commercially reasonable efforts to mutually agree upon a more detailed Development Plan (as such term is defined in the New Development Agreement) and Annual Plan and Budget (as such term is defined in the New Development Agreement) for calendar year 2012, in each case, prior to December 15, 2011. If the Parties are able to reach such agreement, such agreed upon Development Plan and/or Annual Plan and Budget, as applicable, will replace the Development Plan attached to the New Development Agreement as
Exhibit E
and/or the Annual Plan and Budget attached to the New Development Agreement as
Exhibit F
, as applicable; provided that if the Parties are unable to reach such agreement, the Development Plan attached as of the date hereof to the New Development Agreement as
Exhibit E
and/or the Annual Plan and Budget attached as of the date hereof to the New Development Agreement as
Exhibit F
, as applicable, shall remain in effect.
|
27.
|
Tax Partnership Agreement
. With respect to the Tax Partnership Agreement, certain agreements of the Parties are set forth on
Schedule III
.
|
28.
|
NAESB Agreement
. At Closing, in lieu of executing the form of NAESB Agreement attached to the Acquisition Agreement, the Parties shall execute the form of NAESB Agreement attached hereto as
Annex XII
(the “
New NAESB Agreement
”) and all references in the Acquisition Agreement to the “NAESB Agreement” shall hereafter be deemed to refer to the New NAESB Agreement.
|
29.
|
Recordings
. The Parties agree that the Assignments and Bills of Sale (including any associated affidavits of tax value), Deeds and Mineral Interest Deeds being executed by the Parties, as a result of, inter alia, acreage additions or deletions, may include allocated tax values for the Conveyed Interests that are different than the Allocated Values attributable to such Conveyed Interests under the Acquisition Agreement and this Agreement. Accordingly, the Parties agree that they shall cooperate with each other prior to the recording of such Assignments and Bills of Sale, Deeds and Mineral Interest Deeds to ensure that the allocated tax values for the Conveyed Interests are consistent with the Allocated Values attributable to such Conveyed Interests under the Acquisition Agreement and this Agreement.
|
30.
|
Ratification
. The Parties hereby ratify and confirm the terms and provisions of the Acquisition Agreement, to the extent modified hereby, for all purposes.
|
|
CONSOL:
CNX GAS COMPANY LLC
By:
/s/ Stephen W. Johnson
Name: Stephen W. Johnson
Title: Vice President and Secretary
|
|
NOBLE:
NOBLE ENERGY, INC.
By:
/s/ Shawn E. Conner
Name: Shawn E. Conner
Title: Vice President
|
1.
|
I have reviewed this report on Form 10-Q of CONSOL Energy Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
October 31, 2011
|
|
|
|
|
/s/ J. Brett Harvey
|
|
|
J. Brett Harvey
|
|
|
Chairman of the Board and Chief Executive Officer
|
|
|
(Principal Executive Officer)
|
|
1.
|
I have reviewed this report on Form 10-Q of CONSOL Energy Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information;
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
October 31, 2011
|
|
|
|
|
/s/ William J. Lyons
|
|
|
William J. Lyons
|
|
|
Chief Financial Officer and Executive Vice President
(Principal Financial and Accounting Officer)
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.
|
Date:
|
October 31, 2011
|
|
|
|
|
/s/ J. Brett Harvey
|
|
|
J. Brett Harvey
|
|
|
Chairman of the Board and Chief Executive Officer
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.
|
Date:
|
October 31, 2011
|
|
|
|
|
/s/ William J. Lyons
|
|
|
William J. Lyons
|
|
|
Chief Financial Officer and Executive Vice President
|
|