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CNX Resources Corp - Quarter Report: 2014 September (Form 10-Q)





 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 __________________________________________________
FORM 10-Q
  __________________________________________________ 
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
For the quarterly period ended September 30, 2014
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number: 001-14901
  __________________________________________________
CONSOL Energy Inc.
(Exact name of registrant as specified in its charter)

Delaware
 
51-0337383
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
1000 CONSOL Energy Drive
Canonsburg, PA 15317-6506
(724) 485-4000
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 __________________________________________________ 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes  x    No  o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  x    No   o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  x    Accelerated filer  o    Non-accelerated filer  o    Smaller Reporting Company  o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  o    No  x
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class
 
Shares outstanding as of October 17, 2014
Common stock, $0.01 par value
 
230,179,532
 






TABLE OF CONTENTS

 
 
Page
PART I FINANCIAL INFORMATION
 
 
 
 
ITEM 1.
Condensed Financial Statements
 
 
Consolidated Statements of Income for the three and nine months ended September 30, 2014 and 2013.
 
Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2014 and 2013.
 
Consolidated Balance Sheets at September 30, 2014 and December 31, 2013.
 
 
Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013.
 
 
 
 
ITEM 2.
 
 
 
ITEM 3.
 
 
 
ITEM 4.
 
 
PART II OTHER INFORMATION
 
 
 
 
ITEM 1.
 
 
 
ITEM 4.
 
 
 
ITEM 6.


GLOSSARY OF CERTAIN OIL AND GAS MEASUREMENT TERMS

The following are abbreviations of certain measurement terms commonly used in the oil and gas industry and included within this Form 10-Q:

Bbl - One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf - One billion cubic feet of natural gas.
Bcfe - One billion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
Btu - One British thermal unit.
Mbbls - One thousand barrels of oil or other liquid hydrocarbons.
Mcf - One thousand cubic feet of natural gas.
Mcfe - One thousand cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
MMbtu - One million British Thermal units.
MMcfe - One million cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
NGL - Natural gas liquids.
Tcfe - One trillion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
Dth/d- Decatherms per day, with one decatherm being equivalent to one million British Thermal units.






PART I : FINANCIAL INFORMATION
 
ITEM 1.
CONDENSED FINANCIAL STATEMENTS

CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per share data)
Three Months Ended
 
Nine Months Ended
(Unaudited)
September 30,
 
September 30,
Revenues and Other Income:
2014
 
2013
 
2014
 
2013
Natural Gas, NGLs and Oil Sales
$
257,358

 
$
192,781

 
$
753,399

 
$
531,859

Coal Sales
483,960

 
479,311

 
1,554,939

 
1,532,280

Other Outside Sales
73,673

 
63,876

 
213,047

 
197,778

Gas Royalty Interests and Purchased Gas Sales
18,815

 
17,113

 
68,773

 
51,109

Freight-Outside Coal
2,497

 
9,579

 
22,551

 
31,492

Miscellaneous Other Income
40,784

 
20,822

 
165,815

 
77,729

Gain on Sale of Assets
7,529

 
19,863

 
12,615

 
52,208

Total Revenue and Other Income
884,616

 
803,345

 
2,791,139

 
2,474,455

Costs and Expenses:
 
 
 
 
 
 
 
Exploration and Production Costs
 
 
 
 
 
 
 
Lease Operating Expense
30,005

 
23,600

 
85,622

 
70,835

Transportation, Gathering and Compression
68,234

 
46,699

 
179,813

 
144,002

Production, Ad Valorem, and Other Fees
8,486

 
8,033

 
28,817

 
20,011

Direct Administrative and Selling
14,060

 
11,725

 
39,216

 
34,615

Depreciation, Depletion and Amortization
82,538

 
58,998

 
225,766

 
164,832

Exploration and Production Related Other Costs
8,042

 
22,771

 
15,765

 
43,666

Production Royalty Interests and Purchased Gas Costs
15,751

 
13,805

 
58,519

 
41,165

Other Corporate Expenses
13,700

 
26,289

 
60,876

 
74,239

General and Administrative
14,874

 
10,177

 
47,755

 
29,239

Total Exploration and Production Costs
255,690

 
222,097

 
742,149

 
622,604

Coal Costs
 
 
 
 
 
 
 
Operating and Other Costs
339,216

 
328,393

 
1,013,606

 
993,342

Royalties and Production Taxes
23,306

 
24,380

 
77,397

 
79,257

Direct Administrative and Selling
10,479

 
11,608

 
33,589

 
34,744

Depreciation, Depletion and Amortization
64,880

 
57,265

 
186,029

 
169,702

Freight Expense
2,497

 
9,579

 
22,551

 
31,492

General and Administrative Costs
10,434

 
8,607

 
33,397

 
27,946

Other Corporate Expenses
10,114

 
11,145

 
41,444

 
43,056

Total Coal Costs
460,926

 
450,977

 
1,408,013

 
1,379,539

Other Costs
 
 
 
 
 
 
 
Miscellaneous Operating Expense
92,974

 
75,439

 
266,601

 
272,346

General and Administrative Costs
425

 
376

 
1,259

 
1,269

Depreciation, Depletion and Amortization
1,247

 
1,467

 
3,885

 
4,303

Loss on Debt Extinguishment
20,990

 

 
95,267

 

Interest Expense
55,397

 
56,300

 
170,539

 
164,194

Total Other Costs
171,033

 
133,582

 
537,551

 
442,112

Total Costs And Expenses
887,649

 
806,656

 
2,687,713

 
2,444,255

(Loss) Earnings Before Income Tax
(3,033
)
 
(3,311
)
 
103,426

 
30,200

Income Taxes
(1,388
)
 
68,858

 
8,315

 
97,531

(Loss) Income From Continuing Operations
(1,645
)
 
(72,169
)
 
95,111

 
(67,331
)
Income (Loss) From Discontinued Operations, net

 
8,120

 
(5,687
)
 
(11,352
)
Net (Loss) Income
(1,645
)
 
(64,049
)
 
89,424

 
(78,683
)
Less: Net Loss Attributable to Noncontrolling Interests

 
(398
)
 

 
(942
)
Net (Loss) Income Attributable to CONSOL Energy Shareholders
$
(1,645
)
 
$
(63,651
)
 
$
89,424

 
$
(77,741
)
The accompanying notes are an integral part of these financial statements.


3






CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(CONTINUED)
 
Three Months Ended
 
Nine Months Ended
(Dollars in thousands, except per share data)
September 30,
 
September 30,
(Unaudited)
2014
 
2013
 
2014
 
2013
(Loss) Earnings Per Share
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
(Loss) Income from Continuing Operations
$
(0.01
)
 
$
(0.31
)
 
$
0.41

 
$
(0.29
)
Income (Loss) from Discontinued Operations

 
0.03

 
(0.02
)
 
(0.05
)
Total Basic (Loss) Earnings Per Share
$
(0.01
)
 
$
(0.28
)
 
$
0.39

 
$
(0.34
)
Dilutive
 
 
 
 
 
 
 
(Loss) Income from Continuing Operations
$
(0.01
)
 
$
(0.31
)
 
$
0.41

 
$
(0.29
)
Income (Loss) from Discontinued Operations

 
0.03

 
(0.02
)
 
(0.05
)
Total Dilutive (Loss) Earnings Per Share
$
(0.01
)
 
$
(0.28
)
 
$
0.39

 
$
(0.34
)
 
 
 
 
 
 
 
 
Dividends Paid Per Share
$
0.0625

 
$
0.125

 
$
0.1875

 
$
0.25


CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
Three Months Ended
 
Nine Months Ended
(Dollars in thousands)
September 30,
 
September 30,
(Unaudited)
2014
 
2013
 
2014
 
2013
Net (Loss) Income
$
(1,645
)
 
$
(64,049
)
 
$
89,424

 
$
(78,683
)
Other Comprehensive Income (Loss):
 
 
 
 
 
 
 
  Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($107,383), ($15,422), ($108,154), ($70,161))
184,154

 
24,980

 
185,475

 
113,641

  Net Increase (Decrease) in the Value of Cash Flow Hedges (Net of tax: ($25,722), ($8,536), $13,161, ($26,036))
39,151

 
13,246

 
(20,032
)
 
40,400

  Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: $12,084, $14,025, ($5,509), $36,551)
(19,510
)
 
(24,354
)
 
3,754

 
(56,595
)


 

 
 
 
 
Other Comprehensive Income
203,795

 
13,872

 
169,197

 
97,446



 

 
 
 
 
Comprehensive Income (Loss)
202,150

 
(50,177
)
 
258,621

 
18,763



 

 
 
 
 
Less: Comprehensive Loss Attributable to Noncontrolling Interest

 
(398
)
 

 
(942
)

 
 
 
 
 
 
 
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
$
202,150

 
$
(49,779
)
 
$
258,621

 
$
19,705





The accompanying notes are an integral part of these financial statements.



4







CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 
 
(Unaudited)
 
 
(Dollars in thousands)
September 30,
2014
 
December 31,
2013
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and Cash Equivalents
$
225,563

 
$
327,420

Accounts and Notes Receivable:
 
 

Trade
299,939

 
332,574

Notes Receivable

 
25,861

Other Receivables
382,652

 
243,973

Inventories
145,372

 
157,914

Deferred Income Taxes
127,731

 
211,303

Recoverable Income Taxes
41,971

 
10,705

Prepaid Expenses
101,867

 
135,842

Total Current Assets
1,325,095

 
1,445,592

Property, Plant and Equipment:
 
 
 
Property, Plant and Equipment
14,463,328

 
13,578,509

Less—Accumulated Depreciation, Depletion and Amortization
4,499,344

 
4,136,247

Total Property, Plant and Equipment—Net
9,963,984

 
9,442,262

Other Assets:
 
 
 
Investment in Affiliates
185,509

 
291,675

Notes Receivable

 
125

Other
244,347

 
214,013

Total Other Assets
429,856

 
505,813

TOTAL ASSETS
$
11,718,935

 
$
11,393,667






















The accompanying notes are an integral part of these financial statements.


5





CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

 
 
(Unaudited)
 
 
(Dollars in thousands, except per share data)
September 30,
2014
 
December 31,
2013
LIABILITIES AND EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts Payable
$
610,725

 
$
514,580

Current Portion of Long-Term Debt
12,225

 
11,455

Other Accrued Liabilities
610,704

 
565,697

Current Liabilities of Discontinued Operations
12,992

 
28,239

Total Current Liabilities
1,246,646

 
1,119,971

Long-Term Debt:
 
 
 
Long-Term Debt
3,236,172

 
3,115,963

Capital Lease Obligations
43,150

 
47,596

Total Long-Term Debt
3,279,322

 
3,163,559

Deferred Credits and Other Liabilities:
 
 
 
Deferred Income Taxes
395,025

 
242,643

Postretirement Benefits Other Than Pensions
652,050

 
961,127

Pneumoconiosis Benefits
111,514

 
111,971

Mine Closing
321,776

 
320,723

Gas Well Closing
180,520

 
175,603

Workers’ Compensation
73,398

 
71,468

Salary Retirement
48,231

 
48,252

Reclamation
34,499

 
40,706

Other
121,355

 
131,355

Total Deferred Credits and Other Liabilities
1,938,368

 
2,103,848

TOTAL LIABILITIES
6,464,336

 
6,387,378

Stockholders’ Equity:
 
 
 
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 230,177,923 Issued and Outstanding at September 30, 2014; 229,145,736 Issued and Outstanding at December 31, 2013
2,305

 
2,294

Capital in Excess of Par Value
2,412,976

 
2,364,592

Preferred Stock, 15,000,000 shares authorized, None issued and outstanding

 

Retained Earnings
2,995,238

 
2,964,520

Accumulated Other Comprehensive Loss
(155,920
)
 
(325,117
)
Total CONSOL Energy Inc. Stockholders’ Equity
5,254,599

 
5,006,289

TOTAL LIABILITIES AND EQUITY
$
11,718,935

 
$
11,393,667












The accompanying notes are an integral part of these financial statements.


6





CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

 
(Dollars in thousands, except per share data)
Common
Stock
 
Capital in
Excess
of Par
Value
 
Retained
Earnings
(Deficit)
 
Accumulated
Other
Comprehensive
(Loss) Income

 
Total CONSOL Energy Inc.
Stockholders’
Equity
December 31, 2013
$
2,294

 
$
2,364,592

 
$
2,964,520

 
$
(325,117
)
 
$
5,006,289

(Unaudited)
 
 
 
 
 
 
 
 
 
Net Income

 

 
89,424

 

 
89,424

Other Comprehensive Income

 

 

 
169,197

 
169,197

Comprehensive Income

 

 
89,424

 
169,197

 
258,621

Issuance of Common Stock
11

 
13,392

 

 

 
13,403

Treasury Stock Activity

 

 
(15,587
)
 

 
(15,587
)
Tax Benefit From Stock-Based Compensation

 
2,478

 

 

 
2,478

Amortization of Stock-Based Compensation Awards

 
32,514

 

 

 
32,514

Dividends ($0.1875 per share)

 

 
(43,119
)
 

 
(43,119
)
September 30, 2014
$
2,305

 
$
2,412,976

 
$
2,995,238

 
$
(155,920
)
 
$
5,254,599





























The accompanying notes are an integral part of these financial statements.


7





CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
Nine Months Ended
(Unaudited)
September 30,
Operating Activities:
2014
 
2013
Net Income (Loss)
$
89,424

 
$
(78,683
)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided By Continuing Operating Activities:

 

Net Loss from Discontinued Operations
5,687

 
11,352

Depreciation, Depletion and Amortization
415,680

 
338,837

Stock-Based Compensation
32,514

 
44,026

Gain on Sale of Assets
(12,615
)
 
(52,208
)
Loss on Debt Extinguishment
95,267

 

Deferred Income Taxes
6,540

 
(23,335
)
Equity in Earnings of Affiliates
(38,477
)
 
(20,276
)
Return on Equity Investments
47,424

 

Changes in Operating Assets:

 

Accounts and Notes Receivable
(64,241
)
 
11,145

Inventories
12,542

 
11,000

Prepaid Expenses
3,178

 
(8,688
)
Changes in Other Assets
(14,339
)
 
24,318

Changes in Operating Liabilities:

 

Accounts Payable
151,829

 
(18,487
)
Accrued Interest
32,698

 
50,184

Other Operating Liabilities
116,474

 
122,429

Other
(8,480
)
 
39,356

Net Cash Provided by Continuing Operations
871,105

 
450,970

Net Cash (Used in) Provided by Discontinued Operating Activities
(20,934
)
 
138,029

Net Cash Provided by Operating Activities
850,171

 
588,999

Cash Flows from Investing Activities:

 

Capital Expenditures
(1,174,607
)
 
(1,021,127
)
Change in Restricted Cash

 
56,410

Proceeds from Sales of Assets
141,136

 
464,638

Net Investments In Equity Affiliates
108,532

 
(18,112
)
Net Cash Used in Investing Activities in Continuing Operations
(924,939
)
 
(518,191
)
Net Cash Used in Investing Activities in Discontinued Operations

 
(41,246
)
Net Cash Used in Investing Activities
(924,939
)
 
(559,437
)
Cash Flows from Financing Activities:

 

(Payments on) Proceeds from Short-Term Borrowings
(11,736
)
 
47,000

Payments on Miscellaneous Borrowings
(4,169
)
 
(31,858
)
Proceeds from Long-Term Borrowings
1,859,920

 

Payments on Long-Term Borrowings
(1,843,866
)
 

Proceeds from Securitization Facility

 
6,518

Tax Benefit from Stock-Based Compensation
2,478

 
2,316

Dividends Paid
(43,119
)
 
(57,211
)
Issuance of Common Stock
13,403

 
2,698

Treasury Stock Activity

 
609

Net Cash Used in Financing Activities in Continuing Operations
(27,089
)
 
(29,928
)
Net Cash Used in Financing Activities in Discontinued Operations

 
(432
)
Net Cash Used in Financing Activities
(27,089
)
 
(30,360
)
Net Decrease in Cash and Cash Equivalents
(101,857
)
 
(798
)
Cash and Cash Equivalents at Beginning of Period
327,420

 
21,862

Cash and Cash Equivalents at End of Period
$
225,563

 
$
21,064

The accompanying notes are an integral part of these financial statements.


8





CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2014 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2013 has been derived from the Audited Consolidated Financial Statements at that date but does not include all the notes required by generally accepted accounting principles for complete financial statements. For further information, refer to the Consolidated Financial Statements and related notes for the year ended December 31, 2013 included in CONSOL Energy Inc.'s Form 10-K.

Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2013, with no effect on previously reported net income or stockholders' equity.

Basic earnings per share are computed by dividing net income (loss) attributable to shareholders by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similarly to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from stock options, performance stock options, CONSOL stock units, and restricted and performance share units, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options and performance share options were exercised, that outstanding restricted stock units, performance share units, and CONSOL stock units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. CONSOL Energy Inc. (CONSOL Energy or the Company) includes the impact of pro forma deferred tax assets in determining potential windfalls and shortfalls for purposes of calculating assumed proceeds under the treasury stock method. The table below sets forth the share-based awards that have been excluded from the computation of the diluted earnings per share because their effect would be anti-dilutive:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Anti-Dilutive Options
4,116,136
 
 
4,833,174
 
 
359,488
 
 
4,833,174
 
Anti-Dilutive Restricted Stock Units
1,278,078
 
 
1,243,207
 
 
 
 
1,243,207
 
Anti-Dilutive Performance Share Units
287,226
 
 
97,142
 
 
 
 
97,142
 
Anti-Dilutive Performance Share Options
802,804
 
 
602,101
 
 
 
 
602,101
 
 
6,484,244
 
 
6,775,624
 
 
359,488
 
 
6,775,624
 

The table below sets forth the share-based awards that have been exercised or released:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Options
7,456
 
 
11,655
 
 
655,568
 
 
256,768
 
Restricted Stock Units
6,034
 
 
130,523
 
 
396,836
 
 
698,664
 
Performance Share Units
 
 
 
 
378,971
 
 
159,228
 
 
13,490
 

142,178
 
 
1,431,375
 
 
1,114,660
 

The weighted average exercise price per share of the options exercised during the three months ended September 30, 2014 and 2013 was $22.75 and $17.40, respectively. The weighted average exercise price per share of the options exercised during the nine months ended September 30, 2014 and 2013 was $20.44 and $10.49, respectively.


9





The computations for basic and dilutive earnings per share are as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
(Loss) Income from Continuing Operations
$
(1,645
)
 
$
(72,169
)
 
$
95,111
 
 
$
(67,331
)
Income (Loss) from Discontinued Operations
 
 
8,120
 
 
(5,687
)
 
(11,352
)
 Less: Net Loss Attributable to Noncontrolling Interest
 
 
(398
)
 
 
 
(942
)
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders
$
(1,645
)
 
$
(63,651
)
 
$
89,424
 
 
$
(77,741
)
Weighted average shares of common stock outstanding:
 
 
 
 
 
 
 
Basic
230,174,256
 
 
228,876,336
 
 
229,922,936
 
 
228,640,671
 
Effect of stock-based compensation awards
 
 
 
 
1,479,976
 
 
 
Dilutive
230,174,256
 
 
228,876,336
 
 
231,402,912
 
 
228,640,671
 
Earnings per share:
 
 
 
 
 
 
 
Basic (Continuing Operations)
$
(0.01
)
 
$
(0.31
)
 
$
0.41
 
 
$
(0.29
)
Basic (Discontinued Operations)
 
 
0.03
 
 
(0.02
)
 
(0.05
)
Total Basic
$
(0.01
)
 
$
(0.28
)
 
$
0.39
 
 
$
(0.34
)
 
 
 
 
 
 
 
 
Dilutive (Continuing Operations)
$
(0.01
)
 
$
(0.31
)
 
$
0.41
 
 
$
(0.29
)
Dilutive (Discontinued Operations)
 
 
0.03
 
 
(0.02
)
 
(0.05
)
Total Dilutive
$
(0.01
)
 
$
(0.28
)
 
$
0.39
 
 
$
(0.34
)
Changes in Accumulated Other Comprehensive Income / (Loss) by component, net of tax, were as follows:
 
Gains and Losses on Cash Flow Hedges
 
Postretirement Benefits
 
Total
Balance at December 31, 2013
$
42,493
 
 
$
(367,610
)
 
$
(325,117
)
Other comprehensive (loss) income before reclassifications
(20,032
)
 
176,385
 
 
156,353
 
Amounts reclassified from accumulated other comprehensive income
3,754
 
 
9,090
 
 
12,844
 
Current period other comprehensive (loss) income
(16,278
)
 
185,475
 
 
169,197
 
Balance at September 30, 2014
$
26,215
 
 
$
(182,135
)
 
$
(155,920
)

The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Derivative Instruments (Note 13)
 
 
 
 
 
 
 
Natural gas price swaps and options
$
(31,594
)
 
$
(38,379
)
 
$
9,263
 
 
$
(93,146
)
Tax benefit (expense)
12,084
 
 
14,025
 
 
(5,509
)
 
36,551
 
Net of tax
$
(19,510
)
 
$
(24,354
)
 
$
3,754
 
 
$
(56,595
)
Actuarially Determined Long-Term Liability Adjustments*(Note 4 and Note 5)
 
 
 
 
 
 
 
Amortization of prior service costs
$
(2,542
)
 
$
(8,212
)
 
$
(7,625
)
 
$
(24,635
)
Recognized net actuarial loss
11,198
 
 
21,055
 
 
32,705
 
 
69,802
 
Curtailment gains
(36,182
)
 
 
 
(36,182
)
 
 
Settlement loss
4,785
 
 
6,296
 
 
25,492
 
 
38,498
 
Total
(22,741
)
 
19,139
 
 
14,390
 
 
83,665
 
Tax benefit (expense)
8,376
 
 
(7,306
)
 
(5,300
)
 
(31,936
)
Net of tax
$
(14,365
)
 
$
11,833
 
 
$
9,090
 
 
$
51,729
 


10





 


NOTE 2—ACQUISITIONS AND DISPOSITIONS:

In March 2014, CONSOL Energy completed a sale-leaseback of longwall shields for the Harvey Mine. Cash proceeds from the sale offset the basis of $75,357; therefore, no gain or loss was recognized on the sale. The lease has been accounted for as an operating lease. The lease term is five years. 

In December 2013, CONSOL Energy completed the sale of its Consolidation Coal Company (CCC) subsidiary, which includes all five of its longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy). CONSOL Energy retained overriding royalty interests in certain reserves sold in the transaction. Murray Energy also assumed $2,050,656 of CONSOL Energy's employee benefit obligations valued as of December 5, 2013 and its UMWA 1974 Pension Trust obligations. Murray Energy is primarily liable for all 1993 Coal Act liabilities. Cash proceeds of $825,285 were received related to this transaction, which were net of $24,715 in transaction fees. Proceeds are subject to adjustments related to working capital. A pre-tax gain of $1,035,346 was included in Income from Discontinued Operations on the Consolidated Statement of Income. In the first quarter of 2014, there was a pre-tax reduction in gain on sale of $7,044 related to the estimated working capital adjustment and various other miscellaneous items. Final settlement of working capital adjustments are currently being evaluated and are not expected to be material. For all periods presented in the accompanying Consolidated Statements of Income, the sale of CCC was classified as discontinued operations. There were no other active businesses classified as discontinued operations in the presented periods.

In December 2013, CONSOL Energy acquired the gas drilling rights to approximately 90,000 contiguous acres from Dominion Transmission, a unit of Dominion Resources. The acreage, which is associated with Dominion’s Fink-Kennedy, Lost Creek, and Racket Newberne gas storage fields in West Virginia, lies in the northern portion of Lewis County and the southern portion of Harrison County. CONSOL Energy anticipates that over one-half of the acres will have wet gas. CONSOL Energy has acquired the gas rights to both the Marcellus Shale and the Upper Devonian formations in the storage fields. Consideration of up to $190,000 will be paid by CONSOL Energy in two installments: 50% was paid at closing and the balance is due over time as the acres are drilled. In addition, CONSOL Energy will pay an overriding royalty to Dominion Resources based on a sliding scale. With respect to production from this area, CONSOL Energy has committed to be an anchor shipper on Dominion’s transmission system for 250,000 Dth/d with a primary term of 15 years. CONSOL Energy paid $91,243 in 2013 related to this transaction. In the nine months ended September 30, 2014, CONSOL Energy made an additional bonus payment of $16,000 to Dominion Transmission. Noble Energy, our joint venture partner, acquired 50% of the acres and reimbursed CONSOL Energy in 2014. Cash proceeds received from Noble Energy were $46,311 in the nine months ended September 30, 2014.

In August 2013, CONSOL Energy completed the sale of its 50% interest in the CONSOL Energy/Devon Energy joint venture in Alberta, Canada. The properties and coal leases included were those related to Grassy Mountain, Bellevue, Adanac, and Lynx Creek (Crowsnest Pass). Cash proceeds for the sale were $24,764. A gain of $15,260 was included in Other Income in the Consolidated Statement of Income.

In June 2013, CONSOL Energy completed the sale of Potomac coal reserves in Grant and Tucker Counties in West Virginia. Cash proceeds for the sale were $25,000. A gain of $24,663 was included in Other Income in the Consolidated Statement of Income.    

In April 2013, the Company and the Commonwealth of Pennsylvania (Commonwealth) entered into a Settlement Agreement and Release Settlement settling all of the Commonwealth's claims regarding the Ryerson Park Dam (Dam) and the Ryerson Park Lake (Lake). The Settlement provided in part for the payment to the Commonwealth of $36,000 for use to rebuild the Dam and restore the Lake with $13,728 of the settlement amount credited to lease bonus and royalty payments on the Commonwealth's Marcellus gas interests within the Park, subject to the Company's agreement to extract the gas from surface facilities located outside of the boundaries of the Park. The Settlement also provided in part for the conveyance by the Company to the Commonwealth of eight surface parcels (Parcels) containing approximately 506 acres of land adjoining the Park after the Parcels are no longer needed for the Company's operations and the conveyance by the Commonwealth to the Company of certain coal and mining rights in an area of the Bailey Mine where a mining permit application has been approved but with special conditions that will need further approval.

In March 2013, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed negotiations with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for the lease of the oil and gas rights on approximately 9.3 thousand acres. A majority of these


11





contiguous acres are in the liquids area of the Marcellus Shale play. CNX Gas Company paid $46,315 as an up-front bonus payment at closing. Approximately 7.6% of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title. CNX Gas Company has an obligation to spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and CNX Gas Company foregoes the bonus. Our joint venture partner, Noble Energy, acquired a 50% undivided interest in the acreage and has reimbursed CNX Gas Company for 50% of the associated acquisition costs during the year ended December 31, 2013.
 
In January 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Bailey Mine. Cash proceeds for the sale were $71,166. A loss of $358 was recognized due to transaction fees and is included in Other Income in the Consolidated Statement of Income. The lease has been accounted for as an operating lease. The lease term is five years.

NOTE 3—OTHER INCOME:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
Equity in Earnings of Affiliates
$
18,284

 
$
3,610

 
$
39,796

 
$
20,276

Rental Income
9,731

 
770

 
35,336

 
2,654

Coal Contract Settlement

 

 
30,000

 

Gathering Revenue
3,636

 
766

 
24,386

 
5,863

Royalty Income
5,003

 
4,113

 
14,758

 
12,870

Right of Way Issuance
2,485

 
2,102

 
4,898

 
3,810

Bailey Belt Settlement

 

 
4,275

 

Interest Income
527

 
4,300

 
1,827

 
15,701

Business Interruption Insurance

 
2,745

 

 
5,445

Other
1,118

 
2,416

 
10,539

 
11,110

Total Other Income
$
40,784

 
$
20,822

 
$
165,815

 
$
77,729


NOTE 4—COMPONENTS OF PENSION AND OTHER POST-EMPLOYMENT BENEFIT (OPEB) PLANS NET PERIODIC BENEFIT COSTS:

Components of net periodic costs (benefits) for the three and nine months ended September 30 are as follows:
 
Pension Benefits
 
Other Post-Employment Benefits
 
Three Months Ended
 
Nine Months Ended
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
Service cost
$
4,834

 
$
4,897

 
$
13,625

 
$
16,184

 
$
2,331

 
$
4,849

 
$
6,994

 
$
14,547

Interest cost
8,667

 
9,497

 
26,812

 
27,249

 
12,096

 
29,619

 
36,290

 
88,856

Expected return on plan assets
(12,829
)
 
(13,336
)
 
(38,342
)
 
(38,191
)
 

 

 

 

Amortization of prior service credits
(346
)
 
(408
)
 
(1,038
)
 
(1,223
)
 
(2,196
)
 
(7,804
)
 
(6,588
)
 
(23,411
)
Recognized net actuarial loss
6,444

 
8,042

 
18,441

 
30,764

 
6,369

 
17,595

 
19,106

 
52,784

Settlement loss
4,785

 
6,296

 
25,492

 
38,498

 

 

 

 

Curtailment gain
(549
)
 

 
(549
)
 

 
(35,633
)
 

 
(35,633
)
 

Net periodic cost (benefit)
$
11,006

 
$
14,988

 
$
44,441

 
$
73,281

 
$
(17,033
)
 
$
44,259

 
$
20,169

 
$
132,776


Expenses attributable to discontinued operations included in net periodic cost above were $1,699 and $7,078 for the three and nine months ended September 30, 2013, respectively, for the Pension Plans; and were $25,775 and $76,673 for the three and nine months ended September 30, 2013, respectively, for the Other Post-Employment Benefit Plan.

For the nine months ended September 30, 2014, $25,948 was paid to the pension trust from operating cash flows. Additional contributions to the pension trust are not expected to be significant for the remainder of 2014. Net periodic benefit


12





costs are allocated to Exploration and Production Costs, Direct Administrative and Selling Expenses and Coal Costs, Operating and Other Costs in the Consolidated Statements of Income.

On September 30, 2014, the qualified pension plan was remeasured to reflect an announced plan amendment that will reduce future accruals of pension benefits as of January 1, 2015. The plan amendment calls for a hard freeze of the defined benefit pension plan on January 1, 2015 for employees who are under age 40 or have less than 10 years of service as of September 30, 2014. Beginning January 1, 2015, the Company will contribute an additional 3% of eligible compensation into the 401(k) plan accounts for these affected employees. Employees who are age 40 or over and have at least 10 years of service will continue in the defined benefit pension plan unchanged. The modifications to the pension plan resulted in a $21,624 reduction in the pension liability with a corresponding adjustment of $13,659 in Other Comprehensive Income, net of $7,965 in deferred taxes. Additionally, a curtailment gain of $549 was recognized with a corresponding adjustment of $347 in Other Comprehensive Income, net of $202 in deferred taxes. The change was made to align our compensation package more closely with our peer group.

According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lump sum distributions made during a plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the three and nine months ended September 30, 2014. Accordingly, CONSOL Energy recognized settlement expense of $4,785 and $25,492 for the three and nine months ended September 30, 2014 in Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. The settlement charges represented a pro rata portion of the net unrecognized loss based on the percentage reduction in the projected benefit obligation due to the lump sum payments. The settlement accounting was initially triggered in May 2014, resulting in a remeasurement at May 31. Additional lump sum distributions during June and September 2014 resulted in remeasurements at June 30, 2014 and September 30, 2014. The September 30, 2014 remeasurement used a discount rate of 4.33%, an increase from 4.26% used at June 30, 2014. The September remeasurement increased the pension liability by $13,152. The September settlement and corresponding remeasurement of the pension plan resulted in a decrease of $5,285 in Other Comprehensive Income, net of $3,082 in deferred taxes. The May 31 and June 30, 2014 remeasurements used a discount rate of 4.26%, a decrease from 4.87% used at December 31, 2013. The May remeasurement increased the pension liability by $41,527. The May settlement and corresponding remeasurement of the pension plan resulted in a decrease of $14,193 in Other Comprehensive Income, net of $8,276 in deferred taxes. The June remeasurement decreased the pension liability by $6,490. The June settlement and corresponding remeasurement of the pension plan resulted in an increase of $5,141 in Other Comprehensive Income, net of $2,998 in deferred taxes. If CONSOL Energy incurs additional lump sum distributions from the plan in the fourth quarter of 2014, additional settlement charges will be recorded.

Lump sum payments also exceeded the settlement threshold during the three and nine months ended September 30, 2013. Accordingly, CONSOL Energy recognized settlement expense of $6,296 and $38,498 for the three and nine months ended September 30, 2013, respectively, in Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. The settlement charges represented a pro rata portion of the net unrecognized loss based on the percentage reduction in the projected benefit obligation due to the lump sum payments. The 2013 settlement charges also resulted in a remeasurement of the pension plan at September 30, June 30 and March 31, 2013. The September 30, 2013 remeasurement resulted in a change to the discount rate to 4.80% from 4.84% at June 30, 2013. The September remeasurement reduced the pension liability by $21,264. The September settlement and corresponding remeasurement of the pension plan resulted in an increase of $17,040 in Other Comprehensive Income, net of $10,520 in deferred taxes. The June 30, 2013 remeasurement resulted in a change to the discount rate to 4.84% from 4.12% at March 31, 2013. The June remeasurement reduced the pension liability by $48,957. The June settlement and corresponding remeasurement of the pension plan resulted in an increase of $33,414 in Other Comprehensive Income, net of $20,630 in deferred taxes. The March 31, 2013 remeasurement resulted in a change to the discount rate to 4.12% from 4.00% at December 31, 2012. The March remeasurement reduced the pension liability by $29,916. The March settlement and corresponding remeasurement of the pension plan resulted in an increase of $35,261 in Other Comprehensive Income, net of $21,770 in deferred taxes.

On September 30, 2014, the salaried OPEB plan and Production and Maintenance (P&M) OPEB plan were remeasured to reflect an announced plan amendment that will reduce retiree medical and life insurance benefits as of September 30, 2014. Effective September 30, 2014, no retiree medical or life benefits will be provided to active employees. Retirees as of September 30, 2014 will continue in the OPEB plans, which are currently anticipated to remain unchanged through December 31, 2019, and coverage thereafter will be eliminated. The Company elected to make cash transition payments totaling approximately $46,282 to the active employees whose retiree medical and life benefits were eliminated by the changes to the OPEB plan. These cash payments are not considered to be post-retirement benefits, and as such, they are not included in the actuarial calculations related to the OPEB plans. The amendment to the OPEB plan resulted in a $315,439 reduction in the OPEB liability with a corresponding adjustment of $199,252 in Other Comprehensive Income, net of $116,187 in deferred taxes. A


13





curtailment gain of $35,633 was recognized in September 2014 with a corresponding adjustment of $22,508 in Other Comprehensive Income, net of $13,125 in deferred taxes. The amendment resulted in a remeasurement of the OPEB plan at September 30, 2014. The remeasurement resulted in a change to the discount rate to 1.92% for the P&M OPEB plan and 1.84% for the Salaried OPEB plan from 4.88% used at December 31, 2013. The remeasurement increased the OPEB liability by $9,634 with a corresponding decrease of $6,086 in Other Comprehensive Income, net of $3,548 in deferred taxes. The change was made to align our compensation package more closely with our peer group.

CONSOL Energy does not expect to contribute to the other post-employment benefits plan in 2014. We intend to pay benefit claims as they become due. For the nine months ended September 30, 2014, $46,272 of other post-employment benefits have been paid.

NOTE 5—COMPONENTS OF COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION NET PERIODIC BENEFIT COSTS:
Components of net periodic costs (benefits) for the three and nine months ended September 30 are as follows:
 
 
CWP
 
Workers' Compensation
 
Three Months Ended
 
Nine Months Ended
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
Service cost
$
1,419

 
$
2,135

 
$
4,255

 
$
6,405

 
$
2,446

 
$
3,533

 
$
7,336

 
$
10,599

Interest cost
1,384

 
1,808

 
4,153

 
5,424

 
894

 
1,655

 
2,683

 
4,966

Amortization of actuarial gain
(1,549
)
 
(4,213
)
 
(4,647
)
 
(12,638
)
 
(96
)
 
(699
)
 
(287
)
 
(2,098
)
State administrative fees and insurance bond premiums

 

 

 

 
999

 
1,496

 
3,039

 
4,500

Legal and administrative costs

 

 

 

 

 
591

 

 
1,773

Net periodic cost (benefit)
$
1,254

 
$
(270
)
 
$
3,761

 
$
(809
)
 
$
4,243

 
$
6,576

 
$
12,771

 
$
19,740


Expenses (income) attributable to discontinued operations included in the net periodic cost (benefit) above were ($167) and ($497) for the three and nine months ended September 30, 2013, respectively, for CWP; and were $2,474 and $7,327 for the three and nine months ended September 30, 2013, respectively, for Workers' Compensation.
CONSOL Energy does not expect to contribute to the CWP plan in 2014. We intend to pay benefit claims as they become due. For the nine months ended September 30, 2014, $8,870 of CWP benefit claims have been paid.
CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2014. We intend to pay benefit claims as they become due. For the nine months ended September 30, 2014, $11,327 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 6—INCOME TAXES:

The effective tax rate on continuing operations for the nine months ended September 30, 2014 and 2013 was 8.3% and 323.0%, respectively.

The effective tax rate for the nine months ended September 30, 2014 differs from the U.S. federal statutory rate of 35% primarily due to a $20,640 income tax benefit for excess depletion, $8,820 discrete income tax benefit related to the completion of the Internal Revenue Service audit of tax years 2008 and 2009, and $7,013 discrete income tax benefit as a result of changes in estimates of excess percentage depletion and Domestic Production Activities Deduction related to the prior-year tax provision.

For the nine months ended September 30, 2014, CONSOL Energy recognized certain tax benefits as a result of changes in estimates related to a prior-year tax provision. The tax benefit of $7,970 related to increased percentage depletion deductions offset by $957 of tax expense related to changes in the Domestic Production Activities Deduction and changes in various other estimates.



14





The rate for the nine months ended September 30, 2013 differs from the U.S. federal statutory rate of 35% primarily due to a $111,104 income tax benefit for excess depletion, $4,701 discrete income tax charge related to the gain on sale of the Potomac coal reserves, $8,467 discrete income tax charge related to the gain on sale of the Crowsnest Pass coal reserves, a $1,585 income tax benefit due to a refund claim related to prior year Commonwealth of Pennsylvania taxes, and a $5,875 discrete income tax charge as a result of changes in estimates of excess percentage depletion and Domestic Production Activities Deduction related to the prior-year tax provision.

The total amounts of uncertain tax positions at September 30, 2014 and December 31, 2013 were $2,540 and $22,770, respectively. If these uncertain tax positions were recognized, approximately $1,651 and $2,071, respectively, would affect CONSOL Energy’s effective tax rate. There were no additions to the liability for unrecognized tax benefits during the nine months ended September 30, 2014. The reduction in uncertain tax positions was due to the completion of the Internal Revenue Service audit of the 2008 and 2009 tax years.
CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of September 30, 2014 and December 31, 2013, the Company reported an accrued interest liability relating to uncertain tax positions of $1,334 and $6,200, respectively. The accrued interest liability includes $4,866 of interest income and $1,020 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the nine months ended September 30, 2014 and 2013, respectively.
CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of September 30, 2014 and December 31, 2013, CONSOL Energy had no accrued liability for tax penalties.
CONSOL Energy and its subsidiaries file federal income tax returns with the United States and returns within various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to United States federal, state, local, or non-U.S. income tax examinations by tax authorities for the years before 2010. The Internal Revenue Service has issued its audit report related to the examination of CONSOL Energy’s 2008 and 2009 U.S. income tax returns during the nine months ended September 30, 2014. As a result of these findings, CONSOL Energy paid federal income tax deficiencies of $4,464 and $1,001, respectively. The deficiencies were the result of changes in the timing of certain tax deductions. The changes in timing of these tax deductions increased the tax benefit of percentage depletion by $2,925 and $4,493 in tax years 2008 and 2009, respectively. The Company also recognized additional tax benefits of $1,402 primarily related to an increase in the Domestic Production Activities Deduction for the audited periods. Also, as a result of closing the IRS audit, CONSOL Energy was required to file amended state income tax returns for the changes. In the nine months ended September 30, 2014, the Company filed the required amended returns and realized a discrete state income tax charge of $5,496 which was offset by a federal income tax benefit of $1,924.

NOTE 7—INVENTORIES:

Inventory components consist of the following:
 
September 30,
2014
 
December 31,
2013
Coal
$
24,380

 
$
31,944

Merchandise for resale
35,836

 
38,263

Supplies
85,156

 
87,707

Total Inventories
$
145,372

 
$
157,914


Inventories are stated at the lower of cost or market. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead, depreciation, depletion and amortization, and other related costs.

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $19,835 and $18,836 at September 30, 2014 and December 31, 2013, respectively.



15





NOTE 8—ACCOUNTS RECEIVABLE SECURITIZATION:
CONSOL Energy and certain of our U.S. subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The facility allows CONSOL Energy to receive on a revolving basis up to $125,000. The facility also allows for the issuance of letters of credit against the $125,000 capacity. At September 30, 2014, there were letters of credit outstanding against the facility of $61,930. CONSOL Energy management believes that these letters of credit will expire without being funded, and therefore the commitments will not have a material adverse effect on the Company's financial condition. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements.
CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, buys and sells eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocably and without recourse, sell all of their eligible trade accounts receivable to CNX Funding Corporation, which in turn sells these receivables to financial institutions and their affiliates, while maintaining a subordinated interest in a portion of the pool of trade receivables. This retained interest, which is included in Accounts and Notes Receivable Trade in the Consolidated Balance Sheets, is recorded at fair value. Due to a short average collection cycle for such receivables, our collection experience history and the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable. CONSOL Energy will continue to service the sold trade receivables for the financial institutions for a fee based upon market rates for similar services.
In accordance with the Transfers and Servicing Topics of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, CONSOL Energy records transactions under the securitization facility as secured borrowings on the Consolidated Balance Sheets. The pledge of collateral is reported as Accounts Receivable - Securitized and the borrowings are classified as debt in Borrowings under Securitization Facility.
The cost of funds under this facility is based upon commercial paper rates or LIBOR, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $692 and $1,328 for the nine months ended September 30, 2014 and 2013, respectively. These costs have been recorded as financing fees which are included in the Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in March 2015.
At September 30, 2014 and December 31, 2013, eligible accounts receivable totaled $82,500 and $115,000, respectively. There was $20,570 subordinated retained interest at September 30, 2014 and $48,945 subordinated retained interest at December 31, 2013. There were no borrowings under the Securitization Facility as of September 30, 2014 and December 31, 2013. The accounts receivable securitization program had no change in the nine months ended September 30, 2014. In accordance with the facility agreement, the Company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.



16





NOTE 9—PROPERTY, PLANT AND EQUIPMENT:
 
September 30,
2014
 
December 31,
2013
Coal and Other Plant and Equipment
$
3,731,618

 
$
3,681,051

Intangible Drilling Cost
2,388,790

 
1,937,336

Proven Gas Properties
1,684,675

 
1,670,404

Unproven Gas Properties
1,510,307

 
1,463,406

Coal Properties and Surface Lands
1,411,574

 
1,409,408

Gas Gathering Equipment
1,082,355

 
1,058,008

Gas Wells and Related Equipment
850,771

 
688,548

Airshafts
453,689

 
397,466

Mine Development
416,733

 
354,607

Coal Advance Mining Royalties
397,015

 
381,348

Leased Coal Lands
388,033

 
388,020

Other Gas Assets
125,484

 
126,239

Gas Advance Royalties
22,284

 
22,668

Total Property Plant and Equipment
14,463,328

 
13,578,509

Less: Accumulated Depreciation, Depletion, and Amortization
4,499,344

 
4,136,247

Total Net Property, Plant, and Equipment
$
9,963,984

 
$
9,442,262

    
Industry Participation Agreements

CONSOL Energy has two significant industry participation agreements (referred to as "joint ventures" or "JVs") that provided drilling and completion carries for our retained interests.

CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, is party to a joint development agreement with Hess Ohio Developments, LLC (Hess) with respect to approximately 144 thousand net Utica Shale acres in Ohio in which each party has a 50% undivided interest. Under the agreement, as amended, Hess is obligated to pay a total of approximately $335,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. As of September 30, 2014, Hess’ remaining carry obligation is $132,736.  

CNX Gas Company is party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 703 thousand net Marcellus Shale oil and gas acres in West Virginia and Pennsylvania, in which each party owns a 50% undivided interest. Under the agreement, as amended, Noble Energy is obligated to pay a total of approximately $1,884,000 in the form of a one-third drilling carry of certain of CONSOL Energy’s working interest obligations as the property is developed, subject to certain limitations. These limitations include the suspension of the carry if average Henry Hub natural gas prices are below $4.00 per million British thermal units (MMbtu) for three consecutive months. The carry has been in effect since March 1, 2014, and will remain effective until average natural gas prices are below $4.00/MMbtu for three consecutive months. Restrictions also include a $400,000 annual maximum on Noble Energy's carried cost obligation. As of September 30, 2014, Noble Energy’s remaining carry obligation is $1,728,520.

NOTE 10—SHORT-TERM NOTES PAYABLE:
CONSOL Energy entered into a new Amended and Restated Credit Agreement dated June 18, 2014 for a $2,000,000 senior secured revolving credit facility which expires on June 18, 2019. The new senior secured revolving credit facility replaced CONSOL Energy's existing $1,000,000 senior secured revolving credit facility which had been entered into as of April 12, 2011 and was amended and restated on December 5, 2013, and the existing $1,000,000 senior secured revolving credit facility of CNX Gas Corporation (CNX Gas) and its subsidiaries that had been entered into as of April 12, 2011. The new senior secured revolving credit facility resulted in the acceleration of previously deferred financing charges of $2,989 during the nine months ended September 30, 2014. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $2,000,000 of borrowings, which includes $750,000 in letters of credit aggregate sub-limit. CONSOL Energy can request an additional $500,000 increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan value of CONSOL Energy's proved gas reserves. The facility includes a minimum interest coverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The interest coverage ratio was 5.26 to 1.00 at


17





September 30, 2014. The facility includes a minimum current ratio covenant of no less than 1.00 to 1.00, measured quarterly. The minimum current ratio was 2.33 to 1.00 at September 30, 2014. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. The credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems. The facility permits CONSOL Energy to separate its gas and coal businesses if the leverage ratio (which, is essentially, the ratio of debt to EBITDA) of the gas business immediately after the separation would not be greater than 2.75 to 1.00. At September 30, 2014, the $2,000,000 facility had no borrowings outstanding and $264,544 of letters of credit outstanding, leaving $1,735,456 of unused capacity. At December 31, 2013, the prior CONSOL Energy $1,000,000 facility had no borrowings outstanding and $206,988 of letters of credit outstanding, leaving $793,012 of unused capacity. At December 31, 2013, the prior CNX Gas Corporation $1,000,000 facility had no borrowings outstanding and $87,643 of letters of credit outstanding, leaving $912,357 of unused capacity.

NOTE 11—LONG-TERM DEBT:
 
September 30,
2014
 
December 31,
2013
Debt:
 
 
 
Senior notes due April 2017 at 8.00%, issued at par value
$

 
$
1,500,000

Senior notes due April 2020 at 8.25%, issued at par value
1,014,800

 
1,250,000

Senior notes due March 2021 at 6.375%, issued at par value
250,000

 
250,000

Senior notes due April 2022 at 5.875%
1,850,000

 

MEDCO revenue bonds in series due September 2025 at 5.75%
102,865

 
102,865

Senior notes due April 2022 at 5.875%, Premium
6,875

 

Senior notes due April 2022 at 5.875%, Amortization of Bond Premium
(148
)
 

Advance royalty commitments (7.93% weighted average interest rate for September 30, 2014 and December 31, 2013)
11,182

 
11,182

Other long-term notes maturing at various dates through 2031 (total value of $4,892 and $5,923 less unamortized discount of $736 and $1,050 at September 30, 2014 and December 31, 2013, respectively).
4,156

 
4,873

 
3,239,730

 
3,118,920

Less amounts due in one year *
3,558

 
2,957

Long-Term Debt
$
3,236,172

 
$
3,115,963

* Excludes current portion of Capital Lease Obligations of $8,667 and $8,498 at September 30, 2014 and December 31, 2013, respectively.

Accrued interest related to Long-Term Debt of $93,709 and $63,272 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at September 30, 2014 and December 31, 2013, respectively.

On April 16, 2014, CONSOL Energy closed on the private placement of $1,600,000 of 5.875% senior notes due 2022 (the "Notes"). The Notes are guaranteed by substantially all of CONSOL Energy's wholly-owned domestic restricted subsidiaries. CONSOL Energy used substantially all of the net proceeds of the sale of the Notes to purchase the 8.00% senior notes due in 2017.

On August 12, 2014, CONSOL Energy closed on an additional $250,000 of its 5.875% senior notes due 2022 at a price equal to 102.75% of the principal amount of the Additional Notes. CONSOL Energy used $235,200 of the net proceeds of the sale of the Additional Notes to purchase a portion of the outstanding 8.25% senior notes due in 2020.

NOTE 12—COMMITMENTS AND CONTINGENT LIABILITIES:
CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. We accrue the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. Our current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CONSOL Energy. It is possible that the aggregate loss in the future with respect to these lawsuits and


18





claims could ultimately be material to the financial position, results of operations or cash flows of CONSOL Energy; however, such amounts cannot be reasonably estimated. The amount claimed against CONSOL Energy is disclosed below when an amount is expressly stated in the lawsuit or claim, which is not often the case. The maximum aggregate amount claimed in those lawsuits and claims, regardless of probability, where a claim is expressly stated or can be estimated, exceeds the aggregate amounts accrued for all lawsuits and claims by approximately $388,156.

The following lawsuits and claims include those for which a loss is probable and an accrual has been recognized.

Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 6,900 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Texas and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos, and since many of the pending claims are asserted against dozens of defendants in any given action, it has been difficult for Fairmont to determine how many of the pending cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Based on nearly 20 years of experience with this litigation, we have established an accrual to cover our estimated liability for these cases. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheets. Past payments by Fairmont with respect to asbestos cases have not been material.

Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia styled Hale v. CNX Gas Company, et. al. The putative class consists of forced-pooled unleased gas owners whose ownership of the coalbed methane (CBM) gas was declared to be in conflict with rights of others. The lawsuit seeks a judicial declaration of ownership of the CBM, and Plaintiffs also allege CNX Gas Company failed to either pay royalties due to conflicting claimants, or deemed lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form, believes that the case has meritorious defenses, and intends to defend it vigorously. We have established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

Addison Litigation: A putative class action lawsuit was filed on April 28, 2010 in the United States District Court in Abingdon, Virginia styled Addison v. CNX Gas Company, et al.  The plaintiff class consists of gas lessors whose gas ownership is in conflict. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on the allegations that CNX Gas Company failed to either pay royalties due these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Court of Appeals for the Fourth Circuit. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form, believes that the case has meritorious defenses, and intends to defend it vigorously. We have established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheets.

The following royalty and land right lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly, no accrual has been recognized. These claims are influenced by many factors which prevent the estimation of a range of potential loss. These factors include, but are not limited to, generalized allegations of unspecified damages (such as improper deductions), discovery having not commenced or not having been completed, unavailability of expert reports on damages and non-monetary issues are being tried. For example, in instances where a gas lease termination is sought, damages would depend on speculation as to if and when the gas production would otherwise have occurred, how many wells would have been drilled on the lease premises, what their production would be, what the cost of production would be, and what the price of gas would be during the production period. An estimate is calculated, if applicable, when sufficient information becomes available.



19





Ratliff Litigation: On January 30, 2013, the Company was served with a complaint filed on behalf of four individuals against Consolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, as well as CONSOL Energy itself in the United States District Court for the Western District of Virginia. The complaint seeks damages and injunctive relief in connection with the deposit of water from mining activities at the Buchanan Mine into nearby void spaces at some of the mines of ICCC, voids ostensibly underlying their property. The suit alleges damage to coal and coalbed methane and seeks recovery in tort, contract and assumpsit (quasi-contract). The suit seeks damages of approximately $50,000 plus punitive damages. The defendants have asserted Virginia's Mine Void Statute as a defense to plaintiffs’ claims and the plaintiffs have challenged the constitutionality of that statute. On March 18, 2014, the District Court concluded, in ruling on Defendants’ Motion to Dismiss, it could not resolve either the constitutionality or the applicability of the Mine Void Statute on the current record. Discovery is ongoing. CONSOL Energy intends to vigorously defend the suit.
 
    Kennedy Litigation: The Company is a party to a case filed on March 26, 2008 captioned Earl Kennedy (and others) v. CNX Gas Company and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas Company and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas Company. The complaint, as amended, seeks injunctive relief, including removing CNX Gas Company from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court. The suit further sought a determination that the Pittsburgh 8 coal seam does not include the “roof/rider” coal. The court held a bench trial on the “roof/rider” coal issue in November 2011 and ruled in favor of CNX Gas Company and CONSOL Energy. On March 3, 2014, the Company won summary judgment on Counts 1 through 10 of the Amended Complaint, each relating to the alleged trespass of horizontal CBM wells into strata other than the Pittsburgh 8 Seam. The Court rejected each of those claims, essentially holding that if CNX Gas Company went out of the coal seam, it had no intention to do so and, in any event, the plaintiff could not prove any damages as a result. The last remaining Count, seeking to quiet title to approximately 40 acres of Pittsburgh Seam coal, was nonsuited by Plaintiffs, without prejudice, on March 26, 2014. On March 28, 2014, Plaintiffs filed Notices of Appeal with the Pennsylvania Superior Court on all issues decided in CONSOL Energy’s favor.
Rowland Litigation: Rowland Land Company filed a complaint in May 2011 against CONSOL Energy, CNX Gas Company, Dominion Resources Inc., and EQT Production Company (EQT) in Raleigh County Circuit Court, West Virginia. Rowland is the lessor on a 33,000 acre oil and gas lease in southern West Virginia. EQT was the original lessee, but farmed out the development of the lease to Dominion Resources in exchange for an overriding royalty. Dominion Resources sold the indirect subsidiary that held the lease to a subsidiary of CONSOL Energy on April 30, 2010. Subsequent to that acquisition, the subsidiary that held the lease was merged into CNX Gas Company as part of an internal reorganization. Rowland alleges that (i) Dominion Resources' sale of the subsidiary to CONSOL Energy was a change in control that required its consent under the terms of the farmout agreement and lease, and/or (ii) the subsequent merger of the subsidiary into CNX Gas Company was an assignment that required its consent under the lease. Rowland has recently been permitted to file its Third Amended Complaint to include additional allegations that CONSOL Energy has slandered Rowland's title. A hearing on the CNX Gas Company motion to dismiss will be held in the next few weeks. Mediation efforts have been unsuccessful. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liability related to these actions.
At September 30, 2014, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.


20





 
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
$
151,302

 
$
71,915

 
$
79,387

 
$

 
$

Environmental
39,363

 
37,635

 
1,728

 

 

Other
135,809

 
56,209

 
79,600

 

 

Total Letters of Credit
326,474

 
165,759

 
160,715

 

 

Surety Bonds:
 
 
 
 
 
 
 
 
 
Employee-Related
204,884

 
204,884

 

 

 

Environmental
661,191

 
619,041

 
42,150

 

 

Other
25,685

 
25,625

 
59

 

 
1

Total Surety Bonds
891,760

 
849,550

 
42,209

 

 
1

Guarantees:
 
 
 
 
 
 
 
 
 
Coal
183,700

 
125,250

 
58,450

 

 

Other
63,131

 
34,974

 
9,010

 
8,446

 
10,701

Total Guarantees
246,831

 
160,224

 
67,460

 
8,446

 
10,701

Total Commitments
$
1,465,065

 
$
1,175,533

 
$
270,384

 
$
8,446

 
$
10,702


Included in the above table are commitments and guarantees entered into in conjunction with the sale of CCC and certain of its subsidiaries, which contain all five of its longwall coal mines in West Virginia, and its river operations to a subsidiary of Murray Energy. As part of the sales agreement, CONSOL Energy has guaranteed certain equipment lease obligations and coal sales agreements that were assumed by Murray Energy. In the event that Murray Energy would default on the obligations defined in the agreements, CONSOL Energy would be required to perform under the guarantees. If CONSOL Energy would be required to perform, the stock purchase agreement provides various recourse actions. At September 30, 2014, the fair value of these guarantees was $3,000 and was included in Accounts Payable on the Consolidated Balance Sheets. The fair value of certain guarantees was determined using CONSOL Energy’s risk adjusted interest rate. Significant increases or decreases in the risk-adjusted interest rates may result in a significantly higher or lower fair value measurement. Coal sales agreement guarantees were valued based on an evaluation of coal market pricing compared to contracted sales price and includes an adjustment for nonperformance risk. No other amounts related to financial guarantees and letters of credit are recorded as liabilities in the financial statements. Significant judgment is required in determining the fair value of these guarantees. The guarantees of the leases and sales agreements are classified within Level 3 of the fair value hierarchy.

CONSOL Energy regularly evaluates the likelihood of default for all guarantees based on an expected loss analysis and records the fair value, if any, of its guarantees as an obligation in the consolidated financial statements. 
CONSOL Energy and CNX Gas enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheets. As of September 30, 2014, the purchase obligations for each of the next five years and beyond were as follows:
 
Obligations Due
Amount
Less than 1 year
$
240,865

1 - 3 years
371,127

3 - 5 years
224,394

More than 5 years
492,825

Total Purchase Obligations
$
1,329,211


Costs related to these purchase obligations include:


21





 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
Major Equipment Purchases
 
$
9,255

 
$
6,682

 
$
99,416

 
$
15,481

Firm Transportation and Processing Expense
 
27,476

 
24,449

 
76,839

 
67,269

Gas Drilling Obligations
 
32,901

 
26,296

 
85,364

 
81,419

Total Costs Related to Purchase Obligations
 
$
69,632

 
$
57,427

 
$
261,619

 
$
164,169

    
    
NOTE 13—DERIVATIVE INSTRUMENTS:

CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. The fair value of CONSOL Energy's derivatives (natural gas price swaps and options) are based on pricing models which utilize inputs that are either readily available in the public market, such as natural gas forward curves, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by our counterparties for reasonableness. Changes in the fair value of the derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in the fair value of the derivatives are reported in Other Comprehensive Income or Loss (OCI) on the Consolidated Balance Sheets and reclassified into Natural Gas, NGL's and Oil Sales on the Consolidated Statements of Income in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current period. CONSOL Energy currently utilizes only cash flow hedges that are considered highly effective.

CONSOL Energy formally assesses both at inception of the hedge and on an ongoing basis whether each derivative is highly effective in offsetting changes in the fair values or the cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.

CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.

None of our counterparty master agreements currently require CONSOL Energy to post collateral for any of its hedges. However, as stated in the counterparty master agreements, if CONSOL Energy's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CONSOL Energy would have to post collateral for hedges in a liability position in excess of defined thresholds. All of our derivative instruments are subject to master netting arrangements with our counterparties.  CONSOL Energy recognizes all financial derivative instruments as either assets or liabilities at fair value on the Consolidated Balance Sheets on a gross basis.
 
                Each of CONSOL Energy's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CONSOL Energy and the applicable counterparty would net settle all open hedge positions.

CONSOL Energy has entered into swap and option contracts for natural gas to manage the price risk associated with the forecasted natural gas sales. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted sales from the underlying commodity. As of September 30, 2014, the total notional amount of the Company’s outstanding derivative instruments was 199.6 billion cubic feet. These derivative instruments are forecasted to settle through December 31, 2016 and meet the criteria for cash flow hedge accounting. As these contracts settle, the cash received and/or paid will be shown on the Consolidated Statements of Cash Flows as Changes in Prepaid Expenses, Changes in Other Assets, Changes in Other Operating Liabilities and/or Changes in Other Liabilities. Assuming no changes in price during the next twelve months, $14,853 of unrealized gain is expected to be reclassified from Other Comprehensive Income on the Consolidated Balance Sheets and into Natural Gas, NGL's and Oil Sales on the Consolidated Statements of Income, as a result of the gross settlements of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

The gross fair value at September 30, 2014 of CONSOL Energy's derivative instruments, which all qualify as cash flow hedges, was an asset of $51,710 and a liability of $8,554. The total asset is comprised of $31,520 and $20,190 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is


22





comprised of $7,204 and $1,350 which was included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

The gross fair value at December 31, 2013 of CONSOL Energy's derivative instruments, which all qualify as cash flow hedges, was an asset of $83,661 and a liability of $18,212. The total asset is comprised of $59,605 and $24,056 which was included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $12,327 and $5,885 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

The effect of derivative instruments in cash flow hedging relationships on the Consolidated Statements of Income and the Consolidated Statements of Stockholders' Equity net of tax was as follows:

 
 
 
For the Three Months Ended September 30,
 
2014
 
2013
Natural Gas Price Swaps and Options
 
 
 
Beginning Balance – Accumulated OCI

$
6,574

 
$
71,674

Gain recognized in Accumulated OCI
39,151

 
13,246

Less: Gain reclassified from Accumulated OCI into Natural Gas, NGL's and Oil Sales
19,510

 
24,354

Ending Balance – Accumulated OCI

$
26,215

 
$
60,566

Gain recognized in Natural Gas, NGL's and Oil Sales for ineffectiveness 
$
1,850

 
$
2,592


 
 
 
For the Nine Months Ended September 30,
 
2014
 
2013
Natural Gas Price Swaps and Options
 
 
 
Beginning Balance – Accumulated OCI

$
42,493

 
$
76,761

(Loss)/Gain recognized in Accumulated OCI
(20,032
)
 
40,400

Less: (Loss)/Gain reclassified from Accumulated OCI into Natural Gas, NGL's and Oil Sales
(3,754
)
 
56,595

Ending Balance – Accumulated OCI

$
26,215

 
$
60,566

Gain/(Loss) recognized in Natural Gas, NGL's and Oil Sales for ineffectiveness 
$
2,713

 
$
(120
)

There were no amounts excluded from the assessment of hedge effectiveness in the nine months ended September 30, 2014 or 2013.

NOTE 14—FAIR VALUE OF FINANCIAL INSTRUMENTS:

The financial instruments measured at fair value on a recurring basis are summarized below:
 
Fair Value Measurements at September 30, 2014
 
Fair Value Measurements at December 31, 2013
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
$

 
$
43,156

 
$

 
$

 
$
65,449

 
$

Murray Energy Guarantees
$

 
$

 
$
3,000

 
$

 
$

 
$
3,000

*- The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs, including NYMEX forward curves, LIBOR-based discount rates and basis forward curves.
**- The fair value of the assets and liabilities included in Level 3 are based on unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. The significant unobservable inputs used in the fair value measurement of our third party guarantees are the credit risk of the third party and the third party surety bond markets. A significant increase or decrease in the these values, in isolation, would have a directionally similar effect resulting in higher or lower fair value measurement of our Level 3 guarantees.



23






The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:

Cash and cash equivalents: The carrying amount reported in the balance sheets for cash and cash equivalents approximates its fair value due to the short-term maturity of these instruments.

Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses. The discounted cash flow analyses are based on current market rates for instruments with similar cash flows.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
 
September 30, 2014
 
December 31, 2013
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Cash and Cash Equivalents
$
225,563

 
$
225,563

 
$
327,420

 
$
327,420

Long-Term Debt
$
(3,239,730
)
 
$
(3,269,768
)
 
$
(3,118,920
)
 
$
(3,299,875
)

NOTE 15—SEGMENT INFORMATION:
CONSOL Energy has two principal business divisions: Exploration and Production (E&P) and Coal. The principal activity of the E&P division is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The E&P division includes four reportable segments. These reportable segments are Marcellus, Coalbed Methane, Shallow Oil and Gas and Other Gas. The Other Gas segment includes our purchased gas activities, general and administrative activities as well as various other activities assigned to the E&P division but not allocated to each individual well type. The principal activities of the Coal division are mining, preparation and marketing of thermal coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal division includes four reportable segments. These reportable segments are Thermal, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the three and nine months ended September 30, 2014, the Thermal aggregated segment includes the following mines: Bailey Complex, Buchanan Mine, Enlow Fork Mine, Harvey Mine and Miller Creek Complex. For the three and nine months ended September 30, 2014, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine. For the three and nine months ended September 30, 2014, the High Volatile Metallurgical aggregated segment includes: Bailey Complex, Enlow Fork Mine, and Harvey Mine coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, general and administrative activities as well as various other activities assigned to the Coal division but not allocated to each individual mine. CONSOL Energy’s All Other segment includes industrial supplies, coal terminal operations and various other corporate activities that are not allocated to the E&P or Coal division. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at the division level only (E&P, Coal, and Other) and are not allocated between each individual segment. This presentation is consistent with the information regularly reviewed by the chief operating decision maker. The assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy where each individual asset may service more than one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.



24





Industry segment results for the three months ended September 30, 2014 are:
 
 
Marcellus
Shale
 
Coalbed
Methane
 
Shallow Oil and Gas
 
Other
Gas
 
Total
E&P
 
Thermal
 
Low Volatile
Metallurgical
 
High Volatile
Metallurgical
 
Other
Coal
 
Total Coal
 
All
Other
 
Corporate,
Adjustments
&
Eliminations
 
Consolidated
 
Sales—outside
$
109,850

 
$
82,913

 
$
25,377

 
$
39,218

 
$
257,358

 
$
398,863

 
$
69,850

 
$
14,684

 
$
563

 
$
483,960

 
$
73,673

 
$

 
$
814,991

(A)
Sales—purchased gas

 

 

 
1,205

 
1,205

 

 

 

 

 

 

 

 
1,205

  
Sales—gas royalty interests

 

 

 
17,610

 
17,610

 

 

 

 

 

 

 

 
17,610

  
Freight—outside

 

 

 

 

 

 

 

 
2,497

 
2,497

 

 

 
2,497

  
Intersegment transfers

 
485

 

 

 
485

 

 

 

 

 

 
23,066

 
(23,551
)
 

  
Total Sales and Freight
$
109,850

 
$
83,398

 
$
25,377

 
$
58,033

 
$
276,658

 
$
398,863

 
$
69,850

 
$
14,684

 
$
3,060

 
$
486,457

 
$
96,739

 
$
(23,551
)
 
$
836,303

  
Earnings (Loss) Before Income Taxes
$
27,328

 
$
19,790

 
$
(9,341
)
 
$
(92
)
 
$
37,685

 
$
81,660

 
$
9,115

 
$
8,056

 
$
(46,484
)
 
$
52,347

 
$
2,689

 
$
(95,754
)
 
$
(3,033
)
(B)
Segment assets
 
 
 
 
 
 
 
 
$
6,901,696

 
 
 
 
 
 
 
 
 
$
4,119,591

 
$
295,279

 
$
402,369

 
$
11,718,935

(C)
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
$
82,538

 
 
 
 
 
 
 
 
 
$
64,880

 
$
1,247

 
$

 
$
148,665

  
Capital expenditures
 
 
 
 
 
 
 
 
$
281,641

 
 
 
 
 
 
 
 
 
$
72,496

 
$
1,175

 
$

 
$
355,312

  
 
(A)    Included in the Coal segment are sales of $107,915 to Duke Energy, which comprises over 10% of sales.
(B)     Includes equity in earnings of unconsolidated affiliates of $9,991, $6,842 and $132 for E&P, Coal and All Other, respectively.
(C)    Includes investments in unconsolidated equity affiliates of $92,188, $25,844 and $67,477 for E&P, Coal and All Other, respectively.


25





Industry segment results for the three months ended September 30, 2013 are:
 
 
Marcellus
Shale
 
Coalbed
Methane
 
Shallow Oil and Gas
 
Other
Gas
 
Total E&P
 
Thermal
 
Low Volatile
Metallurgical
 
High Volatile
Metallurgical
 
Other
Coal
 
Total
Coal
 
All
Other
 
Corporate,
Adjustments
&
Eliminations
 
Consolidated
 
Sales—outside
$
72,406

 
$
83,269

 
$
32,957

 
$
4,149

 
$
192,781

 
$
352,362

 
$
98,232

 
$
22,290

 
$
6,427

 
$
479,311

 
$
63,876

 
$

 
$
735,968

(D)
Sales—purchased gas

 

 

 
1,607

 
1,607

 

 

 

 

 

 

 

 
1,607

  
Sales—gas royalty interests

 

 

 
15,506

 
15,506

 

 

 

 

 

 

 

 
15,506

  
Freight—outside

 

 

 

 

 

 

 

 
9,579

 
9,579

 

 

 
9,579

  
Intersegment transfers

 
601

 

 

 
601

 

 

 

 

 

 
32,213

 
(32,814
)
 

  
Total Sales and Freight
$
72,406

 
$
83,870

 
$
32,957

 
$
21,262

 
$
210,495

 
$
352,362

 
$
98,232

 
$
22,290

 
$
16,006

 
$
488,890

 
$
96,089

 
$
(32,814
)
 
$
762,660

  
Earnings (Loss) Before Income Taxes
$
27,963

 
$
20,908

 
$
(2,123
)
 
$
(48,615
)
 
$
(1,867
)
 
$
95,916

 
$
21,297

 
$
4,801

 
$
(57,625
)
 
$
64,389

 
$
(2,385
)
 
$
(63,448
)
 
$
(3,311
)
(E)
Segment assets
 
 
 
 
 
 
 
 
$
5,994,072

 
 
 
 
 
 
 
 
 
$
4,118,351

 
$
356,731

 
$
2,267,918

 
$
12,737,072

(F)
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
$
58,998

 
 
 
 
 
 
 
 
 
$
57,265

 
$
1,467

 
$

 
$
117,730

  
Capital expenditures
 
 
 
 
 
 
 
 
$
273,474

 
 
 
 
 
 
 
 
 
$
32,497

 
$
7,704

 
$

 
$
313,675

  

(D)
There were no sales to customers aggregating over 10% of total revenue in the three months ending September 30, 2013.
(E)
Includes equity in earnings of unconsolidated affiliates of $5,307, $(1,769) and $72 for E&P, Coal and All Other, respectively.
(F)    Includes investments in unconsolidated equity affiliates of $183,895, $20,131 and $57,192 for E&P, Coal and All Other, respectively.





26





Industry segment results for the nine months ended September 30, 2014 are:
 
 
Marcellus
Shale
 
Coalbed
Methane
 
Shallow Oil and Gas
 
Other
Gas
 
Total E&P
 
Thermal
 
Low Volatile
Metallurgical
 
High Volatile
Metallurgical
 
Other
Coal
 
Total
Coal
 
All
Other
 
Corporate,
Adjustments
&
Eliminations
 
Consolidated
 
Sales—outside
$
339,391

 
$
259,665

 
$
84,278

 
$
70,065

 
$
753,399

 
$
1,262,248

 
$
221,162

 
$
64,099

 
$
7,430

 
$
1,554,939

 
$
213,047

 
$

 
$
2,521,385

(G)
Sales—purchased gas

 

 

 
6,183

 
6,183

 

 

 

 

 

 

 

 
6,183

  
Sales—gas royalty interests

 

 

 
62,590

 
62,590

 

 

 

 

 

 

 

 
62,590

  
Freight—outside

 

 

 

 

 

 

 

 
22,551

 
22,551

 

 

 
22,551

  
Intersegment transfers

 
1,937

 

 

 
1,937

 

 

 

 

 

 
62,412

 
(64,349
)
 

  
Total Sales and Freight
$
339,391

 
$
261,602

 
$
84,278

 
$
138,838

 
$
824,109

 
$
1,262,248

 
$
221,162

 
$
64,099

 
$
29,981

 
$
1,577,490

 
$
275,459

 
$
(64,349
)
 
$
2,612,709

  
Earnings (Loss) Before Income Taxes
$
121,197

 
$
71,358

 
$
(16,194
)
 
$
(37,757
)
 
$
138,604

 
$
342,133

 
$
29,837

 
$
24,731

 
$
(117,588
)
 
$
279,113

 
$
5,941

 
$
(320,232
)
 
$
103,426

(H)
Segment assets
 
 
 
 
 
 
 
 
$
6,901,696

 
 
 
 
 
 
 
 
 
$
4,119,591

 
$
295,279

 
$
402,369

 
$
11,718,935

(I)
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
$
225,766

 
 
 
 
 
 
 
 
 
$
186,029

 
$
3,885

 
$

 
$
415,680

  
Capital expenditures
 
 
 
 
 
 
 
 
$
852,097

 
 
 
 
 
 
 
 
 
$
320,196

 
$
2,314

 
$

 
$
1,174,607

  

(G)
Included in the Coal segment are sales of $297,836 to Duke Energy which comprises over 10% of sales.
(H)
Includes equity in earnings of unconsolidated affiliates of $22,801, $16,635 and $(959) for E&P, Coal and All Other, respectively.
(I)    Includes investments in unconsolidated equity affiliates of $92,188, $25,844 and $67,477 for E&P, Coal and All Other, respectively.











27





Industry segment results for the nine months ended September 30, 2013 are:
 
 
Marcellus
Shale
 
Coalbed
Methane
 
Shallow Oil and Gas
 
Other
Gas
 
Total E&P
 
Thermal
 
Low Volatile
Metallurgical
 
High Volatile
Metallurgical
 
Other
Coal
 
Total
Coal
 
All
Other
 
Corporate,
Adjustments
&
Eliminations
 
Consolidated
 
Sales—outside
$
167,394

 
$
254,708

 
$
99,138

 
$
10,619

 
$
531,859

 
$
1,034,228

 
$
356,066

 
$
124,957

 
$
17,029

 
$
1,532,280

 
$
197,778

 
$

 
$
2,261,917

(J)
Sales—purchased gas

 

 

 
4,372

 
4,372

 

 

 

 

 

 

 

 
4,372

  
Sales—gas royalty interests

 

 

 
46,737

 
46,737

 

 

 

 

 

 

 

 
46,737

  
Freight—outside

 

 

 

 

 

 

 

 
31,492

 
31,492

 

 

 
31,492

  
Intersegment transfers

 
2,363

 

 

 
2,363

 

 

 

 

 

 
100,118

 
(102,481
)
 

  
Total Sales and Freight
$
167,394

 
$
257,071

 
$
99,138

 
$
61,728

 
$
585,331

 
$
1,034,228

 
$
356,066

 
$
124,957

 
$
48,521

 
$
1,563,772

 
$
297,896

 
$
(102,481
)
 
$
2,344,518

  
Earnings (Loss) Before Income Taxes
$
53,411

 
$
64,213

 
$
(11,752
)
 
$
(112,989
)
 
$
(7,117
)
 
$
277,289

 
$
106,832

 
$
32,307

 
$
(146,597
)
 
$
269,831

 
$
5,076

 
$
(237,590
)
 
$
30,200

(K)
Segment assets
 
 
 
 
 
 
 
 
$
5,994,072

 
 
 
 
 
 
 
 
 
$
4,118,351

 
$
356,731

 
$
2,267,918

 
$
12,737,072

(L)
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
$
164,832

 
 
 
 
 
 
 
 
 
$
169,702

 
$
4,303

 
$

 
$
338,837

  
Capital expenditures
 
 
 
 
 
 
 
 
$
669,067

 
 
 
 
 
 
 
 
 
$
336,845

 
$
15,215

 
$

 
$
1,021,127

  

(J)
Included in the Coal segment are sales of $492,872 and $441,528 to First Energy and Xcoal Energy & Resources, respectively, which comprises over 10% of sales.
(K)
Includes equity in earnings of unconsolidated affiliates of $9,519, $10,525 and $232 for E&P, Coal and All Other, respectively.
(L)    Includes investments in unconsolidated equity affiliates of $183,895, $20,131 and $57,192 for E&P, Coal and All Other, respectively.



28






Reconciliation of Segment Information to Consolidated Amounts:
Earnings Before Income Taxes:
 
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Segment Earnings Before Income Taxes for total reportable business segments
$
90,032

 
$
62,522

 
$
417,717

 
$
262,714

Segment Earnings Before Income Taxes for all other businesses
2,689

 
(2,385
)
 
5,941

 
5,076

Interest expense, net and other non-operating activity (M)
(79,366
)
 
(57,479
)
 
(277,322
)
 
(166,542
)
Other Corporate Items (M)
(16,388
)
 
(5,969
)
 
(42,910
)
 
(71,048
)
Earnings Before Income Taxes
$
(3,033
)
 
$
(3,311
)
 
$
103,426

 
$
30,200

 
Total Assets:
September 30,
2014
 
2013
Segment assets for total reportable business segments
$
11,021,287

 
$
10,112,423

Segment assets for all other businesses
295,279

 
356,731

Items excluded from segment assets:
 
 
 
Cash and other investments (M)
193,325

 
17,966

Recoverable income taxes
41,971

 

Deferred tax assets
127,731

 
25,585

Bond issuance costs
39,342

 
36,266

Discontinued Operations

 
2,188,101

Total Consolidated Assets
$
11,718,935

 
$
12,737,072

_________________________ 
(M) Excludes amounts specifically related to the E&P segment.

NOTE 16—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:
The payment obligations under the $1,014,800, 8.250% per annum senior notes due April 1, 2020, the $250,000, 6.375% per annum senior notes due March 1, 2021, and the $1,850,000, 5.875% per annum senior notes due April 1, 2022 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by substantially all subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.








29





Income Statement for the Three Months Ended September 30, 2014 (unaudited):
 
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Revenues and Other Income:
 
 
 
 
 
 
 
 
 
 
 
Natural Gas, NGLs and Oil Sales
$

 
$
257,844

 
$

 
$

 
$
(486
)
 
$
257,358

Coal Sales

 

 
483,960

 

 

 
483,960

Other Outside Sales

 

 
8,175

 
65,498

 

 
73,673

Gas Royalty Interests and Purchased Gas Sales

 
18,815

 

 

 

 
18,815

Freight-Outside Coal

 

 
2,497

 

 

 
2,497

Miscellaneous Other Income
68,307

 
13,858

 
24,358

 
2,400

 
(68,139
)
 
40,784

Gain (Loss) on Sale of Assets

 
5,488

 
2,033

 
8

 

 
7,529

Total Revenue and Other Income
68,307

 
296,005

 
521,023

 
67,906

 
(68,625
)
 
884,616

Costs and Expenses:
 
 
 
 
 
 
 
 
 
 
 
Exploration and Production Costs
 
 
 
 
 
 
 
 
 
 
 
Lease Operating Expense

 
30,005

 

 

 

 
30,005

Transportation, Gathering and Compression

 
68,234

 

 

 

 
68,234

Production, Ad Valorem, and Other Fees

 
8,486

 

 

 

 
8,486

Direct Administrative and Selling

 
14,060

 

 

 

 
14,060

Depreciation, Depletion and Amortization

 
82,538

 

 

 

 
82,538

Exploration and Production Related Other Costs

 
8,042

 

 

 

 
8,042

Production Royalty Interests and Purchased Gas Costs

 
15,751

 

 

 

 
15,751

Other Corporate Expenses

 
13,700

 

 

 

 
13,700

General and Administrative

 
14,874

 

 

 

 
14,874

Total Exploration and Production Costs

 
255,690

 

 

 

 
255,690

Coal Costs
 
 
 
 
 
 
 
 
 
 
 
Operating and Other Costs
3,458

 

 
336,243

 

 
(485
)
 
339,216

Royalties and Production Taxes

 

 
23,306

 

 

 
23,306

Direct Administrative and Selling

 

 
10,479

 

 

 
10,479

Depreciation, Depletion and Amortization
159

 

 
64,721

 

 

 
64,880

Freight Expense

 

 
2,497

 

 

 
2,497

General and Administrative Costs

 

 
10,434

 

 

 
10,434

Other Corporate Expenses
10,114

 

 

 

 

 
10,114

Total Coal Costs
13,731

 

 
447,680

 

 
(485
)
 
460,926

Other Costs
 
 
 
 
 
 
 
 
 
 
 
Miscellaneous Operating Expense
23,681

 

 
6,050

 
63,243

 

 
92,974

General and Administrative Costs

 

 
205

 
220

 

 
425

Depreciation, Depletion and Amortization
6

 

 
775

 
466

 

 
1,247

Loss on Debt Extinguishment
20,990

 

 

 

 

 
20,990

Interest Expense
52,907

 
2,629

 
1,587

 
82

 
(1,808
)
 
55,397

Total Other Costs
97,584

 
2,629

 
8,617

 
64,011

 
(1,808
)
 
171,033

Total Costs And Expenses
111,315

 
258,319

 
456,297

 
64,011

 
(2,293
)
 
887,649

(Loss) Earnings Before Income Tax
(43,008
)
 
37,686

 
64,726

 
3,895

 
(66,332
)
 
(3,033
)
Income Taxes
(41,363
)
 
13,281

 
25,221

 
1,473

 

 
(1,388
)
(Loss) Income From Continuing Operations
(1,645
)
 
24,405

 
39,505

 
2,422

 
(66,332
)
 
(1,645
)
Income From Discontinued Operations, net

 

 

 

 

 

Net (Loss) Income Attributable to CONSOL Energy Shareholders
$
(1,645
)
 
$
24,405

 
$
39,505

 
$
2,422

 
$
(66,332
)
 
$
(1,645
)


30





Balance Sheet at September 30, 2014 (unaudited):
 
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Assets:
 
 
 
 
 
 
 
 
 
 
 
Current Assets:
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
$
191,555

 
$
33,121

 
$

 
$
887

 
$

 
$
225,563

Accounts and Notes Receivable:
 
 
 
 
 
 
 
 
 
 
 
Trade

 
95,746

 

 
204,193

 

 
299,939

Other Receivables
49,930

 
323,154

 
5,673

 
3,895

 

 
382,652

Inventories

 
14,086

 
95,450

 
35,836

 

 
145,372

Deferred Income Taxes
127,366

 
365

 

 

 

 
127,731

Recoverable Income Taxes
57,067

 
(15,096
)
 

 

 

 
41,971

Prepaid Expenses
39,202

 
36,182

 
24,655

 
1,828

 

 
101,867

Total Current Assets
465,120

 
487,558

 
125,778

 
246,639

 

 
1,325,095

Property, Plant and Equipment:
 
 
 
 
 
 
 
 
 
 
 
Property, Plant and Equipment
165,885

 
7,694,180

 
6,577,039

 
26,224

 

 
14,463,328

Less-Accumulated Depreciation, Depletion and Amortization
118,444

 
1,410,235

 
2,950,922

 
19,743

 

 
4,499,344

Total Property, Plant and Equipment-Net
47,441

 
6,283,945

 
3,626,117

 
6,481

 

 
9,963,984

Other Assets:
 
 
 
 
 
 
 
 
 
 
 
Investment in Affiliates
12,481,970

 
92,188

 
78,231

 

 
(12,466,880
)
 
185,509

Other
172,625

 
23,264

 
39,822

 
8,636

 

 
244,347

Total Other Assets
12,654,595

 
115,452

 
118,053

 
8,636

 
(12,466,880
)
 
429,856

Total Assets
$
13,167,156

 
$
6,886,955

 
$
3,869,948

 
$
261,756

 
$
(12,466,880
)
 
$
11,718,935

Liabilities and Equity:
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Accounts Payable
$
102,157

 
$
400,751

 
$
93,156

 
$
14,661

 
$

 
$
610,725

Accounts Payable (Recoverable)—Related Parties
4,502,239

 
152,871

 
(5,286,273
)
 
65,013

 
566,150

 

Current Portion Long-Term Debt
1,571

 
6,590

 
3,393

 
671

 

 
12,225

Short-Term Notes Payable

 
566,150

 


 

 
(566,150
)
 

Other Accrued Liabilities
163,415

 
109,704

 
329,341

 
8,244

 

 
610,704

Current Liabilities of Discontinued Operations

 

 

 
12,992

 

 
12,992

Total Current Liabilities
4,769,382

 
1,236,066

 
(4,860,383
)
 
101,581

 

 
1,246,646

Long-Term Debt:
3,125,439

 
38,907

 
113,100

 
1,876

 

 
3,279,322

Deferred Credits and Other Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Deferred Income Taxes
(89,966
)
 
484,991

 

 

 

 
395,025

Postretirement Benefits Other Than Pensions

 

 
652,050

 

 

 
652,050

Pneumoconiosis Benefits

 

 
111,514

 

 

 
111,514

Mine Closing

 

 
321,776

 

 

 
321,776

Gas Well Closing

 
120,899

 
59,621

 

 

 
180,520

Workers’ Compensation

 

 
73,053

 
345

 

 
73,398

Salary Retirement
48,231

 

 

 

 

 
48,231

Reclamation

 

 
34,499

 

 

 
34,499

Other
59,471

 
56,788

 
5,096

 

 

 
121,355

Total Deferred Credits and Other Liabilities
17,736

 
662,678

 
1,257,609

 
345

 

 
1,938,368

Total CONSOL Energy Inc. Stockholders’ Equity
5,254,599

 
4,949,304

 
7,359,622

 
157,954

 
(12,466,880
)
 
5,254,599

Total Liabilities and Equity
$
13,167,156

 
$
6,886,955

 
$
3,869,948

 
$
261,756

 
$
(12,466,880
)
 
$
11,718,935



31





Income Statement for the Three Months Ended September 30, 2013 (unaudited):

 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Revenues and Other Income:
 
 
 
 
 
 
 
 
 
 
 
Natural Gas, NGLs and Oil Sales
$

 
$
193,383

 
$
203

 
$

 
$
(805
)
 
$
192,781

Coal Sales

 

 
479,311

 

 

 
479,311

Other Outside Sales

 

 
9,702

 
54,174

 

 
63,876

Gas Royalty Interests and Purchased Gas Sales

 
17,113

 

 

 

 
17,113

Freight-Outside Coal

 

 
9,579

 

 

 
9,579

Miscellaneous Other Income
78,203

 
11,133

 
4,783

 
4,928

 
(78,225
)
 
20,822

Gain (Loss) on Sale of Assets

 
1,462

 
18,401

 

 

 
19,863

Total Revenue and Other Income
78,203

 
223,091

 
521,979

 
59,102

 
(79,030
)
 
803,345

Costs and Expenses:
 
 
 
 
 
 
 
 
 
 
 
Exploration and Production Costs
 
 
 
 
 
 
 
 
 
 
 
Lease Operating Expense

 
23,600

 

 

 

 
23,600

Transportation, Gathering and Compression

 
46,699

 

 

 

 
46,699

Production, Ad Valorem, and Other Fees

 
8,033

 

 

 

 
8,033

Direct Administrative and Selling

 
11,725

 

 

 

 
11,725

Depreciation, Depletion and Amortization

 
58,998

 

 

 

 
58,998

Exploration and Production Related Other Costs

 
22,771

 

 

 

 
22,771

Production Royalty Interests and Purchased Gas Costs

 
13,815

 

 

 
(10
)
 
13,805

Other Corporate Expenses

 
26,289

 

 

 

 
26,289

General and Administrative

 
10,177

 

 

 

 
10,177

Total Exploration and Production Costs

 
222,107

 

 

 
(10
)
 
222,097

Coal Costs
 
 
 
 
 
 
 
 
 
 
 
Operating and Other Costs
2,749

 

 
275,068

 

 
50,576

 
328,393

Royalties and Production Taxes

 

 
24,380

 

 

 
24,380

Direct Administrative and Selling

 

 
11,608

 

 

 
11,608

Depreciation, Depletion and Amortization
3,116

 

 
54,149

 

 

 
57,265

Freight Expense

 

 
9,579

 

 

 
9,579

General and Administrative Costs

 

 
8,607

 

 

 
8,607

Other Corporate Expenses
11,145

 

 

 

 

 
11,145

Total Coal Costs
17,010

 

 
383,391

 

 
50,576

 
450,977

Other Costs
 
 
 
 
 
 
 
 
 
 
 
Miscellaneous Operating Expense
33,572

 

 
4,183

 
56,091

 
(18,407
)
 
75,439

General and Administrative Costs

 

 
141

 
235

 

 
376

Depreciation, Depletion and Amortization
172

 

 
785

 
510

 

 
1,467

Interest Expense
52,165

 
2,578

 
1,547

 
13

 
(3
)
 
56,300

Total Other Costs
85,909

 
2,578

 
6,656

 
56,849

 
(18,410
)
 
133,582

Total Costs And Expenses
102,919

 
224,685

 
390,047

 
56,849

 
32,156

 
806,656

Earnings (Loss) Before Income Tax
(24,716
)
 
(1,594
)
 
131,932

 
2,253

 
(111,186
)
 
(3,311
)
Income Taxes
38,935

 
(602
)
 
31,378

 
(853
)
 

 
68,858

(Loss) Income From Continuing Operations
(63,651
)
 
(992
)
 
100,554

 
3,106

 
(111,186
)
 
(72,169
)
Income From Discontinued Operations, net

 

 

 
8,120

 

 
8,120

Net (Loss) Income
(63,651
)
 
(992
)
 
100,554

 
11,226

 
(111,186
)
 
(64,049
)
Less: Net Loss Attributable to Noncontrolling Interests

 
(398
)
 

 

 

 
(398
)
Net (Loss) Income Attributable to CONSOL Energy Shareholders
$
(63,651
)
 
$
(594
)
 
$
100,554

 
$
11,226

 
$
(111,186
)
 
$
(63,651
)


32





Balance Sheet at December 31, 2013:
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Assets:
 
 
 
 
 
 
 
 
 
 
 
Current Assets:
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
$
320,473

 
$
6,238

 
$

 
$
709

 
$

 
$
327,420

Accounts and Notes Receivable:
 
 
 
 
 
 
 
 
 
 
 
Trade

 
71,911

 

 
260,663

 

 
332,574

Notes Receivable
1,238

 

 
24,623

 

 

 
25,861

Other Receivables
17,657

 
207,128

 
14,969

 
4,219

 

 
243,973

Inventories

 
15,185

 
99,320

 
43,409

 

 
157,914

Deferred Income Taxes
219,566

 
(8,263
)
 

 

 

 
211,303

Recoverable Income Taxes
(16,262
)
 
26,967

 

 

 

 
10,705

Prepaid Expenses
43,698

 
65,701

 
24,915

 
1,528

 

 
135,842

Total Current Assets
586,370

 
384,867

 
163,827

 
310,528

 

 
1,445,592

Property, Plant and Equipment:
 
 
 
 
 
 
 
 
 
 
 
Property, Plant and Equipment
173,719

 
6,919,972

 
6,459,014

 
25,804

 

 
13,578,509

Less-Accumulated Depreciation, Depletion and Amortization
122,022

 
1,188,464

 
2,806,775

 
18,986

 

 
4,136,247

Total Property, Plant and Equipment-Net
51,697

 
5,731,508

 
3,652,239

 
6,818

 

 
9,442,262

Other Assets:
 
 
 
 
 
 
 
 
 
 
 
Investment in Affiliates
11,965,054

 
206,060

 
70,222

 

 
(11,949,661
)
 
291,675

Notes Receivable
125

 

 

 

 

 
125

Other
145,401

 
30,728

 
28,831

 
9,053

 

 
214,013

Total Other Assets
12,110,580

 
236,788

 
99,053

 
9,053

 
(11,949,661
)
 
505,813

Total Assets
$
12,748,647

 
$
6,353,163

 
$
3,915,119

 
$
326,399

 
$
(11,949,661
)
 
$
11,393,667

Liabilities and Equity:
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Accounts Payable
$
91,553

 
$
324,226

 
$
89,201

 
$
9,600

 
$

 
$
514,580

Accounts Payable (Recoverable)-Related Parties
4,629,131

 
23,287

 
(5,121,727
)
 
136,822

 
332,487

 

Current Portion of Long-Term Debt
1,029

 
6,258

 
3,372

 
796

 

 
11,455

Short-Term Notes Payable

 
332,487

 

 

 
(332,487
)
 

Other Accrued Liabilities
144,612

 
89,080

 
322,606

 
9,399

 

 
565,697

Current Liabilities of Discontinued Operations

 

 

 
28,239

 

 
28,239

Total Current Liabilities
4,866,325

 
775,338

 
(4,706,548
)
 
184,856

 

 
1,119,971

Long-Term Debt:
3,005,458

 
42,852

 
113,474

 
1,775

 

 
3,163,559

Deferred Credits and Other Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Deferred Income Taxes
(232,904
)
 
475,547

 

 

 

 
242,643

Postretirement Benefits Other Than Pensions

 

 
961,127

 

 

 
961,127

Pneumoconiosis Benefits

 

 
111,971

 

 

 
111,971

Mine Closing

 

 
320,723

 

 

 
320,723

Gas Well Closing

 
119,429

 
56,174

 

 

 
175,603

Workers’ Compensation

 

 
71,136

 
332

 

 
71,468

Salary Retirement
48,252

 

 

 

 

 
48,252

Reclamation

 

 
40,706

 

 

 
40,706

Other
55,227

 
61,190

 
14,938

 

 

 
131,355

Total Deferred Credits and Other Liabilities
(129,425
)
 
656,166

 
1,576,775

 
332

 

 
2,103,848

Total CONSOL Energy Inc. Stockholders’ Equity
5,006,289

 
4,878,807

 
6,931,418

 
139,436

 
(11,949,661
)
 
5,006,289

Total Liabilities and Equity
$
12,748,647

 
$
6,353,163

 
$
3,915,119

 
$
326,399

 
$
(11,949,661
)
 
$
11,393,667






33





Income Statement for the Nine Months Ended September 30, 2014 (unaudited):
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Revenues and Other Income:
 
 
 
 
 
 
 
 
 
 
 
Natural Gas, NGLs and Oil Sales
$

 
$
755,337

 
$

 
$

 
$
(1,938
)
 
$
753,399

Coal Sales

 

 
1,554,939

 

 

 
1,554,939

Other Outside Sales

 

 
28,685

 
184,362

 

 
213,047

Gas Royalty Interests and Purchased Gas Sales

 
68,773

 

 

 

 
68,773

Freight-Outside Coal

 

 
22,551

 

 

 
22,551

Miscellaneous Other Income
329,842

 
51,688

 
106,794

 
7,442

 
(329,951
)
 
165,815

Gain (Loss) on Sale of Assets

 
11,560

 
1,042

 
13

 

 
12,615

Total Revenue and Other Income
329,842

 
887,358

 
1,714,011

 
191,817

 
(331,889
)
 
2,791,139

Costs and Expenses:
 
 
 
 
 
 
 
 
 
 
 
Exploration and Production Costs
 
 
 
 
 
 
 
 
 
 
 
Lease Operating Expense

 
85,622

 

 

 

 
85,622

Transportation, Gathering and Compression

 
179,813

 

 

 

 
179,813

Production, Ad Valorem, and Other Fees

 
28,817

 

 

 

 
28,817

Direct Administrative and Selling

 
39,216

 

 

 

 
39,216

Depreciation, Depletion and Amortization

 
225,766

 

 

 

 
225,766

Exploration and Production Related Other Costs

 
15,765

 

 

 

 
15,765

Production Royalty Interests and Purchased Gas Costs

 
58,531

 

 

 
(12
)
 
58,519

Other Corporate Expenses

 
60,876

 

 

 

 
60,876

General and Administrative

 
47,755

 

 

 

 
47,755

Total Exploration and Production Costs

 
742,161

 

 

 
(12
)
 
742,149

Coal Costs
 
 
 
 
 
 
 
 
 
 
 
Operating and Other Costs
20,060

 

 
995,483

 

 
(1,937
)
 
1,013,606

Royalties and Production Taxes

 

 
77,397

 

 

 
77,397

Direct Administrative and Selling

 

 
33,589

 

 

 
33,589

Depreciation, Depletion and Amortization
472

 

 
185,557

 

 

 
186,029

Freight Expense

 

 
22,551

 

 

 
22,551

General and Administrative Costs

 

 
33,397

 

 

 
33,397

Other Corporate Expenses
41,444

 

 

 

 

 
41,444

Total Coal Costs
61,976

 

 
1,347,974

 

 
(1,937
)
 
1,408,013

Other Costs
 
 
 
 
 
 
 
 
 
 
 
Miscellaneous Operating Expense
63,903

 

 
21,349

 
181,349

 

 
266,601

General and Administrative Costs

 

 
608

 
651

 

 
1,259

Depreciation, Depletion and Amortization
19

 

 
2,437

 
1,429

 

 
3,885

Loss on Debt Extinguishment
95,267

 

 

 

 

 
95,267

Interest Expense
162,729

 
6,593

 
5,120

 
185

 
(4,088
)
 
170,539

Total Other Costs
321,918

 
6,593

 
29,514

 
183,614

 
(4,088
)
 
537,551

Total Costs And Expenses
383,894

 
748,754

 
1,377,488

 
183,614

 
(6,037
)
 
2,687,713

Earnings (Loss) Before Income Tax
(54,052
)
 
138,604

 
336,523

 
8,203

 
(325,852
)
 
103,426

Income Taxes
(143,476
)
 
51,828

 
96,861

 
3,102

 

 
8,315

Income (Loss) From Continuing Operations
89,424

 
86,776

 
239,662

 
5,101

 
(325,852
)
 
95,111

Loss From Discontinued Operations, net

 

 

 
(5,687
)
 

 
(5,687
)
Net Income (Loss) Attributable to CONSOL Energy Shareholders
$
89,424

 
$
86,776

 
$
239,662

 
$
(586
)
 
$
(325,852
)
 
$
89,424






34





Income Statement for the Nine Months Ended September 30, 2013 (unaudited)
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Revenues and Other Income:
 
 
 
 
 
 
 
 
 
 
 
Natural Gas, NGLs and Oil Sales
$

 
$
534,223

 
$
203

 
$

 
$
(2,567
)
 
$
531,859

Coal Sales

 

 
1,532,280

 

 

 
1,532,280

Other Outside Sales

 

 
35,941

 
161,837

 

 
197,778

Gas Royalty Interests and Purchased Gas Sales

 
51,109

 

 

 

 
51,109

Freight-Outside Coal

 

 
31,492

 

 

 
31,492

Miscellaneous Other Income
354,386

 
29,895

 
32,129

 
15,705

 
(354,386
)
 
77,729

Gain (Loss) on Sale of Assets

 
7,159

 
45,049

 

 

 
52,208

Total Revenue and Other Income
354,386

 
622,386

 
1,677,094

 
177,542

 
(356,953
)
 
2,474,455

Costs and Expenses:
 
 
 
 
 
 
 
 
 
 
 
Exploration and Production Costs
 
 
 
 
 
 
 
 
 
 
 
Lease Operating Expense

 
70,835

 

 

 

 
70,835

Transportation, Gathering and Compression

 
144,002

 

 

 

 
144,002

Production, Ad Valorem, and Other Fees

 
20,011

 

 

 

 
20,011

Direct Administrative and Selling

 
34,615

 

 

 

 
34,615

Depreciation, Depletion and Amortization

 
164,832

 

 

 

 
164,832

Exploration and Production Related Other Costs

 
43,666

 

 

 

 
43,666

Production Royalty Interests and Purchased Gas Costs

 
41,196

 

 

 
(31
)
 
41,165

Other Corporate Expenses

 
74,239

 

 

 

 
74,239

General and Administrative

 
29,239

 

 

 

 
29,239

Total Exploration and Production Costs

 
622,635

 

 

 
(31
)
 
622,604

Coal Costs
 
 
 
 
 
 
 
 
 
 
 
Operating and Other Costs
5,878

 

 
874,946

 

 
112,518

 
993,342

Royalties and Production Taxes

 

 
79,257

 

 

 
79,257

Direct Administrative and Selling

 

 
34,744

 

 

 
34,744

Depreciation, Depletion and Amortization
9,193

 

 
160,509

 

 

 
169,702

Freight Expense

 

 
31,492

 

 

 
31,492

General and Administrative Costs

 

 
27,946

 

 

 
27,946

Other Corporate Expenses
43,056

 

 

 

 

 
43,056

Total Coal Costs
58,127

 

 
1,208,894

 

 
112,518

 
1,379,539

Other Costs
 
 
 
 
 
 
 
 
 
 
 
Miscellaneous Operating Expense
101,711

 

 
34,188

 
165,859

 
(29,412
)
 
272,346

General and Administrative Costs

 

 
474

 
795

 

 
1,269

Depreciation, Depletion and Amortization
542

 

 
2,269

 
1,492

 

 
4,303

Interest Expense
153,141

 
6,375

 
4,868

 
34

 
(224
)
 
164,194

Total Other Costs
255,394

 
6,375

 
41,799

 
168,180

 
(29,636
)
 
442,112

Total Costs And Expenses
313,521

 
629,010

 
1,250,693

 
168,180

 
82,851

 
2,444,255

Earnings (Loss) Before Income Tax
40,865

 
(6,624
)
 
426,401

 
9,362

 
(439,804
)
 
30,200

Income Taxes
118,606

 
(2,557
)
 
(14,976
)
 
(3,542
)
 

 
97,531

(Loss) Income From Continuing Operations
(77,741
)
 
(4,067
)
 
441,377

 
12,904

 
(439,804
)
 
(67,331
)
Loss From Discontinued Operations, net

 

 

 
(11,352
)
 

 
(11,352
)
Net (Loss) Income
(77,741
)
 
(4,067
)
 
441,377

 
1,552

 
(439,804
)
 
(78,683
)
Less: Net Loss Attributable to Noncontrolling Interests

 
(942
)
 

 

 

 
(942
)
Net (Loss) Income Attributable to CONSOL Energy Shareholders
$
(77,741
)
 
$
(3,125
)
 
$
441,377

 
$
1,552

 
$
(439,804
)
 
$
(77,741
)




35







Cash Flow for the Nine Months Ended September 30, 2014 (unaudited):
 
Parent
 
CNX Gas
Guarantor
 
Other Subsidiary Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Net Cash Provided by (Used In) Continuing Operations

$
(87,081
)
 
$
512,135

 
$
191,233

 
$
21,155

 
$
233,663

 
$
871,105

Net Cash Used in Discontinued Operating Activities

 

 

 
(20,934
)
 

 
(20,934
)
Net Cash Provided by (Used In) Operating Activities
$
(87,081
)
 
$
512,135

 
$
191,233

 
$
221

 
$
233,663

 
$
850,171

Cash Flows from Investing Activities:
 
 
 
 
 
 
 
 
 
 
 
Capital Expenditures
$
(2,314
)
 
$
(852,097
)
 
$
(320,196
)
 
$

 
$

 
$
(1,174,607
)
Proceeds From Sales of Assets
(15,941
)
 
57,919

 
99,145

 
13

 

 
141,136

Net Investments in Equity Affiliates

 
79,723

 
28,809

 

 

 
108,532

Net Cash (Used in) Provided by Continuing Operations
(18,255
)
 
(714,455
)
 
(192,242
)
 
13

 

 
(924,939
)
Net Cash Used in Discontinued Investing Activities

 

 

 

 

 

Net Cash (Used in) Provided by Investing Activities
$
(18,255
)
 
$
(714,455
)
 
$
(192,242
)
 
$
13

 
$

 
$
(924,939
)
Cash Flows from Financing Activities:
 
 
 
 
 
 
 
 
 
 
 
(Payments on) Proceeds from Short-Term Borrowings
$
(11,736
)
 
$
233,663

 
$

 
$

 
$
(233,663
)
 
$
(11,736
)
Payments on Miscellaneous Borrowings
(662
)
 

 
(3,451
)
 
(56
)
 

 
(4,169
)
Proceeds from Long-Term Borrowings
1,859,920

 

 

 

 

 
1,859,920

Payments on Long-Term Borrowings
(1,843,866
)
 

 

 

 

 
(1,843,866
)
Tax Benefit from Stock-Based Compensation
2,478

 

 

 

 

 
2,478

Dividends Paid
(43,119
)
 

 

 

 

 
(43,119
)
Proceeds from Issuance of Common Stock
13,403

 

 

 

 

 
13,403

Other Financing Activities

 
(4,460
)
 
4,460

 

 

 

Net Cash (Used in) Provided by Continuing Operations
(23,582
)
 
229,203

 
1,009

 
(56
)
 
(233,663
)
 
(27,089
)
Net Cash Used in Discontinued Financing Activities

 

 

 

 

 

Net Cash (Used in) Provided by Financing Activities
$
(23,582
)
 
$
229,203

 
$
1,009

 
$
(56
)
 
$
(233,663
)
 
$
(27,089
)




















36






Cash Flow for the Nine Months Ended September 30, 2013 (unaudited):
 
 
Parent
 
CNX Gas
Guarantor
 
Other Subsidiary Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Net Cash Provided by (Used in) Continuing Operations

$
(7,909
)
 
$
383,504

 
$
139,014

 
$
(102,139
)
 
$
38,500

 
$
450,970

Net Cash Provided by Discontinued Operating Activities

 

 

 
138,029

 

 
138,029

Net Cash Provided by (Used in) Operating Activities
$
(7,909
)
 
$
383,504

 
$
139,014

 
$
35,890

 
$
38,500

 
$
588,999

Cash Flows from Investing Activities:
 
 
 
 
 
 
 
 
 
 
 
Capital Expenditures
$
(15,216
)
 
$
(669,067
)
 
$
(336,844
)
 
$

 
$

 
$
(1,021,127
)
Change in Restricted Cash


 

 
56,410

 

 

 
56,410

Proceeds From Sales of Assets

 
335,142

 
129,479

 
17

 

 
464,638

Net Investments in Equity Affiliates

 
(30,500
)
 
12,388

 

 

 
(18,112
)
Net Cash (Used in) Provided by Continuing Operations
(15,216
)
 
(364,425
)
 
(138,567
)
 
17

 

 
(518,191
)
Net Cash Used in Discontinued Investing Activities

 

 

 
(41,246
)
 

 
(41,246
)
Net Cash Used in Investing Activities
$
(15,216
)
 
$
(364,425
)
 
$
(138,567
)
 
$
(41,229
)
 
$

 
$
(559,437
)
Cash Flows from Financing Activities:
 
 
 
 
 
 
 
 
 
 
 
Proceeds from (Payments on) Short-Term Borrowings
$

 
$
85,500

 
$

 
$

 
$
(38,500
)
 
$
47,000

Payments on Miscellaneous Borrowings
(26,591
)
 

 
(4,690
)
 
(577
)
 

 
(31,858
)
Proceeds from Securitization Facility

 

 

 
6,518

 

 
6,518

Tax Benefit from Stock-Based Compensation
2,316

 

 

 

 

 
2,316

Dividends (Paid) Received
42,789

 
(100,000
)
 

 

 

 
(57,211
)
Proceeds from Issuance of Common Stock
2,698

 

 

 

 

 
2,698

Proceeds from Issuance of Treasury Stock
609

 

 

 

 

 
609

Capital Lease Payments

 
(4,084
)
 
4,084

 

 

 

Net Cash (Used in) Provided by Continuing Operations
21,821

 
(18,584
)
 
(606
)
 
5,941

 
(38,500
)
 
(29,928
)
Net Cash Used in Discontinued Financing Activities

 

 

 
(432
)
 

 
(432
)
Net Cash (Used in) Provided by Financing Activities
$
21,821

 
$
(18,584
)
 
$
(606
)
 
$
5,509

 
$
(38,500
)
 
$
(30,360
)


37





Statement of Comprehensive Income for the Three Months Ended September 30, 2014 (unaudited):

 
Parent
 
CNX Gas
Guarantor
 
Other Subsidiary Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Net (Loss) Income
$
(1,645
)
 
$
24,405

 
$
39,505

 
$
2,422

 
$
(66,332
)
 
$
(1,645
)
Other Comprehensive Income (Loss):
 
 
 
 
 
 
 
 
 
 
 
 Actuarially Determined Long-Term Liability Adjustments
184,154

 

 
184,154

 

 
(184,154
)
 
184,154

 Net Increase (Decrease) in the Value of Cash Flow Hedge
39,151

 
39,151

 

 

 
(39,151
)
 
39,151

 Reclassification of Cash Flow Hedge from OCI to Earnings
(19,510
)
 
(19,510
)
 

 

 
19,510

 
(19,510
)
Other Comprehensive Income (Loss):
203,795

 
19,641

 
184,154

 

 
(203,795
)
 
203,795

Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
$
202,150

 
$
44,046

 
$
223,659

 
$
2,422

 
$
(270,127
)
 
$
202,150



Statement of Comprehensive Income for the Three Months Ended September 30, 2013 (unaudited):

 
Parent
 
CNX Gas
Guarantor
 
Other Subsidiary Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Net (Loss) Income
$
(63,651
)
 
$
(992
)
 
$
100,554

 
$
11,226

 
$
(111,186
)
 
$
(64,049
)
Other Comprehensive Income (Loss):
 
 
 
 
 
 
 
 
 
 
 
 Actuarially Determined Long-Term Liability Adjustments
24,980

 

 
24,980

 

 
(24,980
)
 
24,980

 Net Increase (Decrease) in the Value of Cash Flow Hedge
13,246

 
13,246

 

 

 
(13,246
)
 
13,246

 Reclassification of Cash Flow Hedge from OCI to Earnings
(24,354
)
 
(24,354
)
 

 

 
24,354

 
(24,354
)
Other Comprehensive Income (Loss):
13,872

 
(11,108
)
 
24,980

 

 
(13,872
)
 
13,872

Comprehensive Loss (Income)
(49,779
)
 
(12,100
)
 
125,534

 
11,226

 
(125,058
)

(50,177
)
  Less: Comprehensive (Loss) Attributable to Noncontrolling Interest

 
(398
)
 

 

 

 
(398
)
Comprehensive Loss (Income) Attributable to CONSOL Energy Inc. Shareholders
$
(49,779
)
 
$
(11,702
)
 
$
125,534

 
$
11,226

 
$
(125,058
)
 
$
(49,779
)




38





Statement of Comprehensive Income for the Nine Months Ended September 30, 2014 (unaudited):

 
Parent
 
CNX Gas
Guarantor
 
Other Subsidiary Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Net Income (Loss)
$
89,424

 
$
86,776

 
$
239,662

 
$
(586
)
 
$
(325,852
)
 
$
89,424

Other Comprehensive Income (Loss):
 
 


 


 


 


 
 
  Actuarially Determined Long-Term Liability Adjustments
185,475

 

 
185,475

 

 
(185,475
)
 
185,475

  Net (Decrease) Increase in the Value of Cash Flow Hedge
(20,032
)
 
(20,032
)
 

 

 
20,032

 
(20,032
)
  Reclassification of Cash Flow Hedge from OCI to Earnings
3,754

 
3,754

 

 

 
(3,754
)
 
3,754

Other Comprehensive Income (Loss):
169,197


(16,278
)

185,475




(169,197
)
 
169,197

Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
$
258,621


$
70,498


$
425,137


$
(586
)

$
(495,049
)
 
$
258,621


Statement of Comprehensive Income for the Nine Months Ended September 30, 2013 (unaudited):

 
Parent
 
CNX Gas
Guarantor
 
Other Subsidiary Guarantors
 
Non-
Guarantors
 
Elimination
 
Consolidated
Net (Loss) Income
$
(77,741
)
 
$
(4,067
)
 
$
441,377

 
$
1,552

 
$
(439,804
)
 
$
(78,683
)
Other Comprehensive Income (Loss):
 
 
 
 
 
 
 
 
 
 
 
  Actuarially Determined Long-Term Liability Adjustments
113,641

 

 
113,641

 

 
(113,641
)
 
113,641

  Net Increase (Decrease) in the Value of Cash Flow Hedge
40,400

 
40,400

 

 

 
(40,400
)
 
40,400

  Reclassification of Cash Flow Hedge from OCI to Earnings
(56,595
)
 
(56,595
)
 

 

 
56,595

 
(56,595
)
Other Comprehensive Income (Loss):
97,446

 
(16,195
)
 
113,641

 

 
(97,446
)
 
97,446

Comprehensive Income (Loss)
19,705

 
(20,262
)
 
555,018

 
1,552

 
(537,250
)
 
18,763

  Less: Comprehensive (Loss) Attributable to Noncontrolling Interest

 
(942
)
 

 

 

 
(942
)
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
$
19,705

 
$
(19,320
)
 
$
555,018

 
$
1,552

 
$
(537,250
)
 
$
19,705


NOTE 17—RELATED PARTY TRANSACTIONS:
CONE Midstream Partners LP
On September 30, 2014, CONE Midstream Partners, LP (the Partnership) closed its initial public offering of 20,125,000 common units representing limited partnership interests at a price to the public of $22.00 per unit, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters. The Partnership's general partner is CONE Midstream GP LLC, a wholly owned subsidiary of CONE Gathering LLC (CONE).
As a result of the IPO filing, the Partnership received net proceeds of $412,741 from the offering, after deducting underwriting discounts and commissions, and structuring fees of $28,779 along with additional estimated offering expenses of approximately $1,230. Of the proceeds received, $203,986 was distributed to both CNX Gas Company LLC ("CNX Gas Company"), and Noble Energy on September 30, 2014.
During the nine months ended September 30, 2014, CONE provided CNX Gas Company gathering services in the ordinary course of business. Gathering services received from CONE were $17,794 and $44,001 for the three and nine months ended September 30, 2014, respectively, and were $9,689 and $24,470 for the three and nine months ended September 30, 2013, respectively, which were included in Exploration and Production Costs - Transportation, Gathering and Compression on the Consolidated Statements of Income.
As of September 30, 2014 and December 31, 2013, CONSOL Energy had a net payable of $11,435 and $5,448, respectively, due to CONE which was comprised of the following items:


39





 
September 30,
 
December 31,
 
 
 
2014
 
2013
 
Location on Balance Sheet
Reimbursement for CONE Expenses
$
(913
)
 
$
(2,168
)
 
Accounts Receivable–Other
Reimbursement for Services Provided to CONE
(122
)
 
(265
)
 
Accounts Receivable–Other
CONE Gathering Capital Reimbursement
(2,789
)
 

 
Accounts Receivable–Other
CONE Gathering Fee Payable
15,259

 
7,881

 
Accounts Payable
Net Payable due to CONE
$
11,435

 
$
5,448

 
 

NOTE 18—RECENT ACCOUNTING PRONOUNCEMENTS:

In June 2014, the Financial Accounting Standards Board (FASB) issued Update 2014-12 - Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. The objective of the amendments in this update is to resolve the diverse accounting treatment of share-based payment awards. The amendments in this update apply to all reporting entities that grant their employees share-based payments in which the terms of the award provide that a performance target that affects vesting could be achieved after the requisite service period. The amendments require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in either (i) the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered or (ii) if the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period will reflect the number of awards that are expected to vest and will be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in this update are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in this update either (a) prospectively to all awards granted or modified after the effective date or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. We are currently still evaluating the impact this guidance may have on our operations.

In May 2014, the Financial Accounting Standards Board issued Update 2014-09 - Revenue from Contracts with Customers (Topic 606). The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance for accounting principles generally accepted in the United States (U.S. GAAP) and International Financial Reporting Standards (IFRS). The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity should disclose sufficient information, both qualitative and quantitative, to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

In April 2014, the Financial Accounting Standards Board issued Update 2014-08 - Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The objective of the amendments in this update is to change the criteria for reporting discontinued operations and enhance convergence of the FASB's and the International Accounting Standards Board's (IASB) reporting requirements for discontinued operations. The amendments in this update change the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity, or a business or nonprofit activity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amendments in this update require an entity to present, for each comparative period, the assets and liabilities of a disposal group that includes a discontinued operation separately in the asset and liability sections, respectively, of the statement of financial position. The amendments in this update also require additional disclosures about discontinued operations. Public business entities must apply the amendments in this update prospectively to both of the following: (1) All disposals (or classifications as held for sale) of components of an entity that


40





occur within annual periods beginning on or after December 15, 2014, and interim periods within those years; (2) All businesses or nonprofit activities that, on acquisition, are classified as held for sale that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

NOTE 19 - SUBSEQUENT EVENTS:

In October 2014, CONSOL Energy sold various non-strategic assets, including various coal reserves and investments in equity affiliates, for total cash proceeds of approximately $71,000 and a note receivable for approximately $12,000. The financial gain for these transactions is approximately $14,000.
 




41






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

E&P Marketing and Transportation Update:

Third quarter 2014 average dry gas prices, including the impact of our hedging program and net of basis, averaged $3.60 per Mcf. CONSOL's expansion into wet gas production areas provided a liquids value uplift of $0.37 per Mcfe, bringing the overall average sales price to $3.97 per Mcfe. Third quarter 2014 liquids volumes of 6.3 Bcfe were over six times greater than the 2013 third quarter and made up 10% of the company’s total volumes compared with 2% in the third quarter of last year. CONSOL Energy expects to continue to realize liquids uplift on future average sales prices as additional wells are brought online in the liquid-rich areas of the Marcellus and Utica shales.

Faster-than-expected replenishment of gas inventories and increasing Marcellus production have put downward pressure on gas prices. These factors have contributed to a decline in the NYMEX index price for natural gas along with the basis differentials for most Appalachian market sales points. CONSOL Energy continues to mitigate the effect of the current downward basis pressure by finding opportunities to optimize and diversify sales opportunities among our 80+ customers located in five index markets. In addition, CONSOL Energy continues to manage the impact of price volatility through an actively-monitored hedge program.

CONSOL Energy continues to develop a diversified portfolio of firm transportation capacity to support the three-year production growth plan. In September 2014, the company entered into a precedent agreement with DTE Energy and Spectra Energy for its Nexus project as an anchor shipper to transport gas from the Appalachian Basin to Midwest markets. The pipeline is expected to be placed into service in late 2017.

The Company currently has a total of 1.4 Bcf per day of effective firm transportation capacity. This capacity is adequate for the remainder of 2014 and supports the majority of projected volumes for the three-year growth plan. This is comprised of 0.7 Bcf per day of firm capacity on existing pipelines, contracted volumes of 0.5 Bcf per day under precedent agreements with several pipeline projects (including the Nexus project) that will be completed over the next few years, and an additional 0.2 Bcf per day of long-term firm sales with major customers that have their own firm capacity. The average demand cost for the existing firm capacity is approximately $0.23 per MMBtu. The average demand cost for existing, plus future, firm capacity is approximately $0.32 per MMBtu.

In addition to firm transportation capacity, CONSOL Energy has developed a processing portfolio that supports the increasing volumes from our wet production areas. The company has agreements to support the processing of 211 MMcf per day of gross gas volumes growing to more than 380 MMcf per day in the next twelve months. These commitments are sufficient to cover projected processing requirements for the next two years. CONSOL Energy will continue to layer in processing capacity as needed to support the liquids development plan.

In addition to establishing a solid processing portfolio, CONSOL Energy is developing a diversified approach to managing ethane. The company has entered into supply agreements with INEOS Europe and also expects to supply volumes to Shell's cracker plant in Monaca, Pennsylvania. CONSOL Energy is actively negotiating to supply ethane to other proposed regional cracker facilities. In addition to term sales, the company executed several spot deals to move ethane to Mont Belvieu via the ATEX pipeline. CONSOL will also realize ethane value through blending capabilities. Employing this multi-faceted approach enables us to meet pipeline quality specifications, diversify the ethane portfolio, and maximize our ethane pricing. CONSOL Energy is in active discussions with a number of ethane customers and midstream companies for future outlet opportunities.

Coal Marketing Update:

In the third quarter, CONSOL Energy sold 1 million tons of Buchanan low volatile coal. Despite the recent decrease in the BHP Billiton Mitsubishi Alliance (BMA) settlement price, Buchanan’s low cost position allows the mine to compete, and remain profitable, in the current domestic and worldwide metallurgical markets.  CONSOL Energy continues to ship low-vol coal to European and South American end users. CONSOL Energy does continue to focus on expanding domestic metallurgical sales and recently secured additional new contracts with U.S. customers for 2015.

Also in the third quarter, CONSOL Energy exported 200,000 tons of Bailey high-vol coal to existing end users in Korea and Brazil. Prices for high volatile coal remains more stable than other classes of metallurgical coal. End users continue to demand Bailey coal due to its versatility, which allows it to compete as high volatile metallurgical, pulverized coal injection (PCI) and high-Btu thermal coal.


42





As winter approaches, CONSOL Energy believes that domestic utility market demand, buoyed by utility inventories remaining below normal levels, will support continued spot market and term contracting activity. As CONSOL Energy contracts Bailey coal’s 2015 production, the company is dedicated to placing the tons in markets that provide the most value. For the third quarter of 2014, CONSOL Energy completed sales to six different customers for 2.4 million tons and is currently in negotiations for additional domestic and export shipments end users.

CONSOL Energy 2014 - 2016 Guidance:

Fourth quarter gas production, net to CONSOL Energy, is expected to be approximately 70 – 75 Bcfe. If achieved, this would result in 2014 production of approximately 235 – 240 Bcfe. CONSOL Energy continues to expect its 2015 and 2016 annual gas production to grow by 30%.

As of October 31, 2014, the carry with Noble Energy is suspended and it will remain suspended until average Henry Hub natural gas prices are above $4.00 per million British thermal units (MMBtu) for three consecutive months.

CONSOL Energy’s hedging strategy and formulaic approach for its natural gas portfolio requires entering into hedges that meet certain short and long-term internal pricing parameters. Due to the quantities and types of hedges in place during the quarter, as well as the then-expected future gas prices, CONSOL Energy's hedge position met company requirements, and the company did not add any new hedges during the quarter. The annual gas hedge position for three years is shown in the table below:

E&P DIVISION GUIDANCE
 
 
2014
 
2015
 
2016
Total Yearly Production (Bcfe) / % growth
 
235-240
 
+30%
 
+30%
Volumes Hedged (Bcf),as of 10/14/14
 
159.9*
 
82.6
 
75.3
Average Hedge Price ($/Mcf)
 
$4.58
 
$4.07
 
$4.17
* Includes 2014 Actual Settlements of 118.2 Bcf.

The hedged gas volumes shown in the previous table include the following NYMEX hedges that have basis hedged as well.

NYMEX PLUS BASIS HEDGES
 
 
 
 
 
 
 
 
 
Q4 2014
 
2015
 
2016
Columbia (TCO)
 
 
 
 
 
 
      Volume (Bcf)
 
10.7
 
35.9
 
39.4
Average Hedge Price ($/Mcf)
 
$4.02
 
$3.86
 
$3.93
Dominion South (DTI)
 
 
 
 
 
 
       Volume (Bcf)
 
1.7
 
-
 
-
Average Hedge Price ($/Mcf)
 
$5.31
 
-
 
-

COAL DIVISION GUIDANCE

In coal, the lower end of the low-vol guidance range for 2014 has increased slightly to reflect new Atlantic market business, which the company believes will be ongoing. This shift illustrates the expansion of the Buchanan product into new markets. For 2015, the low-vol guidance was left unchanged from the previous guidance on the assumption that pricing will improve from current levels. The thermal guidance range for 2014 has remained relatively flat.



43





 
 
Q4 2014

 
2014

 
2015

     Est. Total Coal Sales
 
8.0 - 8.4

 
32.3 - 32.7

 
31.0 - 35.0

       Tonnage: Firm
 
8.1

 
32.4

 
21.1

       Price: Sold (firm)
 
$
62.21

 
$
63.28

 
$
64.19

     Est. Low-Vol Met Sales
 
0.7 - 0.9

 
3.7 - 3.9

 
3.5 - 5.0

       Tonnage: Firm
 
0.7

 
3.7

 
1.0

     Est. High-Vol Met Sales
 
0.3

 
1.3

 
1.9

       Tonnage: Firm
 
0.2

 
1.2

 
0.3

     Est. Thermal Sales
 
7.0 - 7.2

 
27.3 - 27.5

 
25.6 - 28.1

       Tonnage: Firm
 
7.2

 
27.5

 
19.8

Note: While most of the data in the table are single point estimates, the inherent uncertainty of markets and mining operations means that investors should consider a reasonable range around these estimates. CONSOL Energy has chosen not to forecast prices for open tonnage due to ongoing customer negotiations. Firm tonnage is tonnage that is both sold and priced, and excludes collared tons. CONSOL Energy has sold additional coal volumes that are not yet priced. Those volumes are excluded from this table. There are no collared tons in 2014 or 2015.  Not included in the category breakdowns are the thermal tons from equity affiliate Harrison Resources and high vol and thermal tons from Western Allegheny Energy (WAE). Harrison Resources has 0.3 million tons for 2014. WAE has 0.5 million tons and 0.6 million tons for all of 2014, and 2015, respectively.
 




44


Results of Operations
Three Months Ended September 30, 2014 Compared with Three Months Ended September 30, 2013

Net Loss Attributable to CONSOL Energy Shareholders
CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $2 million, or a loss of $0.01 per diluted share, for the three months ended September 30, 2014, compared to a net loss attributable to CONSOL Energy shareholders of $64 million, or a loss of $0.28 per diluted share, for the three months ended September 30, 2013. Net loss attributable to CONSOL Energy shareholders for the three months ended September 30, 2013 included a loss from continuing operations of $72 million, or a loss of $0.31 per diluted share, and income from discontinued operations of $8 million, or income of $0.03 per diluted share.

The total Exploration and Production (E&P) division includes Marcellus, coalbed methane (CBM), shallow oil and gas, and other gas. The total E&P division contributed income of $38 million before income tax for the three months ended September 30, 2014 compared to a loss of $2 million before income tax for the three months ended September 30, 2013. Total E&P production was 64.9 Bcfe for the three months ended September 30, 2014 compared to 46.1 Bcfe for the three months ended September 30, 2013.

The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s production and sales portfolio:
 
 
For the Three Months Ended September 30,
 in thousands (unless noted)
 
2014
 
2013
 
Variance
 
Percent
Change
LIQUIDS
 
 
 
 
 
 
 
 
NGLs:
 
 
 
 
 
 
 
 
Sales Volume (MMcfe)
 
5,330

 
740

 
4,590

 
620.3
 %
Sales Volume (Mbbls)
 
888

 
123

 
765

 
622.0
 %
Gross Price ($/Bbl)
 
$
36.00

 
$
42.54

 
$
(6.54
)
 
(15.4
)%
Gross Revenue
 
$
31,952

 
$
5,241

 
$
26,711

 
509.7
 %
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
Sales Volume (MMcfe)
 
183

 
148

 
35

 
23.6
 %
Sales Volume (Mbbls)
 
31

 
25

 
6

 
24.0
 %
Gross Price ($/Bbl)
 
$
90.12

 
$
99.24

 
$
(9.12
)
 
(9.2
)%
Gross Revenue
 
$
2,750

 
$
2,441

 
$
309

 
12.7
 %
 
 
 
 
 
 
 
 
 
Condensate:
 
 
 
 
 
 
 
 
Sales Volume (MMcfe)
 
815

 
72

 
743

 
1,031.9
 %
Sales Volume (Mbbls)
 
136

 
12

 
124

 
1,033.3
 %
Gross Price ($/Bbl)
 
$
87.96

 
$
95.28

 
$
(7.32
)
 
(7.7
)%
Gross Revenue
 
$
11,950

 
$
1,139

 
$
10,811

 
949.2
 %
 
 
 
 
 
 
 
 
 
GAS
 
 
 
 
 
 
 
 
Sales Volume (MMcf)
 
58,585

 
45,128

 
13,457

 
29.8
 %
Sales Price ($/Mcf)
 
$
3.24

 
$
3.49

 
$
(0.25
)
 
(7.2
)%
Hedging Impact ($/Mcf)
 
$
0.36

 
$
0.60

 
$
(0.24
)
 
(40.0
)%
Gross Revenue including Hedging Impact
 
$
211,190

 
$
184,561

 
$
26,629

 
14.4
 %
    








45



The average sales price and average costs for all active E&P operations were as follows: 
 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Average Sales Price (per Mcfe)
$
3.97

 
$
4.20

 
$
(0.23
)
 
(5.5
)%
Average Costs (per Mcfe)
3.12

 
3.23

 
(0.11
)
 
(3.4
)%
Margin
$
0.85

 
$
0.97

 
$
(0.12
)
 
(12.4
)%

Total E&P division Natural Gas, NGLs, and Oil sales revenues were $258 million for the three months ended September 30, 2014 compared to $193 million for the three months ended September 30, 2013. The increase was primarily due to the 40.8% increase in total volumes sold offset, in part, by the 5.5% decrease in average price per Mcfe. The decrease in average sales price was primarily due to a $0.25 per Mcf decrease in general market prices for natural gas and a $0.24 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 41.7 Bcf of our produced gas sales volumes for the three months ended September 30, 2014 at an average gain of $0.51 per Mcf. These financial hedges represented approximately 24.0 Bcf of our produced gas sales volumes for the three months ended September 30, 2013 at an average gain of $1.12 per Mcf. The decreases due to general market prices and our hedging program were offset, in part, by the $0.26 per Mcfe increase in sales of NGLs, oil and condensate.

Changes in the average cost per Mcfe of gas sold were primarily related to the following items:
The improvement in unit costs is primarily due to the increase in volumes in the period-to-period comparison and the shift to lower cost Marcellus production. Marcellus production made up 47% of gas sales volume for the three months ended September 30, 2014 compared to 38% in the three months ended September 30, 2013
The decrease to lifting costs on a per unit basis due to the increase in sales volumes was offset, in part, by an increase in total dollars relating to higher salt water disposal, and well site maintenance costs.
The decrease to ad valorem, severance, and other taxes on a per unit basis due to the increase in sales volumes was offset, in part, by an increase in total dollars from the increase in volumes sold and the mix of volumes by state.
The decrease to depreciation, depletion and amortization on a per unit basis due to the increase in gas sales volume was offset, in part, by an increase in total dollars as the portion of production from higher investment cost segments continued to grow.
Gathering expense per unit increased in the period-to-period comparison due to increased firm transportation costs and increased processing fees associated with natural gas liquids. The increase in unit costs was partially offset by the increase in sales volumes.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $53 million of earnings before income tax for the three months ended September 30, 2014 compared to $64 million for the three months ended September 30, 2013. The total coal division sold 7.8 million tons of coal produced from CONSOL Energy mines for the three months ended September 30, 2014 compared to 6.9 million tons for the three months ended September 30, 2013. Current period sales tons were comprised of 85% thermal and 15% metallurgical. Prior period sales tons were comprised of 78% thermal and 22% metallurgical.
The average sales price and average cost of goods sold per ton for continuing coal operations were as follows:
 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Average Sales Price per ton sold
$
62.32

 
$
68.23

 
$
(5.91
)
 
(8.7
)%
Average Costs of Goods Sold per ton
49.93

 
50.70

 
(0.77
)
 
(1.5
)%
Margin
$
12.39

 
$
17.53

 
$
(5.14
)
 
(29.3
)%

The lower average sales price per ton sold reflects a continuing decline in the global metallurgical coal markets, an oversupply in coal used in steelmaking, and lower thermal coal pricing due to the continuing roll-off of some higher-priced legacy contracts. The coal division priced 1.3 million tons on the export market at an average sales price of $65.15 per ton for the three months ended September 30, 2014 compared to 1.8 million tons at an average price of $70.48 per ton for the three months ended September 30, 2013. All other tons were sold on the domestic market.



46


The decrease in the average cost of goods sold per ton was primarily attributable to the increase in tons sold, as well as the decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014. The decrease was offset, in part, by geologic issues at the Enlow Fork Mine and Harvey Mine.
The other segment includes industrial supplies activity, coal terminal activity, income taxes and other business activities not assigned to the E&P or Coal division.
General and Administrative costs are allocated between divisions (E&P, Coal and Other) based primarily on percentage of total revenue and percentage of total projected capital expenditures. General and Administrative costs are excluded from the E&P and Coal unit costs above. Total General and Administrative costs were made up of the following items:
 
For the Three Months Ended September 30,
 (in millions)
2014
 
2013
 
Variance
 
Percent
Change
Continuing Operations General and Administrative Expenses
$
26

 
$
19

 
$
7

 
36.8
 %
Discontinued Operations General and Administrative Expenses

 
9

 
(9
)
 
(100.0
)%
Total Company General and Administrative Expense
$
26

 
$
28

 
$
(2
)
 
(7.1
)%

Overall, total Company General and Administrative Expenses decreased $2 million in the period-to-period comparison. This was primarily due to reduced staffing and cost control projects following the December 2013 sale of five of our West Virginia coal mines. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.

Total Company long-term liabilities for continuing operations, such as OPEB, the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy continuing operations expense related to our actuarial liabilities was $36 million for the three months ended September 30, 2014 compared to $33 million for the three months ended September 30, 2013. The increase of $3 million for total CONSOL Energy continuing operations expense was primarily due to an increase in the discount rate assumptions used to calculate expense for benefit plans at the measurement date, which is December 31, partially offset by required pension settlement accounting which resulted in $5 million of expense during three months ended September 30, 2014 and $6 million of expense in three months ended September 30, 2013. Pension settlement accounting is required when lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. Not included in the long-term liability expense totals discussed above are curtailment gains of $36 million, and $46 million of expense for cash payments made to active employees both of which arose from modifications to the OPEB and Pension plans during the three months ended September 30, 2014. The pension settlement expense, cash payments and curtailment gains were not allocated to individual operating segments and are therefore not included in unit costs presented for the E&P or Coal divisions. See Note 4 - Pension and Other Post-Employment Benefit Plans and Note 5 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional detail of the total Company expense.



47


TOTAL E&P SEGMENT ANALYSIS for the three months ended September 30, 2014 compared to the three months ended September 30, 2013:
The E&P segment contributed $38 million to earnings before income tax for the three months ended September 30, 2014 compared to a loss before income tax of $2 million in the three months ended September 30, 2013. Variances by the individual E&P segments are discussed below.
 
For the Three Months Ended
 
Difference to Three Months Ended
 
September 30, 2014
 
September 30, 2013
 (in millions)
Marcellus
 
CBM
 
Shallow Oil and Gas
 
Other
Gas
 
Total E&P
 
Marcellus
 
CBM
 
Shallow Oil and Gas
 
Other
Gas
 
Total
E&P
Sales:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Produced
$
110

 
$
82

 
$
25

 
$
40

 
$
257

 
$
38

 
$
(1
)
 
$
(8
)
 
$
36

 
$
65

Related Party

 
1

 

 

 
1

 

 

 

 

 

Total Outside Sales
110

 
83

 
25

 
40

 
258

 
38

 
(1
)
 
(8
)
 
36

 
65

Gas Royalty Interest

 

 

 
18

 
18

 

 

 

 
3

 
3

Purchased Gas

 

 

 
1

 
1

 

 

 

 
(1
)
 
(1
)
Other Income

 

 

 
19

 
19

 

 

 

 
6

 
6

Total Revenue and Other Income
110

 
83

 
25

 
78

 
296

 
38

 
(1
)
 
(8
)
 
44

 
73

Lifting
6

 
9

 
11

 
4

 
30

 
1

 
1

 
2

 
3

 
7

Ad Valorem, Severance, and Other Taxes
5

 
3

 
1

 
(1
)
 
8

 
2

 

 
(1
)
 
(1
)
 

Gathering
29

 
27

 
7

 
5

 
68

 
18

 
(1
)
 

 
4

 
21

E&P Direct Administrative, Selling & Other
9

 
2

 
1

 
2

 
14

 
3

 

 
(1
)
 

 
2

Depreciation, Depletion and Amortization
34

 
22

 
14

 
13

 
83

 
15

 

 
(1
)
 
10

 
24

General & Administration

 

 

 
15

 
15

 

 

 

 
5

 
5

Gas Royalty Interest

 

 

 
15

 
15

 

 

 

 
2

 
2

Purchased Gas

 

 

 
1

 
1

 

 

 

 

 

Exploration and Other Costs

 

 

 
8

 
8

 

 

 

 
(15
)
 
(15
)
Other Corporate Expenses

 

 

 
13

 
13

 

 

 

 
(13
)
 
(13
)
Interest Expense

 

 

 
3

 
3

 

 

 

 

 

Total Cost
83

 
63

 
34

 
78

 
258

 
39

 

 
(1
)
 
(5
)
 
33

Earnings Before Income Tax
$
27

 
$
20

 
$
(9
)
 
$

 
$
38

 
$
(1
)
 
$
(1
)
 
$
(7
)
 
$
49

 
$
40




48



MARCELLUS GAS SEGMENT
The Marcellus segment contributed $27 million to the total Company earnings before income tax for the three months ended September 30, 2014 compared to $28 million for the three months ended September 30, 2013.
 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Marcellus Gas - Gas Sales Volumes (Bcf)
27.0

 
16.5

 
10.5

 
63.6
 %
NGLs Sales Volumes (Bcfe)*
3.3

 
0.8

 
2.5

 
312.5
 %
Condensate Sales Volumes (Bcfe)*
0.4

 
0.1

 
0.3

 
300.0
 %
Total Marcellus Gas Sales Volumes (Bcfe)*
30.7

 
17.4

 
13.3

 
76.4
 %
 
 
 
 
 
 
 


Average Sales Price - Gas (Mcf)
$
2.83

 
$
3.56

 
$
(0.73
)
 
(20.5
)%
Hedging Impact - Gas (Mcf)
$
0.39

 
$
0.43

 
$
(0.04
)
 
(9.3
)%
Average Sales Price - NGLs (Mcfe)*
$
5.34

 
$
7.09

 
$
(1.75
)
 
(24.7
)%
Average Sales Price - Condensate (Mcfe)*
$
14.52

 
$
16.29

 
$
(1.77
)
 
(10.9
)%
 
 
 
 
 
 
 


Total Average Marcellus sales price (per Mcfe)
$
3.58

 
$
4.16

 
$
(0.58
)
 
(13.9
)%
Average Marcellus lifting costs (per Mcfe)
$
0.18

 
$
0.29

 
$
(0.11
)
 
(37.9
)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)
$
0.15

 
$
0.17

 
$
(0.02
)
 
(11.8
)%
Average Marcellus gathering costs (per Mcfe)
$
0.95

 
$
0.66

 
$
0.29

 
43.9
 %
Average Marcellus direct administrative, selling & other costs (per Mcfe)
$
0.30

 
$
0.34

 
$
(0.04
)
 
(11.8
)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)
$
1.11

 
$
1.09

 
$
0.02

 
1.8
 %
   Total Average Marcellus costs (per Mcfe)
$
2.69

 
$
2.55

 
$
0.14

 
5.5
 %
   Average Margin for Marcellus (per Mcfe)
$
0.89

 
$
1.61

 
$
(0.72
)
 
(44.7
)%
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGLs, condensate, and natural gas prices.

The Marcellus segment sales revenues were $110 million for the three months ended September 30, 2014 compared to $72 million for the three months ended September 30, 2013. The $38 million increase is primarily due to a 76.4% increase in total volumes sold offset, in part, by a 13.9% decrease in total average sales price in the period-to-period comparison. The 13.3 Bcfe increase in sales volumes is primarily due to additional wells coming online from our ongoing drilling program. The $0.58 per Mcfe decrease in Marcellus total average sales price was primarily the result of the $0.73 per Mcf decrease in gas market prices and a $0.04 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 19.0 Bcf of our produced Marcellus gas sales volumes for the three months ended September 30, 2014 at an average gain of $0.55 per Mcf. For the three months ended September 30, 2013, these financial hedges represented approximately 6.4 Bcf at an average gain of $1.11 per Mcf. The decrease in average sales price was offset, in part, by an uplift from an additional 2.8 Bcfe, or $0.19 per Mcfe, of NGLs and condensate sales volumes.

Total costs for the Marcellus segment were $83 million for the three months ended September 30, 2014 compared to $44 million for the three months ended September 30, 2013. The increase in total dollars and unit costs for the Marcellus segment is due to the following items:

Marcellus lifting costs were $6 million for the three months ended September 30, 2014 compared to $5 million for the three months ended September 30, 2013. The increase in total dollars primarily relates to an increase in contract services relating to well tending and well site maintenance, which is a direct result of the increase in the number of wells in production. The decrease in unit costs is due to the increase in sales volumes during the current period.

Marcellus ad valorem, severance and other taxes were $5 million for the three months ended September 30, 2014 compared to $3 million for the three months ended September 30, 2013. The increase in total dollars is primarily due to an increase in severance tax expense caused by the 76.4% increase in sales volumes during the current period offset, in part, by the 20.5% decrease in average gas sales prices, without the impact of hedging. The decrease in unit costs is due to the additional sales volumes and mix of volumes produced by state.


49



Marcellus gathering costs were $29 million for the three months ended September 30, 2014 compared to $11 million for the three months ended September 30, 2013. Total dollars increased primarily due to the 76.4% increase in sales volumes which resulted in increased related party gathering fees, increased processing fees associated with NGLs and an increase in utilized firm transportation expenses. The impact on average unit costs due to the total dollar increase was offset, in part, by the higher sales volumes.

Marcellus direct administrative, selling and other costs were $9 million for the three months ended September 30, 2014 compared to $6 million for the three months ended September 30, 2013. Direct administrative, selling and other costs attributable to the total E&P division are allocated to the individual E&P segments based on a combination of capital, production and employee counts. The increase in direct administrative, selling & other costs was primarily due to Marcellus volumes representing a larger proportion of CONSOL Energy's total gas sales volumes. The decrease in unit costs was primarily due to the increase in volumes sold.

Depreciation, depletion and amortization costs were $34 million for the three months ended September 30, 2014 compared to $19 million for the three months ended September 30, 2013. There was approximately $33 million, or $1.09 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended September 30, 2014. There was approximately $19 million, or $1.08 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended September 30, 2013. There was $1 million, or $0.02 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the three months ended September 30, 2014. There was less than $1 million, or $0.01 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the three months ended September 30, 2013.



50


COALBED METHANE (CBM) GAS SEGMENT
The CBM segment contributed $20 million to the total Company earnings before income tax for the three months ended September 30, 2014 compared to $21 million for the three months ended September 30, 2013.
 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
CBM Gas - Gas Sales Volumes (Bcf)
20.0

 
21.0

 
(1.0
)
 
(4.8
)%
 
 
 
 
 
 
 
 
Average Sales Price - Gas (Mcf)
$
3.79

 
$
3.40

 
$
0.39

 
11.5
 %
Hedging Impact - Gas (Mcf)
$
0.38

 
$
0.59

 
$
(0.21
)
 
(35.6
)%
 
 
 
 
 
 
 
 
Total Average CBM sales price (per Mcf)
$
4.17

 
$
3.99

 
$
0.18

 
4.5
 %
Average CBM lifting costs (per Mcf)
$
0.46

 
$
0.39

 
$
0.07

 
17.9
 %
Average CBM ad valorem, severance, and other taxes (per Mcf)
$
0.13

 
$
0.12

 
$
0.01

 
8.3
 %
Average CBM gathering costs (per Mcf)
$
1.36

 
$
1.31

 
$
0.05

 
3.8
 %
Average CBM direct administrative, selling & other costs (per Mcf)
$
0.13

 
$
0.11

 
$
0.02

 
18.2
 %
Average CBM depreciation, depletion and amortization costs (per Mcf)
$
1.10

 
$
1.06

 
$
0.04

 
3.8
 %
   Total Average CBM costs (per Mcf)
$
3.18

 
$
2.99

 
$
0.19

 
6.4
 %
   Average Margin for CBM (per Mcf)
$
0.99

 
$
1.00

 
$
(0.01
)
 
(1.0
)%

CBM sales revenues were $83 million in the three months ended September 30, 2014 compared to $84 million for the three months ended September 30, 2013. The $1 million decrease was primarily due to the 4.8% decrease in volumes sold offset, in part, by the 4.5% increase in total average sales price per Mcf. CBM sales volumes decreased 1.0 Bcf for the three months ended September 30, 2014 compared to the 2013 period primarily due to normal well declines without a corresponding amount of additional wells drilled. The decrease in wells drilled is due to the Company's current focus on Marcellus production. The decline in wells drilled is also due to the decline in coal production at our Buchanan Mine which resulted in fewer GOB collection wells being drilled. The CBM total average sales price increased $0.18 per Mcf primarily due to a $0.39 per Mcf increase in average market prices offset, in part, by a $0.21 per Mcf decrease resulting from various transactions relating to our hedging program. Financial hedges represented approximately 17.8 Bcf of our produced CBM gas sales volumes for the three months ended September 30, 2014 at an average gain of $0.42 per Mcf. For the three months ended September 30, 2013, these financial hedges represented approximately 13.8 Bcf at an average gain of $0.89 per Mcf.

Total costs for the CBM segment were $63 million for the three months ended September 30, 2014 and September 30, 2013. The increase in unit costs for the CBM segment was due to the following items:
 
CBM lifting costs were $9 million for the three months ended September 30, 2014 compared to $8 million for the three months ended September 30, 2013. The increase in total dollars was primarily due to an increase in well tending and repair and maintenance costs. The $0.07 per Mcf increase in unit costs was primarily due to the decrease in gas sales volumes.

CBM ad valorem, severance and other taxes were $3 million for the three months ended September 30, 2014 and September 30, 2013. Unit costs were negatively impacted by the decrease in gas sales volumes.

CBM gathering costs were $27 million for the three months ended September 30, 2014 compared to $28 million for the three months ended September 30, 2013. The decrease in total dollars was due to lower utilized firm transportation expense resulting from the decrease in sale volumes. The decrease was offset, in part, by an increase in pipeline maintenance. Improvements in unit costs due to the decrease in total dollars were more than offset by the decrease in gas sales volumes.

CBM direct administrative, selling and other costs were $2 million for the three months ended September 30, 2014 and September 30, 2013. Unit costs were negatively impacted by the decrease in gas sales volumes.
 
Depreciation, depletion and amortization attributable to the CBM segment was $22 million for the three months ended September 30, 2014 and September 30, 2013. There was approximately $15 million, or $0.73 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended September 30, 2014. The production portion of depreciation,


51


depletion and amortization was $15 million, or $0.74 per unit-of-production in the three months ended September 30, 2013. There was approximately $7 million, or $0.37 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the three months ended September 30, 2014. The non-production related depreciation, depletion and amortization was $7 million, or $0.32 per Mcf for the three months ended September 30, 2013.

SHALLOW OIL AND GAS SEGMENT

The shallow oil and gas segment had a loss before income tax of $9 million for the three months ended September 30, 2014 compared to a loss before income tax of $2 million for the three months ended September 30, 2013.
 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Shallow Oil and Gas - Gas Sales Volumes (Bcf)
6.6

 
6.7

 
(0.1
)
 
(1.5
)%
Oil Sales Volumes (Bcfe)*
0.1

 
0.1

 

 
 %
Total Shallow Oil and Gas Sales Volumes (Bcfe)*
6.7

 
6.8

 
(0.1
)
 
(1.5
)%
 
 
 
 
 
 
 
 
Average Sales Price - Gas (Mcf)
$
3.17

 
$
3.55

 
$
(0.38
)
 
(10.7
)%
Hedging Impact - Gas (Mcf)
$
0.38

 
$
1.11

 
$
(0.73
)
 
(65.8
)%
Average Sales Price - Oil (Mcfe)*
$
14.73

 
$
17.35

 
$
(2.62
)
 
(15.1
)%
 
 
 
 
 
 
 
 
Total Average Shallow Oil and Gas sales price (per Mcfe)
$
3.76

 
$
4.85

 
$
(1.09
)
 
(22.5
)%
Average Shallow Oil and Gas lifting costs (per Mcfe)
$
1.59

 
$
1.36

 
$
0.23

 
16.9
 %
Average Shallow Oil and Gas ad valorem, severance, and other taxes (per Mcfe)
$
0.09

 
$
0.27

 
$
(0.18
)
 
(66.7
)%
Average Shallow Oil and Gas gathering costs (per Mcfe)
$
1.11

 
$
1.01

 
$
0.10

 
9.9
 %
Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)
$
0.19

 
$
0.37

 
$
(0.18
)
 
(48.6
)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs (per Mcfe)
$
2.16

 
$
2.15

 
$
0.01

 
0.5
 %
   Total Average Shallow Oil and Gas costs (per Mcfe)
$
5.14

 
$
5.16

 
$
(0.02
)
 
(0.4
)%
   Average Margin for Shallow Oil and Gas (per Mcfe)
$
(1.38
)
 
$
(0.31
)
 
$
(1.07
)
 
(345.2
)%
*Oil is converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.

Shallow Oil and Gas sales revenues were $25 million for the three months ended September 30, 2014 compared to $33 million for the three months ended September 30, 2013. The $8 million decrease was due to a 1.5% decrease in total volumes sold and a 22.5% decrease in the total average sales price. The decrease in total volumes sold was primarily due to normal well declines. The decrease in shallow oil and gas total average sales price was primarily the result of a $0.73 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 3.8 Bcf of our produced shallow oil and gas sales volumes for the three months ended September 30, 2014 at an average gain of $0.67 per Mcf. For the three months ended September 30, 2013, these financial hedges represented approximately 3.8 Bcf at an average gain of $1.96 per Mcf. The decrease in average sales price was also the result of a $0.38 per Mcf decrease in average gas market prices.

Total costs for the shallow oil and gas segment were $34 million for the three months ended September 30, 2014 compared to $35 million for the three months ended September 30, 2013. The decrease in total dollars and unit costs for the shallow oil and gas segment is due to the following items:

Shallow Oil and Gas lifting costs were $11 million for the three months ended September 30, 2014 compared to $9 million for the three months ended September 30, 2013. The $2 million increase in total dollars is primarily due to an increase in environmental compliance, pumping and swabbing, and general well site maintenance expenses. Unit costs were also negatively impacted by the decrease in gas sales volumes.

Shallow Oil and Gas ad valorem, severance and other taxes were $1 million for the three months ended September 30, 2014 compared to $2 million for the three months ended September 30, 2013. The $1 million decease in total dollars is


52


primarily due to the decrease in gas sales volumes and the decrease in total average sales price during the current period. The improvement in unit costs was offset, in part, by the decrease in gas sales volumes.

Shallow Oil and Gas gathering costs were $7 million for the three months ended September 30, 2014 and September 30, 2013. The impairment in unit costs was due to the decrease in gas sales volumes.

Shallow Oil and Gas direct administrative, selling and other costs were $1 million for the three months ended September 30, 2014 compared to $2 million for the three months ended September 30, 2013. The $1 million decrease in the period-to-period comparison was due to Shallow Oil and Gas volumes representing a smaller proportion of CONSOL Energy's total gas sales volumes. These decreases in costs were offset, in part, by lower sales volumes.

Depreciation, depletion and amortization attributable to the Shallow Oil & Gas segment was $14 million for the three months ended September 30, 2014 compared to $15 million for the three months ended September 30, 2013. There was approximately $13 million, or $1.90 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended September 30, 2014. There was approximately $13 million, or $1.91 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended September 30, 2013. There was approximately $1 million, or $0.26 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended September 30, 2014. There was $2 million, or $0.24 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended September 30, 2013.

OTHER GAS SEGMENT

The other E&P segment includes activity not assigned to the Marcellus, CBM, or Shallow Oil and Gas segments. This segment includes purchased gas activity, gas royalty interest activity, exploration and other costs, other corporate expenses, and miscellaneous operational activity not assigned to a specific E&P segment.

Other gas sales volumes are primarily related to production from the Utica Shale and the Chattanooga Shale in Tennessee. Revenue from Utica Shale operations was approximately $36 million for the three months ended September 30, 2014 compared to $1 million for the three months ended September 30, 2013. Revenue from other Shale operations was $4 million for the three months ended September 30, 2014 compared to $3 million for the three months ended September 30, 2013. Total costs related to Utica Shale operations were $16 million for the three months ended September 30, 2014 compared to $1 million for the three months ended September 30, 2013. Total costs related to other Shale operations were $7 million for the three months ended September 30, 2014 compared to $6 million for the three months ended September 30, 2013. A per unit analysis of the other operating costs in the Utica Shale and Chattanooga Shale is not meaningful due to the relatively low volumes sold in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas sales revenue was $18 million for the three months ended September 30, 2014 compared to $15 million for the three months ended September 30, 2013. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period increase.
 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)
5.5

 
3.5

 
2.0

 
57.1
 %
Average Sales Price Per thousand cubic feet
$
3.21

 
$
4.41

 
$
(1.20
)
 
(27.2
)%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $1 million for the three months ended September 30, 2014 compared to $2 million for the three months ended September 30, 2013.


53


 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Purchased Gas Sales Volumes (in billion cubic feet)
0.4

 
0.3

 
0.1

 
33.3
 %
Average Sales Price Per thousand cubic feet
$
3.08

 
$
5.13

 
$
(2.05
)
 
(40.0
)%

Other income was $19 million for the three months ended September 30, 2014 compared to $13 million for the three months ended September 30, 2013. The $6 million increase was primarily due to the following items:

Other income increased $3 million primarily due to an increase in revenue related to certain gathering arrangments.
Earnings from our equity affiliates increased $5 million primarily due to an increase in earnings from CONE Gathering LLC. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information. 
Gain on property sales increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.
Interest income decreased $4 million due to the scheduled collection of the final installment in 2013 on the notes receivable from the 2011 Noble joint venture transaction.
The remaining $2 million decrease relates to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative costs are allocated to the total E&P segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $15 million for the three months ended September 30, 2014 compared to $10 million for the three months ended September 30, 2013. Refer to the discussion of total Company general and administrative costs contained in the section "Net Loss Attributable to CONSOL Energy Shareholders" of this quarterly report for a detailed cost explanation.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas costs were $15 million for the three months ended September 30, 2014 compared to $13 million for the three months ended September 30, 2013. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.
 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)
5.5

 
3.5

 
2.0

 
57.1
 %
Average Cost Per thousand cubic feet sold
$
2.70

 
$
3.66

 
$
(0.96
)
 
(26.2
)%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The lower average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $1 million for the three months ended September 30, 2014 and September 30, 2013.
 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Purchased Gas Volumes (in billion cubic feet)
0.4

 
0.3

 
0.1

 
33.3
 %
Average Cost Per thousand cubic feet sold
$
2.42

 
$
3.01

 
$
(0.59
)
 
(19.6
)%

Exploration and other costs were $8 million for the three months ended September 30, 2014 compared to $23 million for the three months ended September 30, 2013. The $15 million decrease is due to the following items:


54


 
For the Three Months Ended September 30,
(in millions)
2014
 
2013
 
Variance
 
Percent
Change
Marcellus Title Defects
$

 
$
12

 
$
(12
)
 
(100.0
)%
Seismic Activity
1

 
3

 
(2
)
 
(66.7
)%
Lease Expiration Costs
3

 
3

 

 
 %
Other
4

 
5

 
(1
)
 
(20.0
)%
Total Exploration and Other Costs
$
8

 
$
23

 
$
(15
)
 
(65.2
)%

CONSOL Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $12 million for the three months ended September 30, 2013.

Seismic Activity decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
Lease expiration costs relate to locations where CONSOL Energy allowed the primary lease term to expire because of unfavorable drilling economics and remained consistent in the period-to-period comparison.
Other expenses decreased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
Other corporate expenses were $13 million for the three months ended September 30, 2014 compared to $26 million for the three months ended September 30, 2013. The $13 million decrease was made up of the following items:

 
For the Three Months Ended September 30,
(in millions)
2014
 
2013
 
Variance
 
Percent
Change
Litigation Settlements
$
(5
)
 
$

 
$
(5
)
 
(100.0
)%
Unutilized Firm Transportation and Processing Fees
9

 
12

 
(3
)
 
(25.0
)%
Short-term Incentive Compensation
4

 
7

 
(3
)
 
(42.9
)%
Bank Fees

 
2

 
(2
)
 
(100.0
)%
Stock-based Compensation
3

 
4

 
(1
)
 
(25.0
)%
Other
2

 
1

 
1

 
100.0
 %
Total Other Corporate Expenses
$
13

 
$
26

 
$
(13
)
 
(50.0
)%

Litigation settlements decreased $5 million due to various activities that occurred in the current period, none of which were individually material.
Unutilized firm transportation and processing fees represent pipeline transportation capacity the E&P segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The $3 million decrease is primarily due to a decrease in firm transportation capacity which has not been utilized by active operations.
The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for, among other things, safety, production, compliance and unit costs. Short-term incentive compensation expense decreased $3 million due to lower projected payouts in the current period.
Bank fees decreased $2 million due to a reduction in revolver related fees. The CNX Gas revolver was amended and restated on June 18, 2014.
Stock-based compensation decreased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
Other corporate related expenses increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

Interest expense related to the gas segment remained consistent at $3 million for the three months ended September 30, 2014 and September 30, 2013.



55



TOTAL COAL SEGMENT ANALYSIS for the three months ended September 30, 2014 compared to the three months ended September 30, 2013:
The coal segment contributed $53 million of earnings before income tax in the three months ended September 30, 2014 compared to $64 million in the three months ended September 30, 2013. Variances by the individual coal segments are discussed below.

 
For the Three Months Ended
 
Difference to Three Months Ended
 
September 30, 2014
 
September 30, 2013
 (in millions)
Thermal
Coal
 
High
Vol
Met
Coal
 
Low
Vol
Met
Coal
 
Other
Coal
 
Total
Coal
 
Thermal
Coal
 
High
Vol
Met
Coal
 
Low
Vol
Met
Coal
 
Other
Coal
 
Total
Coal
Sales:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Produced Coal
$
398

 
$
15

 
$
70

 
$

 
$
483

 
$
46

 
$
(7
)
 
$
(28
)
 
$

 
$
11

Purchased Coal

 

 

 
1

 
1

 

 

 

 
(5
)
 
(5
)
Total Outside Sales
398

 
15

 
70

 
1

 
484

 
46

 
(7
)
 
(28
)
 
(5
)
 
6

Freight Revenue

 

 

 
2

 
2

 

 

 

 
(8
)
 
(8
)
Other Income

 
3

 

 
23

 
26

 
(1
)
 
3

 

 
(3
)
 
(1
)
Total Revenue and Other Income
398

 
18

 
70

 
26

 
512

 
45

 
(4
)
 
(28
)
 
(16
)
 
(3
)
Costs and Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning inventory costs
12

 

 
12

 

 
24

 
(20
)
 

 
3

 

 
(17
)
Total direct operating costs
205

 
6

 
31

 
33

 
275

 
47

 
(5
)
 
(14
)
 
(4
)
 
24

Total royalty/production taxes
18

 
1

 
4

 

 
23

 
2

 

 
(2
)
 
(1
)
 
(1
)
Total direct services to operations
32

 
1

 
6

 
25

 
64

 

 
(1
)
 
(1
)
 
(11
)
 
(13
)
Total retirement and disability
24

 
1

 
4

 
1

 
30

 
9

 

 
(2
)
 
(2
)
 
5

Depreciation, depletion and amortization
42

 
1

 
11

 
11

 
65

 
10

 
(1
)
 

 
(2
)
 
7

Ending inventory costs
(17
)
 

 
(7
)
 

 
(24
)
 
11

 

 

 

 
11

Total Costs and Expenses
316

 
10

 
61

 
70

 
457

 
59

 
(7
)
 
(16
)
 
(20
)
 
16

Freight Expense

 

 

 
2

 
2

 

 

 

 
(8
)
 
(8
)
Total Costs
316

 
10

 
61

 
72

 
459

 
59

 
(7
)
 
(16
)
 
(28
)
 
8

Earnings (Loss) Before Income Taxes
$
82

 
$
8

 
$
9

 
$
(46
)
 
$
53

 
$
(14
)
 
$
3

 
$
(12
)
 
$
12

 
$
(11
)




56


THERMAL COAL SEGMENT
The thermal coal segment contributed $82 million to total Company earnings before income tax for the three months ended September 30, 2014 and $96 million for the three months ended September 30, 2013. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:

 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Company Produced Thermal Tons Sold (in millions)
6.6

 
5.4

 
1.2

 
22.2
 %
Average Sales Price Per Thermal Ton Sold
$
60.77

 
$
65.07

 
$
(4.30
)
 
(6.6
)%
 
 
 
 
 
 
 
 
Beginning Inventory Costs Per Thermal Ton
$
56.82

 
$
57.47

 
$
(0.65
)
 
(1.1
)%
 
 
 
 
 
 
 
 
Total Direct Operating Costs Per Thermal Ton Produced
$
30.68

 
$
29.38

 
$
1.30

 
4.4
 %
Total Royalty/Production Taxes Per Thermal Ton Produced
2.69

 
2.99

 
(0.30
)
 
(10.0
)%
Total Direct Services to Operations Per Thermal Ton Produced
4.75

 
5.99

 
(1.24
)
 
(20.7
)%
Total Retirement and Disability Per Thermal Ton Produced
3.55

 
2.77

 
0.78

 
28.2
 %
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced
6.35

 
5.84

 
0.51

 
8.7
 %
     Total Production Costs Per Thermal Ton Produced
$
48.02

 
$
46.97

 
$
1.05

 
2.2
 %
 
 
 
 
 
 
 
 
Ending Inventory Costs Per Thermal Ton
$
48.22

 
$
53.04

 
$
(4.82
)
 
(9.1
)%
 
 
 
 
 
 
 
 
     Total Costs Per Thermal Ton Sold
$
48.30

 
$
47.45

 
$
0.85

 
1.8
 %
     Average Margin Per Thermal Ton Sold
$
12.47

 
$
17.62

 
$
(5.15
)
 
(29.2
)%

Thermal coal outside sales revenue was $398 million for the three months ended September 30, 2014 compared to $352 million for the three months ended September 30, 2013. The $46 million increase was attributable to a 1.2 million increase in tons sold offset, in part, by a $4.30 per ton lower average sales price. Thermal coal pricing was lower because of the roll-off of some higher-priced legacy sales contracts. The decrease in average sales price was offset, in part, by 0.4 million tons of thermal coal being priced on the export market at an average sales price of $70.95 per ton for the three months ended September 30, 2014 compared to 0.6 million tons at an average price of $64.11 per ton for the three months ended September 30, 2013.
Other income attributable to the thermal coal segment represents earnings from our equity affiliates that operate thermal coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.
Total cost of goods sold is comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. The costs of tons produced include items such as direct operating costs, royalty and production taxes, direct services to operations, retirement and disability, and depreciation, depletion, and amortization costs. Total cost of goods sold for thermal coal was $316 million for the three months ended September 30, 2014, or $59 million higher than the $257 million for the three months ended September 30, 2013. Total cost of goods sold for thermal coal was $48.30 per ton in the three months ended September 30, 2014 compared to $47.45 per ton in the three months ended September 30, 2013. The increase in total dollars and unit costs was primarily due to various maintenance projects at Bailey Mine related to an additional longwall overhaul, a belt repair project, and six thousand additional continuous miner footage. The additional continuous miner footage resulted in additional roof support, haulage, and mine maintenance costs. Unit costs were also negatively impacted in the current period due to geological conditions at Enlow Fork Mine and Harvey Mine. The increase in unit costs was partially offset by the 22.2% increase in thermal tons sold.


57


HIGH VOL METALLURGICAL COAL SEGMENT
The high volatile metallurgical coal segment contributed $8 million to total Company earnings before income tax for the three months ended September 30, 2014 compared to $5 million for the three months ended September 30, 2013. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:

 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Company Produced High Vol Met Tons Sold (in millions)
0.2

 
0.4

 
(0.2
)
 
(50.0
)%
Average Sales Price Per High Vol Met Ton Sold
$
72.76

 
$
60.13

 
$
12.63

 
21.0
 %
 
 
 
 
 
 
 
 
Beginning Inventory Costs Per High Vol Met Ton
$

 
$

 
$

 
 %
 
 
 
 
 
 
 
 
Total Direct Operating Costs Per High Vol Met Ton Produced
$
29.68

 
$
30.20

 
$
(0.52
)
 
(1.7
)%
Total Royalty/Production Taxes Per High Vol Met Ton Produced
2.53

 
2.82

 
(0.29
)
 
(10.3
)%
Total Direct Services to Operations Per High Vol Met Ton Produced
4.82

 
5.33

 
(0.51
)
 
(9.6
)%
Total Retirement and Disability Per High Vol Met Ton Produced
3.63

 
2.93

 
0.70

 
23.9
 %
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced
6.69

 
5.93

 
0.76

 
12.8
 %
     Total Production Costs Per High Vol Met Ton Produced
$
47.35

 
$
47.21

 
$
0.14

 
0.3
 %
 
 
 
 
 
 
 
 
Ending Inventory Costs Per High Vol Met Ton
$

 
$

 
$

 
 %
 
 
 
 
 
 
 
 
     Total Costs Per High Vol Met Ton Sold
$
47.35

 
$
47.21

 
$
0.14

 
0.3
 %
     Margin Per High Vol Met Ton Sold
$
25.41

 
$
12.92

 
$
12.49

 
96.7
 %

High volatile metallurgical coal outside sales revenue was $15 million for the three months ended September 30, 2014 compared to $22 million for the three months ended September 30, 2013. The $7 million decrease was primarily attributable to the 0.2 million decrease in tons sold offset, in part, by the $12.63 per ton increase in average sales price. Average sales prices for high volatile metallurgical coal primarily increased in the period-to-period comparison due to CONSOL Energy pricing 0.2 million tons of high volatile metallurgical coal in the export market at an average sales price of $72.76 per ton for the three months ended September 30, 2014 compared to 0.4 million tons at an average price of $60.13 per ton for the three months ended September 30, 2013. The remaining tons sold in the period-to-period comparison were sold on the domestic market.
Other income attributable to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate high volatile metallurgical coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.
Total cost of goods sold for high volatile metallurgical coal was $10 million for the three months ended September 30, 2014, or $7 million lower than the $17 million for the three months ended September 30, 2013. Total cost of goods sold for high volatile metallurgical coal was $47.35 per ton in the three months ended September 30, 2014 compared to $47.21 per ton in the three months ended September 30, 2013. The decrease in total dollars and increase in unit costs is due to lower tons sold in the period-to-period comparison.


58


LOW VOL METALLURGICAL COAL SEGMENT
The low volatile metallurgical coal segment contributed $9 million to total Company earnings before income tax in the three months ended September 30, 2014 compared to $21 million in the three months ended September 30, 2013. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:

 
For the Three Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Company Produced Low Vol Met Tons Sold (in millions)
1.0

 
1.1

 
(0.1
)
 
(9.1
)%
Average Sales Price Per Low Vol Met Ton Sold
$
70.50

 
$
85.77

 
$
(15.27
)
 
(17.8
)%
 
 
 
 
 
 
 
 
Beginning Inventory Costs Per Low Vol Met Ton
$
60.96

 
$
64.76

 
$
(3.80
)
 
(5.9
)%
 
 
 
 
 
 
 
 
Total Direct Operating Costs Per Low Vol Met Ton Produced
$
33.58

 
$
41.08

 
$
(7.50
)
 
(18.3
)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced
4.36

 
5.16

 
(0.80
)
 
(15.5
)%
Total Direct Services to Operations Per Low Vol Met Ton Produced
6.57

 
5.85

 
0.72

 
12.3
 %
Total Retirement and Disability Per Low Vol Met Ton Produced
4.57

 
5.57

 
(1.00
)
 
(18.0
)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced
10.96

 
9.67

 
1.29

 
13.3
 %
     Total Production Costs Per Low Vol Met Ton Produced
$
60.04

 
$
67.33

 
$
(7.29
)
 
(10.8
)%
 
 
 
 
 
 
 
 
Ending Inventory Costs Per Low Vol Met Ton
$
52.53

 
$
65.42

 
$
(12.89
)
 
(19.7
)%
 
 
 
 
 
 
 
 
     Total Costs Per Low Vol Met Ton Sold
$
61.29

 
$
67.18

 
$
(5.89
)
 
(8.8
)%
     Margin Per Low Vol Met Ton Sold
$
9.21

 
$
18.59

 
$
(9.38
)
 
(50.5
)%

Low volatile metallurgical coal outside sales revenue was $70 million for the three months ended September 30, 2014 compared to $98 million for the three months ended September 30, 2013. The $28 million decrease was attributable to a $15.27 per ton lower average sales price and a 0.1 million decrease in tons sold. Average sales prices for low volatile metallurgical coal decreased in the period-to-period comparison due to the continued weakening in the global metallurgical coal market and the oversupply of coal used in steelmaking.
Total cost of goods sold for low volatile metallurgical coal was $61 million for the three months ended September 30, 2014, or $16 million lower than the $77 million for the three months ended September 30, 2013. Total cost of goods sold for low volatile metallurgical coal was $61.29 per ton in the three months ended September 30, 2014 compared to $67.18 per ton in the three months ended September 30, 2013. The decrease in total dollars and unit costs per low volatile metallurgical ton sold was primarily due to lower royalty and production taxes, lower wage and wage related expenses, and a reduction in the number of degas wells drilled. These decreases were related to lower average sales prices and cost control measures that were implemented due to the weak metallurgical coal market. Part of the cost control measures included a decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014. These improvements were offset, in part, by lower tons sold.


59


OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $46 million for the three months ended September 30, 2014 compared to a loss before income tax of $58 million for the three months ended September 30, 2013. The other coal segment includes purchased coal activities and idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications and coal purchased from third parties and sold directly to our customers. Purchased coal sales are offset by purchased coal expense. The revenues were $1 million for the three months ended September 30, 2014 compared to $6 million for the three months ended September 30, 2013. The decrease in the period-to-period comparison was due to lower volumes of coal that needed to be purchased to fulfill various contracts.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue 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 offset by freight expense. Freight revenue was $2 million for the three months ended September 30, 2014 compared to $10 million for the three months ended September 30, 2013. The decrease in freight revenue was due to lower shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $23 million for the three months ended September 30, 2014 compared to $26 million for the three months ended September 30, 2013. The change is due to the following items:

 
 
For the Three Months Ended September 30,
(in millions)
 
2014
 
2013
 
Variance
Gain on Sale of Assets
 
$
2

 
$
18

 
$
(16
)
Royalty Income
 
5

 
4

 
1

Equity in earnings of affiliates
 
4

 
(2
)
 
6

Rental Income
 
10

 
1

 
9

Other
 
2

 
5

 
(3
)
Total Other Income Coal Segment
 
$
23

 
$
26

 
$
(3
)

Gain on sale of assets decreased $16 million primarily due to the following activity during the three months ended September 30, 2013: the sale of 1.5MM tons of Pittsburgh 8 Coal that CONSOL Energy controlled in Belmont County, OH, resulting in a gain of $2 million; and the sale of a 50% interest in a joint venture in Alberta, Canada, resulting in a gain of $15 million. No such transactions were entered into during the three months ended September 30, 2014.
Royalty income increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
Equity in earnings of affiliates increased $6 million due to various transactions completed by our equity partners, none of which were individually material.
Rental income increased $9 million due to equipment subleased to a third-party. These arrangements began in December 2013.
Other income decreased $3 million due to various items, none of which were individually significant.

Other coal segment total costs were $72 million for the three months ended September 30, 2014 compared to $100 million for the three months ended September 30, 2013. The decrease of $28 million was primarily due to the following items:


60


 
 
For the Three Months Ended September 30,
(in millions)
 
2014
 
2013
 
Variance
Litigation Settlements
 
$

 
$
13

 
$
(13
)
Purchased Coal
 
2

 
11

 
(9
)
Freight Expense
 
2

 
10

 
(8
)
Depreciation, Depletion, and Amortization
 
6

 
9

 
(3
)
Closed and Idle Mines
 
25

 
27

 
(2
)
Stock-based and Incentive Compensation
 
10

 
11

 
(1
)
General and Administrative Expense
 
10

 
9

 
1

Lease Rental Expense
 
6

 

 
6

Other
 
11

 
10

 
1

Total Other Coal Segment Costs
 
$
72

 
$
100

 
$
(28
)

Litigation settlements decreased $13 million primarily due to a specific settlement that occurred in the third quarter of 2013.
Purchased coal costs decreased $9 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.
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 by freight revenue. The decrease in freight expense was due to lower shipments under contracts which CONSOL Energy contractually provides transportation services.
Depreciation, Depletion, and Amortization decreased $3 million primarily due to various transactions that occurred throughout both periods, none of which were individually material.
Closed and idle mine costs decreased approximately $2 million due to various changes in the operational status of other mines, between idled and operating, throughout both periods, none of which were individually material.
Stock-based and Incentive Compensation decreased approximately $1 million due to various transactions that occurred throughout both periods, none of which were individually material
General and Administrative Expense related to the other coal segment increased by $1 million primarily due to various transactions, none of which were individually material. Refer to the discussion of total general and administrative costs contained in the section entitled "Net Loss Attributable to CONSOL Energy Shareholders" of this quarterly report for detailed cost explanations.
Lease rental expense increased $6 million primarily due to equipment leases that are subleased to a third-party. The third-party subleases began in December 2013.
Other expenses related to the Other Coal segment increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.



61


OTHER SEGMENT ANALYSIS for the three months ended September 30, 2014 compared to the three months ended September 30, 2013:

The other segment includes activity from the sales of industrial supplies, coal terminal activity and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $93 million for the three months ended September 30, 2014 compared to a loss before income tax of $66 million for the three months ended September 30, 2013. The other segment also includes total Company income tax benefit of $1 million for the three months ended September 30, 2014 compared to an income tax expense of $69 million for the three months ended September 30, 2013.

 
For the Three Months Ended September 30,
 (in millions)
2014
 
2013
 
Variance
 
Percent
Change
Sales—Outside
$
74

 
$
64

 
$
10

 
15.6
 %
Other Income
1

 

 
1

 
100.0
 %
Total Revenue
75

 
64

 
11

 
17.2
 %
Cost of Goods Sold and Other Charges
94

 
76

 
18

 
23.7
 %
Depreciation, Depletion & Amortization
1

 
1

 

 
 %
Loss on Debt Extinguishment
21

 

 
21

 
100.0
 %
Interest Expense
52

 
53

 
(1
)
 
(1.9
)%
Total Costs
168

 
130

 
38

 
29.2
 %
Loss Before Income Tax
(93
)
 
(66
)
 
(27
)
 
40.9
 %
Income Tax
(1
)
 
69

 
(70
)
 
(101.4
)%
Net Loss
$
(92
)
 
$
(135
)
 
$
43

 
31.9
 %

Industrial supplies:

Outside Sales from industrial supplies were $66 million for the three months ended September 30, 2014, compared to $54 million for the three months ended September 30, 2013. The increase of $12 million was primarily related to higher sales volumes.

Total costs related to industrial supply sales were $63 million for the three months ended September 30, 2014, compared to $53 million for the three months ended September 30, 2013. The increase of $10 million was primarily related to higher sales volumes and various changes in inventory costs, none of which were individually material.

Coal terminal activity:

Outside Sales from terminal activity were $8 million for the three months ended September 30, 2014, compared to $10 million for the three months ended September 30, 2013. The decrease of $2 million was primarily attributable to decreased thru-put volumes for the quarter.

Total costs related to terminal activity were $6 million for the three months ended September 30, 2014, compared to $8 million for the three months ended September 30, 2013. Costs decreased $2 million due to lower per ton thru-put costs and a decrease in thru-put volumes.

Miscellaneous other:

Other income was $1 million for the three months ended September 30, 2014, and less than $1 million for the three months ended September 30, 2013. The increase is due to various items in both periods, none of which were individually material.

Other corporate costs were $99 million for the three months ended September 30, 2014 compared to $69 million for the three months ended September 30, 2013. Other corporate costs increased due to the following items:


62


 
 
For the Three Months Ended September 30,
(in millions)
 
2014
 
2013
 
Variance
Loss on Debt Extinguishment
 
$
21

 
$

 
$
21

Long-Term Liability Plan Changes
 
10

 

 
10

Bank Fees
 
4

 
4

 

Interest Expense
 
52

 
53

 
(1
)
Pension Settlement
 
5

 
6

 
(1
)
Other
 
7

 
6

 
1

 
 
$
99

 
$
69

 
$
30


Loss on Debt Extinguishment of $21 million was recognized in the three months ended September 30, 2014 related to the early extinguishment of debt due to the partial purchase of the 8.25% senior notes that were due in 2020 at an average premium of 1.075%. No such transactions occurred in the prior period.
Long-Term Liability Plan Changes include $36 million of income as a result of curtailment associated with amendments to the pension and OPEB plans, which were adopted during the third quarter, offset by $46 million of expense for cash payments made to active employees related to changes in the OPEB plan.
Bank Fees remained consistent in the period-to-period comparison.
Interest Expense decreased $1 million in the period-to-period comparison primarily due to various transactions that occurred throughout both periods, none of which were individually material.
Pension Settlement expense is required when the lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. Settlement accounting was triggered in both periods. See Note 4 - Pension and Other Post-Employment Benefit Plans and Note 5 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional detail of the total Company expense increase.
Other corporate items increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

Income Taxes:

The effective income tax rate was 28.4% for the three months ended September 30, 2014 compared to (2,079.7)% for the three months ended September 30, 2013. The effective rates for the three months ended September 30, 2014 and 2013 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. The relationship between pre-tax earnings and percentage depletion also impacts the effective tax rate. As a result of closing the IRS audit, CONSOL Energy was required to file amended state income tax returns. In the three months ended September 30, 2014, the Company filed the required amended returns and realized a discrete state income tax charge of $0.4 million which was offset by a federal income tax benefit of $0.1 million. See Note 6 - Income Taxes of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information. 
 
For the Three Months Ended September 30,
(in millions)
2014
 
2013
 
Variance
 
Percent
Change
Total Company Loss Before Income Tax
$
(3
)
 
$
(3
)
 
$

 
 %
Income Tax (Benefit) Expense
$
(1
)
 
$
69

 
$
(70
)
 
(102.0
)%
Effective Income Tax Rate
28.4
%
 
(2,079.7
)%
 
2,108.1
%
 
 



63





Results of Operations
Nine Months Ended September 30, 2014 Compared with Nine Months Ended September 30, 2013

Net Income (Loss) Attributable to CONSOL Energy Shareholders
CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $89 million, or income of $0.39 per diluted share, for the nine months ended September 30, 2014, compared to a net loss attributable to CONSOL Energy shareholders of $78 million, or a loss of $0.34 per diluted share, for the nine months ended September 30, 2013. Included in net income was income from continuing operations of $95 million, or income of $0.41 per diluted share, for the nine months ended September 30, 2014. There was a loss from continuing operations of $67 million, or a loss of $0.29 per diluted share, for the nine months ended September 30, 2013. Also included in net income is a loss from discontinued operations of $6 million, or a loss of $0.02 per diluted share, for the nine months ended September 30, 2014. There was a loss from discontinued operations of $11 million, or a loss of $0.05 per diluted share, for the nine months ended September 30, 2013.

The total Exploration and Production (E&P) division includes Marcellus, coalbed methane (CBM), shallow oil and gas, and other gas. The total E&P division contributed income of $139 million before income tax for the nine months ended September 30, 2014 compared to a loss of $7 million before income tax for the nine months ended September 30, 2013. Total E&P production was 165.2 Bcfe for the nine months ended September 30, 2014 compared to 123.9 Bcfe for the nine months ended September 30, 2013.

The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s production and sales portfolio:
 
 
For the Nine Months Ended September 30,
 in thousands (unless noted)
 
2014
 
2013
 
Variance
 
Percent
Change
LIQUIDS
 
 
 
 
 
 
 
 
NGLs:
 
 
 
 
 
 
 
 
Sales Volume (MMcfe)
 
8,818

 
1,505

 
7,313

 
485.9
 %
Sales Volume (Mbbls)
 
1,470

 
251

 
1,219

 
485.7
 %
Gross Price ($/Bbl)
 
$
42.30

 
$
48.66

 
$
(6.36
)
 
(13.1
)%
Gross Revenue
 
$
62,148

 
$
12,209

 
$
49,939

 
409.0
 %
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
Sales Volume (MMcfe)
 
510

 
414

 
96

 
23.2
 %
Sales Volume (Mbbls)
 
85

 
69

 
16

 
23.2
 %
Gross Price ($/Bbl)
 
$
91.92

 
$
87.42

 
$
4.50

 
5.1
 %
Gross Revenue
 
$
7,808

 
$
6,034

 
$
1,774

 
29.4
 %
 
 
 
 
 
 
 
 
 
Condensate:
 
 
 
 
 
 
 
 
Sales Volume (MMcfe)
 
1,591

 
187

 
1,404

 
750.8
 %
Sales Volume (Mbbls)
 
265

 
31

 
234

 
754.8
 %
Gross Price ($/Bbl)
 
$
86.76

 
$
85.50

 
$
1.26

 
1.5
 %
Gross Revenue
 
$
23,004

 
$
2,663

 
$
20,341

 
763.8
 %
 
 
 
 
 
 
 
 
 
GAS
 
 
 
 
 
 
 
 
Sales Volume (MMcf)
 
154,267

 
121,793

 
32,474

 
26.7
 %
Sales Price ($/Mcf)
 
$
4.30

 
$
3.75

 
$
0.55

 
14.7
 %
Hedging Impact ($/Mcf)
 
$
(0.01
)
 
$
0.46

 
$
(0.47
)
 
(102.2
)%
Gross Revenue including Hedging Impact
 
$
662,376

 
$
513,316

 
$
149,060

 
29.0
 %






64






The average sales price and average costs for all active E&P operations were as follows: 
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Average Sales Price (per Mcfe)
$
4.57

 
$
4.31

 
$
0.26

 
6.0
 %
Average Costs (per Mcfe)
3.37

 
3.49

 
(0.12
)
 
(3.4
)%
Margin
$
1.20

 
$
0.82

 
$
0.38

 
46.3
 %

Total E&P division Natural Gas, NGLs, and Oil sales revenues were $755 million for the nine months ended September 30, 2014 compared to $534 million for the nine months ended September 30, 2013. The increase was primarily due to the 33.3% increase in total volumes sold, along with a 6.0% increase in average price per Mcfe. The increase in average sales price is the result of a $0.55 per Mcfe increase in general market prices and the $0.18 per Mcfe increase in sales of NGLs, oil and condensate. The increase was offset, in part, by the $0.47 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 118.2 Bcf of our produced gas sales volumes for the nine months ended September 30, 2014 at an average loss of $0.01 per Mcf. These financial hedges represented approximately 60.3 Bcf of our produced gas sales volumes for the nine months ended September 30, 2013 at an average gain of $0.94 per Mcf.

Changes in the average cost per Mcfe of gas sold were primarily related to the following items:
The improvement in the unit costs is primarily due to the 33.3% increase in volumes in the period-to-period comparison and the shift to lower cost Marcellus production. Marcellus production made up 45.5% of gas sales volume for the nine months ended September 30, 2014 compared to 31.0% in the nine months ended September 30, 2013.
Lifting costs per unit decreased in the period-to-period comparison due to the increase in sales volumes. The decrease was offset, in part, by an increase in total dollars relating to higher salt water disposal, well site maintenance costs, and costs related to wells operated by our joint-venture partners.
Gathering expense per unit also decreased in the period-to-period comparison due to the increase in sales volumes. The decrease in unit costs was partially offset by an increase in total dollars related to an increase in firm transportation costs and increased processing fees associated with NGLs.
Ad valorem, severance, and other taxes increased in the period-to-period comparison due to the higher average gas sales price, without the impact of hedging, which is the primary basis for severance tax. The increase is also related to the increase in volumes sold and the mix of volumes by state.
Depreciation, depletion and amortization increased as the portion of production from higher investment cost segments continued to grow.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $279 million of earnings before income tax for the nine months ended September 30, 2014 compared to $270 million for the nine months ended September 30, 2013. The total coal division sold 24.3 million tons of coal produced from CONSOL Energy mines for the nine months ended September 30, 2014 compared to 21.6 million tons for the nine months ended September 30, 2013. Current period sales tons were comprised of 83% thermal and 17% metallurgical. Prior period sales tons were comprised of 74% thermal and 26% metallurgical.
The average sales price and average cost of goods sold per ton for continuing coal operations were as follows:
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Average Sales Price per ton sold
$
63.64

 
$
70.17

 
$
(6.53
)
 
(9.3
)%
Average Costs of Goods Sold per ton
47.55

 
51.03

 
(3.48
)
 
(6.8
)%
Margin
$
16.09

 
$
19.14

 
$
(3.05
)
 
(15.9
)%

The lower average sales price per ton sold reflects a decrease in the global metallurgical coal markets, the oversupply of coal used in steelmaking, and lower thermal coal pricing due to the roll-off of some higher-priced legacy contracts. The coal division priced 4.7 million tons on the export market at an average sales price of $64.24 per ton for the nine months ended September 30, 2014 compared to 6.0 million tons at an average price of $74.04 per ton for the nine months ended September 30, 2013. All other tons were sold on the domestic market.


65






Changes in the average cost of goods sold per ton were primarily attributable to the increase in tons sold, as well as the mix of volumes sold. A higher percentage of thermal coal was sold in the current period compared to the prior period. These tons had a lower unit cost per ton sold compared to low volatile metallurgical which lowered the overall average cost of the company. Average cost of goods sold was also impacted by the decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014. The decrease was offset, in part, by geoglogical conditions at Enlow Fork Mine.
The other segment includes industrial supplies activity, coal terminal activity, income taxes and other business activities not assigned to the E&P or Coal division.
General and Administrative costs are allocated between divisions (E&P, Coal and Other) based primarily on percentage of total revenue and percentage of total projected capital expenditures. General and Administrative costs are excluded from the E&P and Coal unit costs above. Total General and Administrative costs were made up of the following items:
 
For the Nine Months Ended September 30,
 (in millions)
2014
 
2013
 
Variance
 
Percent
Change
Continuing Operations General and Administrative Expenses
$
82

 
$
58

 
$
24

 
41.4
 %
Discontinued Operations General and Administrative Expenses

 
31

 
(31
)
 
(100.0
)%
Total Company General and Administrative Expense
$
82

 
$
89

 
$
(7
)
 
(7.9
)%

Overall, total Company General and Administrative Expenses decreased $7 million in the period-to-period comparison. This was primarily due to reduced staffing and cost control projects following the December 2013 sale of five of our West Virginia coal mines. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.

Total Company long-term liabilities for continuing operations, such as OPEB, the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy continuing operations expense related to our actuarial liabilities was $116 million for the nine months ended September 30, 2014 compared to $127 million for the nine months ended September 30, 2013. The decrease of $11 million for total CONSOL Energy continuing operations expense was primarily due to required pension settlement accounting which resulted in $25 million of expense during nine months ended September 30, 2014 compared to $38 million of expense in nine months ended September 30, 2013. Pension settlement accounting is required when lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. Not included in the long-term liability expense totals discussed above are curtailment gains of $36 million, and $46 million of expense for cash payments made to active employees both of which arose from modifications to the OPEB and Pension plans during the nine months ended September 30, 2014. The pension settlement expense, cash payments and curtailment gains were not allocated to individual operating segments and are therefore not included in unit costs presented for the E&P or Coal divisions. See Note 4 - Pension and Other Post-Employment Benefit Plans and Note 5 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional detail of the total Company expense.     



66





TOTAL E&P SEGMENT ANALYSIS for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013:
The E&P segment contributed $139 million to earnings before income tax for the nine months ended September 30, 2014 compared to a loss before income tax of $7 million in the nine months ended September 30, 2013. Variances by the individual E&P segments are discussed below.
 
For the Nine Months Ended
 
Difference to Nine Months Ended
 
September 30, 2014
 
September 30, 2013
 (in millions)
Marcellus
 
CBM
 
Shallow Oil and Gas
 
Other
Gas
 
Total E&P
 
Marcellus
 
CBM
 
Shallow Oil and Gas
 
Other
Gas
 
Total
E&P
Sales:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Produced
$
339

 
$
259

 
$
84

 
$
70

 
$
752

 
$
172

 
$
4

 
$
(15
)
 
$
59

 
$
220

Related Party

 
3

 

 

 
3

 

 
1

 

 

 
1

Total Outside Sales
339

 
262

 
84

 
70

 
755

 
172

 
5

 
(15
)
 
59

 
221

Gas Royalty Interest

 

 

 
63

 
63

 

 

 

 
16

 
16

Purchased Gas

 

 

 
6

 
6

 

 

 

 
2

 
2

Other Income

 

 

 
63

 
63

 

 

 

 
26

 
26

Total Revenue and Other Income
339

 
262

 
84

 
202

 
887

 
172

 
5

 
(15
)
 
103

 
265

Lifting
19

 
28

 
27

 
12

 
86

 
5

 
1

 
1

 
9

 
16

Ad Valorem, Severance, and Other Taxes
11

 
9

 
6

 
3

 
29

 
5

 
2

 
(2
)
 
3

 
8

Gathering
71

 
79

 
22

 
8

 
180

 
41

 
(6
)
 
(4
)
 
5

 
36

E&P Direct Administrative, Selling & Other
26

 
8

 
3

 
2

 
39

 
7

 
2

 
(4
)
 
(1
)
 
4

Depreciation, Depletion and Amortization
91

 
67

 
42

 
26

 
226

 
46

 
(1
)
 
(2
)
 
18

 
61

General & Administration

 

 

 
48

 
48

 

 

 

 
19

 
19

Gas Royalty Interest

 

 

 
53

 
53

 

 

 

 
15

 
15

Purchased Gas

 

 

 
5

 
5

 

 

 

 
2

 
2

Exploration and Other Costs

 

 

 
15

 
15

 

 

 

 
(29
)
 
(29
)
Other Corporate Expenses

 

 

 
61

 
61

 

 

 

 
(13
)
 
(13
)
Interest Expense

 

 

 
6

 
6

 

 

 

 

 

Total Cost
218

 
191

 
100

 
239

 
748

 
104

 
(2
)
 
(11
)
 
28

 
119

Earnings Before Income Tax
$
121

 
$
71

 
$
(16
)
 
$
(37
)
 
$
139

 
$
68

 
$
7

 
$
(4
)
 
$
75

 
$
146




67





MARCELLUS GAS SEGMENT
The Marcellus segment contributed $121 million to the total Company earnings before income tax for the nine months ended September 30, 2014 compared to $53 million for the nine months ended September 30, 2013.
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Marcellus Gas - Gas Sales Volumes (Bcf)
68.3

 
36.8

 
31.5

 
85.6
 %
NGLs Sales Volumes (Bcfe)*
6.2

 
1.5

 
4.7

 
313.3
 %
Condensate Sales Volumes (Bcfe)*
0.7

 
0.2

 
0.5

 
250.0
 %
Total Marcellus Gas Sales Volumes (Bcfe)*
75.2

 
38.5

 
36.7

 
95.3
 %
 
 
 
 
 
 
 
 
Average Sales Price - Gas (Mcf)
$
4.16

 
$
3.79

 
$
0.37

 
9.8
 %
Hedging Impact - Gas (Mcf)
$
0.04

 
$
0.37

 
$
(0.33
)
 
(89.2
)%
Average Sales Price - NGLs (Mcfe)*
$
6.93

 
$
8.14

 
$
(1.21
)
 
(14.9
)%
Average Sales Price - Condensate (Mcfe)*
$
13.72

 
$
14.55

 
$
(0.83
)
 
(5.7
)%
 
 
 
 
 
 
 
 
Total Average Marcellus sales (per Mcfe)
$
4.51

 
$
4.35

 
$
0.16

 
3.7
 %
Average Marcellus lifting costs (per Mcfe)
$
0.25

 
$
0.38

 
$
(0.13
)
 
(34.2
)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)
$
0.16

 
$
0.15

 
$
0.01

 
6.7
 %
Average Marcellus gathering costs (per Mcfe)
$
0.95

 
$
0.79

 
$
0.16

 
20.3
 %
Average Marcellus direct administrative, selling & other costs (per Mcfe)
$
0.34

 
$
0.48

 
$
(0.14
)
 
(29.2
)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)
$
1.20

 
$
1.16

 
$
0.04

 
3.4
 %
   Total Average Marcellus costs (per Mcfe)
$
2.90

 
$
2.96

 
$
(0.06
)
 
(2.0
)%
   Average Margin for Marcellus (per Mcfe)
$
1.61

 
$
1.39

 
$
0.22

 
15.8
 %
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGLs, condensate, and natural gas prices.

The Marcellus segment sales revenues were $339 million for the nine months ended September 30, 2014 compared to $167 million for the nine months ended September 30, 2013. The $172 million increase is primarily due to a 95.3% increase in total volumes sold, and a 3.7% increase in total average sales prices in the period-to-period comparison. The 36.7 Bcfe increase in sales volumes is primarily due to additional wells coming online from our ongoing drilling program. The $0.16 per Mcfe increase in Marcellus total average sales price was primarily the result of the $0.37 per Mcf increase in gas market prices, along with an uplift from an additional 5.2 Bcfe, or $0.12 per Mcfe, of NGLs and condensate sales volumes. The increase was offset, in part, by a $0.33 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 50.3 Bcf of our produced Marcellus gas sales volumes for the nine months ended September 30, 2014 at an average gain of $0.05 per Mcf. For the nine months ended September 30, 2013, these financial hedges represented approximately 15.2 Bcf at an average gain of $0.90 per Mcf.

Total costs for the Marcellus segment were $218 million for the nine months ended September 30, 2014 compared to $114 million for the nine months ended September 30, 2013. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

Marcellus lifting costs were $19 million for the nine months ended September 30, 2014 compared to $14 million for the nine months ended September 30, 2013. The increase in total dollars primarily relates to an increase in salt water disposal costs, well tending costs, and costs related to wells operated by our joint-venture partners. The increase in total dollars were more than offset by the increase in gas sales volumes and resulted in an improvement in unit costs.

Marcellus ad valorem, severance and other taxes were $11 million for the nine months ended September 30, 2014 compared to $6 million for the nine months ended September 30, 2013. The increase in total dollars and unit costs is primarily due to an increase in severance tax expense caused by the 9.8% increase in average gas sales prices, without the impact of hedging, and the additional sales volumes and mix of volumes produced by state.



68





Marcellus gathering costs were $71 million for the nine months ended September 30, 2014 compared to $30 million for the nine months ended September 30, 2013. Total dollars increased primarily due to the 95.3% increase in sales volumes which resulted in an increase in related party gathering fees, increased processing fees associated with NGLs, and an increase in utilized firm transportation expense. The impact on unit costs due to the increase in total dollars was offset, in part, by the increase in sales volumes.

Marcellus direct administrative, selling and other costs were $26 million for the nine months ended September 30, 2014 compared to $19 million for the nine months ended September 30, 2013. Direct administrative, selling and other costs attributable to the total E&P division are allocated to the individual E&P segments based on a combination of capital, production and employee counts. The increase in direct administrative, selling & other costs was primarily due to Marcellus volumes representing a larger proportion of CONSOL Energy's total gas sales volumes. The decrease in unit costs was primarily due to the increase in volumes sold.

Depreciation, depletion and amortization costs were $91 million for the nine months ended September 30, 2014 compared to $45 million for the nine months ended September 30, 2013. There was approximately $89 million, or $1.19 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the nine months ended September 30, 2014. There was approximately $44 million, or $1.15 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the nine months ended September 30, 2013. There was approximately $2 million, or $0.01 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the nine months ended September 30, 2014. There was $1 million, or $0.01 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for for the nine months ended September 30, 2013.

COALBED METHANE (CBM) GAS SEGMENT
The CBM segment contributed $71 million to the total Company earnings before income tax for the nine months ended September 30, 2014 compared to $64 million for the nine months ended September 30, 2013.
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
CBM Gas - Gas Sales Volumes (Bcf)
59.5

 
62.6

 
(3.1
)
 
(5.0
)%
 
 
 
 
 
 
 
 
Average Sales Price - Gas (Mcf)
$
4.47

 
$
3.71

 
$
0.76

 
20.5
 %
Hedging Impact - Gas (Mcf)
$
(0.07
)
 
$
0.40

 
$
(0.47
)
 
(117.5
)%
 
 
 
 
 
 
 
 
Total Average CBM sales price (per Mcf)
$
4.40

 
$
4.11

 
$
0.29

 
7.1
 %
Average CBM lifting costs (per Mcf)
$
0.47

 
$
0.44

 
$
0.03

 
6.8
 %
Average CBM ad valorem, severance, and other taxes (per Mcf)
$
0.16

 
$
0.10

 
$
0.06

 
60.0
 %
Average CBM gathering costs (per Mcf)
$
1.33

 
$
1.37

 
$
(0.04
)
 
(2.9
)%
Average CBM direct administrative, selling & other costs (per Mcf)
$
0.13

 
$
0.10

 
$
0.03

 
30.0
 %
Average CBM depreciation, depletion and amortization costs (per Mcf)
$
1.11

 
$
1.07

 
$
0.04

 
3.7
 %
   Total Average CBM costs (per Mcf)
$
3.20

 
$
3.08

 
$
0.12

 
3.9
 %
   Average Margin for CBM (per Mcf)
$
1.20

 
$
1.03

 
$
0.17

 
16.5
 %

CBM sales revenues were $262 million in the nine months ended September 30, 2014 compared to $257 million for the nine months ended September 30, 2013. The $5 million increase was primarily due to a 7.1% increase in total average sales price offset, in part, by a 5.0% decrease in total volumes sold. CBM sales volumes decreased 3.1 Bcf for the nine months ended September 30, 2014 compared to the 2013 period. The decrease was primarily due to normal well declines without a corresponding offset of additional wells drilled since the Company's current focus is on Marcellus production. The decline in wells drilled is also due to the decline in coal production at our Buchanan Mine which resulted in fewer GOB collection wells being drilled. The CBM total average sales price increased $0.29 per Mcf due to a $0.76 per Mcf increase in market prices. The increase was offset, in part, by a $0.47 per Mcf decrease resulting from various transactions relating to our hedging program. Financial hedges represented approximately 53.0 Bcf of our produced CBM gas sales volumes for the nine months ended


69





September 30, 2014 at an average loss of $0.08 per Mcf. For the nine months ended September 30, 2013, these financial hedges represented approximately 34.4 Bcf at an average gain of $0.73 per Mcf.

Total costs for the CBM segment were $191 million for the nine months ended September 30, 2014 compared to $193 million for the nine months ended September 30, 2013. The decrease in total dollars and increase in unit costs for the CBM segment was due to the following items:
 
CBM lifting costs were $28 million for the nine months ended September 30, 2014 compared to $27 million for the nine months ended September 30, 2013. The increase in total dollars was primarily due to an increase in well servicing costs. The increase in unit costs was primarily due to the decrease in gas sales volumes.

CBM ad valorem, severance and other taxes were $9 million for the nine months ended September 30, 2014 compared to $7 million for the nine months ended September 30, 2013. The increase of $2 million was due to an increase in severance tax expense resulting from the increase in average sales price, without the impact of hedging, as described above. Unit costs were also negatively impacted by the decrease in gas sales volumes.

CBM gathering costs were $79 million for the nine months ended September 30, 2014 compared to $85 million for the nine months ended September 30, 2013. The decrease in total dollars and average per unit costs is due to lower utilized firm transportation expenses resulting from the decrease in gas sales volumes. Improvements in unit costs were offset, in part, by the decrease in gas sales volumes.

CBM direct administrative, selling and other costs were $8 million for the nine months ended September 30, 2014 compared to $6 million for the nine months ended September 30, 2013. The $2 million increase in the period-to-period comparison was due to CBM volumes representing a larger proportion of CONSOL Energy's total gas sales volumes. Unit costs were also negatively impacted by the decrease in gas sales volumes.
 
Depreciation, depletion and amortization attributable to the CBM segment was $67 million for the nine months ended September 30, 2014 and $68 million for the nine months ended September 30, 2013. There was approximately $45 million, or $0.75 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the nine months ended September 30, 2014. The production portion of depreciation, depletion and amortization was $47 million, or $0.74 per unit-of-production in the nine months ended September 30, 2013. There was approximately $22 million, or $0.36 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the nine months ended September 30, 2014. The non-production related depreciation, depletion and amortization was $21 million, or $0.33 per Mcf for the nine months ended September 30, 2013.



70





SHALLOW OIL AND GAS SEGMENT

The shallow oil and gas segment had a loss before income tax of $16 million for the nine months ended September 30, 2014 compared to a loss before income tax of $12 million for the nine months ended September 30, 2013.
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Shallow Oil and Gas - Gas Sales Volumes (Bcf)
18.1

 
20.3

 
(2.2
)
 
(10.8
)%
Oil Sales Volumes (Bcfe)*
0.3

 
0.3

 

 
 %
Total Shallow Oil and Gas Sales Volumes (Bcfe)*
18.4

 
20.6

 
(2.2
)
 
(10.7
)%
 
 
 
 
 
 
 
 
Average Sales Price - Gas (Mcf)
$
4.37

 
$
3.80

 
$
0.57

 
15.0
 %
Hedging Impact - Gas (Mcf)
$
0.02

 
$
0.87

 
$
(0.85
)
 
(97.7
)%
Average Sales Price - Oil (Mcfe)*
$
15.02

 
$
13.55

 
$
1.47

 
10.8
 %
 
 
 
 
 
 
 
 
Total Average Shallow Oil and Gas sales price (per Mcfe)
$
4.59

 
$
4.81

 
$
(0.22
)
 
(4.6
)%
Average Shallow Oil and Gas lifting costs (per Mcfe)
$
1.47

 
$
1.27

 
$
0.20

 
15.7
 %
Average Shallow Oil and Gas ad valorem, severance, and other taxes (per Mcfe)
$
0.31

 
$
0.36

 
$
(0.05
)
 
(13.9
)%
Average Shallow Oil and Gas gathering costs (per Mcfe)
$
1.21

 
$
1.26

 
$
(0.05
)
 
(4.0
)%
Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)
$
0.19

 
$
0.34

 
$
(0.15
)
 
(44.1
)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs (per Mcfe)
$
2.29

 
$
2.15

 
$
0.14

 
6.5
 %
   Total Average Shallow Oil and Gas costs (per Mcfe)
$
5.47

 
$
5.38

 
$
0.09

 
1.7
 %
   Average Margin for Shallow Oil and Gas (per Mcfe)
$
(0.88
)
 
$
(0.57
)
 
$
(0.31
)
 
(54.4
)%
*Oil is converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.

Shallow Oil and Gas sales revenues were $84 million for the nine months ended September 30, 2014 compared to $99 million for the nine months ended September 30, 2013. The $15 million decrease is the result of a 10.7% decrease in total volumes sold and a 4.6% decrease in the total average sales price. The decrease in total volumes sold was primarily due to normal well declines in addition to some wells being shut-in in areas that have active Marcellus drilling. The decrease in shallow oil and gas total average sales price was primarily the result of an $0.85 per Mcf decrease resulting from various transactions relating to our hedging program offset by a $0.57 per Mcf increase in average gas market prices. These financial hedges represented approximately 11.4 Bcf of our produced shallow oil and gas sales volumes for the nine months ended September 30, 2014 at an average gain of $0.03 per Mcf. For the nine months ended September 30, 2013, these financial hedges represented approximately 10.6 Bcf at an average gain of $1.67 per Mcf.

Total costs for the shallow oil and gas segment were $100 million for the nine months ended September 30, 2014 compared to $111 million for the nine months ended September 30, 2013. The decrease in total dollars and increase in unit costs for the shallow oil and gas segment are due to the following items:

Shallow Oil and Gas lifting costs were $27 million for the nine months ended September 30, 2014 compared to $26 million for the nine months ended September 30, 2013. The $1 million increase in total dollars is primarily due to an increase in environmental compliance, well servicing costs, and general well site maintenance expenses offset, in part, by a decrease in road maintenance expense. Unit costs were also negatively impacted by the decrease in gas sales volumes.

Shallow Oil and Gas ad valorem, severance and other taxes were $6 million for the nine months ended September 30, 2014 compared to $8 million for the nine months ended September 30, 2013. The $2 million decease in total dollars is primarily due to decrease in gas sales volumes offset, in part, by the increase in average gas sales prices, without the impact of hedging. The improvement in unit costs was offset, in part, by the decrease in gas sales volumes.

Shallow Oil and Gas gathering costs were $22 million for the nine months ended September 30, 2014 compared to $26 million for the nine months ended September 30, 2013. Gathering costs decreased $4 million primarily due to a decrease in


71





both interruptible gathering and utilized firm transportation expenses in the period-to-period comparison. The decrease in total dollars was partially offset by the decrease in gas sales volumes.

Shallow Oil and Gas direct administrative, selling and other costs were $3 million for the nine months ended September 30, 2014 compared to $7 million for the nine months ended September 30, 2013. The $4 million decrease in the period-to-period comparison was due to Shallow Oil and Gas volumes representing a smaller proportion of CONSOL Energy's total gas sales volumes. The decrease in total dollars was partially offset by the decrease in gas sales volumes.

Depreciation, depletion and amortization attributable to the Shallow Oil & Gas segment was $42 million for the nine months ended September 30, 2014 compared to $44 million for the nine months ended September 30, 2013. There was approximately $37 million, or $2.00 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the nine months ended September 30, 2014. There was approximately $39 million, or $1.90 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the nine months ended September 30, 2013. There was approximately $5 million, or $0.29 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the nine months ended September 30, 2014. There was $5 million, or $0.25 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the nine months ended September 30, 2013.

OTHER GAS SEGMENT

The other E&P segment includes activity not assigned to the Marcellus, CBM, or Shallow Oil and Gas segments. This segment includes purchased gas activity, gas royalty interest activity, exploration and other costs, other corporate expenses, and miscellaneous operational activity not assigned to a specific E&P segment.

Other gas sales volumes are primarily related to production from the Utica Shale and the Chattanooga Shale in Tennessee. Revenue from Utica Shale operations was approximately $56 million for the nine months ended September 30, 2014 compared to $2 million for the nine months ended September 30, 2013. Revenue from other Shale operations was $14 million for the nine months ended September 30, 2014 compared to $9 million for the nine months ended September 30, 2013. Total costs related to Utica Shale operations were $31 million for the nine months ended September 30, 2014 compared to $3 million for the nine months ended September 30, 2013. Total costs related to other Shale operations were $20 million for the nine months ended September 30, 2014 compared to $14 million for the nine months ended September 30, 2013. A per unit analysis of the other operating costs in the Utica Shale and Chattanooga Shale is not meaningful due to the relatively low volumes sold in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas sales revenue was $63 million for the nine months ended September 30, 2014 compared to $47 million for the nine months ended September 30, 2013. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period increase.
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)
14.6

 
10.9

 
3.7

 
33.9
%
Average Sales Price Per thousand cubic feet
$
4.30

 
$
4.27

 
$
0.03

 
0.7
%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $6 million for the nine months ended September 30, 2014 compared to $4 million for the nine months ended September 30, 2013.
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Purchased Gas Sales Volumes (in billion cubic feet)
1.1

 
1.1

 

 
%
Average Sales Price Per thousand cubic feet
$
5.72

 
$
4.12

 
$
1.60

 
38.8
%



72





Other income was $63 million for the nine months ended September 30, 2014 compared to $37 million for the nine months ended September 30, 2013. The $26 million increase was primarily due to the following items:

Other income increased $19 million primarily due to an increase in revenue related to certain gathering arrangements.     
Earnings from our equity affiliates increased $13 million primarily due to an increase in earnings from CONE Gathering LLC. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information. 
Interest income decreased $13 million due to the scheduled collection of the final installment in 2013 on the notes receivable from the 2011 Noble Energy joint venture transaction.
Gain on property sales increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.
The remaining $3 million increase relates to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative costs are allocated to the total E&P segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $48 million for the nine months ended September 30, 2014 compared to $29 million for the nine months ended September 30, 2013. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this quarterly report for a detailed cost explanation.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas costs were $53 million for the nine months ended September 30, 2014 compared to $38 million for the nine months ended September 30, 2013. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)
14.6

 
10.9

 
3.7

 
33.9
%
Average Cost Per thousand cubic feet sold
$
3.68

 
$
3.50

 
$
0.18

 
5.1
%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $5 million for the nine months ended September 30, 2014 compared to $3 million for the nine months ended September 30, 2013.
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Purchased Gas Volumes (in billion cubic feet)
1.1

 
1.1

 

 
%
Average Cost Per thousand cubic feet sold
$
4.63

 
$
2.79

 
$
1.84

 
65.9
%

Exploration and other costs were $15 million for the nine months ended September 30, 2014 compared to $44 million for the nine months ended September 30, 2013. The $29 million decrease is due to the following items:
 
For the Nine Months Ended September 30,
(in millions)
2014
 
2013
 
Variance
 
Percent
Change
Marcellus Title Defects
$

 
$
22

 
$
(22
)
 
(100.0
)%
Lease Expiration Costs
5

 
6

 
(1
)
 
(16.7
)%
Land Rentals
4

 
5

 
(1
)
 
(20.0
)%
Seismic Activity
3

 
3

 

 
 %
Other
3

 
8

 
(5
)
 
(62.5
)%
Total Exploration and Other Costs
$
15

 
$
44

 
$
(29
)
 
(65.9
)%

CONSOL Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $22 million for the nine months ended September 30, 2013.


73





Lease expiration costs relate to locations where CONSOL Energy allowed the primary lease term to expire because of unfavorable drilling economics. The $1 million decrease is due to various transactions that occurred throughout both periods, none of which were individually material.
Land Rentals decreased $1 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.
Seismic Activity remained consistent in the period-to-period comparison.
Other expenses decreased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.
  
Other corporate expenses were $61 million for the nine months ended September 30, 2014 compared to $74 million for the nine months ended September 30, 2013. Other corporate expense was made up of the following items:

 
For the Nine Months Ended September 30,
(in millions)
2014
 
2013
 
Variance
 
Percent
Change
Litigation Settlements
$
(5
)
 
$
2

 
$
(7
)
 
(350.0
)%
Stock-based Compensation
13

 
19

 
(6
)
 
(31.6
)%
Short-term Incentive Compensation
15

 
16

 
(1
)
 
(6.3
)%
Bank Fees
4

 
5

 
(1
)
 
(20.0
)%
Unutilized Firm Transportation and Processing Fees
29

 
28

 
1

 
3.6
 %
Other
5

 
4

 
1

 
25.0
 %
Total Other Corporate Expenses
$
61

 
$
74

 
$
(13
)
 
(17.6
)%

Litigation settlements decreased $7 million due to various transactions that occurred throughout both periods, none of which were individually material.
Stock-based compensation decreased $6 million in the period-to-period comparison primarily due to a reduction in the non-cash amortization expense and less accelerated expense for retiree eligible employees under our current plans.
The short term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for, among other things, safety, production, compliance and unit costs. Short term incentive compensation expense decreased $1 million in the period-to-period comparison due to lower projected payouts.
Bank fees decreased $1 million due to various items that occurred throughout both periods, none of which were individually material.
Unutilized firm transportation and processing fees represent pipeline transportation capacity the E&P segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The $1 million increase is primarily due to increased firm transportation capacity which has not been utilized by active operations.
Other corporate related expenses increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

Interest expense related to the gas segment remained consistent at $6 million for the nine months ended September 30, 2014 and September 30, 2013.



74





TOTAL COAL SEGMENT ANALYSIS for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013:
The coal segment contributed $279 million of earnings before income tax in the nine months ended September 30, 2014 compared to $270 million in the nine months ended September 30, 2013. Variances by the individual coal segments are discussed below.

 
For the Nine Months Ended
 
Difference to Nine Months Ended
 
September 30, 2014
 
September 30, 2013
 (in millions)
Thermal
Coal
 
High
Vol
Met
Coal
 
Low
Vol
Met
Coal
 
Other
Coal
 
Total
Coal
 
Thermal
Coal
 
High
Vol
Met
Coal
 
Low
Vol
Met
Coal
 
Other
Coal
 
Total
Coal
Sales:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Produced Coal
$
1,263

 
$
64

 
$
221

 
$

 
$
1,548

 
$
229

 
$
(61
)
 
$
(135
)
 
$

 
$
33

Purchased Coal

 

 

 
8

 
8

 

 

 

 
(9
)
 
(9
)
Total Outside Sales
1,263

 
64

 
221

 
8

 
1,556

 
229

 
(61
)
 
(135
)
 
(9
)
 
24

Freight Revenue

 

 

 
23

 
23

 

 

 

 
(8
)
 
(8
)
Other Income

 
6

 

 
100

 
106

 
(2
)
 
4

 

 
16

 
18

Total Revenue and Other Income
1,263

 
70

 
221

 
131

 
1,685

 
227

 
(57
)
 
(135
)
 
(1
)
 
34

Costs and Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning inventory costs
21

 

 
11

 

 
32

 
(12
)
 

 
(10
)
 

 
(22
)
Total direct operating costs
586

 
29

 
113

 
102

 
830

 
116

 
(34
)
 
(34
)
 
10

 
58

Total royalty/production taxes
59

 
3

 
13

 
1

 
76

 
5

 

 
(7
)
 

 
(2
)
Total direct services to operations
91

 
4

 
17

 
87

 
199

 
(5
)
 
(7
)
 
(1
)
 
(20
)
 
(33
)
Total retirement and disability
64

 
3

 
15

 
2

 
84

 
19

 
(3
)
 
(4
)
 
(7
)
 
5

Depreciation, depletion and amortization
117

 
6

 
29

 
34

 
186

 
28

 
(6
)
 
(2
)
 
(4
)
 
16

Ending inventory costs
(17
)
 

 
(7
)
 

 
(24
)
 
11

 

 

 

 
11

Total Costs and Expenses
921

 
45

 
191

 
226

 
1,383

 
162

 
(50
)
 
(58
)
 
(21
)
 
33

Freight Expense

 

 

 
23

 
23

 

 

 

 
(8
)
 
(8
)
Total Costs
921

 
45

 
191

 
249

 
1,406

 
162

 
(50
)
 
(58
)
 
(29
)
 
25

Earnings (Loss) Before Income Taxes
$
342

 
$
25

 
$
30

 
$
(118
)
 
$
279

 
$
65

 
$
(7
)
 
$
(77
)
 
$
28

 
$
9





75





THERMAL COAL SEGMENT
The thermal coal segment contributed $342 million to total Company earnings before income tax for the nine months ended September 30, 2014 compared to $277 million for the nine months ended September 30, 2013. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:

 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Company Produced Thermal Tons Sold (in millions)
20.2

 
15.9

 
4.3

 
27.0
 %
Average Sales Price Per Thermal Ton Sold
$
62.38

 
$
64.82

 
$
(2.44
)
 
(3.8
)%
 
 
 
 
 
 
 
 
Beginning Inventory Costs Per Thermal Ton
$
50.82

 
$
50.86

 
$
(0.04
)
 
(0.1
)%
 
 
 
 
 
 
 
 
Total Direct Operating Costs Per Thermal Ton Produced
$
28.98

 
$
29.62

 
$
(0.64
)
 
(2.2
)%
Total Royalty/Production Taxes Per Thermal Ton Produced
2.93

 
3.41

 
(0.48
)
 
(14.1
)%
Total Direct Services to Operations Per Thermal Ton Produced
4.52

 
6.08

 
(1.56
)
 
(25.7
)%
Total Retirement and Disability Per Thermal Ton Produced
3.18

 
2.84

 
0.34

 
12.0
 %
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced
5.77

 
5.63

 
0.14

 
2.5
 %
     Total Production Costs Per Thermal Ton Produced
$
45.38

 
$
47.58

 
$
(2.20
)
 
(4.6
)%
 
 
 
 
 
 
 
 
Ending Inventory Costs Per Thermal Ton
$
48.22

 
$
53.04

 
$
(4.82
)
 
(9.1
)%
 
 
 
 
 
 
 
 
     Total Costs Per Thermal Ton Sold
$
45.43

 
$
47.53

 
$
(2.10
)
 
(4.4
)%
     Average Margin Per Thermal Ton Sold
$
16.95

 
$
17.29

 
$
(0.34
)
 
(2.0
)%

Thermal coal outside sales revenue was $1,263 million for the nine months ended September 30, 2014 compared to $1,034 million for the nine months ended September 30, 2013. The $229 million increase was attributable to a 4.3 million increase in tons sold offset, in part, by a $2.44 per ton decrease in average sales price. Thermal coal pricing was lower because of the roll-off of some higher-priced legacy sales contracts. The decrease in price was offset, in part, due to 1.4 million tons of thermal coal being priced on the export market at an average sales price of $67.18 per ton for the nine months ended September 30, 2014 compared to 1.4 million tons at an average price of $63.32 per ton for the nine months ended September 30, 2013.
Other income attributable to the thermal coal segment represents earnings from our equity affiliates that operate thermal coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.
Total cost of goods sold is comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. The costs of tons produced include items such as direct operating costs, royalty and production taxes, direct services to operations, retirement and disability, and depreciation, depletion, and amortization costs. Total cost of goods sold for thermal coal was $921 million for the nine months ended September 30, 2014, or $162 million higher than the $759 million for the nine months ended September 30, 2013. Total cost of goods sold for thermal coal was $45.43 per ton in the nine months ended September 30, 2014 compared to $47.53 per ton in the nine months ended September 30, 2013. The increase in total dollars and decrease in unit costs was primarily due to the 27.0% increase in thermal tons sold. Fixed costs are allocated over more tons, resulting in lower unit costs. These improvements were offset, in part, by various maintenance projects at Bailey Mine related to an additional longwall overhaul, a belt repair project, and 32k additional continuous miner footage. The additional continuous miner footage resulted in additional roof support, haulage, and mine maintenance costs. Unit costs were also negatively impacted in the current period due to geological conditions at Enlow Fork Mine along with geological conditions and equipment issues at the Harvey Mine.



76





HIGH VOL METALLURGICAL COAL SEGMENT
The high volatile metallurgical coal segment contributed $25 million to total Company earnings before income tax for the nine months ended September 30, 2014 compared to $32 million for the nine months ended September 30, 2013. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:

 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Company Produced High Vol Met Tons Sold (in millions)
1.1

 
1.9

 
(0.8
)
 
(42.1
)%
Average Sales Price Per High Vol Met Ton Sold
$
60.99

 
$
64.84

 
$
(3.85
)
 
(5.9
)%
 
 
 
 
 
 
 
 
Beginning Inventory Costs Per High Vol Met Ton
$

 
$

 
$

 
 %
 
 
 
 
 
 
 
 
Total Direct Operating Costs Per High Vol Met Ton Produced
$
27.30

 
$
32.10

 
$
(4.80
)
 
(15.0
)%
Total Royalty/Production Taxes Per High Vol Met Ton Produced
2.95

 
1.66

 
1.29

 
77.7
 %
Total Direct Services to Operations Per High Vol Met Ton Produced
4.11

 
5.97

 
(1.86
)
 
(31.2
)%
Total Retirement and Disability Per High Vol Met Ton Produced
3.10

 
3.11

 
(0.01
)
 
(0.3
)%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced
5.78

 
6.10

 
(0.32
)
 
(5.2
)%
     Total Production Costs Per High Vol Met Ton Produced
$
43.24

 
$
48.94

 
$
(5.70
)
 
(11.6
)%
 
 
 
 
 
 
 
 
Ending Inventory Costs Per High Vol Met Ton
$

 
$

 
$

 
 %
 
 
 
 
 
 
 
 
     Total Costs Per High Vol Met Ton Sold
$
43.24

 
$
48.94

 
$
(5.70
)
 
(11.6
)%
     Margin Per High Vol Met Ton Sold
$
17.75

 
$
15.90

 
$
1.85

 
11.6
 %

High volatile metallurgical coal outside sales revenue was $64 million for the nine months ended September 30, 2014 compared to $125 million for the nine months ended September 30, 2013. The $61 million decrease was primarily due to the 0.8 million decrease in sales tons along with the $3.85 per ton decrease in average sales price. The decrease in sales price was due to 1.1 million tons of high volatile metallurgical coal being sold on the export market at an average sales price of $60.94 per ton for the nine months ended September 30, 2014 compared to 1.7 million tons at an average price of $62.70 per ton for the nine months ended September 30, 2013. The remaining tons sold in the period-to-period comparison were sold on the domestic market.
Other income attributable to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate high volatile metallurgical coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.
Total cost of goods sold for high volatile metallurgical coal was $45 million for the nine months ended September 30, 2014, or $50 million lower than the $95 million for the nine months ended September 30, 2013. Total cost of goods sold for high volatile metallurgical coal was $43.24 per ton in the nine months ended September 30, 2014 compared to $48.94 per ton in the nine months ended September 30, 2013. The decrease in total dollars and unit costs was due to the lower tons sold in the period-to-period comparison.



77





LOW VOL METALLURGICAL COAL SEGMENT
The low volatile metallurgical coal segment contributed $30 million to total Company earnings before income tax in the nine months ended September 30, 2014 compared to $107 million in the nine months ended September 30, 2013. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:

 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Variance
 
Percent
Change
Company Produced Low Vol Met Tons Sold (in millions)
3.0

 
3.7

 
(0.7
)
 
(18.9
)%
Average Sales Price Per Low Vol Met Ton Sold
$
72.94

 
$
95.89

 
$
(22.95
)
 
(23.9
)%
 
 
 
 
 
 
 
 
Beginning Inventory Costs Per Low Vol Met Ton
$
65.68

 
$
86.38

 
$
(20.70
)
 
(24.0
)%
 
 
 
 
 
 
 
 
Total Direct Operating Costs Per Low Vol Met Ton Produced
$
37.67

 
$
41.00

 
$
(3.33
)
 
(8.1
)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced
4.46

 
5.59

 
(1.13
)
 
(20.2
)%
Total Direct Services to Operations Per Low Vol Met Ton Produced
5.57

 
5.11

 
0.46

 
9.0
 %
Total Retirement and Disability Per Low Vol Met Ton Produced
5.19

 
5.43

 
(0.24
)
 
(4.4
)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced
9.58

 
8.64

 
0.94

 
10.9
 %
     Total Production Costs Per Low Vol Met Ton Produced
$
62.47

 
$
65.77

 
$
(3.30
)
 
(5.0
)%
 
 
 
 
 
 
 
 
Ending Inventory Costs Per Low Vol Met Ton
$
52.53

 
$
65.42

 
$
(12.89
)
 
(19.7
)%
 
 
 
 
 
 
 
 
     Total Costs Per Low Vol Met Ton Sold
$
63.10

 
$
67.12

 
$
(4.02
)
 
(6.0
)%
     Margin Per Low Vol Met Ton Sold
$
9.84

 
$
28.77

 
$
(18.93
)
 
(65.8
)%

Low volatile metallurgical coal outside sales revenue was $221 million for the nine months ended September 30, 2014 compared to $356 million for the nine months ended September 30, 2013. The $135 million decrease was attributable to a $22.95 per ton lower average sales price and a 0.7 million decrease in tons sold. Average sales prices for low volatile metallurgical coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market.
Total cost of goods sold for low volatile metallurgical coal was $191 million for the nine months ended September 30, 2014, or $58 million lower than the $249 million for the nine months ended September 30, 2013. Total cost of goods sold for low volatile metallurgical coal was $63.10 per ton in the nine months ended September 30, 2014 compared to $67.12 per ton in the nine months ended September 30, 2013. The decrease in total dollars and unit costs per low volatile metallurgical ton was primarily due to lower royalty and production taxes, lower wage and wage related expenses, and a reduction in the number of degas wells drilled. The decreases were related to lower average sales prices and cost control measures that were implemented due to the weak metallurgical coal market. Part of the cost control measures included a decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014. These improvements were offset, in part, by lower tons sold.



78





OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $118 million for the nine months ended September 30, 2014 compared to a loss before income tax of $146 million for the nine months ended September 30, 2013. The other coal segment includes purchased coal activities and idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications and coal purchased from third parties and sold directly to our customers. The revenues were $8 million for the nine months ended September 30, 2014 compared to $17 million for the nine months ended September 30, 2013. The decrease in the period-to-period comparison was due to lower volumes of coal that needed to be purchased to fulfill various contracts.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue 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 offset by freight expense. Freight revenue was $23 million for the nine months ended September 30, 2014 compared to $31 million for the nine months ended September 30, 2013. The $8 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $100 million for the nine months ended September 30, 2014 compared to $84 million for the nine months ended September 30, 2013. The change is due to the following items:

 
 
For the Nine Months Ended September 30,
(in millions)
 
2014
 
2013
 
Variance
Rental Income
 
$
35

 
$
2

 
$
33

Coal Contract Buyout
 
30

 

 
30

Equity in earnings of affiliates
 
11

 
7

 
4

Royalty Income
 
15

 
13

 
2

Business Interruption Proceeds - Bailey Mine
 

 
5

 
(5
)
Gain on Sale of Assets
 
1

 
45

 
(44
)
Other
 
14

 
12

 
2

Total Other Income Coal Segment
 
$
106

 
$
84

 
$
22


Rental income increased $33 million due to equipment subleased to a third-party. These arrangements began in December 2013.
For the nine months ended September 30, 2014, $30 million of income was related to a coal customer contract buyout. The discontinued contract was a long term contract that created pricing risks for both parties. The parties agreed to an amicable settlement and anticipate a continued relationship in the future. No such transactions were entered into in the nine months ended September 30, 2013.
Equity in earnings of affiliates increased $4 million due to various transactions completed by our equity partners, none of which were individually material.
Royalty income increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
Business interruption proceeds of $5 million were received in the prior year-to-date period related to the 2012 Bailey Belt Conveyor accident.
Gain on sale of assets decreased $44 million primarily due to the sale of Potomac coal reserves, as well as the sale of a 50% interest in a joint venture in Alberta, Canada in the nine months ended September 30, 2013. No such transactions were entered into in the nine months ended September 30, 2014.
Other income increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

Other coal segment total costs were $249 million for the nine months ended September 30, 2014 compared to $278 million for the nine months ended September 30, 2013. The decrease of $29 million was primarily due to the following items:


79





 
 
For the Nine Months Ended September 30,
(in millions)
 
2014
 
2013
 
Variance
Closed and Idle Mines
 
$
62

 
$
85

 
$
(23
)
Purchased Coal
 
13

 
32

 
(19
)
Freight Expense
 
23

 
31

 
(8
)
Stock-based and Incentive Compensation
 
41

 
43

 
(2
)
Depreciation, Depletion, and Amortization
 
19

 
21

 
(2
)
General and Administrative Expense
 
33

 
28

 
5

Lease Rental Expense
 
23

 
1

 
22

Other
 
35

 
37

 
(2
)
Total Other Coal Segment Costs
 
$
249

 
$
278

 
$
(29
)

Closed and idle mine costs decreased approximately $23 million for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013. This was due to a $14 million decrease in the asset retirement obligation, primarily at the Fola Mining Complex. The remaining $9 million decrease was due to various changes in the operational status of other mines, between idled and operating throughout both periods, none of which were individually material.
Purchased coal costs decreased $19 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.
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 by freight revenue. The decrease in freight expense was due to lower shipments under contracts which CONSOL Energy contractually provides transportation services.
Stock-based and Incentive Compensation decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
Depreciation, Depletion, and Amortization decreased $2 million primarily due to various transactions that occurred throughout both periods, none of which were individually material.
General and Administrative Expense related to the other coal segment increased by $5 million primarily due to various transactions, none of which were individually material. Refer to the discussion of total general and administrative costs contained in the section entitled "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this quarterly report for detailed cost explanations.
Lease rental expense increased $22 million primarily due to equipment leases that are subleased to a third-party. The third-party subleases began in December 2013.
Other expenses related to the Other Coal segment decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.



80





OTHER SEGMENT ANALYSIS for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013:

The other segment includes activity from the sales of industrial supplies, coal terminal activity and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $314 million for the nine months ended September 30, 2014 compared to a loss before income tax of $233 million for the nine months ended September 30, 2013. The other segment also includes total Company income tax expense of $8 million for the nine months ended September 30, 2014 compared to an income tax expense of $98 million for the nine months ended September 30, 2013.

 
For the Nine Months Ended September 30,
 (in millions)
2014
 
2013
 
Variance
 
Percent
Change
Sales—Outside
$
213

 
$
198

 
$
15

 
7.6
 %
Other Income
6

 
5

 
1

 
20.0
 %
Total Revenue
219

 
203

 
16

 
7.9
 %
Cost of Goods Sold and Other Charges
269

 
274

 
(5
)
 
(1.8
)%
Depreciation, Depletion & Amortization
4

 
4

 

 
 %
Loss on Debt Extinguishment
95

 

 
95

 
100.0
 %
Interest Expense
165

 
158

 
7

 
4.4
 %
Total Costs
533

 
436

 
97

 
22.2
 %
Loss Before Income Tax
(314
)
 
(233
)
 
(81
)
 
34.8
 %
Income Tax
8

 
98

 
(90
)
 
(91.8
)%
Net Loss
$
(322
)
 
$
(331
)
 
$
9

 
(2.7
)%

Industrial supplies:

Outside Sales from industrial supplies were $184 million for the nine months ended September 30, 2014 compared to $162 million for the nine months ended September 30, 2013. The increase of $22 million was primarily related to higher sales volumes.

Total costs related to industrial supply sales were $180 million for the nine months ended September 30, 2014 compared to $159 million for the nine months ended September 30, 2013. The increase of $21 million was primarily related to higher sales volumes and various changes in inventory costs, none of which were individually material.

Coal terminal activity:

Outside Sales from terminal activity were $29 million for the nine months ended September 30, 2014 compared to $36 million for the nine months ended September 30, 2013. The decrease of $7 million was primarily attributable to decreased thru-put volumes for the current year.

Total costs related to terminal activity were $20 million for the nine months ended September 30, 2014 compared to $25 million for the nine months ended September 30, 2013. Costs decreased $5 million due to decreased thru-put volumes for the current year.

Miscellaneous other:

Additional other income of $6 million was recognized for the nine months ended September 30, 2014 compared to $5 million for the nine months ended September 30, 2013. The $1 million decrease was due to various items that occurred throughout both periods, none of which were individually material.

Other corporate costs were $333 million for the nine months ended September 30, 2014 compared to $252 million for the nine months ended September 30, 2013. Other corporate costs increased due to the following items:


81





 
 
For the Nine Months Ended September 30,
(in millions)
 
2014
 
2013
 
Variance
Loss On Debt Extinguishment
 
$
95

 
$

 
$
95

Long-Term Liability Plan Changes
 
10

 

 
10

Interest Expense
 
165

 
158

 
7

Revolver Modification Fees
 
3

 

 
3

Bank Fees
 
12

 
11

 
1

Corporate Initiative Fees and Other Legal Charges
 
6

 
12

 
(6
)
Pension Settlement
 
26

 
38

 
(12
)
CNX Gas Shareholder Settlement
 

 
20

 
(20
)
Other
 
16

 
13

 
3

 
 
$
333

 
252

 
$
81


Loss on Debt Extinguishment of $95 million was recognized in the nine months ended September 30, 2014 related to the early extinguishment of debt due to the purchase of all the 8.00% senior notes that were due in 2017 at an average premium of 1.04%, and the partial purchase of the 8.25% senior notes that were due in 2020 at an average premium of 1.075%. No such transactions occurred in the prior period.
Long-Term Liability Plan Changes include $36 million of income as a result of measurements associated with amendments to the pension and OPEB plans, which were adopted during the third quarter, offset by $46 million of expense for cash payments made to active employees related to changes in the OPEB plan.
Interest expense increased $7 million primarily due to the decrease in capitalized interest related to the Harvey Mine going into production in 2014. The increase was offset, in part, by the IRS audit resolution causing a reduction to anticipated interest (See Note 6 - Income Taxes of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q), the early payoff of the 2017 bonds and partial purchase of the 2020 bonds. The decease in interest expense also related to the additional bonds, due 2022, issued in April 2014 and August 2014 which have a lower interest rate than the 2017 and the 2020 bonds.
Revolver modification fees resulted in a $3 million acceleration of previously deferred financing fees.
Bank fees increased $1 million primarily due to various transactions that occurred throughout both periods, none of which were individually material.
Corporate initiative fees and other legal charges reflect various fees for services related to corporate initiatives to evaluate structure changes and various asset sales. These fees also include legal charges related to land title issues raised by our joint venture partners and the CNX Gas shareholder settlement case. See Note 8 - Property, Plant, and Equipment and Note 11 - Commitments and Contingencies of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.
Pension settlement expense is required when the lump sum distributions made for a given plan year exceeds the total of the service and interest costs for that same plan year. Settlement accounting was triggered in both periods. See Note 4 - Pension and Other Post-Employment Benefit Plans and Note 5 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional detail.
The CNX Gas shareholder settlement was the result of an agreement for resolution of the class actions brought by shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010. The total settlement provided for payment to the plaintiffs of $43 million, of which the Company's portion was $20 million.
Other corporate items increased $3 million primarily due to various transactions that occurred throughout both periods, none of which were individually material.

Income Taxes:

The effective income tax rate was 8.3% for the nine months ended September 30, 2014 compared to 323.0% for the nine months ended September 30, 2013. The effective rates for the nine months ended September 30, 2014 and 2013 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. For the nine months ended September 30, 2014, CONSOL Energy recognized certain tax benefits as a result of changes in estimates related to a prior-year tax provision. That resulted in a benefit of $8 million related to increased percentage of depletion deductions, offset, in part, by $1 million of tax expense due to changes in the Domestic Production Activities Deduction. Also, the Internal Revenue Service issued its audit report relating to the examination of CONSOL Energy’s 2008


82





and 2009 U.S. income tax returns during the nine months ended September 30, 2014. The result of these findings was a change in timing of certain tax deductions which increased the tax benefit of percentage of depletion by $7 million. Also, as a result of closing the IRS audit, CONSOL Energy was required to file amended state income tax returns. The company filed the required amended returns and realized a discrete state income tax charge of $5 million which was offset by a federal income tax benefit of $2 million. See Note 6 - Income Taxes of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information. 
 
For the Nine Months Ended September 30,
(in millions)
2014
 
2013
 
Variance
 
Percent
Change
Total Company Earnings Before Income Tax
$
103

 
$
30

 
$
73

 
(242.5
)%
Income Tax Expense
$
8

 
$
98

 
$
(90
)
 
(91.5
)%
Effective Income Tax Rate
8.3
%
 
323.0
%
 
(314.7
)%
 
 



83





Liquidity and Capital Resources
CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CONSOL Energy entered into a new Amended and Restated Credit Agreement dated June 18, 2014 for a $2.0 billion senior secured revolving credit facility which expires on June 18, 2019. The new senior revolving credit facility replaced CONSOL Energy's existing $1.0 billion senior secured revolving credit facility which had been entered into as of April 12, 2011 and amended and restated on December 5, 2013 and the existing $1.0 billion senior secured revolving credit facility of CNX Gas Corporation and its subsidiaries that had been entered into as of April 12, 2011. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $2.0 billion of borrowings, which includes $750 million letters of credit aggregate sub-limit. CONSOL Energy can request an additional $500 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan value of CONSOL Energy's proved gas reserves. The facility includes a minimum interest coverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The interest coverage ratio is calculated as the ratio of Adjusted EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 5.26 to 1.00 at September 30, 2014. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, uncommon gains and losses, gains and losses on discontinued operations, losses on debt extinguishment and includes cash distributions received from affiliates, plus pro-rata earnings from material acquisitions. The facility also includes a minimum current ratio covenant of no less than 1.00 to 1.00, measured quarterly. The minimum current ratio is calculated as the ratio of current assets, plus revolver availability, to current liabilities excluding borrowings under the revolver and accounts receivable securitization facility. The minimum current ratio was 2.33 to 1.00 at September 30, 2014. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. The credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems. The facility permits CONSOL Energy to separate its gas and coal businesses if the leverage ratio (which, is essentially, the ratio of debt to EBITDA) of the gas business immediately after the separation would not be greater than 2.75 to 1.00. At September 30, 2014, the facility had no outstanding borrowings and $265 million of letters of credit outstanding, leaving $1,735 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.
CONSOL Energy also has an accounts receivable securitization facility. This facility allows the Company to receive, on a revolving basis, up to $125 million of short-term funding and letters of credit. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivable. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds is based on commercial paper or LIBOR rates plus a charge for administrative services paid to financial institutions. At September 30, 2014, eligible accounts receivable totaled approximately $83 million. At September 30, 2014, the facility had no outstanding borrowings and $62 million of letters of credit outstanding, leaving $21 million of unused capacity.
Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. The risks include declines in our stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact our collection of trade receivables. As a result, CONSOL Energy regularly monitors the creditworthiness of our customers. We believe that our current group of customers are financially sound and represent no abnormal business risk.

CONSOL Energy believes that cash generated from operations, asset sales and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments and to provide required letters of credit. Nevertheless, the ability of CONSOL Energy to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the coal and gas industries and other financial and business factors, some of which are beyond CONSOL Energy’s control.
In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap and option transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $43 million at September 30, 2014. The ineffective portion of these contracts was $2.7 million during the nine months ended September 30, 2014. No issues related to our hedge agreements have been encountered to date.


84





CONSOL Energy frequently evaluates potential acquisitions. CONSOL Energy has funded acquisitions with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance that additional capital resources, including debt and equity financing, will be available to CONSOL Energy on terms which CONSOL Energy finds acceptable, or at all.

Cash Flows (in millions)
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
Change
Cash Flows from Operating Activities
$
850

 
$
589

 
$
261

Cash Used in Investing Activities
$
(925
)
 
$
(559
)
 
$
(366
)
Cash (Used in) Provided by Financing Activities
$
(27
)
 
$
(30
)
 
$
3


Cash flows provided by operating activities changed in the period-to-period comparison primarily due to the following items:

Net income increased $168 million in the period-to-period comparison.
Adjustments to reconcile net income to cash flow provided by operating activities increased $95 million due to the loss on extinguishment of debt, $38 million from the return on the equity in earnings, and additional depreciation, depletion and amortization of $77 million.
Return on equity investments of $47 million was related to IPO proceeds received from CONE Midstream Partners, LP.
Income tax refunds of $71 million, net of payments, in the nine months ended September 30, 2014 compared to $46 million of payments in the nine months ended September 30, 2013.
These increases were offset, in part, by changes in discontinued operations.
Other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both periods also contributed to the increase in operating cash flows.

Net cash used in investing activities changed in the period-to-period comparison primarily due to the following items:

Capital expenditures from continuing operations increased $154 million in the period-to-period comparison due to:

Gas segment capital expenditures increased $183 million. The increase was comprised of increased drilling and completions activity in the Marcellus and Utica plays and various other individually insignificant projects. The increase was partially offset by $174 million of carry received from our JV Partners.
Coal segment capital expenditures decreased $2 million. This was comprised of an increase of $57 million for the acquisition of the Harvey Mine longwall shields, offset by a decrease of $22 million related to the Enlow Fork Overland Belt Project, which was completed in February 2014 and a decrease of $37 million in various other projects, none of which were material; and
Other capital expenditures decreased $27 million due to a decrease in capitalized interest of $9 million related to the completion of the Harvey Mine capital project and a decrease of $18 million related to various other transactions that occurred throughout the nine months ended September 30, 2014, none of which were individually material.

Proceeds from the sale of assets, continuing operations, increased $4 million in the period-to-period comparison due to:

$75 million received in March 2014 related to the Harvey Mine shield sale-leaseback;
$46 million received in January 2014 as a reimbursement from Noble Energy for 50% of the Dominion Resources lease acquisition;
$25 million received in June 2013 related to the sale of Potomac Coal reserves;
$71 million received in January 2013 related to the Bailey Mine longwall shield sale-leaseback;
$25 million received in August 2013 related to the sale of the Crowsnest Pass.
(See Note 2 - Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for more information.)



85





Net investments in equity affiliates increased $127 million primarily due to a $157 million increase on the return of investment from the IPO of CONE Midstream Partners, LP, offset by $30 million of additional capital contributions to CONE in 2014.
Restricted cash decreased $56 million due to the release of the cash restrictions including $48 million associated with the Ram River & Scurry Canadian asset proceeds and $20 million associated with the Ryerson Dam Settlement. This was offset by the additional $12 million of restricted cash associated with the sale of the 50% interest in the CONSOL/Devon Energy joint venture in Alberta, Canada in August 2013.
There were no investing activities related to discontinued operations in 2014. Discontinued Operations in 2013 consisted of $175 million of capital expenditures offset by $134 million in proceeds related to two sales leasebacks of two long wall shields.

Net cash used in financing activities changed in the period-to-period comparison primarily due to the following items:

In the nine months ended September 30, 2014, CONSOL Energy repaid $4 million of miscellaneous borrowings. In the nine months ended September 30, 2013, CONSOL Energy repaid $32 million of miscellaneous borrowings.
In the nine months ended September 30, 2014, CONSOL Energy paid $12 million related to transaction fees in the refinancing of the revolving credit facilities, as compared to $47 million of short term borrowings received under the revolving credit facilities in the nine months ended September 30, 2013.
In the nine months ended September 30, 2014, CONSOL Energy received $13 million related to the issuance of common stock in its stock based compensation plans as compared to $2 million in the nine months ended September 30, 2013.
In 2013, CONSOL Energy received $7 million of borrowings under its Securitization Facility, there was no activity in 2014.
In the nine months ended September 30, 2014, CONSOL Energy had net proceeds from long-term borrowings of $16 million. See Note 11 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Staments of this Form 10-Q for additional details.
In the nine months ended September 30, 2014, CONSOL Energy paid three quarterly dividends totaling $43 million at an amount per share of $.0625. In the nine months ended September 30, 2013, CONSOL Energy paid only two quarterly dividends totaling $57 million at an amount per share of $.125. This was due to the accelerated declaration and payment of the regular quarterly dividend in the fourth quarter of 2012 which resulted in no dividends paid in the first quarter of 2013.
The remaining change is due to various other transactions that occurred throughout both periods, none of which were individually material.

The following is a summary of our significant contractual obligations at September 30, 2014 (in thousands):
 
Payments due by Year
 
Less Than
1 Year
 
1-3 Years
 
3-5 Years
 
More Than
5 Years
 
Total
Purchase Order Firm Commitments
$
130,669

 
$
175,764

 
$
65,408

 
$
16,006

 
$
387,847

Gas Firm Transportation and Processing
110,196

 
195,363

 
158,986

 
476,819

 
941,364

Long-Term Debt
3,558

 
6,712

 
2,619

 
3,226,841

 
3,239,730

Interest on Long-Term Debt
212,018

 
429,011

 
428,758

 
473,359

 
1,543,146

Capital (Finance) Lease Obligations
8,667

 
15,015

 
13,569

 
14,530

 
51,781

Interest on Capital (Finance) Lease Obligations
3,256

 
4,883

 
3,144

 
1,213

 
12,496

Operating Lease Obligations
104,883

 
183,147

 
99,878

 
83,014

 
470,922

Long-Term Liabilities—Employee Related (a)
88,071

 
184,506

 
187,115

 
479,379

 
939,071

Other Long-Term Liabilities (b)
328,605

 
194,694

 
85,527

 
356,095

 
964,921

Total Contractual Obligations (c)
$
989,923

 
$
1,389,095

 
$
1,045,004

 
$
5,127,256

 
$
8,551,278

 _________________________
(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 payout table due to the uncertainty regarding amounts to be contributed. Estimated fourth quarter 2014 contributions are expected to be approximately $0.5 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.


86





Debt
At September 30, 2014, CONSOL Energy had total long-term debt and capital lease obligations of $3.3 billion outstanding, including the current portion of long-term debt of $12.2 million. This long-term debt consisted of:
An aggregate principal amount of $1.02 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% senior unsecured 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 $1.85 billion of 5.875% notes due in April 2022. Interest on the notes is payable April 15 and October 15 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.
Advance royalty commitments of $11 million with an average interest rate of 7.93% per annum.
An aggregate principal amount of $4 million on other various rate notes maturing through June 2031.
An aggregate principal amount of $52 million of capital leases with a weighted average interest rate of 6.29% per annum.

At September 30, 2014, CONSOL Energy had no outstanding borrowings and had approximately $265 million of letters of credit outstanding under its $2.0 billion senior secured revolving credit facility.
At September 30, 2014, CONSOL Energy had no outstanding borrowings and had $62 million of letters of credit outstanding under its accounts receivable securitization facility.
Total Equity and Dividends
CONSOL Energy had total equity of $5.3 billion at September 30, 2014 and $5.0 billion at December 31, 2013. Total equity increased primarily due to net income in the current period, amortization of stock-based compensation, changes in comprehensive income, and issuance of common stock. The increase in equity was offset, in part, by payment of dividends and treasury stock activity. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.
Dividend information for the current year to date were as follows:
Declaration Date
 
Amount Per Share
 
Record Date
 
Payment Date
February 3, 2014
 
$0.0625
 
February 14, 2014
 
February 28, 2014
April 30, 2014
 
$0.0625
 
May 12, 2014
 
May 30, 2014
July 30, 2014
 
$0.0625
 
August 15, 2014
 
September 2, 2014
October 29, 2014
 
$0.0625
 
November 10, 2014
 
December 2, 2014

The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of Directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. Our credit facility limits our ability to pay dividends in excess of an annual rate of $0.50 per share when our leverage ratio exceeds 3.50 to 1.00 and subject to an aggregate amount up to the then cumulative credit calculation. The total leverage ratio was 2.68 to 1.00 and the cumulative credit was approximately $450 million at September 30, 2014. The credit facility does not permit dividend payments in the event of default. The indentures to the 2020 and 2021 notes limit dividends to $0.40 per share annually unless several conditions are met. The indentures to the 2022 notes limit dividends to $0.50 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the nine months ended September 30, 2014.



87





Off-Balance Sheet Transactions

CONSOL Energy does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q. CONSOL Energy participates in various multi-employer benefit plans such as the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at September 30, 2014. The various multi-employer benefit plans are discussed in Note 18—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of the December 31, 2013 Form 10-K. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters of credit to secure our financial obligations for employee-related, environmental, performance and various other items which are not reflected on the consolidated balance sheet at September 30, 2014. Management believes these items will expire without being funded. See Note 12 - Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CONSOL Energy.



88





Forward-Looking Statements

We are including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. With the exception of historical matters, the matters discussed in this Quarterly Report on Form 10-Q are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Quarterly Report on Form 10-Q speak only as of the date of this Quarterly Report on Form 10-Q; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

deterioration in global 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 demand for or prices we receive for our natural gas and coal 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 natural gas and coal to market;
a loss of our competitive position because of the competitive nature of the natural gas and coal industries, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;
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 natural gas and coal;
foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;
the risks inherent in natural gas and coal 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;
decreases in the availability of, or increases in, the price of commodities or capital equipment used in our mining operations;
decreases in the availability of, an increase in the prices charged by third party contractors or, failure of third party contractors to provide quality services to us in a timely manner could impact our profitability;
obtaining and renewing governmental permits and approvals for our natural gas and coal 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 natural gas and coal operations;
our ability to find adequate water sources for our use in gas drilling, or our ability to dispose of water used or removed from strata in connection with our gas operations at a reasonable cost and within applicable environmental rules;
the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut down a natural gas well or a mine;
the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current gas and coal operations;
the effects of mine closing, reclamation, gas well closing and certain other liabilities;
uncertainties in estimating our economically recoverable gas and coal reserves;
defects may exist in our chain of title and we may incur additional costs associated with perfecting title for gas or coal rights on some of our properties or failing to acquire these additional rights may result in a reduction of our estimated reserves;
the impacts of various asbestos litigation claims;


89





the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities Exchange Act of 1934;
increased exposure to employee-related long-term liabilities;
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 that we recently have completed or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, 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 terms of our existing joint ventures restrict our flexibility, actions taken by the other party in our gas joint ventures may impact our financial position and various circumstances could cause us not to realize the benefits we anticipate receiving from these joint ventures;
risks associated with our debt;
replacing our natural gas reserves, which if not replaced, will cause our gas reserves and gas production to decline;
our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;
changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs, could cause our financial position and profitability to deteriorate;
failure to appropriately allocate capital and other resources among our strategic opportunities may adversely affect our financial condition;
failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its obligations under various arrangements, which we guaranteed, could materially or adversely affect our results of operations, financial position, and cash flows; and
other factors discussed in the 2013 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.



90






ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In addition to the risks inherent in operations, CONSOL Energy is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CONSOL Energy's exposure to the risks of changing commodity prices, interest rates and foreign exchange rates.

CONSOL Energy is exposed to market price risk in the normal course of selling natural gas production and to a lesser extent in the sale of coal. CONSOL Energy sells coal under both short-term and long-term contracts with fixed price and/or indexed price contracts that reflect market value. CONSOL Energy uses fixed-price contracts, options and derivative commodity instruments that qualify as cash-flow hedges under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification to minimize exposure to market price volatility in the sale of natural gas. Our risk management policy prohibits the use of derivatives for speculative purposes.

CONSOL Energy has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base. All of the derivative instruments without other risk assessment procedures are held for purposes other than trading. They are used primarily to mitigate uncertainty, volatility and cover underlying exposures. CONSOL Energy's market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.

CONSOL Energy believes that the use of derivative instruments, along with our risk assessment procedures and internal controls, mitigates our exposure to material risks. However, the use of derivative instruments without other risk assessment procedures could materially affect CONSOL Energy's results of operations depending on market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.

For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of CONSOL Energy's 2013 Form 10-K.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at September 30, 2014. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $62.6 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $31.6 million.
CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At September 30, 2014, CONSOL Energy had $3.30 billion aggregate principal amount of debt outstanding under fixed-rate instruments and no amount of debt outstanding under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were no borrowings outstanding for the three months ended September 30, 2014.

Almost all of CONSOL Energy’s transactions are denominated in U.S. dollars, and, as a result, it does not have material exposure to currency exchange-rate risks.




















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Hedging Volumes

As of October 14, 2014, our hedged volumes for the periods indicated are as follows:
 
For the Three Months Ended
 
 
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
Total Year
2014 Fixed Price Volumes
 
 
 
 
 
 
 
 
 
Hedged Mcf
N/A
 
N/A
 
N/A
 
41,740,578

 
41,740,578

Weighted Average Hedge Price per Mcf
N/A
 
N/A
 
N/A
 
$
4.58

 
$
4.58

2015 Fixed Price Volumes
 
 
 
 
 
 
 
 
 
Hedged Mcf
20,376,220

 
20,602,622

 
20,829,025

 
20,829,025

 
82,636,892

Weighted Average Hedge Price per Mcf
$
4.07

 
$
4.07

 
$
4.07

 
$
4.07

 
$
4.07

2016 Fixed Price Volumes
 
 
 
 
 
 
 
 
 
Hedged Mcf
18,711,058

 
18,711,058

 
18,916,674

 
18,916,674

 
75,255,464

Weighted Average Hedge Price per Mcf
$
4.17

 
$
4.17

 
$
4.17

 
$
4.17

 
$
4.17


ITEM 4.
CONTROLS AND PROCEDURES

Disclosure controls and procedures. CONSOL Energy, under the supervision and with the participation of its management, including CONSOL Energy’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, CONSOL Energy’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, 2014 to ensure that information required to be disclosed by CONSOL Energy in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in internal controls over financial reporting. There were no changes in the Company's internal controls over financial reporting that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II: OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS
The first through the ninth paragraphs of Note 12—Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q are incorporated herein by reference.

ITEM 4.     MINE SAFETY DISCLOSURES
The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in exhibit 95 to this quarterly report.



92





ITEM 6.
EXHIBITS
4.1

 
Registration Rights Agreement, dated as of August 12, 2014, among CONSOL Energy Inc., the subsidiary guarantors party thereto and Goldman, Sachs & Co. as the initial purchaser named therein, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on August 12, 2014.
 
 
 
31.1

  
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
31.2

  
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
32.1

  
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.
 
 
95

 
Mine Safety and Health Administration Safety Data.
 
 
101

  
Interactive Data File (Form 10-Q for the quarterly period ended September 30, 2014 furnished in XBRL).
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.




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

Dated: November 4, 2014
 
 
CONSOL ENERGY INC.
 
 
 
 
 
By: 
 
/S/    NICHOLAS J. DEIULIIS       
 
 
 
Nicholas J. DeIuliis
 
 
 
Chief Executive Officer and President
(Duly Authorized Officer and Principal Executive Officer)
 
 
 
 
 
By: 
 
/S/    DAVID M. KHANI       
 
 
 
David M. Khani
 
 
 
Chief Financial Officer and Executive Vice President
(Duly Authorized Officer and Principal Financial Officer)
 
 
 
 
 
By: 
 
/S/    LORRAINE L. RITTER     
 
 
 
Lorraine L. Ritter
 
 
 
Controller and Vice President
(Duly Authorized Officer and Principal Accounting Officer)
 


94