Document/ExhibitDescriptionPagesSize 1: 10-K Annual Report HTML 3.27M
2: EX-10.54 Amended and Restated Change in Control Severance HTML 138K
Agreement
3: EX-10.55 Change in Control Severance Agreement HTML 137K
4: EX-10.67 Rsu Award Agreement HTML 75K
5: EX-10.69 Psu Award Agreement HTML 103K
7: EX-14.1 Code of Employee Business Conduct and Ethics HTML 108K
8: EX-21 Subsidiaries of Consol Energy Inc. HTML 50K
9: EX-23.1 Consent of Ernst & Young LLP HTML 41K
10: EX-23.2 Consent of Nertherland Sewell & Associates, Inc. HTML 42K
11: EX-23.3 Consent of Golder Associates Inc. HTML 42K
16: EX-95 Mine Safety Disclosure Exhibit HTML 129K
17: EX-99.1 Engineers Audit Letter HTML 89K
18: EX-99.2 Mining Egineers' and Geologits' Audit Letter HTML 47K
6: EX-12 Computation of Ratio of Earnings to Fixed Charges HTML 57K
12: EX-31.1 Certification of Chief Executive Officer Pursuant HTML 48K
to Section 302
13: EX-31.2 Certification of Chief Financial Officer Pursuant HTML 47K
to Section 302
14: EX-32.1 Certification of Chief Executive Officer Pursuant HTML 42K
to 18 U.S.C. Section 1350
15: EX-32.2 Certification of Chief Financial Officer Pursuant HTML 42K
to 18 U.S.C. Section 1350
110: R1 Document and Entity Information HTML 69K
82: R2 Consolidated Statements of Income HTML 210K
102: R3 Consolidated Statement of Comprehensive Income HTML 73K
115: R4 Consolidated Statement of Comprehensive Income HTML 48K
Parentheticals
145: R5 Consolidated Balance Sheets HTML 216K
87: R6 Consolidated Balance Sheets Parentheticals HTML 70K
101: R7 Consolidated Statements of Stockholders' Equity HTML 196K
75: R8 Consolidated Statements of Cash Flows HTML 195K
62: R9 Discontinued Operations (Notes) HTML 63K
147: R10 Acquisitions and Dispositions HTML 60K
117: R11 Other Income HTML 74K
116: R12 Interest Expense HTML 57K
124: R13 Income Taxes HTML 178K
125: R14 Stock Repurchase (Notes) HTML 44K
121: R15 Inventories HTML 51K
126: R16 Accounts Receivable Securitization HTML 50K
103: R17 Property, Plant and Equipment HTML 89K
112: R18 Short-Term Notes Payable HTML 51K
119: R19 Other Accrued Liabilities HTML 73K
159: R20 Long-Term Debt HTML 66K
137: R21 Leases HTML 89K
94: R22 Pension and OPEB HTML 459K
118: R23 CWP and Workers Comp HTML 205K
98: R24 Other Employee Benefits HTML 66K
51: R25 Stock Based Compensation HTML 144K
139: R26 Supplemental Cash Flow HTML 54K
152: R27 Concentrations of Credit Risk HTML 60K
69: R28 Fair Value of Financial Instruments HTML 64K
68: R29 Derivatives HTML 71K
73: R30 Commitments and Contingencies HTML 118K
74: R31 Segment Information HTML 448K
76: R32 Guarantor Subsidiaries Financial Information HTML 1.29M
37: R33 Related Party HTML 50K
135: R34 Supplemental Coal Data (Unaudited) HTML 77K
91: R35 Supplemental Gas Data HTML 263K
95: R36 Supplemental Quarterly Info (Unaudited) HTML 159K
56: R37 Significant Accounting Policy (Policies) HTML 329K
158: R38 Mine Closing, Reclamation, and Gas Well Closing HTML 63K
ARO Accounting Policy (Policies)
25: R39 Property, Plant and Equipment PP&E Accounting HTML 57K
Policy (Policies)
79: R40 Derivatives Derivatives Policy (Policies) HTML 43K
143: R41 Significant Accounting Policy (Tables) HTML 110K
53: R42 Discontinued Operations (Tables) HTML 59K
67: R43 Other Income (Tables) HTML 73K
72: R44 Interest Expense (Tables) HTML 55K
83: R45 Mine Closing, Reclamation, and Gas Well Closing HTML 54K
(Tables)
36: R46 Inventories (Tables) HTML 49K
61: R47 Property, Plant and Equipment (Tables) HTML 83K
28: R48 Other Accrued Liabilities (Tables) HTML 72K
141: R49 Long-Term Debt Annual Discounted Maturities HTML 71K
(Tables)
52: R50 Leases (Tables) HTML 88K
136: R51 Pension and OPEB (Tables) HTML 426K
57: R52 CWP and Workers Comp (Tables) HTML 201K
80: R53 Other Employee Benefits (Tables) HTML 99K
27: R54 Stock Based Compensation (Tables) HTML 119K
33: R55 Supplemental Cash Flow (Tables) HTML 49K
71: R56 Fair Value of Financial Instruments (Tables) HTML 60K
43: R57 Derivatives (Tables) HTML 57K
148: R58 Commitments and Contingencies (Tables) HTML 100K
89: R59 Segment Information (Tables) HTML 445K
122: R60 Guarantor Subsidiaries Financial Information HTML 1.21M
(Tables)
60: R61 Supplemental Coal Data (Unaudited) (Tables) HTML 74K
64: R62 Supplemental Gas Data (Tables) HTML 322K
132: R63 Supplemental Quarterly Info (Unaudited) (Tables) HTML 158K
127: R64 Significant Accounting Policy Anit-Dilutive HTML 62K
Securities (Details)
93: R65 Significant Accounting Policy Earnings Per Share HTML 119K
(Details)
130: R66 Significant Accounting Policy Common Stock HTML 49K
Rollforward (Details)
58: R67 Significant Accounting Policy Other (Details) HTML 44K
99: R68 Significant Accounting Policy Other Comprehensive HTML 71K
Income (Details)
151: R69 Significant Accounting Policy Accumulated Other HTML 119K
Comprehensive Income (Details)
31: R70 Discontinued Operations (Details) HTML 51K
50: R71 Discontinued Operations Income (Loss) from HTML 70K
Discontinued Operations (Details)
81: R72 Discontinued Operations Balance Sheet (Details) HTML 43K
41: R73 Acquisitions (Details) HTML 93K
157: R74 Dispositions (Details) HTML 111K
54: R75 Other Income (Details) HTML 78K
45: R76 Interest Expense (Details) HTML 55K
49: R77 Income Taxes Income Tax Components (Details) HTML 61K
34: R78 Income Taxes Effective Tax Rate Reconciliation HTML 129K
(Details)
38: R79 Income Taxes Income Taxes (Details) HTML 82K
113: R80 Income Taxes Net Deferred Tax assets/Liabilities HTML 126K
(Details)
47: R81 Income Taxes Unrecognized tax benefits (Details) HTML 66K
149: R82 Mine Closing, Reclamation, and Gas Well Closing HTML 61K
(Details)
77: R83 Inventory Components (Details) HTML 54K
120: R84 Accounts Receivable Securitization (Details) HTML 59K
129: R85 Property, Plant and Equipment PROPERTY PLANT AND HTML 84K
EQUIPMENT (Details)
46: R86 Property, Plant and Equipment Assets Amortized by HTML 74K
Units of Production (Details)
48: R87 Property, Plant and Equipment Capital Leases HTML 54K
(Details)
146: R88 Property, Plant and Equipment Joint Participation HTML 48K
Agreements (Details)
42: R89 Short-Term Notes Payable (Details) HTML 70K
114: R90 Other Accrued Liabilities (Details) HTML 97K
106: R91 Long-Term Debt (Details) HTML 87K
133: R92 Long-Term Debt Debt Maturity Schedule (Details) HTML 94K
105: R93 Leases Operating Leases (Details) HTML 84K
88: R94 Leases Capital Leases (Details) HTML 72K
140: R95 Pension and OPEB Pension and OPEB Liability HTML 368K
Disclosures (Details)
85: R96 Pension and OPEB Pension Plan Assets Fair Value HTML 300K
(Details)
55: R97 CWP and Workers Comp (Details) HTML 245K
96: R98 Other Employee Benefits Long-Term Disability HTML 68K
(Details)
90: R99 Other Employee Benefits MultiEmployer Plans HTML 63K
(Details)
70: R100 Stock Based Compensation (Details) HTML 73K
160: R101 Stock Based Compensation Weighted Average Fair HTML 74K
Value of Grants (Details)
131: R102 Stock Based Compensation Stock Option Rollforward HTML 175K
(Details)
104: R103 Stock Based Compensation Restricted and HTML 113K
Performance Stock Unit Rollforward (Details)
35: R104 Supplemental Cash Flow Supplemental Cash Flow HTML 64K
(Details)
142: R105 Concentrations of Credit Risk (Details) HTML 54K
150: R106 Financial Instruments Measured at Fair Value on a HTML 75K
Recurring Basis (Details)
144: R107 Carrying Amounts and Fair Values of Financial HTML 61K
Instruments for Which the Fair Value Option Was
Not Elected (Details)
100: R108 Derivatives Derivates Impact on Income (Details) HTML 81K
44: R109 Derivatives Derivatives by Balance Sheet Location HTML 82K
(Details)
123: R110 Maximum Potential Total of Future Payments Under HTML 164K
Commitment Instruments (Details)
59: R111 Unrecorded Unconditional Purchase Obligation HTML 59K
(Details)
26: R112 Segment Information Industry Segment Results HTML 333K
(Details)
86: R113 Reconciliation of Segment Information, Revenue and HTML 110K
Other Income (Details)
78: R114 Reconciliation of Segment Information, Total HTML 90K
Assets (Details)
138: R115 Segment Information Reconciliation of Earnings HTML 58K
Before Income Tax (Details)
63: R116 Guarantor Subsidiaries Income Statement (Details) HTML 527K
154: R117 Guarantor Subsidiaries Financial Information HTML 53K
Additional Information (Details)
39: R118 Guarantor Subsidiaries Balance Sheet (Detail) HTML 426K
109: R119 Guarantor Subsidiaries, Condensed Statement of HTML 273K
Cash Flows (Detail)
128: R120 Guarantor Subsidiaries Financial Information HTML 143K
Guarantor Subsidiaries Comprehensive Income
Statement (Details)
29: R121 Related Party (Details) HTML 65K
107: R122 Supplemental Coal Data (Unaudited) (Details) HTML 93K
97: R123 Supplemental Gas Data Capitalized Costs (Details) HTML 73K
32: R124 Supplemental Gas Data Oil and Gas Expenditures HTML 56K
(Details)
111: R125 Supplemental Gas Data Results of Operations HTML 94K
(Details)
156: R126 Supplemental Gas Data Average Unit Prices HTML 61K
(Details)
40: R127 Supplemental Gas Data Acreages (Details) HTML 70K
65: R128 Supplemental Gas Data Oil and Gas Reserve HTML 149K
Quantities (Details)
134: R129 Supplemental Gas Data Exploratary Wells (Details) HTML 56K
155: R130 Supplemental Gas Data PV-10 (Details) HTML 67K
92: R131 Supplemental Gas Data PV-10 Reconciliation HTML 111K
(Details)
108: R132 Supplemental Quarterly Info (Unaudited) (Details) HTML 118K
153: XML IDEA XML File -- Filing Summary XML 242K
30: EXCEL IDEA Workbook of Financial Reports XLSX 868K
66: EXCEL IDEA Workbook of Financial Reports (.xls) XLS 8.44M
19: EX-101.INS XBRL Instance -- cnx-20141231 XML 11.72M
21: EX-101.CAL XBRL Calculations -- cnx-20141231_cal XML 359K
22: EX-101.DEF XBRL Definitions -- cnx-20141231_def XML 1.87M
23: EX-101.LAB XBRL Labels -- cnx-20141231_lab XML 3.48M
24: EX-101.PRE XBRL Presentations -- cnx-20141231_pre XML 2.44M
20: EX-101.SCH XBRL Schema -- cnx-20141231 XSD 367K
84: ZIP XBRL Zipped Folder -- 0001070412-15-000009-xbrl Zip 691K
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o
Indicate
by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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
The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 2014, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price of the common stock on the New York Stock Exchange on such date was $6,530,992,270.
Portions of CONSOL Energy's Proxy Statement for the Annual Meeting of Shareholders to be held on May 6, 2015, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III.
The following are abbreviations of certain measurement terms commonly used in the oil and gas industry and included within this Form 10-K:
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.
FORWARD-LOOKING STATEMENTS
We
are including the following cautionary statement in this Annual Report on Form 10-K 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 Annual Report on Form 10-K are forward-looking statements (as defined in Section 21E of the Exchange Act) 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 Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; 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 economic conditions in any of the industries in which our customers operate may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital;
•
prices for natural gas, natural gas liquids and coal are volatile and can fluctuate widely based upon a number of factors beyond our control including
oversupply relative to the demand available for our products, weather and the price and availability of alternative fuels. An extended decline in the prices we receive for our natural gas, natural gas liquids and coal affecting our operating results and cash flows;
•
foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;
•
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;
•
the risks inherent in natural gas and coal operations, including our reliance upon third party contractors, being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant
3
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;
•
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 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, oil and coal reserves;
•
defects
may exist in our chain of title and we may incur additional costs associated with perfecting title for gas rights on some of our properties or failing to acquire these additional rights may result in a reduction of our estimated reserves;
•
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 gas and oil reserves, which if not replaced, will cause our gas and oil reserves and 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;
•
information theft, data corruption, operational disruption and/or financial loss resulting from a terrorist attack or cyber incident;
•
operating in a single geographic area;
•
our
inability to complete the proposed initial public offerings of a master limited partnership (MLP) owning certain of our thermal coal assets or a subsidiary owning certain of our metallurgical coal asset (Metco) on the terms currently contemplated; and
•
other factors discussed in this 2014 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.
A registration statement relating to the securities of the MLP and Metco that would be sold in the offering has not been filed with the Securities and Exchange Commission or become effective. This announcement
does not constitute an offer to sell, or the solicitation of an offer to buy, any securities.
4
PART I
ITEM 1.
Business
General
CONSOL
Energy is an integrated energy company operated through two primary divisions, oil and gas exploration and production (E&P) and coal mining. The E&P division is focused on Appalachian area natural gas and liquids activities, including production, gathering, processing and acquisition of natural gas properties in the Appalachian Basin. The coal division is focused on the extraction and preparation of coal, also in the Appalachian Basin.
CONSOL Energy was incorporated in Delaware in 1991, but its predecessors had been mining coal, primarily in the Appalachian Basin, since 1864. CONSOL Energy entered the natural gas business in the 1980s initially to increase the safety and efficiency of our coal mines by capturing methane from coal seams prior to mining, which makes the mining process safer and more efficient. Over the past ten years, CONSOL Energy's natural gas business
has grown by approximately 330% to produce 235.7 net Bcfe in 2014. This business has grown from coalbed methane production in Virginia into other unconventional production, such as the Marcellus Shale and Utica Shale, in the Appalachian Basin. This growth was accelerated with the 2010 asset acquisition of the Appalachian Exploration & Production business of Dominion Resources, Inc. Subsequently, on December 5, 2013 we sold Consolidation Coal Company and certain subsidiaries, including five active coal mines in West Virginia, to a subsidiary of Murray Energy Corporation.
Our E&P Division operates, develops and explores for natural gas primarily in Appalachia (Pennsylvania, West Virginia, Ohio, Virginia and Tennessee). Currently,
our primary focus is the continued development of our Marcellus Shale acreage and the exploration and development of our Utica Shale acreage. We believe that our concentrated operating area, our legacy surface acreage position, our regional operating expertise, our geological logs from nearly 100 years of shallow oil and gas drilling activity in the region, our held by production acreage position, and our ability to coordinate gas drilling with coal mining activity gives us a significant operating advantage over our competitors. We expect to produce 300-310 Bcfe for 2015 and achieve 30% annual gas production growth in 2016.
We are also party to two strategic joint ventures, one with Noble Energy, Inc. (Noble) in the Marcellus Shale and one with a subsidiary of Hess Corporation (Hess) in the Utica Shale. These joint ventures require our partners to pay a portion of our qualifying
drilling and completion costs in certain circumstances, which improves drilling economics and enables the acceleration of development of these assets.
Our land holdings in the Marcellus Shale and Utica Shale plays cover large areas, provide multi-year drilling opportunities and, collectively, have sustainable lower risk growth profiles. We currently control approximately 441,000 net acres in the Marcellus Shale and approximately 226,000 net acres in the Utica Shale in Ohio, West Virginia, and Pennsylvania. In addition, we estimate that approximately 345,000 net acres of our Marcellus Shale acreage in Pennsylvania and West Virginia are prospective for the slightly shallower Upper Devonian Shale. We also have 2.4 million net acres in our coalbed methane play.
Highlights of our 2014 production
include the following:
•
Total production of 645,792 Mcfe per day, an increase of 37% over 2013;
•
92% Natural Gas, 8% Liquids; and
•
47% Marcellus, 34% coalbed methane, 7% Utica, and 12% other.
At December
31, 2014, our proved reserves had the following characteristics:
•
6.8 Tcfe of proved reserves;
•
92.5% natural gas;
•
46.9% proved developed;
•
71.9%
operated; and
•
A reserve life ratio of 28.97 years (based on 2014 production).
Highlights of coal activities from continuing operations in 2014 include the following:
•
Underground mining complexes are among the safest in the United States of America;
•
Production
of 32.2 million tons of coal from continuing operations;
•
Coal reserve holdings of 3.2 billion tons;
•
5% of coal sales delivered to export markets;
5
•
72%
of coal sales to domestic utilities; and
•
Harvey Mine in southwest Pennsylvania came on-line in March 2014.
Additionally, we provide energy services, including coal terminal services (the Baltimore Terminal), water services and land resource management services.
The following map provides the location of CONSOL Energy's gas and coal operations by region:
CONSOL Energy
defines itself through its core values which are:
•
Safety,
•
Compliance, and
•
Continuous Improvement.
These values are the foundation of CONSOL Energy's
identity and are the basis for how management defines continued success. We believe CONSOL Energy's rich resource base, coupled with these core values, allows management to create value for the long-term. The electric power industry generates approximately two-thirds of its output by burning natural gas or coal, the two fuels we produce. We believe that the use of natural gas and coal will continue for many years as the principal fuel sources for electricity in the United States. Additionally, we believe that as worldwide economies grow, the demand for electricity from fossil fuels will grow as well, resulting in expansion of worldwide demand for our coal and potentially natural gas.
CONSOL Energy's Strategy
CONSOL Energy's strategy is to increase shareholder value through growth of its
existing gas assets, selective acquisition of gas and liquids acreage leases within its footprint, and through participation in the forecasted global growth of thermal and metallurgical coal markets. We also will continue to focus on monetization of assets to accelerate value creation to minimize the shortfall between operating cash flows and our growth capital requirements.
6
CONSOL Energy intends to continue to grow its gas production. The 2015 gas production guidance range is 300-310 Bcfe, net to CONSOL Energy, or 30% growth compared to 2014 total production, when using the midpoint of the range. CONSOL Energy continues to expect 2016
annual gas production to grow by 30%.
We expect natural gas to become a more significant contributor to the domestic electric generation mix as well as fueling industrial growth in the U.S. economy. Also, the U.S. is expected to become a net exporter of gas in the next few years. Our increasing gas production will allow CONSOL Energy to participate in these growing markets.
The 2015 coal production guidance range is 30.5-33.0 million tons. CONSOL Energy’s coal assets align with the company’s long term strategic objectives. The production from the company’s Pennsylvania
Operations, which include the Bailey, Enlow Fork, and Harvey mines can be sold domestically or abroad, as either thermal coal or high volatile metallurgical coal. These low-cost mines, with five longwalls, and with estimated production of between 24.9-26.6 million tons in 2015, produce a high-Btu Pittsburgh-seam coal that is lower in sulfur than many Northern Appalachian coals. Also, the company’s Buchanan Mine which is in our Virginia Operations produces a premium low volatile metallurgial coal for the steel industry. It is estimated to produce between 3.7-4.2 million tons in 2015 at a cost that is among the lowest of any domestic metallurgical coal mine. Our other coal operations, which primarily includes our Miller Creek Complex, are expected to produce between 1.9-2.2 million tons in 2015.
These
mines along with the 100%-owned Baltimore Terminal, will continue to allow CONSOL Energy to participate in the growth of the world’s thermal and metallurgical coal markets. The International Energy Agency (IEA) forecasts continued growth in world demand for thermal coal. The ability to serve both domestic and international markets with premium thermal and metallurgical coal provides tremendous optionality.
In December 2014, CONSOL Energy announced that its Board of Directors authorized management to pursue the formation of a master limited partnership (MLP) for the company’s thermal coal business, which would own interests in CONSOL Energy’s thermal coal properties and related mining operations located in Pennsylvania, including its Bailey Mine, Enlow Fork Mine, Harvey Mine and the related
preparation plant. CONSOL Energy also announced that its Board of Directors authorized management to separately pursue the structuring and formation of a subsidiary entity for the purpose of owning CONSOL Energy’s metallurgical coal properties and related mining operations, with a view to conducting an initial public offering of up to 20% of the subsidiary’s equity. The subsidiary’s assets would include CONSOL Energy’s Buchanan Mine and related preparation plant and its interest in its Western Allegheny Energy joint venture. CONSOL Energy believes that these transactions would achieve four objectives: (i) they bring the value of its thermal and metallurgical coal assets forward, thereby increasing CONSOL Energy’s net asset value per share, (ii) they improve transparency into the value of these assets, which will permit a more accurate sum-of-the-parts valuation, (iii) they provide additional vehicles for accessing the capital markets on favorable terms, and (iv) they
allow CONSOL Energy to retain control of these assets so it can continue to realize the operational synergies that exist between its natural gas and coal businesses. CONSOL Energy would designate separate management teams to run each of these businesses so as to most effectively maintain operational focus. After giving effect to these transactions, CONSOL Energy would consist primarily of (i) its core oil and gas exploration and production business, (ii) its interest in CONE Midstream Partners LP (NYSE: CNNX), (iii) a controlling interest in its cash flow generating thermal coal MLP and (iv) a controlling interest in its metallurgical coal subsidiary. While these transactions are anticipated in 2015, whether and when CONSOL Energy proceeds with initial public offerings of the thermal coal MLP and metallurgical coal subsidiary are subject to a number of factors, including prevailing market conditions and the approval of CONSOL Energy’s Board of Directors. No registration
statement relating to the securities that would be sold in either offering has been filed with the Securities and Exchange Commission.
7
CONSOL
Energy's Capital Expenditure Budget
In 2015, CONSOL expects to invest approximately $1.0 billion in its E&P Division, while maintaining its 30% year-over-
year production growth targets for 2015 and 2016. In addition to E&P capital, in 2015 CONSOL Energy also expects to
invest $220 million in the Coal Division: $160 million in maintenance of production capital, and $60 million in land,
safety, water, coal terminal operations, and other miscellaneous categories.
The $1.0 billion E&P budget consists of drilling and completion capital and midstream investments to continue building
out
the Marcellus Shale gathering systems, which are part of CONE Midstream Partners and will provide future
dropdown opportunities. As the year progresses, CONSOL Energy will allocate capital expenditures across its operating areas
in projects where the company can realize the highest rates of return based on results, commodity prices, basis, and
other factors. The E&P capital budget does not include land, permitting, and business development expenditures. The
company expects liquids volumes (NGL, condensates, and oil) to remain between 10%-15% as a percentage of total
production by the end of 2016.
CONSOL
Energy and its joint venture partner, Noble Energy, are working together to optimize the capital plan for 2015 in
light of the commodity price environment. The parties have not formally agreed on a 2015 capital budget, and CONSOL Energy could increase activity levels in the Marcellus Shale beyond the levels contemplated by the E&P budget if the commodity price environment improves. Currently, drilling and completion capital is expected to be weighted towards the liquids-rich areas.
DETAIL GAS OPERATIONS
Our Gas operations are located throughout Appalachia and include the following plays.
Marcellus Shale
We
have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 441,000 net Marcellus Shale acres at December 31, 2014.
CONSOL Energy and Noble Energy, our joint venture partner, drilled a record 169 gross wells in the Marcellus Shale in 2014. CONSOL Energy drilled 77 of those wells in the dry gas area of the formation. The geographic breakdown was as follows:
•
44 wells in Southwestern Pennsylvania,
•
10 wells
in Central Pennsylvania,
•
23 wells in Northern West Virginia,
•
1 well drilled in Ohio in the wet gas area of the play, and
•
91 wells drilled by Noble Energy in the wet gas area of the play.
CONSOL
Energy also completed 73 Marcellus Shale wells in 2014. The average lateral length was 7,807 feet in 2014, or a 36% increase over the previous year's lateral length of 5,744 feet. These longer drilled laterals enabled the company to perform more hydraulic fracturing, or “fracking,” to complete the wells. In 2014, the average completed well had 46 "frac" stages, or a 77% increase over the 26 stages from the previous year. Longer lateral lengths and more "frac" stages per well (shorter stage laterals and reduced cluster spacing) are expected to enhance well economics. The wells completed in this manner have shown initial production rates being improved by as much as 40%.
In 2015, the Company
expects Marcellus Shale drilling activity to be the primary driver of gas production growth along with significant growth from the Utica Shale. In the Marcellus Shale joint venture, CONSOL Energy and Noble Energy continue to work together to optimize their activity levels for 2015 in light of the rapidly changing commodity price environment.
We also hold a 50% interest in a gathering company which builds and operates the gathering system for most of our Marcellus shale production. CONSOL Energy operates these midstream assets. As of September 30, 2011, we contributed our existing Marcellus Shale gathering assets to this company. In September of 2014, the majority of these assets were contributed to CONE Midstream Partners LP. CONSOL Energy and Noble Energy have dedicated approximately 516,000 net acres of their jointly owned
Marcellus Shale acreage to this partnership for an initial term of 20 years and they have also granted a right of first offer on an additional approximately 186,000 net acres. This master limited partnership formed by us and Noble Energy
8
will continue to build and operate most of our Marcellus Shale gathering systems. CONSOL Energy continues to serve as operator for CONE Midstream Partners LP. See "Midstream Gas Services" for a more detailed explanation.
Utica Shale
CONSOL Energy controls approximately
118,000 net acres of Utica Shale potential in eastern Ohio at December 31, 2014. Additionally, CONSOL Energy controls an additional 108,000 net acres in southwestern Pennsylvania and northern West Virginia that contain the rights to the natural gas in Utica Shale. In addition, we estimate that approximately 388,000 net acres of our Marcellus Shale acreage in Pennsylvania and West Virginia are prospective for the Utica Shale. The thickness of the Utica Shale in these areas ranges from 200 to 450 feet.
In 2014, CONSOL Energy and Hess, our joint venture partner, drilled 39 gross wells in the Utica Shale. CONSOL Energy drilled 14 of those wells.
Coalbed Methane (CBM)
We
have the rights to extract CBM in Virginia from approximately 268,000 net CBM acres, which cover a portion of our coal reserves in Central Appalachia. We produce gas primarily from the Pocahontas #3 seam which is the main coal seam mined by our Buchanan Mine.
We also have the right to extract CBM in West Virginia, southwestern Pennsylvania, and Ohio from approximately 934,000 net CBM acres. In central Pennsylvania we have the right to extract CBM from approximately 260,000 net CBM acres. In addition, we control 768,000 net CBM acres in Illinois, Kentucky, Indiana, and Tennessee. We also have the right to extract CBM on 139,000 net acres in the San Juan Basin, and 20,000 net acres in the Powder River Basin. We have no plans to drill CBM wells in these areas in 2015.
Other Gas
Shallow
Oil and Gas
The shallow oil and gas acreage position of CONSOL Energy is approximately 853,000 net acres mainly in Illinois, Indiana, Kentucky, West Virginia, Pennsylvania, Virginia, and New York at December 31, 2014. The majority of our shallow oil and gas leasehold position is held by production and all of it is extensively overlain by existing third party gas gathering and transmission infrastructure. The shallow oil and gas assets provide multiple synergies with our CBM and unconventional shale operations, and the held by production nature of the shallow oil and gas properties affords CONSOL Energy considerable flexibility to choose when to exploit those and other gas assets including shale assets.
Upper Devonian
The
Upper Devonian Shale formation lies above the Marcellus Shale formation in southwestern Pennsylvania and northern West Virginia. The company holds a large number of acres that have Upper Devonian potential; generally these acres have not been disclosed separately, since they are not the primary drilling target as of December 31, 2014.
CONSOL Energy, with our joint venture partner Noble Energy, drilled nine wells in the Burkett Shale and two wells in the Rhinestreet Shale. Our Marcellus Shale joint venture partner owns a 50% interest in the Burkett Shale formation within the joint venture area of mutual interest. CONSOL Energy controls a 100% interest in the Rhinestreet Shale formation that was acquired
prior to the joint venture, with exception to the two drilled wells Noble Energy opted into in 2014.
Chattanooga
The Chattanooga Shale in Tennessee is a Devonian-age shale found at a depth of approximately 3,500 feet. The shale thickness is between 40-80 feet, and CONSOL Energy has found it to be rich in total organic content. CONSOL Energy has 218,000 net acres of Chattanooga Shale. This largely contiguous acreage is composed of only a small number of leases, a rarity in Appalachia. CONSOL Energy is the operator of all of its horizontal Chattanooga Shale wells.
Huron
We have 386,000 net acres of Huron Shale potential in Kentucky, West Virginia, and Virginia; a portion of this acreage has tight
sands potential.
Net
acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable. See Risk Factors in Section 1A of this Form 10-K.
(2)
Acreage amounts are shown under the target strata CONSOL Energy expects to produce, although the reported acres may include rights to multiple gas seams (CBM, Utica, Marcellus, etc.). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect the acres in the strata we expect to produce. As more information
is obtained or circumstances change, the acreage classification may change.
Producing Wells and Acreage
Most of our development wells and proved acreage are located in Virginia, West Virginia and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2014, the number of producing wells, developed acreage and undeveloped acreage:
Gross
Net(1)
Producing
Gas Wells (including gob wells)
17,044
12,918
Producing Oil Wells
154
34
Net
Acreage Position
Proved Developed Acreage
537,935
515,439
Proved Undeveloped Acreage
112,617
63,801
Unproven
Acreage
4,946,174
3,933,975
Total Acreage
5,596,726
4,513,215
(1)
Net
acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable. See Risk Factors in Section 1A of this Form 10-K.
10
The following table represents the terms under which we hold these
acres:
Net Unproved Acres
Net Proved Undeveloped Acres
Held by production/fee
3,792,960
49,756
Expiration
within 2 years
39,385
2,665
Expiration beyond 2 years
101,630
11,380
Total
Acreage
3,933,975
63,801
The leases reflected above as Net Unproved Acres with expiration dates are included in our current drill plan or active land program. Leases with expiration dates within two years represent less than 1% of our total acres in the above categories and leases with expiration dates beyond two years represent less than 3% of our total acres in the above categories. In each case, we deemed this acreage to not be material to our overall acreage
position. Additionally, based on our current drill plans and lease management we do not anticipate any material impact to our consolidated financial statements from the expiration of such leases.
Development Wells (Net)
During the years ended December 31, 2014, 2013 and 2012 we drilled 180.3, 139.8 and 95.5 net development wells, respectively. Gob wells and wells drilled by operators other than our primary joint venture partners, Noble Energy and Hess Corporation, are excluded from net development wells. In 2014, there were 287 gross development wells. There were no dry development wells in 2014, 2013, or 2012. As of December 31, 2014, there
are 52 net developmental wells still in process. The following table illustrates the net wells drilled by well classification type:
During the years ended December 31, 2014, 2013
and 2012, we drilled, in the aggregate, 8.5, 5.5, and 22.0 net exploratory wells, respectively. As of December 31, 2014, there are 2.5 net exploratory wells in process. The following table illustrates the exploratory wells drilled by well classification type:
The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the Securities and Exchange Commission (SEC).
Total
proved developed and undeveloped reserves(a)
6,827,616
5,731,214
3,993,458
___________
(a)
For additional
information on our reserves, see “Other Supplemental Information–Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Discounted Future Net Cash Flows
The following table shows our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%:
Discounted
Future
Net Cash Flows
(Dollars in millions)
2014
2013
2012
Future
net cash flows
$
9,321
$
6,568
$
2,792
Total PV-10 measure of pre-tax discounted future net cash flows (1)
$
4,884
$
2,780
$
1,242
Total
standardized measure of after tax discounted future net cash flows
$
2,984
$
1,681
$
736
____________
(1)
We
calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-Generally Accepted Accounting Principle (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of the financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.
*Oil,
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.
CONSOL Energy projects its 2015 natural gas production, net to CONSOL, to be 300 – 310 Bcfe, or 30% growth compared to 2014 total production, when using the midpoint of the range. CONSOL Energy continues to expect 2016 annual gas production to grow by 30%.
Average Sales Price and Average Lifting Cost
The following table sets forth the total average sales price and the total average lifting cost for all of our gas production for the periods indicated, including intersegment transactions. Total lifting cost is the cost of raising gas to
the gathering system and does not include depreciation, depletion or amortization. See Part II Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K for a breakdown by segment.
Total Average Gas Sales Price Before Effects of Financial Settlements (per Mcfe)
$
4.26
$
3.85
$
3.00
Average
Effects of Financial Settlements (per Mcfe)
$
0.11
$
0.45
$
1.22
Total Average Gas Sales Price Including Effects of Financial
Settlements (per Mcfe)
$
4.37
$
4.30
$
4.22
Average Lifting Costs excluding ad valorem and severance taxes (per Mcfe)
$
0.50
$
0.56
$
0.58
Sales
of NGLs, condensates, and oil enhance our reported gas equivalent sales prices. Across all volumes, sales of liquids added $0.24 per Mcfe, $0.13 per Mcfe, and $0.05 per Mcfe for 2014, 2013, and 2012, respectively, to average gas sales prices. CONSOL Energy expects to continue to realize a liquids uplift benefit as additional wells are brought online in the liquid-rich areas of the Marcellus and Utica shales. We continue to sell the majority of our NGLs through the large midstream companies that process our gas. This approach allows us to take advantage of the processors’ transportation efficiencies and diversified markets. CONSOL Energy’s processing contracts provide for the ability to take our NGLs “in kind” and market them directly if desired. The processed purity products are ultimately sold to industrial, commercial, and petrochemical markets.
We
enter into physical gas sales transactions with various counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, we have delivered quantities required under these contracts. We also enter into various gas swap transactions. These gas swap transactions exist parallel to the underlying physical transactions and represented approximately 159.9 Bcf of our produced gas sales volumes for the year ended December 31, 2014 at an average price of $4.58 per Mcf. These gas swaps represented approximately 84.3 Bcf of our produced gas sales volumes for the year ended December 31, 2013 at an average price of $4.68 per Mcf. As of January 15,
2015, we expect these transactions will represent approximately 121.2 Bcf of our estimated 2015 production at an average price of $4.05 per Mcf and 94.7 Bcf of our estimated 2016 production at an average price of $4.11 per Mcf.
The hedging strategy and information regarding derivative instruments used are outlined in Part II, Item 7A Qualitative and Quantitative Disclosures About Market Risk and in Note 23 - Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.
Midstream Gas Services
CONSOL
Energy has traditionally designed, built and operated natural gas gathering systems to move gas from the wellhead to interstate pipelines or other local sales points. In addition, CONSOL Energy has acquired extensive gathering assets. CONSOL Energy now owns or operates approximately 5,000 miles of gas gathering pipelines as well as 250,000 horsepower of compression, of which, just over 75% is wholly owned with the balance being leased. Along with this compression capacity, CONSOL Energy owns and operates a number of gas processing facilities. This infrastructure is capable of delivering approximately 500 billion cubic feet per year of pipeline quality gas.
CONSOL Energy owns 50% of CONE Gathering, LLC ("CONE" or "CONE Gathering") along with Noble Energy owning the other 50% interest. CONE Gathering develops, operates
and owns substantially all of both Noble Energy's and CONSOL Energy's Marcellus Shale gathering system needs. CONSOL Energy operates this equity affiliate. We believe that the network of right-of-ways, vast surface holdings and experience in building and operating gathering systems in the Appalachian basin will give CONE Gathering an advantage in building the midstream assets required to develop the joint venture's Marcellus Shale position. 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.
As
a result of the IPO transaction, 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.
In the Utica Shale, we and our joint venture partner, Hess, are primarily contracting with third parties for gathering services.
14
CONSOL Energy continues to develop a diversified portfolio
of firm transportation capacity options to support our production growth plan. In September, we 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. We also benefit from the strategic location of our primary production areas in Southwest Pennsylvania, Northern West Virginia, and Eastern Ohio. These areas are served by a large concentration of major pipelines that provide us with the capacity to move our production to the major gas markets. In addition to firm transportation capacity, CONSOL Energy continues to develop a processing portfolio to support the increasing volumes from our wet production areas.
CONSOL Energy has the advantage of having gas production from CBM, which can be lower
Btu than pipeline specification, as well as higher Btu Marcellus Shale production. These two types of gas can complement each other by reducing and in some cases eliminating the need for the costly processing of CBM. In addition, both our lower Btu CBM and dry Marcellus production offers an opportunity to blend ethane back into the gas stream when pricing or capacity for ethane markets dictate. In developing a diversified approach to managing ethane, CONSOL Energy has entered into ethane supply agreements and is actively discussing future outlet opportunities with a number of ethane customers and midstream companies. These measures will allow us more flexibility in bringing Marcellus Shale wells on-line at qualities that meet interstate pipeline specifications.
Natural Gas Competition
The
United States natural gas industry is highly competitive and more diversified than the coal industry. CONSOL Energy competes with other large producers, as well as thousands of smaller producers, pipeline imports from Canada, and Liquefied Natural Gas (LNG) from around the globe. According to data from the Natural Gas Supply Association and the Energy Information Agency (EIA), the five largest U.S. producers of natural gas produced about 19% of dry natural gas production in the first six months of 2014. The EIA reported 487,286 producing natural gas wells in the United States in 2013, the latest year for which government statistics are available.
Natural gas has maintained market share in the U.S. electric generation market compared to 2013 (based on preliminary 2014 results). However, we expect natural gas to become a more significant contributor to
the domestic electric generation mix in the long-term, as well as fuel industrial growth in the U.S. economy. There is potential for natural gas to become a significant contributor to the transportation market. Additionally, the U.S. is expected to become a net exporter of gas in the next few years. Our increasing gas production will allow CONSOL Energy to participate in these growing markets.
CONSOL Energy's gas operations are primarily located in the eastern United States. The gas market is highly fragmented and not dominated by any single producer. We believe that competition within our market is based primarily on natural gas commodity trading fundamentals and pipeline transportation availability to the various markets.
Continued demand for CONSOL Energy's natural gas and the prices
that CONSOL Energy obtains are affected by natural gas use in the production of electricity, U.S. manufacturing and the overall strength of the economy, environmental and government regulation, technological developments and the availability and price of competing alternative fuel supplies.
DETAIL COAL OPERATIONS
Coal Reserves
At December 31, 2014, CONSOL Energy had an estimated 3.2 billion tons of proven and probable reserves, excluding equity affiliates. Reserves are the portion of the proven and probable tonnage that meet CONSOL Energy's economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping
ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels.
Spacing of points of observation for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). Our estimates for proven reserves have the highest degree of geologic assurance. Estimates for proven reserves are based on points of observation that are equal to or less than 0.5 miles apart. Estimates for probable reserves have a moderate degree of geologic assurance and are computed from points of observation that are between 0.5 to 1.5 miles apart.
An exception is made concerning spacing of observation points with respect to our Pittsburgh coal seam reserves. Because of the
well-known continuity of this seam, spacing requirements are 3,000 feet or less for proven reserves and between 3,000 and 8,000 feet for probable reserves.
15
CONSOL Energy's estimates of proven and probable reserves do not rely on isolated points of observation. Small pods of reserves based on a single observation point are not considered; continuity between observation points over a large area is necessary for proven or probable reserves.
Our estimate of proven and probable coal reserves has been determined by CONSOL Energy’s geologists and mining engineers. CONSOL Energy geologists and mining
engineers completed an extensive re-evaluation of the longwall mineable Pittsburgh and Illinois No. 5 seams during 2014. The re-evaluations included the use of mine specific assumptions and mine plans versus general mine recovery factors and general parameters. To date, approximately 50% of CONSOL Energy’s reserves have been re-evaluated using mine specific parameters as opposed to an assumed average mining recovery factors. The 2014 re-evaluations resulted in 460 million of the total 471 million additional tons of proven and probable reserves added as result of revisions and other changes in 2014 (See Supplemental Coal Data in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K).
CONSOL Energy's proven and probable coal reserves fall within the range of commercially marketed coals in the United States. The marketability of coal depends on its
value-in-use for a particular application, and this is affected by coal quality, such as, sulfur content, ash and heating value. Modern power plant boiler design aspects can compensate for coal quality differences that occur. Therefore, any of CONSOL Energy's coals can be marketed for the electric power generation industry. Additionally, the growth in worldwide demand for metallurgical coals allows some of our proven and probable coal reserves, currently classified as thermal coals, that possess certain qualities to be sold as metallurgical coal. The addition of this cross-over market adds additional assurance to CONSOL Energy that all of its proven and probable coal reserves are commercially marketable.
CONSOL Energy assigns coal reserves to each of our mining complexes. The amount of coal we assign to a mining complex generally is sufficient to support mining through the
duration of our current mining permit. Under federal law, we must renew our mining permits every five years. All assigned reserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured.
In addition, our mining complexes may have access to additional reserves that have not yet been assigned. We refer to these reserves as accessible. Accessible reserves are proven and probable reserves that can be accessed by an existing mining complex, utilizing the existing infrastructure of the complex to mine and to process the coal in this area. Mining an accessible reserve does not require additional capital spending beyond that required to extend or to continue the normal progression of the mine, such as the sinking of airshafts or the construction of portal facilities.
Some
reserves may be accessible by more than one mining complex because of the proximity of many of our mining complexes to one another. In the table below, the accessible reserves indicated for a mining complex are based on our review of current mining plans and reflect our best judgment as to which mining complex is most likely to utilize the reserve.
Assigned and unassigned coal reserves are proven and probable reserves which are either owned or leased. The leases have terms extending up to 30 years and generally provide for renewal through the anticipated life of the associated mine. These renewals are exercisable by the payment of minimum royalties. Under current mining plans, assigned reserves reported will be mined out within the period of existing leases or within the time period of probable lease renewal periods.
16
Mining
Complexes
The following table provides the location of CONSOL Energy's active mining complexes and the coal reserves associated with each of the continuing operations.
CONSOL ENERGY MINING COMPLEXES
Proven
and Probable Assigned and Accessible Coal Reserves as of December 31, 2014 and 2013
Recoverable
Average
As
Received Heat
Reserves(2)
Preparation
Seam
Value(1)
Tons
in
Facility
Reserve
Coal
Thickness
(Btu/lb)
Owned
Leased
Millions
Mine/Reserve
Location
Class
Seam
(feet)
Typical
Range
(%)
(%)
12/31/2014
(4)
12/31/2013
(4)
ASSIGNED–OPERATING
PA
Operations
Bailey
(3)
Enon, PA
Assigned Operating
Pittsburgh
7.6
12,930
12,800 – 13,050
53%
47%
84.0
96.9
Accessible
Pittsburgh
7.5
12,930
12,720
– 13,190
78%
22%
170.5
278.7
Harvey (3)
Enon, PA
Assigned
Operating
Pittsburgh
6.6
13,040
12,940 – 13,230
89%
11%
27.1
—
Accessible
Pittsburgh
7.6
12,930
12,870
– 13,160
99%
1%
181.2
—
Enlow Fork (3)
Enon, PA
Assigned
Operating
Pittsburgh
7.8
12,920
12,800 – 13,000
99%
1%
21.6
16.9
Accessible
Pittsburgh
7.6
12,980
12,720
– 13,120
76%
24%
301.2
232.8
VA Operations
Buchanan
Mavisdale,
VA
Assigned Operating
Pocahontas 3
6.0
13,790
13,690 – 14,050
20%
80%
44.8
47.2
Accessible
Pocahontas
3
5.9
13,760
13,690 – 13,900
15%
85%
47.3
46.1
Amonate
Complex
Amonate, VA
Assigned Operating
Multiple
4.3
13,150
12,850 – 13,350
69%
31%
15.8
20.1
Accessible
Multiple
6.4
12,880
12,880
– 12,880
100%
—%
3.9
6.6
Other Operations
Amvest
Fola Complex (3)
Bickmore, WV
Assigned Operating
Multiple
4.6
12,380
12,250 – 12,550
86%
14%
73.4
73.4
Miller
Creek Complex
Delbarton, WV
Assigned Operating
Multiple
2.6
12,100
11,600 – 12,650
40%
60%
52.0
52.6
Accessible
Multiple
5.1
12,650
12,650
– 12,650
—%
100%
0.8
0.7
Total Assigned Operating and Accessible
1,023.6
872.0
17
_____________
(1)
The
heat value shown for Assigned Operating reserves is based on the quality of coal mined and processed during the year ended December 31, 2014. The heat values shown for Accessible Reserves are based on as received, dry values obtained from drill hole analyses, adjusted for moisture, and prorated by the associated Assigned Operating product values to account for similar mining and processing methods.
(2)
Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered
during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustments for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams that are controlled by ownership or leases.
(3)
A portion of these reserves contain metallurgical qualities and are currently being sold on the metallurgical market.
(4)
The table excludes
both 55.0 million tons of recoverable reserves held by an equity affiliate of which CONSOL Energy owns a 49% interest and approximately 118.8 million tons of reserves at December 31, 2014 that are assigned to projects that have not produced coal in 2014. These assigned reserves are in the Northern Appalachia (Pennsylvania, Ohio and Northern West Virginia), Central Appalachia (Virginia and Southern West Virginia) and Western U.S. (Utah) and are approximately 71% owned and 29% leased.
The following table sets forth our unassigned proven and probable reserves by region:
Northern
Appalachia (Pennsylvania, Ohio, Northern West Virginia)
11,400 – 13,600
87%
13%
1,219.1
951.7
Central Appalachia (Virginia,
Southern West Virginia)
11,400 – 14,100
51%
49%
321.2
349.6
Illinois Basin (Illinois, Western Kentucky, Indiana)
11,600
– 12,000
53%
47%
555.6
731.9
Total
72%
28%
2,095.9
2,033.2
_______________
(1)
The
heat value estimates for Northern Appalachian and Central Appalachian Unassigned coal reserves include adjustments for moisture that may be added during mining or processing as well as for dilution by rock lying above or below the coal seam. The mining and processing methods currently in use, are used for these estimates. The heat value estimates for the Illinois Basin, unassigned reserves are based primarily on exploration drill core data that may not include adjustments for moisture added during mining or processing or for dilution by rock lying above or below the coal seam.
(2)
Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill
core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustment for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are only reported for those coal seams that are controlled by ownership or leases.
18
The
following table classifies CONSOL Energy coals by rank, projected sulfur dioxide emissions and heating value (British thermal units per pound). The table also classifies bituminous coals as high, medium and low volatile which is based on fixed carbon and volatile matter.
CONSOL
Energy Proven and Probable Recoverable Coal Reserves
The
table above excludes 55.0 million tons of recoverable reserves held by an equity affiliate of which CONSOL Energy owns a 49% interest.
Title to coal properties that we lease or purchase and the boundaries of these properties are verified by law firms retained by us at the time we lease or acquire the properties. Consistent with industry practice, abstracts and title reports are reviewed and updated approximately five years prior to planned development or mining of the property. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine reserves could be adversely affected.
The following table sets forth, with respect to properties that we lease to other coal operators, the total royalty tonnage, acreage leased and the amount
of income (net of related expenses) we received from royalty payments for the years ended December 31, 2014, 2013 and 2012.
Total
Total
Total
Royalty
Coal
Royalty
Tonnage
Acreage
Income
Year
(in
thousands)
Leased
(in thousands)
2014
10,230
281,894
$18,460
2013
8,335
271,755
$16,906
2012
8,326
271,760
$16,853
Royalty
tonnage leased to third parties is not included in the amounts of produced tons that we report. Proven and probable reserves do not include reserves attributable to properties that we lease to third parties.
19
Production
In the year ended December 31, 2014,
93% of CONSOL Energy's production from continuing operations came from underground mines and 7% from surface mines. CONSOL Energy employs longwall mining systems in our underground mines where the geology is favorable and reserves are sufficient. For the year ended December 31, 2014, 93% of our production came from mines equipped with longwall mining systems. Underground longwall systems are highly mechanized, capital intensive operations. Mines using longwall systems have a low variable cost structure compared with other types of mines and can achieve high productivity levels compared with those of other underground mining methods. Because CONSOL Energy has substantial reserves readily suitable to these operations, CONSOL Energy believes that these longwall mines can increase capacity at a low incremental cost.
The following table
shows the production from continuing operations, in millions of tons, for CONSOL Energy's mines for the years ended December 31, 2014, 2013 and 2012, the location of each mine, the type of mine, the type of equipment used at each mine, method of transportation and the year each mine was established or acquired by us.
Preparation
Tons
Produced
Year
Facility
Mine
Mining
(in millions)
Established
Mine
Location
Type
Equipment
Transportation
2014
2013
2012
or
Acquired
PA Operations
Bailey
(3)
Enon, PA
U
LW/CM
R R/B
12.3
10.8
10.1
1984
Enlow
Fork (3)
Enon, PA
U
LW/CM
R R/B
10.6
10.1
9.5
1990
Harvey
(5)
Enon, PA
U
LW/CM
R R/B
3.2
0.6
—
2014
VA
Operations
Buchanan (1)
Mavisdale,
VA
U
LW/CM
R T
4.0
4.8
3.5
1983
Amonate
(1)(2)
Amonate, VA
U/S
A/S/CM
R T
—
—
0.1
2012
Other
Miller
Creek Complex (2)
Delbarton, WV
U/S
CM/S/L
R T
2.1
2.2
2.9
2004
AMVEST-Fola
Complex (1)(2)
Bickmore, WV
U/S
A/S/L/CM
R T
—
—
1.1
2007
Total
32.2
28.5
27.2
CONSOL
Energy Portion of Equity Affiliates
Harrison
Resources (2)(4)
Cadiz, OH
S
S/L
R T
0.3
0.4
0.4
2007
Western
Allegheny (2)(4)
Young Township, PA
U
CM
R T
0.5
0.3
0.1
2010
Total
CONSOL Energy Portion of Equity Affiliates
0.8
0.7
0.5
A
–
Auger
S
–
Surface
U
–
Underground
LW
–
Longwall
CM
–
Continuous
Miner
S/L
–
Stripping Shovel and Front End Loaders
R
–
Rail
R/B
–
Rail to Barge
T
–
Truck
(1)
–
Mine
was idled for part of the year(s) presented due to market conditions.
(2)
–
Harrison Resources, Miller Creek Complex, AMVEST–Fola Complex, Amonate Complex and Western Allegheny (includes facilities operated by independent contractors).
(3)
–
Mine was idle for three weeks during 2012 due to a structural failure at the above-ground conveyor system at the Bailey Preparation Plant. Production later resumed at a reduced capacity.
(4)
–
Production
amounts represent CONSOL Energy's 49% ownership interest. Interest in Harrison Resources was sold on October 1, 2014.
(5)
–
Completed development work and was placed in service in March 2014.
20
Coal Capital
In 2015, CONSOL Energy expects to invest $220 million in the Coal and other Division: $160 million in maintenance of production capital, and $60 million in land, safety, water, terminal operations, and other miscellaneous categories.
Coal Marketing and Sales
Our sales of bituminous coal from continuing operations were at average sales price per ton sold as follows:
Average Sales Price Per Ton Sold– Other Operations
$
60.12
$
70.22
$
71.44
Average
Sales Price Per Ton Sold– Total Company
$
63.03
$
69.34
$
77.75
We sell coal
produced by our mining complexes and additional coal that is purchased by us for resale from other producers. We maintain United States sales offices in Charlotte, Philadelphia and Pittsburgh. In addition, we sell coal through agents and to brokers and unaffiliated trading companies.
A breakdown of total coal sales from continuing operations is as follows:
Tons
Percent
of
Sold
Total
PA Operations
26.1
81
%
VA Operations
4.1
13
%
Other
Operations
2.2
6
%
Total tons sold
32.4
100
%
Approximately
72% of our 2014 coal sales from continuing operations were made to U. S. electric generators, 5% of our 2014 coal sales were priced on export markets and 23% of our coal sales were made to other domestic customers. We had over 50 customers from our 2014 coal operations. During 2014, Duke Energy and Xcoal Energy Resources each comprised over 10% of our revenues from continuing operations, and the top four coal customers accounted for more than 30% of our total revenues from continuing operations.
We sell coal to an established customer base through opportunities as a result of strong business relationships, or through a formalized bidding
process. Contract volumes range from a single shipment to multi-year agreements for millions of tons of coal. The average contract term is between one to three years. As a normal course of business, efforts are made to renew or extend contracts scheduled to expire. Although there are no guarantees, we generally have been successful in renewing or extending contracts in the past. For the year ended December 31, 2014, over 66% of all the coal we produced from continuing operations was sold under contracts
with terms of one year or more.
21
The following
table sets forth as of January 18, 2015, CONSOL Energy's estimated production and sales for 2015 through 2016.
COAL DIVISION GUIDANCE
(Tons in millions)
Q1
2015
2015
2016
Estimated Total Coal Sales
8.0 - 8.5
30.5 - 33.0
30.5
- 33.0
Tonnage: Firm
7.3
24.2
13.4
Price: Sold (firm)
$
62.24
$
63.06
$
63.12
Estimated
PA Operations Sales
6.6 - 6.8
24.9 - 26.6
24.9 - 26.6
Tonnage: Firm
5.9
20.7
11.8
Estimated
VA Operations Sales
1.0 - 1.2
3.7 - 4.2
3.7 - 4.2
Tonnage: Firm
0.9
1.6
0.8
Estimated
Other Sales
0.4 - 0.5
1.9 - 2.2
1.9 - 2.2
Tonnage: Firm
0.5
1.9
0.8
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. There are no collared tons in 2015. Collared tons in 2016 are 0.9 million tons, with a ceiling of $61.46 per ton and a floor of $57.54 per ton. Not included in the category breakdowns are the tons from Western Allegheny Energy (WAE). WAE has 0.1 million tons for Q1 2015, and 0.5 million tons and 0.4 million tons for all of 2015, and 2016, respectively.
Coal pricing for contracts with terms of one year or less is
generally fixed. Coal pricing for multiple-year agreements generally provide the opportunity to periodically adjust the contract prices through pricing mechanisms consisting of one or more of the following:
•
Fixed price contracts with pre-established prices;
•
Periodically negotiated prices that reflect
market conditions at the time;
•
Price restricted to an agreed-upon percentage increase or decrease; or
•
Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices, or other negotiated indices.
The volume of coal to be delivered is specified in each of our coal contracts.
Although the volume to be delivered under the coal contracts is stipulated, the parties may vary the timing of the deliveries within specified limits.
Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include, but are not limited to, unexpected significant geological conditions or natural disasters. Depending on the language of the contract, some contracts may terminate upon continuance of
an event of force majeure that extends for a period greater than three to twelve months.
Distribution
Coal is transported from CONSOL Energy's mining complexes to customers by railroad cars, trucks or a combination of these means of transportation. We employ transportation specialists who negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines, terminal operators, ocean vessel brokers and trucking companies for certain customers.
Coal Competition
The United States coal industry is highly competitive, with numerous producers selling into all
markets that use coal. CONSOL Energy competes against several other large producers and numerous small producers in the United States and overseas. Demand for our coal by our principal customers is affected by many factors including:
•
the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and
renewable energy sources, such as hydroelectric power, wind or solar;
•
environmental and government regulation;
22
•
coal
quality;
•
transportation costs from the mine to the customer;
•
the reliability of fuel supply;
•
worldwide demand for steel;
•
natural/weather
disasters; and
•
political changes in international governments.
Continued demand for CONSOL Energy's coal and the prices that CONSOL Energy obtains are affected by demand for electricity, technological developments, environmental and governmental regulation, and the availability and price of competing coal and alternative fuel supplies. We sell coal to foreign electricity generators and to the more specialized metallurgical coal markets, both of which are significantly affected by international demand and competition.
Other Operations
CONSOL
Energy provides other services both to our own operations and to others. These include land services, coal terminal services and water services.
Non-Core Mineral Assets and Surface Properties
CONSOL Energy owns significant gas and coal assets that are not in our short or medium term development plans. We continually explore the monetization of these non-core assets by means of sale, lease, contribution to joint ventures, or a combination of the foregoing in order to bring the value of these assets forward for the benefit of our shareholders. We also control a significant amount of surface acreage. This surface acreage is valuable to us in the development of the gathering system for our Marcellus Shale and Utica Shale production. We also derive value from this surface control by granting
rights of way or development rights to third parties when we are able to derive appropriate value for our shareholders.
Terminal Services
In 2014, approximately 9.6 million tons of coal were shipped through CONSOL Energy's subsidiary, CNX Marine Terminals Inc.'s, exporting terminal in the Port of Baltimore. Approximately 42% of the tonnage shipped was produced by CONSOL Energy coal mines. The terminal can either store coal or load coal directly into vessels from rail cars. It is also one of the few terminals in the United States served by two railroads, Norfolk Southern Corporation and CSX Transportation Inc.
Water Services
CNX
Water Assets LLC, a CONSOL Energy subsidiary, is acquiring and developing existing sources of water in order to support our gas and coal operations, develop business in water sales, promote cutting edge water technologies, treat both acid mine drainage (AMD) water and fracturing water, and reduce our environmental liabilities. CNX Water Assets' operate an advanced waste water treatment plant in support of coal operations as well as fresh water reservoirs. CNX Water Assets' objective is to develop and maximize the value of existing water assets, which will be used to provide water for drilling and hydraulic fracturing in support of gas operations and meeting the needs of mining operations. CNX Water Assets' also has contracts to provide water to third parties for industrial use from various water sources owned by CONSOL Energy.
Employee
and Labor Relations
At December 31, 2014, CONSOL Energy had 3,834 employees. Less than 1% of the total workforce is represented by the United Mine Workers of America (UMWA).
Industry Segments
Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years ended December 31, 2014, 2013 and 2012 is included in Note 25 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K
and incorporated herein.
23
Laws and Regulations
Overview
Our gas and coal mining operations are subject to various types of federal, state and local laws and regulations. Regulations relating to our operations include permitting and other licensing requirements; water withdrawal and procurement for well stimulation purposes; well drilling and casing; well production; well plugging; venting or flaring of natural gas; pipeline compression
and transmission of natural gas and liquids; reclamation and restoration of properties after gas or mining operations are completed; storage, transportation and disposal of materials used or generated by gas and mining operations; the calculation, reporting and disbursement of taxes; gathering of gas production in certain circumstances; surface subsidence from underground mining; discharge of water from coal mining operations; air quality standards; protection of wetlands; endangered plant and wildlife protection; and employee health and safety. Numerous governmental permits and approvals under these laws and regulations are required for gas and mining operations. Lastly, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our gas and coal products.
Compliance
with these laws has substantially increased the cost of gas production and mining of coal for all domestic gas and coal producers. We also post performance bonds or letters of credit pursuant to state oil and gas laws and regulations to guarantee reclamation of gas well sites and plugging of gas wells. We post surety performance bonds or letters of credit pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, often including the cost of treating mine water discharge. We endeavor to conduct our gas and mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements against a backdrop of variable geologic and seasonal conditions, permit exceedances and violations during gas and mining operations can and do occur. The possibility exists that new legislation or regulations may be adopted which would have a
significant impact on our gas and coal mining operations or our customers' ability to use our gas and coal and may require us or our customers to change their operations significantly or incur substantial costs.
CONSOL Energy is committed to complying with all laws and regulations. This commitment is evident in CONSOL Energy's demonstrated cost and effort to abate and control pollution and/or contamination at its facilities. CONSOL Energy made capital expenditures for environmental control facilities of approximately $19.0 million, $1.6 million, and $1.3 million in the years ended December 31, 2014, 2013 and 2012, respectively. CONSOL Energy expects to have capital expenditures of $19.9 million in 2015 for environmental control
facilities.
Environmental Laws
Clean Air Act and Related Regulations. The federal Clean Air Act (CAA) and corresponding state laws and regulations regulate air emissions primarily through permitting and/or emissions control requirements. This affects gas production and processing operations as well as coal mining and coal handling and processing.
We are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions. On August 16, 2012, the U.S. Environmental Protection
Agency (EPA) published final revisions to the New Source Performance Standards (NSPS) to regulate emissions of volatile organic compounds (VOCs) and sulfur dioxide (SO2) from various oil and gas exploration, production, processing and transportation facilities and revisions to the National Emission Standards for Hazardous Air Pollutants (NESHAPS) to further regulate emissions from the oil and natural gas production sector and the transmission and storage of natural gas. Section 111 of the CAA authorized the EPA to develop technology based standards which apply to specific categories of stationary sources. In September 2009, the EPA finalized the Mandatory Reporting of Greenhouse Gas Rule. The current version of this rule requires annual reporting of emissions from gas wells, coal mines and associated facilities.
The
U.S. EPA is currently proposing to amend the Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse Gas Reporting Program (GHGRP). This proposed rule would add reporting of greenhouse gas emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. The rule would also require operators to install new monitoring equipment during the next year in order to comply with Subpart W. In addition, on January 14, 2014, the Obama Administration announced its goal to significantly reduce methane emission from oil and gas sources by 2014. As part of this announcement, the EPA announced that it will issue a proposed rule in the summer of 2015 and a final rule in 2016 setting standards for methane and VOC emissions from new and modified oil and gas productions sources and natural gas processing and transmission
sources.
24
The CAA also indirectly and more significantly affects the U.S. coal industry by extensively regulating the air emissions of coal-fired electric power generating plants operated by our customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. Carbon dioxide, a greenhouse gas, is also emitted when coal is burned. Environmental regulations governing emissions from coal-fired electric generating plants increase the costs to operate and could affect demand for coal as a fuel source and affect the volume of our sales. Moreover,
additional environmental regulations increase the likelihood that existing coal-fired electric generating plants will be decommissioned, including plants to which CONSOL Energy sells coal to, and reduce the likelihood that new coal-fired plants will be built in the future.
In early 2012, the EPA promulgated or finalized several rules for new source performance standards (NSPS) for coal- and oil- fired power plants and these changes affect coal-generating facilities. The Utility Maximum Control Technology (UMACT) rule requires more stringent NSPS for particulate matter (PM), SO2 and NOX and the Mercury and Air Toxics Standards (MATS) rule requires new mercury and air toxic standards. In November 2012, EPA published a notice of reconsideration
of certain aspects of the UMACT and MATS rules. Following reconsideration, in April 2013, EPA promulgated final UMACT and MATS rules at which point the standards become applicable to new power plants. The final rules have higher emission limits, but the standards are still stringent and compliance with the rules is expensive.
On July 6, 2011, the EPA finalized a rule known as the Cross-State Air Pollution Rule (CSAPR). CSAPR regulates cross-border emissions of criteria air pollutants include SO2 and NOX, as well as byproducts, fine particulate matter (PM2.5) and ozone by requiring states to limit emissions from sources that "contribute significantly" to noncompliance with air quality standards for the criteria air pollutants. If the ambient levels of criteria air pollutants are above the thresholds set by the EPA, a region
is considered to be in "nonattainment" for that pollutant and the EPA applies more stringent control standards for sources of air emissions located in the region. After sever years of litigation, implementation of CSAPR Phase 1 is now scheduled for 2015, with Phase 2 beginning in 2017.
In April 2012, the EPA published its proposed NSPS for carbon dioxide (CO2) emissions from coal-powered electric generating units. The proposed rules would have applied to new power plants and to existing plants that make major modifications. If the rules had been adopted as proposed, the only new coal-fired power plants that could have met the proposed emission limits would have been coal-fired plants with CO2 capture and storage (CCS). Commercial scale
CCS is not likely to be available in the near future, and if available, it may make coal-fired electric generation units uneconomical compared to new gas-fired electric generation units. On January 8, 2014, EPA re-proposed NSPS for CO2 for new fossil fuel fired power plants and rescinded the rules that were proposed on April 12, 2012.
On September 20, 2013, the EPA issued a new proposal to control carbon emissions from new power plants. Under the proposal, EPA would establish separate NSPS for CO2 emissions for natural gas-fired turbines and coal-fired units. The proposed “Carbon Pollution Standard
for New Power Plants” replaces an earlier proposal released by EPA in 2012.
In another proposed rulemaking related to CO2 emissions, on June 2, 2014, EPA proposed the Clean Power Plan to cut carbon emissions from existing power plants. Under this proposed rule, EPA would create emission guidelines for states to follow in developing plans to address greenhouse gas emissions from existing fossil fuel-fired electric generating units. Specifically, the EPA is proposing state-specific rate-based goals for CO2 emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve the state-specific goals.
The
CAA requires EPA to set National Ambient Air Quality Standards (NAAQS) for certain pollutants and the CAA identifies two types of NAAQS. Primary standards provide public health protection, including protecting the health of "sensitive" populations such as asthmatics, children, and the elderly. Secondary standards provide public welfare protection, including protection against decreased visibility and damage to animals, crops, vegetation, and buildings. On December 17, 2014, the EPA proposed a rule to lower the primary and secondary NAAQS for ozone. Under the proposal, the primary standard would be reduced from the current 0.075 ppm to a standard within the range of 0.065 ppm to 0.070 ppm. Similarly the secondary standard would be reduced to a standard within the range of 0.065 ppm to 0.070 ppm. This proposed rule could have a large impact on both the oil and gas and coal mining industries as states would be required
to update their permitting standards to meet these potentially unachievable limits.
Clean Water Act. The federal Clean Water Act (CWA) and corresponding state laws affect our gas and coal operations by regulating discharges into surface waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. The CWA and corresponding state laws include requirements for: improvement of designated "impaired waters" (i.e., not meeting state water quality standards) through the use of effluent limitations; anti-degradation regulations which protect state designated "high quality/exceptional use" streams by restricting or prohibiting discharges; requirements to treat discharges from coal mining properties for non-traditional pollutants,
25
such
as chlorides, selenium and dissolved solids; requirements to minimize impacts and compensate for unavoidable impacts resulting from discharges of fill materials to regulated streams and wetlands; and requirements to dispose of produced wastes and other oil and gas wastes at approved disposal facilities. In addition, the Spill Prevention, Control and Countermeasure (SPCC) requirements of the CWA apply to all CONSOL Energy operations that use or produce fluids and require the implementation of plans to address any spills and the installation of secondary containment around all tanks. These requirements may cause CONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.
Pursuant to a Congressional requirement in EPA's 2010 budget appropriation, EPA must conduct a comprehensive study of the potential
adverse impact that hydraulic fracturing may have on water quality and public health. Hydraulic fracturing is a way of producing gas from tight rock formations such as the Marcellus and Utica shales. The EPA initiated the study in early January 2011 with a final report originally intended to be published in 2014. EPA’s current estimate of the completion time for a draft of its study of the risks posed by hydraulic fracturing to drinking water is now projected by the agency to be completed in early 2015.
CONSOL Energy utilizes pipelines extensively for its gas, water and coal businesses, and mitigation permits from the Army Corps of Engineers (ACOE) are typically required for certain impacts to streams and wetlands. On April 21, 2014 EPA published a proposed rule called “Definition of ‘Waters of the United States’ Under the
Clean Water Act.” The proposal would expand the scope of the CWA to include previously non-jurisdictional streams, wetlands, and waters, making these areas jurisdictional inter-coastal waters of the U.S. If finalized, the rulemaking will likely cause states that have jurisdiction over their own waters to make regulatory changes to their already robust regulatory programs while offering little to no added environmental protection or benefit from the changes. This would only add unwarranted delays to the permitting process and extend review times even further for regulatory agencies already under-resourced. These changes would also lead to additional mitigation cost and severely limit CONSOL Energy’s ability to avoid regulated jurisdictional waters, while extending the coverage of “waters of the United States” into areas that have no significant hydrologic connection to jurisdictional waters. We believe the proposal as written does not accomplish EPA’s goal
of clarification, and has blurred the lines between what is and is not jurisdictional under the CWA.
In order to obtain a permit for surface coal mining activities, including valley fills associated with steep slope mining, an operator must obtain a permit for the discharge of fill material from the ACOE and a discharge permit from the state regulatory authority under the state counterpart to the Clean Water Act. Beginning in early 2009, the EPA implemented several initiatives that have delayed and obstructed the issuance of surface mining operation permits in the Appalachian states including Pennsylvania and Virginia where our principal mining complexes are located. Increased oversight of delegated state programmatic authority, coupled with individual permit review and additional requirements imposed by the EPA, has resulted in delays in the review and issuance of permits for
surface coal mining operations, including applications for surface facilities for underground mines, such as applications for coal refuse disposal areas. The coal industry has had some success challenging EPA’s policies but EPA continues with its initiatives. Thus far, CONSOL Energy subsidiaries have been able to continue operating their existing mines. There is no assurance that permits can be obtained for future mining operations.
Resource Conservation and Recovery Act. The federal Resource Conservation and Recovery Act (RCRA) and corresponding state laws and regulations affect gas operations and coal mining by imposing requirements for the treatment, storage and disposal of hazardous wastes. Facilities at which hazardous wastes have been treated, stored or disposed
are subject to corrective action orders issued by the EPA that could adversely affect our results, financial condition and cash flows. In 2010, EPA proposed options for the regulation of Coal Combustion Residuals (CCRs) from the electric power sector as either hazardous waste or non-hazardous waste. On December 19, 2014, EPA announced the first national regulations for the disposal of CCRs from electric utilities and independent power producers under RCRA. EPA finalized these regulations under the solid waste provisions (Subtitle D) of RCRA and not the hazardous waste provisions (Subtitle C). EPA plans to publish the final rule in the Federal Register in early January 2015. EPA affirms in the preamble to the final rule that “this rule does not apply to CCR placed in active or abandoned underground or surface mines.” Instead, “the U.S. Department of Interior (DOI) and EPA will address the management of CCR
in mine fills in a separate regulatory action(s).”
Endangered Species Act. The Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify gas well pad siting or pipeline right of ways, mining plans, or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on species that have been identified and the current application of endangered species laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to produce gas or mine coal from our properties. The U.S.
Fish and Wildlife Service (USFWS) announced a 12-month finding that listing of the Northern Long-Eared Bat as endangered is warranted throughout the bat’s range. CONSOL Energy,
26
along with others in industry has submitted comments against the listing. This listing will establish habitat protection for the species but will not prevent the cause of the decline in the population of the Northern Long-Eared Bat, which is due to a disease commonly referred to as White Nose Syndrome (WNS). This will lead to significant timing and critical path hurdles, ultimately limiting the ability to clear timber for construction activities. Both the Northeast Association of Fish and Wildlife
Agencies (NEAFWA) and Midwest Association of Fish and Wildlife Agencies (MAFWA) have indicated that an endangered listing is “not warranted,” but recommends it be listed as threatened due to WNS. The USFWS has stated that “A final decision on listing the northern long-eared bat will be made no later than April 2, 2015.”
Surface Mining Control and Reclamation Act. The federal Surface Mining Control and Reclamation Act (SMCRA) establishes minimum national operational and reclamation standards for all surface mines as well as most aspects of underground mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. Permits for all mining operations must be obtained from the U.S. Office of Surface
Mining (OSM) or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards which are more stringent than the requirements of SMCRA and OSM's regulations and in many instances have done so. Our active mining complexes are located in states which have achieved primary jurisdiction for enforcement of SMCRA through approved state programs. In addition, SMCRA imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund (AML Fund), which is used to restore unreclaimed and abandoned mine lands mined before 1977. The current per ton fee is $0.28 per ton for surface mined coal and $0.12 per ton for underground mined coal. These fees are currently scheduled to be in effect until September 30, 2021.
Excess
Spoil, Coal Mine Waste, Diversions, and Buffer Zones for Perennial and Intermittent Streams. OSM has issued final amendments to regulations concerning stream buffer zones, stream channel diversions, excess spoil, and coal mine waste to comply with an order issued by the U.S. District Court for the District of Columbia on February 20, 2014, which vacated the stream buffer zone rule that was published December 12, 2008. OSM has indicated that a new proposed Revised Stream Buffer Zone rule is likely in spring or summer of 2015, with a final goal for rule promulgation in December 2016.
West Virginia Above Ground Storage Tank Rules. In response to a spill by Freedom Industries of crude 4-methylcyclohexanemethanol (MCHM) to the Elk River
on January 9, 2014, West Virginia signed into law Senate Bill 373 (also known as the Above Ground Storage Tank Act), which requires that all above ground storage tanks (ASTs) be registered with the Department of Environmental Protection (DEP) and meet additional requirements. West Virginia DEP filed a Final Interpretive Rule addressing initial inspection, certification and spill prevention response plan requirements on October 21, 2014. This Interpretive Rule is a temporary measure until more comprehensive rules are filed. The West Virginia DEP plans to propose additional rules for public notice and comment in the coming year. With approximately 4,000 impacted ASTs currently operational in West Virginia and more needed for the oil and gas production, these rules could have a significant financial impact on CONSOL Energy.
Federal
Regulation of the Sale and Transportation of Gas
Regulations and orders set forth by the Federal Energy Regulatory Commission (FERC) impact our gas business to a certain degree. Although the FERC does not directly regulate our gas production activities, the FERC has stated that it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the FERC continues to review its transportation regulations, including whether to allocate all short-term capacity on the basis of competitive auctions and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. The FERC has also issued numerous orders confirming the sale and abandonment of natural gas gathering
facilities previously owned by interstate pipelines and acknowledging that if the FERC does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. We own certain natural gas pipeline facilities that we believe meet the traditional tests which the FERC has used to establish a pipeline's status as a gatherer not subject to the FERC jurisdiction.
27
Health
and Safety Laws
Occupational Safety and Health Act. Our gas operations are subject to regulation under the federal Occupational Safety and Health Act (OSHA) and comparable state laws in some states, all of which regulate health and safety of employees at our gas operations. Also, OSHA's hazardous communication standard requires that information be maintained about hazardous materials used or produced by our gas operations and that this information be provided to employees, state and local governments and the public.
Mine Safety. Legislative and regulatory changes have required us to purchase additional safety equipment, construct stronger seals to isolate mined out areas, and engage in additional training. We have also experienced more
aggressive inspection protocols and with new regulations the amount of civil penalties has increased. The actions taken thus far by federal and state governments include requiring:
•
the caching of additional supplies of self-contained self-rescuer (SCSR) devices underground;
•
the purchase and installation of electronic communication and personal tracking devices underground;
•
the
placement of refuge chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;
•
the replacement of existing seals in worked-out areas of mines with stronger seals;
•
the purchase of new fire resistant conveyor belting underground;
•
additional
training and testing that creates the need to hire additional employees; and
•
more stringent rock dusting requirements.
According to a November 2013 regulatory update, the Department of Labor (DOL) intends to publish final rules for underground coal mining operations concerning proximity detection systems for continuous mining machines and rules concerning the exposure of coal miners to crystalline silica. On January 15, 2015, MSHA published a final rule requring underground coal mine operations to equip continuous mining machines, except full-face continuous mining machines, with
proximity detection systems. The proximity detection system strengthens protection for miners by reducing the potential of pinning, crushing and striking hazards that result in accidents involving life-treating injuries and death. The final rule becomes effective March 15, 2015 and includes a phased in schedule for newly manufactured and in-service equipment. In 2010 MSHA rolled out the “End Black Lung, Act Now” initiative. As a result, MSHA has implemented a new final rule on August 1, 2014 to lower miners’ exposure to respirable coal mine dust including using the new Personal Dust Monitor (PDM) technology. This final rule will be implemented in three phases. The first phase began on August 1, 2014 and utilizes the current gravimetric sampling device to take full shift dust samples from the current designated occupations
and areas. It also requires additional record keeping and immediate corrective action in the event of overexposure. The second phase begins on February 1, 2016 and requires additional sampling for designated and other occupations using the new continuous personal dust monitor (CPDM) technology, which provides real time dust exposure information to the miner. CONSOL Energy has ordered the necessary CPDM equipment which is required to meet compliance with the new rule at a cost of $2 million. We are also in the process of hiring Dust Coordinators and Dust Technicians to meet the staffing demand to manage compliance with the new rule at an estimated cost of $3 million. The final phase of the new rule will take effect on August 1, 2016. The current respirable dust standard will then be reduced from 2.0 to 1.5mg/m3 for designated occupations and from 1.0 to 0.5mg/m3 for Part
90 Miners.
Black Lung Legislation. Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to:
•
current and former coal miners totally disabled from black lung disease;
•
certain survivors of a miner who dies from black lung disease or pneumoconiosis; and
•
a
trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner's last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
The Patient Protection and Affordable Care Act (PPACA) made two changes to the Federal Black Lung Benefits Act. First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in
underground coal mines, or in similar conditions, and suffer from a totally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner's work. Second, it changed the law so black lung benefits will continue to be paid to dependent survivors when the miner passes away, regardless of the cause of the miner's death. The
28
changes have increased the cost to CONSOL Energy of complying with the Federal Black Lung Benefits Act. In addition to the federal legislation, we are also liable under various state statutes for black lung claims.
Other
State and Local Laws Related to Our Gas Business
Regulation Affecting Gas Operations. Our gas operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the siting and construction of well pads and roads, drilling of wells, bonding requirements, protection of ground water and surface water resources and protection of drinking water supplies, the method of drilling and casing wells, the surface use and restoration of well sites, gas flaring, the plugging and abandoning of wells, the disposal of fluids used in connection with operations, and gas operations producing coalbed methane in relation to active mining. A number of states have either enacted new laws or may be considering the adequacy of existing laws affecting gathering rates and/or services.
Other state regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. Our gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although we do not believe that they would be affected by such regulation any differently than other natural gas producers or gatherers. However, these regulatory burdens may affect profitability, and we are unable to predict the future cost or impact of complying with such regulations.
Ownership of Mineral Rights. CONSOL Energy acquires ownership or leasehold rights to gas and coal properties
prior to conducting operations on those properties. As is customary in the gas and coal industries, we have generally conducted only a summary review of the title to gas and coal rights that are not in our development plans, but which we believe we control. This summary review is conducted at the time of acquisition or as part of a review of our land records to determine control of mineral rights. Given CONSOL Energy's long history as a coal producer, we believe we have a well-developed ownership position relating to our coal control; however, our ownership of oil and gas rights, particularly those rights that we acquired in connection with our historic coal operations and some of the rights we acquired in 2010 from Dominion are less developed. As we continue to review our land records and confirm title in anticipation of development, we expect that adjustments to our ownership position (either increases or decreases) will be required.
Prior
to the commencement of development operations on gas and coal properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We generally will not commence operations on a property until we have cured any material title defects on such property. We are typically responsible for the cost of curing any title defects. In addition, the acquisition of the necessary rights may not be feasible in some cases. Our discovering gas title defects which we are unable to cure may adversely impact our ability to develop those properties and we may have to reduce our estimated gas reserves including our proved undeveloped reserves. We have completed title work on substantially all of our gas and coal producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry.
Available
Information
CONSOL Energy maintains a website on the World Wide Web at www.consolenergy.com. CONSOL Energy makes available, free of charge, on this website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the 1934 Act), as soon as reasonably practicable after such reports are available, electronically filed with, or furnished to the SEC, and are
also available at the SEC's website www.sec.gov. Apart from SEC filings, we also use our website to publish information which may be important to investors, such as presentations to analysts.
Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Executive Officers of CONSOL Energy” (included herein pursuant to Item 401(b) of
Regulation S-K).
29
ITEM 1A.
Risk Factors
Investment in our securities is subject to various risks, including risks and uncertainties inherent in our business. The following sets forth factors related to our business, operations, financial position or future financial performance or cash flows which could
cause an investment in our securities to decline and result in a loss.
Deterioration in the global economic conditions in any of the industries in which our customers operate, or a worldwide financial downturn, such as the 2008 - 2009 financial crisis, or negative credit market conditions may have lasting effects on our liquidity, business and financial condition that we cannot predict.
Economic conditions in a number of industries in which our customers operate, such as electric power generation and steel making, substantially deteriorated in recent years and reduced the demand for natural gas and coal. Although global industrial activity recovered from 2009 levels, the general economic challenges for some of our customers continued in 2014 and the outlook is uncertain. In addition,
liquidity is essential to our business and developing our assets. Renewed or continued weakness in the economic conditions of any of the industries served by our customers could adversely affect our business and financial condition in a number of ways. For example:
•
demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas and thermal coal business;
•
demand
for metallurgical coal depends on steel demand in the United States and globally, which if weakened would negatively impact the revenues, margins and profitability of our metallurgical coal business including our ability to sell our thermal coal as higher-priced high volatile metallurgical coal;
•
the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables and the amount of receivables eligible for sale pursuant to our accounts receivable securitization facility may decline; and
•
our
ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our gas or coal reserves.
Prices for natural gas, natural gas liquids and coal are volatile and can fluctuate widely based upon a number of factors beyond our control including oversupply relative to the demand available for our products, weather and the price and availability of alternative fuels. An extended decline in the prices we receive for our natural gas, natural gas liquids, and coal will adversely affect our operating results and cash flows.
Our financial results are significantly affected by the prices we receive for our natural gas, natural gas liquids, oil and coal.
Natural
gas, natural gas liquids and oil accounted for approximately 32% of our outside sales revenues from continuing operations in 2014. Natural gas, natural gas liquids and oil prices are very volatile and can fluctuate widely based upon supply from energy producers relative to demand for these products and other factors beyond our control. The sale to Murray Energy in 2013 of almost one half of our thermal coal production increased our exposure to fluctuations in the price of metallurgical coal, natural gas, natural gas liquids and oil.
In particular, while demand for natural gas has recovered to pre-recession levels, the U.S. natural gas industry continues to face concerns of oversupply due to the success of Marcellus and other new shale plays. The oversupply of natural gas in 2012 resulted in domestic prices hovering around ten year lows, and drilling continued in these plays, despite
lower gas prices, to meet drilling commitments. Although gas prices recovered somewhat during 2013 and the first quarter of 2014, they again significantly declined in the latter part of 2014 due to oversupply.
Our gas operations are geographically concentrated in the mid-Atlantic states. The success of the Marcellus Shale play and development of other Shale plays has resulted in growth in gas production in this region with production per day in Pennsylvania, West Virginia and Ohio more than doubling since 2011. Traditionally, natural gas produced in the mid-Atlantic states sold at a premium to the benchmark Louisiana Henry Hub prices. However, as Appalachian production increased this premium narrowed and during 2014, the spot prices at some Appalachian hubs fell below Henry Hub prices. This decline, or negative basis, to the Henry Hub price is forecasted to continue in future
years and may widen due to anticipated further increased Appalachian gas production. Oversupply from the continued drilling in these plays, despite lower prices, directly affects prices we receive. Thus, apart from the general impact of domestic production on overall gas prices, the price paid for
30
our natural gas also may be adversely affected by increasing production and oversupply in our market. Low gas prices adversely impact our gas operations revenues and earnings before income taxes.
An extended period of lower natural gas prices could negatively affect us in several
other ways. These include reduced cash flow, which would decrease funds available for capital expenditures employed to replace reserves or increase production. For example, in light of the low natural gas prices during 2012, the number of wells drilled in our Noble joint venture during 2012 was significantly reduced from the number we initially planned to drill. Also, our access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable. Additionally, lower natural gas prices may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We
are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management's plans change with respect to those assets. We may incur impairment charges in the future, which could have an adverse effect on our results of operations in the period taken.
We and our joint venture partners have increased drilling activity in areas of shale formations which may also contain natural gas liquids and/or oil. The prices for natural gas liquids and oil are also volatile for reasons similar to those described above regarding natural gas. As a result of increasing supply, including from shale plays, oil prices fell to five year lows during 2014. In addition, similar to the oversupply of natural gas,
increased drilling activity in 2012 by third parties in formations containing natural gas liquids has led to a significant decline in the price of natural gas liquids. If we discover and produce significant amounts of natural gas liquids or oil, our results of operation may be adversely affected by downward fluctuations in natural gas liquids and oil prices.
The coal industry also faces concerns with respect to oversupply. Coal accounted for approximately 61% of our outside sales revenues from continuing operations in 2014. In 2013, our average sales price per ton of low volatile metallurgical coal fell by approximately 34% due to oversupply which was particularly acute in the international market. This trend continued in 2014 with metallurgical coal prices falling to six year lows and our average sales price of low volatile metallurgical coal further declined by another 22%
from 2013’s depressed price.
Apart from issues with respect to the supply of products we produce, demand can fluctuate widely due to a number of matters beyond our control including:
•
changes in the consumption pattern of industrial consumers, electricity generators and residential users;
•
weather conditions in our markets which affect the demand for natural gas and thermal coal (for example,
the unusually warm 2011 - 2012 winter left utilities with large coal stockpiles and depressed the demand for thermal coal);
•
proximity and capacity of gas pipelines and other transportation facilities;
•
the price and availability of alternative fuels, especially thermal coal; the price and supply of imported liquefied natural gas; and
•
increased
utilization by the steel industry of electric arc furnaces or pulverized coal processes to make steel which do not use furnace coke, an intermediate product produced from metallurgical coal, decreases the demand for metallurgical coal.
Foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.
We compete in international markets against coal produced in other countries. Coal is sold internationally in U.S. dollars. As a result, mining costs in competing producing countries may be reduced in U.S. dollar terms based on currency exchange rates, providing an advantage to foreign coal producers. We also expect in the future that an international market will develop for exporting domestic natural gas and natural gas liquids. Currency fluctuations
among countries purchasing and selling coal could adversely affect the competitiveness of our coal in international markets.
If coal customers do not extend existing contracts or do not enter into new long-term coal contracts, profitability of CONSOL Energy's operations could be affected.
During the year ended December 31, 2014, approximately 66% of the coal CONSOL Energy produced from continued operations was sold under long-term contracts (contracts
with terms of one year or more). If a substantial portion of CONSOL Energy's long-term contracts are modified or terminated or if force majeure is exercised, CONSOL Energy would be adversely affected if we are unable to replace the contracts or if new contracts are not at the same level of profitability. If existing
31
customers do not honor current contract
commitments, our revenue would be adversely affected. The profitability of our long-term coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production costs and other factors. Price changes, if any, provided in long-term supply contracts may not reflect our cost increases, and therefore, increases in our costs may reduce our profit margins. In addition, in periods of declining market prices, provisions in our long-term coal
contracts for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility. As a result, CONSOL Energy may not be able to obtain long-term agreements at favorable prices compared to either market conditions, as they may change from time to time, or our cost structure, and long-term contracts may not contribute to our profitability.
The loss of, or significant reduction in, purchases by our largest coal customers could adversely affect our revenues.
For the year ended December 31, 2014, we derived
over 10% of our total revenues from sales to two coal customers individually and more than 30% of our total revenue from sales to our four largest coal and gas customers. At December 31, 2014, we had approximately 30 coal supply agreements with these customers that expire at various times from 2015 to 2018. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be successful and these customers may not continue to purchase coal from us under long-term coal supply agreements. If any one of these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer.
Our
ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.
Our ability to receive payment for natural gas and coal sold and delivered depends on the continued creditworthiness of our customers. Some power plant owners may have credit ratings that are below investment grade. If the creditworthiness of our customers declines significantly, our $125 million accounts receivable securitization program and our business could be adversely affected. In addition, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer's contractual obligations are honored.
Our
gas business depends on gathering, processing and transportation facilities owned by others and the disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas. Similarly, the availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.
We gather, process and transport our gas to market by utilizing pipelines and facilities owned by others. If pipeline or facility capacity is limited, or if pipeline or facility capacity is unexpectedly disrupted for any reason, our gas sales and/or sales of natural gas liquids could be limited, reducing our profitability. If we cannot access processing pipeline transportation facilities, we may have to reduce our production of gas. If our sales of gas or natural gas
liquids are reduced because of transportation or processing constraints, our revenues will be reduced, and our unit costs will also increase. If pipeline quality standards change, we might be required to install additional processing equipment which could increase our costs. The pipeline could also curtail our flows until the gas delivered to their pipeline is in compliance.
Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to provide access to markets. Disruption of transportation services because of weather-related problems, strikes, lock-outs, terrorist attacks or other events could temporarily impair our ability to supply coal to customers and adversely affect our profitability. Transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is a critical factor in a customer's
purchasing decision. Increases in transportation costs could make our coal less competitive.
Competition within the natural gas and coal industries may adversely affect our ability to sell our products. Increased competition or a loss of our competitive position could adversely affect our sales of, or our prices for, our natural gas and coal products, which could impair our profitability.
The gas industry is intensely competitive with companies from various regions of the United States. We compete with these companies and we may compete with foreign companies for domestic sales. Many of the companies we compete with are larger and have greater financial, technological, human and other resources. If we are unable to compete, our
company, our operating results and financial position may be adversely affected. In addition, larger companies may be able to pay more to
32
acquire new gas properties for future exploration, limiting our ability to replace natural gas we produce or to grow our production. Our ability to acquire additional properties and to discover new natural gas resources also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.
CONSOL Energy competes with coal producers in various regions of the United
States and with some foreign coal producers for domestic sales primarily to electric power generators. CONSOL Energy also competes with both domestic and foreign coal producers for sales in international markets. Demand for our coal by our principal customers is affected by the delivered price of competing coals, other fuel supplies and alternative generating sources, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric and wind power. CONSOL Energy sells coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition. Increases in coal prices could encourage existing producers to expand capacity or could encourage new producers to enter the market. If overcapacity results, prices could fall or we may not be able to sell our coal, which would reduce revenue.
The
characteristics of coal may make it costly for electric power generators and other coal users to comply with various environmental standards regarding the emissions of impurities released when coal is burned which could cause utilities to replace coal-fired power plants with alternative fuels. In addition, various incentives have been proposed to encourage the generation of electricity from renewable energy sources. A reduction in the use of coal for electric power generation could decrease the volume of our domestic coal sales and adversely affect our results of operations.
Coal contains impurities, including sulfur, mercury, and other constituents, many of which are released into the air along with fine particulate matter and carbon dioxide when coal is burned. Environmental regulations governing emissions from coal fired electric generating plants could affect demand for
coal as a fuel source and affect volume of our sales. Complying with regulations on these emissions can be costly for electric power generators. For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users would either need to install and operate advanced air pollution control equipment, purchase emission allowances, or switch to other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. Switching to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which electric power generators switch to alternative fuel could materially affect us. In the last two years the U.S. EPA promulgated or finalized several rulemakings impacting coal generating facilities. These include
the Utility Maximum Control Technology (UMACT) rule which includes more stringent emission limits for particulate matter (PM), SO2 and NOX; and the Mercury and Air Toxics Standards (MATS) rule which set new mercury and air toxic standards. Additionally, litigation staying implementation of EPA’s Cross-State Air Pollution Rule (CSAPR) was finalized and the rule went into effect in October 2014 with Phase 1 implementation scheduled for 2015 and Phase 2 beginning in 2017. In late 2014, the EPA also proposed to lower the primary and secondary standard National Ambient Air Quality Standards (NAAQS) for ozone which could have a large impact on the fossil fuel industry.
In December 2014, the EPA resolved the uncertainty that surrounded the future management of coal combustion residuals (CCR), also known as coal ash,
produced from the combustion of coal in coal-fired electric generating units and finalized rules requiring the management of CCRs pursuant to the solid waste provisions (Subtitle D) of the Resource Conservation and Recovery Act (RCRA) and not under the hazardous waste provisions (Subtitle C).
Finally, in May 2014, the EPA finalized standards under Section 316(b) of the Clean Water Act (CWA) to reduce the injury and death of fish and other aquatic life caused by cooling-water intake structures at existing power plants, including coal- and natural gas-fired power plants. These national requirements will be implemented through facility permits pursuant to the National Pollutant Discharge Elimination System (NPDES),
Apart from actual and potential regulation of
emissions, waste water, and solid wastes from coal-fired plants, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reductions in the amount of coal consumed by domestic electric power generators as a result of current or new standards for the emission of impurities or incentives to switch to alternative fuels or renewable energy sources could reduce the demand for our coal, thereby reducing our revenues and
adversely affecting our business and results of operations.
33
Regulation of greenhouse gas emissions as well as uncertainty concerning such regulation could adversely impact the market for natural gas and coal and the regulation of greenhouse gas emissions may increase our operating costs and reduce the value of our natural gas and coal assets.
While climate change legislation in the U.S. is unlikely in the next several years, the issue of global climate change continues to attract considerable public and scientific attention with
widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (GHGs) such as carbon dioxide and methane. Combustion of fossil fuels, such as the natural gas and coal we produce, results in the creation of carbon dioxide emissions into the atmosphere by natural gas and coal end-users, such as coal-fired electric power generation plants. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Other states have elected to participate in voluntary regional cap-and-trade programs like the Regional Greenhouse Gas Initiative (RGGI) in the northeastern U.S. Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (but has not been ratified by the United States, and Canada
officially withdrew from its Kyoto commitment in 2012) was nominally extended past its expiration date of December 2012 with a requirement for a new legal construct to be put into place by 2015. The EPA has elected to regulate GHGs under the Clean Air Act.
New rules governing carbon dioxide emissions from fossil fuel powered electric generating plants were proposed in 2013 and 2014, including a New Source Performance Standard (NSPS) for new fossil fuel fired power plants and the Clean Power Plan, respectively, to cut carbon emissions from existing power plants. The EPA estimates that by 2030, the rule will achieve a 30% reduction in CO2 emissions from the U.S. electric power sector from 2005 levels and will reduce coal consumption for electricity generation by about 27% relative to the base case (i.e., relative to what it would be in the absence of the regulation), and will
reduce mine-mouth coal prices by about 15% relative to the base case.
Apart from governmental regulation, on February 4, 2008, three of Wall Street’s largest investment banks announced that they had adopted climate change guidelines. The guidelines require the evaluation of carbon risks in the financing of electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants.
Adoption of comprehensive legislation or regulation focusing on GHGs emission reductions for the United States (including the proposed rules discussed above) or other countries where we sell coal, or the inability of utilities to obtain financing in connection with coal-fired plants, may make it more costly to operate
fossil fuel fired (especially coal-fired) electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural gas-fueled power generation could become more economically attractive than coal-fueled power generation, substantially increasing the demand for natural gas. Apart from actual regulation, uncertainty over the extent of regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal or possibly natural gas consumed by domestic electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. We or our
customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal or natural gas and comply with future GHG emission standards.
In addition, coalbed methane must be expelled from our underground coal mines for mining safety reasons. Coalbed methane has a greater GHG effect than carbon dioxide. Our natural gas operations capture coalbed methane from our underground coal mines, although some coalbed methane is vented into the atmosphere when the coal is mined. If regulation of GHG emissions does not exempt the release of coalbed methane, we may have to further reduce our methane emissions, pay higher taxes, incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines or perhaps curtail coal production.
Our
natural gas and coal mining operations are subject to operating risks, including our reliance upon third party contractors, which could increase our operating expenses and decrease our production levels which could adversely affect our results of operations. Our natural gas and coal operations are also subject to hazards and any losses or liabilities we suffer from hazards which occur in our operations may not be fully covered by our insurance policies.
Our exploration for and production of natural gas involves numerous operating risks. The cost of drilling, completing and operating our shale gas wells, shallow oil and gas wells and coalbed methane (CBM) wells is often uncertain, and a number of factors can delay or prevent drilling operations, decrease production and/or increase the cost of our gas operations at particular sites for varying lengths of time thereby adversely
affecting our operating results. The operating risks that may have a significant impact on our gas operations include:
34
•
unexpected drilling conditions;
•
title problems;
•
pressure
or irregularities in geologic formations;
•
equipment failures or repairs;
•
fires, explosions or other accidents;
•
adverse weather conditions;
•
reductions
in natural gas prices;
•
security breaches or terroristic acts;
•
pipeline ruptures;
•
lack of adequate capacity for treatment or disposal of waste water generated in drilling, completion and production operations;
•
environmental
contamination from surface spillage of fluids used in well drilling, completion or operation including fracturing fluids used in hydraulic fracturing of wells, or other contamination of groundwater or the environment resulting from our use of such fluids; and
•
unavailability or high cost of drilling rigs, other field services and equipment.
Our coal mining operations are predominantly underground mines. These mines are subject to a number of operating risks that could disrupt operations, decrease production and increase the cost of mining at particular mines for varying lengths of time thereby adversely affecting our operating results.
In addition, if coal production declines, we may not be able to produce sufficient amounts of coal to deliver under our long-term coal contracts. CONSOL Energy's inability to satisfy contractual obligations could result in our customers initiating claims against us. The operating risks that may have a significant impact on our coal operations include:
•
variations in thickness of the layer, or seam, of coal;
•
amounts
of rock and other natural materials intruding into the coal seam and other geological conditions that could affect the stability of the roof and the side walls of the mine;
•
equipment failures or repairs;
•
fires, explosions or other accidents;
•
weather conditions; and
•
security
breaches or terroristic acts.
Although we maintain insurance for a number of hazards, we may not be insured or fully insured against the losses or liabilities that could arise from a significant accident in our gas or coal operations.
We also rely upon third party contractors to provide key services to our gas operations. We contract with third parties for well services, related equipment, and qualified experienced field personnel to drill wells and conduct field operations. The demand for these field services in the natural gas and oil industry can fluctuate significantly. Higher oil and natural gas prices generally stimulate increased demand causing periodic shortages. These
shortages may lead to escalating prices for drilling equipment, crews and associated supplies, equipment and services. Shortages may lead to poor service and inefficient drilling operations and increase the possibility of accidents due to the hiring of inexperienced personnel and overuse of equipment by contractors. In addition, the costs and delivery times of equipment and supplies are substantially greater in periods of peak demand. Accordingly, we cannot assure that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or increases in the costs of, drilling equipment, crews and associated supplies, equipment and field services in the future. We utilize third-party contractors to provide land acquisition and related services to support our land operational needs for both gas and coal segments. We also use third party contractors to provide construction and specialized services
to our mining operations. A decrease in the availability of field services or equipment and supplies, an increase in the prices charged for field services, equipment and supplies, or the failure of third party contractors to provide quality field services to us, could decrease our gas and coal production, increase our costs of gas and coal production, and decrease our anticipated profitability.
We attempt to mitigate the risks involved with increased industrial activity by entering into “take or pay”contracts with well service providers which commit them to provide field services to us at specified levels and commit us to pay for field services at specified levels even if we do not use those services. However, these contracts
expose us to economic risk. For example, if the price of natural gas declines and it is not economical to drill and produce additional natural gas, we may have to pay for field services that we did not use. This would decrease our cash flow and raise our costs of production.
A decrease in the availability or increase in the costs of commodities or capital equipment used in mining operations could decrease our coal production, impact our cost of coal production and decrease our anticipated profitability.
35
Coal mining consumes large
quantities of commodities including steel, copper, rubber products and liquid fuels and requires the use of capital equipment. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for commodities and capital equipment are strongly impacted by the global market. A rapid or significant increase in the costs of commodities or capital equipment we use in our operations could impact our mining operations costs because we may have a limited ability to negotiate lower prices, and, in some cases, may not have a ready substitute.
For drilling and mining operations, CONSOL Energy must obtain, maintain, and renew governmental permits and approvals which if we cannot obtain in a timely manner would reduce our production, cash flow and results of operations.
State
and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing and well site restoration. Delays or denials of gas permits could reduce our production, cash flows and results of operations.
Most coal producers in the eastern U.S. are being impacted by government regulations and enforcement to a much greater extent than a few years ago, particularly in light of the renewed focus by environmental agencies and the government generally on the mining industry, including more stringent enforcement and interpretation of the laws that regulate mining. The pace with which the government issues permits needed for new operations and for on-going operations to continue
mining has negatively impacted expected production, especially in Central Appalachia. Environmental groups in Southern West Virginia and Kentucky have challenged state and U.S. Army Corps of Engineers (ACOE) permits for mountaintop and other types of surface mining operations on various grounds. The most recent challenges have focused on the adequacy of the U.S. Army Corps of Engineers analysis of impacts to streams and the adequacy of mitigation plans to compensate for stream impacts resulting from valley fill permits required for mountaintop mining. These challenges have also enhanced the EPA's oversight and involvement in the review of permits by state regulatory authorities. In 2011, the EPA revoked an ACOE-issued Section 404 permit to a mining operator. Following the U.S. Supreme Court’s refusal in March 2012 to hear an appeal from the D.C. Circuit Court’s ruling upholding the EPA’s power to revoke a permit, in September 2014 the U.S. Court of Appeals upheld the
EPA’s action to revoke the permit. In addition, in July 2014 the D.C Circuit reversed a lower court’s decision and affirmed the EPA’s authority to adopt the Enhanced Coordination Process governing coordination with the ACOE in the processing of CWA permits. The Court also rejected challenges to EPA’s 2012 “Final Guidance” document regarding appropriate permit conditions, namely those affecting acceptable conductivity limits (e.g., acceptable ionic strength to support aquatic life). However, the Court left it up to the states on whether to adopt the guideline recommendations when issuing final NPDES permits. This decision has left mining permits in some degree of uncertainty whether the EPA will concur with a state’s draft permit conditions should they not contain specified limits regarding conductivity, further increasing operational uncertainty and costs.
Existing
and future government laws, regulations and other legal requirements relating to protection of the environment, and others that govern our business may increase our costs of doing business for coal and may restrict our coal operations.
We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authorities relating to protection of the environment. These include those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, threatened and endangered plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, the installation of various safety equipment in our mines,
remediation of impacts of surface subsidence from underground mining, and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitive position.
In addition, there is the possibility that we could incur substantial costs as a result of violations under environmental laws. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authorities or new interpretations of existing legal requirements by regulatory bodies relating to the protection of the environment could further affect our costs of operations and competitive position. The Clean Water Act is being used by opponents of mountain top removal mining as a means to challenge permits
and bring citizen suits to make coal mining more expensive. At CONSOL Energy’s Fola Mining Operations, six citizen suits have been filed challenging water discharge permits. Two of those suits were settled in 2014, and at least two are potentially affected by recent settlements by another mining operator in a similar case,
36
Existing and future government laws, regulations and other legal requirements relating to protection of the environment, and others that govern our business may increase our costs of doing business for natural gas, and may restrict our gas operations.
Regulations
applicable to the gas industry are under constant review for amendment or expansion at the federal and state level. Any future changes may affect, among other things, the pricing or marketing of gas production. For example, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as Marcellus Shale. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. Hydraulic fracturing is currently exempt from regulation under the federal Safe Drinking Water Act, except for hydraulic fracturing using diesel fuel. The disposal of produced water, drilling fluids and other wastes in underground injection disposal wells is regulated by the EPA under the federal Safe Drinking Water Act or by the states under counterpart
state laws and regulations. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing operations or to dispose of waste resulting from such operations. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities with a final report to be issued in 2015 along with stated accompanying regulation. EPA has also announced it will expand its CAA Subpart W regulations in 2015 to further address GHG and carbon dioxide emissions at wellheads and gathering facilities associated with natural gas production. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (DOE), the U.S. Government Accountability Office and the Department of the Interior. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing
in certain circumstances. If hydraulic fracturing is regulated at the federal, state or local level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs.
Further, air emissions that stem from hydraulic fracturing and completions processes, as well as from midstream activities such as the gathering and transmission of natural gas, are regulated by federal and state rules. However, interpretations of those rules, as well as additional changes to the regulations, could negatively impact our ability to meet our stated production objectives for the company. For example, source aggregation of air emissions to determine whether, under the Clean Air Act a source comprises
a single stationary source and is therefore a major source of air pollution, and thereby subject to the applicability of Nonattainment Prevention of Significant Deterioration and Title V permitting requirements, has and continues to be debated by the EPA, state regulatory agencies and the courts. Federal and state activities as well as court decisions could impact the development and transmission of plans of CONSOL, our joint venture partners, and gathering systems being installed and operated by CONE Midstream Partners, LP.
Additionally, some states have begun to adopt more stringent regulation and oversight of natural gas gathering lines than is currently required by federal standards. Pennsylvania, under Act 127, authorized the Public Utility Commission (PUC) oversight of Class I gathering lines, as well as requiring standards and fees associated with Class II and Class III
pipelines. The state of Ohio also moved to regulate natural gas gathering lines in a similar manner pursuant to Ohio Senate Bill 315 (SB315). SB315 expanded the Ohio PUC's authority over rural natural gas gathering lines. These changes in interpretation and regulation affect CONSOL Energy's midstream activities, requiring changes in reporting as well as increased costs.
Further, some state and local governments in the Marcellus Shale region in Pennsylvania and New York have considered or imposed a temporary moratorium on drilling operations using hydraulic fracturing until further study of the potential for environmental and human health impacts by the EPA or the relevant agencies are completed. Further, states could elect to prohibit hydraulic fracturing altogether, as Governor Andrew Cuomo of the State of New York announced in December 2014 with regard to fracturing activities
in New York. Also, a few municipalities in Colorado have adopted ordinances to ban hydraulic fracturing. No assurance can be given as to whether or not similar measures might be considered or implemented in jurisdictions in which our gas properties are located. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in states in which we operate, such legal requirements could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby could affect the determination of whether a well is commercially viable. New laws or regulations could also cause delays or interruptions or terminations of operations, the extent of which cannot be predicted, and could reduce the amount of oil and natural gas that we ultimately are able to produce in commercially paying quantities from our gas properties, all of which could have a materially adverse effect on our results of operations
and financial condition.
Our shale gas drilling and production operations require both adequate sources of water to use in the fracturing process as well as the ability to dispose of water and other wastes after hydraulic fracturing. Our CBM gas drilling
37
and production operations also require the removal and disposal of water from the coal seams from which we produce gas. If we cannot find adequate sources of water for our use or are unable to dispose of the water we use or remove it from the strata at a reasonable cost and
within applicable environmental rules, our ability to produce gas economically and in commercial quantities could be impaired.
As part of our drilling and production in shale formations, we use hydraulic fracturing processes. Thus, we need access to adequate sources of water to use in our shale operations. Further, we must remove and dispose of the portion of the water that we use to fracture our shale gas wells that flows back to the well-bore as well as drilling fluids and other wastes associated with the exploration, development or production of natural gas. In addition, in our CBM drilling and production, coal seams frequently contain water that must be removed and disposed of in order for the gas to detach from the coal and flow to the well bore. Our inability to locate sufficient amounts of water with respect to our shale operations, or the inability to dispose of or recycle
water and other wastes used in our shale and our CBM operations, could adversely impact our operations. For example, in Ohio, underground injection of gas well production fluids was temporarily suspended for underground injection disposal wells near Youngstown while regulatory authorities investigated whether injection of wastewater into the wells was causing low category earthquakes in the area.
Our mines are subject to stringent federal and state safety regulations that increase our cost of doing business at active operations and may place restrictions on our methods of operation. In addition, government inspectors under certain circumstances, have the ability to order our operations to be shutdown based on safety considerations. A mine could be shutdown for an extended period of time if a disaster were to occur at it.
Stringent
health and safety standards were imposed by federal legislation when the Federal Coal Mine Health and Safety Act of 1969 was adopted. The Federal Coal Mine Safety and Health Act of 1977 expanded the enforcement of safety and health standards of the Coal Mine Health and Safety Act of 1969 and imposed safety and health standards on all (non-coal as well as coal) mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in mine emergency procedures, mine plans and other matters. The additional requirements of the Mine Improvement and New Emergency Response Act of 2006 (the Miner Act) and implementing federal regulations include, among other things, expanded emergency response plans, providing additional quantities of breathable air for emergencies, installation of refuge chambers in underground coal mines, installation of two-way communications and tracking
systems for underground coal mines, new standards for sealing mined out areas of underground coal mines, more available mine rescue teams and enhanced training for emergencies. Most states in which CONSOL Energy operates have programs for mine safety and health regulation and enforcement. We believe that the combination of federal and state safety and health regulations in the coal mining industry is, perhaps, the most comprehensive system for protection of employee safety and health affecting any industry. Most aspects of mine operations, particularly underground mine operations, are subject to extensive regulation. The various requirements mandated by law or regulation can place restrictions on our methods of operations, creating a significant effect on operating costs and productivity. In addition, government inspectors under certain circumstances, have the ability to order our operation to be shutdown based on safety considerations. If a disaster were to occur at
one of our mines, it could be shutdown for an extended period of time and our reputation with our customers could be materially damaged.
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in liabilities to us.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage.” We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean-up of soil, surface water, groundwater, and other
media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or for the entire share.
We maintain extensive coal refuse areas and slurry impoundments at a number of our mining complexes. Such areas and impoundments are subject to extensive regulation. Structural failure of a slurry impoundment or coal refuse area could result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened
risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to claims for the resulting environmental contamination and associated liability, as well as for fines and penalties. Our coal refuse areas and slurry impoundments are designed, constructed, and inspected by our company and by regulatory authorities according to stringent environmental and safety standards.
38
In West Virginia there are areas where drainage from coal mining operations contains concentrations of selenium that
without treatment would result in violations of state water quality standards that are set to protect fish and other aquatic life. CONSOL Energy has several operations with selenium discharges. CONSOL Energy and other coal companies have worked to expeditiously develop cost effective means to remove selenium from mine water.
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us. An example of this is Naturally Occurring Radioactive Material (NORM) or Technologically-Enhanced, Naturally Occurring Radioactive Material (TENORM). NORM or TENORM is produced when activities such as deep drilling concentrate or expose radioactive materials that occur naturally in ores, soils, water, or other
natural materials. State and federal agencies are examining the possibility for worker exposure or associated environmental hazards due to processing and disposal of wastes containing NORM or TENORM. CONSOL Energy's operations could be affected if there is a hazard associated with NORM/TENORM or if it were to be regulated in such a way as to require expensive treatment and disposal options.
CONSOL Energy has reclamation, mine closing and gas well plugging obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.
The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. Also, state laws
require us to plug gas wells and reclaim well sites after the useful life of our gas wells has ended. CONSOL Energy accrues for the costs of current mine disturbance, gas well plugging and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing liabilities and gas well plugging, which are based upon permit requirements and our experience, were approximately $576 million at December 31, 2014. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely
affected.
Most states where we operate require us to post bonds for the full cost of coal mine reclamation (full cost bonding). West Virginia is not a full cost bonding state. West Virginia has an alternative bond system (ABS) for coal mine reclamation which consists of (i) individual site bonds posted by the permittee that are less than the full estimated reclamation cost plus (ii) a bond pool (Special Reclamation Fund) funded by a per ton fee on coal mined in the State which is used to supplement the site specific bonds if needed in the event of bond forfeiture. The Special Reclamation Fund was underfunded, resulting in a citizen suit before the U.S. District Court in West Virginia. In an effort to settle the issue in 2012, the WV legislature authorized an increase in the per ton fee levied on coal production to make up the shortfall. There remains the possibility that WV may
move to full cost bonding in the future which could cause individual mining companies and/or surety companies to exceed bonding capacity and would result in the need to post cash bonds or letters of credit which would reduce operating capital. Pennsylvania is expanding its full cost bonding program to cover all coal mine bonding, further increasing the amount of surety bonds CONSOL Energy must seek in order to permit its mining activities.
We face uncertainties in estimating our economically recoverable natural gas, oil and coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.
Natural gas and oil reserves require subjective estimates of underground accumulations of natural gas and oil and
assumptions concerning natural gas and oil prices, production levels, reserve estimates and operating and development costs. As a result, estimated quantities of proved natural gas and oil reserves and projections of future production rates and the timing of development expenditures may be incorrect. For example, a significant amount of our proved undeveloped reserves extensions and discoveries during the last three years were due to the addition of wells on our Marcellus Shale acreage more than one offset location away from existing production with reliable technology, which may be more susceptible to positive and negative changes in reserve estimates than our proved developed reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing and production. Also, we make certain assumptions regarding natural gas and oil prices, production levels, and operating and development costs that may prove incorrect.
Any significant variance from these assumptions to actual figures could greatly affect our estimates of our natural gas reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of natural gas and oil reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas we ultimately recover being different from reserve estimates. The present value of future net cash flows from our proved
39
reserves is not necessarily the
same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved natural gas reserves on historical average prices and costs. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:
•
geological conditions;
•
changes in governmental regulations and taxation;
•
the
amount and timing of actual production;
•
assumptions governing future prices;
•
future operating costs; and
•
capital costs of drilling, completion and gathering assets.
The timing
of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. If natural gas prices decline by $0.10 per Mcf, then the pre-tax present value using a 10% discount rate of our proved natural gas reserves as of December 31, 2014 would decrease from $4.9 billion to $4.7 billion.
Similarly, there are uncertainties inherent in estimating quantities and values of economically recoverable
coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include:
• geologic conditions;
• historical production from the area compared with production from other producing areas;
• the assumed effects of regulations and taxes by governmental agencies;
• assumptions governing future prices; and
•
future operating costs, including the cost of materials.
In addition, we hold substantial coal reserves in areas containing Marcellus Shale and other shales. These areas are currently the subject of substantial exploration for oil and natural gas, particularly by horizontal drilling. If a well is in the path of our mining for coal, we may not be able to mine through the well unless we purchase it. Although in the past we have purchased vertical wells, the cost of purchasing a producing horizontal well could be substantially greater. Horizontal wells with multiple laterals extending from the well pad may access larger oil and natural gas reserves than a vertical well which could result in higher costs. In future years, the cost associated with purchasing oil and natural gas wells which are in the path of our coal mining may make mining through those wells uneconomical thereby
effectively causing a loss of significant portions of our coal reserves.
Each of the factors which impacts reserve estimation may in fact vary considerably from the assumptions used in estimating the reserves. For these reasons, estimates of natural gas and coal reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal and natural gas reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual coal and natural gas reserves.
Defects may exist in our chain of title for our gas estate and we have not done a thorough chain of title examination of our gas estate. We may incur additional costs and delays to produce gas because we have to acquire additional property
rights to perfect our title to gas rights. If we fail to acquire additional property rights to perfect our title to gas rights, we may have to reduce our estimated reserves.
Substantial amounts of acreage in which we believe we control gas rights are in areas where we have not yet done a thorough chain of title examination of the gas estate. A number of our gas properties were acquired primarily for the coal rights with the focus on the coal estate title, and, in many cases were acquired years ago. In addition, we have acquired gas rights in substantial acreage from third parties who had not performed thorough chain of title work on their gas properties. Our practice, and we believe industry practice, is not to perform a thorough title examination on gas properties until shortly before the commencement of drilling activities at which time we seek to acquire
any additional rights needed to perfect our ownership of the gas estate for development and production purposes. When we perform a thorough chain of title examination, we may discover material defects in our title which would require us to acquire additional property rights. We may incur substantial costs to acquire these additional property rights. In addition, the acquisition of the necessary rights may not be feasible in some
40
cases. Our discovering of title defects which we are unable to cure may adversely impact our ability to develop those properties and we may have to reduce our estimated gas reserves including our proved undeveloped reserves.
Some
states (West Virginia and Virginia) permit us to produce coalbed methane gas without perfected ownership under an administrative process known as “pooling,” which requires us to give notice to all potential claimants and pay royalties into escrow until the undetermined rights are resolved. As a result, we may have to pay royalties to produce coalbed methane gas on acreage that we control and these costs may be material. Further, the pooling process is time-consuming and may delay our drilling program in the affected areas.
CONSOL Energy and its subsidiaries are subject to various legal proceedings, which may have an adverse effect on our business.
We are party to a number of legal proceedings
in the normal course of business activities. Defending these actions, especially purported class actions, can be costly, and can distract management. For example, we are a defendant in three pending purported class action lawsuits dealing with claimants’ entitlement to, and accounting for, gas royalties. There is the potential that the costs of defending litigation in an individual matter or the aggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position. See Note 24 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal proceedings.
CONSOL Energy has obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, could result in CONSOL Energy being required
to expense greater amounts than anticipated.
CONSOL Energy provides various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. At December 31, 2014, the current and non-current portions of these obligations included:
•
postretirement medical and life insurance ($761 million);
•
coal workers'
black lung benefits ($126 million);
•
salaried retirement benefits ($119 million); and
•
workers' compensation ($90 million).
However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Salary retirement benefits are funded in accordance with Employer Retirement Income Security Act of 1974 (ERISA) regulations. The other obligations are
unfunded. In addition, the federal government and several states in which we operate consider changes in workers' compensation and black lung laws from time to time. Such changes, if enacted, could increase our benefit expense.
If lump sum payments made to retiring salaried employees pursuant to CONSOL Energy's defined benefit pension plan exceed the total of the service cost and the interest cost in a plan year, CONSOL Energy would need to make an adjustment to operating results equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum payment in that year, which may result in an adjustment that could reduce operating results.
CONSOL Energy's defined benefit pension plan for salaried employees allows such employees to receive a lump-sum distribution
for benefits earned up through December 31, 2005 in lieu of annual payments when they retire from CONSOL Energy. Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans for Terminations Benefits requires that if the lump-sum distributions made for a plan year exceed the total of the service cost and interest cost for the plan year, CONSOL Energy would need to recognize for that year's results of operations an adjustment equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum in that year. If the settlement is triggered in future periods, it may be material to operating results.
Acquisitions that we have completed, acquisitions that we may undertake in the future, as well as expanding existing company mines, involve a number of risks, any of which
could cause us not to realize the anticipated benefits and to the extent we plan to engage in joint ventures and divestitures, we do not control the timing of these and they may not provide anticipated benefits.
We have completed several acquisitions and investments in the past. We also continually seek to grow our business by adding and developing gas and coal reserves through acquisitions and by expanding the production at existing mines and
41
existing gas operations. If we are
unable to successfully integrate the companies, businesses or properties we acquire, we may fail to realize the expected benefits of the acquisition and our profitability may decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Acquisitions, mine expansion and gas operation expansion involve various inherent risks, including:
•
uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of expansion and acquisition opportunities
•
the
potential loss of key customers, management and employees of an acquired business;
•
the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition opportunity:
•
the potential revision of assumptions regarding gas reserves as we acquire more knowledge by operating an acquired gas business:
•
problems
that could arise from the integration of the acquired business;
•
unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or the acquisition opportunity; and
•
we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.
From time to time
part of our business and financing plans include entering into joint venture arrangements and the divestiture of certain assets. However, we do not control the timing of divestitures or joint venture arrangements and delays in entering into divestitures or joint venture arrangements may reduce the benefits from them. In addition, the terms of divestitures and joint venture arrangements may cause a substantial portion of the benefits we anticipate receiving from them to be subject to future matters that we do not control.
We have entered into two significant natural gas joint ventures. These joint ventures restrict our operational and corporate flexibility; actions taken by our joint venture partners may materially impact our financial position and results of operations; and we may not realize the benefits we expect to realize from these joint ventures.
In
the second half of 2011, we, through our principal gas operations subsidiary, CNX Gas, entered into joint venture arrangements with Noble Energy, Inc. and with a subsidiary of Hess Corporation, regarding our shale gas assets. We sold a 50% undivided interest in certain of our Marcellus shale oil and natural gas assets to Noble Energy and a 50% undivided interest in certain of our Utica shale acres in Ohio to Hess. The following aspects of these joint ventures could materially impact us:
The development of these properties is subject to the terms of our joint development agreements with these parties and we no longer have the flexibility to control completely the development of these properties. For example, the joint development agreements for each of these joint ventures sets forth required capital expenditure programs that each party must participate in unless the parties
mutually agree to change such programs or, in certain limited circumstances in the case of the Noble Energy joint development agreement, a party elects to exercise a non-consent right with respect to an entire year. If we do not timely meet our financial commitments under the respective joint development agreements, our rights to participate in such joint ventures will be adversely affected and the other parties to the joint ventures may have a right to acquire a share of our interest in such joint ventures proportionate to, and in satisfaction of, our unmet financial obligations. In addition, each joint venture party has the right to elect to participate in all acreage and other acquisitions in certain defined areas of mutual interest.
Each joint development agreement assigns to each party designated areas over which that party will manage and control operations. We could incur
liability as a result of action taken by one of our joint venture partners.
One of the potential benefits of these two joint ventures is the obligation of the other party to pay a portion of our share of drilling and development costs for new wells, which we called "carried costs." At December 31, 2014, the remaining carried costs obligation of Noble Energy was approximately $1.63 billion while Hess' remaining carried costs obligation was approximately $99 million. Thus, the benefits we anticipate receiving in the joint ventures depend in part upon the rate at which new wells are drilled and developed in each joint venture, which could fluctuate significantly from period to period. Moreover, the performance of these third party obligations is outside our control. The inability or failure of our joint venture partners to
pay their portion of development costs, including our carried costs during the carry period, could increase our costs of operations or result in reduced drilling and production of oil and natural gas or loss of rights to develop the oil and natural gas properties held by that joint venture.
42
Noble Energy's obligation to pay carried costs is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per million British thermal units or “MMbtu” in any three consecutive month period and will remain suspended until average natural gas prices are above $4.00/MMbtu for three consecutive months. As a
result of this provision, Noble Energy's obligation to pay carried costs was suspended from December 1, 2011 to March 1, 2014 and was again suspended on November 1, 2014. We cannot predict when this latest suspension will be lifted and Noble Energy's obligation to pay the carried costs will resume. This suspension has the effect of requiring us to incur our entire 50 percent share of the drilling and completion costs for new wells during the suspension period and delaying receipt of a portion of the value we expect to receive in the transaction.
The Hess joint development agreement provides that any transfer of interest in the joint venture by us or Hess will be subject to a right of first offer in favor of the other party. These
restrictions may preclude transactions which could be beneficial to our shareholders.
Disputes between us and our joint venture partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.
We may also enter into other joint venture arrangements in the future which could pose risks similar to risks described above.
The provisions of our debt agreements and the risks associated with our debt could adversely affect our business, financial condition and results of operations.
As
of December 31, 2014, our total indebtedness was approximately $3.29 billion of which approximately $1.85 billion was under our 5.875% senior unsecured notes due 2022 plus $7 million of unamortized bond premium, $1.02 billion was under our 8.250% senior unsecured notes due 2020, $250 million was under our 6.375% senior notes due 2021, $103 million was under our Maryland Economic Development Corporation Port Facilities Refunding Revenue Bonds (MEDCO) 5.75% revenue bonds due September 2025, $47 million of capitalized leases due through 2021, and $17 million of miscellaneous debt. The degree to which we are leveraged could have important consequences, including, but not limited to:
•
increasing
our vulnerability to general adverse economic and industry conditions;
•
requiring us to dedicate a substantial portion of our cash flow from operations to the payment of interest and principal due under our outstanding debt, which will limit our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our gas and coal reserves or other general corporate requirements;
•
limiting our flexibility in planning for, or reacting to, changes in our business and
in the coal and gas industries;
•
placing us at a competitive disadvantage compared to our competitors with lower leverage and better access to capital resources; and
•
limiting our ability to implement our business strategy, including the structuring and formation of a master limited partnership for our thermal coal business and a subsidiary entity for the purpose of owning the metallurgical coal properties and related mining operations.
Our
senior secured credit facility and the indentures governing our 5.875%, 8.250% and 6.375% senior unsecured notes limit the incurrence of additional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreement and the indentures governing our 5.875%, 8.250% and 6.375% senior unsecured notes subject us to financial and/or other restrictive covenants. Under our senior secured credit agreement, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio, and a minimum current ratio, as defined therein. Our senior secured credit agreement and the indentures governing our 5.875%, 8.250% and 6.375% senior unsecured
notes impose a number of restrictions upon us, such as restrictions on granting liens on our assets, making investments, paying dividends, stock repurchases, selling assets and engaging in acquisitions. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have an adverse effect on us.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations.
Our senior secured credit agreement and the indentures governing our 5.875%, 8.250% and 6.375% senior unsecured notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.
43
Unless we replace our gas and oil reserves, our gas and oil reserves and production will decline, which would adversely affect our business, financial condition,
results of operations and cash flows.
Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2014, production is expected to decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future natural gas and oil reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring
additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs
Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.
To manage our exposure to fluctuations in the price of natural gas, we enter into hedging arrangements with respect to a portion of our expected production. As of January 15, 2015, we had hedges on approximately 121.2 Bcf of our 2015 natural gas production and 94.7 Bcf of our 2016 natural gas production. To the extent that we engage
in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges. If we choose not to engage in, or reduce our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas prices than our competitors who engage in hedging arrangements to a greater extent than we do.
In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
the creditworthiness of our counterparties or their guarantors is substantially impaired.
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.
The
passage of legislation or any other similar changes in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas, oil or coal exploration and development. Any such change could negatively affect our financial condition and results of operations.
For example, in February 2012, the state legislature of Pennsylvania passed a new natural gas impact fee in Pennsylvania, where a substantial portion of our acreage in the Marcellus Shale is located. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average New York Mercantile Exchange’s natural gas prices from the last day of each month. The estimated
total fees per well based on today’s current natural gas price is between $240 thousand and $310 thousand over the 15 year period. The passage of this legislation increases the financial burden on our operations in the Marcellus Shale.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition. Additionally, our development and exploration projects require substantial capital expenditures and if we fail to obtain required capital or financing on satisfactory terms, our natural gas reserves may decline.
Our future growth prospects are dependent upon our ability to identify optimal
strategies for our business. In developing our business plan, we considered allocating capital and other resources to various aspects of our businesses including well development (primarily drilling), reserve acquisitions, exploratory activity, coal development, corporate items and other alternatives. We also considered our likely sources of capital, including cash generated from operations and borrowings under our credit facilities. Notwithstanding the determinations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and future
44
growth
may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
As part of our strategic determinations, we expect to continue to make substantial capital expenditures in the development and acquisition of natural gas reserves. We cannot assure you that we will have sufficient cash from operations, borrowing capacity under our credit facilities or the ability to raise additional funds in the capital markets. If cash flow generated by our operations or available borrowings under our credit facilities are not sufficient to meet our capital requirements, or we are unable to obtain additional financing, we could be required to curtail the pace of the development of our natural gas properties, which in turn could lead
to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.
Any failure by Murray Energy to satisfy the liabilities it assumed from us, as well as to perform its obligations under various agreements whose performance by Murray Energy we guaranteed, or under various agreements with us, could materially increase our liabilities and materially adversely affect our results of operations, financial position and cash flows.
In 2013, Murray Energy and its subsidiaries (Murray Energy) acquired approximately $2.4 billion of liabilities which had been reflected on our books. In addition to these assumed liabilities, (i) Murray Energy
acquired our obligations under the multi-employer defined benefit pension plan for United Mine Workers of America (1974 Pension Plan), (ii) we guaranteed performance by Murray Energy under various West Virginia and Pennsylvania operational surety bonds and workers compensation obligations, under various equipment leases and to reclaim an impoundment site, and (iii) we leased or subleased various mining equipment to Murray Energy and we guaranteed performance by Murray Energy of certain coal supply agreements that Murray Energy acquired in the transaction. Our maximum estimated exposure under our Murray Energy guarantees as of December 31, 2014 was approximately $261 million. The leases and subleases we entered into with Murray Energy relate to approximately $201 million of equipment. Murray Energy also acquired retiree medical liabilities under the Coal Industry Retiree Health Benefits Act of 1992, for which Murray Energy
is primarily liable, but CONSOL Energy remains secondarily liable. On November 12, 2013 in connection with the transaction, Moody’s assigned Murray Energy a family credit rating of B3 (speculative and subject to high credit risk) and its secured second lien notes due 2021 a rating of Caa1(poor standing and subject to very high credit risk). Any failure by Murray Energy to satisfy these assumed liabilities or perform under these agreements could result in substantial claims against us by third parties and materially adversely affect our results of operations, financial position and cash flows. In addition, we will regularly evaluate the likelihood of default by Murray Energy under the guarantees we have provided. The results of the evaluation may materially impact our results of operations. If Murray Energy defaults under the obligations we guarantee our cash flows may also be materially impacted.
Terrorist
attacks or a cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber attacks than other targets in the United States. Deliberate attacks on, or security breaches in our systems or infrastructure, or the systems or infrastructure of third parties, or the cloud could lead to corruption or
loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
A substantial majority of sales of thermal coal and high volatile metallurgical coal are from three mines at one
location in Pennsylvania while a substantial majority of our low volatile metallurgical coal is from one mine located in Virginia, making us vulnerable to risks associated with operating in a single geographic area.
The substantial majority of our sales of thermal coal and high volatile metallurgical coal, as well as our thermal coal reserves, are from our Bailey, Enlow Fork and Harvey underground mining complexes located in Greene County, Pennsylvania. In addition, we also rely upon one coal processing plant and rail load facility, located in Enon, Pennsylvania for shipping coal from all of these mines. Any disruption in the functioning of this coal processing plant and rail load facility such as the
45
structural
failure at the above ground conveyor system which occurred in 2012 or in transportation in this area could significantly reduce our sales of thermal and high volatile metallurgical coal and adversely affect our results of operation and financial condition.
Similarly, the substantial majority of our low volatile metallurgical coal sales, as well as our low volatile metallurgical coal reserves, are from our Buchanan mine located in Mavisdale, Virginia. Any disruption in the functioning of this mine (such as the 2007 mine incident which idled the Buchanan mine for approximately nine months) or transportation in this area could significantly reduce our sales of low volatile metallurgical coal and adversely affect our results of operation and financial condition.
Our inability to complete
the proposed initial public offerings of our thermal coal and metallurgical coal businesses on the terms currently contemplated, or at all, may result in a reduction in our 2015 capital budget.
We are pursuing an initial public offering of limited partnership interests in a master limited partnership entity that would indirectly own substantially all of our thermal coal assets. We are also pursuing an initial public offering for a subsidiary which would indirectly own substantially all of our low volatile metallurgical coal assets. Adverse developments in our thermal or metallurgical coal businesses may result in our failure to complete either or both of these initial public offerings or decrease the proceeds which we anticipate receiving. Adverse developments include the various matters set forth in these risk factors which could adversely impact our coal businesses. In addition,
general market conditions, including the market for yield securities, may impact our ability to complete the initial public offerings on the terms currently contemplated, or at all. Our inability to complete the initial public offerings on the terms currently contemplated, or at all, may result in a reduction in our 2015 capital budget.
ITEM 1B.
Unresolved Staff Comments
None.
ITEM
2.
Properties
See “Coal Operations” and “Gas Operations” in Item 1 of this 10-K for a description of CONSOL Energy's properties.
ITEM 3.
Legal Proceedings
The first through the eighth paragraphs of Note 24–Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K are incorporated
herein by reference.
ITEM 4.
Mine Safety and Health Administration Safety Data
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 is included in Exhibit 95 to this annual report.
46
PART
II
ITEM 5.
Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
The Company's common stock is listed on the New York Stock Exchange under the symbol CNX. The following table sets forth, for the periods indicated, the range of high and low sales prices per share of our common stock as reported on the New York Stock Exchange and the cash dividends declared on the common stock for the periods indicated:
As
of December 31, 2014, there were 148 holders of record of our common stock.
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the common stock of CONSOL Energy to the cumulative shareholder return for the same period of a peer group and the Standard & Poor's 500 Stock Index. The peer group is comprised of CONSOL Energy, Alpha Natural Resources Inc., Arch Coal Inc., Chesapeake Energy Corp., Devon Energy Corp., EOG Resources Inc., Noble Energy Inc., Peabody Energy Corp., Southwestern Energy Co., QEP Resources Inc., and WPX Energy, Inc., Teck Resources Limited, EQT, Walter Energy Inc., Range Resources Corp., Cabot Oil & Gas Corp., Antero Resources Corp. The graph assumes that the value of the investment in CONSOL
Energy common stock and each index was $100 at December 31, 2009. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2014.
2009
2010
2011
2012
2013
2014
CONSOL
Energy Inc.
100.0
97.9
73.9
65.1
76.4
67.8
Peer
Group
100.0
104.5
91.3
83.1
105.4
88.2
S&P
500 Stock Index
100.0
112.6
110.6
125.4
162.5
181.0
47
Cumulative
Total Shareholder Return Among CONSOL Energy Inc., Peer Group and S&P 500 Stock Index
The above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).
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 3.03 to 1.00 and the cumulative credit was approximately $397 million at December 31, 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 year ended December 31, 2014.
CONSOL Energy has publicly announced that if CONSOL Energy effects an initial public offering of a thermal coal MLP, CONSOL Energy anticipates that it would reduce or eliminate its current regular dividend effective in the first quarter after the initial public offering.
See Part III, Item 12. “Security Ownership of Certain
Beneficial Owners and Management and Related Stockholder Matters” for information relating to CONSOL Energy's equity compensation plans.
48
ITEM 6.
Selected Financial Data
The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial
data for, and as of the end of, each of the years ended December 31, 2014, 2013, 2012, 2011 and 2010 are derived from our audited Consolidated Financial Statements. Certain reclassifications of prior year data have been made to conform to the year ended December 31, 2014 presentation. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with Item 7 “Management's Discussion and Analysis of Financial Condition and Results
of Operations” and the financial statements and related notes included in this Annual Report.
Net
Income Attributable to CONSOL Energy Inc. Shareholders
$
163,090
$
660,442
$
388,470
$
632,497
$
346,779
Earnings
(Loss) per share:
Basic:
Income
from Continuing Operations
$
0.73
$
0.35
$
1.40
$
3.01
$
1.41
(Loss)
Income from Discontinued Operations
(0.02
)
2.54
0.31
(0.22
)
0.20
Net
Income
$
0.71
$
2.89
$
1.71
$
2.79
$
1.61
Dilutive:
Income
from Continuing Operations
$
0.73
$
0.35
$
1.39
$
2.98
$
1.40
(Loss)
Income from Discontinued Operations
(0.03
)
2.52
0.31
(0.22
)
0.20
Net
Income
$
0.70
$
2.87
$
1.70
$
2.76
$
1.60
Assets
from Continuing Operations
$
11,759,530
$
11,393,667
$
10,383,343
$
9,952,077
$
9,543,457
Assets
from Discontinued Operations
—
—
2,614,251
2,573,623
2,527,153
Total
Assets
$
11,759,530
$
11,393,667
$
12,997,594
$
12,525,700
$
12,070,610
Long-Term
Debt from Continuing Operations (including current portion)
$
3,288,894
$
3,175,014
$
3,185,497
$
3,196,455
$
3,209,101
Long-Term
Debt from Discontinued Operations (including current portion)
—
—
2,574
1,659
1,820
Total
Long-Term Debt (including current portion)
$
3,288,894
$
3,175,014
$
3,188,071
$
3,198,114
$
3,210,921
Cash
Dividends Declared Per Share of Common Stock
$
0.250
$
0.375
$
0.625
$
0.425
$
0.400
See
Item 1A, “Risk Factors” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of an adjustment to operating revenues for all periods and other matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.
Net
sales volumes produced (in billion cubic feet)
235.7
172.4
156.3
153.5
127.9
Average
sales price ($ per Mcfe)(A)
$
4.37
$
4.30
$
4.22
$
4.90
$
5.83
Average
cost ($ per Mcfe)
$
3.31
$
3.51
$
3.37
$
3.53
$
3.54
Proved
reserves (in Bcfe) (B)
6,828
5,731
3,993
3,480
3,732
Coal:
Tons
sold from continuing operations (in thousands)(C)
32,419
28,776
27,612
32,090
32,280
Tons
produced from continuing operations (in thousands)
32,218
28,476
27,178
31,721
31,895
Average
sales price of tons produced ($ per ton produced)
$
63.03
$
69.34
$
77.75
$
90.10
$
73.31
Average
Cost of Goods Sold ($ per ton produced)
$
46.91
$
50.78
$
53.98
$
51.88
$
44.37
Recoverable
coal reserves (tons in millions)(D)
3,238
3,032
4,229
4,314
4,229
Number
of active mining complexes (at end of period)
3
4
5
7
7
____________
(A)
Represents
average net sales price including the effect of derivative transactions.
(B)
Represents proved developed and undeveloped gas reserves at period end.
(C)
Includes sales of coal produced by CONSOL Energy and purchased from third parties. Of the tons sold, CONSOL Energy purchased the following amount from third parties: 0.2 million tons, 0.6 million tons, 0.5 million tons, 0.6 million tons, and 0.2 million tons for the years ended December 31, 2014,
2013, 2012, 2011 and 2010, respectively.
(D)
Represents proven and probable coal reserves at period end, excluding equity affiliates.
50
ITEM
7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
General
2014 Highlights
•
Record total gas production of 235.7 Bcfe in 2014, 37% higher than 2013.
•
Record
Marcellus Shale production of 111.7 Bcfe in 2014, 93% higher than 2013.
•
On December 29, 2014 CNX Gas Company LLC, a wholly-owned subsidiary of CONSOL Energy, finalized an agreement with Columbia Energy Ventures to sublease approximately 20,600 acres of Utica Shale gas rights in Greene and Washington Counties in Pennsylvania, and Marshall and Ohio Counties in West Virginia. Consideration of up to $96,106 will be paid by CONSOL Energy over the next five years as drilling occurs.
•
CONSOL
received $411,596 in cash proceeds from the sales of assets which resulted in a gain on sale of $43,601. These sales included several non-core business assets: our industrial supplies subsidiary, coal reserves in the Illinois Basin, surface properties in Illinois, a 50% interest in an equity affiliate and a 50% interest in Utica Shale acres to our joint venture partner, Noble Energy. See Note 3 - Acquisitions and Dispositions in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
•
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. Of the proceeds received, $204 million was distributed to CNX Gas Company LLC.
•
Harvey Mine began longwall mining in March 2014.
2015 Expectations:
•
Our 2015 annual gas production is expected to be between 300 - 310 Bcfe with annual production growth of 30% through 2016.
•
Our
2015 gas capital investment is expected to be $1.0 billion.
•
Our 2015 coal production is expected to be between 30.5 - 33.0 million tons.
•
Our 2015 coal and other capital investment is expected to be $220 million.
•
In December 2014, CONSOL Energy announced that its Board of Directors authorized
management to pursue the formation of a master limited partnership (MLP) for the Company’s thermal coal business, which would own interests in CONSOL Energy’s thermal coal properties and related mining operations located in Pennsylvania, including its Bailey Mine, Enlow Fork Mine, Harvey Mine and the related preparation plant. CONSOL Energy also announced that its Board of Directors authorized management to separately pursue the structuring and formation of a subsidiary entity for the purpose of owning CONSOL Energy’s metallurgical coal properties and related mining operations, with a view to conducting an initial public offering of up to 20% of the subsidiary’s equity. The subsidiary’s assets would include CONSOL Energy’s Buchanan Mine and related preparation plant and its interest in its Western Allegheny Energy joint venture.
•
In
December 2014, CONSOL Energy’s Board of Directors approved a stock repurchase program under which CONSOL Energy may purchase from time to time up to $250,000 of its common stock over the next two years.
Net Income Attributable to CONSOL Energy Shareholders
CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $163 million, or income of $0.70 per diluted share, for the year ended December 31, 2014, compared to net income attributable to CONSOL Energy shareholders of $660
million, or income of $2.87 per diluted share, for the year ended December 31, 2013. The breakdown of net income attributable to CONSOL Energy shareholders is as follows:
For the Years Ended December 31,
(Dollars in millions, except per share data)
2014
2013
Variance
Income
from Continuing Operations
$
169
$
79
$
90
(Loss) Income from Discontinued Operations, net
(6
)
580
(586
)
Net
Income
163
659
(496
)
Less: Net Loss Attributable to Noncontrolling Interests
—
(1
)
1
Net
Income Attributable to CONSOL Energy Shareholders
$
163
$
660
$
(497
)
Income
from Continuing Operations
$
0.73
$
0.35
$
0.38
(Loss) Income from Discontinued Operations
(0.03
)
2.52
(2.55
)
Total
Dilutive Earnings Per Share
$
0.70
$
2.87
$
(2.17
)
The total Exploration and Production (E&P) division includes Marcellus, Utica, coalbed methane
(CBM) and other gas. The total E&P division contributed income of $190 million before income tax for the year ended December 31, 2014 compared to a loss of $2 million before income tax for the year ended December 31, 2013. Total E&P production was 235.7 Bcfe for the year ended December 31, 2014 compared to 172.4 Bcfe for the year ended December 31, 2013.
The
following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s production and sales portfolio.
For the Years Ended December 31,
in
thousands (unless noted)
2014
2013
Variance
Percent Change
LIQUIDS
NGLs:
Sales
Volume (MMcfe)
15,475
2,628
12,847
488.9
%
Sales Volume (Mbbls)
2,579
438
2,141
488.8
%
Gross
Price ($/Bbl)
$
35.70
$
53.76
$
(18.06
)
(33.6
)%
Gross
Revenue
$
92,136
$
23,541
$
68,595
291.4
%
Oil:
Sales
Volume (MMcfe)
681
634
47
7.4
%
Sales Volume (Mbbls)
114
106
8
7.5
%
Gross
Price ($/Bbl)
$
89.10
$
89.58
$
(0.48
)
(0.5
)%
Gross
Revenue
$
10,108
$
9,471
$
637
6.7
%
Condensate:
Sales
Volume (MMcfe)
3,298
382
2,916
763.4
%
Sales Volume (Mbbls)
550
64
486
759.4
%
Gross
Price ($/Bbl)
$
66.96
$
81.06
$
(14.10
)
(17.4
)%
Gross
Revenue
$
36,808
$
5,156
$
31,652
613.9
%
GAS
Sales
Volume (MMcf)
216,260
168,737
47,523
28.2
%
Sales Price ($/Mcf)
$
4.02
$
3.72
$
0.30
8.1
%
Hedging
Impact ($/Mcf)
$
0.11
$
0.45
$
(0.34
)
(75.6
)%
Gross
Revenue
$
891,522
$
702,700
$
188,822
26.9
%
52
The
average sales price and average costs for all active gas operations were as follows:
Total
E&P division Natural Gas, NGLs, and Oil outside sales revenues were $1,031 million for the year ended December 31, 2014 compared to $741 million for the year ended December 31, 2013. The increase was primarily due to the 36.7% increase in total volumes sold, along with a 1.6% increase in overall average sales price per Mcfe. The increase in average sales price is the result of a $0.30 per Mcfe increase in general market prices and the $0.11 per Mcfe increase in sales of NGLs, oil and condensate. The increase was offset, in part, by the $0.34
per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 159.9 Bcf of our produced gas sales volumes for the year ended December 31, 2014 at an average gain of $0.15 per Mcf. These financial hedges represented approximately 84.3 Bcf of our produced gas sales volumes for the year ended December 31, 2013 at an average gain of $0.89 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 36.7% increase in volumes in the period-to-period comparison and the shift to lower cost Marcellus and Utica Shale production. Marcellus production made up 47.4% of natural gas and liquid sales volume for the year ended December 31, 2014 compared to 33.6% in the year ended December 31, 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 natural gas liquids (NGLs).
The coal division includes Pennsylvania (PA) operations, Virginia (VA) operations
and other coal. The total coal division contributed $411 million of earnings before income tax from continuing operations for the year ended December 31, 2014 compared to $348 million for the year ended December 31, 2013. The total coal division sold 32.4 million tons of coal produced from continuing operations for the year ended December 31, 2014 compared to 28.8 million tons for the year ended December 31, 2013.
The
average sales price and average costs per ton for continuing coal operations were as follows:
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 overall lower coal pricing due to the roll-off of some higher-priced legacy contracts. The coal division priced 6.4 million tons on the export market for the year ended December 31, 2014 compared to 8.0 million tons for the year ended December 31, 2013. All other tons were sold on the domestic market.
Changes in the average cost of goods sold per ton were primarily attributable to the increase in tons sold. Total cost per ton sold was also impacted
by the decrease in operating shifts and other cost control measures implemented at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014. The decrease in total costs per ton sold was offset, in part, by geological conditions at Enlow Fork Mine and Harvey Mine.
The Other division includes industrial supplies activity (sold in December 2014), income taxes and other business activities not assigned to the E&P or Coal division.
53
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 Years Ended December 31,
(in millions)
2014
2013
Variance
Percent
Change
Continuing
Operations General and Administrative Expenses
$
110
$
80
$
30
37.5
%
Discontinued
Operations General and Administrative Expenses
—
39
(39
)
(100.0
)%
Total Company General and Administrative Expense
$
110
$
119
$
(9
)
(7.6
)%
Overall,
total Company General and Administrative Expenses decreased $9 million in the period-to-period comparison. This was primarily due to reduced staffing and cost control measures following the December 2013 sale of five of our West Virginia coal mines. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
Total Company long-term liabilities, 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 expense for continuing operations related
to our actuarially calculated liabilities was $132 million for the year ended December 31, 2014 compared to $152 million for the year ended December 31, 2013. The decrease 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, along with a decrease in pension settlement expense. Pension settlement expense is required when lump sum distributions for a plan year exceed the total of the service and interest cost for the plan year. Pension settlement expense was $29 million for the year ended December 31, 2014, compared to $39 million for the year ended December 31,
2013. Additionally, a part of the decrease was due to modifications made to the OPEB and Pension plans, which required remeasurement at September 30, 2014. 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 the modifications to the OPEB and Pension plans during the year ended December 31, 2014. The pension settlement expense, curtailment gains, and cash payment expenses 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 16—Pension and Other Postretirement Benefit Plans and Note 17—Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Consolidated Financial Statements
in Item 8 of this Form 10-K for additional details related to the total Company expense decrease.
The E&P division contributed $190 million to earnings before income tax for the year ended December 31,
2014 compared to a loss before income tax of $2 million for the year ended December 31, 2013. Variances by individual E&P segment are discussed below.
Earnings
Before Noncontrolling Interest and Income Tax
$
152
$
41
$
92
$
(95
)
$
190
$
72
$
45
$
11
$
64
$
192
55
MARCELLUS
GAS SEGMENT
The Marcellus segment contributed $152 million to the total Company earnings before income tax for the year ended December 31, 2014 compared to $80 million for the year ended December 31, 2013.
Average
Marcellus ad valorem, severance, and other taxes (per Mcfe)
$
0.16
$
0.16
$
—
—
%
Average
Marcellus gathering costs (per Mcfe)
$
0.98
$
0.86
$
0.12
14.0
%
Average
Marcellus direct administrative and selling (per Mcfe)
$
0.32
$
0.45
$
(0.13
)
(28.9
)%
Average
Marcellus depreciation, depletion and amortization costs (per Mcfe)
$
1.18
$
1.16
$
0.02
1.7
%
Total
Average Marcellus costs (per Mcfe)
$
2.88
$
2.98
$
(0.10
)
(3.4
)%
Average
Margin for Marcellus (per Mcfe)
$
1.36
$
1.37
$
(0.01
)
(0.7
)%
*
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 oil, NGLs, condensate, and natural gas prices.
The Marcellus segment outside sales revenues were $473 million for the year ended December 31, 2014 compared to $252 million for the year ended December 31, 2013. The $221 million increase is primarily due to a 93.3% increase in total volumes sold offset, in part,
by a 2.5% decrease in total average sales prices in the period-to-period comparison. The 53.9 Bcfe increase in sales volumes was primarily due to additional wells coming on-line from our ongoing drilling program. The $0.11 per Mcfe decrease in Marcellus total average sales price was primarily the result of the $0.17 per Mcf decrease resulting from various transactions relating to our hedging program offset, in part, by a $0.06 per Mcf increase in gas market prices. These financial hedges represented approximately 70.4 Bcf of our produced Marcellus gas sales volumes for the year ended December 31, 2014
at an average gain of $0.21 per Mcf. For the year ended December 31, 2013, these financial hedges represented approximately 21.6 Bcf at an average gain of $0.81 per Mcf.
Total costs for the Marcellus segment were $321 million for the year ended December 31, 2014 compared to $172 million for the year ended December 31, 2013. The increase in total dollars and decrease
in unit costs for the Marcellus segment were due to the following items:
•Marcellus lifting costs were $26 million for the year ended December 31, 2014 compared to $20 million for the year ended December 31, 2013. The increase in total dollars primarily relates to an increase in sales volumes, along with an increase in well tending costs, repair and maintenance costs, and costs related to wells operated by our joint-venture partners. The increase in total dollars was 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 $17 million for the year ended December 31, 2014 compared to $9 million for the year ended December 31, 2013. The increase in total dollars was primarily due to an increase in severance tax expense caused by the 93.3% increase in gas and liquid sales volumes, changes in the mix of volumes produced by state as well as a 1.6% increase in average gas sales price, without the impact of hedging.
56
•Marcellus
gathering costs were $110 million for the year ended December 31, 2014 compared to $50 million for the year ended December 31, 2013. Total dollars increased primarily due to the 93.3% 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 $36 million for the year ended December 31, 2014 compared to $26 million for the year ended December 31, 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 $132 million for the year ended December 31, 2014 compared to $67 million for the year ended December 31, 2013. There was approximately $129 million, or $1.16 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 year ended December 31, 2014. There was approximately $66 million, or $1.14
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 year ended December 31, 2013. There was approximately $3 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 year ended December 31, 2014. 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 for the year ended December 31, 2013.
57
UTICA GAS SEGMENT
The Utica segment contributed $41 million to the total Company earnings before income tax for the year ended December 31, 2014 compared to a loss before income tax of $4
million for the year ended December 31, 2013.
Average
Utica ad valorem, severance, and other taxes (per Mcfe)
$
0.08
$
(0.67
)
$
0.75
111.9
%
Average
Utica gathering costs (per Mcfe)
$
0.45
$
0.53
$
(0.08
)
(15.1
)%
Average
Utica direct administrative and selling (per Mcfe)
$
0.24
$
2.79
$
(2.55
)
(91.4
)%
Average
Utica depreciation, depletion and amortization costs (per Mcfe)
$
1.11
$
4.96
$
(3.85
)
(77.6
)%
Total
Average Utica costs (per Mcfe)
$
2.82
$
11.08
$
(8.26
)
(74.5
)%
Average
Margin for Utica (per Mcfe)
$
2.45
$
(5.28
)
$
7.73
146.4
%
*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 oil, NGLs, condensate, and natural gas prices.
Utica sales revenues were $88 million for the year ended December 31, 2014 compared to $4 million for the year ended December 31, 2013. The $84 million increase was primarily due to the 2,285.7% increase in total volumes sold, partially offset by a 9.1%
decrease in total average sales price in the period-to-period comparison. The 16.0 Bcfe increase in sales volumes was primarily due to additional wells coming on-line from our ongoing drilling program. The decrease in Utica total average sales price was primarily the result of the $0.37 per Mcf decrease in gas market prices, along with a $0.28 per Mcfe decrease in the uplift related to NGLs and condensate.
During the fourth quarter of the 2014 period, a midstream company that handles and processes some of CONSOL Energy’s gas and liquids had a fatality on one of their sites, during their operations. Over the course of the quarter CONSOL Energy elected to shut-in pads serviced by this midstream provider while safety processes and procedures were evaluated and validated. As a result of this
process, it is estimated that the shut-in pads accounted for 2.7 Bcfe worth of lost production in the year ended December 31, 2014.
Total costs for the Utica segment were $47 million for the year ended December 31, 2014 compared to $8 million for the year ended December 31, 2013. The increase in total dollars and improvement in unit costs were all directly related to the 2,285.7% increase in total volumes sold, thus a per unit analysis of the Utica segment is not meaningful.
58
COALBED
METHANE (CBM) GAS SEGMENT
The CBM segment contributed $92 million to the total Company earnings before income tax for the year ended December 31, 2014 compared to $81 million for the year ended December 31, 2013.
Average
CBM ad valorem, severance, and other taxes (per Mcf)
$
0.15
$
0.10
$
0.05
50.0
%
Average
CBM gathering costs (per Mcf)
$
1.35
$
1.37
$
(0.02
)
(1.5
)%
Average
CBM direct administrative and selling (per Mcf)
$
0.13
$
0.10
$
0.03
30.0
%
Average
CBM depreciation, depletion and amortization costs (per Mcf)
$
1.12
$
1.10
$
0.02
1.8
%
Total
Average CBM costs (per Mcf)
$
3.22
$
3.11
$
0.11
3.5
%
Average
Margin for CBM (per Mcf)
$
1.15
$
0.98
$
0.17
17.3
%
CBM
sales revenues were $347 million for the year ended December 31, 2014 compared to $339 million for the year ended December 31, 2013. The $8 million increase was primarily due to a 6.8% increase in total average sales price offset, in part, by a 4.1% decrease in total volumes sold. CBM sales volumes decreased 3.4 Bcf for the year ended December 31, 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 and Utica production. The decline in wells drilled was 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 $0.28 per Mcf due to a $0.63 per Mcf increase in market prices. The increase was offset, in part, by a $0.35 per Mcf decrease resulting from various transactions relating to our hedging program. Financial hedges represented approximately 70.0 Bcf of our produced CBM gas sales volumes for the year ended December 31,
2014 at an average gain of $0.06 per Mcf. For the year ended December 31, 2013, these financial hedges represented approximately 48.3 Bcf at an average gain of $0.69 per Mcf.
Total costs for the CBM segment were $255 million for the year ended December 31, 2014 compared to $258 million for the year ended December 31, 2013. The decrease in
total dollars and increase in unit costs for the CBM segment were due to the following items:
•CBM lifting costs were $37 million for the year ended December 31, 2014 and December 31, 2013. The increase in unit costs was primarily due to the decrease in gas sales volumes.
•CBM ad valorem, severance and other taxes were $12 million for the year ended December 31, 2014
compared to $9 million for the year ended December 31, 2013. The increase of $3 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 $108 million for the year ended December 31, 2014 compared to $114 million for the year ended December 31,
2013. The decrease in total dollars and average per unit costs was 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 $10 million for the year ended December 31, 2014 compared to $8 million for the year ended December 31, 2013. Direct administrative, selling and other costs attributable to the total E&P
59
division
are allocated to the individual E&P segments based on a combination of capital and production. The $2 million increase in the period-to-period comparison was due a larger portion of total direct administrative costs being allocated to the E&P segment over the Coal and Other segments. The $0.03 per Mcf increase in unit costs can be attributed to both an increase in total dollars allocated to the segment and a decline in gas sales volumes.
•Depreciation, depletion and amortization costs attributable to the CBM segment were $88 million for the year ended December 31, 2014 and $90
million for the year ended December 31, 2013. There was approximately $59 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 year ended December 31, 2014. The production portion of depreciation, depletion and amortization was $62 million, or $0.77 per unit-of-production in the year ended December 31, 2013. There was approximately $29
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 year ended December 31, 2014. The non-production related depreciation, depletion and amortization was $28 million, or $0.33 per Mcf for the year ended December 31, 2013.
OTHER GAS SEGMENT
The other gas segment had a loss before income taxes of $95 million
for the year ended December 31, 2014 compared to a loss before income tax of $159 million for the year ended December 31, 2013.
Average
Other ad valorem, severance, and other taxes (per Mcfe)
$
0.28
$
0.36
$
(0.08
)
(22.2
)%
Average
Other gathering costs (per Mcfe)
$
1.21
$
1.19
$
0.02
1.7
%
Average
Other direct administrative and selling (per Mcfe)
$
0.19
$
0.41
$
(0.22
)
(53.7
)%
Average
Other depreciation, depletion and amortization costs (per Mcfe)
$
2.60
$
2.22
$
0.38
17.1
%
Total
Average Other costs (per Mcfe)
$
5.67
$
5.39
$
0.28
5.2
%
Average
Margin for Other (per Mcfe)
$
(1.28
)
$
(0.67
)
$
(0.61
)
(91.0
)%
*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.
The other gas segment includes activity not assigned to the Marcellus, Utica, or CBM 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 division.
Other gas sales volumes are primarily related to shallow oil and gas production as well as Upper Devonian Shale in Pennsylvania and West Virginia. Outside sales revenue from the other gas segment was approximately $123 million for the year ended December 31,
2014 compared to $146 million for the year ended December 31, 2013. Total costs related to these other sales were $162 million for the year ended December 31, 2014 compared to $170 million for the year ended December 31, 2013. The decrease in total volumes sold was primarily due to normal well declines which also had a negative impact on unit costs.
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 $82 million for the year ended December 31, 2014 compared to $63 million for the year ended December 31, 2013. The increase in sales volumes, changes in
60
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.
Gas Royalty Interest Sales Volumes (in billion cubic feet)
19.9
15.3
4.6
30.1
%
Average
Sales Price per thousand cubic feet
$
4.14
$
4.13
$
0.01
0.2
%
Purchased
gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $9 million for the year ended December 31, 2014 compared to $7 million for the year ended December 31, 2013.
Purchased Gas Sales Volumes (in billion cubic feet)
1.9
1.6
0.3
18.8
%
Average
Sales Price per thousand cubic feet
$
4.65
$
4.12
$
0.53
12.9
%
Other
income was $113 million for the year ended December 31, 2014 compared to $58 million for the year ended December 31, 2013. The $55 million increase was primarily due to the following items:
Gain
on sale of assets increased $25 million primarily due to the sale of Utica rights in Marshall County, WV to Noble Energy, which closed in December 2014 and resulted in proceeds and a pre-tax gain of $25 million.
•
Gathering revenue increased $23 million primarily due to an increase in revenue related to certain gathering arrangements.
•
Earnings from our equity affiliates increased $17
million primarily due to an increase in earnings from CONE Midstream Partners, LP. See Note 27 - Related Party Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
•
Interest income decreased $13 million primarily due to the 2013 collection of the final installment on the notes receivable from the 2011 Noble Energy joint venture transaction.
•
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 division based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $64 million for the year ended December 31, 2014 compared to $39 million for the year ended December 31, 2013. Refer to discussion of total Company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this annual 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 division. Royalty interest gas costs were $70 million for the year ended December 31, 2014 compared to $53 million for the year ended December 31, 2013. The increase in sales volumes, changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the
Gas
Royalty Interest Sales Volumes (in billion cubic feet)
19.9
15.3
4.6
30.1
%
Average Cost per thousand cubic feet sold
$
3.51
$
3.47
$
0.04
1.2
%
Purchased
gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes also reflect the impact of pipeline imbalances. The higher average cost per thousand cubic feet was due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $7 million for the year ended December 31, 2014 compared to $5 million for the year ended December 31, 2013.
Exploration
and other costs were $23 million for the year ended December 31, 2014 compared to $61 million for the year ended December 31, 2013. The $38 million decrease in costs is primarily related to the following items:
Total
Exploration and Production Related Other Costs
$
23
$
61
$
(38
)
(62.3
)%
•
CONSOL
Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $23 million for the year ended December 31, 2013.
•
Dry hole costs decreased $7 million due to various transaction 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. 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 increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
•
Other expenses decreased $8 million due to various transactions that occurred throughout both periods, none of which were individually material.
Other corporate expenses related to the E&P division were $87 million for the year ended December 31, 2014 compared to $96
million for the year ended December 31, 2013. The $9 million decrease in the period-to-period comparison was made up of the following items:
Unutilized
Firm Transportation and Processing Fees
38
36
2
5.6
%
Short-term Incentive Compensation
23
20
3
15.0
%
Other
10
6
4
66.7
%
Total
Other Corporate Expenses
$
87
$
96
$
(9
)
(9.4
)%
•
Litigation
settlements decreased $8 million due to various transactions that occurred throughout both periods, none of which were individually material.
•
Stock-based compensation decreased $7 million in the period-to-period comparison primarily due to a reduction in non-cash amortization expense and less accelerated expense for retiree eligible employees under our current plans.
•
Bank fees decreased $3
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 $2 million increase was primarily due to increased 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 increased $3 million in the period-to-period comparison due to higher projected payouts.
•
Other corporate related expenses increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.
Interest expense remained consistent at $9
million for the year ended December 31, 2014 and December 31, 2013. Interest was incurred by the other gas segment on the CNX Gas revolving credit facility along with interest allocated to the E&P segment under CONSOL Energy's credit facility, a capital lease and debt held by a variable interest entity.
The coal division contributed $411 million of earnings before income tax in the year ended December 31, 2014 compared to $348 million in the year ended December 31, 2013. Variances by individual coal segment are discussed below.
The PA Operations coal segment principal activities are mining, preparation and marketing of thermal coal to power generators. The segment also includes general and administrative activities as well as various other activities assigned to the PA Operations coal segment but not allocated to each individual mine and are therefore not included in unit cost presentation. For the years ended December 31, 2014 and 2013 the segment included the following mines: Bailey Mine, Enlow Fork Mine, Harvey Mine and the corresponding preparation plant facilities.
The PA Operations coal segment contributed $427 million to total Company earnings before income tax for the year ended
December 31, 2014 compared to $310 million for the year ended December 31, 2013. PA Operations coal revenue and cost components on a per unit basis for these periods were as follows:
Company Produced PA Operations Tons Sold (in millions)
26.1
21.2
4.9
23.1
%
Average
Sales Price Per PA Operations Ton Sold
$
61.88
$
63.93
$
(2.05
)
(3.2
%)
Total
Operating Costs Per Ton Sold
$
33.70
$
36.13
$
(2.43
)
(6.7
%)
Total
Direct Administration and Selling Costs Per Ton Sold
1.20
1.26
(0.06
)
(4.8
%)
Total Royalty/Production Taxes Per Ton Sold
2.72
2.58
0.14
5.4
%
Total
Depreciation, Depletion and Amortization Costs Per Ton Sold
6.13
5.58
0.55
9.9
%
Total Costs Per PA Operations Ton Sold
$
43.75
$
45.55
$
(1.80
)
(4.0
%)
Average
Margin Per PA Operations Ton Sold
$
18.13
$
18.38
$
(0.25
)
(1.4
%)
PA
Operations outside sales revenue was $1,617 million for the year ended December 31, 2014 compared to $1,357 million for the year ended December 31, 2013. The $260 million increase was attributable to 4.9 million additional tons sold in the 2014 period partially offset by a $2.05 per ton lower average sales price. The lower average PA Operations coal sales price in the 2014 period was the result of the roll-off of some higher-priced legacy sales contracts. The PA
Operations coal segment revenue was also impacted by 3.3 million tons of PA Operations coal being priced on the export market for the year ended December 31, 2014, which was 0.8 million tons lower than the tons sold in the year ended December 31, 2013.
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) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue was $17 million for the year
ended December 31, 2014 compared to $18 million for the year ended December 31, 2013. The $1 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides transportation services.
Miscellaneous other income was $38 million for the year ended December 31, 2014 compared to $6 million for the year ended December 31,
2013. The $32 million increase was due to the following items:
For
the year ended December 31, 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. No such transactions were entered into in the year ended December 31, 2013.
•
Rental/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 Mine Belt Conveyor accident.
65
•
Other
income increased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.
Gain on sale of assets increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
Total operating costs and expenses is comprised of changes in PA Operations coal inventory, both volumes and carrying values, and costs of tons sold in the period. The costs per ton sold include items such as direct operating costs, royalty and production taxes, direct administration and selling, and depreciation, depletion, and amortization costs. Total operating costs and expenses for PA Operations were $1,143 million for the year ended
December 31, 2014, or $176 million higher than the $967 million for the year ended December 31, 2013. Total costs per PA Operations ton sold was $43.75 per ton in the year ended December 31, 2014 compared to $45.55 per ton in the year ended December 31, 2013. The increase in total dollars and decrease in unit costs was primarily due to the 23.1% increase in PA Operations
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 and Enlow Fork Mine related to additional longwall overhauls and twenty-two thousand additional continuous miner feet mined at Bailey and Enlow Fork Mines. 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 adverse geological conditions at Enlow Fork Mine along with adverse geological conditions and equipment issues at the Harvey Mine.
Other Costs And Expenses
Other costs is comprised of various costs and expenses that are assigned to the PA Operations coal segment but not allocated to each individual mine and therefore not included in unit costs. Other costs were $18
million for the year ended December 31, 2014 compared to $23 million for the year ended December 31, 2013. The change is due to the following items:
Supplies
expense decreased $6 million primarily due to the prior year-to-date period including additional supplies needed for repairs related to the 2012 Bailey Mine Belt Conveyor accident which was not included in active mining costs.
•
Property and other taxes remained consistent in the period-to-period comparison.
•
Other expense increased $1 million due to various items that occurred throughout both periods, none of which were individually
material.
Direct Administrative expense is primarily made up of labor and benefits and consulting expenses that were allocated to the Harvey Mine while it was in development phase prior to March 2014. The amount of direct administrative expense allocated to the PA Operations coal segment remained consistent in the period-to-period comparison.
Depreciation, depletion, and amortization increased $1 million primarily due to additional assets placed in service in the period-to-period comparison.
General and Administrative costs are allocated to each coal segment based upon the activity at the segment determined by their level of operating
activity. The amount of General and Administrative costs allocated to PA Operations was $26 million for the year ended December 31, 2014 compared to $23 million for the year ended December 31, 2013. Refer to the discussion of total company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation.
Other corporate expense is made up of expenses for stock based compensation and the short-term incentive compensation program. These expenses
are made up of costs that are directly related to each coal segment along with a portion of costs that are allocated to each segment based on a percent of total labor dollars. For the year ended December 31, 2014 other corporate expenses were $39 million compared to $38 million for the year ended December 31, 2013. The increase of $1 million was primarily due to PA Operations representing a larger portion of total coal labor dollars.
66
Freight
expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail) 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 $1 million decrease in freight expense was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.
VIRGINIA (VA) OPERATIONS COAL SEGMENT
The VA Operations coal segment principal activities are mining, preparation and marketing of low metallurgical
coal to metal and coke producers. The segment also includes general and administrative activities as well as various other activities assigned to the VA Operations coal segment but not allocated to each individual mine and are therefore not included in unit cost presentation. For the years ended December 31, 2014 and 2013 the segment included the following mines: Buchanan Mine, Amonate Complex and the corresponding preparation plant facilities. Operations at Amonate Complex were idled in September 2012, but the complex continued to sell coal inventory in 2013.
The VA Operations coal segment contributed $14 million to total Company earnings before income tax for the year ended December 31,
2014 compared to $93 million for the year ended December 31, 2013. The VA Operations coal revenue and cost components on a per unit basis for these periods were as follows:
Company
Produced VA Operations Tons Sold (in millions)
4.1
4.9
(0.8
)
(16.3
%)
Average Sales Price Per VA Operations Ton Sold
$
71.80
$
92.43
$
(20.63
)
(22.3
%)
Total
Operating Costs Per Ton Sold
$
45.29
$
51.54
$
(6.25
)
(12.1
%)
Total
Direct Administrative and Selling Costs Per Ton Sold
1.42
1.24
0.18
14.5
%
Total Royalty/Production Taxes Per Ton Sold
4.33
5.50
(1.17
)
(21.3
%)
Total
Depreciation, Depletion and Amortization Costs Per Ton Sold
9.63
8.71
0.92
10.6
%
Total Costs Per VA Operations Ton Sold
$
60.67
$
66.99
$
(6.32
)
(9.4
%)
Average
Margin Per VA Operations Ton Sold
$
11.13
$
25.44
$
(14.31
)
(56.3
%)
VA
Operations coal outside sales revenue was $297 million for the year ended December 31, 2014 compared to $450 million for the year ended December 31, 2013. The $153 million decrease was attributable to a $20.63 per ton lower average sales price and a 0.8 million decrease in tons sold. Average sales prices for VA Operations coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market. The VA Operations coal segment revenue was also impacted by 3.1 million tons of VA Operations coal being priced on the export
market for the year ended December 31, 2014, which was 0.7 million tons lower than the tons sold in the year ended December 31, 2013.
Freight revenue was $1 million for the year ended December 31, 2014 compared to $4 million for the year ended December 31, 2013. The $3 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides transportation services.
Miscellaneous
other income decreased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.
Gain on sale of assets decreased $5 million in the period-to-period comparison primarily due to various asset sales in the year ended December 31, 2013. No such transactions occurred in the year ended December 31, 2014.
Total operating costs and expenses for VA Operations were $251 million for the year ended December 31,
2014, or $75 million lower than the $326 million for the year ended December 31, 2013. Total costs per VA Operations ton sold were $60.67 per ton in the year ended December 31, 2014 compared to $66.99 per ton in the year ended December 31, 2013. The decrease in total dollars and unit costs per VA Operations 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. 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.
67
Other Costs And Expenses
Total other costs for VA Operations were $6 million for the year ended December 31, 2014 compared to $8
million for the year ended December 31, 2013. The $2 million decrease was due to the following items:
Idle
mine costs are costs related to the temporary idling of the Amonate Complex which remained consistent year over year.
•
Other expense decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
Depreciation, depletion, and amortization decreased $5 million primarily due to a decrease in assets placed in service in the period-to-period comparison.
General and Administrative costs allocated
to the VA Operations coal segment were $9 million for the year ended December 31, 2014 and December 31, 2013. Refer to the discussion of total company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation.
For the year ended December 31, 2014 other corporate expenses were $9 million compared to $11
million for the year ended December 31, 2013. The decrease of $2 was primarily related to VA Operations representing a smaller portion of total coal labor dollars which is the basis of the allocation.
Freight expense decreased $3 million in the period-to-period comparison due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.
68
OTHER
COAL SEGMENT
The Other coal segment primarily includes coal terminal operations, idle mine activities and purchased coal activities as well as various other activities not assigned to either PA Operations or VA Operations. The Other coal segment also includes activities related to mining, preparation and marketing of thermal coal to power generators geographically separated from PA Operations. For the year ended December 31, 2014 and 2013 the segment included the Miller Creek Complex.
The Other coal segment had a loss of $30 million before income tax for the year ended December 31,
2014 compared to a loss of $55 million for the year ended December 31, 2013. Other coal revenue and cost components on a per unit basis for these periods were as follows:
Company
Produced Other Operations Tons Sold (in millions)
2.2
2.7
(0.5
)
(18.5
%)
Average Sales Price Per Other Operations Ton Sold
$
60.12
$
70.22
$
(10.10
)
(14.4
%)
Total
Operating Costs Per Ton Sold
$
49.54
$
47.95
$
1.59
3.3
%
Total
Direct Administration and Selling Costs Per Ton Sold
1.14
1.03
0.11
10.7
%
Total Royalty/Production Taxes Per Ton Sold
4.82
7.80
(2.98
)
(38.2
%)
Total
Depreciation, Depletion and Amortization Costs Per Ton Sold
3.33
5.98
(2.65
)
(44.3
%)
Total Costs Per Other Operations Ton Sold
$
58.83
$
62.76
$
(3.93
)
(6.3
%)
Average
Margin Per Other Operations Ton Sold
$
1.29
$
7.46
$
(6.17
)
(82.7
%)
Other
coal outside sales revenue was $129 million for the year ended December 31, 2014 compared to $188 million for the year ended December 31, 2013. The $59 million decrease was attributable to a 0.5 million decrease in tons sold in 2014 and a $10.10 per ton lower average sales price. The lower average coal sales price in the 2014 period was the result of the roll-off of some higher-priced legacy sales contracts.
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 $9 million for the year ended December 31, 2014 compared to $23 million for the year ended December 31, 2013. The $14 million decrease in the period-to-period comparison was due to lower volumes of coal that needed to be purchased to fulfill various contracts.
Other
outside sales revenue for the Other coal segment consist of revenues from our coal terminal operations. Coal terminal operations sales revenues decreased $2 million in the period-to-period comparison primarily due to a decrease in thru-put volumes in the current year.
Freight revenue was $10 million for the year ended December 31, 2014 compared to $13 million for the year ended December 31, 2013. The $3 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides
transportation services.
Miscellaneous other income was $101 million for the year ended December 31, 2014 compared to $50 million for the year ended December 31, 2013. The $51 million increase was due to the following items:
Rental
income increased $41 million primarily due to equipment subleased to a third-party. These arrangements began in December 2013.
•
Land rental income primarily consists of income related to the sale of right of ways on property that CONSOL Energy owns. The $4 million increase was due to an increase in land activity in the period-to-period comparison.
•
Royalty income increased $3 million
due to various transactions that occurred throughout both periods, none of which were individually material.
•
Equity in earnings of affiliates increased $1 million due to various transactions completed by our equity partners, none of which were individually material.
•
Other increased $2 million due to various activities that occurred in the current period, none of which were individually material.
Gain
on sale of assets was $28 million for the year ended December 31, 2014 compared to $41 million for the year ended December 31, 2013. The decrease of $13 million was primarily due to various asset sales that occurred in both periods. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Other Costs And Expenses
Other coal segment other costs were $151 million
for the year ended December 31, 2014 compared to $164 million for the year ended December 31, 2013. The decrease of $13 million was due to the following items:
Purchased
coal costs decreased $29 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.
•
Closed and idle mine costs decreased approximately $12 million for the year ended December 31, 2014 compared to the year ended December 31, 2013. This was due to a $14 million decrease in the asset retirement obligation, primarily at the Fola Mining Complex.
The decrease was offset, in part, by a $2 million increase in various changes in the operational status of other mines, between idled and operating throughout both periods, none of which were individually material.
•
Coal terminal operations costs decreased $6 million due to decreased thru-put volumes in the current year.
•
Coal reserve holding costs which primarily consists of property and other taxes, remained consistent in the period-to-period comparison.
•
Lease
rental expense increased $30 million primarily due to equipment leases that were subleased to a third-party. The third-party subleases began in December 2013.
•
Other expenses related to the Other Coal segment increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.
Direct Administrative expense is primarily made up of labor and benefits and consulting expenses that relate to coal terminal operations and idle mine locations. Direct Administrative expense decreased $10
million in the period-to-period comparison due to less resources being allocated to idle mine locations in the current period.
Royalty and production taxes decreased $1 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.
Depreciation, depletion, and amortization increased $1 million primarily due to additional assets placed in service in the period-to-period comparison.
70
General
and Administrative costs allocated to the Other coal segment were $10 million for the year ended December 31, 2014 compared to $8 million for the year ended December 31, 2013. Refer to the discussion of total company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation.
Freight expense decreased $3 million in the period-to-period comparison due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.
The other division includes activity from the sales of industrial supplies and various other corporate activities that are not allocated to the E&P or coal divisions. The other segment had a loss before income tax of $414 million for the year ended December 31, 2014 compared to a loss before income tax of $297 million for the year ended December 31, 2013. The other division also includes total company income tax expense of $14 million for the year
ended December 31, 2014 compared to an income tax benefit of $33 million for the year ended December 31, 2013.
Outside
sales revenue from the other division was $235 million for the year ended December 31, 2014 compared to $217 million for the year ended December 31, 2013. The increase was related to higher sales volumes from our industrial supplies subsidiary which was sold in December 2014. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
Other income of $2 million was recognized for the year ended December 31, 2014
compared to $15 million for the year ended December 31, 2013. The $13 million decrease was primarily due to the following items:
Pennsylvania
Turnpike Settlement relates to mediation with the PA Turnpike Commission that was settled for $9 million in 2013.
•
Interest Income decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
71
•
Equity
in Earnings of Affiliates decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
•
Other remained consistent in the period to period comparison.
Total costs in the other segment include interest expense, transaction and financing fees and various other miscellaneous corporate charges. Total other costs were $620 million for the year ended December 31, 2014 compared to $529
million for the year ended December 31, 2013. Other corporate costs increased due to the following items:
Loss
on Debt Extinguishment of $95 million was recognized in the year ended December 31, 2014 related to the early extinguishment of debt due to the purchase of all of 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.
•
Industrial supplies costs represent costs from our industrial supplies subsidiary which was sold in December 2014. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional
details. The $16 million increase in costs was due to higher sales volumes in the current period along with various changes in inventory costs, none of which were individually material.
•
Long-Term Liability Plan Changes include $36 million of income as a result of amendments to the pension and OPEB plans, which were adopted during the third quarter of 2014, offset by $46 million of expense for cash payments made to active employees related to changes in the OPEB plan. See Note 16—Pension and Other Postretirement Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to the total Company expense.
•
Interest
Expense increased $4 million in the period-to-period comparison 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 7 - Income Taxes of the Notes to the Audited Consolidated Financial Statements of this Form 10-K), the early payoff of the 2017 bonds and partial purchase of the 2020 bonds. The decrease 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. The $5 million decrease was due to various transactions that occurred in both periods, none of which were individually material. See Note 11 - Property, Plant, and Equipment and Note 24 - Commitments and Contingencies of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
•
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 16 - Pension and Other Post-Employment Benefit Plans in the Notes to the Audited
Consolidated Financial Statements of this Form 10-K for additional detail.
72
•
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.
•
Various other corporate expenses decreased $3 million due to various transactions that occurred throughout both periods, none of which were individually material.
Income Taxes:
The effective income tax rate from continuing operations was 7.8% for the year ended December 31, 2014 compared to (72.0)% for the year ended
December 31, 2013. The effective rates for the years ended December 31, 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 year ended December 31, 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 $10 million related to increased percentage 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 and 2009 U.S. income tax returns during the year ended December 31, 2014. The result of these findings was a change in timing of certain tax deductions which increased the tax benefit of percentage depletion by $7 million. See Note 7-Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Net Income Attributable to CONSOL Energy Shareholders
CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $660 million, or $2.87 per diluted share, for the year ended December 31, 2013. Net income attributable to CONSOL Energy shareholders was $388 million,
or $1.70 per diluted share, for the year ended December 31, 2012. The breakdown of net income attributable to CONSOL Energy shareholders is as follows:
For the Years Ended December 31,
(Dollars in millions, except per share data)
2013
2012
Variance
Income
from Continuing Operations
$
79
$
318
$
(239
)
Income from Discontinued Operations, net
580
70
510
Net
Income
659
388
271
Less: Net Loss Attributable to Noncontrolling Interests
(1
)
—
(1
)
Net
Income Attributable to CONSOL Energy Shareholders
$
660
$
388
$
272
Income
from Continuing Operations
$
0.35
$
1.39
$
(1.04
)
Income from Discontinued Operations
2.52
0.31
2.21
Total
Dilutive Earnings Per Share
$
2.87
$
1.70
$
1.17
The total Exploration and Production (E&P) division includes Marcellus, Utica, coalbed
methane (CBM), and other gas. The total E&P division contributed a loss of $2 million before income tax for the year ended December 31, 2013 compared to $39 million of earnings before income tax for the year ended December 31, 2012. Total gas production was 172.4 Bcfe for the year ended December 31, 2013 compared to 156.3 Bcfe for the year ended December 31, 2012.
The
following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s production and sales portfolio:
For the Years Ended December 31,
in
thousands (unless noted)
2013
2012
Variance
Change
LIQUIDS
NGLs:
Sales
Volume (MMcfe)
2,628
610
2,018
330.8
%
Sales Volume (Mbbls)
438
102
336
329.4
%
Gross
Price ($/Bbl)
$
53.76
$
52.32
$
1.44
2.8
%
Gross
Revenue
$
23,541
$
5,314
$
18,227
343.0
%
Oil:
Sales
Volume (MMcfe)
634
600
34
5.7
%
Sales Volume (Mbbls)
106
100
6
6.0
%
Gross
Price ($/Bbl)
$
89.58
$
92.58
$
(3.00
)
(3.2
)%
Gross
Revenue
$
9,471
$
9,252
$
219
2.4
%
Condensate:
Sales
Volume (MMcfe)
382
63
319
506.3
%
Sales Volume (Mbbls)
64
11
53
481.8
%
Gross
Price ($/Bbl)
$
81.06
$
78.84
$
2.22
2.8
%
Gross
Revenue
$
5,156
$
823
$
4,333
526.5
%
GAS
Sales
Volume (MMcf)
168,737
155,052
13,685
8.8
%
Sales Price ($/Mcf)
$
3.72
$
2.94
$
0.78
26.5
%
Hedging
Impact ($/Mcf)
$
0.45
$
1.22
$
(0.77
)
(63.1
)%
Gross
Revenue
$
702,700
$
645,053
$
57,647
8.9
%
74
The
average sales price and average costs for all active gas operations were as follows:
Total
E&P division outside sales revenues were $741 million for the year ended December 31, 2013 compared to $659 million for the year ended December 31, 2012. The increase was primarily due to the 10.3% increase in total volumes sold, along with a 1.9% increase in average price per Mcfe. The increase in average sales price was the result of an increase in general market prices and the increase in sales of natural gas liquids and condensate. The increase was offset, in part, by various gas swap transactions that
occurred throughout both periods. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 84.3 Bcf of our produced gas sales volumes for the year ended December 31, 2013 at an average gain of $0.89 per Mcf. These financial hedges represented approximately 76.9 Bcf of our produced gas sales volumes for the year ended December 31, 2012 at an average gain of $2.47 per Mcf.
Changes in the average cost per Mcfe of gas sold were primarily related to the following items:
•
Gathering
costs increased in the period-to-period comparison due to a $0.04 per Mcfe increase in processing fees associated with natural gas liquids and a $0.10 per Mcfe increase in firm transportation costs.
•
Depreciation, depletion and amortization rates increased due to higher units-of-production for producing properties in the period to period comparison offset, in part, by additional volumes.
•
These increases were offset, in part, by higher volumes in the period-to-period comparison due to the on-going Marcellus drilling
program. Fixed costs are allocated over increased volumes, resulting in lower unit costs.
The coal division includes Pennsylvania (PA) operations, Virginia (VA) operations and other coal. The total coal division contributed $348 million of earnings before income tax for the year ended December 31, 2013 compared to $610 million for the year ended December 31, 2012. The total coal division sold 28.8 million tons of coal produced from CONSOL Energy mines, for the year ended December 31,
2013 compared to 27.6 million tons for the year ended December 31, 2012.
The average sales price and average cost of goods sold per ton for continuing coal operations were as follows:
The
lower average sales price per ton sold reflects a decrease in the global metallurgical coal markets. The coal division priced 8.0 million tons on the export market for the year ended December 31, 2013 compared to 7.5 million tons at an average for the year ended December 31, 2012. All other tons were sold on the domestic market.
Changes in the average cost of goods sold per ton were primarily related to the following items:
•
Average
cost of goods sold decreased due to an increase in tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.
•
On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The incident caused a total of four longwalls to be idled for approximately three weeks, and production to be at approximately 60% for the third quarter of 2012. The mines operated at full capacity for the entire 2013 period, which resulted in lower direct operating costs per ton produced.
•
The
Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-period comparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall average direct operating costs per ton produced.
75
•
Direct services to operations are improved primarily due to a reduction in subsidence expenses related to the timing and nature of properties and streams undermined as well as a reduction in direct administration employees as a result of the
2012 Voluntary Severance Incentive Plan discussed below under general and administrative costs.
•
Depreciation, depletion and amortization was improved primarily due to the idling of operations at the Fola Mining Complex in August 2012. The improvements were offset, in part, by higher costs in the 2013 period related to Bailey, Enlow Fork, and Buchanan Mines running for the full year in 2013 compared to being idled at various times throughout 2012.
•
Average direct operating costs were impaired due to CONSOL Energy entering
into a new longwall lease in 2013 at our Bailey Mine.
•
Costs were impaired in the current period due to the idling of the Buchanan Mine for various months throughout 2012. Although idled at times during 2012, the Buchanan Mine ran the continuous miners and worked on various projects which increased overall 2012 unit costs.
The other division includes industrial supplies 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:
Continuing
Operations General and Administrative Expenses
$
80
$
77
$
3
3.9
%
Discontinued
Operations General and Administrative Expenses
39
56
(17
)
(30.4
)%
Total Company General and Administrative Expense
$
119
$
133
$
(14
)
(10.5
)%
Overall,
total Company General and Administrative Expenses decreased $14 million in the period-to-period comparison. This was primarily due to a $17 million decrease in employee wages and related expenses, attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan. Total other post-employment benefit (OPEB) expenses were also lower in the period-to-period comparison, related to changes in the discount rates and other assumptions. The remaining $3 million change related to various transactions that occurred throughout both periods, none of which were individually significant.
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 $152 million for the year ended December 31, 2013 compared to $135 million for the year ended December 31, 2012. The increase of $17 million for total CONSOL Energy continuing operations expense was primarily due to required pension settlement accounting which resulted in $39 million of expense. Pension settlement expenses were required when lump sum distributions made for the 2013 plan year exceeded the total of the service cost and interest cost for the 2013 plan year. The pension
settlement was not allocated to individual operating segments and is therefore not included in unit costs presented for E&P or coal. This was offset, in part, due to a modification of the salaried post-employment benefit plan, which required a remeasurement at March 31, 2012. See Note 16 - Pension and Other Post-Employment Benefit Plans and Note 17 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional detail of the total Company expense increase.
The E&P division had a loss before income tax of $2 million for the year ended December 31, 2013 compared to earnings before income tax of $39 million for the year ended December 31, 2012. Variances by individual E&P segment are discussed below.
The Marcellus segment contributed $80 million to the total Company earnings before income tax for the year ended December 31, 2013 compared to $30 million for the year ended December 31, 2012.
Average
Marcellus ad valorem, severance, and other taxes (per Mcfe)
$
0.16
$
0.12
$
0.04
33.3
%
Average
Marcellus gathering costs (per Mcfe)
$
0.86
$
0.67
$
0.19
28.4
%
Average
Marcellus direct administrative and selling (per Mcfe)
$
0.45
$
0.46
$
(0.01
)
(2.2
)%
Average
Marcellus depreciation, depletion and amortization costs (per Mcfe)
$
1.16
$
1.30
$
(0.14
)
(10.8
)%
Total
Average Marcellus costs (per Mcfe)
$
2.98
$
2.89
$
0.09
3.1
%
Average
Margin for Marcellus (per Mcfe)
$
1.37
$
0.79
$
0.58
73.4
%
*
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 oil, NGLs, condensate, and natural gas prices.
The Marcellus segment sales revenues were $252 million for the year ended December 31, 2013 compared to $134 million for the year ended December 31, 2012. The $118 million increase was primarily due to a 58.4% increase in total volumes sold, and an 18.2%
increase in total average sales prices in the period-to-period comparison. The increase in sales volumes was primarily due to additional wells coming on-line from our on-going drilling program. The increase in Marcellus total average sales price was the result of the $0.88 per Mcf increase in gas market prices, along with an uplift from an additional 2.2 Bcfe, or $0.16 per Mcf, of natural gas liquids and condensate sales volumes. The increase was offset, in part, by a $0.37 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 21.6 Bcf of our produced Marcellus gas sales volumes for the year ended December 31,
2013 at an average gain of $0.81 per Mcf. For the year ended December 31, 2012, these financial hedges represented 12.4 Bcf at an average gain of $1.99 per Mcf.
Total costs for the Marcellus segment were $172 million for the year ended December 31, 2013 compared to $104 million for the year ended December 31, 2012. The increase in total dollars
and unit costs for the Marcellus segment was due to the following items:
•Marcellus lifting costs were $20 million for the year ended December 31, 2013 compared to $12 million for the year ended December 31, 2012. The increase primarily relates to an increase in sales volumes, along with an increase in salt water disposal costs, road maintenance costs, and well tending costs. The impact on average unit costs from these increases was offset by higher sales volumes.
•Marcellus
ad valorem, severance and other taxes were $9 million for the year ended December 31, 2013 compared to $4 million for the year ended December 31, 2012. The increase in total dollars and unit costs was primarily due to an increase in severance tax expense caused by higher average gas sales prices and the 58.4% increase in sales volumes during the current period.
78
•Marcellus
gathering costs were $50 million for the year ended December 31, 2013 compared to $24 million for the year ended December 31, 2012. Total dollars increased due to an increase in processing fees associated with natural gas liquids, which resulted in an increase in average unit costs. Higher firm transportation costs also resulted in an increase on unit costs. The impact on average unit costs from these increases was offset, in part, by higher sales volumes.
•Marcellus direct administrative, selling and other costs were $26 million
for the year ended December 31, 2013 compared to $17 million for the year ended December 31, 2012. Direct administrative, selling and other costs attributable to the total E&P segment are allocated to the individual E&P segments based on a combination of 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 impact on average unit costs from the increase in direct administrative costs was offset by higher sales volumes.
•Depreciation, depletion and amortization
costs were $67 million for the year ended December 31, 2013 compared to $47 million for the year ended December 31, 2012. There was approximately $66 million, or $1.14 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 year ended December 31, 2013. There was approximately $44 million, or $1.24
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 year ended December 31, 2012. There was approximately $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 year ended December 31, 2013. There was $3 million, or $0.06 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis
for the year ended December 31, 2012.
79
UTICA GAS SEGMENT
The Utica segment had a loss before income tax of $4 million for the year ended December 31, 2013 compared to a loss before income tax of $2 million for the year ended December 31,
2012.
Average
Utica ad valorem, severance, and other taxes (per Mcfe)
$
(0.67
)
$
24.72
$
(25.39
)
(102.7
)%
Average
Utica gathering costs (per Mcfe)
$
0.53
$
—
$
0.53
100.0
%
Average
Utica direct administrative and selling (per Mcfe)
$
2.79
$
38.34
$
(35.55
)
(92.7
)%
Average
Utica depreciation, depletion and amortization costs (per Mcfe)
$
4.96
$
(0.03
)
$
4.99
16,633.3
%
Total
Average Utica costs (per Mcfe)
$
11.08
$
69.65
$
(58.57
)
(84.1
)%
Average
Margin for Utica (per Mcfe)
$
(5.28
)
$
(58.63
)
$
53.35
91.0
%
*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 oil, NGLs, condensate, and natural gas prices.
A per unit analysis of the Utica segment is not meaningful due to less than 0.1 Bcfe of production in the prior period.
80
COALBED METHANE (CBM) GAS SEGMENT
The CBM segment contributed $81 million to the
total Company earnings before income tax for the year ended December 31, 2013 compared to $126 million for the year ended December 31, 2012.
Average
CBM ad valorem, severance, and other taxes (per Mcf)
$
0.10
$
0.12
$
(0.02
)
(16.7
)%
Average
CBM gathering costs (per Mcf)
$
1.37
$
1.21
$
0.16
13.2
%
Average
CBM direct administrative and selling (per Mcf)
$
0.10
$
0.16
$
(0.06
)
(37.5
)%
Average
CBM depreciation, depletion and amortization costs (per Mcf)
$
1.10
$
0.98
$
0.12
12.2
%
Total
Average CBM costs (per Mcf)
$
3.11
$
2.89
$
0.22
7.6
%
Average
Margin for CBM (per Mcf)
$
0.98
$
1.43
$
(0.45
)
(31.5
)%
CBM
sales revenues were $339 million in the year ended December 31, 2013 compared to $380 million for the year ended December 31, 2012. The $41 million decrease was primarily due to a 6.0% decrease in total volumes sold and a 5.3% decrease in total average sales price per Mcf. CBM sales volumes decreased 5.3 Bcf for the year ended December 31,
2013 compared to the 2012 period primarily due to normal well declines without a corresponding amount of additional wells drilled. The decrease in wells drilled was due to the Company's current focus on Marcellus and Utica production. The CBM total average sales price decreased $0.23 per Mcf primarily due to a $1.04 per Mcf decrease resulting from various transactions relating to our hedging program. Financial hedges represented approximately 48.3 Bcf of our produced CBM gas sales volumes for the year ended December 31, 2013 at an average gain of $0.69
per Mcf. For the year ended December 31, 2012, these financial hedges represented 45.8 Bcf at an average gain of $2.76 per Mcf. The decrease was offset, in part, by a $0.81 per Mcf increase in average gas market prices.
Total costs for the CBM segment were $258 million for the year ended December 31, 2013 compared to $254 million for the year
ended December 31, 2012. The increase in total dollars and unit costs for the CBM segment were due to the following items:
•CBM lifting costs were $37 million for the year ended December 31, 2013 and December 31, 2012. The increase in unit costs was due to the decrease in gas sales volumes.
•CBM ad valorem, severance and other taxes were $9
million for the year ended December 31, 2013 compared to $10 million for the year ended December 31, 2012. The decrease of $1 million was primarily due to a reassessment of our ad valorem taxes paid to Tazewell County, Virginia resulting in a refund. The decrease was offset, in part, by an increase in severance tax expense resulting from the increase in average sales price, without the impact of hedging, as described above.
•CBM gathering costs were $114 million for the year
ended December 31, 2013 compared to $106 million for the year ended December 31, 2012. The increase in total dollars and average per unit costs was due to increased compression costs, increased power fees, and increased pipeline and road maintenance. Unit costs were also negatively impacted by the decrease in gas sales volumes.
•CBM direct administrative, selling and other costs were $8 million for the year ended December 31, 2013 compared
to $14 million for the year ended December 31, 2012. Direct administrative, selling & other costs attributable to the total E&P segment were allocated to the individual E&P segments based on a combination of production and employee counts. The decrease in direct administrative, selling & other costs was primarily due to reduced direct administrative labor and CBM volumes representing a smaller proportion of CONSOL Energy's total gas sales volumes. Improvements in unit costs were offset, in part, by the decrease in gas sales volumes.
81
•Depreciation,
depletion and amortization costs attributable to the CBM segment were $90 million for the year ended December 31, 2013 compared to $87 million for the year ended December 31, 2012. There was approximately $62 million, or $0.77 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 year ended December 31,
2013. The production portion of depreciation, depletion and amortization was $60 million, or $0.67 per unit-of-production in the year ended December 31, 2012. There was approximately $28 million, or $0.33 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the year ended December 31, 2013. The non-production related depreciation, depletion and amortization was $27
million, or $0.31 per Mcf for the year ended December 31, 2012.
82
OTHER GAS SEGMENT
The other gas segment had a loss before income taxes of $159 million for the year ended December 31, 2013 compared to a
loss before income tax of $115 million for the year ended December 31, 2012.
Average
Other ad valorem, severance, and other taxes (per Mcfe)
$
0.36
$
0.34
$
0.02
5.9
%
Average
Other gathering costs (per Mcfe)
$
1.19
$
0.95
$
0.24
25.3
%
Average
Other direct administrative and selling (per Mcfe)
$
0.41
$
0.49
$
(0.08
)
(16.3
)%
Average
Other depreciation, depletion and amortization costs (per Mcfe)
$
2.22
$
2.15
$
0.07
3.3
%
Total
Average Other costs (per Mcfe)
$
5.39
$
5.23
$
0.16
3.1
%
Average
Margin for Other (per Mcfe)
$
(0.67
)
$
(0.66
)
$
(0.01
)
(1.5
)%
*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, NGLs, condensate, and natural gas prices.
The other gas segment includes activity not assigned to the Marcellus, Utica, or CBM 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 division.
Other gas sales volumes are primarily related to shallow oil and gas production as well as Upper Devonian Shale in Pennsylvania and West Virginia. Revenue from these operations was approximately $146 million for the year ended December 31,
2013 and $145 million for the year ended December 31, 2012. Total costs related to these other sales were $170 million for the year ended December 31, 2013 and $170 million for the year ended December 31, 2012.
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
year ended December 31, 2013 compared to $50 million for the year ended December 31, 2012. 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.
Gas Royalty Interest Sales Volumes (in billion cubic feet)
15.3
18.0
(2.7
)
(15.0
)%
Average
Sales Price per thousand cubic feet
$
4.13
$
2.74
$
1.39
50.7
%
Purchased
gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $7 million for the year ended December 31, 2013 compared to $3 million for the year ended December 31, 2012.
Purchased Gas Sales Volumes (in billion cubic feet)
1.6
1.1
0.5
45.5
%
Average
Sales Price per thousand cubic feet
$
4.12
$
3.03
$
1.09
36.0
%
Other
income was $58 million for the year ended December 31, 2013 compared to $57 million for the year ended December 31, 2012. The $1 million increase was due 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 $39 million for the year ended December 31, 2013
and $34 million for the year ended December 31, 2012. Refer to the discussion of total company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this annual 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 year ended December 31, 2013 compared to $38 million for the year ended
December 31, 2012. 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.
Gas
Royalty Interest Sales Volumes (in billion cubic feet)
15.3
18.0
(2.7
)
(15.0
)%
Average Cost per thousand cubic feet sold
$
3.47
$
2.16
$
1.31
60.6
%
Purchased
gas volumes represent volumes of gas purchased from third-party producers that are subsequently sold to customers. Changes in the average cost per Mcf were due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $5 million for the year ended December 31, 2013 compared to $3 million for the year ended December 31, 2012.
Exploration
and other costs were $61 million for the year ended December 31, 2013 compared to $39 million for the year ended December 31, 2012. The $22 million increase in costs is primarily related to the following items:
Total
Exploration and Production Related Other Costs
$
61
$
39
$
22
56.4
%
•
CONSOL
Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $23 million for the year ended December 31, 2013 compared to $4 million for the year ended December 31, 2012.
•
Dry hole costs increased $6 million due to various transactions that occurred throughout both periods, none of which were individually material.
84
•
Land
Rentals remained consistent in the period-to-period comparison.
•
Seismic Activity remained consistent in the period-to-period comparison.
•
Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $5 million decrease was due to fewer lease expirations in the 2013 period when compared with the 2012 period.
•
Other
expenses increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
Other corporate expenses were $96 million for the year ended December 31, 2013 compared to $81 million for the year ended December 31, 2012. The $15 million increase in the period-to-period comparison was made up of the following items:
Unutilized
firm transportation costs represent pipeline transportation capacity the gas segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. The $20 million increase was due to increased firm transportation capacity which has not been utilized by active operations.
•
Stock-based compensation was $6 million higher in the period-to-period comparison primarily due to additional non-cash expense and accelerated non-cash expense for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program, when compared to the prior year. The
new program replaces several previously provided long-term executive compensation award programs. The compensation expense of the CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.
•
Bank Fees remained consistent in the period-to-period comparison.
•
Litigation settlements decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
•
The
short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation expense decreased $6 million due to lower projected payouts in the 2013 period.
•
Other corporate related expenses decreased $3 million due to various transactions that occurred throughout both periods, none of which were individually material.
Interest expense related to the gas segment was $9
million for the year ended December 31, 2013 compared to $5 million for the year ended December 31, 2012. Interest was incurred by the gas segment on the CNX Gas revolving credit facility and a capital lease. The $4 million increase was primarily due to higher levels of borrowings on the revolving credit facility throughout the period-to-period comparison.
The coal segment contributed $348 million of earnings before income tax from continuing operations in the year ended December 31, 2013 compared to $610 million in the year ended December 31, 2012. Variances by individual coal segment are discussed below.
The PA Operations coal segment principal activities are mining, preparation and marketing of thermal coal to power generators. The segment also includes general and administrative activities as well as various other activities assigned to the PA Operations coal segment but not allocated to each individual mine and are therefore not included in unit cost presentation. For the years ended December 31, 2013 and 2012 the segment included the following mines: Bailey Mine, Enlow Fork Mine, Harvey Mine and the corresponding preparation plant facilities.
The PA Operations coal segment contributed $310 million to total Company earnings before income tax for the year ended
December 31, 2013 compared to $338 million for the year ended December 31, 2012. The PA Operations coal revenue and cost components on a per unit basis for these periods were as follows:
Company Produced PA Operations Tons Sold (in millions)
21.2
19.6
1.6
8.2
%
Average
Sales Price Per PA Operations Ton Sold
$
63.93
$
67.67
$
(3.74
)
(5.5
%)
Total
Operating Costs Per Ton Sold
$
36.13
$
35.07
$
1.06
3.0
%
Total
Direct Administration and Selling Costs Per Ton Sold
1.26
1.49
(0.23
)
(15.4
%)
Total Royalty/Production Taxes Per Ton Sold
2.58
2.43
0.15
6.2
%
Total
Depreciation, Depletion and Amortization Costs Per Ton Sold
5.58
5.90
(0.32
)
(5.4
%)
Total Costs Per PA Operations Ton Sold
$
45.55
$
44.89
$
0.66
1.5
%
Average
Margin Per PA Operations Ton Sold
$
18.38
$
22.78
$
(4.40
)
(19.3
%)
PA
Operations outside sales revenue was $1,357 million for the year ended December 31, 2013 compared to $1,324 million for the year ended December 31, 2012. The $33 million increase was attributable to 1.6 million increase in tons sold offset, in part, by $3.74 per ton lower average sales price. The lower average PA Operations coal sales price in the 2013 period was the result of the renewal of several domestic PA Operations contracts whose pricing
was reduced effective January 1, 2013. The PA Operations coal segment revenue was also impacted by 2.0 million tons of PA Operations coal being priced on the export market for the year ended December 31, 2013 compared to 2.1 million tons for the year ended December 31, 2012.
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) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is almost completely offset in freight expense. Freight revenue was $18
million for the year ended December 31, 2013 compared to $51 million for the year ended December 31, 2012. The $33 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides transportation services.
Miscellaneous other income was $6 million for the year ended December 31, 2013 compared to $12 million for the year ended December 31,
2012. The $6 million decrease was due to the following items:
For
the year ended December 31, 2012, $5 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. No such transactions were entered into in the year ended December 31, 2013.
•
Rental/Royalty
income decreased $3 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 year ended December 31, 2013 compared to $2 million in the year ended December 31, 2012 related to the 2012 Bailey Belt Conveyor accident.
87
•
Other
income decreased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
Total operating costs and expenses is comprised of changes in PA Operations coal inventory, both volumes and carrying values, and costs of tons sold in the period. The costs per ton sold include items such as direct operating costs, royalty and production taxes, direct administration and selling, and depreciation, depletion, and amortization costs. Total operating costs and expenses for PA Operations were $967 million for the year ended December 31, 2013, or $89 million higher than the $878
million for the year ended December 31, 2012. Total costs per PA Operations ton sold were $45.55 per ton in the year ended December 31, 2013 compared to $44.89 per ton in the year ended December 31, 2012. The increase in total dollars and unit costs were primarily related to a structural failure that occurred on July 27, 2012, at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The incident caused a total of four longwalls to be idled
for approximately three weeks, and production to be at approximately 60% for the third quarter of 2012. The mines operated at full capacity for the entire 2013 period.
Other Costs And Expenses
Other costs is comprised of various costs and expenses that are assigned to the PA Operations coal segment but not allocated to each individual mine and therefore not included in unit costs. Other costs was $23 million for the year ended December 31, 2013 compared to $58 million for the year ended December 31, 2012. The change was due to the following items:
Bailey
Belt incident costs represent expenses related to continued advancement of the mines and on-going projects at the mines that took place during the idles phase when belt reconstruction was occurring and which was not included in active mining costs.
•
Property and other taxes decreased $5 million due to a tax reassessment that occurred in the 2013 period.
•
Litigation Contingencies increased $4 million in the period-to-period
comparison due to various items. See Note 24- Commitments and Contingent Liabilities in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Company expense.
•
Supplies expense increased $9 million primarily due to the 2013 period including additional supplies needed for repairs related to the 2012 Bailey Belt Conveyor accident which was not included in active mining costs.
•
Other expense decreased
$1 million due to various items that occurred throughout both periods, none of which were individually material.
Direct Administrative expense is primarily made up of labor and benefits, marketing, and consulting expenses that were allocated to the Harvey Mine while it was in development phase. Direct Administration expense allocated to PA Operations decreased $1 million in the period-to-period comparison due to more labor and benefit costs being allocated in the prior period.
Depreciation, depletion, and amortization decreased $3 million due to a decrease in assets placed in service in the current period.
General
and Administrative costs are allocated to each coal segment based upon the activity at the segment determined by their level of operating activity. General and Administrative costs allocated to the PA Operations coal segment were $23 million for the year ended December 31, 2013 compared to $24 million for the year ended December 31, 2012. Refer to the discussion of total company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation.
88
Other
corporate expense is made up of expenses for stock based compensation and the short-term incentive compensation program. These expenses are made up of costs that are directly related to each coal segment along with a portion of costs that are allocated to each segment based on a percent of total labor dollars. For the year ended December 31, 2013 other corporate expenses were $38 million compared to $32 million for the year ended December 31, 2012. The $6 million increase was primarily due to PA Operations representing a larger portion of total coal labor costs.
Freight
expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail) 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 $33 million decrease in freight expense was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.
VIRGINIA (VA) OPERATIONS COAL SEGMENT
The VA Operations coal segment principal activities are mining, preparation and marketing of low metallurgical
coal to metal and coke producers. The segment also includes general and administrative activities as well as various other activities assigned to the VA Operations coal segment but not allocated to each individual mine and are therefore not included in unit cost presentation. For the years ended December 31, 2013 and 2012 the segment included the following mines: Buchanan Mine, Amonate Complex and the corresponding preparation plant facilities. Operations at Amonate Complex were idled in September 2012, but the complex continued to sell coal inventory in 2013.
The VA Operations coal segment contributed $93 million to total Company earnings before income tax in the year ended December 31,
2013 compared to $178 million in the year ended December 31, 2012. The VA Operations coal revenue and cost components on a per ton basis for these periods were as follows:
Company
Produced VA Operations Tons Sold (in millions)
4.9
3.6
1.3
36.1
%
Average Sales Price Per VA Operations Ton Sold
$
92.43
$
140.11
$
(47.68
)
(34.0
%)
Total
Operating Costs Per Ton Sold
$
51.54
$
61.84
$
(10.30
)
(16.7
%)
Total
Direct Administrative and Selling Costs Per Ton Sold
1.24
1.72
(0.48
)
(27.9
%)
Total Royalty/Production Taxes Per Ton Sold
5.50
8.32
(2.82
)
(33.9
%)
Total
Depreciation, Depletion and Amortization Costs Per Ton Sold
8.71
10.00
(1.29
)
(12.9
%)
Total Costs Per VA Operations Ton Sold
$
66.99
$
81.88
$
(14.89
)
(18.2
%)
Average
Margin Per VA Operations Ton Sold
$
25.44
$
58.23
$
(32.79
)
(56.3
%)
VA
Operations coal outside sales revenue was $450 million for the year ended December 31, 2013 compared to $506 million for the year ended December 31, 2012. The $56 million decrease was attributable to a $47.68 per ton lower average sales price. Average sales prices for VA Operations coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market. The VA Operations coal segment revenue was also impacted by 3.8 million tons of VA Operations coal being priced on the export market for the year ended December 31,
2013, which was 0.8 million tons higher than the tons sold in the year ended December 31, 2012.
Freight revenue was $4 million for the year ended December 31, 2013 compared to $36 million for the year ended December 31, 2012. The $32 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides transportation services.
Miscellaneous other income
increased $1 million in the period-to-period comparison primarily due to various items that occurred in both periods none of which were individually material.
Gain on sale of assets decreased $8 million in the period-to-period comparison primarily due to various asset sales that occurred in both periods none of which were individually material. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
89
Total
operating costs and expenses for VA Operations was $326 million for the year ended December 31, 2013, or $30 million higher than the $296 million for the year ended December 31, 2012. Total cost per VA Operations ton sold was $66.99 per ton in the year ended December 31, 2013 compared to $81.88 per ton in the year ended December 31, 2012. The increase in total dollars
and decrease in unit costs per VA Operations ton was primarily due to the Buchanan Mine longwall being temporarily idled in March, April, and October of 2012. The increase in costs was partially offset by several cost saving initiatives at the Buchanan Mine in the 2013 period, such as, slowing the pace of major maintenance projects, right sizing the workforce to fit the five-day work schedule implemented earlier in 2013, and opening the Horn Mountain portal, which allowed employees to enter the mine much closer to the longwall face. VA Operations coal production was 1.3 million tons higher in the 2013 period primarily due to Buchanan Mine being temporarily idled in the 2012 period, as mentioned above. This resulted in 2012 fixed costs being allocated over less tons, resulting in higher unit costs in the prior period.
Other Costs
And Expenses
Total other costs for VA Operations was $8 million for the year ended December 31, 2013 compared to $19 million for the year ended December 31, 2012. The $11 million change was due to the following items:
Idle
mine costs decreased $11 million in the period-to-period comparison primarily due to the Buchanan Mine operating throughout 2013 but was temporarily idled in the 2012 period.
•
Water treatment costs remained consistent in the period-to-period comparison.
•
Other expense remained consistent in the period-to-period comparison.
Depreciation, depletion, and amortization
increased $1 million primarily due to additional assets placed in service in the current period.
General and Administrative costs allocated to the VA Operations coal segment were $9 million for the year ended December 31, 2013 compared to $8 million for the year ended December 31, 2012. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation.
For
the year ended December 31, 2013 other corporate expenses were $11 million compared to $10 million for the year ended December 31, 2012. The increase of $1 million was primarily due to VA Operations representing a larger portion of total coal labor costs which is the basis for the allocation.
Freight expense decreased $32 million in the period-to-period comparison due to decreased shipments under contracts which CONSOL
Energy contractually provides transportation services.
OTHER COAL SEGMENT
The Other coal segment primarily includes coal terminal operations, idle mine activities and purchased coal activities as well as various other activities not assigned to either PA Operations or VA Operations. The Other coal segment also includes activities related to mining, preparation and marketing of thermal coal to power generators geographically separated from PA Operations. For the years ended December 31, 2013 and 2012 the segment included the Miller Creek Complex and the Fola Complex.
The Other coal segment
had a loss before income tax of $55 million for the year ended December 31, 2013 compared to income of $94 million for the year ended December 31, 2012. Other coal revenue and cost components on a per unit basis for these periods were as follows:
Company Produced Other Operations Tons Sold (in millions)
2.7
4.4
(1.7
)
(38.6
%)
Average
Sales Price Per Other Operations Ton Sold
$
70.22
$
71.44
$
(1.22
)
(1.7
%)
Total
Operating Costs Per Ton Sold
$
47.95
$
55.97
$
(8.02
)
(14.3
%)
Total
Direct Administration and Selling Costs Per Ton Sold
1.03
1.39
(0.36
)
(25.9
%)
Total Royalty/Production Taxes Per Ton Sold
7.80
8.87
(1.07
)
(12.1
%)
Total
Depreciation, Depletion and Amortization Costs Per Ton Sold
5.98
5.09
0.89
17.5
%
Total Costs Per Other Operations Ton Sold
$
62.76
$
71.32
$
(8.56
)
(12.0
%)
Average
Margin Per Other Operations Ton Sold
$
7.46
$
0.12
$
7.34
6,116.7
%
Other
coal outside sales revenue was $188 million for the year ended December 31, 2013 compared to $322 million for the year ended December 31, 2012. The $134 million decrease was attributable to a 1.7 million decrease in tons sold in 2013 and a $1.22 per ton lower average sales price.
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 $23 million for the year ended December 31, 2013 compared to $17 million for the year ended December 31, 2012. The increase was primarily due to an increase in 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) used by the customers
to which CONSOL Energy contractually provides transportation services. Freight revenue was offset by freight expense. Freight revenue was $13 million for the year ended December 31, 2013 compared to $20 million for the year ended December 31, 2012. The $7 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.
Miscellaneous other income was $50
million for the year ended December 31, 2013 compared to $53 million for the year ended December 31, 2012. The $3 million decrease was due to the following items:
For
the year ended December 31, 2012, $4 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. No such transactions were entered into during the year ended December 31, 2013.
•
Royalty
income remained consistent in the period-to-period comparison.
•
Equity in earnings of affiliates increased $2 million due to various transactions completed by our equity partners, none of which were individually material.
•
Land rental income primarily consists of income related to the sale of right of ways on property that CONSOL Energy owns. The $3 million increase was due to an increase in land activity in the period-to-period
comparison.
•
Other decreased $4 million due to various transactions that occurred in the prior period, none of which were individually material.
91
Gain on sale of assets attributable to the Other Coal segment was $41 million in the year ended December 31,
2013 compared to $257 million in the year ended December 31, 2012. The decrease of $216 million was due to various asset sales that occurred in both periods. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
Other Costs And Expenses
Other costs were $164 million for the year ended December 31, 2013 compared to $216 million for the
year ended December 31, 2012. The decrease of $52 million was due to the following items:
Closed
and idle mine costs decreased approximately $21 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. Closed and idle mine costs decreased $16 million due to the decision to shutdown the Fola Mining Complex in August 2012. Other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material resulted in an additional $5 million decrease.
•
Litigation Contingencies decreased $17
million in the year-to-year comparison due to various items. See Note 24- Commitments and Contingent Liabilities in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Company expense.
•
In November 2012, CONSOL Energy offered a voluntary severance incentive program (VSIP) to active salaried corporate and operation support employees with 30 years of service, or more. Under this program, eligible employees who accepted the offer received a severance payment equal to one year's salary. Approximately 100 employees volunteered for the program. Severance pay was approximately $13 million.
•
Coal
Terminal Operations costs decreased $1 million due to decreased thru-put volumes in the 2013 period.
•
Coal reserve holding costs which primarily consist of property and other taxes, remained consistent in the period-to-period comparison.
•
Purchased coal costs increased $2 million due to higher amounts of coal that was purchased to fulfill various contracts.
•
Other
expenses related to the coal segment decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
Direct Administrative expense increased $2 million in the period-to-period comparison due to an increase in labor and employee benefits allocated to the other segment.
Royalty and productions taxes decreased $1 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.
Depreciation, depletion,
and amortization increased $6 million primarily due to additional assets placed in service in the period-to-period comparison.
General and Administrative costs allocated to the Other coal segment were $8 million for the year ended December 31, 2013 compared to $11 million for the year ended December 31, 2012. Refer to the discussion of total company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost
explanation.
92
For the year ended December 31, 2013 other corporate expenses were $7 million compared to $11 million for the year ended December 31, 2012. The decrease of $4 million was primarily related to the other coal segment representing a smaller portion of total coal labor costs which is the basis of the allocation.
Freight
expense decreased $7 million in the period-to-period comparison due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.
The other division includes activity from the sales of industrial supplies and various other corporate activities that are not allocated to the E&P or coal divisions.
The other segment had a loss before income tax of $297 million for the year ended December 31, 2013 compared to a loss before income tax of $241 million for the year ended December 31, 2012. The other division also includes the total company income tax benefit of $33 million for the year ended December 31, 2013 compared to the total company income tax expense of $89
million for the year ended December 31, 2012.
Outside
sales revenue was $217 million for the year ended December 31, 2013 compared to $243 million for the year ended December 31, 2012. The decrease was related to lower sales volumes from our industrial supplies subsidiary.
Additional other income of $15 million was recognized for the year ended December 31, 2013 compared to $3 million for the year ended December 31, 2012.
The $12 million increase was primarily due to the following items:
Pennsylvania
Turnpike Settlement relates to mediation with the PA Turnpike Commission that was settled for $9 million.
•
Interest Income increased $3 million mainly due to various transactions that occurred throughout both periods, none of which were individually material.
•
Equity in Earnings of Affiliates increased $1 million due to various transactions that occurred throughout both periods,
none of which were individually material.
•
Other income decreased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
Total costs of the other segment include interest expense, transaction and financing fees and various other miscellaneous corporate charges. Total other costs were $529 million for the year ended December 31, 2013 compared to $487 million for the year ended December 31,
2012. Other corporate costs increased due to the following items:
Pension
settlement expense 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.
•
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 paid $20 million.
•
Corporate
initiative fees and other legal charges reflect various charges 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 case. See Note 11 - Property, Plant and Equipment and Note 24 - Commitments and Contingent Liabilities of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
•
Bank fees increased $5 million mainly due to higher borrowings on the CNX Gas revolving credit facilities in the period-to-period comparison, as well as bank fees from the accelerated
amortization of the previously deferred fees in relation to the capacity reduction in CONSOL Energy's revolving credit facility from $1.5 billion to $1.0 billion.
•
Interest Expense decreased $4 million primarily due to an increase in capitalized interest as a result of additional capital expenditures for major construction projects in 2013.
•
The decrease of $24 million related to industrial supplies was primarily related to
lower sales volumes and various changes in inventory costs, none of which were individually material.
•
Other corporate items decreased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.
Income Taxes:
The 2013 effective tax rate is the result of lower pre-tax income without a corresponding reduction in the percentage depletion deduction, resulting in a tax loss from continuing operations in the 2013 period. CONSOL Energy's effective tax rate is significantly impacted by the relationship
between the pre-tax earnings and percentage depletion. See Note 7-Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities in the consolidated financial statements and at the date of the financial statements. See Note 1-Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making the judgments about the carrying values of assets and liabilities that are not readily apparent from other
sources. We evaluate our estimates on an on-going basis. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.
Other Post Employment Benefits (OPEB), Salaried Pensions, Workers’ Compensation and Coal Workers’ Pneumoconiosis (CWP)
Liabilities and expenses for OPEB, pension, workers’ compensation and CWP are determined using actuarial methodologies and incorporate significant assumptions, including the interest rate used to discount the future estimated liability, the expected long-term rate of return on plan assets, and several assumptions relating to the employee workforce (salary increases, health care
cost trend rates, retirement age, and mortality).
The interest rate used to discount future estimated liabilities is determined using a Company-specific yield curve model (above-median) developed with the assistance of an external actuary. The Company-specific yield curve uses a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody’s or Standard & Poor’s as of the measurement date. The yield curve model parallels the plans’ projected cash flows.
The assumed rate of return on plan assets can also impact CONSOL Energy’s pension liability. The market related asset value is derived by taking the cost value of assets as of December
31, 2014 and multiplying it by the average 36-month ratio of the market value of assets to the cost value of assets. CONSOL Energy’s pension plan weighted average asset allocations at December 31, 2014 consisted of 60% equity securities and 40% debt securities.
The estimated liabilities recognized at December 31, 2014 and the benefit payments made for the year end December 31, 2014 were as follows:
Reclamation, Mine Closure and Gas Well Closing Obligations
The Surface Mining Control and Reclamation Act established operational, reclamation and closure standards for all aspects
of surface mining as well as most aspects of deep mining. CONSOL Energy accrues for the costs of current mine disturbance and final mine and gas well closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing, and gas well closing liabilities which are based upon permit requirements and CONSOL Energy engineering expertise related to these requirements, including the current portion, were approximately $575.5 million at December 31, 2014. This liability is reviewed annually, or when events and circumstances indicate an adjustment is necessary, by CONSOL Energy management and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental regulations change significantly.
Accounting for Asset Retirement Obligations
requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate to the closure of mines and gas wells and the reclamation of land upon exhaustion of coal and gas reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the mine closing, reclamation and gas well closing
95
liabilities. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs,
estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.
Accounting for Asset Retirement Obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines.
Income Taxes
Deferred tax assets and liabilities are recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities.
Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2014, CONSOL Energy has deferred tax liabilities in excess of deferred tax assets of approximately $259.0 million. The deferred tax assets are evaluated periodically to determine if a valuation allowance is necessary.
CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determined on a cumulative
probability basis that is more likely than not to be realized upon ultimate settlement is determined. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax liability. Actual results could differ from those estimates upon subsequent resolution of identified matters. CONSOL Energy has no uncertain tax liabilities at December 31, 2014.
Stock-Based Compensation
As of December 31, 2014, we have issued four types of share based payment awards: options, restricted stock units, performance stock options and performance share units. The Black-Scholes option pricing model is used to determine fair value of stock options at the grant date. Various inputs are utilized in the Black-Scholes pricing model, such as:
•
stock price on measurement date,
•
exercise
price defined in the award,
•
expected dividend yield based on historical trend of dividend payouts,
•
risk-free interest rate based on a zero-coupon treasury bond rate,
•
expected term based on historical grant and exercise behavior, and
•
expected
volatility based on historic and implied stock price volatility of CONSOL Energy stock and public peer group stock.
These factors can significantly impact the value of stock options expense recognized over the requisite service period of option holders.
The fair value of each restricted stock unit awarded is equivalent to the closing market price of a share of our company's stock on the date of the grant. The fair value of each performance share unit is determined by the underlying share price of our company stock on the date of the grant and management's estimate of the probability that the performance
conditions required for vesting will be achieved.
As of December 31, 2014, $21.7 million of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.89 years. See Note 19 - Stock-based Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 in this Form 10-K for more information.
96
Contingencies
CONSOL Energy is currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for the resolution of these claims. This estimate has been developed in consultation with legal counsel involved in the defense of these matters and is based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters, and management's intended response. Future results of operations for any particular quarter or annual period could be materially affected by changes in our assumptions or the outcome of these proceedings. Legal fees associated with defending these various lawsuits and claims are expensed when incurred. See Note 24-Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 in this Form 10-K for further discussion.
Derivative
Instruments
CONSOL Energy enters into financial derivative instruments to manage exposure to natural gas and oil price volatility. We measure every derivative instrument at fair value and record them on the balance sheet as either an asset or liability. Changes in fair value of 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 fair value of the derivative are reported in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year.
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 fair values or cash flows of the hedge 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.
On December 31, 2014, CONSOL Energy de-designated all of its derivative positions as hedging instruments. Subsequent changes in fair value will be recorded in current earnings. Deferred gains and losses in other comprehensive income as of that date will
be recorded in earnings when the related physical transaction occurs or when it is determined that the physical transaction is no longer probable of occurring.
Gas and Coal Reserve Values
There are numerous uncertainties inherent in estimating quantities and values of economically recoverable gas and coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable gas and coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Our gas reserves are reviewed by independent experts each year. Our coal reserves are periodically reviewed by an independent third party consultant. Some of the factors and assumptions which
impact economically recoverable reserve estimates include:
•
geological conditions;
•
historical production from the area compared with production from other producing areas;
•
the assumed effects of regulations and taxes by governmental agencies;
•
assumptions
governing future prices; and
•
future operating costs.
Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of gas and coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. See "Risk Factors" in Item 1A of this report for a discussion of
the uncertainties in estimating our reserves.
CONSOL Energy performed a quantitative annual impairment test over proven producing wells using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. Utilizing these assumptions there were undiscounted cash flows in excess of book value, as a result no further impairment procedures were required. Our conventional gas assets are quantitatively and qualitatively close to triggering impairment. If gas prices continue to decrease, an impairment of these assets is possible in the near future.
97
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 an aggregate sub-limit for letters of credit of $750 million. 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 4.90 to 1.00 at December 31, 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 2.42 to 1.00 at December 31, 2014. Affirmative and negative covenants in the facility limit the Company's 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 December 31, 2014, the facility had no outstanding borrowings and $244 million of letters of credit outstanding, leaving $1,756 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. CONSOL Energy sometimes use letters of credit to satisfy these requirements and these letters of credit reduce the Company's 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 December 31, 2014, eligible accounts receivable totaled approximately $78 million. At December 31, 2014, the facility had no outstanding borrowings and $60 million of letters of credit outstanding, leaving $18 million of unused capacity.
Uncertainty
in the financial markets brings additional potential risks to CONSOL Energy. The risks include declines in the Company's stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact the Company's collection of trade receivables. As a result, CONSOL Energy regularly monitors the creditworthiness of its customers. CONSOL Energy believes that its current group of customers are financially sound and represent no abnormal business risk.
CONSOL Energy believes that cash generated from operations, asset sales and the Company's
borrowing capacity will be sufficient to meet the Company's 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
98
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 $192 million at December 31, 2014. The ineffective portion of these contracts was $4 million during the year ended December 31, 2014. No issues
related to the Company's hedge agreements have been encountered to date.
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 provided by operating activities increased $278 million in the period-to-period comparison primarily due to the following items:
•
Net income decreased $496 million in the period-to-period comparison;
•
Discontinued operations changes increased $446 million primarily as a result of the gain on sale of CCC and certain subsidiaries to Murray Energy
Corporation in December 2013;
•
Operating cash flows increased $24 million in the period-to-period comparison due to changes in the gain on the sale of assets. See Note 3 - Acquisitions and Dispositions in the Notes to Audited Financial Statements in Item 8 of this Form 10-K for more information;
•
Return on equity earnings was related to $47 million IPO proceeds received from CONE Midstream Partners, LP and $55 million related to various other equity investment sales;
•
Other
Adjustments to reconcile net income to cash flow provided by operating activities increased due to $95 million on the loss on extinguishment of debt, and $110 million of additional depreciation, depletion, and amortization; and
•
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 increased $839 million in the period-to-period comparison primarily due to the following items:
•
Capital expenditures decreased $3 million due to:
•
Gas segment capital expenditures increased $135 million. The increase was comprised of a $267 million increase in drilling and completion costs in the Marcellus and Utica plays. This increase was partially offset by a decrease of $132 million in land acquisitions in Monroe and Noble Counties and various other individually insignificant projects.
•
Coal segment capital expenditures decreased $75 million. The decrease was comprised of
a $57 million decrease in various projects at Enlow Fork Mine. Capitalized Interest also decreased $17 million due to the completion of the Harvey Mine as well as an additional $21 million decrease in various miscellaneous transactions that occurred throughout both periods, none of which were individually material.
This decrease was partially offset by an increase of $16 million in capital projects at Harvey Mine; and
•
Other capital expenditures decreased $63 million. The decrease was comprised of a $53 million decrease in equipment lease buyouts as well as an additional $6 million decrease in various miscellaneous transactions that occurred throughout both periods, none of which were individually
material.
•
Proceeds from sale of assets, continuing operations, increased $127 million in the period-to-period comparison primarily due to $238 million received in 2013 related to the 2011 Noble Joint Venture Agreement, offset in part by various asset sales executed in each period. See Note 3 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
99
•
Net
investments in equity affiliates decreased $131 million primarily due to a $157 million increase on the return of investment from the IPO of CONE Midstream Partners, LP, offset by $87 million of additional capital contributions to CONE in 2014. The remaining increase was due to various changes in our equity partners, none of which were individually material. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
•
Restricted cash increased $69 million due to the release of $48 million associated with the Ram River & Scurry Canadian sale and $21 million associated with the Ryerson Dam Settlement, both of which occurred in the year ended December
31, 2012.
•
Discontinued operations changes increased $777 million primarily as a result of the gain on the sale of CCC and certain subsidiaries to Murray Energy Corporation in December 2013.
Net cash used in financing activities decreased $105 million in the period-to-period comparison primarily due to the following items:
•
Net
payments on short term borrowing were $22 million in 2014 versus $69 million in 2013.
•
In 2014, CONSOL Energy had net proceeds from long-term borrowings of $16 million related to the issuance of the 2022 Bonds offset by the extinguishment of the 2017 Bonds. See Note 14 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-K for additional details.
•
In 2014, CONSOL Energy paid four quarterly dividends totaling $58 million at an amount per share of $.0625. In 2013, CONSOL Energy
paid only three quarterly dividends totaling $86 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.
100
The
following is a summary of our significant contractual obligations at December 31, 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
141,680
149,556
25,025
1,543
317,804
Gas
Firm Transportation
108,791
188,756
156,583
453,871
908,001
Long-Term
Debt
5,052
8,406
3,511
3,224,505
3,241,474
Interest
on Long-Term Debt
214,576
429,288
428,954
386,231
1,459,049
Capital
(Finance) Lease Obligations
7,964
13,941
12,932
12,583
47,420
Interest
on Capital (Finance) Lease Obligations
3,110
4,594
2,848
899
11,451
Operating
Lease Obligations
104,232
181,631
85,773
78,954
450,590
Long-Term
Liabilities—Employee Related (a)
84,187
162,819
157,472
594,747
999,225
Other
Long-Term Liabilities (b)
342,098
239,472
83,426
336,184
1,001,180
Total
Contractual Obligations (c)
$
1,011,690
$
1,378,463
$
956,524
$
5,089,517
$
8,436,194
_________________________
(a)
Long-term
liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. CONSOL Energy does not expect to contribute to the pension in 2015.
(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.
Debt
At December 31, 2014, CONSOL Energy had total long-term debt and capital lease obligations of $3,289 million outstanding, including the current portion of long-term debt and capital lease obligations of $13 million. This long-term debt consisted of:
•
An
aggregate principal amount of $1,015 million of 8.25% senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.
•
An aggregate principal amount of $250 million of 6.375% notes due in March 2021. Interest on the notes is
payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.
•
An aggregate principal amount of $1,850 million of 5.875% notes due in April 2022 plus $7 million of unamortized bond premium. 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. Payment of the principal and interest on the notes is guaranteed by CONSOL Energy.
•
Advance royalty commitments of $13 million with an average interest rate of 7.91% per annum.
•
An
aggregate principal amount of $4 million on a note maturing through March 2018.
•
An aggregate principal amount of $47 million of capital leases with a weighted average interest rate of 6.56% per annum.
At December 31, 2014, CONSOL Energy had no outstanding borrowings
and approximately $244 million of letters of credit outstanding under the $2 billion senior secured revolving credit facility.
At December 31, 2014, CONSOL Energy had no outstanding borrowings and had $60 million of letters of credit outstanding under the accounts receivable securitization facility.
101
Total Equity and Dividends
CONSOL Energy had total
equity of $5.3 billion at December 31, 2014 compared to $5.0 billion at December 31, 2013. Total equity increased primarily due to net income, adjustments to actuarial liabilities, changes in the fair value of cash flow hedges, and the amortization of stock-based compensation awards. These increases were offset, in part, by the declaration of dividends and the issuance of treasury stock. See the Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for additional details.
Dividend information for the current year-to-date were as follows:
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 3.03 to 1.00 and the cumulative credit was approximately
$397 million at December 31, 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 year ended December 31,
2014.
CONSOL Energy has publicly announced that if CONSOL Energy effects an initial public offering of a thermal coal MLP, CONSOL Energy anticipates that it would reduce or eliminate its current regular dividend effective in the first quarter after the initial public offering.
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 Audited Consolidated Financial Statements. CONSOL Energy participates in the UMWA Combined Benefit Fund and the UMWA 1992 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 December 31, 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 this 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 balance sheet at December 31,
2014. Management believes these items will expire without being funded. See Note 24—Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details of the various financial guarantees that have been issued by CONSOL Energy.
102
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. Management is currently still evaluating the impact this guidance may have on CONSOL Energy's 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. Management believes 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 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. Management believes adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.
103
ITEM
7A.
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 related to changes in commodity prices, interest rates and foreign exchange rates.
CONSOL Energy is exposed to market price fluctuations and locational pricing differentials 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 and basis swaps to minimize exposure to market price volatility in the sale of natural gas. The Company's risk management policy prohibits the use of derivatives for speculative purposes. Until they were all de-designated on December 31, 2014, the Company's fixed price contracts qualified as cash-flow hedges under the Financial Accounting Standards Board Accounting Standards Codification. The Company's basis swaps
are designated as fair value hedges at December 31, 2014. For a summary of accounting policies related to derivative instruments, see Note 1 - Significant Accounting Policies in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K.
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 its risk assessment procedures and internal controls, mitigates its 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, management believes that use of these instruments will not have a material adverse effect on the Company's financial position or liquidity.
A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at December 31, 2014. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related
to derivatives by $45 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $29 million.
Excluding capital lease obligations, CONSOL Energy had $3.242 billion aggregate principal amount of debt outstanding under fixed-rate instruments at December 31, 2014. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to its revolving credit facility and accounts receivable securitization facility, under which there were no borrowings outstanding at December 31, 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.
Hedging
Volumes
As of January 15, 2015, 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
2015
Fixed Price Volumes
Hedged Bcf
29.9
30.2
30.6
30.5
121.2
Weighted
Average Hedge Price/Mcf
$
4.05
$
4.05
$
4.05
$
4.05
$
4.05
2016
Fixed Price Volumes
Hedged Bcf
23.5
23.5
23.8
23.9
94.7
Weighted
Average Hedge Price/Mcf
$
4.11
$
4.11
$
4.11
$
4.11
$
4.11
104
ITEM
8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CONSOL Energy Inc. and Subsidiaries
We
have audited the accompanying consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements
and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the
consolidated financial position of CONSOL Energy Inc. and Subsidiaries at December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance
with the standards of the Public Company Accounting Oversight Board (United States), CONSOL Energy Inc. and Subsidiaries' internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework and our report dated February 6, 2015 expressed an unqualified opinion thereon.
Current
Portion of Long-Term Debt (Note 14 and Note 15)
13,016
11,455
Other Accrued Liabilities (Note 13)
602,972
565,697
Current Liabilities
of Discontinued Operations (Note 2)
—
28,239
Total Current Liabilities
1,147,961
1,119,971
Long-Term Debt:
Long-Term
Debt (Note 14)
3,236,422
3,115,963
Capital Lease Obligations (Note 15)
39,456
47,596
Total Long-Term Debt
3,275,878
3,163,559
Deferred
Credits and Other Liabilities:
Deferred Income Taxes (Note 7)
325,592
242,643
Postretirement Benefits Other Than Pensions (Note 16)
703,680
961,127
Pneumoconiosis
Benefits (Note 17)
116,941
111,971
Mine Closing (Note 8)
306,789
320,723
Gas Well Closing (Note 8)
175,369
175,603
Workers’
Compensation (Note 17)
75,947
71,468
Salary Retirement (Note 16)
109,956
48,252
Reclamation (Note 8)
33,788
40,706
Other
158,171
131,355
Total
Deferred Credits and Other Liabilities
2,006,233
2,103,848
TOTAL LIABILITIES
6,430,072
6,387,378
Stockholders’ Equity:
Common
Stock, $.01 Par Value; 500,000,000 Shares Authorized, 230,265,463 Issued and Outstanding at December 31, 2014; 229,145,736 Issued and Outstanding at December 31, 2013
2,306
2,294
Capital in Excess of Par Value
2,424,102
2,364,592
Preferred
Stock, 15,000,000 Shares Authorized, None Issued and Outstanding
—
—
Retained Earnings
3,054,150
2,964,520
Accumulated Other Comprehensive
Loss - Continuing Operations
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
NOTE 1—SIGNIFICANT ACCOUNTING POLICIES:
A summary of the significant accounting policies of CONSOL Energy Inc. and subsidiaries (CONSOL Energy or the Company) is presented below. These, together with the other notes that follow, are an integral part
of the Consolidated Financial Statements.
Basis of Consolidation:
The Consolidated Financial Statements include the accounts of majority-owned and controlled subsidiaries. Investments in business entities in which CONSOL Energy does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. Investments in oil and gas producing entities are accounted for under the proportionate consolidation method. The accounts of variable interest entities, where CONSOL Energy is the primary beneficiary, are included in the Consolidated Financial Statements. All significant intercompany transactions and accounts have been eliminated in consolidation.
Discontinued
Operations:
Businesses to be divested are classified in the Consolidated Financial Statements as either discontinued operations or held for sale when the provision of Accounting Standards Codification (ASC) Topic 205 or ASC Topic 360 are met. For businesses classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities of discontinued operations on the Consolidated Balance Sheet and to discontinued operations on the Consolidated Statements of Income and Cash Flows, respectively, for all periods presented. The gains or losses associated with these divested businesses are recorded in discontinued operations on the Consolidated Statements of Income. Additionally, the accompanying notes, including segment information, do not include the assets, liabilities, or operating results of businesses classified as discontinued operations
for all periods presented. Management expects these businesses will be disposed of within one year, without any significant continuing involvement following their divestiture.
Use of Estimates:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates. The most significant estimates included in the preparation of the financial statements are related to other postretirement benefits, coal workers' pneumoconiosis, workers' compensation, salary retirement benefits, stock-based compensation, asset retirement obligations, deferred income tax assets and liabilities, contingencies, and the values of coal and
gas reserves.
Cash and Cash Equivalents:
Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.
Trade Accounts Receivable:
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CONSOL Energy reserves for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. CONSOL Energy regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged
off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Reserves for uncollectible amounts were not material in the periods presented. In addition, there were no material financing receivables with a contractual maturity greater than one year at December 31, 2014 or 2013.
113
Inventories:
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, amortization, and other related costs. The cost of merchandise for resale is determined by the last-in, first-out (LIFO) method and includes industrial maintenance, repair and operating supplies for sale to third parties. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in our coal and gas operations.
Property, Plant and Equipment:
CONSOL Energy uses the successful efforts method of accounting for gas producing activities. Costs of property acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination
cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are also amortized on a units-of-production method. Units-of-production amortization rates are revised at least once per year, or more frequently if events and circumstances indicate an adjustment is necessary; such revisions are accounted for prospectively as changes in accounting estimates.
Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Costs of additional mine facilities required to maintain
production after a mine reaches the production stage, generally referred to as “receding face costs,” are expensed as incurred; however, the costs of additional airshafts and new portals are capitalized. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred.
Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore or minerals before beginning the development stage of the mine.
Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which are costs incurred to make the mineral physically accessible, include costs to prepare property for
shafts, driving main entries for ventilation, haulage, personnel, construction of airshafts, roof protection and other facilities. Costs of developing the first pit within a permitted area of a surface mine are capitalized. A surface mine is defined as the permitted mining area which includes various adjacent pits that share common infrastructure, processing equipment and a common ore body. Surface mine development costs include construction costs for entry roads, drilling, blasting and removal of overburden in developing the first cut for mountain stripping or box cuts for surface stripping. Stripping costs incurred during the production phase of a mine are expensed as incurred.
Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized
costs. The Company employs this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once per year. Any material effect from changes in estimates is disclosed in the period the change occurs. Amortization of development cost begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine's production capacity and is not considered to shift the mine into the production phase.
Coal
reserves are controlled either through fee ownership or by lease. The duration of the leases vary; however, the lease terms generally are extended automatically through the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction and are legally considered real property interests. The Company also makes advance payments (advanced mining royalties) to lessors under certain lease agreements that are recoupable against future production, and it makes payments that are generally based upon a specified rate per ton or a percentage of gross realization from the sale of the coal. The Company evaluates its properties periodically for impairment issues or whenever events or circumstances
indicate that the carrying amount may not be recoverable.
Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production using the units-of-production method. Depletion of leased coal interests is computed using the units-of-
114
production method over proven and probable coal reserves. Advance mining royalties and leased coal interests are evaluated periodically, or at a minimum once per year, for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Any revisions are accounted for prospectively as changes in accounting estimates.
When
properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized as gain or loss in other income.
Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows:
Years
Buildings and improvements
10
to 45
Machinery and equipment
3 to 25
Leasehold improvements
Life of Lease
Costs to obtain coal lands are capitalized based on the cost at acquisition and are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned and accessible to the mine. Proven and probable coal reserves exclude non-recoverable coal reserves and anticipated processing losses. Rates are updated when revisions to coal reserve estimates
are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is produced. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material effect from changes in estimates is disclosed in the period the change occurs.
Costs for purchased and internally developed software are expensed until it has been determined that the software will result in probable future economic benefits and management has committed to funding the project. Thereafter, all direct costs of materials and services incurred in developing or obtaining software, including certain payroll and benefit costs of employees associated with the project, are capitalized and amortized using the straight-line method over the estimated
useful life which does not exceed seven years.
Impairment of Long-lived Assets:
Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the assets' carrying value. There was no impairment expense recognized for the years ended December 31, 2014, 2013,
and 2012.
CONSOL Energy performs a quantitative annual impairment test over proven producing wells using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. Utilizing these assumptions, there were undiscounted cash flows in excess of book value. As a result, no further impairment procedures were required. The Company's conventional gas assets are quantitatively and qualitatively close to triggering impairment. If gas prices continue to decrease, an impairment of these assets is possible in the near future.
Capitalized costs of unproved gas properties are evaluated for recoverability on a prospective
basis. Indicators of potential impairment include potential shifts in business strategy, overall economic factors and historical experience. If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period the determination is made. Exploration expense was $23,356, $61,104 and $39,005 for the years ended December 31, 2014, 2013 and 2012, respectively, which was primarily related to lease expirations.
Income Taxes:
Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in CONSOL
Energy's financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of CONSOL Energy's assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized.
115
CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination.
For positions that do not meet the more likely than not to be sustained criteria, the Company determines, on a cumulative probability basis, the largest amount of benefit that is more likely than not to be realized upon ultimate settlement. A previously recognized tax position is derecognized when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that the Company believes are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax position
liability. Actual results could differ from those estimates upon subsequent resolution of identified matters.
Restricted Cash:
For the year ended December 31, 2012, restricted cash included a $48,294 deposit into escrow associated with the Ram River Asset sale. The deposit was released upon CONSOL Energy's filing of all Canadian tax returns associated with the transaction. For the year ended December 31, 2012, restricted cash also included a $20,379 deposit into escrow as security to perfect CONSOL Energy's appeal to the Pennsylvania Environmental Hearing Board under the applicable statute related to the Ryerson Dam litigation. Both escrow accounts were released in the year ended December
31, 2013 and are reflected in the Change in Restricted Cash line included in Net Cash Used in Investing Activities of the Consolidated Statement of Cash Flows.
Postretirement Benefits Other Than Pensions:
Postretirement benefit obligations established by the Coal Industry Retiree Health Benefit Act of 1992 (the Health Benefit Act) are treated as a multi-employer plan which requires expense to be recorded for the associated obligations as payments are made. Postretirement benefits other than pensions, except for those established pursuant to the Health Benefit Act, are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the Financial Accounting Standards Board (FASB) Accounting Standards Codification which requires employers to accrue the cost of such retirement benefits for the employees' active
service periods. Such liabilities are determined on an actuarial basis and CONSOL Energy is primarily self-insured for these benefits. Differences between actual and expected results or changes in the value of obligations are recognized through Other Comprehensive Income.
Pneumoconiosis Benefits and Workers' Compensation:
CONSOL Energy is required by federal and state statutes to provide benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers' pneumoconiosis. CONSOL Energy is also required by various state statutes to provide workers' compensation benefits for employees who sustain employment related physical injuries or some types of occupational disease. Workers' compensation benefits include compensation for their disability, medical costs, and on some occasions, the cost of rehabilitation. CONSOL Energy is primarily
self-insured for these benefits. Provisions for estimated benefits are determined on an actuarial basis.
Mine Closing, Reclamation and Gas Well Closing Costs:
CONSOL Energy accrues for mine closing costs, reclamation costs, perpetual water care costs and dismantling and removing costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Depreciation of the capitalized
asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Operating and Other Costs on the Consolidated Statements of Income. Asset retirement obligations primarily relate to the closure of mines and gas wells, which includes treatment of water and the reclamation of land upon exhaustion of gas and coal reserves.
Accrued mine closing costs, perpetual care costs, reclamation and costs of dismantling and removing gas-related facilities are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements.
Retirement Plans:
CONSOL Energy has non-contributory defined benefit retirement
plans covering substantially all salaried and non-represented hourly employees. The benefits for these plans are based primarily on years of service and employees' pay near
116
retirement. These plans are accounted for using the guidance outlined in the Compensation - Retirement Benefits Topic of the FASB Accounting Standards Codification. The cost of these retiree benefits are recognized over the employees' service periods. CONSOL Energy uses actuarial methods and assumptions in the valuation of defined benefit obligations and the determination of expense. Differences between actual and expected results or changes in the value of obligations and plan assets are recognized through Other Comprehensive Income.
Revenue
Recognition:
Revenues are recognized when title passes to the customers. For gas sales, this occurs at the contractual point of delivery. For domestic coal sales, this generally occurs when coal is loaded at mine or offsite storage locations. For export coal sales, this generally occurs when coal is loaded onto marine vessels at terminal locations. For industrial supplies and equipment sales, this generally occurs when the products are delivered. For terminal, land and research and development, revenue is recognized generally as the service is provided to the customer.
CONSOL Energy has operational gas-balancing agreements with various interstate pipelines. These imbalance agreements are managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken by the purchaser.
CONSOL Energy sells
gas to accommodate the delivery points of its customers. In general this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty which qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are therefore recorded net in the Consolidated Statements of Income in Production Royalty Interest and Purchased Gas line.
CONSOL Energy purchases gas produced by third parties at market prices less a fee. The gas purchased from third party producers is then resold to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as Gas Royalty Interests and Purchased Gas Sales in the Consolidated Statements of Income. Purchased gas revenue is recognized
when title passes to the customer. Purchased gas costs are recognized when title passes to CONSOL Energy from the third party producer.
Royalty Interest Gas Sales represent the revenues related to the portion of production sold by CONSOL Energy that belongs to royalty interest owners.
Freight Revenue and Expense:
Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight-Outside Coal and Freight Expense, respectively.
Royalty Recognition:
Royalty expenses for gas rights are included in Production Royalty Interests and Purchased Gas Costs when the related revenue for the gas
sale is recognized. Royalty expenses for coal rights are included in Cost of Goods Sold and Other Operating Charges when the related revenue for the coal sale is recognized. These royalty expenses are paid in cash in accordance with the terms of each agreement. Revenues for gas and coal sold related to production under royalty contracts, versus owned by CONSOL Energy, are recorded on a gross basis.
Contingencies:
From time to time, CONSOL Energy, or our subsidiaries, is 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. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and management's intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.
117
Stock-Based
Compensation:
Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award's vesting term. See Note 19–Stock Based Compensation for further discussion.
Earnings per Share:
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 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:
Actuarially
Determined Long-Term Liability Adjustments*(Note 16 and Note 17)
Amortization of prior service costs
$
(22,381
)
$
(32,164
)
$
(53,853
)
Recognized
net actuarial loss
46,155
86,481
106,299
Curtailment gains
(36,182
)
—
—
Settlement
loss
29,095
39,482
—
Total
16,687
93,799
52,446
Tax
expense
(6,139
)
(35,806
)
(19,720
)
Net of tax
$
10,548
$
57,993
$
32,726
*Excludes
amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the years ended December 31, 2014, December 31, 2013 and December 31, 2012. Excludes $258,250, net of tax, of reclassifications of adjustments out of accumulated other comprehensive income related to discontinued operations for the year ended December 31, 2013.
Accounting for Derivative Instruments:
CONSOL Energy enters into financial derivative instruments to manage its exposure to commodity price volatility. The derivatives are accounted for as an
asset or a liability in the accompanying Consolidated Balance Sheets at their fair value using “Level Two” inputs, which is further defined in Note 22 - “Fair Value of Financial Instruments”. Changes in the fair values of derivatives are recorded in earnings unless special hedge accounting criteria are met. For derivatives designated as cash flow hedges, the effective portions of changes in the fair values of the derivatives are reported in Other Comprehensive Income or Loss (OCI) on the Consolidated Balance Sheets, net of tax, and reclassified into Natural Gas, NGLs and Oil Sales on the Consolidated
119
Statements of Income in the same period or periods in which the forecasted transactions affect earnings. Any ineffective
portion of a hedge is recognized in earnings in the current period.
CONSOL Energy formally assesses both at inception of the hedge and on an ongoing basis whether each derivative is highly effective for the purpose of 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.
On December 31, 2014, CONSOL Energy de-designated all of its derivative positions as hedging instruments. Subsequent changes in fair value will be recorded in current earnings. Deferred gains and losses in OCI as of that date will be recorded in earnings when the related physical transaction occurs or when it is determined that the physical transaction
is no longer probable of occurring.
All of CONSOL Energy’s derivative instruments are subject to master netting arrangements with its counterparties, none of which 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 be required to post collateral for hedges that are in a liability position in excess of defined thresholds. 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 is exposed to credit risk in the event of nonperformance by counterparties, whose creditworthiness is subject to continuing review. Historically, CONSOL Energy has not experienced any issues of non-performance by derivative counterparties.
Accounting for Business Combinations:
CONSOL Energy accounts for its business acquisitions under the acquisition method of accounting consistent with the requirements of the Business Combination Topic of the FASB Accounting Standards Codification. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment and often involves the use of significant
estimates and assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.
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. Management is currently still evaluating the impact this guidance may have on CONSOL Energy's 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
120
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. Management believes 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 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. Management believes adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.
Reclassifications:
Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2014, respectively, with no effect on previously reported net income or stockholders' equity.
Subsequent Events:
The
Company has evaluated all subsequent events through the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.
NOTE 2—DISCONTINUED OPERATIONS:
In December 2013, CONSOL Energy completed the sale of its Consolidation Coal Company (CCC) subsidiary, which included 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. 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.
For all periods presented in the accompanying Consolidated Statement of Income, the sale of CCC is classified as discontinued operations. There were no other active businesses classified as discontinued operations in the three-year period ended December 31,
2014.
In late 2013, CONSOL Energy reclassified CCC to discontinued operations based on the decision to divest the business. The Consolidated Financial Statements for all periods presented were reclassified to reflect the business in discontinued operations. The divestiture of the CCC was completed on December 5, 2013.
121
The following table details selected financial information for the divested business included within discontinued operations:
(Loss)
Income from discontinued operations before income taxes
$
(7,044
)
$
969,685
$
90,587
Income taxes benefit (expense)
1,357
(389,893
)
(20,473
)
(Loss)
Income from discontinued operations
$
(5,687
)
$
579,792
$
70,114
There were
no remaining major classes of assets or liabilities of discontinued operations at December 31, 2014. At December 31, 2013 current liabilities of discontinued operations were $ 28,239.
NOTE 3—ACQUISITIONS AND DISPOSITIONS:
On December 29, 2014, CNX Gas Company LLC (CNX Gas Company), a wholly-owned subsidiary of CONSOL Energy, finalized an agreement with Columbia Energy Ventures to sublease approximately 20,000 acres of Utica Shale and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West Virginia. Up-front bonus consideration
of up to $96,106 will be paid by CONSOL Energy over the next five years as drilling occurs in addition to royalties, of which $49,533 is recorded in Other Current Liabilities and $40,286 is recorded on a discounted basis in Other Long-Term Liabilities.
On December 18, 2014, CNX Gas Company sold approximately 1,700 net Utica Shale acres in Marshall County, West Virginia, for cash consideration of $25,337, all of which was recorded in Gain on Sale of Assets in CONSOL Energy’s Consolidated Statement of Income.
On
December 18, 2014, CONSOL Energy sold surface land at its Burning Star 5 properties in Franklin, Jackson, and Williamson Counties, Illinois to an unrelated third party for cash proceeds of $24,566. CONSOL Energy recorded a net gain on the sales of $22,085, which was included in Gain on Sale of Assets in the Consolidated Statement of Income.
On December 12, 2014, CONSOL Energy completed the sale of its industrial supplies subsidiary, to an unrelated third party for expected net proceeds of approximately $51,000, of which $44,035 was received and included in cash flows from investing activities during
the year ended December 31, 2014. In connection with the sale, CONSOL Energy signed a supply agreement under which, among other things, it will continue to purchase certain goods exclusively from the new entity for a period of at least three years. CONSOL Energy could also receive up to an additional $6,000 of cash consideration in the future, which has not been recognized in the consolidated financial statements as it is subject to future events. CONSOL Energy recorded a net loss on the sale of $30,845, which was included in Gain on Sale of Assets in the Consolidated Statement of Income.
In March 2014, CONSOL Energy completed a sale-leaseback of longwall shields for the Harvey Mine (formerly the BMX Mine Cash proceeds for the sale offset
the basis of $75,357; therefore, no gain or loss was recognized on the sale. The five- year lease has been accounted for as an operating lease.
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 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. Finally, CONSOL Energy has committed to be an anchor shipper on Dominion’s transmission system, with the specific terms to be negotiated at a future date. CONSOL Energy paid $91,243 in 2013 related to this transaction. In the year ended December 31, 2014, CONSOL Energy made an additional bonus payment of $16,000 to Dominion Transmission. Following the acquisition by CONSOL Energy, Noble Energy Inc., our joint venture partner, acquired 50% of the acres and reimbursed CONSOL Energy for 50% of the associated costs.
122
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 Gain on Sale of Assets 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 Gain on Sale of Assets in the Consolidated Statement of Income.
In
April 2013, the Company and the Commonwealth of Pennsylvania (Commonwealth) entered into a Settlement Agreement and Release 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 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, 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 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. At December 31, 2014, approximately 7.6% of the bonus payment continues to be held in 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 must spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and CNX Gas Company forgoes the bonus. Our joint venture partner, Noble Energy Inc., has acquired a 50%
interest in the acreage and accordingly, reimbursed CNX Gas Company for 50% of the associated costs during the year ended December 31, 2013.
On December 21, 2012, CONSOL Energy completed the disposition of its non-producing Ram River & Scurry Ram assets in Western Canada which consisted of 36 thousand acres of coal lands. In December 2012, cash proceeds of $51,869 were received related to this transaction. These proceeds were net of $637 in transaction fees. Additionally, a note receivable was recognized in 2012 related to the two additional cash payments to be received in June 2013 and June
2014. Payment of $25,500 was received in June 2013 and payment of $24,500 was received in June 2014. The gain on the transaction was $89,943 and was included in Gain on Sale of Assets in the Consolidated Statement of Income for the year ended December 31, 2012.
On June 29, 2012, CONSOL Energy completed the disposition of its non-producing Northern Powder River Basin assets in southern Montana and northern Wyoming for cash proceeds of $169,500. The assets consisted of CONSOL Energy's 50% interest in Youngs Creek Mining Company LLC, CONSOL Energy's 50%
interest in CX Ranch and related properties in and around Sheridan, Wyoming. The gain on the transaction was $150,677 and is included in Gain on Sale of Assets in the Consolidated Statement of Income for the year ended December 31, 2012. Additionally, CONSOL Energy retained an 8% production royalty interest on approximately 200 million tons of permitted fee coal.
On April 4, 2012, CONSOL Energy completed the disposition of its non-producing Elk Creek property in southern West Virginia, which consisted of 20 thousand acres of coal lands and surface rights, for proceeds of $26,000.
The gain on the transaction was $11,235 and is included in Gain on Sale of Assets in the Consolidated Statement of Income for the year ended December 31, 2012.
Interest on other payables for the years ended December 31, 2014 and December 31, 2012 includes a reversal of interest expense of $6,200 and $543, respectively, related to uncertain tax positions. Interest on other payables for the year ended December 31, 2013 includes interest expense of $1,369 related to uncertain tax positions. See Note 7–Income Taxes, for further discussion.
NOTE 6—
STOCK REPURCHASE:
In December 2014, CONSOL Energy’s Board of Directors approved a stock repurchase program under which CONSOL Energy may purchase from time to time up to $250,000 of its common stock over the next two years. Under the terms of the program, CONSOL Energy may make repurchases in the open market, in privately negotiated transactions, accelerated repurchase programs or in structured share repurchase programs. Any repurchases of common stock will be funded from available cash on hand or short-term borrowings. The program does not obligate CONSOL Energy to acquire any particular amount of common stock, and it may be modified or suspended at any time at the Company’s discretion. The program will be conducted in compliance with applicable legal requirements and with the limits imposed
by any credit agreement, receivables purchase agreement or indenture and shall be subject to market conditions and other factors. No purchases were made under this program through December 31, 2014.
124
NOTE 7—INCOME TAXES:
Income tax expense (benefit) provided on earnings from continuing operations consisted of:
**Valuation
allowance of $(6,096) has been allocated to long-term deferred tax asset for 2014. Valuation allowance of $(7,532) has been allocated to long-term deferred tax asset for 2013.
A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2014 and 2013, positive evidence considered included financial and tax earnings generated over the past three years for certain subsidiaries, future income
projections based on existing fixed price contracts and forecasted expenses, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence included financial and tax losses generated in prior periods and the inability to achieve forecasted results for those periods. CONSOL Energy continues to report, on an after federal tax basis, a deferred tax asset related to state operating losses of $49,638 with a related valuation allowance of $6,080 at December 31, 2014. The deferred tax asset related to state operating losses, on an after tax adjusted basis, was $51,765 with a related valuation allowance of $7,528
at December 31, 2013. A review of positive and negative evidence regarding these tax benefits concluded that the valuation allowances for various CONSOL Energy subsidiaries was warranted. The net operating losses expire at various times between 2015 and 2033.
The deferred tax assets attributable to future deductible temporary differences for certain CONSOL Energy subsidiaries with histories of financial and tax losses were also reviewed for positive and negative evidence regarding the realization of the deferred tax assets. A valuation allowance of $16 and $4
on an after federal tax adjusted basis, has also been recorded for 2014 and 2013 respectively. Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods, as appropriate, that could materially impact net income.
126
During 2014, the deferred tax asset relating to federal alternative minimum tax decreased $7,784. This change was due to 2014 business activity, the 2013 accrual
to 2013 return adjustments, the settlement of the 2008 and 2009 IRS audit, and the foreign tax credit claimed on amended returns.
The following is a reconciliation stated as a percentage of pretax income, of the United States statutory federal income tax rate to CONSOL Energy's effective tax rate:
Increase in unrecognized tax benefits resulting from tax positions taken during current period
—
—
Increase
(decrease) in unrecognized tax benefits resulting from tax positions taken during prior periods
4,265
—
Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations
(2,540
)
—
Reduction
of unrecognized tax benefits as a result of a settlement with taxing authorities
(32,246
)
—
Balance at end of period
$
4,265
$
34,786
If
these unrecognized tax benefits were recognized, $4,265 and $2,071 at December 31, 2014 and December 31, 2013 respectively, would have affected CONSOL Energy's effective income tax rate.
CONSOL Energy and its subsidiaries file income tax returns in the U.S. federal, various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for the years before 2010.
In
2014, CONSOL Energy recognized a reduction in unrecognized tax benefits. The IRS completed its audit of tax years 2008 and 2009 in 2014. Also, during 2014, the statute of limitations for assessing additional income tax deficiencies expired for certain tax years in several state tax jurisdictions. The expiration of the statute of limitations for these years resulted in an $2,071 benefit to net income for CONSOL Energy's total uncertain income tax positions for the twelve-month period.
CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. At December 31, 2014 there was no accrued interest related to unrecognized tax positions. As of December 31, 2013, the
Company had an accrued liability of $6,200 for interest related to uncertain tax positions, which was reversed and resulted in a benefit to income for the year ended December 31, 2014. Interest expense of $1,369 was recorded in the Company's Consolidated Statements of Income
127
for the year ended December 31, 2013. During the year ended December
31, 2014, CONSOL Energy paid $835 and $141 of interest related to income tax deficiencies for tax years 2008 and 2009, respectively.
CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2014 and 2013, there were no accrued penalties recognized.
NOTE 8—MINE CLOSING, RECLAMATION & GAS WELL CLOSING:
CONSOL Energy accrues for reclamation, mine closing costs, perpetual water care costs and dismantling and removing
costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes capitalized asset retirement costs by increasing the carrying amount of related long-lived assets. The obligation for asset retirements is included in Mine Closing, Reclamation, Gas Well Closing and Other Accrued Liabilities on the Consolidated Balance Sheets.
The reconciliation of changes in the asset retirement obligations at December 31, 2014 and 2013 is as follows:
For the year ended December 31, 2014, Other includes $(9,221) related to the disposition of the non-producing Hamilton Nos. 1 and 2 Mines (see Note 3 - Acquisitions and Dispositions), and $(4,325) related
to the completion of this transfer of permits at the former Jones Fork Mines. For the year ended December 31, 2013, Other includes $15,429 related to a contractual agreement between CONSOL Energy and Murray Energy whereby CONSOL Energy will retain the obligation of water treatment at sixteen locations sold to Murray Energy.
During the year ended December 31, 2014, CONSOL Energy sold its wholly owned subsidiary that accounted for its entire merchandise for resale balance, which was valued using the LIFO cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $18,836
at December 31, 2013 (See Note 3 - Acquisitions and Dispositions for details of the sale).
128
NOTE 10—ACCOUNTS RECEIVABLE SECURITIZATION:
CONSOL Energy and certain of its 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 receivables facility expires in March 2015. It
allows CONSOL Energy to receive, on a revolving basis, up to $125,000, subject to receivables eligibility criteria. CONSOL Energy may also issue letters of credit against the facility, which decreases the amount available to draw upon.
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, who 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, CONSOL Energy's collection experience history and the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of its 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 Topic 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.
At December 31, 2014 and December 31, 2013, eligible accounts receivable totaled $77,800 and $115,000, respectively. After taking into account outstanding letters of credit of $60,230 and $66,054, there remained $17,570 and $48,945 in subordinated retained interest at December 31,
2014 and December 31, 2013, respectively. CONSOL Energy management believes that the 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.
There were no borrowings under the securitization facility recorded on the Consolidated Balance Sheets at December 31, 2014 or December 31, 2013. The
Company drew $37,846 on the accounts receivable securitization facility in the year ended December 31, 2012, which was subsequently repaid in full the following year. These changes are reflected in the Net Cash Used In Financing Activities in the Consolidated Statement of Cash Flows.
The cost of funds under this facility is based upon LIBOR and commercial paper rates, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $892, $1,737 and $1,723 for the years ended December 31, 2014, 2013 and 2012,
respectively. These costs have been recorded as financing fees which are included in Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. No servicing asset or liability has been recorded at December 31, 2014.
Less
Accumulated Depreciation, Depletion and Amortization
4,512,305
4,136,247
Total Net Property, Plant and Equipment
$
10,162,472
$
9,442,262
The
following assets are amortized using the units-of-production method. Amounts reflect properties where mining or drilling operations have not yet commenced and therefore, are not being amortized for the years ended December 31, 2014 and 2013, respectively.
As
of December 31, 2014 and 2013, plant and equipment includes gross assets under capital lease of $87,055 and $96,015, respectively. For the years ended December 31, 2014 and 2013, the E&P division maintains a capital lease for the Jewell Ridge Pipeline of $66,919, which is included in Gas gathering equipment. For the years ended December 31, 2014 and 2013, the E&P division also maintains a capital lease for vehicles of $10,207 and $10,652,
respectively, which are included in Other gas assets. For the years ended December 31, 2014 and 2013, the All Other segment maintains capital leases for vehicles and computer equipment of $9,929 and $18,444, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was $49,735 and $50,371 at December 31, 2014 and 2013, respectively. Amortization expense for capital leases is included in Depreciation, Depletion and Amortization in the Consolidated Statements of Income. See Note 15–Leases for further discussion of capital leases.
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 is party to a joint development agreement with Hess Ohio Developments, LLC (Hess) with respect to approximately 153 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
130
certain
CONSOL Energy working interest obligations as the acreage is developed. As of December 31, 2014, Hess’ remaining carry obligation is $99,474.
CNX Gas Company is party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 702 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 $1,846,000 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 was in effect from March 1, 2014, and remained effective until November 1, 2014 when average natural gas prices had been below $4.00/MMbtu for the three prior months and continues to be suspended. Restrictions also include a $400,000 annual maximum on Noble Energy's carried cost obligation. As of December 31, 2014, Noble Energy’s remaining carry obligation is approximately$1,627,065.
NOTE
12—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 credit facility allows for up to $2,000,000 of borrowings, which includes a $750,000 letters of credit sub-limit. CONSOL Energy can request an additional $500,000 in the aggregate borrowing limit amount. The new senior revolving credit facility replaced CONSOL Energy's $1,000,000 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 $1,000,000 senior secured revolving credit facility of CNX Gas Corporation 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 year ended December 31, 2014.
The facility is secured by substantially all of the assets of
CONSOL Energy and certain of its subsidiaries. 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 contains a number of affirmative and negative covenants that limit the Company's 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 facility also requires that CONSOL Energy maintain
a minimum interest coverage ratio of 2.50 to 1.00 and a minimum current ratio of 1.00 to 1.00, each of which are measured quarterly. At December 31, 2014, the interest coverage ratio was 4.90 to 1.00 and the current ratio was 2.42 to 1.00. Further, the credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems and 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 E&P business immediately after the separation would not be greater than the 2.75 to 1.00.
At
December 31, 2014, the $2,000,000 facility had no borrowings outstanding and $244,418 of letters of credit outstanding, leaving $1,755,582 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.
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% including Amortization of Bond Premium
1,856,506
—
MEDCO
revenue bonds in series due September 2025 at 5.75%
102,865
102,865
Advance royalty commitments (7.91% and 7.93% weighted average interest rate for December 31, 2014 and 2013, respectively)
13,473
11,182
Other
long-term notes maturing at various dates through 2031 (total value of $4,473 and $5,923 less unamortized discount of $643 and $1,050 at December 31, 2014 and December 31,2013, respectively).
Annual undiscounted maturities on long-term debt during the next five years are as follows:
132
Year
ended December 31,
Amount
2015
$
4,480
2016
4,454
2017
2,944
2018
1,266
2019
904
Thereafter
3,235,692
Total
Long-Term Debt Maturities
$
3,249,740
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 15—LEASES:
CONSOL Energy uses various leased facilities and equipment in our operations. Future minimum lease payments under capital and operating leases, together
with the present value of the net minimum capital lease payments, at December 31, 2014, are as follows:
Rental
expense under operating leases was $126,078, $90,128, and $83,064 for the years ended December 31, 2014, 2013 and 2012, respectively.
At December 31, 2014, certain of the above operating leases for mining equipment were subleased to third parties. The following represents the minimum rental payments for those operating subleases:
2015
2016
2017
2018
2019
Thereafter
Total
$
26,685
$
26,685
$
26,685
$
26,685
$
13,343
$
—
$
120,083
CONSOL
Energy leases certain owned mining equipment to a third party under operating leases. The owned equipment included in gross property, plant and equipment was $31,059, with $6,212 accumulated depreciation at December 31, 2014.
At December 31, 2014, scheduled minimum rental payments for operating leases related to this equipment were as follows:
133
2015
2016
2017
2018
2019
Thereafter
Total
$
8,561
$
7,637
$
4,496
$
2,992
$
1,701
$
627
$
26,014
NOTE
16—PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:
Pension:
CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all salaried and non-represented hourly employees. The benefits for these plans are based primarily on years of service and employees' pay near retirement. CONSOL Energy's qualified pension plan allows for lump-sum distributions of benefits earned up until December 31, 2005, at the employees' election. On September 30, 2014, the qualified pension plan was amended to reduce future accruals of pension benefits as of December 31, 2014. The plan amendment called for a hard freeze of the defined benefit pension plan on December
31, 2014 for employees who were under age 40 or had less than 10 years of service as of September 30, 2014. In addition, employees hired or rehired on or after October 1, 2014 are not eligible to participate in the plan; however, 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 were age 40 or over and had at least 10 years of service as of September 30, 2014 will continue in the defined benefit pension plan unchanged. The modifications to the pension plan resulted in a $21,624 curtailment 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.
According to the Defined Benefit Plans Topic of the FASB Accounting Standards Codification, if the lump sum distributions made for the 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 from the pension plan exceeded this threshold during
the years ended December 31, 2014 and 2013. Accordingly, CONSOL Energy recognized expense of $29,095 and $39,482 for the years ended December 31, 2014 and 2013, respectively, in 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 charges noted above also resulted in remeasurements of the pension plan throughout 2014 and 2013.
Other Postretirement Benefit Plans:
Certain
subsidiaries of CONSOL Energy provide medical, prescription drug, and life insurance benefits to retired employees not covered by the Coal Industry Retiree Health Benefit Act of 1992 (the OPEB Plans). The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare. Also, salaried retirees contribute a target of 20% of the medical plan operating costs. Contributions may be higher, dependent on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared by CONSOL Energy and the participants based on their age and years of service at retirement. Annual cost increases in excess of 6% will be the responsibility of the participants. The eligibility requirements to participate in these plans are as follows:
•
Represented
hourly retirees are eligible to participate based upon the terms of the National Bituminous Coal Wage Agreement of 2011 or "The Coal Act."
•
For salaried or non-represented hourly retirees hired before January 1, 2007 that did not work in a corporate or operational support position, the eligibility requirement is either age 55 with 20 years of service or age 62 with 15 years of service for traditional retiree health coverage.
•
Salaried or non-represented hourly
retirees hired or re-hired on or after January 1, 2007 that did not work in a corporate or operational support position receive a retiree medical spending allowance of $2,250 per year for each year of service at retirement.
•
Retirees who worked in corporate or operational support positions at retirement receive a fixed annual retiree medical contribution into a Health Reimbursement Account. The amount of the contribution is dependent on several factors, and the money in the account can be used to help pay for a commercial medical plan, Medicare Part B or Part D premiums, and other qualified medical expenses
On
September 30, 2014, the plans were amended to reduce future benefits as of October 1, 2014. Salaried and non-represented hourly retirees as of September 30, 2014 will continue in the aforementioned OPEB plans, which are currently anticipated to remain unchanged, until December 31, 2019, and coverage thereafter will be eliminated. Further, effective September 30, 2014, retiree medical, prescription drug, and life insurance benefits are no longer provided to active employees. The Company elected to make cash transition payments totaling approximately $46,282 to the active employees whose retiree
medical, prescription
134
drug, and life insurance benefits were eliminated by the changes to the OPEB plans. These cash payments are not considered to be post-retirement benefits, and as such, they are not reflected in the actuarial calculations related to the OPEB plans. The amendment to the OPEB plans 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 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 also resulted in a remeasurement of the OPEB plan at September 30, 2014.
On December 5, 2013, CONSOL Energy completed the sale of its wholly-owned subsidiary Consolidation Coal Company and certain other subsidiaries to Murray Energy Corporation (the CCC Sale). As a result of the CCC Sale, the obligations for certain participants of the OPEB Plan are the primary responsibility of Murray Energy. This reduced CONSOL Energy's OPEB liability by $1,891,057
at December 31, 2013. These plan settlements resulted in adjustments of $339,318 in Other Comprehensive Income, net of $203,610 in deferred taxes at December 31, 2013. As the result of corporate staffing reductions associated with the sale, the Pension and OPEB plans also recognized curtailment gains of $374 and $39,650, respectively, for the year ended December 31, 2013. The curtailment gains resulted in adjustments of $231 and $24,515 in Other Comprehensive Income, net of $143 and $15,135
in deferred taxes for the Pension Plan and the OPEB plan, respectively, at December 31, 2013.
The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2014 and 2013, is as follows:
Expenses
(income) attributable to discontinued operations included in the net periodic cost (credit) above (including settlements and curtailments associated with the CCC Sale) were $8,231, and $11,587 for the years ended December 31, 2013 and 2012, respectively, for the Pension Plans and were $(1,293,975), and $101,418 for the years ended December 31, 2013 and 2012, respectively, for the OPEB Plans. There were no expenses attributable to discontinued operations in 2014.
Amounts included in accumulated other
comprehensive loss which are expected to be recognized in 2015 net periodic benefit costs:
Other
Pension
Postretirement
Benefits
Benefits
Prior
service credit recognition
$
(704
)
$
(58,546
)
Actuarial loss recognition
$
27,760
$
35,705
CONSOL
Energy utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the Pension Plan. Cumulative gains and losses that are in excess of 10% of the greater of either the projected benefit obligation (PBO) or the market-related value of plan assets are amortized over the expected average remaining future service of the current active membership for the Pension plan.
CONSOL Energy also utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the OPEB Plan. Cumulative gains and losses that are in excess of 10% of the greater of either the accumulated postretirement benefit obligation (APBO) or the market-related value of plan assets are amortized over the average future remaining lifetime of the current inactive population for the UMWA OPEB plan, and over the period of time remaining until the
plan sunsets for the Salaried and P&M OPEB plans.
The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan assets:
The
discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company plans'.
The weighted-average assumptions used to determine
net periodic benefit costs are as follows:
The
long-term rate of return is the sum of the portion of total assets in each asset class held multiplied by the expected return for that class, adjusted for expected expenses to be paid from the assets. The expected return for each class is determined using the plan asset allocation at the measurement date and a distribution of compound average returns over a 20-year time horizon. The model uses asset class returns, variances and correlation assumptions to produce the expected return for each portfolio. The return assumptions used forward-looking gross returns influenced by the current Treasury yield curve. These returns recognize current bond yields, corporate bond spreads and equity risk premiums based on current market conditions.
The assumed health care cost trend rates are as follows:
Rate
to which the cost trend is assumed to decline (ultimate trend rate)
4.50
%
4.50
%
4.50
%
Year that the rate reaches ultimate trend rate
2026
2026
2026
Assumed
health care cost trend rates have a significant effect on the amounts reported for the medical plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:
1-Percentage
1-Percentage
Point
Increase
Point Decrease
Effect on total of service and interest cost components
$
6,975
$
(5,779
)
Effect on accumulated postretirement benefit obligation
$
88,174
$
(74,274
)
Assumed
discount rates also have a significant effect on the amounts reported for both pension and other benefit costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:
138
0.25 Percentage
0.25
Percentage
Point Increase
Point Decrease
Pension benefit costs (decrease) increase
$
(1,955
)
$
1,914
Other
postemployment benefits costs (decrease) increase
$
(3,476
)
$
3,663
Plan Assets:
The company’s overall investment strategy is to meet current and future benefit
payment needs through diversification across asset classes, fund strategies and fund managers to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation. The target allocations for plan assets are 31 percent U.S. equity securities, 20 percent non-U.S. equity securities, 9 percent global equity securities, and 40 percent fixed income. Both the equity and fixed income portfolios are comprised of both active and passive investment strategies. The Trust is primarily invested in Mercer Common Collective Trusts. Equity securities consist of investments in large and mid/small cap companies with non-U.S. equities being derived from both developed and emerging markets. Fixed income securities consist of U.S. as well as international instruments, including emerging markets. The core domestic fixed income portfolios invest in government, corporate, asset-backed securities and mortgage-backed obligations. The
average quality of the fixed income portfolio must be rated at least “investment grade” by nationally recognized rating agencies. Within the fixed income asset class, investments are invested primarily across various strategies such that its overall profile strongly correlates with the interest rate sensitivity of the Trust’s liabilities in order to reduce the volatility resulting from the risk of changes in interest rates and the impact of such changes on the Trust’s overall financial status. Derivatives, interest rate swaps, options and futures are permitted investments for the purpose of reducing risk and to extend the duration of the overall fixed income portfolio; however they may not be used for speculative purposes. All or a portion of the assets may be invested in mutual funds or other comingled vehicles so long as the pooled investment funds have an adequate asset base relative to their asset class; are invested in a diversified manner; and have management
and/or oversight by an Investment Advisor registered with the SEC. The Retirement Board, as appointed by the CONSOL Energy Board of Directors, reviews the investment program on an ongoing basis including asset performance, current trends and developments in capital markets, changes in Trust liabilities and ongoing appropriateness of the overall investment policy.
The fair values of plan assets at December 31, 2014 and 2013 by asset category are as follows:
US
Long Duration Investment Grade Fixed Income (j)
57,713
—
57,713
—
55,593
—
55,593
—
US
Long Duration Fixed Income (k)
34,728
—
34,728
—
33,489
—
33,489
—
US
Large Cap Passive Equity (l)
75,219
—
75,219
—
75,468
—
75,468
—
US
Passive Fixed Income (m)
21,511
—
21,511
—
20,287
—
20,287
—
US
Long Duration Passive Fixed Income (n)
33,149
—
33,149
—
34,108
—
34,108
—
US
Ultra Long Duration Fixed Income (o)
12,555
—
12,555
—
7,656
—
7,656
—
US
Active Long Corporate Investment (p)
101,420
—
101,420
—
105,412
—
105,412
—
Long
Strips Fixed Income (q)
3,276
—
3,276
—
2,022
—
2,022
—
Opportunistic
Fixed Income (r)
2,026
—
2,026
—
2,097
—
2,097
—
Total
$
751,176
$
662
$
750,514
$
—
$
768,831
$
648
$
768,183
$
—
__________
(a)
This
category includes investments in US common stocks and corporate debt.
(b)
This category invests primarily in common stock of large cap companies in the U.S. with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Russell 1000 Growth Index.
(c)
This
category invests primarily in U.S. large cap companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Russell 1000 Value Index.
(d)
This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary
active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The smaller cap orientation of the strategy requires the
140
investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.
(e)
This category invests in small to mid-sized U.S. companies that appear to be undervalued relative to their intrinsic
value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Value Index.
(f)
This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S.
bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targeted to be within 20% of the benchmark’s duration. Total exposure to high yield issues is typically less than 10%, inclusive of direct investment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.
(g)
This category invests in all cap companies primarily operating in developed non-US markets, with some exposure to
emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the MSCI EAFE Index.
(h)
This category invests in companies operating in non-US emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing
in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the MSCI Emerging Markets Index.
(i)
This category invests in companies operating in developed markets, globally. The strategy targets a diversified portfolio of equity securities issued by companies which the investment managers believe will exhibit less volatility in their price performance relative to the broad equity market as described by the MSCI World Index. The strategy is benchmarked to the MSCI World Index.
(j)
This
category invests in a passively managed U.S. long duration corporate investment grade portfolio at a 90% weight and a passively managed U.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing for short term liquidity through a strategic allocation to US Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% to the Barclays Capital Long Treasury.
(k)
This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 15 years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds,
and TIPs. The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.
(l)
This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.
(m)
This category invests primarily in U.S.
dollar-denominated investment grade bonds and government securities. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Aggregate Index.
(n)
This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 15 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.
(o)
This category seeks to reduce the volatility of the plan’s funded
status and extend the duration of the assets by investing in a series of ultra long duration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return in excess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets to the plan’s liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.
(p)
This
category invests in a U.S. long duration corporate investment grade portfolio at a 90% weight and a U.S. long treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade corporate bonds with an emphasis on reducing default risk through active management while allowing for short term liquidity through a
141
strategic allocation to U.S. Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Corporate Index and 10% to the Barclay’s Capital Long Treasury.
(q)
This
category invests primarily in long dated U.S. Treasury STRIPS often with maturities greater than 20 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital U.S. 20+ Year STRIPS Index.
(r)
This category invests primarily in fixed income securities from issuers either located in developing/emerging markets or those rated below investment grade (high yield), globally. The strategy is benchmarked to a blended index of 50% JP Morgan Government Bond Index Emerging Markets Global Diversified and 50% Bank of America/Merrill Lynch Global High Yield Index.
There are no investments in CONSOL Energy stock
held by these plans at December 31, 2014 or 2013.
There are no assets in the other postretirement benefit plans at December 31, 2014 or 2013.
Cash Flows:
If necessary, CONSOL Energy intends to contribute to the pension trust using prudent funding methods. However, the Company does not expect to contribute to the pension plan
trust in 2015. Pension benefit payments are primarily funded from the trust. CONSOL Energy does not expect to contribute to the other postemployment plan in 2015 and intends to pay benefit claims as they are due.
The following benefit payments, reflecting expected future service, are expected to be paid:
Other
Pension
Postretirement
Benefits
Benefits
2015
$
59,425
$
57,279
2016
$
50,145
$
57,336
2017
$
49,854
$
57,180
2018
$
50,951
$
56,691
2019
$
52,457
$
56,007
Year
2020-2024
$
263,337
$
200,261
NOTE 17—COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION:
CONSOL Energy is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, for
medical and disability benefits to employees and their dependents resulting from occurrences of coal workers' pneumoconiosis disease. CONSOL Energy is also responsible under various state statutes for pneumoconiosis benefits. CONSOL Energy primarily provides for these claims through a self-insurance program. The calculation of the actuarial present value of the estimated pneumoconiosis obligation is based on an annual actuarial study by independent actuaries and uses assumptions regarding disability incidence, medical costs, indemnity levels, mortality, death benefits, dependents and interest rates which are derived from actual company experience and outside sources. Recent legislative changes have not been favorable for CWP. Although these changes have not had a significant impact on the liability, CONSOL has noticed an increase in claims. Actuarial gains or losses can result from differences in incident rates and severity of claims filed as compared to original assumptions.
CONSOL Energy must also compensate individuals who sustain employment-related physical injuries or some types of occupational diseases and, on some occasions, for costs of their rehabilitation. Workers' compensation laws will also compensate survivors of workers who suffer employment-related deaths. Workers' compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy primarily provides for these claims through a self-insurance program. CONSOL Energy recognizes an actuarial present value of the estimated workers' compensation obligation calculated by independent actuaries. The calculation is based on claims filed and an estimate of claims incurred but not yet reported as well as various assumptions, including discount rate, future healthcare trend rate, benefit
duration and recurrence of injuries. Actuarial losses associated with workers' compensation have resulted from discount rate changes and differences in claims experience and incident rates as compared to prior assumptions.
On December 5, 2013, CONSOL Energy completed the CCC Sale, in connection with which the obligations for certain participants of the CWP and Workers' Compensation plans were transferred to Murray Energy. These plan settlements reduced CONSOL Energy's CWP and Workers' Compensation liabilities by $49,652 and $105,308, respectively at December 31, 2013 and resulted in adjustments of $43,892 and $13,768 in Other Comprehensive Income,
net of $26,337 and $8,262 in deferred taxes for
142
CWP and Workers' Compensation, respectively, at December 31, 2013. The settlements were included in the results of discontinued operations.
State
administrative fees and insurance bond premiums
—
—
—
3,352
5,324
6,727
Settlement
gain
—
(119,881
)
—
—
(121,838
)
—
Net
periodic cost (credit)
$
5,015
$
(121,066
)
$
(4,058
)
$
16,328
$
(96,800
)
$
27,022
Including
settlements and curtailments associated with the CCC Sale, expenses (income) attributable to discontinued operations included in the net periodic cost (credit) were $(120,496), and $(2,374), respectively, for CWP and $(113,097) and $10,132, respectively, for Workers' Compensation for the years ended December 31, 2013, and 2012. No amounts were included in discontinued operations for the year ended December 31, 2014.
Following are amounts included in accumulated other comprehensive income that are expected to be recognized in 2015 net periodic benefit costs:
Workers'
CWP
Compensation
Benefits
Benefits
Actuarial
gain recognition
$
(5,576
)
$
(30
)
CONSOL Energy utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the Workers’ Compensation and CWP plans. Cumulative gains and losses that are in excess of 10% of the greater of either the estimated liability or the market-related value of plan assets are
amortized over the expected average remaining future service of the current active membership of the Workers’ Compensation and CWP plans.
Assumptions:
The weighted-average discount rates used to determine benefit obligations and net periodic cost (benefit) are as follows:
Discount
rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company's plans.
Assumed discount rates have a significant effect on the amounts reported for both CWP costs and Workers'
Compensation costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:
144
0.25 Percentage
0.25
Percentage
Point Increase
Point Decrease
CWP costs (decrease) increase
$
(134
)
$
138
Workers'
compensation costs (decrease) increase
$
(95
)
$
102
Cash Flows:
CONSOL Energy does not intend to make contributions to the CWP or Workers' Compensation plans in 2015, but it intends to pay benefit claims as they become due.
The following benefit payments, which reflect expected future claims as
appropriate, are expected to be paid:
Workers' Compensation
CWP
Total
Actuarial
Other
Benefits
Benefits
Benefits
Benefits
2015
$
9,156
$
17,101
$
13,795
$
3,306
2016
$
7,483
$
17,027
$
13,639
$
3,388
2017
$
6,802
$
17,123
$
13,650
$
3,473
2018
$
6,402
$
17,287
$
13,727
$
3,560
2019
$
6,207
$
17,443
$
13,794
$
3,649
Year
2020-2024
$
29,376
$
91,222
$
71,563
$
19,659
NOTE
18—OTHER EMPLOYEE BENEFIT PLANS:
UMWA Benefit Trusts:
The Coal Industry Retiree Health Benefit Act of 1992 (the Act) created two multi-employer benefit plans: (1) the United Mine Workers of America Combined Benefit Fund (the Combined Fund) into which the former UMWA Benefit Trusts were merged, and (2) the United Mine Workers of America 1992 Benefit Plan (1992 Benefit Plan). In connection with the sale of Consolidation Coal Company and certain subsidiaries, CONSOL Energy retained responsibility for the contributions to these two funds. CONSOL Energy accounts for required contributions to these multi-employer trusts as expense when incurred.
The Combined Fund provides medical and death benefits for all
beneficiaries of the former UMWA Benefit Trusts who were actually receiving benefits as of July 20, 1992. The 1992 Benefit Plan provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and for those who retired between July 20, 1992 and September 30, 1994. The Act provides for the assignment of beneficiaries to former employers and the allocation of unassigned beneficiaries (referred to as orphans) to companies using a formula set forth in the Act. The Act requires that responsibility for funding the benefits to be paid to beneficiaries be assigned to their former signatory employers or related companies. This cost is recognized when contributions are assessed. CONSOL Energy's total contributions under the Act
were $10,121, $11,435, and $12,358 for the years ended December 31, 2014, 2013 and 2012, respectively. Based on available information at December 31, 2014, CONSOL Energy's obligation for the Act is estimated to be approximately $110,864.
Pursuant to the provisions of the Tax Relief and Healthcare Act of 2006 (The 2006 Act) and the 1992 Benefit Plan, CONSOL Energy is required to provide security in an amount
based on the annual cost of providing health care benefits for all individuals receiving benefits from the 1992 Benefit Plan who are attributable to CONSOL Energy, plus all individuals receiving benefits from an individual employer plan maintained by CONSOL Energy who are entitled to receive such benefits. In accordance with the terms of the 2006 Act and the 1992 Benefit Plan, CONSOL Energy must secure its obligations by posting letters of credit, which were $21,394, $60,741, and $63,614 at December 31, 2014, 2013 and 2012, respectively. The 2014, 2013
and 2012 security amounts were based on the annual cost of providing health care benefits and included a reduction in the number of eligible employees. The 2014 security amount also reflects the further reduction in the number of eligible individuals receiving benefits from CONSOL Energy's individual employer plan as the result of the CCC Sale, in connection with which the Company's obligation for certain participants was transferred to Murray Energy.
145
Equity Incentive Plans:
CONSOL
Energy has an equity incentive plan that provides grants of stock-based awards to key employees and to non-employee directors. See Note 19–Stock Based Compensation for further discussion of CONSOL Energy's equity incentive plans.
Investment Plan:
CONSOL Energy has an investment plan available to all domestic, non-represented employees. Throughout the year ended December 31, 2014, the Company's matching contribution was 6% of eligible compensation contributed for all non-represented employees, except for those employees of Fairmont Supply Company, whose contribution was a match of 50% of the first 12% of eligible compensation contributed by the employee. Total payments and costs were $21,606, $23,748,
and $24,127 for the years ended December 31, 2014, 2013 and 2012, respectively.
In conjunction with the qualified pension plan changes, beginning January 1, 2015, the Company will contribute an additional 3% of eligible compensation into the 401(k) plan accounts for employees hired or rehired on or after October 1, 2014 or who were under age 40 or who had less than 10 years of service with the Company as of September
30, 2014.
Long-Term Disability:
CONSOL Energy has a Long-Term Disability Plan available to all eligible full-time salaried employees. The benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled.
Discount
rate assumption used to determine net periodic benefit costs
3.53
%
3.04
%
3.62
%
Expenses attributable to discontinued operations included in the net periodic cost (credit) above were $2,073 and $1,816 for
the years ended December 31, 2013 and 2012.
Liabilities incurred under the Long-Term Disability Plan are included in Other Accrued Liabilities and Deferred Credits and Other Liabilities–Other in the Consolidated Balance Sheets. and amounted to a combined total of $22,427 and $20,425 at December 31, 2014 and 2013, respectively. As a result of the CCC Sale, the obligations for certain participants of the
Long-Term Disability plan now belong to Murray Energy. This was accounted for as a plan settlement and resulted in an adjustment at December 31, 2013 of $1,338 in Other Comprehensive Income, which is net of $803 in deferred taxes. It also reduced CONSOL Energy's Long-Term Disability liability by $10,140 at December 31, 2013.
2012 Voluntary Severance Incentive Program (VSIP):
CONSOL Energy offered a VSIP to active salaried corporate and operation support employees with 30 years of service, or more. Under this program, eligible employees who accepted
the offer received a severance payment equal to one year's salary and any 2013 accrued vacation earned as of December 31, 2012. Approximately 100 employees volunteered for the program. Severance and vacation pay costs of $13,304 were accrued for the program at December 31, 2012, all of which was paid in 2013.
NOTE 19—STOCK-BASED COMPENSATION:
CONSOL Energy adopted the CONSOL Energy Inc. Equity Incentive Plan (the Equity Incentive Plan) on April 7, 1999. The Equity Incentive Plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments
to the Equity Incentive Plan have been approved by the Board of Directors since the commencement of the plan. Most recently, in May 2012, the Board of Directors approved an 8,000,000 increase to the total number of shares available for issuance, which brought the total number of shares of common stock that can be covered by grants to 31,800,000. At December 31, 2014, 4,367,713 shares of common stock remain available for all awards. The Equity Incentive Plan provides that the aggregate number of shares available for issuance will be reduced by one share for each share issued in settlement of stock options and by 1.62 for each share issued in settlement of Performance Share Units (PSUs), Restricted Stock Units (RSUs), or CONSOL Stock Units (CSUs). No award of stock options may be
exercised under the Equity Incentive Plan after the tenth anniversary of the effective date of the award.
For only those shares expected to vest, CONSOL Energy recognizes stock-based compensation costs on a straight-line basis over the requisite service period of the award, which is generally the vesting term, or to an employee's eligible retirement date, if earlier and applicable. Awards vest immediately if granted to retiree-eligible employees who are aged 62 and older. Awards vest
146
at the end of one year when granted to employees aged 55 to 62 and who have also completed ten years of service. Awards vest over a three year term at 33% per year to all other employees. The vesting of
all awards will accelerate in the event of death and disability and may accelerate upon a change in control of CONSOL Energy. See each specific award section for special vesting terms related to non-employee directors and other specific awards. The total stock-based compensation expense recognized during the years ended December 31, 2014, 2013 and 2012 was $41,877, $56,987 and $41,127, respectively. The related deferred tax benefit totaled $15,243, $21,769 and $15,464, for the years ended December 31,
2014, 2013 and 2012, respectively.
As of December 31, 2014, CONSOL Energy has $21,738 of unrecognized compensation cost related to all nonvested stock-based compensation awards, which is expected to be recognized over a weighted-average period of 1.89 years. When stock options are exercised and restricted and performance stock unit awards become vested, the issuances are made from CONSOL Energy's common stock shares.
Stock Options:
CONSOL Energy did not grant stock option awards during the years ended December
31, 2014 or 2013. The last awards were granted during 2012, at which time CONSOL Energy examined its historical pattern of option exercises in an effort to determine if there were any discernable activity patterns based on certain employee populations. From this analysis, CONSOL Energy identified two distinct employee populations and used the Black-Scholes option pricing model to value the options for each of the employee populations. The expected term computation presented in the table below is based upon a weighted average of the historical exercise patterns and post-vesting termination behavior of the two populations. The risk-free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S. Treasury obligations for the expected term of the award. The expected forfeiture rate is based upon historical forfeiture activity. A combination
of historical and implied volatility is used to determine expected volatility and future stock price trends. The total fair value of options granted during the year ended December 31, 2012 was $8,515, based on the following assumptions and weighted average fair values:
At
December 31, 2014, there are 3,912,402 stock options outstanding under the Equity Incentive Plan. Additionally, there are 100,066 fully vested employee stock options outstanding which vested under terms ranging from six months to one year. Non-employee director stock options vested 33% per year, beginning one year after the grant date. There are 30,561 fully vested stock options outstanding under these grants.
147
The aggregate intrinsic value in the table above represents the total pretax intrinsic
value (the difference between CONSOL Energy's closing stock price on the last trading day of the year ended December 31, 2014 and the option's exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2014. This amount varies based on the fair market value of CONSOL Energy's stock. The total intrinsic value of options exercised for the years ended December 31, 2014, 2013 and 2012 was $14,545, $6,820
and $18,562, respectively.
Cash received from option exercises for the years ended December 31, 2014, 2013 and 2012 was $15,011, $3,720 and $8,383, respectively. The tax impact from option exercises totaled $2,629, $2,929, and $8,678, for the years ended December 31, 2014, 2013
and 2012, respectively. This excess tax benefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.
Restricted Stock Units:
Under the Equity Incentive Plan, CONSOL Energy grants certain employees and non-employee directors restricted stock unit awards, which entitle the holder to shares of common stock as the award vests. Non-employee director restricted stock units vest at the end of one year. In 2014, restricted stock units were granted that will vest over a five year period unless certain market conditions are met, in which the award will accelerate. Compensation expense is recognized over the vesting period of the units, described above. The total fair value of restricted stock units granted during the years ended December 31, 2014,
2013 and 2012 was $31,360, $20,687 and $26,426, respectively. The total fair value of restricted stock units vested during the years ended December 31, 2014, 2013 and 2012 was $15,686, $37,002 and $23,097, respectively. The following represents the nonvested restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant:
Under the Equity Incentive Plan, CONSOL Energy grants certain employees performance share unit awards, which entitle the holder to shares of common stock subject to the achievement of certain market and performance goals. Compensation expense is recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification
for awards with market and performance vesting conditions. At December 31, 2014, achievement of the market and performance goals is believed to be probable. The total fair value of performance share units granted during the years ended December 31, 2014, 2013 and 2012 was $11,853, $1,270 and $16,794, respectively. The total fair value of performance share units vested during the years ended December 31, 2014, 2013
and 2012 was $18,759, $10,899 and $7,312, respectively. The following represents the nonvested performance share units and their corresponding fair value (based upon the closing share price) on the date of grant:
Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance options, which entitled the holder to shares of common stock subject to the achievement of certain performance goals. Compensation expense was recognized over the vesting period of the options, described above. The annual goals for the performance options included a gas cost goal and a gas production
goal, both of which were met at December 31, 2014. Achievement of the gas production goal for the year ended December 31, 2012 did not occur and resulted in a reversal of compensation expense of $1,671 for the year ended December 31,
148
2012. The Black-Scholes option valuation model was used to value each tranche separately. The total fair value of performance options vested during the years ended December 31, 2014, 2013
and 2012 was $4,949, $1,650 and $6,599, respectively. No performance stock options were exercised during the year ended December 31, 2014. All of the performance options vested and the following represents their corresponding fair value (based upon the closing share price) at the date of grant:
Under the Equity Incentive Plan, CONSOL Energy granted certain employees CONSOL Stock Unit Awards, which entitled the holder to shares of common stock subject to the achievement of certain market and performance goals. Compensation expense was recognized over the performance measurement period of the units in accordance with the provisions
of the Stock Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. CONSOL Energy used the Monte Carlo methodology to estimate the fair value of the CONSOL Stock Units. At December 31, 2014, the achievement of the market and performance goals is believed to be probable. The total fair value of CONSOL Stock Units granted during the years ended December 31, 2014 and 2013 was $189 and $28,381, respectively. The following represents the nonvested CONSOL Stock Unit awards and their corresponding fair value (based upon the closing share
price) at the date of grant:
The following are non-cash transactions that impact the investing and financing activities of CONSOL Energy. For non-cash transactions that relate to acquisitions and dispositions, see Note 2 - Discontinued Operations and Note - 3 Acquisitions and Dispositions.
CONSOL
Energy obtains capital lease arrangements for company-used vehicles. For the years ended December 31, 2014, 2013 and 2012, CONSOL Energy entered into non-cash capital lease arrangements of $1,572, $4,178, and $3,583, respectively.
As of December 31, 2014, 2013 and 2012, CONSOL Energy purchased goods and services related to capital projects in the amount of $74,292, $40,870
and $63,051, respectively, that are included in accounts payable.
During the year ended December 31, 2012, CONSOL Energy entered into a promissory note for $6,236 with the lessor of its former headquarters to replace the existing operating lease.
The following table shows cash paid (received) during the year for:
NOTE
21—CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS:
CONSOL Energy markets natural gas primarily to gas wholesalers, thermal coal principally to electric utilities in the United States, Canada and Western Europe and metallurgical coal to steel and coke producers worldwide.
Total Accounts Receivable Trade (including Accounts Receivable—Securitized)
$
259,817
$
332,574
Accounts
receivable from thermal coal utilities and steel and coke producers include amounts sold under the accounts receivable securitization facility. See Note 10–Accounts Receivable Securitization for further discussion. Credit is extended based on an evaluation of the customer's financial condition, and generally collateral is not required. Credit losses have been consistently minimal.
During the year ended December 31, 2014, coal sales to Duke Energy were $394,849 and coal sales to Xcoal Energy Resources were $344,617, each of which comprised over 10% of the Company's revenues.
During
the year ended December 31, 2013, coal sales to Xcoal Energy Resources were $495,242 and coal sales to Duke Energy were $346,424, each of which comprised over 10% of the Company's revenues.
During the year ended December 31, 2012, coal sales to Xcoal Energy Resources were $382,843, which was over 10% of the Company's revenues.
NOTE
22—FAIR VALUE OF FINANCIAL INSTRUMENTS:
CONSOL Energy determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including NYMEX forward curves, LIBOR-based discount rates and basis forward curves), while unobservable inputs reflect the
Company's own assumptions of what market participants would use.
The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below.
Level One - Quoted prices for identical instruments in active markets.
Level Two - 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.
Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity. The significant unobservable inputs used in the fair value measurement of the Company's
third party guarantees are the credit risk of the third party and the third party surety bond markets. A significant increase or decrease in these values, in isolation, would have a directionally similar effect resulting in higher or lower fair value measurement of the Company's Level 3 guarantees.
In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.
150
The
financial instruments measured at fair value on a recurring basis are summarized below:
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:
Cash
and cash equivalents represent highly-liquid instruments and constitute Level 1 fair value measurements. Certain of the Company’s debt is actively traded on a public market and, as a result, constitute Level 1 fair value measurements. The portion of the Company’s debt obligations that are not actively traded are valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.
NOTE 23—DERIVATIVE INSTRUMENTS:
CONSOL Energy enters into financial
derivative instruments to manage our exposure to commodity price volatility. CONSOL Energy derivatives that meet the criteria for cash flow hedge accounting, reflect changes in their fair values in Other Comprehensive Income.
CONSOL Energy’s derivative instruments that qualified for cash flow hedge accounting are for a total notional amount of production of 215.9 billion cubic feet. On December 31, 2014, CONSOL Energy de-designated all of its cash flow hedges and will account for all existing and future gas commodity hedges on a mark-to-market basis with changes in fair value recorded in current period earnings. In connection with this change, CONSOL Energy froze the balances recorded in Accumulated Other Comprehensive Income at December 31, 2014 and will reclassify balances
to earnings as the underlying physical transactions occur, unless it is no longer probable that the physical transaction will occur at which time the related OCI will be immediately recorded in earnings. The gross fair value of CONSOL Energy's derivative instruments that were de-designated from cash flow hedge treatment on December 31, 2014 was an asset of $192,332, of which $123,676 was included in Prepaid Expense and $68,656 which was included in Other Assets on the Consolidated Balance Sheets. CONSOL Energy expects to reclassify $78,051 out of Accumulated Other Comprehensive Income into Natural Gas, NGLs and Oil Sales on the Consolidated Statements of Income during the year ending December
31, 2015.
In November 2014, CONSOL Energy entered into basis only swaps that did not qualify for hedge accounting. The swaps were entered into to decrease the risk related to pricing differences between local markets and NYMEX. At December 31, 2014, the fair values of these swaps, which were for notional amounts of 10.6 billion cubic feet, were $1,064 that was recorded in Prepaid Expenses and $327 that was recorded in Other Current Liabilities in the Consolidated Balance Sheets. The basis only swaps resulted in $737 being recorded in Natural Gas, NGLs and Oil Sales on the Consolidated Statements of Income during the year ending December
31, 2014.
At December 31, 2013 the gross fair values of CONSOL Energy's derivative instruments resulted in assets of $83,661 and liabilities of $18,212. The total assets were comprised of $59,605 that were recorded in Prepaid Expense and $24,056 which were included in Other Assets on the Consolidated Balance Sheets. The total liabilities were comprised of $12,327 which were recorded
151
in Other Accrued Liabilities
and $5,885 which were included Other Liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2013 and 2012, no gains were reclassified into earnings as a result of the discontinuance of cash flow hedges.
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, were as follows:
Less: Gain reclassified from Accumulated OCI into Outside Sales
$
18,288
$
79,899
$
189,259
Ending
Balance – Accumulated OCI
$
121,521
$
42,493
$
76,761
Gain (Loss) recognized in Outside Sales for ineffectiveness
$
4,168
$
(4,645
)
$
579
There
were no amounts recognized in earnings related to the amounts excluded from the assessment of hedge effectiveness in 2014, 2013 or 2012.
NOTE 24—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 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 $388,986.
The
following lawsuits and claims include those for which a loss is probable and an accrual has been recognized.
Hale Litigation: This class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia. 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 damages based on allegations 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 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: This class action lawsuit was filed on April
28, 2010 in the United States District Court in Abingdon, Virginia. The putative 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 the case has meritorious defenses, and intends to defend it vigorously. We have established
152
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.
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. 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 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. The appeal is fully briefed, and a panel of the Superior Court heard argument on December 10, 2014.
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. The parties have recently reached a settlement in principle of this matter, which will be dismissed with prejudice.
At December 31, 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.
153
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
$
150,042
$
124,536
$
25,506
$
—
$
—
Environmental
5,509
5,509
—
—
—
Other
149,097
141,337
7,760
—
—
Total
Letters of Credit
304,648
271,382
33,266
—
—
Surety
Bonds:
Employee-Related
223,579
223,579
—
—
—
Environmental
598,877
598,877
—
—
—
Other
24,437
24,436
—
—
1
Total
Surety Bonds
846,893
846,892
—
—
1
Guarantees:
Coal
133,600
100,200
33,400
—
—
Other
61,571
34,974
8,822
8,367
9,408
Total
Guarantees
195,171
135,174
42,222
8,367
9,408
Total
Commitments
$
1,346,712
$
1,253,448
$
75,488
$
8,367
$
9,409
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 Corporation (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 December 31, 2014, the fair value of these guarantees was $1,275 and were
included in Other Accrued Liabilities 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 December 31, 2014, the purchase obligations for each of the next five years and beyond were as follows:
Obligations Due
Amount
Less
than 1 year
$
250,471
1 - 3 years
338,312
3 - 5 years
181,608
More than 5 years
455,414
Total
Purchase Obligations
$
1,225,805
154
NOTE 25—SEGMENT INFORMATION:
CONSOL
Energy consists of two principal business divisions: Exploration and Production (E&P) and Coal. The principal activity of the E&P division, which includes four reportable segments, is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The E&P division's reportable segments are Marcellus, Utica, Coalbed Methane, and Other Gas. The Other Gas segment is primarily related to conventional oil and gas production as well as Upper Devonian Shale, and includes the Company's purchased gas activities and general and administrative activities, as well as various other activities assigned to the Gas 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 three reportable segments, which are Pennsylvania (PA) Operations, Virginia (VA) Operations, and Other Coal. Each of these reportable segments includes a number of operating segments (which are individual mines or the type of coal sold). For the year ended December 31, 2014, the PA Operations aggregated segment includes the following mines: Bailey, Enlow Fork, and Harvey Mines and the corresponding preparation plant facilities. For the year ended December 31, 2014, the VA Operations aggregated segment includes the Buchanan Mine and the corresponding preparation plant facilities. For the year ended December 31, 2014, the Other
Coal segment includes, Miller Creek Complex, coal terminal operations, the Company's purchased coal activities, idled mine activities and 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 division includes industrial supplies (sold December 2014 - See Note 3 - Acquisitions and Dispositions) and various other corporate expenses that are not allocated to the E&P or Coal segment.
In the preparation of the following information, 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 for E&P and are not allocated
between each individual E&P segment. These assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy, whereby 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.
Total
Revenues and Freight from External Customers (K)
$
3,476,100
$
3,120,722
$
3,282,350
_________________________
(J) CONSOL
Energy attributes revenue to individual countries based on the location of the customer.
(K) CONSOL Energy has contractual relationships with certain U.S. based customers who distribute coal to international markets. The table above reflects the ultimate destination of CONSOL Energy coal.
CONSOL Energy's Property, Plant and Equipment by geographical location are:
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 $1,856,506, 5.875% per annum senior notes due April 15, 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.
Net
Increase (Decrease) in the Value of Cash Flow Hedge
114,240
114,240
—
—
(114,240
)
114,240
Reclassification
of Cash Flow Hedge from OCI to Earnings
(189,259
)
(189,259
)
—
—
189,259
(189,259
)
Other
Comprehensive Income (Loss):
$
54,212
$
(75,019
)
$
129,231
$
—
$
(54,212
)
$
54,212
Comprehensive
Income (Loss)
442,682
(50,656
)
677,183
80,690
(707,614
)
442,285
Less: Net
Loss Attributable to Noncontrolling Interests
—
(397
)
—
—
—
(397
)
Comprehensive
Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
$
442,682
$
(50,259
)
$
677,183
$
80,690
$
(707,614
)
$
442,682
168
NOTE
27—RELATED PARTY TRANSACTIONS
On September 30 2011, CNX Gas Company and Noble Energy, Inc. (Noble Energy), an unrelated third party and joint venture partner, formed CONE Gathering LLC to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CONSOL Energy accounts for CNX Gas Company's 50% ownership interest in CONE Gathering LLC under the equity method of accounting.
On May 30, 2014, CONE Gathering LLC formed CONE Midstream Partners, LP (the Partnership). On September 30, 2014, CONE Gathering LLC contributed certain assets and liabilities to the Partnership, which closed on an initial public offering of 20,125,000
of its common units at a per unit price of $22.00, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters (the CONE IPO). The Partnership received net proceeds of $413,005 in connection with the CONE IPO, which is net of underwriting discounts, commissions, structuring fees and other offering expense of $29,745. The Partnership distributed $203,986 of the net proceeds from the CONE IPO to CNX Gas Company, which CONSOL Energy recorded as a return on equity investments within cash flows from operating activities and as a net investment in equity affiliates within cash flows from investing activities, pursuant to the cumulative earnings approach. Under this approach, all distributions received
by the investor are deemed to be returns on the investment unless the cumulative distributions exceed the cumulative equity in earnings recognized by the investor. The excess distributions are deemed to be returns of the investment and are classified as investing cash flows.
Following the CONE IPO, CONE Gathering LLC has a 2% general partner interest in the Partnership, while each sponsor has a 32.1% limited partner interest. CNX Gas Company accounts for its portion of the earnings in the Partnership under the equity method of accounting. At December 31, 2014, CNX Gas Company and Noble Energy each continue to own a 50% interest in the assets of CONE Gathering LLC that were not contributed to the Partnership.
During the years ended
December 31, 2014 and 2013, CONE Gathering LLC (prior to September 30, 2014) and the Partnership (after September 30, 2014) provided gathering services to CNX Gas Company in the ordinary course of business totaling $65,584 and $35,765 respectively. These costs were included in Exploration and Production Costs - Transportation, Gathering and Compression on CONSOL Energy’s accompanying Consolidated Statements of Income. At December 31, 2014 and December 31, 2013, CONSOL Energy had a net payable of $21,535 and $5,448
respectively, due to both the Partnership and CONE Gathering LLC primarily for accrued but unpaid gathering services.
169
Supplemental Gas Data (unaudited):
The following information was prepared in accordance with the FASB's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).”
Average gas sales price before effects of financial settlements (per Mcf)
$
4.26
$
3.85
$
3.00
Average
effects of financial settlements (per Mcf)
$
0.11
$
0.45
$
1.22
Average gas sales price including effects of financial settlements
(per Mcf)
$
4.37
$
4.30
$
4.22
Average lifting costs, excluding ad valorem and severance taxes (per Mcf)
$
0.50
$
0.56
$
0.58
During
the years ended December 31, 2014, 2013 and 2012, we drilled 180.3, 139.8, and 95.5 net development wells, respectively. There were no net dry development wells in 2014, 2013, or 2012.
During the years ended December 31, 2014, 2013 and 2012, we drilled 8.5, 5.5, and 22.0 net exploratory wells, respectively. There were no net dry exploratory wells in 2014 or 2013, and 9.5 net dry exploratory wells in 2012.
At December 31, 2014, there were 52.0 net development wells and
2.5 net exploratory wells in the process of being drilled.
We are committed to provide 153.5 Bcf of gas under existing sales contracts or agreements over the course of the next four years. We expect to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.
Most of our development wells and proved acreage are located in Virginia, West Virginia and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2014, the number of producing wells, developed acreage and undeveloped
acreage:
171
Gross
Net(1)
Producing Gas Wells (including
gob wells)
17,044
12,918
Producing Oil Wells
154
34
Proved
Developed Acreage
537,935
515,439
Proved Undeveloped Acreage
112,617
63,801
Unproved
Acreage
4,946,174
3,933,975
Total Acreage
5,596,726
4,513,215
____________
(1)
Net
acres include acreage attributable to our working interests of the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
Proved Oil and Gas Reserves Quantities:
Annually, the preparation of gas reserves estimates are completed in accordance with CONSOL Energy's prescribed internal control procedures, which include verification of input data into a gas reserves forecasting and economic evaluation software, as well as multi-functional management review. The input data verification includes reviews of the price and cost assumptions
used in the economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer with over 10 years of experience in the oil and gas industry. Our 2014 gas reserves results, which are reported in the Supplemental Gas Data year ended December 31, 2014 Form 10-K, were audited by Netherland Sewell. The technical person primarily responsible for overseeing the audit of our reserves is a registered professional engineer in the state of Texas with over 15 years of experience in the oil and gas industry. The gas reserves estimates are as follows:
Revisions
are primarily due to corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas and reservoirs. These changes along with upward revisions attributable to efficiencies in operations and well performance had the total affect of the positive revisions for 2013 and 2012.
(b)
Extensions and Discoveries in 2013 and 2012 are primarily due to the addition of wells on our Marcellus Shale acreage more than one offset location away with reliable technology.
(c)
Proved developed
and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CONSOL Energy cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.
(d)
Revisions
for 2014 are primarily due to efficiencies in operations and well optimization and had the total effect of positive revisions. Additionally, the 2014 revisions include a reclassification of ethane volumes from natural gas to NGLs.
(e)
Extensions and Discoveries in 2014 are primarily due to the addition of wells on our Marcellus and Utica Shale acreage. We also included Marcellus Shale wells which are more than one offset location away due to continued use of reliable technology.
During 2014, various exploration and development drilling and evaluations were completed. Approximately, $389,838
of capital was spent in the year ended December 31, 2014 related to undeveloped reserves that were transferred to developed.
(b) Plan and other revisions are due to corporate planning changes that affect the number of wells forecasted to be drilled in our various areas and reservoirs. These changes along with upward revisions attributable to efficiencies in operations and well performance had the total affect of a positive revision.
(c)
Included in proved undeveloped reserves at December 31, 2014 are approximately 212,161 MMcfe of reserves that have been
reported for more than five years. These reserves specifically relate to CONSOL Energy's Buchanan Mine, more specifically, to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine. Evidence also exists that supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance which resulted from an external factor. These reasons constitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.
(d)
Included in proved
undeveloped reserves at December 31, 2014 are 229 gross proved undeveloped locations that generate positive future net revenue but have negative present worth discounted at 10 percent as of December 31, 2014, representing 12.1% of our total proved undeveloped reserves. Additionally, the 438.8 Bcfe of natural gas and equivalents attributable to these locations represent approximately 6.4% of our total proved reserves. The Company includes these well sites in its current drilling plans and currently intends to drill these sites as our economic modeling of these well locations generate positive future cash flows.
The following table represents the capitalized exploratory well cost activity as indicated:
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves
$
27,453
$
12,140
$
14,447
Costs
expensed due to determination of dry hole or abandonment of project
$
2,041
$
8,596
$
3,320
CONSOL Energy's proved gas reserves
are located in the United States.
174
Standardized Measure of Discounted Future Net Cash Flows:
The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year ended December 31, 2014. Because prices used in the calculation are average prices for that year, the standardized
measure could vary significantly from year to year based on the market conditions that occurred.
The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CONSOL Energy. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CONSOL Energy's investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and cost assumptions.
The standardized measure is intended to provide a better means for comparing the value of CONSOL Energy's proved reserves
at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.
Proved
and probable reserves at beginning of period
3,032
4,229
4,314
4,229
4,350
Purchased
reserves
—
1
—
6
4
Reserves
sold in place
(233
)
(1,199
)
(155
)
—
(41
)
Production
(32
)
(55
)
(55
)
(62
)
(62
)
Revisions
and other changes
471
56
125
141
(22
)
Consolidated
proved and probable reserves at end of period*
3,238
3,032
4,229
4,314
4,229
Proportionate
share of proved and probable reserves of unconsolidated equity affiliates (excluded from the table above)*
55
57
41
145
172
______________
* Proved
and probable coal reserves are the equivalent of “demonstrated reserves” under the coal resource classification system of the U.S. Geological Survey. Generally, these reserves would be commercially mineable at year-end prices and cost levels, using current technology and mining practices.
CONSOL Energy's coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2014, 319 million tons were assigned to mines either in production or temporarily idled. The proved and probable reserves at December 31, 2014 include 2,759 million tons of thermal coal reserves, of which approximately 5
percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million British thermal unit (Btu), 17 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu and an additional 78 percent has a sulfur content equivalent to greater than 2.5 pounds sulfur dioxide per million Btu. The reserves also include 480 million tons of metallurgical coal in consolidated reserves, of which approximately 41 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu and an additional 59 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu.
Our estimate of proven and
probable coal reserves has been determined by CONSOL Energy’s geologists and mining engineers. CONSOL Energy geologists and mining engineers completed an extensive re-evaluation of the longwall mineable Pittsburgh and Illinois No. 5 seams during 2014. The re-evaluations included the use of mine specific assumptions and mine plans versus general mine recovery factors and general parameters. To date, approximately 50% of CONSOL Energy’s reserves have been re-evaluated using mine specific parameters as opposed to an assumed average mining recovery factor. The 2014 re-evaluations resulted in 407 million of the total 471 million additional tons of proven and probable reserves added as result of revisions and other changes in 2014. During 2014, Golder Associates (Golder) audited approximately 86% of the above revisions and other changes that occurred in 2014.
Net
(Loss) Income Attributable to CONSOL Energy Inc Shareholders
$
(1,564
)
$
(12,526
)
$
(63,651
)
$
738,183
Earnings
Per Share
Basic:
(Loss)
Income from Continuing Operations
$
(0.02
)
$
0.04
$
(0.31
)
$
0.64
Income
(Loss) from Discontinued Operations
$
0.01
$
(0.09
)
$
0.03
$
2.59
Net
(Loss) Income
$
(0.01
)
$
(0.05
)
$
(0.28
)
$
3.23
Dilutive:
(Loss)
Income from Continuing Operations
$
(0.02
)
$
0.04
$
(0.31
)
$
0.64
Income
(Loss) from Discontinued Operations
$
0.01
$
(0.09
)
$
0.03
$
2.57
Net
(Loss) Income
$
(0.01
)
$
(0.05
)
$
(0.28
)
$
3.21
(A)
Includes natural gas, NGLs, and oil sales; coal sales; other outside sales; and gas royalty interests and purchased gas sales.
(B) Includes exploration and production costs, coal costs, and miscellaneous operating expense, excluding DD&A, other corporate expenses, general and administrative, and freight expense.
177
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
ITEM
9A.
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 Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Annual Report on Form 10-K. 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 December 31, 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.
Management's Annual Report on Internal Control Over Financial Reporting. CONSOL
Energy's management is responsible for establishing and maintaining adequate internal control over financial reporting. CONSOL Energy's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
CONSOL Energy's internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and
the directors of CONSOL Energy; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of CONSOL Energy's assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of CONSOL Energy's internal control over financial reporting as of December 31,
2014. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (COSO) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management has concluded that CONSOL Energy maintained effective internal control over financial reporting as of December 31, 2014.
The effectiveness of CONSOL Energy's internal control over financial reporting as of December 31, 2014 has been audited by Ernst and Young, an independent registered public accounting firm, as stated in their report set forth in the Report of Independent Registered Public Accounting Firm in Part II, Item 9a of this annual report
on Form 10-K.
Changes in internal controls over financial reporting. There were no changes in the Company's internal controls over financial reporting that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
178
Report
of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CONSOL Energy Inc. and Subsidiaries
We have audited CONSOL Energy Inc. and Subsidiaries' internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework (the COSO criteria). CONSOL Energy Inc. and Subsidiaries'
management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting appearing under Item 9a. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, CONSOL Energy Inc. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.
We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2014 of CONSOL Energy Inc. and Subsidiaries and our report dated December 31, 2014
expressed an unqualified opinion thereon.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item is incorporated herein by reference from the information under the captions
“PROPOSAL NO. 1-ELECTION OF DIRECTORS-Biographies of Nominees,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION and “SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the Proxy Statement for the annual meeting of shareholders to be held on May 6, 2015 (the “Proxy Statement”).
Executive Officers of CONSOL Energy
The following is a list, as of February 1, 2015, of CONSOL Energy executive officers, their ages and their positions and offices held with CONSOL Energy.
Name
Age
Position
Nicholas
J. DeIuliis
46
President and Chief Executive Officer
Stephen W. Johnson
56
Executive Vice President - Chief Legal and Corporate Affairs Officer
David M. Khani
51
Executive
Vice President and Chief Financial Officer
James C. Grech
53
Executive Vice President and Chief Commercial Officer
Timothy C. Dugan
53
Chief Operating Officer - Exploration and Production
James A. Brock
58
Chief
Operating Officer - Coal
Nicholas J. DeIuliis has been President of CONSOL Energy since February 23, 2011 and on May 7, 2014 he was named CONSOL's Chief Executive Officer. Mr. DeIuliis previously served in various positions at CNX Gas Corporation, including President, Chief Executive Officer and Chief Operating Officer. He is currently Chairman of the Board at CNX Gas Corporation. He was Executive Vice President and Chief Operating Officer of CONSOL Energy from January 16, 2009 until February 23, 2011. Prior to that time, he held the following positions at CONSOL Energy: Senior Vice President - Strategic Planning (November
1, 2004 to August 2005); Vice President Strategic Planning (April 1, 2002 to November 1, 2004); Director-Corporate Strategy (October 1, 2001 to April 1, 2002); Manager-Strategic Planning (January 1, 2001 to October 2001); and Supervisor-Process Engineering (April 1, 1999 to January 1, 2001).
Stephen W. Johnson became Executive Vice President and Chief Legal and Corporate Affairs Officer of CONSOL Energy and CNX Gas Corporation on December 31, 2012. Prior
to that time, Mr. Johnson served as Senior Vice President and General Counsel of CONSOL Energy and CNX Gas Corporation from February 5, 2009 through December 31, 2012. Prior to February 5, 2009, he served in the following positions with CNX Gas Corporation: General Counsel from September 1, 2005 until December 2, 2005, Senior Vice President and General Counsel from December 2, 2005 through June 21, 2007 and Executive Vice President, General Counsel and Secretary from June 21, 2007 until February 5, 2009. Effective May
30, 2014, Mr. Johnson became a director of the general partnership of CONE Midstream Partners LP.
David M. Khani joined CONSOL Energy on September 1, 2011 as its Vice President - Finance, and was promoted to Executive Vice President and Chief Financial Officer effective March 1, 2013. Prior to joining CONSOL Energy, Mr. Khani was with FBR Capital Markets & Co. ("FBR"), an investment banking and advisory firm and held the following positions: Director of Research from February 2007 through October 2010, and then Co-Director of Research from November 2010 through August 2011. Effective May 30, 2014, Mr. Khani became a director and the Chief Financial Officer of the general partnership of CONE
Midstream Partners LP.
James C. Grech became Chief Commercial Officer on November 15, 2012 and was promoted to Executive Vice President and Chief Commercial Officer effective March 1, 2013. Mr. Grech had served as Senior Vice President of CNX Land Resources Inc., a subsidiary of CONSOL Energy from September 13, 2011 until December 5, 2013. He joined the company in 2001 as Vice President of Business Development and was promoted to Senior Vice President - Marketing of CONSOL Energy Sales Company, another subsidiary of CONSOL Energy, a position he held from August
15, 2005 to October 25, 2011.
180
Timothy C. Dugan has been Chief Operating Officer- Exploration & Production of CONSOL Energy since January 28, 2014. He was President and Chief Operating Office of CNX Gas Corporation from May 22, 2014 to December 1, 2014, when he became President and Chief Executive Officer. Prior to joining CONSOL Energy, Mr. Dugan was Vice President - Appalachia South Business Unit at Chesapeake Energy Corporation. During his seven years
with Chesapeake Energy, he held the titles of Senior Asset Manager, Operations Superintendent, Senior Asset Manager and District Manager. From 2001 to 2007, Mr. Dugan was employed with EQT Corporation, where he held the titles of Regional Reservoir Engineer and Director of Operations - Engineering.
James A. Brock has been Chief Operating Officer - Coal of CONSOL Energy since December 10, 2010. Prior to this appointment, he served as Senior Vice President - Northern Appalachia - West Virginia Operations of CONSOL Energy beginning December 3, 2007. From September 7, 2006 until December 3, 2007 he served as Vice President-Operations. Mr. Brock began his
career with CONSOL Energy in 1979 at the Matthews Mine and since then has served at various locations in many positions including Section Foreman, Mine Longwall Coordinator, General Mine Foreman, and Superintendent.
CONSOL Energy has a written Code of Business Conduct that applies to CONSOL Energy's Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer) and others. The Code of Business Conduct is available on CONSOL Energy's website at www.consolenergy.com. Any amendments to, or waivers from, a provision of our code of employee business conduct and ethics that applies to our principal
executive officer, our principal financial and accounting officer and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting such information on our website at www.consolenergy.com.
By certification dated May 22, 2014, CONSOL Energy's Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was not aware of any violation by the Company of the NYSE corporate governance listing standards. In addition, the required Sarbanes-Oxley Act, Section 302 certifications
regarding the quality of our public disclosures were filed by CONSOL Energy as exhibits to this Form 10-K.
ITEM 11.
EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from the information under the captions “BOARD OF DIRECTORS AND COMPENSATION INFORMATION and “EXECUTIVE COMPENSATION INFORMATION” (excluding the Compensation Committee Report) in the Proxy Statement.
ITEM
12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item is incorporated by reference from the information under the caption “BENEFICIAL OWNERSHIP OF SECURITIES” and “SECURITIES AUTHORIZED FOR ISSUANCE UNDER CONSOL ENERGY EQUITY COMPENSATION PLAN” in the Proxy Statement.
181
ITEM
13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information requested by this Item is incorporated by reference from the information under the caption “PROPOSAL NO. 1-ELECTION OF DIRECTORS in the Proxy Statement.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated
by reference from the information under the caption “ACCOUNTANTS AND AUDIT COMMITTEE-INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in the Proxy Statement.
In reviewing any agreements incorporated by reference in this Form 10-K or filed with this 10-K, please remember that such agreements are included to provide information regarding their terms.
They are not intended to be a source of financial, business or operational information about CONSOL Energy or any of its subsidiaries or affiliates. The representations, warranties and covenants contained in these agreements are made solely for purposes of the agreements and are made as of specific dates; are solely for the benefit of the parties; may be subject to qualifications and limitations agreed upon by the parties in connection with negotiating the terms of the agreements, including being made for the purpose of allocating contractual risk between the parties instead of establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors or security holders. Investors and security holders should not rely on the representations, warranties and covenants or any description thereof
as characterizations of the actual state of facts or condition of CONSOL Energy or any of its subsidiaries or affiliates or, in connection with acquisition agreements, of the assets to be acquired. Moreover, information concerning the subject matter of the representations, warranties and covenants may change after the date of the agreements. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.
(A)(1)
Financial
Statements Contained in Item 8 hereof.
(A)(2)
Financial Statement Schedule-Schedule II Valuation and qualifying accounts.
2.1
Purchase and Sale Agreement, dated as of March 14, 2010, among Dominion Resources, Inc., Dominion Transmission, Inc., Dominion Energy, Inc. and CONSOL Energy Holdings LLC VI, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on March
16, 2010.
2.2
Parent Guarantee, dated March 14, 2010, by and among CONSOL Energy Inc. and Dominion Resources, Inc., Dominion Transmission, Inc. and Dominion Energy, Inc., incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
Stock Purchase Agreement, dated October 25, 2013, among CONSOL Energy Inc., Consolidation Coal Company, Ohio Valley Resources, Inc., and, as to certain provisions of the Purchase Agreement, Murray Energy Corporation, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on December 11, 2013.
Indenture, dated as of April 1, 2010, among CONSOL Energy Inc., the Subsidiary Guarantors named therein and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on April 2, 2010.
182
4.2
Supplemental
Indenture, dated as of April 30, 2010, among Dominion Exploration & Production, Inc., Dominion Reserves, Inc., Dominion Coalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian Development Properties, LLC, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.4 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.
4.3
Supplemental
Indenture No. 2, dated as of June 16, 2010, among Cardinal States Gathering Company, CNX Gas Company LLC, CNX Gas Corporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.5 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.
Supplemental
Indenture No. 4, dated as of September 10, 2013, to Indenture dated as of April 1, 2010, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.1 of Form 10-Q (file no. 001-14901) filed on November
1, 2013.
4.6
Indenture, dated as of April 1, 2010, among CONSOL Energy, Inc., the Subsidiary Guarantors named therein and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on April 2, 2010.
4.7
Supplemental
Indenture, dated as of April 30, 2010, among Dominion Exploration & Production, Inc., Dominion Reserves, Inc., Dominion Coalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian Development Properties, LLC, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.6 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.
4.8
Supplemental
Indenture No. 2, dated as of June 16, 2010, among Cardinal States Gathering Company, CNX Gas Company LLC, CNX Gas Corporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.7 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.
Supplemental
Indenture No. 4, dated as of September 10, 2013, to Indenture dated as of April 1, 2010, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 of Form 10-Q (file no. 001-14901) filed on November
1, 2013.
Supplemental
Indenture No. 2, dated as of September 10, 2013, to Indenture dated as of March 9, 2011, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 6.375 % Senior Notes due 2021, incorporated by reference to Exhibit 4.3 of Form 10-Q (file no. 001-14901) filed on November
1, 2013.
Registration
Rights Agreement, dated as of April 1, 2010, by and among CONSOL Energy Inc., the Guarantors listed on Schedule I attached thereto and Banc of America Securities LLC, as Representative of the Initial Purchasers, incorporated by reference to Exhibit 4.3 to From 8-K (file no. 001-14901) filed on April 2, 2010.
183
4.16
Registration
Rights Agreement, dated as of March 9, 2011, by and among CONSOL Energy Inc., the Guarantors listed on Schedule I attached thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Representative of the Initial Purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on March 11, 2011.
4.17
Registration Rights Agreement,
dated as of April 16, 2014, by and among CONSOL Energy Inc., the guarantors signatory thereto and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
Agreement of Resignation, Appointment and Acceptance, dated July 22, 2013, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. signatory thereto, Wells Fargo Bank, National Association, as Successor Trustee to The Bank
of Nova Scotia Trust Company of New York, and The Bank of Nova Scotia Trust Company of New York, as Resigning Trustee (related to the Indenture dated as of April 1, 2010 with respect to the 8.00% Senior Notes due 2017, the Indenture dated as of April 1, 2010 with respect to the 8.25% Senior Notes due 2020, and the Indenture dated as of March 9, 2011 with respect to the 6.375% Senior Notes due 2021), incorporated by reference to Exhibit 4.4 of Form 10-Q (file no. 001-14901)
filed on November 1, 2013.
4.20
Indenture, dated as of April 16, 2014, among CONSOL Energy Inc., the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, a national banking association, as trustee, with respect to the 5.875% Senior Notes due 2022, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
10.1
Purchase
and Sale Agreement, dated as of April 30, 2003, by and among CONSOL Energy Inc., CONSOL Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company, CNX Gas Company LLC, CNX Marine Terminals Inc. and CNX Funding Corporation, incorporated by reference to Exhibit 10.30 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2003, filed on August 13, 2003.
10.2
First
Amendment to Purchase and Sale Agreement dated as of April 30, 2007, entered into among CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals Inc., each an “Originator” and CNX Funding Corporation, incorporated by reference to Exhibit 10.31 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.3
Second
Amendment to Purchase and Sale Agreement dated as of November 16, 2007, entered into among CONSOL Energy Inc. (“CONSOL Energy”), CONSOL Energy Sales Company, CONSOL of Kentucky Inc., Consol Pennsylvania Coal Company LLC, Consolidation Coal Company, Island Creek Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals Inc. (each an “Existing Originator”) and collectively the “Existing Originators”), Fola Coal Company, LLC., Little Eagle Coal Company, LLC., Mon River Towing, Inc., Terry Eagle Coal Company, LLC., Tri-River Fleeting Harbor Service, Inc., and Twin Rivers Towing Company (each, a “New Originator” and collectively the “New Originators”; the Existing Originators and the New Originators, each an “Originator” and collectively, the “Originators”), Windsor Coal Company (the “Released Originator”)
and CNX Funding Corporation, incorporated by reference to Exhibit 10.32 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.4
Third Amendment to the Purchase and Sale Agreement, dated as of March 12, 2010, among CNX Marine Terminals Inc., CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company LLC, Consolidated Coal Company, Eighty-Four Mining Company, Fola Coal Company, L.L.C., Island
Creek Coal Company, Keystone Coal Mining Corporation, Little Eagle Coal Company, L.L.C., McElroy Coal Company, Mon River Towing, Inc., Terry Eagle Coal Company, L.L.C., Twin Rivers Towing Company and CNX Funding Corporation, incorporated by reference to Exhibit 10.6 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
Amended and Restated Receivable Purchase Agreement, dated as of April 30, 2007, by and among CNX Funding Corporation, CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek
Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company, CNX Marine Terminals Inc., Market Street Funding LLC, Liberty Street Funding LLC, PNC Bank, National Association, and the Bank of Nova Scotia, incorporated by reference to Exhibit 10.33 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
184
10.7
First
Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 9, 2007, entered into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.34 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.8
Second
Amendment to Amended and Restated Receivables Purchase Agreement, dated as of July 27, 2007, entered into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer (in such capacity, the “Servicer”), the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.35 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.9
Third
Amendment to Amended and Restated Receivables Purchase Agreement, dated as of November 16, 2007, entered into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various new sub-servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.36 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.10
Fourth
Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 27, 2009, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.4 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
10.11
Fifth
Amendment to Amended and Restated Receivables Purchase Agreement and Waiver, dated as of March 12, 2010, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.5 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
10.12
Sixth
Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 23, 2010, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages of the Amendment, the Conduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LC Participants listed on the signature pages of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.13 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February 10, 2011.
10.13
Seventh
Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 30, 2012, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages of the Amendment, the Conduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LC Participants listed on the signature pages of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.5 to Form 10-Q for the quarter ended March 31, 2012 (file no. 001-14901), filed on April 30, 2012.
10.14
Eighth
Amendment to Amended and Restated Receivables Purchase Agreement, dated as of November 8, 2012, by and among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.15
Ninth
Amendment to Amended and Restated Receivables Purchase Agreement, dated September 23, 2013, by and among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, Market Street Funding LLC, as Assignor, and PNC Bank, National Association, as Administrator, as LC Bank and as Assignee, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2013, filed on November 1, 2013.
10.16
Tenth
Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 28, 2014, by and among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
Commitment Letter, dated March 14, 2010, among Banc of America Bridge LLC, Banc of America Securities LLC, PNC Bank, National Association PNC Capital Markets LLC and CONSOL Energy Inc., incorporated
by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
Amended
and Restated Credit Agreement, dated as of April 12, 2011, by and among CONSOL Energy Inc., the Guarantors Party thereto, the Lenders Party thereto, PNC Bank, National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and Sovereign Bank, as the Co-Documentation Agents, and PNC Capital Markets LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Joint Lead Arrangers, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.21
Amendment
No. 1 to Credit Agreement, dated as of December 5, 2013, to the Amended and Restated Credit Agreement, dated as of April 12, 2011, by and among CONSOL Energy Inc., the lenders and agents party thereto and PNC Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on December 11, 2013.
10.22
Amended and Restated Credit Agreement, dated as of June 18, 2014,
by and among CONSOL Energy Inc., the lenders and agents party thereto and PNC Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K/A (file no. 001-14901) filed on June 25, 2014.
10.23
Amended and Restated Collateral Trust Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc. and its Designated Subsidiaries, Wilmington Trust Company, as Corporate Trustee and David A. Vanaskey, as
Individual Trustee, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on May 13, 2010.
10.24
Amended and Restated Pledge Agreement, dated as of May 7, 2010, made and entered into by each of the pledgors listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.3 to Form
8-K (file no. 001-14901) filed on May 13, 2010.
10.25
Amended and Restated Security Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc., each of the parties listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.4 to Form 8-K (file no. 001-14901)
filed on May 13, 2010.
10.26
Patent, Trademark and Copyright Security Agreement, dated as of June 27, 2007, by and among each of the pledgors listed on the signature pages thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 10.20 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February
10, 2011.
10.27
First Amendment to Amended and Restated Patent, Trademark and Copyright Security Agreement, dated as of May 7, 2010, by and among each of the pledgors listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.5 to Form 8-K (file no. 001-14901) filed on May 13, 2010.
10.28
Patent,
Trademark and Copyright Assignment and Assumption, dated as of April 12, 2011, between Wilmington Trust Company as assignor and PNC Bank, National Association as assignee, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of May 7, 2010, jointly and severally given by each of the undersigned thereto and each of the other persons which become Guarantors thereunder from time to time in favor of PNC Bank, National Association, in its capacity as the administrative agent for the Lenders, in connection with that certain Amended and Restated Credit Agreement, as defined
therein, incorporated by reference to Exhibit 10.22 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February 10, 2011.
Successor Agent Agreement, dated as of April 12, 2011, by and among among Wilmington Trust Company and David A. Varansky as existing agents,
PNC Bank, National Association as Collateral Trustee and CONSOL Energy Inc. and certain of its subsidiaries, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.33
Amended and Restated Credit Agreement, dated as of April 12, 2011, by and among CNX Gas Corporation, the Guarantors Party thereto, the Lenders Party thereto, PNC Bank, National Association, as the Administrative Agent, Bank of America,
N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and Wells Fargo Bank, N.A., as the Co-Documentation Agents, and PNC Capital Markets LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Bookrunners and Joint Lead Arrangers, incorporated by reference to Exhibit 10.3 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.34
Amendment No. 1 to Credit Agreement, dated as of December 14, 2011, by and among CNX Gas Corporation, the lenders and agents party thereto and PNC Bank, National
Association, as Administrative Agent, incorporated by reference to Exhibit 10.29 to Form 10-K for the year ended December 31, 2012 (file no. 01-14901), filed on February 7, 2013.
10.35
Amendment No. 2 to Credit Agreement, dated as of March 12, 2013, to the Amended and Restated Credit Agreement, dated as of April 12, 2011, as amended by Amendment No. 1, dated December 14, 2011, by and among
CNX Gas Corporation, the lenders and agents party thereto and PNC Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.
10.36
Collateral Trust Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation, its Designated Subsidiaries, Wilmington Trust Company,
as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by reference to Exhibit 2.1 to the CNX Gas Corporation Form 8-K (file no. 001-32723) filed on May 13, 2010.
10.37
Pledge Agreement, dated as of May 7, 2010, by each of the pledgors listed on the signature pages thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference
to Exhibit 2.2 to the CNX Gas Corporation Form 8-K (file no. 001-32723) filed on May 13, 2010.
10.38
Security Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation and each of the undersigned parties thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.3 to the CNX Gas Corporation Form 8-K (file no. 001-32723)
filed on May 13, 2010.
Successor Agent Agreement, dated as of April 12, 2011, by and among Wilmington Trust Company and David A. Vanaskey as existing agents, PNC Bank,
National Association as Collateral Trustee and CNX Gas Corporation and certain of its subsidiaries, incorporated by reference to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
Stipulation and Agreement of Compromise and Settlement, dated May 8, 2013, between and among (i) plaintiffs Harold L. Hurwitz and James R. Gummel, on their own behalf and on behalf of the Class (as defined therein) and (ii) defendants CNX Gas Corporation, CONSOL Energy Inc. and certain individual defendants, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended June
30, 2013, filed on August 5, 2013.
Purchase
Agreement, dated as of April 10, 2014, among CONSOL Energy Inc., the subsidiary guarantors party thereto and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers named therein, incorporated by reference to Exhibit 1.1 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
Amended and Restated Retirement Restoration Plan of CONSOL Energy Inc., incorporated reference to Exhibit 10.30 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
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 Disclosure Exhibit
99.1
Engineers' Audit Letter
99.2
Mining
Engineers' and Geologists' Audit Letter
101
Interactive Data File (Form 10-K for the year ended December 31, 2014 furnished in XBRL).
Supplemental Information
No annual report or proxy material has been sent to shareholders of CONSOL Energy at the time of filing of this Form 10-K. An annual report will be sent to shareholders and to the commission subsequent to the filing of this Form 10-K.
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.
189
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) 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, as of the 6th day of February, 2015.
CONSOL ENERGY INC.
By:
/s/ NICHOLAS J.
DEIULIIS
Nicholas J. DeIuliis
Director, Chief Executive Officer and President
(Duly
Authorized Officer and Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 5th day of February, 2015, by the following persons on behalf of the registrant in the capacities indicated:
Signature
Title
/s/ NICHOLAS J.
DEIULIIS
Director, Chief Executive Officer and President
Nicholas J. DeIuliis
(Duly Authorized Officer and Principal Executive Officer)
/s/ DAVID M. KHANI
Chief
Financial Officer and Executive Vice President
David M. Khani
(Duly Authorized Officer and Principal Financial Officer)
/s/ LORRAINE L. RITTER
Controller and Vice President
Lorraine L. Ritter
(Duly
Authorized Officer and Principal Accounting Officer)
