CNX Resources Corp - Annual Report: 2013 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-K

__________________________________________________

(Mark One)



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

For the fiscal year ended December 31, 2013



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)



Delaware		51-0337383
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

__________________________________________________

Securities registered pursuant to Section 12(b) of the Act:



Title of each class				Name of exchange on which registered
Common Stock ($.01 par value)				New York Stock Exchange
Preferred Share Purchase Rights				New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

__________________________________________________

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. x

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, 2013, 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 $3,294,530,080.

The number of shares outstanding of the registrant's common stock as of January 20, 2014 is 229,162,591 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of CONSOL Energy's Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2014, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III.

TABLE OF CONTENTS

		Page
PART I
ITEM 1.	Business	5
ITEM 1A.	Risk Factors	29
ITEM 1B.	Unresolved Staff Comments	44
ITEM 2.	Properties	44
ITEM 3.	Legal Proceedings	44
ITEM 4.	Mine Safety and Health Administration Safety Data	44

PART II
ITEM 5.	Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	45
ITEM 6.	Selected Financial Data	47
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	49
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	104
ITEM 8.	Financial Statements and Supplementary Data	106
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	179
ITEM 9A.	Controls and Procedures	179
ITEM 9B.	Other Information	181

PART III
ITEM 10.	Directors and Executive Officers of the Registrant	181
ITEM 11.	Executive Compensation	182
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	182
ITEM 13.	Certain Relationships and Related Transactions and Director Independence	182
ITEM 14.	Principal Accounting Fees and Services	182

PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	183
SIGNATURES		191

GLOSSARY OF CERTAIN OIL AND GAS MEASUREMENT TERMS

The following are abbreviations of certain measurement terms commonly used in the oil and gas industry and included within this Form 10-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 global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;


•	an extended decline in demand for or prices we receive for our natural gas and coal affecting our operating results and cash flows;


•	our customers extending existing contracts or entering into new long-term contracts for coal;


•	our reliance on major customers;


•	our inability to collect payments from customers if their creditworthiness declines;


•	the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our natural gas and coal to market;


•	a loss of our competitive position because of the competitive nature of the natural gas and coal industries, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;


•	coal users switching to other fuels in order to comply with various environmental standards related to coal combustion emissions;


•	the impact of potential, as well as any adopted regulations relating to greenhouse gas emissions on the demand for natural gas and coal;


•	foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;


•	the risks inherent in natural gas and coal operations being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, explosions, accidents and weather conditions which could impact financial results;


•	decreases in the availability of, or increases in, the price of commodities or capital equipment used in our mining operations;


•	decreases in the availability of, an increase in the prices charged by third party contractors or, failure of third party contractors to provide quality services to us in a timely manner could impact our profitability;


•	obtaining and renewing governmental permits and approvals for our natural gas and coal operations;


•	the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous substances and wastes generated during our natural gas and coal operations;


•	our ability to find adequate water sources for our use in gas drilling, or our ability to dispose of water used or removed from strata in connection with our gas operations at a reasonable cost and within applicable environmental rules;


•	the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut down a natural gas well or a mine;


•	the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current gas and coal operations;


•	the effects of mine closing, reclamation, gas well closing and certain other liabilities;


•	uncertainties in estimating our economically recoverable gas and coal reserves;


•	defects may exist in our chain of title and we may incur additional costs associated with perfecting title for gas or coal rights on some of our properties or failing to acquire these additional rights may result in a reduction of our estimated reserves;


•	the impacts of various asbestos litigation claims;


•	the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities Exchange Act of 1934;


•	increased exposure to employee-related long-term liabilities;


•	lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan exceeding total service and interest cost in a plan year;


•	acquisitions that we recently have completed or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we may have made and divestitures we anticipate may not occur or produce anticipated proceeds;


•	the terms of our existing joint ventures restrict our flexibility, actions taken by the other party in our gas joint ventures may impact our financial position and various circumstances could cause us not to realize the benefits we anticipate receiving from these joint ventures;


•	risks associated with our debt;


•	replacing our natural gas reserves, which if not replaced, will cause our gas reserves and gas production to decline;


•	our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;


•	changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs, could cause our financial position and profitability to deteriorate;


•	failure to appropriately allocate capital and other resources among our strategic opportunities may adversely affect our financial condition;


•	failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its obligations under various arrangements, which we guaranteed, could materially or adversely affect our results of operations, financial position, and cash flows; and


•	other factors discussed in this 2013 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.

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 290% to produce 172.4 net Bcfe in 2013. 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.

Our Gas Division operates, develops and explores for natural gas primarily in Appalachia (Pennsylvania, West Virginia, Virginia, Ohio, 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 215-235 Bcfe for 2014 and achieve 30% annual gas production growth in 2015 and 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 cost's 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 446 thousand net acres in the Marcellus Shale and approximately 109 thousand net acres in the Utica Shale. In addition, we estimate that approximately 345 thousand net acres of our Marcellus Shale acreage in Pennsylvania and West Virginia are prospective for the slightly shallower Upper Devonian Shale. We also have 2.5 million net acres in our coalbed methane play, primarily in Virginia.

Highlights of our 2013 production include the following:


•	Total production of 472,274 Mcfe per day, an increase of 10% over 2012;


•	98% Natural Gas, 2% Liquids; and


•	34% Marcellus, 48% coalbed methane, 16% shallow oil & gas, 2% other.

At December 31, 2013, our proved reserves had the following characteristics:


•	5.7 Tcfe of proved reserves;


•	97.5% natural gas;


•	43.9% proved developed;


•	85.7% operated; and


•	A reserve life ratio of 33.25 years (based on fourth quarter 2013 production);

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 (the "Murray Energy Transaction"). These coal mines produced 26.7 million tons of thermal coal in 2013 and had approximately 1.1 billion tons of coal reserves. After the Murray Energy transaction, our coal division continues to focus on the extraction and processing of coal primarily in Pennsylvania and Virginia.

Highlights of coal activities from continuing operations in 2013 include the following:


•	Underground mining complexes are among the safest in the United States of America;


•	Production of 28.5 million tons of coal from continuing operations;


•	Coal reserve holdings of 3.0 billion tons;


•	30% of sales delivered to export markets;


•	59% of sales to domestic utilities; and


•	New BMX Mine in southwest Pennsylvania scheduled to come on-line in March 2014, as planned.

Additionally, we provide energy services, including terminal services (the Baltimore Terminal), industrial supply services, 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'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.

CONSOL Energy intends to continue to grow its gas production. The 2014 gas production guidance range is 215-235 Bcfe, net to CONSOL Energy, of which 5-8% is expected to be liquids. For 2015 and 2016, the company expects 30% annual gas production growth.

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, natural gas may potentially become a significant contributor to the transportation market. Our increasing gas production will allow CONSOL Energy to participate in these growing markets.

The 2014 coal production guidance range is 30.1 - 32.1 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 soon-to-be-completed BMX 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 nearly 24 million tons in 2014, produce a high-Btu Pittsburgh-seam coal that is lower in sulfur than many Northern Appalachian coals. Also, the company’s Buchanan Mine in southwestern Virginia produces a premium low volatile metallurgial coal for the steel industry. It typically produces 4-5 million tons per year at a cost that is among the lowest of any domestic metallurgical coal mine.

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 meaningful 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.

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 over 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 Capital Expenditure Budget-

The following table outlines CONSOL Energy's capital expenditure budget for 2014:



	Capex ($MM)
Natural Gas Operations:
Land and Permitting:	$	70
Liquids-rich drilling and completions:
Marcellus	410
Utica	105
Dry-gas drilling and completions:
Marcellus/Upper Devonian	415
Utica	10
CBM/Shallow Gas	40
Midstream:
Marcellus Gathering	60
Total Natural Gas Operations	$	1,110

Coal Operations:
BMX Mine	$	200
Maintenance of Production	130
Land/Safety/Water/Terminal	60
Total Coal Operations	$	390

Total Company	$	1,500

CONSOL Energy expects to invest about $1.1 billion in its natural gas operations, much of which will be directed toward drilling and completion costs in the highly productive Marcellus and Utica shales. Approximately one-half of the company’s total drilling capital will target the liquids-rich areas within these two plays. On the dry gas side, drilling will primarily focus on those areas in the Marcellus shale that have established economics resulting from high net revenue interest, economies of scale, or reservoir performance.

Our joint venture partner is required to pay a portion of our drilling and completion costs in the certain circumstances. However, the Marcellus shale drilling and completions capital is not reduced because of the contingent nature of the drilling carry in place with the Marcellus shale joint venture. The Marcellus shale joint venture drilling carry is currently suspended and will be reinstated upon Henry Hub natural gas prices being equal to or greater than $4.00 per MMbtu for three consecutive months. Based on current Henry Hub futures and the expected corresponding reinstatement of the drilling carry, approximately $220 million of the Marcellus shale joint venture drilling carry is expected to be realized for drilling and completions capital incurred between March and December of the current year.

The Utica shale drilling and completions capital reflects a $115 million reduction for drilling carry we expect to be paid by our joint venture partner.

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, Ohio and New York from approximately 446,000 net Marcellus Shale acres at December 31, 2013.

CONSOL Energy and Noble Energy, our joint venture partner, drilled a record 117 gross wells in the Marcellus Shale in 2013. CONSOL Energy drilled 46 of those wells in the dry gas area of the formation. The geographic breakdown was as follows:


•	26 wells in Southwestern Pennsylvania,


•	10 wells in Central Pennsylvania,


•	10 wells in Northern West Virginia, and


•	71 wells drilled by Noble Energy in the wet gas area of the play.

CONSOL Energy also completed 59 Marcellus Shale wells in 2013. The average lateral length was 5,744 feet in 2013, or a 4% increase over the previous year's lateral length of 5,514 feet. These longer drilled laterals enabled the company to perform more hydraulic fracturing, or “fracking,” to complete the wells. In 2013, the average completed well had 26 "frac" stages, or a 44% increase over the 18 stages from the previous year. Longer lateral lengths and more "frac" stages per well are expected to enhance well economics.

In 2014, the company expects Marcellus Shale drilling activity to be the primary driver of gas production growth. In the Marcellus Shale joint venture, CONSOL Energy and Noble Energy plan to operate an average of 4-5 horizontal rigs each to drill at least a combined 162 gross wells. At least 88 of the joint venture wells will be drilled in the liquids-rich areas of the play, including 2 within the recently acquired acreage that lies beneath the Pittsburgh International Airport. At least 74 wells are planned to target the dry gas area of the joint venture. These dry locations include 6 Upper Devonian laterals (5 Burkett; 1 Rhinestreet) in Washington County, Pennsylvania (4) and Doddridge County, West Virginia (2). Current plans of both partners include increased usage of shorter stage laterals and reduced cluster spacing. The early results of these enhanced completion techniques in Southwestern Pennsylvania have been very promising. The wells completed in this manner have shown initial production rates being improved by as much as 40%, which the company believes will translate into potential increases to well EURs of 15%-20%.

We also hold a 50% interest in a gathering company which builds and operates the gathering system for most of our Marcellus shale production. We contributed our existing Marcellus Shale gathering assets to this company as of September 30, 2011. Joint operations are conducted in accordance with a joint development agreement.

Utica

CONSOL Energy also controls approximately 109,000 net acres of Utica Shale potential in eastern Ohio at December 31, 2013. Additionally, CONSOL Energy controls a large number of acres in southwestern Pennsylvania and northern West Virginia that contain the rights to the Utica Shale. These acres are disclosed in other plays because the Utica Shale is not the primary drilling target as of December 31, 2013. The thickness of the Utica Shale in these areas range from 200 to 450 feet.

In 2013, CONSOL Energy and Hess, our joint venture partner, drilled 24 gross wells in the Utica. CONSOL Energy drilled 9 of those wells.

In the Utica Shale joint venture, a total of 32 gross wells are planned to be drilled in 2014 within the liquids-rich corridor that runs across Harrison, Belmont, Guernsey, and Noble counties of Ohio. CONSOL Energy and its partner will also test enhanced completion techniques in the Utica as efforts in 2014 will focus on ramping up production.

We and our joint venture partner are seeking to monetize approximately 62,000 gross joint venture Utica shale acres which are located outside of our core operating area.

Separate from the joint venture activity, CONSOL Energy expects to invest $24 million in Monroe County, Ohio in 2014. In addition to continuing to build-out its land position, the company will drill two 100%-owned wells. One well will target the liquids-rich Marcellus formation, while the other will be designed to penetrate the dry-gas Utica zone. Both will be drilled from the same pad.

Coalbed Methane (CBM)

We have the rights to extract CBM in Virginia from approximately 267,000 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. For 2014, the coalbed methane program will again be kept at minimal drilling levels, with the expected drilling of 71 wells. Total capital for the 2014 CBM drilling program is estimated to be $34 million.

We also have the right to extract CBM in West Virginia, southwestern Pennsylvania, and Ohio from approximately 965,000 net CBM acres. In central Pennsylvania we have the right to extract CBM from approximately 263,000 net CBM acres. In addition, we control 808,000 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 2014.

Shallow Oil and Gas

The shallow oil and gas acreage position of CONSOL Energy is approximately 906,000 net acres mainly in Illinois, Indiana, Kentucky, West Virginia, Pennsylvania, Virginia, and New York at December 31, 2013. 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. For 2014, the company continues to de-emphasize its shallow oil and gas program, and plans to drill a total of 5 wells.

Other Gas

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, 2013.

CONSOL Energy's first Upper Devonian well, which was drilled in the Burkett Shale and turned in line in June 2013, continues to demonstrate a shallow decline rate and an EUR in the range of 5-6 Bcfe. CONSOL Energy expects to drill five additional Burkett Shale wells in 2014, as well as at least one Rhinestreet Shale formation well. Our Marcellus Shale joint venture partner owns a 50% interest in the Burkett Shale formation within the joint venture area of mutual interest, while CONSOL Energy controls a 100% interest in the Rhinestreet Shale formation.

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 243,000 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 Chattanooga Shale wells.

Huron

We have 406,000 net acres of Huron Shale potential in Kentucky, West Virginia, and Virginia; a portion of this acreage has tight sands potential.

Summary of Properties as of December 31, 2013



			Shallow Oil
	CBM		and Gas		Marcellus		Other Gas
	Segment		Segment		Segment		Segment		Total
Estimated Net Proved Reserves (MMcfe)	1,544,970		582,846		3,373,093		230,305		5,731,214
Percent Developed	73	%	100	%	21	%	34	%	44	%
Net Producing Wells (including gob wells)	4,310		8,324		132		108		12,874
Net Acreage Position
Net Proved Developed Acres	258,601		248,318		11,527		9,247		527,693
Net Proved Undeveloped Acres	9,986		—		44,396		4,964		59,346
Net Unproved Acres(1)	2,193,699		625,706		380,964		1,011,661		4,212,030
Total Net Acres(2)	2,462,286		874,024		436,887		1,025,872		4,799,069

_________

(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.

(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, Shallow Oil and Gas, 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 is 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, 2013, the number of producing wells, developed acreage and undeveloped acreage:



	Gross	Net(1)
Producing Wells (including gob wells)	15,063	12,874
Net Acreage Position
Proved Developed Acreage	542,388	527,693
Proved Undeveloped Acreage	105,019	59,346
Unproven Acreage	5,396,659	4,212,030
Total Acreage	6,044,066	4,799,069

___________


(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.

Development Wells (Net)

During the years ended December 31, 2013, 2012 and 2011 we drilled 139.8, 95.5 and 254.9 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 2013, there were 205 gross development wells. There were no dry development wells in 2013, 2012, or 2011. As of December 31, 2013, there are 31 net developmental wells still in process. The following table illustrates the net wells drilled by well classification type:



	For the Year
	Ended December 31,
	2013	2012	2011
CBM segment	63.8	42.5	221.4
Shallow Oil and Gas segment	5.0	2.0	4.0
Marcellus segment	56.0	44.0	17.5	(A)
Other Gas segment	15.0	7.0	12.0
Total Development Wells	139.8	95.5	254.9

(A) For the year ended December 31, 2011, the Marcellus Segment includes 15 gross development wells drilled prior to September 30, 2011. A 50% interest in these wells was sold to Noble Energy on September 30, 2011.

Exploratory Wells (Net)

During the years ended December 31, 2013, 2012 and 2011, we drilled in the aggregate 5.5, 22.0, and 69.5 net exploratory wells, respectively. As of December 31, 2013, there is 1.0 net exploratory well in process. In 2013, there were 11.0 gross exploratory wells. The following table illustrates the exploratory wells drilled by well classification type:



	For the Year Ended December 31,
	2013			2012			2011
	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.
CBM segment	—	—	—	—	—	—	—	—	—
Shallow Oil and Gas segment	—	—	—	4.0	7.0	4.0	12.0	1.0	1.0
Marcellus segment	0.5	—	2.0	0.5	—	0.5	47.5	1.0	—
Other Gas segment (1)	—	—	3.0	1.0	0.5	4.5	5.5	—	1.5
Total	0.5	—	5.0	5.5	7.5	9.0	65.0	2.0	2.5

(1) For the year ended December 31, 2013, the Other Gas Segment includes three net exploratory wells drilled in the Utica Shale in Ohio, all of which are still being evaluated.

For the year ended December 31, 2012, the Other Gas Segment includes five net exploratory wells drilled in the Utica Shale in Ohio.

For the year ended December 31, 2011, the Marcellus Segment includes 41 gross exploratory wells drilled prior to September 30, 2011. A 50% interest in these wells was sold to Noble Energy on September 30, 2011. There were a total of 15 gross exploratory wells drilled after September 30, 2011 under the joint venture agreement with Noble Energy and are reflected in the table above at the applicable ownership percentage.

Reserves

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).



	Net Reserves
	(Million cubic feet equivalent)
	as of December 31,
	2013	2012	2011
Proved developed reserves	2,514,294	2,165,483	2,135,805
Proved undeveloped reserves	3,216,920	1,827,975	1,344,222
Total proved developed and undeveloped reserves(a)	5,731,214	3,993,458	3,480,027

___________


(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)
	2013		2012		2011
Future net cash flows	$	6,568	$	2,792	$	4,877
Total PV-10 measure of pre-tax discounted future net cash flows (1)	$	2,780	$	1,242	$	2,861
Total standardized measure of after tax discounted future net cash flows	$	1,681	$	736	$	1,747

____________

(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.

Reconciliation of PV-10 to Standardized Measure



	As of December 31,
	2013			2012			2011
	(Dollars in millions)
Future cash inflows	$	21,603		$	11,778		$	14,804
Future production costs	(7,106		)	(4,824		)	(5,263		)
Future development costs (including abandonments)	(3,903		)	(2,451		)	(1,675		)
Future net cash flows (pre-tax)	10,594			4,503			7,866
10% discount factor	(7,814		)	(3,261		)	(5,005		)
PV-10 (Non-GAAP measure)	2,780			1,242			2,861
Undiscounted income taxes	(4,026		)	(1,711		)	(2,989		)
10% discount factor	2,927			1,205			1,875
Discounted income taxes	(1,099		)	(506		)	(1,114		)
Standardized GAAP measure	$	1,681		$	736		$	1,747

Gas Production

The following table sets forth net sales volumes produced for the periods indicated:



	For the Year
	Ended December 31,
	2013	2012	2011
GAS
Marcellus Sales Volumes (MMcf)	55,048	35,853	26,863
CBM Sales Volumes (MMcf)	82,867	88,149	92,360
Shallow Oil and Gas Sales Volumes (MMcf)	27,457	28,684	31,731
Other Sales Volumes (MMcf)	3,365	2,366	1,987
LIQUIDS*
NGLs Sales Volumes (MMcfe)	2,628	610	—
Oil Sales Volumes (MMcfe)	634	600	563
Condensate Sales Volumes (MMcfe)	381	63	—
TOTAL (MMcfe)	172,380	156,325	153,504

*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 2014 natural gas production to be between 215 - 235 Bcfe, of which 5%-8% is expected to be NGLs/condensates/oil. With the continued focus on the liquids-rich areas of its plays, the company expects that mix to increase to 10%-15% by the end of 2016, while overall volumes are expected to increase 30% per year over the the same time period.

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.



	For the Year
	Ended December 31,
	2013		2012		2011
Total Average Gas Sales Price Before Effects of Financial Settlements (per Mcfe)	$	3.85	$	3.00	$	4.27
Average Effects of Financial Settlements (per Mcfe)	$	0.45	$	1.22	$	0.63
Total Average Gas Sales Price Including Effects of Financial Settlements (per Mcfe)	$	4.30	$	4.22	$	4.90
Average Lifting Costs excluding ad valorem and severance taxes (per Mcfe)	$	0.56	$	0.58	$	0.69

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 that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions and 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. These gas swaps represented approximately 76.9 Bcf of our produced gas sales volumes for the year ended December 31, 2012 at an average price of $5.25 per Mcf. As of January 21, 2014, we expect these transactions will represent approximately 129.3 Bcf of our estimated 2014 production at an average price of $4.61 per Mcf, 78.6 Bcf of our estimated 2015 production at an average price of $4.10 per Mcf, and 71.3 Bcf of our estimated 2016 production at an average price of $4.20 per Mcf.

CONSOL Energy continues to develop a diversified portfolio of firm capacity transportation options to support our three-year production growth plan. We are benefited 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.

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 4,600 miles of gas gathering pipelines as well as 250,000 horsepower of compression, of which, approximately 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 300 billion cubic feet per year of pipeline quality gas.

CONSOL Energy also 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 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.

In the Utica Shale, we and our joint venture partner, Hess, are primarily contracting with third parties for gathering services.

CONSOL Energy has had the advantage of having gas production from CBM, which can be lower Btu than pipeline specification, as well as higher Btu Marcellus Shale production which 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. This will allow CONSOL Energy 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 producers of natural gas produced about 20% of dry natural gas production in the first six months of 2013. The EIA reported 482,822 producing natural gas wells in the United States in 2012, the latest year for which government statistics are available.

Natural gas has lost three percent of market share in the U.S. electric generation market compared to record natural gas generation in 2012 (based on preliminary 2013 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, 2013, CONSOL Energy had an estimated 3.0 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.

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. Our coal reserves are periodically reviewed by an independent third party consultant. In previous years, the independent consultant has reviewed the procedures used by us to prepare our internal estimates, verified the accuracy of our property reserve estimates and retabulated reserve groups according to standard classifications of reliability.

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.

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, 2013 and 2012

							Recoverable
				Average	As Received Heat		Reserves(2)
				Seam	Value(1)				Tons in
		Reserve	Coal	Thickness	(Btu/lb)		Owned	Leased	Millions
Mine/Reserve	Location	Class	Seam	(feet)	Typical	Range	(%)	(%)	12/31/2013	12/31/2012
ASSIGNED–OPERATING									(4)
Thermal Reserves
Enlow Fork (3)	Enon, PA	Assigned	Pittsburgh	5.4	12,920	12,760 – 13,020	100%	—%	16.9	27.0
		Accessible	Pittsburgh	5.3	13,020	12,830 – 13,100	79%	21%	232.8	232.8
Bailey (3)	Enon, PA	Assigned	Pittsburgh	5.5	12,940	12,840 – 13,000	62%	38%	96.9	92.2
		Accessible	Pittsburgh	5.7	12,940	12,770 – 13,090	88%	12%	278.7	303.0
Amvest-Fola Complex (3)	Bickmore, WV	Assigned	Multiple	4.6	12,380	12,250 – 12,550	86%	14%	73.4	73.4
Miller Creek Complex	Delbarton, WV	Assigned	Multiple	2.6	12,050	11,600 – 12,650	44%	56%	52.6	13.4
		Accessible	Multiple	5.1	12,610	12,610 – 12,610	1%	99%	0.7	8.2

Metallurgical Reserves
Buchanan	Mavisdale, VA	Assigned	Pocahontas 3	6.2	13,740	13,610 – 14,130	20%	80%	47.2	51.7
		Accessible	Pocahontas 3	5.9	13,720	13,630 – 13,870	14%	86%	46.1	46.3
Amonate Complex	Amonate, VA	Assigned	Multiple	4.2	13,150	12,850 – 13,350	64%	36%	20.1	14.8
		Accessible	Multiple	5.2	13,010	13,010 – 13,010	100%	—%	6.6	6.6
Total Assigned Operating and Accessible									872.0	869.4

_____________


(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, 2013. The heat value shown for accessible reserves are based on as received, dry values obtained from drill hole analysis prorated by the associated Assigned Operating reserve 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 57 million tons of recoverable reserves which represents CONSOL Energy's portion of tonnage held by two equity affiliates. CONSOL Energy owns a 49% interest in both of these affiliates.

The following table sets forth our unassigned proven and probable reserves by region:



CONSOL Energy UNASSIGNED Recoverable Coal Reserves as of December 31, 2013 and 2012

					Recoverable
		Recoverable Reserves(2)			Reserves
				Tons in	(tons in
	As Received Heat	Owned	Leased	Millions	Millions)
Coal Producing Region	Value(1) (Btu/lb)	(%)	(%)	12/31/2013	12/31/2012
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)	11,400 – 13,600	86%	14%	951.7	1,424.0
Central Appalachia (Virginia, Southern West Virginia)	11,400 – 14,100	54%	46%	349.6	354.7
Illinois Basin (Illinois, Western Kentucky, Indiana)	11,600 – 12,000	45%	55%	731.9	733.6
Total		65%	35%	2,033.2	2,512.3

_______________

(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.

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
By Product (In Millions of Tons) As of December 31, 2013

		≤ 1.20 lbs.						> 1.20 ≤ 2.50 lbs.						> 2.50 lbs.
		S02/MMBtu						S02/MMBtu						S02/MMBtu
		Low		Med		High		Low		Med		High		Low		Med		High				Percent By
By Region		Btu		Btu		Btu		Btu		Btu		Btu		Btu		Btu		Btu		Total		Product
Metallurgical(1):
	High Vol A Bituminous	—		—		6.2		—		—		208.7		—		—		—		214.9		7.1	%
	Med Vol Bituminous	—		5.1		56.1		—		—		2.9		—		—		—		64.1		2.1	%
	Low Vol Bituminous	—		—		186.6		—		—		55.2		—		—		—		241.8		8.0	%
	Total Metallurgical	—		5.1		248.9		—		—		266.8		—		—		—		520.8		17.2	%
Thermal(1):
	High Vol A Bituminous	34.5		80.4		2.8		41.5		105.2		61.5		66.8		62.2		1,289.7		1,744.6		57.5	%
	High Vol B Bituminous	—		17.9		—		—		75.4		—		—		401.1		—		494.4		16.3	%
	High Vol C Bituminous	—		—		—		—		159.4		—		108.3		—		—		267.7		8.8	%
	Low Vol Bituminous	—		—		—		—		—		—		—		—		4.5		4.5		0.2	%
	Total Thermal	34.5		98.3		2.8		41.5		340.0		61.5		175.1		463.3		1,294.2		2,511.2		82.8	%
	Total	34.5		103.4		251.7		41.5		340.0		328.3		175.1		463.3		1,294.2		3,032.0		100.0	%
	Percent of Total	1.1	%	3.4	%	8.3	%	1.4	%	11.2	%	10.8	%	5.8	%	15.3	%	42.7	%	100.0	%

The table above excludes 57 million tons of reserves held by two equity affiliates. CONSOL Energy owns 49% of both of these affiliates.

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, 2013, 2012 and 2011.



	Total	Total	Total
	Royalty	Coal	Royalty
	Tonnage	Acreage	Income
Year	(in thousands)	Leased	(in thousands)
2013	8,335	271,755	$16,906
2012	8,326	271,760	$16,853
2011	8,488	289,833	$17,969

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.

Production

In the year ended December 31, 2013, 94% of CONSOL Energy's production from continuing operations came from underground mines and 6% from surface mines. Where the geology is favorable and reserves are sufficient, CONSOL Energy employs longwall mining systems in our underground mines. For the year ended December 31, 2013, 90% 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, 2013, 2012 and 2011, 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.



					Tons Produced			Year
		Mine	Mining		(in millions)			Established
Mine	Location	Type	Equipment	Transportation	2013	2012	2011	or Acquired
Thermal
Bailey (3)	Enon, PA	U	LW/CM	R R/B	10.1	8.6	8.6	1984
Enlow Fork (3)	Enon, PA	U	LW/CM	R R/B	8.9	8.0	8.3	1990
Miller Creek Complex(2)	Delbarton, WV	U/S	CM/S/L	R T	2.2	2.9	2.8	2004
AMVEST-Fola Complex(1)(2)	Bickmore, WV	U/S	A/S/L/CM	R T	—	0.8	2.1	2007
High Volatile Metallurgical
Bailey-Met (3)	Enon, PA	U	LW/CM	R R/B	1.3	1.5	2.1	1984
Enlow Fork-Met (3)	Enon, PA	U	LW/CM	R R/B	1.2	1.5	1.8	1990
AMVEST-Fola Complex(1)(2)-Met	Bickmore, WV	U/S	A/S/L/CM	R T	—	0.3	0.1	2007
AMVEST-Terry Eagle Complex(1)(2)-Met	Jodie, WV	U/S	CM/A/S/L	R T	—	—	0.1	2007
Low Volatile Metallurgical
Buchanan(1)	Mavisdale, VA	U	LW/CM	R T	4.8	3.5	5.7	1983
Amonate (1)(2)	Amonate, VA	U/S	A/S/CM	R T	—	0.1	—	2012
Total					28.5	27.2	31.6

CONSOL Energy Portion of Equity Affiliates
Harrison Resources(2)(4)	Cadiz, OH	S	S/L	R T	0.4	0.4	0.4	2007
Western Allegheny-Knob Creek(2)(4)	Young Township, PA	U	CM	R T	0.3	0.1	0.1	2010
Total CONSOL Energy Portion of Equity Affiliates					0.7	0.5	0.5



A	–	Auger
S	–	Surface
U	–	Underground
LW	–	Longwall
CM	–	Continuous Miner
S/L	–	Stripping Shovel and Front End Loaders
R	–	Rail
B	–	Barge
R/B	–	Rail to Barge
T	–	Truck
CB	–	Conveyor Belt
(1)	–	Mine was idled for part of the year(s) presented due to market conditions.
(2)	–	Harrison Resources, Miller Creek Complex, AMVEST–Fola Complex, AMVEST–Terry Eagle Complex, Amonate Complex and Western Allegheny–Knob Creek include 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 was then resumed at a reduced capacity.
(4)	–	Production amounts represent CONSOL Energy's 49% ownership interest.

Coal Capital

Coal operations anticipate investing $200 million in 2014 to complete the BMX Mine in mid-March. This underground mine is adjacent to CONSOL Energy’s Bailey and Enlow Fork mines in Southwestern Pennsylvania. On a full-year basis, the single-longwall BMX Mine is expected to produce approximately 5 million annual tons of high-quality Pittsburgh seam coal to be sold in either the high volatile metallurgical or thermal markets.

Due to the well capitalized nature of the company’s retained coal assets, we anticipate that maintenance-of-production capital for 2014 will be held to under $4.25 per ton on the 31 million tons expected to be produced for the year.

Coal Marketing and Sales

Our sales of bituminous coal from continuing operations were at average sales price per ton sold as follows:



	Years Ended December 31,
	2013		2012		2011
Average Sales Price Per Ton Sold– Thermal Coal	$	64.78	$	69.08	$	66.84
Average Sales Price Per Ton Sold– High Volatile Met Coal	$	63.44	$	63.93	$	78.57
Average Sales Price Per Ton Sold– Low Volatile Met Coal	$	92.64	$	140.11	$	191.81
Average Sales Price Per Ton Sold– Total Company	$	69.34	$	77.75	$	90.10

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
Thermal	21.4	74	%
High Volatile Metallurgical	2.5	9	%
Low Volatile Metallurgical	4.9	17	%
Total tons sold	28.8	100	%

Approximately 59% of our 2013 coal sales from continuing operations were made to U. S. electric generators, 30% of our 2013 coal sales were priced on export markets and 11% of our coal sales were made to other domestic customers. We had over 60 customers from our 2013 continuing operations. During 2013, Xcoal Energy Resources and Duke Energy Carolinas each comprised over 10% of our revenues from continuing operations, and the top four coal and gas customers accounted for more than 35% of our total revenues from continuing operations.

Coal Contracts

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. However, several multi-year agreements have terms ranging from five to twenty 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, 2013, over 70% of all the coal we produced from continuing operations was sold under contracts with terms of one year or more.

The following table sets forth as of January 22, 2014, CONSOL Energy's estimated production and sales for 2014 through 2015.



COAL DIVISION GUIDANCE
(Tons in millions)

	Q1 2014		2014		2015
Est. Total Coal Sales	7.2 - 7.6		30.1 - 32.1		34.0
Tonnage: Firm	6.9		23.8		12.2
Price: Sold (firm)	$	64.75	$	65.35	$	69.23
Est. Low-Vol Met Sales	1.1 - 1.2		4.2 - 4.7		4.9
Tonnage: Firm	0.8		1.7		0.8
Est. High-Vol Met Sales	0.7+		2.3+		2.4
Tonnage: Firm	0.6		0.9		0.3
Est. Thermal Sales	5.6+		23.8+		26.7
Tonnage: Firm	5.5		21.2		11.1

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 2014. Collared tons in 2015 are 1.4 million tons, with a ceiling of $72.59 per ton and a floor of $48.59 per ton. Not included in the category breakdowns are the tons from equity affiliates Harrison Resources and Western Allegheny Energy (WAE). Harrison Resources has 0.1 million tons for Q1 2014, and 0.4 million tons for all of 2014 and 2015. WAE has 0.1 million tons for Q1 2014, and 0.5 million tons and 0.9 million tons for all of 2014, and 2015, 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;


•	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, industrial supply services, 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.

Industrial Supply Services

Fairmont Supply Company, a CONSOL Energy subsidiary, is a general-line distributor of mining, drilling, and industrial supplies in the United States. Fairmont Supply has 27 customer service centers nationwide. Fairmont Supply also provides integrated supply procurement and management services. Integrated supply procurement is a materials management strategy that utilizes a single, full-line distribution to minimize total cost in the maintenance, repair and operating supply chain.

Fairmont Supply provides mine and drilling supplies to CONSOL Energy's mining and gas operations. CONSOL Energy's coal and gas divisions accounted for 37% of Fairmont Supply's sales in 2013.

Terminal Services

In 2013, approximately 10.2 million tons of coal were shipped through CONSOL Energy's subsidiary, CNX Marine Terminals Inc.'s, exporting terminal in the Port of Baltimore. Approximately 21% 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, 2013, CONSOL Energy had 4,633 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, 2013, 2012 and 2011 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.

Laws and Regulations

Overview

Our gas and coal mining operations are subject to various types of federal, state and local 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 made capital expenditures for environmental control facilities of approximately $1.6 million, $1.3 million, and $4.2 million in the years ended December 31, 2013, 2012 and 2011, respectively. CONSOL Energy expects to have capital expenditures of $9.9 million in 2014 for environmental control facilities.

Environmental Laws

Clean Air Act and Related Regulations. The federal Clean Air Act and similar state laws and regulations which regulate emissions into the air, affect gas production and processing operations, as well as coal mining, coal handling and processing, primarily through permitting and/or emissions control requirements.

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. 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 Clean Air Act also indirectly and more significantly affects the U.S. coal industry by extensively regulating the air emissions of the 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 could affect demand for coal as a fuel source and affect the volume of our sales. In 2012, the EPA promulgated or finalized several rulemakings impacting coal generating facilities. Two of these were final rules for new source performance standards

for coal and oil fueled power plants in the Utility Maximum Control Technology (UMACT) rule which includes more stringent new source performance standards (NSPS) for particulate matter (PM), SO 2 and NO X and the Mercury and Air Toxics Standards (MATS) rule which sets new mercury and air toxic standards. In November 2012, EPA published a notice of reconsideration of certain aspects of the UMACT and MATS rules. In April 2013, EPA issued a final version of its reconsideration of its UMACT and MATS rules. The reconsideration resulted in higher limits, but the standards are still stringent and compliance will be expensive. In addition, in August 2012, the U.S. Court of Appeals in Washington, DC invalidated EPA's 2011 Cross-State Air Pollution Rule which was intended to regulate sulfur dioxide (SO2), nitrogen dioxide (NOx) and fine particulate matter. The Court ruled that the agency had overstepped its bounds and vacated the rulemaking, ordering the agency to continue to enforce the Clean Air Interstate Rule promulgated in 2005 until a viable replacement to the cross-state regulation could be issued. An appeal from the Circuit Court’s decision was argued before the U.S. Supreme Court in December 2013.

In April 2012, the EPA published its proposed New Source Performance Standards (NSPS) for carbon dioxide 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 carbon dioxide 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. These proposed rules will also require CCS for new coal fired power plants.

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 Clean Water Act and corresponding state laws include requirements for: improvement of designated "impaired waters" (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, such as chlorides, selenium and dissolved solids; for minimizing impacts and compensating for unavoidable impacts resulting from discharges of fill materials to regulated streams and wetlands; and the 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, including brine and oil, and require that plans be in place to address any spills and that secondary containment be installed 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 the EPA's 2010 budget appropriation, the 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 to be published in 2014. In 2012, EPA has also announced plans to conduct a review of water produced in conjunction with the production of Coal Bed Methane (CBM) to determine whether its disposal should be further regulated. In late 2013, EPA announced that it did not intend to continue with its effort to revise effluent limits for coalbed methane operations.

CONSOL Energy utilizes pipelines extensively for its gas, water and coal businesses, and as such must obtain permits with associated mitigation from the Army Corps of Engineers (ACOE) for impacts to streams and wetlands that we are unable to avoid. In 2013, the EPA issued a draft report entitled Connectivity of Streams and Wetlands to Downstream Waters which affects a proposed rulemaking that would expand the scope of the Clean Water Act (CWA) to include previously non-jurisdictional streams, wetlands, and waters and make these areas jurisdictional inter-coastal Waters of the U.S. This rulemaking will likely cause states that have jurisdiction over their own waters to make regulatory changes to their already robust regulatory programs 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.

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 took a number of initiatives that have resulted in delays and obstruction of the issuance of such permits for surface mining operation 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.

In late June 2012, we received informal notification from the Pennsylvania Department of Environmental Protection of the Department's intent pursuant to a Technical Guidance Document entitled “Surface Water Protection-Underground Bituminous Coal Mining” to require a change in the mine plan of a pending application for a permit for expansion of the Company's Bailey longwall mine. If ultimately required, this change in mine plan could have a material effect on our forecasted production for 2015. We do not agree that a modification of its mining plan is necessary to comply with applicable regulatory performance standards and we continue to submit information to the permitting authority to support our position. Additionally, we are currently evaluating potential modifications that would be required if we are compelled to modify our application.

Comprehensive Environmental Response, Compensation and Liability Act (Superfund). The Comprehensive Environmental Response, Compensation and Liability Act (Superfund) and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. We could incur liability under CERCLA relative to our gas or coal operations. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

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 which could adversely affect our results, financial condition and cash flows. In 2010, the EPA proposed options for the regulation of Coal Combustion Residuals from the electric power sector as either hazardous waste or non-hazardous waste. A final decision is expected in 2014. Depending on the outcome of that decision, demand for coal fired electricity generation could be adversely impacted.

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 the 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 US 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, along with others in industry have 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 Long-Eared bat, which is due to a disease commonly referred to as White Nose Syndrome. This will lead to significant timing and critical path hurdles, ultimately limiting the ability to clear timber for construction activities.

Surface Mining Control and Reclamation Act. The federal Surface Mining Control and Reclamation Act (SMCRA) establishes minimum national operational, reclamation 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 $0.280 per ton for surface mined coal and $0.120 per ton for underground mined coal. These fees are currently scheduled to be in effect until September 30, 2021.

OSM is currently considering modifications to the existing stream buffer zone regulation, which amendments are referred to as the Stream Protection Rule. OSM’s latest position is that proposed Stream Protection regulations will be published in August 2014. Although it is too early to predict what the impacts of the proposed amendments will be, they could result in loss of access to significant amounts of coal and/or significant increases in reclamation costs. In Pennsylvania, where we operate two longwall mines, approximately $16.0 million, $21.1 million and $25.7 million of expenses were incurred from continuing operations during the years ended December 31, 2013, 2012 and 2011, respectively, to mitigate and repair impacts on streams

from subsidence. We currently estimate expenses related to subsidence of streams in Pennsylvania will be approximately $15.8 million for the year ended December 31, 2014.

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.

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 have 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, in the first quarter of 2014 the Department of Labor intends to publish final rules for underground coal mining operations concerning lowering coal miners exposure to respirable coal mine dust and concerning proximity detection systems for continuous mining machines. Proposed rules for concerning exposure of coal miners to crystalline silica and proximity detection systems for mobile machines in underground mines are intended to be published in the second quarter of 2014.

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. 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.

Executive Officers of the Registrant

Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Directors and Executive Officers of CONSOL Energy” (included herein pursuant to Item 401 (b) of Regulation S-K).


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 continued in 2013 and the outlook is uncertain. In addition, liquidity is essential to our business. Although we cannot predict the impacts, renewed weakness in the economic conditions of any of the industries we serve, or another financial crisis, 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;


•	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; and


•	our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.

An extended decline in demand for our products, or the prices CONSOL Energy receives for natural gas, natural gas liquids, and coal will adversely affect our operating results and cash flows.

Our financial results are significantly affected by the demand for our products and the prices we receive for our natural gas, natural gas liquids, and coal.

Natural gas and natural gas liquids accounted for approximately 26% of our revenues from continuing operations in 2013. Natural gas prices are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede growth. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:


•	the overall domestic supply of natural gas;


•	the supply of natural gas in our market;


•	changes in the consumption pattern of industrial consumers, electricity generators and residential users;


•	weather conditions;


•	proximity and capacity of gas pipelines and other transportation facilities;


•	overall domestic and global economic conditions;


•	the price and availability of alternative fuels, especially thermal coal; and


•	the price and supply of imported liquefied natural gas.

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. Our gas operations are geographically concentrated in the mid-Atlantic states and oversupply from the continued drilling in these plays, despite lower prices, directly affects prices we receive. Low gas prices adversely impacts our gas operations revenues and earnings before income taxes.

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. 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. Thus, apart from the general impact of domestic production on overall gas prices, the price paid for our natural gas also may be adversely affected by increasing production in our market.

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 volatile for reasons similar to those described above regarding natural gas. 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 sale to Murray Energy in 2013 of almost one half or our thermal coal production increased our exposure to fluctuations in the price of coal, natural gas and natural gas liquids.

Coal accounted for approximately 66% of our revenues from continuing operations in 2013. Prices of and demand for our coal may fluctuate due to factors beyond our control such as:


•	overall domestic and global economic conditions, technological advances affecting energy consumption, price and availability of foreign coal, and domestic and foreign government regulations;


•	the consumption pattern of industrial consumers, electricity generators and residential users;


•	weather can impact thermal coal demand (for example, the unusually warm 2011 - 2012 winter left utilities with large coal stockpiles and depressed the demand for thermal coal);

•

the price and availability of alternative fuels for electricity generation, especially natural gas (for example, abundant natural gas supplies at prices averaging less than $3/MMbtu during 2012 depressed the demand for thermal coal as natural gas fired electricity generation market share increased from approximately 25% in 2011 to 30% in 2012 and coal-fired generation declined from approximately 42% in 2011 to 37% in 2012); 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.

Decreased demand and extended or substantial price declines for coal adversely affect our operating results for future periods and our ability to generate cash flows necessary to improve productivity and expand operations. For example, in 2012 domestic and global economic deterioration, unusually warm winter weather and abundant cheap natural gas decreased demand for our coal as well as decreased the average sales price for our metallurgical coal and resulted in our coal revenues and earnings before income taxes significantly declining from 2011. 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.

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, 2013, approximately 70% 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 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, 2013, we derived over 10% of our total revenues from sales to two coal customers individually and more than 35% of our total revenue from sales to our four largest coal and gas customers. At December 31, 2013, we had approximately twenty-four coal supply agreements with these customers that expire at various times from 2014 to 2028. 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 $200 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, 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 or vent our produced gas to the atmosphere because we do not have facilities to store excess inventory. 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 tariffs 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, 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 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, chlorine and other elements or compounds, many of which are released into the air along with fine particulate matter and carbon dioxide when coal is burned. 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 will need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), 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. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. 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. Recent EPA rulemaking proceedings requiring additional reductions in permissible emission levels of impurities by coal-fired plants will likely make it more costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative for electric power generation in the future. Examples are (i) adoption of the Cross-State Air Pollution Rule (CASPR) in 2011 (to be effective January 1, 2012, but currently subject to a stay ordering the agency to continue to enforce the Clean Air Interstate Rule promulgated in 2005 until a viable replacement to the cross-state regulation could be issued, with an appeal of CASPR currently pending before the U.S. Supreme Court); and (ii) adoption in 2012 of the Utility Maximum Control Technology (UMACT) rule in 2012, which included more stringent new source performance standards (NSPS) for particulate matter (PM), SO₂ and NO_X, and the Mercury and Air Toxics Standards (MATS) rule which set new mercury and air toxic standards (both of which were reconsidered and reissued with slightly less stringent limits in 2013).

Another source of uncertainty is the consideration of regulation of coal ash disposal by the EPA. In May 2010, the EPA proposed new approaches for the regulation of Coal Combustion Residuals from electric generating facilities. The EPA is re-evaluating its August 1993 and May 2000 Bevill determinations that currently provide exemptions from the definition of hazardous wastes for certain materials. In October 2013, the U.S. District Court for the District of Columbia ordered the EPA to publish proposed coal ash facility regulations under the non-hazardous provisions of the Resource Conservation and Recovery Act. The EPA proposed regulations are not yet published.

Apart from actual and potential regulation of emissions 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.

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. 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. 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. These proposed rules will also require CCS for new coal fired power plants.

Apart from governmental regulation, on February 4, 2008, three of Wall Street's largest investment banks announced that they had adopted climate change guidelines for lenders. 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 or other countries where we sell coal, or the inability of utilities to obtain financing in connection with coal-fired plants, it 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 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.

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. Currency fluctuations among countries purchasing and selling coal could adversely affect the competitiveness of our coal in international markets.

Our natural gas and coal mining operations are subject to operating risks, 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:


•	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.

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.

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.

We rely upon third party contractors to provide various field services to our gas and coal operations. A decrease in the availability of or an increase in the prices charged by third party contractors or failure of third party contractors to provide quality services to us in a timely manner could decrease our production, increase our costs of production, and decrease our anticipated profitability.

We 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.

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 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 2007, the U.S. District Court for the Southern District of West Virginia found other operators' permits for mining in these areas to be deficient. In February 2009, the U.S. Court of Appeals for the Fourth Circuit reversed that decision, finding that the permits were adequate. Nevertheless, the EPA's objections and an enhanced review process that was being implemented under a federal multi-agency memorandum of understanding effectively held up the issuance of permits for all types of mining operations that require Clean Water Act Section 402 discharge permits and Section 404 dredge and fill permits, including surface facilities for underground mines. The EPA's enhanced review process was invalidated in October 2011, in part because the EPA failed to follow public notice and rulemaking requirements, and on July 31, 2012, the federal District Court for the District of Columbia struck down the EPA's “guidance memorandum” for coal-related water permitting actions in which the EPA recommended permits include limits on specific conductivity which currently neither the EPA nor the states have a standard. However, normal permitting has not yet resumed. Also, the EPA may elect to seek to adopt regulations to codify its enhanced review process. CONSOL Energy's surface and underground operations have been impacted to a limited extent to date, but a permit for a new mine was impacted which resulted in the issuance of a Worker Adjustment and Retraining Notification (WARN) which affected some 145 employees on October 30, 2012. CONSOL Energy was able, in this instance, to redeploy these employees to work at another adjacent coal mine property for which a permit was already issued. However, the permit for the new mine still has not been issued and there is no assurance that CONSOL Energy would be able to re-deploy its employees under future similar circumstances. In addition, the length of time needed to bring a new mine into production has increased by several years because of the increased time required to obtain necessary permits. These delays or denials of mining permits could reduce our production, cash flow and results of operations.

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. In addition, CONSOL Energy may incur costs associated with the investigation and remediation of environmental contamination under the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) and similar state statutes and has been named as a potentially responsible party at Superfund sites in the past.

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 2014. 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.

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 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. 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 material 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 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.

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 are working to expeditiously develop cost effective means to remove selenium from mine water. If such technology or processes are not developed promptly, the only available effective treatment technologies are expensive to construct and operate which will increase coal production costs.

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 $601 million at December 31, 2013. 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.

CONSOL Energy faces uncertainties in estimating our economically recoverable gas and coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

Natural gas reserves require subjective estimates of underground accumulations of natural gas and assumptions concerning natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved gas reserves and projections of future production rates and the timing of development expenditures may be incorrect. 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 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 gas reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of gas 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 gas we ultimately recover being different from reserve estimates. The present value of future net cash flows from our proved 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 gas reserves on historical average prices and costs. However, actual future net cash flows from our 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 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 gas reserves as of December 31, 2013 would decrease from $2.8 billion to $2.6 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:


•	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, 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 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 gas reserves than a vertical well which could result in higher costs. In future years, the cost associated with purchasing oil and 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 gas and coal reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal and 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 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 and coal because we have to acquire additional property rights to perfect our title to gas or coal rights. If we fail to acquire additional property rights to perfect our title to gas or coal 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 cases. Our discovering 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 require 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.

While chain of title for our coal estate generally has been established, there may be defects in it that we do not realize until we have committed to developing those properties or coal reserves. As such, the title to the coal estate that we intend to mine may contain defects. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs perfecting title. If we cannot cure these defects, we may have to reduce our coal reserves.

Our subsidiaries, primarily Fairmont Supply Company, are co-defendants in various asbestos litigation cases which could result in making payments in the future that are material.

One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 6,900 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Texas and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Past payments by Fairmont with respect to asbestos cases have not been material, however, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material to the financial position, results of operations or cash flows of CONSOL Energy.

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, 2013, the current and non-current portions of these obligations included:


•	postretirement medical and life insurance ($1.0 billion);


•	coal workers' black lung benefits ($121.2 million);


•	salaried retirement benefits ($43.8 million); and


•	workers' compensation ($85.1 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 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 make 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 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 operation; and we may not realize the benefits we expect to realize from these joint ventures.

In the second half of 2011 CONSOL Energy, through its principal gas operations subsidiary, CNX Gas Company LLC (CNX Gas Company), entered into joint venture arrangements with Noble Energy, Inc. (Noble Energy) and Hess Ohio Developments, LLC (Hess) regarding our shale gas assets. We sold a 50% undivided interest in our Marcellus shale oil and gas assets to Noble Energy and a 50% undivided interest in our Utica shale acres in Ohio to Hess. The following aspects of these joint ventures could materially impact CONSOL Energy:

•

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 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 venture 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.

•

Approximately $1.9 billion of consideration that we expect to receive from Noble Energy depends upon Noble Energy paying a portion of our share of drilling and development costs for new wells, which we call “carried costs.” We entered into a similar transaction with Hess Ohio Developments, LLC (Hess) in which approximately $335 million of consideration that we expect to receive from Hess is dependent upon Hess paying carried costs. 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 a joint venturer to pay its 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 gas or loss of rights to develop the oil and gas properties held by that joint venture.

•

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 beginning on December 1, 2011. We cannot predict when this 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 Noble Energy joint development agreement prohibits prior to March 31, 2014, unless Noble Energy consents in its sole discretion, any transfer of our interests in the Noble Energy joint venture assets or our selling or otherwise transferring control of CNX Gas Company. The Hess joint development agreement prohibits prior to October 21, 2014, unless Hess consents in its sole discretion, any transfer of our interests in the Hess joint venture assets. 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, 2013, our total indebtedness was approximately $3.175 billion of which approximately $1.5 billion was under our 8.00% senior unsecured notes due April 2017, $1.25 billion was under our 8.25% senior unsecured notes due April 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, $56 million of capitalized leases due through 2021, and $16 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;


•	limiting 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; and


•	placing us at a competitive disadvantage compared to less leveraged competitors.

Our senior secured credit facilities and the indentures governing our 8.00%, 8.25% 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 agreements and the indentures governing our 8.00%, 8.25% and 6.375% senior unsecured notes subject us to financial and/or other restrictive covenants. Under our senior secured credit agreements, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio, and a maximum senior secured leverage ratio, as defined. Our senior secured credit agreements and the indentures governing our 8.00%, 8.25% 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, 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 8.00%, 8.25% 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.

Unless we replace our gas reserves, our gas reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.

Producing natural gas 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, 2013, 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 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 21, 2014, we had hedges on approximately 129.3 Bcf of our 2014 natural gas production, 78.6 Bcf of our 2015 natural gas production, and 71.3 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:


•	our production is less than expected;


•	the counterparties to our contracts fail to perform the contracts; or


•	the creditworthiness of our counterparties or their guarantors is substantially impaired.

If our gas hedges would no longer qualify for hedge accounting, we will be required to mark them to market and recognize the adjustments through current year earnings. This may result in more volatility in our income in future periods.

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.

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 $310 thousand over the 15 year period. The passage of this legislation increases the financial burden on our operations in the Marcellus Shale.

Several portions of Act 13 were overturned by the Pennsylvania Supreme Court in December 2013, including the portion that addressed municipal uniformity, and the Company is assessing the exact reach and scope of that decision. In the meantime, disparities in municipal rules for industry operations are likely. Moreover, the Pennsylvania Supreme Court’s ruling may affect the annual impact fee on unconventional gas wells, as the fee was tied to municipal-ordinance uniformity.

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.

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. 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 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.

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 to satisfy obligations, or under various agreements with us could materially increase our liabilities and materially adversely affect our results of operations, financial position and cash flows.

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, 2013 was approximately $404 million. The leases and subleases we entered into with Murray Energy relate to approximately $200 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 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.


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 sixth 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.

PART II


ITEM 5.	Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities

Our 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:



		High		Low		Dividends
Year Period Ended December 31, 2013
	Quarter Ended March 31, 2013	$	34.79	$	29.91	$	—
	Quarter Ended June 30, 2013	$	35.79	$	27.10	$	0.125
	Quarter Ended September 30, 2013	$	35.56	$	26.51	$	0.125
	Quarter Ended December 31, 2013	$	38.42	$	33.99	$	0.125
Year Period Ended December 31, 2012
	Quarter Ended March 31, 2012	$	39.37	$	31.72	$	0.125
	Quarter Ended June 30, 2012	$	35.15	$	26.80	$	0.125
	Quarter Ended September 30, 2012	$	33.79	$	27.83	$	0.125
	Quarter Ended December 31, 2012	$	36.60	$	29.71	$	0.250

As of December 31, 2013, there were 162 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., Anadarko Petroleum Corp., Apache Corp., Arch Coal Inc., Chesapeake Energy Corp., Devon Energy Corp., EOG Resources Inc., Newfield Exploration Co., Noble Energy Inc., Peabody Energy Corp., Southwestern Energy Co., QEP Resources Inc., and WPX Energy, Inc. The graph assumes that the value of the investment in CONSOL Energy common stock and each index was $100 at December 31, 2008. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2013.



	2008	2009	2010	2011	2012	2013
CONSOL Energy Inc.	100.0	175.6	173.3	132.1	117.8	141.0
Peer Group	100.0	149.0	167.3	140.2	131.4	151.2
S&P 500 Stock Index	100.0	63.4	79.8	91.7	104.0	134.8

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 $0.40 per share when our leverage ratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 5.14 to 1.00 and our availability was approximately $793 million at December 31, 2013. The credit facility does not permit dividend payments in the event of default. The indentures to the 2017, 2020 and 2021 notes limit dividends to $0.40 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, 2013.

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.


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, 2013, 2012, 2011, 2010 and 2009 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, 2013 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 “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes included in this Annual Report.



	For the Years Ended December 31,
	2013		2012		2011			2010		2009
Operating revenues from Continuing Operations	$	3,120,722	$	3,282,350	$	4,237,913		$	3,559,511	$	3,202,549
Income from Continuing Operations	$	79,264	$	317,959	$	681,675		$	315,240	$	515,700
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	660,442	$	388,470	$	632,497		$	346,779	$	539,717
Earnings per share:
Basic:
Income from Continuing Operations	$	0.35	$	1.40	$	3.01		$	1.41	$	2.70
Income from Discontinued Operations	2.54		0.31		(0.22		)	0.20		0.29
Net Income	$	2.89	$	1.71	$	2.79		$	1.61	$	2.99
Dilutive:
Income from Continuing Operations	$	.35	$	1.39	$	2.98		$	1.40	$	2.67
Income from Discontinued Operations	2.52		0.31		(0.22		)	0.20		0.28
Net Income	$	2.87	$	1.70	$	2.76		$	1.60	$	2.95

Assets from Continuing Operations	$	11,393,667	$	10,383,343	$	9,952,077		$	9,543,457	$	5,281,010
Assets from Discontinued Operations	—		2,614,251		2,573,623			2,527,153		2,494,391
Total assets	$	11,393,667	$	12,997,594	$	12,525,700		$	12,070,610	$	7,775,401

Long-term debt from Continuing Operations (including current portion)	$	3,175,014	$	3,185,497	$	3,196,455		$	3,209,101	$	465,975
Long-term debt from Discontinued Operations (including current portion)	—		2,574		1,659			1,820		2,327
Total Long-term debt (including current portion)	$	3,175,014	$	3,188,071	$	3,198,114		$	3,210,921	$	468,302
Cash dividends declared per share of common stock	$	0.375	$	0.625	$	0.425		$	0.400	$	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.

OTHER OPERATING DATA

(unaudited)



	Years Ended December 31,
	2013		2012		2011		2010		2009
Gas:
Net sales volumes produced (in billion cubic feet)	172.4		156.3		153.5		127.9		94.4
Average sales price ($ per Mcfe)(A)	$	4.30	$	4.22	$	4.90	$	5.83	$	6.68
Average cost ($ per Mcfe)	$	3.51	$	3.37	$	3.53	$	3.54	$	3.15
Proved reserves (in Bcfe) (B)	5,731		3,993		3,480		3,732		1,911

Coal:
Tons sold from continuing operations (in thousands)(C)	28,776		27,612		32,090		32,280		32,185
Tons produced from continuing operations (in thousands)	28,476		27,178		31,721		31,895		32,987
Average sales price of tons produced ($ per ton produced)	$	69.34	$	77.75	$	90.10	$	73.31	$	66.71
Average Cost of Goods Sold ($ per ton produced)	$	50.78	$	53.98	$	51.88	$	44.37	$	41.76
Recoverable coal reserves (tons in millions)(D)	3,032		4,229		4,314		4,229		4,350
Number of active mining complexes (at end of period)	4		5		7		7		6

____________


(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: 0.6 million tons, 0.5 million tons, 0.6 million tons, 0.2 million tons, and 0.3 million tons for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively.


(D)	Represents proven and probable coal reserves at period end, excluding equity affiliates.


ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations

General

2013 Highlights


•	Record total gas production of 172.4 Bcfe in 2013, 10% higher than 2012.


•	Record Marcellus Shale production of 57.8 Bcfe in 2013, 58% higher than 2012.

•

Completed a lease with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for 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. An up-front bonus payment of $46.3 million was paid at closing. Noble Energy, our joint venture partner, acquired 50% of the acres and accordingly, reimbursed CONSOL Energy for 50% of the associated costs. Approximately 7.6% of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title. To date, less than 1% of this amount has been released from escrow. We must spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and the bonus is foregone.

•

Entered into a farm-in agreement for approximately 90 thousand additional Marcellus Shale acres in West Virginia. Consideration of up to $190 million will be paid by CONSOL Energy in two installments: (i) 50% was paid at closing and (ii) the balance due over time as the acres are drilled. Closing occurred on December 5, 2013. Noble Energy, our Marcellus Shale joint venture partner, acquired a 50% interest in the acres and accordingly, will reimburse CONSOL Energy for 50% of the associated costs.

•

Completed the sale of Consolidation Coal Company (CCC) and certain of its subsidiaries, which contains all five of CONSOL Energy's longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy). The CCC mines sold were McElroy Mine, Shoemaker Mine, Robinson Run Mine, Loveridge Mine, and Blacksville No. 2 Mine. Collectively, these mines produced 26.7 million tons of thermal coal in 2013 and 28.8 million tons of thermal coal in 2012. Murray Energy acquired approximately 1.1 billion tons of Pittsburgh No. 8 seam reserves. CONSOL Energy’s River and Dock Operations were included in the transaction. CONSOL Energy received $850 million in cash as a result of the transaction. CONSOL Energy retained an overriding royalty interest in certain reserves sold in the transaction that included minimum royalty payments of $42 million. Additionally, Murray Energy acquired approximately $1.9 billion of other postretirement benefit plan liabilities, $100 million of workers compensation liabilities, $50 million of coal workers’ pneumoconiosis liabilities, $10 million of long term disability liabilities, $155 million of environmental liabilities and CONSOL Energy’s UMWA 1974 Pension Trust Obligations. The pre-tax financial gain resulting from the transaction was $1,035 million.


•	In conjunction with the sale of CCC and certain of its subsidiaries, CONSOL Energy realigned its dividend policy to reflect the company’s increased emphasis on growth. CONSOL Energy intends to pay a regular quarterly rate of $0.0625 per common share, or a 2014 annual rate of $0.25 per share, beginning with the first quarter of 2014.

2014 Expectations:


•	Our 2014 annual gas production is expected to be between 215 - 235 Bcfe with annual production growth of 30% for 2015 and 2016.


•	Our 2014 gas capital investment is expected to be $1,110 million.


•	Our 2014 coal production is expected to be between 30.1 - 32.1 million tons.


•	Our 2014 coal capital investment is expected to be $390 million.


•	Pension settlement accounting may occur in 2014 related to staff reduction that occured in relation to the sale of CCC and certain subsidiaries.


•	BMX Mine is expected to begin longwall mining during the first quarter of 2014.

Several significant transactions occurred in the year ended December 31, 2013. These events include the following:

Continuing Operations:


•	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 $24.7 million. The transaction resulted in a $15.3 million pre-tax gain on the sale of assets.


•	On June 24, 2013, CONSOL Energy closed the sale of the Potomac coal reserves located in Grant and Tucker Counties in West Virginia. Cash proceeds from the sale were $25.0 million. The transaction resulted in a $24.7 million pre-tax gain on the sale of assets.

•

Pension settlement accounting required the acceleration of previously unrecognized actuarial losses due to lump sum payments from the Company's qualified and non-qualified salary retirement pension plans exceeding the annual projected service and interest costs of the plans. The pension settlement resulted in a $39.5 million pre-tax expense adjustment. Many of the lump sum payments in the year ended December 31, 2013 were paid to employees who elected to retire under the 2012 Voluntary Severance Incentive Plan.

•

A review of certain titles in the Company's Marcellus Shale acreage, continued throughout the year ended December 31, 2013. As a result of the Company's review of the title defects, asserted by its joint venture partner Noble Energy, and working in collaboration with Noble, CONSOL Energy has conceded defects on acreage with a value of $23.1 million. See Note 11- Property, Plant and Equipment, in the Notes to the Audited Consolidated Financial Statements included in this Form 10-K for additional details.

•

In the year ended December 31, 2013, an agreement was reached for resolution of the class actions brought by shareholders of CNX Gas alleging that the price paid by CONSOL Energy to acquire all the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010 was not fair. The total settlement provided for a payment to the plaintiffs of $42.7 million, of which the CONSOL Energy’s portion was $19.2 million. See Note 24 - Commitments and Contingencies, in the Notes to the Audited Consolidated Financial Statements included in this Form 10-K for additional details.

Discontinued Operations:

•

On March 12, 2013, smoke was detected exiting the Orndoff shaft at CONSOL Energy's Blacksville No. 2 Mine near Wayne in Greene County, Pennsylvania. All day shift underground employees were safely evacuated and no one sustained injuries. The location of the fire was identified and containment and extinguishment procedures were followed. The fire was successfully extinguished and the longwall restarted May 20, 2013. This event resulted in a pre-tax expense of $34.3 million in the year ended December 31, 2013.


•	Severance and related costs of $9.5 million pre-tax expense related to the change in control of the 5 coal mines and the reduction of supporting administrative staff was reflected in the 2013 financial results.


•	Settlement and curtailment gains totaling $1.6 billion were recognized related to the company’s obligations under the Other Postretirement Benefits, Workers’ Compensation, Pension, Coal Workers’ Pneumoconiosis, and Long-Term Disability plans as a result of the sale to Murray Energy.

Results of Operations

Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

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. Included in net income is income from continuing operations of $79 million, or $0.35 per diluted share, for the year ended December 31, 2013. Income from continuing operations was $318 million, or $1.39 per diluted share, for the year ended December 31, 2012. Also included in net income is income from discontinued operations of $580 million, or $2.52 per diluted share, for the year ended December 31, 2013. Income from discontinued operations was $70 million, or $0.31 per diluted share, for the year ended December 31, 2012.

The total gas division includes Marcellus, coalbed methane (CBM), shallow oil and gas, and other gas. The total gas 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			Percent 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	$	9,469	$	9,252	$	217		2.3	%

Condensate:
Sales Volume (MMcfe)	381		63		318			504.8	%
Sales Volume (Mbbls)	64		11		53			481.8	%
Gross Price ($/Bbl)	$	81.06	$	78.84	$	2.22		2.8	%
Gross Revenue	$	5,158	$	823	$	4,335		526.7	%

GAS
Sales Volume (MMcf)	168,737		155,052		13,685			8.8	%
Sales Price ($/Mcf)	$	3.71	$	2.94	$	0.77		26.2	%
Hedging Impact ($/Mcf)	$	0.45	$	1.22	$	(0.77	)	(63.1	)%
Gross Revenue	$	702,700	$	645,053	$	57,647		8.9	%

The average sales price and average costs for all active gas operations were as follows:



	For the Years Ended December 31,
	2013		2012		Variance			Percent Change
Average Sales Price (per Mcfe)	$	4.30	$	4.22	$	0.08		1.9	%
Average Costs (per Mcfe)	3.51		3.37		0.14			4.2	%
Margin	$	0.79	$	0.85	$	(0.06	)	(7.1	)%

Total gas 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 is 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 price of $4.68 per Mcf. These financial hedges represented 76.9 Bcf of our produced gas sales volumes for the year ended December 31, 2012 at an average price of $5.25 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 thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $337 million of earnings before income tax for the year ended December 31, 2013 compared to $592 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:



	For the Years Ended December 31,
	2013		2012		Variance			Percent Change
Average Sales Price per ton sold	$	69.34	$	77.75	$	(8.41	)	(10.8	)%
Average Costs of Goods Sold per ton	50.78		53.98		(3.20		)	(5.9	)%
Margin	$	18.56	$	23.77	$	(5.21	)	(21.9	)%

The lower average sales price per ton sold reflects a decrease in the global metallurgical coal markets. The coal division priced 7.9 million tons on the export market at an average sales price of $72.27 per ton for the year ended December 31, 2013 compared to 7.5 million tons at an average price of $83.67 per ton 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.


•	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 segment includes industrial supplies activity, coal terminal activity, income taxes and other business activities not assigned to the gas or coal segment.

General and Administrative costs for continuing operations are allocated between divisions (Coal, Gas, Other) based primarily on percentage of total revenue and percentage of total projected capital expenditures. General and Administrative costs are excluded from the coal and gas unit costs above. Total General and Administrative costs from continuing operations were made up of the following items:



	For the Years Ended December 31,
	2013		2012		Variance			Percent Change
Contributions	$	7	$	9	$	(2	)	(22.2	)%
Employee Wages and Related Expenses	33		35		(2		)	(5.7	)%
Advertising and Promotion	4		4		—			—	%
Consulting and Professional Services	21		14		7			50.0	%
Miscellaneous	17		17		—			—	%
Total Company General and Administrative Expenses	$	82	$	79	$	3		3.8	%

Total Company General and Administrative Expenses changed due to the following:


•	Contributions decreased $2 million related to various transactions that occurred throughout both periods, none of which were individually material.


•	Employee wages and related expenses decreased $2 million primarily attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan, as previously discussed. There was also lower salary other post-employment benefit (OPEB) expenses in the period-to-period comparison related to changes in the discount rates and other assumptions.


•	Advertising and promotion remained consistent in the period-to-period comparison.


•	Consulting and professional services increased $7 million in the period-to-period comparison. Various legal proceedings accounted for $3 million of the increase and an additional $2 million was related to tax advisory services. The remaining increase was due to various other corporate initiatives, none of which were individually significant.


•	Miscellaneous general and administrative expenses remained consistent in the period-to-period comparison.

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 $166 million for the year ended December 31, 2013 compared to $148 million for the year ended December 31, 2012. The increase of $18 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 gas or coal. This was offset, in part, due to a modification of the salaried post-employment benefit plan and an increase in the discount rate assumptions used to calculate expense for benefit plans at the

measurement date, which is December 31. 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.

TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2013 compared to the year ended December 31, 2012:

The gas segment had a loss before income tax of $2 million for the year ended December 31, 2013 compared to a earnings before income tax of $39 million for the year ended December 31, 2012.



	For the Year Ended													Difference to Year Ended
	December 31, 2013													December 31, 2012
	Marcellus		CBM		Shallow Oil and Gas			Other Gas			Total Gas			Marcellus		CBM			Shallow Oil and Gas			Other Gas			Total Gas
Sales:
Produced	$	252	$	336	$	131		$	19		$	738		$	118	$	(42	)	$	(4	)	$	9		$	81
Related Party	—		3		—			—			3			—		1			—			—			1
Total Outside Sales	252		339		131			19			741			118		(41		)	(4		)	9			82
Gas Royalty Interest	—		—		—			63			63			—		—			—			13			13
Purchased Gas	—		—		—			7			7			—		—			—			4			4
Other Income	—		—		—			58			58			—		—			—			1			1
Total Revenue and Other Income	252		339		131			147			869			118		(41		)	(4		)	27			100
Lifting	20		37		35			5			97			8		—			(5		)	3			6
Ad Valorem, Severance, and Other Taxes	9		9		10			1			29			5		(1		)	—			(1		)	3
Gathering	50		114		34			3			201			26		8			8			(2		)	40
Gas Direct Administrative, Selling & Other	26		8		10			5			49			9		(6		)	(3		)	2			2
Depreciation, Depletion and Amortization	67		90		60			13			230			20		3			1			4			28
General & Administration	—		—		—			45			45			—		—			—			5			5
Gas Royalty Interest	—		—		—			53			53			—		—			—			14			14
Purchased Gas	—		—		—			5			5			—		—			—			2			2
Exploration and Other Costs	—		—		—			61			61			—		—			—			22			22
Other Corporate Expenses	—		—		—			92			92			—		—			—			15			15
Interest Expense	—		—		—			9			9			—		—			—			4			4
Total Cost	172		258		149			292			871			68		4			1			68			141
Earnings (Loss) Before Income Tax	80		81		(18		)	(145		)	(2		)	50		(45		)	(5		)	(41		)	(41		)

MARCELLUS GAS SEGMENT

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.



	For the Years Ended December 31,
	2013		2012		Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	55.0		35.9		19.1			53.2	%
NGLs Sales Volumes (Bcfe)*	2.5		0.6		1.9			316.7	%
Condensate Sales Volumes (Bcfe)*	0.3		—		0.3			100.0	%
Total Marcellus Gas Sales Volumes (Bcfe)*	57.8		36.5		21.3			58.4	%

Average Sales Price - Gas (Mcf)	$	3.77	$	2.89	$	0.88		30.4	%
Hedging Impact - Gas (Mcf)	$	0.32	$	0.69	$	(0.37	)	(53.6	)%
Average Sales Price - NGLs (Mcfe)*	$	9.09	$	8.68	$	0.41		4.7	%
Average Sales Price - Condensate (Mcfe)*	$	13.73	$	13.54	$	0.19		1.4	%

Total Average Marcellus sales (per Mcfe)	$	4.35	$	3.68	$	0.67		18.2	%
Average Marcellus lifting costs (per Mcfe)	$	0.35	$	0.34	$	0.01		2.9	%
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, selling & costs (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 is 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 is 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 a $0.16 per Mcf increase due to the 2.2 Bcfe additional natural gas liquids and condensate sales volumes. The increase was offset, in part, by a $0.37 per Mcf decrease resulting from various gas swap transactions that settled in the year ended December 31, 2013 compared to the 2012 period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. 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 price of $4.67 per Mcf. For the year ended December 31, 2012, these financial hedges represented 12.4 Bcf at an average price of $4.99 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 are 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 is 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.

•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 a $0.12 per Mcfe 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 party, 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 gas segment are allocated to the individual gas 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.

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.



	For the Years Ended December 31,
	2013		2012		Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	82.9		88.2		(5.3		)	(6.0	)%

Average Sales Price - Gas (Mcf)	$	3.69	$	2.88	$	0.81		28.1	%
Hedging Impact - Gas (Mcf)	$	0.40	$	1.44	$	(1.04	)	(72.2	)%

Total Average CBM sales price (per Mcf)	$	4.09	$	4.32	$	(0.23	)	(5.3	)%
Average CBM lifting costs (per Mcf)	$	0.44	$	0.42	$	0.02		4.8	%
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, selling & other costs (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 and fewer CBM wells being drilled in the 2013 period. Currently, the focus of the gas division is to develop its Marcellus and Utica acreage. The CBM total average sales price decreased $1.04 due to various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. Financial hedges represented approximately 48.3 Bcf of our produced CBM gas sales volumes for the year ended December 31, 2013 at an average price of $4.54 per Mcf. For the year ended December 31, 2012, these financial hedges represented 45.8 Bcf at an average price of $5.34 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 are due to the following items:

•CBM lifting costs were $37 million for the year ended December 31, 2013 compared to $37 million for the year ended December 31, 2012. The decrease in total dollars was primarily due to lower road maintenance and lower contractor services in the period-to-period comparison. The increase in unit costs was due to the decrease in gas sales volumes and was offset, in part, by the decrease in total costs.

•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 reassement of our ad valorem taxes paid to Tazewell County, Virginia resulting in a current year 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 gas segment are allocated to the individual gas 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.

•Depreciation, depletion and amortization attributable to the CBM segment was $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 $28 million, or $0.31 per Mcf for the year ended December 31, 2012.

SHALLOW OIL AND GAS SEGMENT

The shallow oil and gas segment had a loss before income tax of $18 million for the year ended December 31, 2013 compared to a loss before income tax of $13 million for the year ended December 31, 2012.



	For the Years Ended December 31,
	2013			2012			Variance			Percent Change
Shallow Oil and Gas Sales Volumes (Bcf)	27.5			28.7			(1.2		)	(4.2	)%
Oil Sales Volumes (Bcfe)*	0.4			0.5			(0.1		)	(20.0	)%
Total Shallow Oil and Gas Sales Volumes (Bcfe)*	27.9			29.2			(1.3		)	(4.5	)%

Average Sales Price - Gas (Mcf)	$	3.66		$	3.12		$	0.54		17.3	%
Hedging Impact - Gas (Mcf)	$	0.89		$	1.33		$	(0.44	)	(33.1	)%
Average Sales Price - Oil (Mcfe)*	$	14.42		$	15.65		$	(1.23	)	(7.9	)%

Total Average Shallow Oil and Gas sales price (per Mcfe)	$	4.70		$	4.64		$	0.06		1.3	%
Average Shallow Oil and Gas lifting costs (per Mcfe)	$	1.28		$	1.37		$	(0.09	)	(6.6	)%
Average Shallow Oil and Gas ad valorem, Severance, and other taxes (per Mcfe)	$	0.36		$	0.35		$	0.01		2.9	%
Average Shallow Oil and Gas gathering costs (per Mcfe)	$	1.21		$	0.92		$	0.29		31.5	%
Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)	$	0.35		$	0.45		$	(0.10	)	(22.2	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs (per Mcfe)	$	2.14		$	2.02		$	0.12		5.9	%
Total Average Shallow Oil and Gas costs (per Mcfe)	$	5.34		$	5.11		$	0.23		4.5	%
Average Margin for Shallow Oil and Gas (per Mcfe)	$	(0.64	)	$	(0.47	)	$	(0.17	)	36.2	%

*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,which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

Shallow Oil and Gas sales revenues were $131 million for the year ended December 31, 2013 compared to $135 million for the year ended December 31, 2012. The $4 million decrease was primarily due to the 4.5% decrease in total volumes sold, offset, in part, by a 1.3% increase in the total average sales price. The increase in shallow oil and gas total average sales price is primarily the result of a $0.54 per Mcf increase in average market prices offset, in part, by a $0.44 per Mcf decrease due to various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 14.3 Bcf of our produced shallow oil and gas sales volumes for the year ended December 31, 2013 at an average price of $5.20 per Mcf. For the year ended December 31, 2012, these financial hedges represented 18.5 Bcf at an average price of $5.23 per Mcf. The hedging impact on the average sales price was a decrease of $0.44 per Mcf.

Total costs for the shallow oil and gas segment were $149 million for the year ended December 31, 2013 compared to $148 million for the year ended December 31, 2012. The increase in total dollars and unit costs for the shallow oil and gas segment are due to the following items:

•Shallow Oil and Gas lifting costs were $35 million for the year ended December 31, 2013 compared to $40 million for the year ended December 31, 2012. The $5 million decrease in total costs and $0.09 per Mcfe decrease in average unit costs is due to lower well tending costs, and lower salt water disposal costs offset, in part, by an increase in accretion expense on the well plugging liability. The related decrease in unit costs is offset, in part, by the decrease in sales volumes.

•Shallow Oil and Gas ad valorem, severance and other taxes remained consistent at $10 million for the year ended December 31, 2013 and 2012. The increase of $0.01 per Mcfe in unit costs was due to the decrease in sales volumes.

•Shallow Oil and Gas gathering costs were $34 million for the year ended December 31, 2013 compared to $26 million for the year ended December 31, 2012. Gathering costs increased $8 million primarily due to increased firm transportation costs in the period-to-period comparison. Unit costs were further impacted by lower sales volumes.

•Shallow Oil and Gas direct administrative, selling and other costs were $10 million for the year ended December 31, 2013 compared to $13 million for the year ended December 31, 2012. Direct administrative, selling and other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The $3 million decrease in the period-to-period comparison is due to reduced direct administrative labor and Shallow Oil and Gas volumes representing a smaller proportion of CONSOL Energy's total gas sales volumes. These decreases in costs were offset, in part, by lower sales volumes.

•Depreciation, depletion and amortization attributable to the Shallow Oil & Gas segment was $60 million for the year ended December 31, 2013 compared to $59 million for the year ended December 31, 2012 There was approximately $52 million, or $1.87 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the year ended December 31, 2013. There was approximately $51 million, or $1.75 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the year ended December 31, 2012. There was approximately $8 million, or $0.27 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the year ended December 31, 2013. There was $8 million, or $0.27 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the year ended December 31, 2012.

OTHER GAS SEGMENT

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

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee and the Utica Shale in Ohio. Revenue from these operations were approximately $19 million for the year ended December 31, 2013 and $10 million for the year ended December 31, 2012. Total costs related to these other sales were $27 million for the year ended December 31, 2013 and $21 million for the year ended December 31, 2012. A per unit analysis of the other operating costs in Chattanooga Shale and Utica Shale is not meaningful due to the relatively low volumes sold in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas 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.



	For the Years Ended December 31,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (Bcf)	15.3		18.0		(2.7		)	(15.0	)%
Average Sales Price (per Mcf)	$	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.



	For the Years Ended December 31,
	2013		2012		Variance		Percent Change
Purchased Gas Sales Volumes (Bcf)	1.6		1.1		0.5		45.5	%
Average Sales Price (per Mcf)	$	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 change 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 gas segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $45 million for the year ended December 31, 2013 and $40 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 quarterly report for a detailed cost explanation.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. Royalty interest gas costs were $53 million for the year ended December 31, 2013 compared to $39 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.



	For the Years Ended December 31,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (Bcf)	15.3		18.0		(2.7		)	(15.0	)%
Average Cost (per Mcf)	$	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.



	For the Years Ended December 31,
	2013		2012		Variance		Percent Change
Purchased Gas Sales Volumes (Bcf)	1.6		1.1		0.5		45.5	%
Average Cost (per Mcf)	$	3.05	$	2.44	$	0.61	25.0	%

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:



	For the Years Ended December 31,
	2013		2012		Variance			Percent Change
Marcellus Title Defects	$	23	$	4	$	19		475.0	%
Dry Hole Costs	8		3		5			166.7	%
Exploration Costs	20		18		2			11.1	%
Lease Expiration Costs	10		14		(4		)	(28.6	)%
Total Exploration and Other Costs	$	61	$	39	$	22		56.4	%


•	CONSOL Energy has completed its review of the title defect notice, asserted by Noble, and working in collaboration with Noble, conceded title defects on acreage which had a carrying value to CONSOL Energy 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 $5 million due to various transactions that occurred throughout both periods, none of which were individually material.


•	Exploration expense increased $2 million due to increased exploratory expenses associated primarily with the Utica operating areas and various transactions that occurred throughout both periods, none of which were individually material.


•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $4 million decrease is due to fewer lease expirations in the current period when compared with the prior period.

Other corporate expenses were $92 million for the year ended December 31, 2013 compared to $77 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:



	For the Years Ended December 31,
	2013		2012		Variance			Percent Change
Unutilized firm transportation	$	35	$	16	$	19		118.8	%
Stock-based compensation	24		18		6			33.3	%
Bank fees	7		7		—			—	%
Short-term incentive compensation	20		26		(6		)	(23.1	)%
PA Impact fees	—		4		(4		)	(100.0	)%
Other	6		6		—			—	%
Total Other Corporate Expenses	$	92	$	77	$	15		19.5	%


•	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 $19 million increase is 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.


•	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.

•

PA impact fees are related to legislation in the state of Pennsylvania (Act 13 of 2012, House Bill 1950) which was signed into law during the first quarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. As part of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to 2012. The $4 million represents this one-time initial assessment on wells drilled prior to January 1, 2012. Ongoing PA impact fees, which relate to wells drilled in the applicable period, are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.


•	Other corporate related expense remained consistent in the period-to-period comparison.

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.

TOTAL COAL SEGMENT ANALYSIS - CONTINUING OPERATIONS for the year ended December 31, 2013 compared to the year ended December 31, 2012:

The coal segment contributed $337 million of earnings before income tax from continuing operations in the year ended December 31, 2013 compared to $592 million in the year ended December 31, 2012.



	For the Year Ended														Increase (Decrease) from Year Ended
	December 31, 2013														December 31, 2012
	Thermal Coal			High Vol Met Coal		Low Vol Met Coal			Other Coal			Total Coal			Thermal Coal			High Vol Met Coal			Low Vol Met Coal			Other Coal			Total Coal
Sales:
Produced Coal	$	1,388		$	160	$	447		$	—		$	1,995		$	(43	)	$	(50	)	$	(59	)	$	(5	)	$	(157	)
Purchased Coal	—			—		—			23			23			—			—			—			6			6
Total Outside Sales	1,388			160		447			23			2,018			(43		)	(50		)	(59		)	1			(151		)
Freight Revenue	—			—		—			35			35			—			—			—			(72		)	(72		)
Other Income	2			2		—			98			102			—			(4		)	—			(226		)	(230		)
Total Revenue and Other Income	1,390			162		447			156			2,155			(43		)	(54		)	(59		)	(297		)	(453		)
Costs and Expenses:
Beginning inventory costs	33			—		21			—			54			(34		)	(2		)	5			—			(31		)
Total direct costs	626			79		196			101			1,002			33			(16		)	12			(44		)	(15		)
Total royalty/production taxes	68			5		26			2			101			(6		)	(4		)	(4		)	(1		)	(15		)
Total direct services to operations	134			15		27			163			339			(20		)	(6		)	5			(54		)	(75		)
Total retirement and disability	58			7		25			10			100			(3		)	(3		)	(3		)	(10		)	(19		)
Depreciation, depletion and amortization	116			15		41			46			218			(4		)	(7		)	4			13			6
Ending inventory costs	(21		)	—		(10		)	—			(31		)	12			—			11			—			23
Total Costs and Expenses	1,014			121		326			322			1,783			(22		)	(38		)	30			(96		)	(126		)
Freight Expense	—			—		—			35			35			—			—			—			(72		)	(72		)
Total Costs of Goods Sold	1,014			121		326			357			1,818			(22		)	(38		)	30			(168		)	(198		)
Earnings (Loss) Before Income Taxes	$	376		$	41	$	121		$	(201	)	$	337		$	(21	)	$	(16	)	$	(89	)	$	(129	)	$	(255	)

THERMAL COAL SEGMENT

The thermal coal segment contributed $376 million to total Company earnings before income tax for the year ended December 31, 2013 compared to $397 million for the year ended December 31, 2012. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Years Ended December 31,
	2013			2012			Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	21.5			20.7			0.8			3.9	%
Average Sales Price Per Thermal Ton Sold	$	64.78		$	69.08		$	(4.30	)	(6.2	%)

Beginning Inventory Costs Per Thermal Ton	$	50.86		$	61.92		$	(11.06	)	(17.9	%)

Total Direct Operating Costs Per Thermal Ton Produced	$	29.55		$	29.29		$	0.26		0.9	%
Total Royalty/Production Taxes Per Thermal Ton Produced	3.22			3.65			(0.43		)	(11.8	%)
Total Direct Services to Operations Per Thermal Ton Produced	6.31			7.61			(1.30		)	(17.1	%)
Total Retirement and Disability Per Thermal Ton Produced	2.76			3.01			(0.25		)	(8.3	%)
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	5.45			5.93			(0.48		)	(8.1	%)
Total Production Costs Per Thermal Ton Produced	$	47.29		$	49.49		$	(2.20	)	(4.4	%)

Ending Inventory Costs Per Thermal Ton	$	(50.82	)	$	(50.89	)	$	0.07		0.1	%

Total Costs of Goods Sold Per Thermal Ton Sold	$	47.33		$	50.00		$	(2.67	)	(5.3	%)
Average Margin Per Thermal Ton Sold	$	17.45		$	19.08		$	(1.63	)	(8.5	%)

Thermal coal revenue was $1,388 million for the year ended December 31, 2013 compared to $1,431 million for the year ended December 31, 2012. The $43 million decrease was attributable to a $4.30 per ton lower average sales price offset, in part, by a 0.8 million increase in tons sold. The lower average thermal coal sales price in the 2013 period was the result of the renewal of several domestic thermal contracts whose pricing was reduced effective January 1, 2013. The decrease in price was partially offset by 2.0 million tons of thermal coal being priced on the export market at an average sales price of $63.04 per ton for the year ended December 31, 2013 compared to 2.1 million tons at an average price of $61.28 per ton for the year ended December 31, 2012.

Other income attributable to the thermal coal segment represents earnings from our equity affiliates that operate thermal coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.

Total cost of goods sold is comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for thermal coal was $1,014 million for the year ended December 31, 2013, or $22 million lower than the $1,036 million for the year ended December 31, 2012. Total cost of goods sold for thermal coal was $47.33 per ton in the year ended December 31, 2013 compared to $50.00 per ton in the year ended December 31, 2012. The decrease in total dollars and unit costs per thermal ton was due to the items described below.

Direct operating costs are comprised of labor, supplies, maintenance, power and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Direct operating costs related to the thermal coal segment were $626 million in the year ended December 31, 2013 compared to $593 million in the year ended December 31, 2012. Direct operating costs were $29.55 per ton produced in the current period compared to $29.29 per ton produced in the prior period. Changes in the average direct operating costs per thermal ton produced were primarily related to the following items:


•	In 2013, CONSOL Energy entered into a new longwall lease at Bailey Mine which resulted in higher cost per ton produced in the period-to-period comparison.


•	Project expense increased in the 2013 period due to a longwall overhaul and a waterline extension project at Bailey Mine.


•	Power expense increased in the 2013 period due to an increase in rates in the current year.


•	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.

•


•	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.

Royalties and production taxes were $68 million for the year ended December 31, 2013 compared to $74 million for the year ended December 31, 2012. The $6 million decrease in total dollars was primarily due to the the lower average sales prices which is the basis for most production taxes. The unit costs per thermal ton produced decreased $0.43 per ton to $3.22 per ton produced, due to the increase in production volumes.

Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The cost of these support services was $134 million in the current period compared to $154 million in the prior period. Direct services to the operations were $6.31 per ton produced in the current period compared to $7.61 per ton produced in the prior period. Changes in the average direct service to operations cost per thermal ton produced were primarily related to the following items:


•	Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing and nature of properties undermined in the period-to-period comparison.


•	Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, as discussed previously.


•	Unit costs decreased due to the increase in production volumes since fixed costs are spread over more tons.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-employment benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. These liabilities 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. The retirement and disability costs attributable to the thermal coal segment were $58 million for the year ended December 31, 2013 compared to $61 million for the year ended December 31, 2012. The decrease in total dollars was primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salaried other post-employment benefit plan that occurred after December 31, 2012. Average cost per thermal ton produced decreased $0.25 per ton to $2.76 per ton produced due to the increase in production volumes.

Depreciation, depletion and amortization for the thermal coal segment was $116 million for the year ended December 31, 2013 compared to $120 million for the year ended December 31, 2012. Unit costs per thermal ton produced decreased $0.48 in the period-to-period comparison to $5.45 per ton. Total dollars and unit costs decreased primarily due the idling of the Fola Complex in August 2012. The decrease was off-set, in part, by lower amortization and depletion for the 2012 period due to the structural failure that affected production at both the Bailey and Enlow Fork Mines. Also, unit costs improved due to the increase in production volumes.

Changes in thermal coal inventory volumes and carrying value resulted in $12 million of cost of goods sold in the year ended December 31, 2013 compared to $34 million of cost of goods sold in the year ended December 31, 2012. Thermal coal inventory was 0.4 million tons at December 31, 2013 compared to 0.6 million tons at December 31, 2012.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $41 million to total Company earnings before income tax for the year ended December 31, 2013 compared to $57 million for the year ended December 31, 2012. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Years Ended December 31,
	2013		2012		Increase (Decrease)			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	2.5		3.3		(0.8		)	(24.2	%)
Average Sales Price Per High Vol Met Ton Sold	$	63.44	$	63.93	$	(0.49	)	(0.8	%)

Beginning Inventory Costs Per High Vol Met Ton	$	—	$	—	$	—		—	%

Total Direct Operating Costs Per High Vol Met Ton Produced	$	31.39	$	28.98	$	2.41		8.3	%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	1.82		2.72		(0.90		)	(33.1	%)
Total Direct Services to Operations Per High Vol Met Ton Produced	5.96		6.22		(0.26		)	(4.2	%)
Total Retirement and Disability Per High Vol Met Ton Produced	2.94		3.10		(0.16		)	(5.2	%)
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	5.96		6.63		(0.67		)	(10.1	%)
Total Production Costs Per High Vol Met Ton Produced	$	48.07	$	47.65	$	0.42		0.9	%

Ending Inventory Costs Per High Vol Met Ton	$	—	$	—	$	—		—	%

Total Costs Per High Vol Met Ton Sold	$	48.07	$	48.43	$	(0.36	)	(0.7	%)
Margin Per High Vol Met Ton Sold	$	15.37	$	15.50	$	(0.13	)	(0.8	%)

High volatile metallurgical coal revenue was $160 million for the year ended December 31, 2013 compared to $210 million for the year ended December 31, 2012. Average sales prices for high volatile metallurgical coal decreased $0.49 per ton in a period-to-period comparison. CONSOL Energy priced 2.3 million tons of high volatile metallurgical coal in the export market at an average sales price of $61.62 per ton for the year ended December 31, 2013 compared to 2.8 million tons at an average price of $60.75 per ton for the year ended December 31, 2012. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Other income attributable to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate high volatile metallurgical coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.

Total cost of goods sold is comprised of changes in high volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for high volatile metallurgical coal was $121 million for the year ended December 31, 2013, or $38 million lower than the $159 million for the year ended December 31, 2012. Total cost of goods sold for high volatile metallurgical coal was $48.07 per ton in the year ended December 31, 2013 compared to $48.43 per ton in the year ended December 31, 2012. The decrease in total dollars and unit costs per high volatile metallurgical ton was due to the items described below.

Direct operating costs related to the high volatile metallurgical coal segment were $79 million in the year ended December 31, 2013 compared to $95 million in the year ended December 31, 2012. The reduction in total dollars was primarily due to a reduction in mine maintenance and supply expense as a result of the shutdown of the Fola Mining Complex in August 2012, along with the mix of mines which sold on the high volatile coal market in the period-to-period comparison. Direct operating costs were $31.39 per ton produced in the current period compared to $28.98 per ton produced in the prior period. The increase in the average direct operating costs per high volatile metallurgical ton produced was primarily due to 0.8 million fewer tons produced. This resulted in fixed costs being allocated over less tons, resulting in higher unit costs.

Royalties and production taxes were $5 million or improved $4 million in the current period primarily due to the shutdown of the Fola Mining Complex in August 2012 and the mix of mines which sold on the high volatile metallurgical coal market. Mines with higher royalty rates produced a larger portion of the high volatile metallurgical coal shipped in the prior

period compared to the current period. Unit costs decreased due to lower total dollars spent, and were offset, in part, by the lower volumes produced.

Direct service costs for high volatile metallurgical coal were $15 million in the current period compared to $21 million in the prior period. Direct services to the operations for high volatile metallurgical coal were $5.96 per ton in the current period compared to $6.22 per ton in the prior period. Changes in the average direct services to operations cost per ton for high volatile metallurgical coal produced were primarily related to the following items:


•	Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing and nature of properties undermined in the period-to-period comparison. The decrease in unit costs was offset, in part, by the reduction in production tons.


•	Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, as discussed previously. The decrease in unit costs was also offset, in part, by the reduction in production tons.

Retirement and disability costs attributable to the high volatile metallurgical coal segment were $7 million for the year ended December 31, 2013 compared to $10 million for the year ended December 31, 2012. The decrease in total high volatile metallurgical coal retirement and disability total dollars and unit costs was primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salaried other post-employment benefit plan that occurred after December 31, 2012. The decrease in unit costs was off-set, in part, by the lower volumes produced.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $15 million for the year ended December 31, 2013 and $22 million for the year ended December 31, 2012. Total dollars and unit costs per high volatile metallurgical ton produced were lower in the year ended December 31, 2013 compared to the year ended December 31, 2012 due to the 0.8 million decrease in production tons which resulted in lower depletion expense.

There were no changes in volumes or carrying value of coal inventory in the year ended December 31, 2013 and December 31, 2012. There was no high volatile metallurgical coal inventory at December 31, 2013 or December 31, 2012.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $121 million to total Company earnings before income tax in the year ended December 31, 2013 compared to $210 million in the year ended December 31, 2012. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Years Ended December 31,
	2013			2012			Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	4.8			3.6			1.2			33.3	%
Average Sales Price Per Low Vol Met Ton Sold	$	92.64		$	140.11		$	(47.47	)	(33.9	%)

Beginning Inventory Costs Per Low Vol Met Ton	$	86.38		$	67.60		$	18.78		27.8	%

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	41.34		$	50.88		$	(9.54	)	(18.8	%)
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	5.54			8.33			(2.79		)	(33.5	%)
Total Direct Services to Operations Per Low Vol Met Ton Produced	5.66			6.03			(0.37		)	(6.1	%)
Total Retirement and Disability Per Low Vol Met Ton Produced	5.28			7.63			(2.35		)	(30.8	%)
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	8.69			10.23			(1.54		)	(15.1	%)
Total Production Costs Per Low Vol Met Ton Produced	$	66.51		$	83.10		$	(16.59	)	(20.0	%)

Ending Inventory Costs Per Low Vol Met Ton	$	(65.68	)	$	(86.38	)	$	20.70		24.0	%

Total Costs Per Low Vol Met Ton Sold	$	67.53		$	81.89		$	(14.36	)	(17.5	%)
Margin Per Low Vol Met Ton Sold	$	25.11		$	58.22		$	(33.11	)	(56.9	%)

Low volatile metallurgical coal revenue was $447 million for the year ended December 31, 2013 compared to $506 million for the year ended December 31, 2012. The $59 million decrease was primarily attributable to a $47.47 per ton lower average sales price. The average sales price for low volatile metallurgical coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market. For the 2013 period, 3.7 million tons of low volatile metallurgical coal were priced on the export market at an average price of $83.81 per ton compared to 2.6 million tons at an average price of $125.37 per ton for the 2012 period. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold is comprised of changes in low volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for low volatile metallurgical coal 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 of goods sold for low volatile metallurgical coal was $67.53 per ton in the year ended December 31, 2013 compared to $81.89 per ton in the year ended December 31, 2012. The increase in total dollars and decrease in unit costs per low volatile metallurgical ton was due to the items described below.

Direct operating costs related to the low volatile metallurgical coal segment were $196 million in the year ended December 31, 2013 compared to $184 million in the year ended December 31, 2012. Direct operating costs increased 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. Direct operating costs were $41.34 per ton produced in the current period compared to $50.88 per ton produced in the prior period. Low volatile metallurgical coal production was 1.2 million tons higher in the current 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.

Royalties and production taxes were $26 million for the year ended December 31, 2013 compared to $30 million for the year ended December 31, 2012. Unit costs improved $2.79 per low volatile metallurgical ton produced to $5.54 per ton

produced in the current period compared to $8.33 per ton produced in the prior period. The decrease in total dollars and unit costs was primarily related to the $47.47 per ton decrease in average sales price, which is the basis for most royalties and production taxes.

Direct services costs for low volatile metallurgical coal were $27 million in the current period and $22 million in the prior period. The increase in total dollars was primarily due to higher water treatment and subsidence costs in the 2013 period. The increase in costs is a direct result of the Buchanan Mine being temporarily idled in the 2012 period. Average cost per low volatile metallurgical ton produced decreased $0.37 per ton due to the increase in production tons.

Retirement and disability costs attributable to the low volatile metallurgical coal segment were $25 million for the year ended December 31, 2013 compared to $28 million for the year ended December 31, 2012. The decrease in the low volatile metallurgical coal retirement and disability costs total dollars was primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salaried other post-employment benefit plan that occurred after December 31, 2012. This, coupled with the increase in volumes, resulted in an improvement in the unit costs of $2.35 per ton in the period-to-period comparison.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $41 million for the year ended December 31, 2013 and $37 million for the year ended December 31, 2012. Unit costs per low volatile metallurgical ton produced were $1.54 per ton lower in the current period due to the 1.2 million increase in production tons.

Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in an increase of $11 million to cost of goods sold in the year ended December 31, 2013 and a decrease of $5 million to cost of goods sold in the year ended December 31, 2012. Produced low volatile metallurgical coal inventory was 0.2 million tons at December 31, 2013 compared to 0.3 million tons at December 31, 2012.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $201 million for the year ended December 31, 2013 compared to a loss before income tax of $72 million for the year ended December 31, 2012. The other coal segment includes purchased coal activities, idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

Other coal segment produced coal sales includes revenue from the sale of 0.1 million tons of coal which was recovered during the reclamation process at idled facilities for the year ended December 31, 2012. No coal was recovered during the reclamation process at idled facilities for the year ended December 31, 2013. The primary focus of the activity at these locations is reclaiming disturbed land in accordance with the mining permit requirements after final mining has occurred. The tons sold are incidental to total Company production or sales.

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.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is offset by freight expense. Freight revenue was $35 million for the year ended December 31, 2013 compared to $107 million for the year ended December 31, 2012. The $72 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $98 million for the year ended December 31, 2013 compared to $324 million for the year ended December 31, 2012. The $226 million decrease is due to the following items:

•

Gain on sale of assets attributable to the Other Coal segment was $46 million in the year ended December 31, 2013 compared to $271 million in the year ended December 31, 2012. The decrease of $225 million was primarily related to 2012 sales of non-producing assets in the Northern Powder River Basin that resulted in a gain on sale of $151 million, as well as coal and surface lands in Illinois and West Virginia that resulted in a gain on sale of $112 million. This is offset by the 2013 sale of Potomac coal reserves that resulted in a gain on sale of $25 million and the sale of 50% interest in a joint venture in Alberta, Canada that resulted in a gain on sale of $15 million. 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 detail of these sales. The remaining $2 million decrease was related to various transactions that occurred throughout both periods, none of which were individually material.


•	In the year ended December 31, 2013, $5 million of business interruption insurance proceeds were received related to the 2012 Bailey Belt Conveyor accident. There is no assurance that additional proceeds from the incident will be received.


•	The remaining $6 million decrease in other income is due to various items, none of which were individually material.

Other coal segment total costs were $357 million for the year ended December 31, 2013 compared to $525 million for the year ended December 31, 2012. The decrease of $168 million was due to the following items:



	For the Years Ended December 31,
	2013		2012		Variance
Freight Expense	$	35	$	107	$	(72	)
Bailey Belt Incident	—		42		(42		)
Closed and Idle Mines	107		134		(27		)
Litigation Contingencies	—		17		(17		)
Voluntary Incentive Separation Program	—		13		(13		)
General and Administrative Expense	100		102		(2		)
Purchased Coal	43		41		2
Stock-based Compensation	33		23		10
Other	39		46		(7		)
Total other coal segment costs	$	357	$	525	$	(168	)

•

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. The $72 million decrease in freight expense was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.


•	Bailey Belt Incident costs represent expenses during the belt-reconstruction period. The mine was idled during this period but there was continued advancement of the mine and on-going projects which resulted in $42 million of expense.

•

Closed and idle mine costs decreased approximately $27 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 and $18 million due to the decision to idle operations at Buchanan Mine for three months in 2012. These decrease were offset, in part, by an increase of $8 million in costs incurred primarily by the Amonate Complex. 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 $1 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.


•	General and Administrative Expense decreased $2 million due to various items that occurred in both periods, none of which were individually material.


•	Purchased coal costs increased $2 million due to higher amounts of coal that was purchased to fulfill various contracts.

•

Stock-based compensation was $10 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. 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.


•	Other expenses related to the coal segment decreased $7 million due to various transactions that occurred throughout both periods, none of which were individually material.

OTHER SEGMENT ANALYSIS for the year ended December 31, 2013 compared to the year ended December 31, 2012:

The other segment includes activity from the sales of industrial supplies, coal terminal operations and various other corporate activities that are not allocated to the gas or coal segment. The other segment had a loss before income tax of $288 million for the year ended December 31, 2013 compared to a loss before income tax of $224 million for the year ended December 31, 2012. The other segment 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.



	For the Years Ended December 31,
	2013			2012			Variance			Percent Change
Sales—Outside	$	260		$	294		$	(34	)	(11.6	)%
Other Income	19			6			13			216.7	%
Total Revenue	279			300			(21		)	(7.0	)%
Cost of Goods Sold and Other Charges	332			292			40			13.7	%
Depreciation, Depletion & Amortization	13			12			1			8.3	%
Taxes Other Than Income Tax	11			5			6			120.0	%
Interest Expense	211			215			(4		)	(1.9	)%
Total Costs	567			524			43			8.2	%
Loss Before Income Tax	(288		)	(224		)	(64		)	(28.6	)%
Income Tax (Benefit) Expense	(33		)	89			(122		)	(137.1	)%
Net Loss	$	(255	)	$	(313	)	$	58		18.5	%

Industrial supplies:

Total revenue from industrial supplies was $218 million for the year ended December 31, 2013 compared to $244 million for the year ended December 31, 2012. The decrease was related to lower sales volumes.

Total costs related to industrial supply sales were $216 million for the year ended December 31, 2013 compared to $239 million for the year ended December 31, 2012. The decrease of $23 million was primarily related to lower sales volumes and various changes in inventory costs, none of which were individually material.

Transportation operations:

Total revenue from transportation operations was $47 million for the year ended December 31, 2013 compared to $52 million for the year ended December 31, 2012. The decrease of $5 million was primarily due to decreased thru-put volumes as well as lower per ton thru-put rates for the current period.

Total costs related to the transportation operations was $41 million for the year ended December 31, 2013 compared to$43 million for the year ended December 31, 2012. The $2 million decrease was due to lower thru-put volumes.

Miscellaneous other:

Additional other income of $14 million was recognized for the year ended December 31, 2013 compared to $4 million for the year ended December 31, 2012. The $10 million increase was primarily due to the following items:



	For the Years Ended December 31,
	2013		2012		Variance
Pennsylvania Turnpike Settlement	$	9	$	—	$	9
Equity in Earnings of Affiliates	1		—		1
Towing Income	1		1		—
Other	3		3		—
	$	14	$	4	$	10


•	Pennsylvania Turnpike Settlement relates to mediation with the PA Turnpike Commission that was settled for $9 million.


•	Equity in Earnings increased $1 million due to an increase in earnings from our Equity Affiliates in the current period.


•	Towing income remained consistent in the period to period comparison.


•	Other income remained consistent in the period to period comparison.

Other corporate costs in the other segment include interest expense, transaction and financing fees and various other miscellaneous corporate charges. Total other costs were $310 million for the year ended December 31, 2013 compared to $242 million for the year ended December 31, 2012. Other corporate costs increased due to the following items:



	For the Years Ended December 31,
	2013		2012		Variance
Pension Settlement	$	39	$	—	$	39
CNX Gas Shareholder Settlement	19		—		19
Corporate Initiative Fees and Other Legal Charges	15		4		11
Accelerated Bank Fees	3		—		3
Bank Fees	15		13		2
Interest Expense	211		215		(4		)
Other	8		10		(2		)
	$	310	$	242	$	68


•	Pension settlement expenses were required when lump sum distributions made for the 2013 plan year exceeded the total of the service and interest costs for the 2013 plan year.

•

The CNX Gas shareholder settlement is the result of an agreement in principle 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 provides for a payment to the plaintiffs of $43 million, of which the Company paid $19 million.

•

Corporate initiative fees and other legal charges reflect various charges for services related to corporate initiatives to evaluate 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.


•	Accelerated Bank Fees represents 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.


•	Bank fees increased $2 million mainly due to higher borrowings on the CNX Gas revolving credit facilities in the period-to-period comparison.


•	Interest Expense decreased $4 million primarily due to a reduction in capitalized interest due to lower capital expenditures for major construction projects in the current period.


•	Other corporate items decreased $2 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 current 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.



	For the Years Ended December 31,
	2013			2012			Variance			Percent Change
Total Company Earnings Before Income Tax	$	46		$	407		$	(361	)	(88.8	)%
Income Tax (Benefit) Expense	$	(33	)	$	89		$	(122	)	(137.5	)%
Effective Income Tax Rate	(72.0		)%	22.0		%	(94.0		)%

Results of Operations

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $388 million, or $1.70 per diluted share, for the year ended December 31, 2012. Net income attributable to CONSOL Energy shareholders was $632 million, or $2.76 per diluted share, for the year ended December 31, 2011. Included in net income is income from continuing operations of $318 million, or $1.39 per diluted share, for the year ended December 31, 2012. Income from continuing operations was $682 million, or $2.98 per diluted share, for the year ended December 31, 2011. Also included in net income is income from discontinued operations of $70 million, or $0.31 per diluted share, for the year ended December 31, 2012. There was a loss from discontinued operations of $49 million, or a loss of $0.22 per diluted share, for the year ended December 31, 2011.

The total gas division includes Marcellus, coalbed methane (CBM), shallow oil and gas, and other gas. The total gas division contributed $39 million of earnings before income tax for the year ended December 31, 2012 compared to $130 million for the year ended December 31, 2011. Total gas production was 156.3 billion net cubic feet for the year ended December 31, 2012 compared to 153.5 billion net cubic feet for the year ended December 31, 2011. Total gas production increased primarily due to the on-going drilling program, partially offset by 10.7 billion net cubic feet of production related to both the 2011 divestiture of Antero Resources Appalachian Corp. (Antero) and the 2011 Noble Joint Venture. Production also decreased due to the Buchanan Mine idling for portions of 2012 as previously discussed.

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)	2012		2011		Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	610		—		610			100.0	%
Sales Volume (Mbbls)	102		—		102			100.0	%
Gross Price ($/Bbl)	$	52.32	$	—	$	52.32		100.0	%
Gross Revenue	$	5,314	$	—	$	5,314		100.0	%

Oil:
Sales Volume (MMcfe)	600		563		37			6.6	%
Sales Volume (Mbbls)	100		94		6			6.4	%
Gross Price ($/Bbl)	$	92.58	$	94.20	$	(1.62	)	(1.7	)%
Gross Revenue	$	9,252	$	8,729	$	523		6.0	%

GAS
Sales Volume (MMcf)	155,052		152,940		2,112			1.4	%
Sales Price ($/Mcf)	$	2.94	$	4.25	$	(1.31	)	(30.8	)%
Hedging Impact ($/Mcf)	$	1.22	$	0.63	$	0.59		93.7	%
Gross Revenue	$	645,053	$	743,038	$	(97,985	)	(13.2	)%

The average sales price and average costs for all active gas operations were as follows:



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Average Sales Price (per Mcfe)	$	4.22	$	4.90	$	(0.68	)	(13.9	)%
Average Costs (per Mcfe)	3.37		3.53		(0.16		)	(4.5	)%
Margin	$	0.85	$	1.37	$	(0.52	)	(38.0	)%

Total gas division outside sales revenues were $659 million for the year ended December 31, 2012 compared to $752 million for the year ended December 31, 2011. The decrease was primarily due to the 13.9% reduction in average price per Mcfe, offset, in part, by the 2% increase in volumes sold. The decrease in average sales price is the result of the decline in general market prices, partially offset 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 76.9 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2012 at an average price of $5.25 per per Mcf. These financial hedges represented 84.0 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2011 at an average price of $5.21 per Mcf.

Changes in the average cost per Mcfe of gas sold were primarily related to the following items:


•	Higher volumes in the period-to-period comparison due to the on-going drilling program, offset, in part, by 10.7 billion cubic feet divested in the 2011 Noble and the 2011 Antero transactions resulted in lower average costs per Mcfe sold. Fixed costs are allocated over increased volumes, resulting in lower unit costs.

•

Lower units-of-production depreciation, depletion and amortization rates for producing properties. These rates were generally calculated using the net book value of assets divided by either proved or proved developed reserve additions. Increased proved and proved developed reserves relative to the net book value of the producing assets as compared with the prior year resulted in a lower units-of-production rate.


•	Lower direct administrative, selling and other costs per Mcfe sold due to increased sales volumes and decreased actual dollars as a result of lower direct administrative labor and other costs.


•	Gathering costs increased in the period-to-period comparison due to higher transportation charges.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $592 million of earnings before income tax from continuing operations for the year ended December 31, 2012 compared to $1,033 million for the year ended December 31, 2011. The total coal division sold 27.6 million tons of coal produced from continuing operations for the year ended December 31, 2012 compared to 32.1 million tons for the year ended December 31, 2011.

The average sales price and average costs per ton for continuing coal operations were as follows:



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Average Sales Price per ton sold	$	77.75	$	90.10	$	(12.35	)	(13.7	)%
Average Costs of Goods Sold per ton	53.98		51.88		2.10			4.0	%
Margin	$	23.77	$	38.22	$	(14.45	)	(37.8	)%

The lower average sales price per ton sold reflects a decrease in the global metallurgical coal markets, slightly offset by higher thermal coal average prices as a result of several successful renegotiations of domestic thermal contracts where pricing took effect January 1, 2012. The coal division priced 7.5 million tons on the export market at an average sales price of $83.67 per ton for the year ended December 31, 2012 compared to 9.7 million tons at an average price of $132.84 per ton for the year ended December 31, 2011. All other tons were sold on the domestic market. The decreased sales tonnage is primarily due to decreased coal demand in both thermal and metallurgical markets and curtailed shipments due to the Bailey Belt incident in 2012, as discussed previously.

Average costs per ton sold increased $2.10 per ton in the period-to-period comparison due primarily to the following:


•	Average cost of goods sold per ton increased due to fewer tons sold. Fixed costs are allocated over fewer sales tons, resulting in higher unit costs.


•	The idled longwall at Buchanan Mine during portions of 2012 resulted in an increase in unit costs as the fixed costs were allocated over fewer tons.


•	Average depreciation, depletion and amortization increased due to additional assets placed into service after the 2011 period.


•	Average operating supplies and maintenance costs per ton increased due to additional equipment maintenance, timing of major equipment overhaul costs, increased fuel and lubricants and use of pumpable cribs for roof support.


•	Average retirement and disability cost per ton decreased due to the improvement in other postretirement benefits discussed in the long-term liabilities section below.

The other segment includes industrial supplies activity, coal terminal activity, income taxes and other business activities not assigned to the gas or coal segment.

At the beginning of 2012, management decided that it would no longer consider general and administrative costs on a segment by segment basis as a factor in their decision making process. These decisions include allocation of capital and individual segment profit performance results. Management did conclude that general and administrative costs would continue to be considered in results at the divisional level (total gas and total coal). In order to present financial information in a manner consistent with internal management's evaluations, the prior period general and administrative costs have been reclassified to reflect information consistent with the current year's presentation. The total divisional results have not changed. Individual segment results within the division have been recast to reflect costs excluding general and administrative. General and administrative costs are excluded from the gas and coal unit costs above. As in the prior periods, general and administrative costs are allocated between divisions (Gas, Coal, Other) based primarily on percentage of total revenue and percentage of total projected capital expenditures. The total general and administrative costs were made up of the following items:



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Employee Wages and Related Expenses	$	35	$	44	$	(9	)	(20.5	)%
Advertising and Promotion	4		7		(3		)	(42.9	)%
Consulting and Professional Services	14		17		(3		)	(17.6	)%
Contributions	9		10		(1		)	(10.0	)%
Miscellaneous	17		19		(2		)	(10.5	)%
Total Company General and Administrative Expenses	$	79	$	97	$	(18	)	(18.6	)%

Total Company General and Administrative Expenses changed due to the following:

•

Employee wages and related expenses decreased $9 million primarily attributable to lower salary OPEB expenses in the period-to-period comparison. The lower expenses relate to changes in the discount rates and other assumptions, and a modification of the salaried other post-employment benefit plan. 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 total Company expense increases


•	Advertising and promotion decreased $3 million in the period-to-period comparison due to a reduction in CONSOL Energy's advertising and promotion campaign.


•	Consulting and professional services decreased $3 million in the period-to-period comparison due to various legal proceedings and corporate initiatives, none of which were individually significant.


•	Contributions decreased $1 million in the period-to-period comparison due to various transactions, none of which were individually material.


•	Miscellaneous general and administrative expenses decreased $2 million in the period-to-period comparison due to various transactions throughout both periods, none of which were individually material.

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 $148 million for the year ended December 31, 2012 compared to $176 million for the year ended December 31, 2011. The decrease was primarily due to a decrease in the discount rate assumptions used to calculate expense for benefit plans at the measurement date, which is December 31. Additionally, a part of the decrease was due to a plan modification for the salaried OPEB plan which required a remeasurement at March 31, 2012. 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 total Company expense increases.

TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2012 compared to the year ended December 31, 2011:

The gas segment contributed $39 million to earnings before income tax for the year ended December 31, 2012 compared to $130 million for the year ended December 31, 2011.



	For the Year Ended												Difference to Year Ended
	December 31, 2012												December 31, 2011
	Marcellus		CBM		Shallow Oil and Gas			Other Gas			Total Gas		Marcellus			CBM			Shallow Oil and Gas			Other Gas			Total Gas
Sales:
Produced	$	134	$	378	$	135		$	10		$	657	$	15		$	(83	)	$	(20	)	$	(2	)	$	(90	)
Related Party	—		2		—			—			2		—			(3		)	—			—			(3		)
Total Outside Sales	134		380		135			10			659		15			(86		)	(20		)	(2		)	(93		)
Gas Royalty Interest	—		—		—			50			50		—			—			—			(17		)	(17		)
Purchased Gas	—		—		—			3			3		—			—			—			(1		)	(1		)
Other Income	—		—		—			57			57		—			—			—			(2		)	(2		)
Total Revenue and Other Income	134		380		135			120			769		15			(86		)	(20		)	(22		)	(113		)
Lifting	12		37		40			2			91		(3		)	(3		)	(9		)	1			(14		)
Ad Valorem, Severance, and Other Taxes	4		10		10			2			26		3			(2		)	(2		)	1			—
Gathering	24		106		26			5			161		9			8			(1		)	3			19
Gas Direct Administrative, Selling & Other	17		14		13			3			47		6			(15		)	(8		)	3			(14		)
Depreciation, Depletion and Amortization	47		87		59			9			202		12			(14		)	(2		)	(1		)	(5		)
General & Administration	—		—		—			40			40		—			—			—			(11		)	(11		)
Gas Royalty Interest	—		—		—			39			39		—			—			—			(20		)	(20		)
Purchased Gas	—		—		—			3			3		—			—			—			(1		)	(1		)
Exploration and Other Costs	—		—		—			39			39		—			—			—			21			21
Other Corporate Expenses	—		—		—			77			77		—			—			—			12			12
Interest Expense	—		—		—			5			5		—			—			—			(5		)	(5		)
Total Cost	104		254		148			224			730		27			(26		)	(22		)	3			(18		)
Earnings Before Noncontrolling Interest and Income Tax	30		126		(13		)	(104		)	39		(12		)	(60		)	2			(25		)	(95		)
Noncontrolling Interest	—		—		—			—			—		—			—			—			(4		)	(4		)
Earnings (Loss) Before Income Tax	$	30	$	126	$	(13	)	$	(104	)	$	39	$	(12	)	$	(60	)	$	2		$	(21	)	$	(91	)

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $30 million to the total Company earnings before income tax for the year ended December 31, 2012 compared to $42 million for the year ended December 31, 2011.



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	35.9		26.9		9.0			33.5	%
NGLs Sales Volumes (Bcfe)*	0.6		—		0.6			100.0	%
Total Marcellus Gas Sales Volumes (Bcfe)*	36.5		26.9		9.6			35.7	%

Average Sales Price - Gas (Mcf)	$	2.89	$	4.22	$	(1.33	)	(31.5	)%
Hedging Impact - Gas (Mcf)	$	0.69	$	0.21	$	0.48		228.6	%
Average Sales Price - NGLs (Mcfe)*	$	8.68	$	—	$	8.68		100.0	%
Average Sales Price - Condensate (Mcfe)*	$	13.54	$	—	$	13.54		100.0	%

Total Average Marcellus sales (per Mcfe)	$	3.68	$	4.43	$	(0.75	)	(16.9	)%
Average Marcellus lifting costs (per Mcfe)	$	0.34	$	0.56	$	(0.22	)	(39.3	)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	$	0.12	$	0.05	$	0.07		140.0	%
Average Marcellus gathering costs (per Mcfe)	$	0.67	$	0.54	$	0.13		24.1	%
Average Marcellus direct administrative, selling & costs (per Mcfe)	$	0.46	$	0.41	$	0.05		12.2	%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	$	1.30	$	1.33	$	(0.03	)	(2.3	)%
Total Average Marcellus costs (per Mcfe)	$	2.89	$	2.89	$	—		—	%
Average Margin for Marcellus (per Mcfe)	$	0.79	$	1.54	$	(0.75	)	(48.7	)%

The Marcellus segment sales revenues were $134 million for the year ended December 31, 2012 compared to $119 million for the year ended December 31, 2011. The $15 million increase was primarily due to a 35.7% increase in total sales volumes, offset, in part, by a 16.9% decrease in total average sales price per Mcfe. The decrease in Marcellus average sales price was the result of the decline in general market prices; offset in part, by various gas swap transactions that matured in the year ended December 31, 2012. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These hedges represented approximately 12.4 Bcf of our produced Marcellus gas sales volumes for the year ended December 31, 2012 at an average price of $4.99 per Mcf. For the year ended December 31, 2011, these financial hedges represented 10.6 Bcf at an average price of $4.64 per Mcf. Marcellus sales volumes increased 9.6 Bcf due to our on-going drilling program.

Total costs for the Marcellus Segment were $104 million for the year ended December 31, 2012 compared to $77 million for the year ended December 31, 2011. The average costs in the period-to-period comparison are discussed below.

•Marcellus lifting costs were $12 million for the year ended December 31, 2012 compared to $15 million for the year ended December 31, 2011. Lifting costs decreased primarily due to lower well servicing costs, well tending costs and additional sales volumes during the 2012 year-to-date period. These improvements, along with additional sales volumes resulted in a $0.22 improvement in average unit costs.

•Marcellus ad valorem, severance, and other taxes were $4 million for the year ended December 31, 2012 compared to $1 million for the year ended December 31, 2011. The increase of $0.07 per Mcfe sold is primarily due to new legislation passed in the state of Pennsylvania (Act 13 of 2012, House Bill 1950). This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within Pennsylvania. The impact on unit costs of this increase was offset, in part, by higher volumes sold.

•Marcellus gathering costs were $24 million for the year ended December 31, 2012 compared to $15 million for the year ended December 31, 2011. Average gathering costs increased $0.13 per Mcfe primarily due to increased firm

transportation usage and the formation of CONE Gathering LLC (CONE), a 50% owned affiliate. CONE began charging CONSOL Energy a fixed gathering rate of $0.46 per MMbtu on Marcellus production volumes during the 4th quarter of 2011.

•Marcellus direct administrative, selling & other costs were $17 million for the year ended December 31, 2012 compared to $11 million for the year ended December 31, 2011. Direct administrative, selling & other costs attributable to the total gas division are allocated to the individual gas segments based on a combination of production and employee counts. The $6 million increase in period-to-period comparison is due to increased direct administrative labor and Marcellus volumes representing a larger portion of total natural gas volumes.

•Depreciation, depletion and amortization costs were $47 million for the year ended December 31, 2012 compared to $35 million for the year ended December 31, 2011. 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 in the year ended December 31, 2012. There was approximately $27 million, or $1.04 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, 2011. The rate was calculated by taking the net book value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. Additionally, there was approximately $3 million, or $0.06 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, 2012. There was $8 million, or $0.29 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, 2011. The decrease in Marcellus gathering and other equipment depreciation, depletion and amortization related to the sale if assets to CONE Gathering LLC (CONE), a 50% owned affiliate.

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $126 million to the total Company earnings before income tax for the year ended December 31, 2012 compared to $186 million for the year ended December 31, 2011.



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	88.2		92.4		(4.2		)	(4.5	)%

Average Sales Price - Gas (Mcf)	$	2.88	$	4.13	$	(1.25	)	(30.3	)%
Hedging Impact - Gas (Mcf)	$	1.44	$	0.92	$	0.52		56.5	%

Total Average CBM sales price (per Mcf)	$	4.32	$	5.05	$	(0.73	)	(14.5	)%
Average CBM lifting costs (per Mcf)	$	0.42	$	0.43	$	(0.01	)	(2.3	)%
Average CBM ad valorem, severance, and other taxes (per Mcf)	$	0.12	$	0.13	$	(0.01	)	(7.7	)%
Average CBM gathering costs (per Mcf)	$	1.21	$	1.06	$	0.15		14.2	%
Average CBM direct administrative, selling & other costs (per Mcf)	$	0.16	$	0.31	$	(0.15	)	(48.4	)%
Average CBM depreciation, depletion and amortization costs (per Mcf)	$	0.98	$	1.10	$	(0.12	)	(10.9	)%
Total Average CBM costs (per Mcf)	$	2.89	$	3.03	$	(0.14	)	(4.6	)%
Average Margin for CBM (per Mcf)	$	1.43	$	2.02	$	(0.59	)	(29.2	)%

CBM sales revenues were $380 million for the year ended December 31, 2012 compared to $466 million for the year ended December 31, 2011. The $86 million decrease was primarily due to a 14.5% decrease in average sales price per Mcf sold, offset, in part, by a 4.5% increase in average volumes sold. The decrease in CBM average sales price is the result of various gas swap transactions that matured in each period and lower average market prices. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 45.8 Bcf of our produced CBM gas sales volumes for the year ended December 31, 2012 at an average price of $5.34 per Mcf. For the year ended December 31, 2011, these financial hedges represented 61.8 Bcf at an average price of $5.36 per Mcf. CBM sales volumes decreased 4.2 Bcf primarily due to normal well declines without a corresponding increase in

wells drilled and the impact on gas production from the idling of the Buchanan Mine during the 2012 period. The focus of the gas division is to develop its Marcellus and Utica acreage.

Total costs for the CBM segment were $254 million for the year ended December 31, 2012 compared to $280 million for the year ended December 31, 2011. Lower costs in the period-to-period comparison are are discussed below.

•CBM lifting costs were $37 million for the year ended December 31, 2012 compared to $40 million for the year ended December 31, 2011. The $3 million decrease is primarily due to idle rig costs incurred during the 2011 period, reduced road maintenance costs, offset, in part, by increased slip repairs.

•CBM ad valorem, severance, and other taxes were $10 million for the year ended December 31, 2012 compared to $12 million for the year ended December 31, 2011. The decrease in total dollars was primarily due to reduced severance tax expense caused by lower average gas sales price during 2012. These changes resulted in a $0.01 reduction to average units costs.

•CBM gathering costs were $106 million for the year ended December 31, 2012 compared to $98 million for the year ended December 31, 2011. Higher CBM gathering units costs are related to increased compressor maintenance, additional equipment lease rentals and lower volumes sold in the period-to-period comparison.

•CBM direct administrative, selling & other costs were $14 million for year ended December 31, 2012 compared to $29 million for the year ended December 31, 2011. Direct administrative, selling & other costs attributable to the total gas segment are allocated to the individual gas 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 portion of total natural gas volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $87 million for the year ended December 31, 2012 compared to $101 million for the year ended December 31, 2011. There was approximately $60 million, or $0.67 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, 2012. The production portion of depreciation, depletion and amortization was $72 million, or $0.78 per unit-of-production in the year ended December 31, 2011. The CBM unit-of-production rate decreased due to revised rates which are generally calculated using the net book value of assets divided by either proved or proved developed reserve additions. There was approximately $28 million, or $0.31 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. The non-production related depreciation, depletion and amortization was $29 million, or $0.32 per Mcf for the year ended December 31, 2011.

SHALLOW OIL AND GAS SEGMENT

The Shallow Oil and Gas segment had a loss before income tax of $13 million for the year ended December 31, 2012 compared to a loss before income tax of $15 million for the year ended December 31, 2011.



	For the Years Ended December 31,
	2012			2011			Variance			Percent Change
Shallow Oil and Gas Sales Volumes (Bcf)	28.7			31.7			(3.0		)	(9.5	)%
Oil Sales Volumes (Bcfe)*	0.5			0.5			—			—	%
Total Shallow Oil and Gas Sales Volumes (Bcfe)*	29.2			32.2			(3.0		)	(9.3	)%

Average Sales Price - Gas (Mcf)	$	3.12		$	4.52		$	(1.40	)	(31.0	)%
Hedging Impact - Gas (Mcf)	$	1.33		$	0.16		$	1.17		731.3	%
Average Sales Price - Oil (Mcfe)*	$	15.65		$	15.71		$	(0.06	)	(0.4	)%

Total Average Shallow Oil and Gas sales price (per Mcfe)	$	4.64		$	4.83		$	(0.19	)	(3.9	)%
Average Shallow Oil and Gas lifting costs (per Mcfe)	$	1.37		$	1.52		$	(0.15	)	(9.9	)%
Average Shallow Oil and Gas ad valorem, Severance, and other taxes (per Mcfe)	$	0.35		$	0.37		$	(0.02	)	(5.4	)%
Average Shallow Oil and Gas gathering costs (per Mcfe)	$	0.92		$	0.83		$	0.09		10.8	%
Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)	$	0.45		$	0.67		$	(0.22	)	(32.8	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs (per Mcfe)	$	2.02		$	1.90		$	0.12		6.3	%
Total Average Shallow Oil and Gas costs (per Mcfe)	$	5.11		$	5.29		$	(0.18	)	(3.4	)%
Average Margin for Shallow Oil and Gas (per Mcfe)	$	(0.47	)	$	(0.46	)	$	(0.01	)	2.2	%

Shallow Oil and Gas sales revenues were $135 million for the year ended December 31, 2012 compared to $155 million for the year ended December 31, 2011. The $20 million decrease was primarily due to the 9.3% decrease in volumes sold as well as the 3.9% decrease in average sales price. The decrease in shallow oil and gas average sales price is the result of lower average market prices, offset, in part by various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 18.5 Bcf of our produced Shallow Oil and Gas gas sales volumes for the year ended December 31, 2012 at an average price of $5.23 per Mcf. For the year ended December 31, 2011, these financials hedges represented 11.5 Bcf at an average price of $4.97 per Mcf. Shallow oil and gas sales volumes decreased 3.0 Bcf primarily due to normal well declines without corresponding increase in wells drilled.

The total costs for the shallow oil and gas segment were $148 million for the year ended December 31, 2012 compared to $170 million for the year ended December 31, 2011. Lower costs in the period-to-period comparison are discussed below.

•Shallow Oil and Gas lifting costs were $40 million for the year ended December 31, 2012 compared to $49 million for the year ended December 31, 2011. Lifting costs per unit decreased $0.15 per Mcfe sold primarily due to lower road maintenance, decreased well tending expenses and decreased swabbing and fishing expenses in the period-to-period comparison.

•Shallow oil and gas ad valorem, severance, and other taxes were $10 million for the year ended December 31, 2012 compared to $12 million for the year ended December 31, 2011. The decrease to total costs and average unit costs was primarily due to reduced severance tax expense caused by lower average gas sales prices during 2012.

•Shallow Oil and Gas gathering costs were $26 million for the year ended December 31, 2012 compared to $27 million for the year ended December 31, 2011. Gathering costs decreased primarily due to lower compressor maintenance and lower

equipment lease expense in the period-to-period comparison. The impact of these reductions on unit costs was offset by lower sales volumes.

•Shallow Oil and Gas direct administrative, selling and other costs were $13 million for the year ended December 31, 2012 compared to $21 million for the year ended December 31, 2011. Direct administrative, selling and other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The $8 million decrease in the period-to-period comparison is due to reduced direct administrative labor and Shallow Oil and Gas volumes representing a smaller proportion of total natural gas volumes.

•Depreciation, depletion and amortization costs were $59 million for the year ended December 31, 2012 compared to $61 million for the year ended December 31, 2011. There was approximately $51 million, or $1.75 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2012. There was approximately $54 million, or $1.67 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the year ended December 31, 2011. The rate was calculated by taking the net book value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. There was approximately $8 million, or $0.27 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, 2012. There was $7 million, or $0.23 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, 2011. The increase was related to additional infrastructure and equipment placed in service after the 2012 period.

OTHER GAS SEGMENT

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $10 million for the year ended December 31, 2012 and $12 million for the year ended December 31, 2011. Total costs related to these other sales were $21 million for the 2012 period and were $14 million for the 2011 period. The increase in costs in the period-to-period comparison were primarily attributable to increased gathering and direct administrative, selling & other costs relating to the Utica operating area during 2012. A per unit analysis of the other operating costs in the Chattanooga shale is not meaningful due to the low volumes produced in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas division. Royalty interest gas sales revenue was $50 million for the year ended December 31, 2012 compared to $67 million for the year ended December 31, 2011. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Gas Royalty Interest Sales Volumes (Bcf)	18.0		16.4		1.6			9.8	%
Average Sales Price (per Mcf)	$	2.74	$	4.07	$	(1.33	)	(32.7	)%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $3 million for the year ended December 31, 2012 compared to $4 million for the year ended December 31, 2011.



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Purchased Gas Sales Volumes (Bcf)	1.1		1.0		0.1			10.0	%
Average Sales Price (per Mcf)	$	3.03	$	4.28	$	(1.25	)	(29.2	)%

Other income was $57 million for the year ended December 31, 2012 compared to $59 million for the year ended December 31, 2011. The $2 million decrease was primarily due to the following items.


•	Gain on sale of assets decreased $30 million due to gains on the Hess transaction and Antero overriding royalty interest of $53 million and $41 million respectively, both of which occurred in 2011. Additionally, CONSOL Energy incurred a $64 million loss on the Noble transaction during 2011.


•	Interest income increased $20 million due to the notes receivable which were part of the Noble joint venture transaction.


•	Revenue from equity affiliates increased $5 million due to the formation of CONE, a 50% owned affiliate. CONE was formed in relation to the Noble joint venture transaction.


•	The remaining $3 million increase relates to various transactions that occurred throughout both periods, none of which were individually material.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. Royalty interest gas costs were $39 million for the year ended December 31, 2012 compared to $59 million for the year ended December 31, 2011. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Gas Royalty Interest Sales Volumes (Bcf)	18.0		16.4		1.6			9.8	%
Average Sales Price (per Mcf)	$	2.16	$	3.61	$	(1.45	)	(40.2	)%

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 lower average cost per Mcf is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $3 million for the year ended December 31, 2012 compared to $4 million for the year ended December 31, 2011.



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Purchased Gas Volumes (Bcf)	1.1		1.2		(0.1		)	(8.3	)%
Average Sales Price (per Mcf)	$	2.44	$	3.07	$	(0.63	)	(20.5	)%

Exploration and other costs were $39 million for the year ended December 31, 2012 compared to $18 million for the year ended December 31, 2011. The $21 million increase in costs is primarily related to the following items:



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Lease Expiration Costs	$	18	$	6	$	12		200.0	%
Marcellus Title Defects	4		—		$	4		100.0	%
Exploration Costs	14		7		7			100.0	%
Dry Hole Costs	3		5		(2		)	(40.0	)%
Total Exploration and Other Costs	$	39	$	18	$	21		116.7	%


•	Lease expiration costs increased $12 million primarily due to lease expirations where CONSOL Energy allowed primary lease terms to expire.


•	CONSOL Energy reviewed title defect notices, asserted by Noble, and working in collaboration with Noble, conceded title defects on acreage which had a carrying value to CONSOL Energy of $4 million for the year ended December 31, 2012.


•	Exploration expense increased $7 million due to higher exploratory expenses associated with the Utica operating area and various other transactions that occurred throughout both periods, none of which were individually material.


•	Dry Hole Costs decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

Other corporate expenses were $77 million for the year ended December 31, 2012 compared to $65 million for the year ended December 31, 2011. The $12 million increase in the period-to-period comparison was made up of the following items:



	For the Years Ended December 31,
	2012		2011		Variance		Percent Change
Legal Fees	$	5	$	—	$	5	100.0	%
PA Impact Fees	4		—		4		100.0	%
Unused FT Commitments	16		14		2		14.3	%
Short-term incentive compensation	26		25		1		4.0	%
Stock-based compensation	18		18		—		—	%
Bank fees	7		7		—		—	%
Other	1		1		—		—	%
Total Other Corporate Expenses	$	77	$	65	$	12	18.5	%


•	Legal fees were related to CNX Gas royalty litigation and title defect work, as previously discussed.

•

PA impact fees are related to legislation in the state of Pennsylvania (Act 13 of 2012, House Bill 1950) which was signed into law during the first quarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. As part of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to 2012. The $4 million represents the one-time initial assessment on wells drilled prior to January 1, 2012. Ongoing PA impact fees, which relate to current year wells drilled, are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.


•	Unutilized firm transportation represents pipeline transportation capacity that the gas segment has obtained to enable gas production to flow uninterrupted as the gas operations continue to increase sales volumes.

•

The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2012 period and an increased allocation of expense from CONSOL Energy as a result of exceeding corporate targets.


•	Stock-based compensation remained consistent in the period-to-period comparison. Stock-based compensation costs are allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.


•	Bank fees remained consistent in the period-to-period comparison.


•	Other corporate related expense remained consistent in the period-to-period comparison.

Interest expense related to the other gas segment was $5 million for the year ended December 31, 2012 compared to $10 million for the year ended December 31, 2011. Interest was incurred by the other gas segment on the CNX Gas revolving credit facility, a capital lease and debt held by a variable interest entity. The $5 million decrease was primarily due to lower levels of borrowings on the revolving credit facility in the period-to-period comparison.

Noncontrolling interest represents 100% of earnings impact of a third party in which CONSOL Energy held no ownership interest. The variance in the noncontrolling amounts reflects the third parties variance in earnings in the period-to-period comparison. In the year ended December 31, 2011, the drilling services contract was bought out. Subsequent to this transaction, the noncontrolling interest was de-consolidated.

TOTAL COAL SEGMENT ANALYSIS for the year ended December 31, 2012 compared to the year ended December 31, 2011:

The coal segment contributed $592 million of earnings before income tax in the year ended December 31, 2012 compared to $1,033 million in the year ended December 31, 2011.



	For the Year Ended														Difference to Year Ended
	December 31, 2012														December 31, 2011
	Thermal Coal			High Vol Met Coal		Low Vol Met Coal			Other Coal			Total Coal			Thermal Coal			High Vol Met Coal			Low Vol Met Coal			Other Coal			Total Coal
Sales:
Produced Coal	$	1,431		$	210	$	506		$	5		$	2,152		$	(65	)	$	(114	)	$	(566	)	$	(22	)	$	(767	)
Purchased Coal	—			—		—			17			17			—			—			—			(23		)	(23		)
Total Outside Sales	1,431			210		506			22			2,169			(65		)	(114		)	(566		)	(45		)	(790		)
Freight Revenue	—			—		—			107			107			—			—			—			(69		)	(69		)
Other Income	2			6		—			324			332			(4		)	(5		)	—			269			260
Total Revenue and Other Income	1,433			216		506			453			2,608			(69		)	(119		)	(566		)	155			(599		)
Costs and Expenses:
Beginning inventory costs	67			2		16			—			85			(17		)	2			6			—			(9		)
Total direct costs	593			95		184			145			1,017			37			(14		)	(14		)	16			25
Total royalty/production taxes	74			9		30			3			116			(10		)	(3		)	(37		)	(5		)	(55		)
Total direct services to operations	154			21		22			217			414			(71		)	(21		)	(24		)	57			(59		)
Total retirement and disability	61			10		28			20			119			(11		)	(6		)	(10		)	6			(21		)
Depreciation, depletion and amortization	120			22		37			33			212			(7		)	(5		)	—			12			—
Ending inventory costs	(33		)	—		(21		)	—			(54		)	35			—			(5		)	—			30
Total Costs and Expenses	1,036			159		296			418			1,909			(44		)	(47		)	(84		)	86			(89		)
Freight Expense	—			—		—			107			107			—			—			—			(69		)	(69		)
Total Costs	1,036			159		296			525			2,016			(44		)	(47		)	(84		)	17			(158		)
Earnings (Loss) Before Income Taxes	$	397		$	57	$	210		$	(72	)	$	592		$	(25	)	$	(72	)	$	(482	)	$	138		$	(441	)

THERMAL COAL SEGMENT

The thermal coal segment contributed $397 million to total Company earnings before income tax for the year ended December 31, 2012 compared to $422 million for the year ended December 31, 2011. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Years Ended December 31,
	2012			2011			Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	20.7			22.4			(1.7		)	(7.6	%)
Average Sales Price Per Thermal Ton Sold	$	69.08		$	66.84		$	2.24		3.4	%

Beginning Inventory Costs Per Thermal Ton	$	61.92		$	53.42		$	8.50		15.9	%

Total Direct Operating Costs Per Thermal Ton Produced	$	29.29		$	25.35		$	3.94		15.5	%
Total Royalty/Production Taxes Per Thermal Ton Produced	3.65			3.82			(0.17		)	(4.5	%)
Total Direct Services to Operations Per Thermal Ton Produced	7.61			10.25			(2.64		)	(25.8	%)
Total Retirement and Disability Per Thermal Ton Produced	3.01			3.28			(0.27		)	(8.2	%)
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	5.93			5.76			0.17			3.0	%
Total Production Costs Per Thermal Ton Produced	$	49.49		$	48.46		$	1.03		2.1	%

Ending Inventory Costs Per Thermal Ton	$	(50.89	)	$	(61.92	)	$	11.03		17.8	%

Total Costs Per Thermal Ton Sold	$	50.00		$	48.25		$	1.75		3.6	%
Average Margin Per Thermal Ton Sold	$	19.08		$	18.59		$	0.49		2.6	%

Thermal coal revenue was $1,431 million for the year ended December 31, 2012 compared to $1,496 million for the year ended December 31, 2011. The $65 million decrease was attributable to 1.7 million fewer tons sold in 2012 partially offset by a $2.24 per ton higher average sales price. The higher average thermal coal sales price in the 2012 period was the result of the successful renegotiations of several domestic thermal contracts during the period. The thermal coal segment was also impacted by 2.1 million tons of thermal coal sold on the high volatile metallurgical coal market for the year ended December 31, 2012, which was 0.7 million tons more than the tons sold in the year ended December 31, 2011.

Total costs of goods sold are comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for thermal coal was $1,036 million for the year ended December 31, 2012, or $44 million lower than the $1,080 million for the year ended December 31, 2011. Although total cost of goods sold dollars were improved, total costs per ton sold on a unit basis were impaired. Total cost of goods sold for thermal coal was $50.00 per ton in the year ended December 31, 2012 compared to $48.25 per ton in the year ended December 31, 2011. The increase in costs of goods sold per thermal ton was due to the items described below.

Direct operating costs related to the thermal coal segment were $593 million for the year ended December 31, 2012 compared to $556 million for the year ended December 31, 2011. Direct operating costs were $29.29 per ton produced in the current year compared to $25.35 per ton produced in the prior year. Changes in the average direct operating costs per thermal ton produced were primarily related to the following items:


•	Average operating costs per thermal ton produced increased due to fewer tons produced. Thermal mines produced 20.3 million tons in 2012 compared to 21.9 million tons in 2011. Fixed costs are allocated over less tons, resulting in higher unit costs.


•	Average operating supplies and maintenance costs per ton increased due to additional maintenance and equipment overhaul costs and additional contractor labor, combined with lower tons produced. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current year. Additional contractor

labor costs resulted from additional underground hourly contractors utilized as well as additional security contractor costs in the current year.


•	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.


•	There were no significant changes in various other unit costs individually or in total.

Royalties and production taxes decreased $10 million to $74 million in the current year. Average cost per thermal ton produced decreased $0.17 per ton due to a change in the mix of coal produced both geographically and in ownership, which changed the production tax and royalty rates, respectively.

Direct service costs were $154 million in the current year compared to $225 million in the prior year. Direct services to the operations were $7.61 per ton in the current year compared to $10.25 per ton in the prior year. Changes in the average direct service to operations cost per thermal ton produced were primarily related to the following items:


•	Average direct service costs to operations were impaired due to lower tons produced in the year-to-year comparison.


•	Permitting and compliance costs have increased due to increased stream monitoring expenses, increased compliance work related to ponds and ditches, and additional permits for water discharge pipelines.


•	Selling expense decreased in the year-to-year comparison due to fewer tons being sold under contracts that require commissions.

Retirement and disability costs attributable to the thermal coal segment were $61 million for the year ended December 31, 2012 compared to $72 million for the year ended December 31, 2011. The decrease in the thermal coal retirement and disability costs was primarily attributable to a change in discount rates used to calculate the cost of the long-term liabilities and a modification of the salaried other post-retirement benefit plan. These improvements were offset, in part, by the reduction in production volumes which negatively impacted unit costs.

Depreciation, depletion and amortization for the thermal coal segment was $120 million for the year ended December 31, 2012 compared to $127 million for the year ended December 31, 2011. The decrease was primarily due to lower depletion directly related to lower production volumes. Unit costs per thermal ton produced were higher for the year ended December 31, 2012 compared to the year ended December 31, 2011 due to additional equipment and infrastructure placed into service after the 2011 year that is depreciated on a straight-line basis.

Changes in thermal coal inventory volumes and carrying value, resulted in $34 million of costs of goods sold for the year ended December 31, 2012 compared to $16 million for the year ended December 31, 2011. Thermal coal inventory was 0.6 million tons at December 31, 2012 compared to 1.1 million tons at December 31, 2011.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $57 million to total Company earnings before income tax for the year ended December 31, 2012 compared to $129 million for the year ended December 31, 2011. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Years Ended December 31,
	2012		2011		Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	3.3		4.1		(0.8		)	(19.5	%)
Average Sales Price Per High Vol Met Ton Sold	$	63.93	$	78.57	$	(14.64	)	(18.6	%)

Beginning Inventory Costs Per High Vol Met Ton	$	—	$	—	$	—		—	%

Total Direct Operating Costs Per High Vol Met Ton Produced	$	28.98	$	26.41	$	2.57		9.7	%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	2.72		2.86		(0.14		)	(4.9	%)
Total Direct Services to Operations Per High Vol Met Ton Produced	6.22		10.23		(4.01		)	(39.2	%)
Total Retirement and Disability Per High Vol Met Ton Produced	3.10		3.87		(0.77		)	(19.9	%)
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	6.63		6.55		0.08			1.2	%
Total Production Costs Per High Vol Met Ton Produced	$	47.65	$	49.92	$	(2.27	)	(4.5	%)

Ending Inventory Costs Per High Vol Met Ton	$	—	$	—	$	—		—	%

Total Costs Per High Vol Met Ton Sold	$	48.43	$	49.89	$	(1.46	)	(2.9	%)
Margin Per High Vol Met Ton Sold	$	15.50	$	28.68	$	(13.18	)	(46.0	%)

High volatile metallurgical coal revenue was $210 million for the year ended December 31, 2012 compared to $324 million for the year ended December 31, 2011. Average sales prices for high volatile metallurgical coal decreased $14.64 per ton in the year-to-year comparison due to a weakening in global metallurgical coal demand. CONSOL Energy priced 2.7 million tons of high volatile metallurgical coal in the export market at an average sales price of $60.75 per ton for the year ended December 31, 2012 compared to 3.8 million tons at an average price of $78.05 per ton for the year ended December 31, 2011. The remaining tons sold in the year-to-year comparison were sold in the domestic market.

Other income attributed to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate high volatile metallurgical coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.

Total cost of goods sold are comprised of changes in high volatile metallurgical coal inventory and costs of tons produced in the period. Total cost of goods sold for high volatile metallurgical coal was $159 million for the year ended December 31, 2012 or $47 million lower than the $206 million for the year ended December 31, 2011. Total cost of goods sold for high volatile metallurgical coal were $48.43 per ton in the year ended December 31, 2012 compared to $49.89 per ton in the year ended December 31, 2011. The decrease in cost of goods sold per high volatile metallurgical ton was due to the items described below.

Direct operating costs related to the high volatile metallurgical coal segment were $95 million in the year ended December 31, 2012 compared to $109 million in the year ended December 31, 2011. Direct operating costs dollars are improved due to lower tons produced in the year-to-year comparison and due to cost control measures that were implemented. Direct operating costs were $28.98 per ton produced in the current year compared to $26.41 per ton produced in the prior year-to-date period. Changes in the average direct operating costs per high volatile metallurgical ton produced were primarily related to the following items:


•	Labor and related benefits average costs per high volatile metallurgical ton produced decreased due to less overtime worked, offset, in part, by lower tons produced and higher hourly wage rates.


•	Mine maintenance and supplies per ton produced decreased due to the mix of mines producing tons that were shipped as high volatile metallurgical coal. Mines with lower cost structures produced a larger portion of the high volatile metallurgical coal shipped in the current year compared to the prior year.


•	Various other unit costs including power and miscellaneous costs did not change significantly individually or in total.


•	Improvements were offset, in part, by the reduction in production volumes which negatively impacted unit costs.

Royalties and production taxes were $9 million in the current year compared to $12 million in the prior year. The $3 million improvement was due to lower volumes and lower average sales prices. High volatile metallurgical coal royalties and production taxes were $2.72 per ton in the current year compared to $2.86 per ton in the prior year. Average cost per high volatile metallurgical ton produced decreased due to a change in the mix of coal produced both geographically and in ownership, which changed the production tax and royalty rates, respectively.

Direct service costs for high volatile metallurgical coal were $21 million in the current year compared to $42 million in the prior year. Lower costs were attributable to fewer tons subject to commission expense, lower direct administrative costs, and lower subsidence costs. Direct services to the operations for high volatile metallurgical coal were $6.22 per ton in the current year compared to $10.23 per ton in the prior year. Changes in the average direct service to operations cost per ton for high volatile metallurgical coal produced were primarily related to a reduction of commission rates due to a decrease in the average sales price.

Retirement and disability costs attributable to the high volatile metallurgical coal segment were $10 million for the year ended December 31, 2012 compared to $16 million for the year ended December 31, 2011. The decrease in the high volatile metallurgical coal retirement and disability costs was primarily attributable to a change in discount rates used to calculate the cost of the long-term liabilities and a modification of the salaried other post-retirement benefit plan. These improvements were offset, in part, by the reduction in production volumes which negatively impacted unit costs.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $22 million for the year ended December 31, 2012 compared to $27 million for the year ended December 31, 2011. The decrease was primarily due to lower depletion directly related to lower production volumes. Unit costs per high volatile ton produced were higher in the year ended December 31, 2012 compared to the year ended December 31, 2011 due to additional equipment and infrastructure placed into service after the 2011 year that was depreciated on a straight-line basis.

There were no changes in volumes or carrying value of coal inventory in the year ended December 31, 2012 and December 31, 2011. There was no high volatile metallurgical coal inventory at December 31, 2012 or December 31, 2011.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $210 million to total Company earnings before income tax in the year ended December 31, 2012 compared to $692 million in the year ended December 31, 2011. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Years Ended December 31,
	2012			2011			Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	3.6			5.6			(2.0		)	(35.7	%)
Average Sales Price Per Low Vol Met Ton Sold	$	140.11		$	191.81		$	(51.70	)	(27.0	%)

Beginning Inventory Costs Per Low Vol Met Ton	$	67.60		$	62.51		$	5.09		8.1	%

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	50.88		$	34.90		$	15.98		45.8	%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	8.33			11.74			(3.41		)	(29.0	%)
Total Direct Services to Operations Per Low Vol Met Ton Produced	6.03			8.15			(2.12		)	(26.0	%)
Total Retirement and Disability Per Low Vol Met Ton Produced	7.63			6.71			0.92			13.7	%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	10.23			6.54			3.69			56.4	%
Total Production Costs Per Low Vol Met Ton Produced	$	83.10		$	68.04		$	15.06		22.1	%

Ending Inventory Costs Per Low Vol Met Ton	$	(86.38	)	$	(67.60	)	$	(18.78	)	(27.8	%)

Total Costs Per Low Vol Met Ton Sold	$	81.89		$	67.90		$	13.99		20.6	%
Margin Per Low Vol Met Ton Sold	$	58.22		$	123.91		$	(65.69	)	(53.0	%)

Low volatile metallurgical coal revenue was $506 million for the year ended December 31, 2012 compared to $1,072 million for the year ended December 31, 2011. The $566 million decrease was attributable to a $51.70 per ton lower average sales price and nearly two million less tons sold. Average sales prices for low volatile metallurgical coal decreased in the year-to-year comparison due to the weakening in global metallurgical coal demand. For the year ended December 31, 2012, 2.6 million tons of low volatile metallurgical coal was priced on the export market at an average price of $125.73 per ton compared to 4.6 million tons at an average price of $196.46 per ton for the 2011 year. The remaining tons sold in the year-to-year comparison were sold on the domestic market.

Total cost of goods sold are comprised of changes in low volatile metallurgical coal inventory and costs of tons produced in the period. Total cost of goods sold for low volatile metallurgical coal was $296 million for the year ended December 31, 2012, or $84 million lower than the $380 million for the year ended December 31, 2011. Total cost of goods sold for low volatile metallurgical coal was $81.89 per ton for the year ended December 31, 2012 compared to $67.90 per ton for the year ended December 31, 2011. The increase in cost of goods sold per low volatile metallurgical ton was due to the items described below.

Direct operating costs related to the low volatile metallurgical coal segment were $184 million for the year ended December 31, 2012 compared to $198 million for the year ended December 31, 2011. Direct operating costs dollars are improved $14 million due to lower tons produced in the year-to-year comparison and cost control measures implemented, however, the cost improvements did not offset the impact of reduced production on unit costs. Direct operating costs were $50.88 per ton produced in the current year compared to $34.90 per ton produced in the prior year. Changes in the average direct operating costs per low volatile ton produced were primarily related to the following items:


•	The Buchanan longwall was idled during the months of March, April and October of 2012 which resulted in higher direct operating costs produced. The mine continued to run the continuous miners and perform mine maintenance during the months when the longwall was idled. This negatively impacted unit costs.

•

Low volatile metallurgical coal production was 3.7 million tons for the year ended December 31, 2012 compared to 5.7 million tons for the year ended December 31, 2011. Production was significantly lower in the year-to-year comparison due to the Buchanan Mine being idled for portions of 2012. The mine was idled in response to weak market demand for low volatile metallurgical coal. Late in 2012, a five day work week instead of the normal seven

day work week was implemented. Fixed costs were then spread over fewer tons produced which increased all costs on a per unit basis.

Royalties and production taxes improved $37 million to $30 million in the current year-to-date period compared to $67 million in the prior year-to-date period. Unit costs also improved $3.41 per low volatile metallurgical ton produced to $8.33 per ton in the current year-to-date period compared to $11.74 per ton in the prior year-to-date period. Average cost per low volatile metallurgical ton produced decreased due to lower royalties and lower production taxes. These decreases were related to lower volumes produced and lower average sales prices.

Direct service costs for low volatile metallurgical coal were $22 million in the current year compared to $46 million in the prior year. Direct services to the operations for low volatile metallurgical coal were $6.03 per ton in the current year compared to $8.15 per ton in the prior year. Changes in the average direct service to operations cost per ton for low volatile metallurgical coal produced were primarily related to lower tons of coal produced in the period-to-period comparison.

Retirement and disability costs attributable to the low volatile metallurgical coal segment were $28 million for the year ended December 31, 2012 compared to $38 million for the year ended December 31, 2011. The decrease in the low volatile metallurgical coal retirement and disability costs was primarily attributable to a decrease in discount rates used to calculate the cost of the long-term liabilities and a modification of the salaried other post-retirement benefit plan. This improvement was offset, in part, by the reduction in production volumes which negatively impacted unit costs.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $37 million for both the years ended December 31, 2012 and 2011. Unit costs per low volatile metallurgical ton produced were higher in the year ended December 31, 2012 compared to the year ended December 31, 2011 due to lower volumes produced.

Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in $5 million of cost of goods sold in the year ended December 31, 2012 compared to $6 million of cost of goods sold in the year ended December 31, 2011. Produced low volatile metallurgical coal inventory was 0.2 million tons at December 31, 2012 and December 31, 2011.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $72 million for the year ended December 31, 2012 compared to a loss before income tax of $210 million for the year ended December 31, 2011. The other coal segment includes purchased coal activities, idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

The other coal segment produced coal sales includes revenue from the sale of 0.1 million tons of coal which was recovered during the reclamation process at idled facilities for the year ended December 31, 2012 compared to 0.4 million tons for the year ended December 31, 2011. The primary focus of the activity at these locations is reclaiming disturbed land in accordance with the mining permit requirements after final mining has occurred. The tons sold are incidental to total Company production or sales.

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 $17 million for the year ended December 31, 2012 compared to $40 million for the year ended December 31, 2011. The decrease was primarily due to increased volumes sold partially offset by a decrease in the average sales price.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is almost completely offset in freight expense. Freight revenue was $107 million for the year ended December 31, 2012 compared to $176 million for the year ended December 31, 2011. The $69 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $324 million for the year ended December 31, 2012 compared to $55 million for the year ended December 31, 2011. The $269 million increase is due to the following items:

•

Gain on sale of assets attributable to the Other Coal segment were $271 million for the year ended December 31, 2012 compared to $5 million for the year ended December 31, 2011. The change was primarily related to sales of non-producing assets in the Northern Powder River Basin that resulted in income of $151 million, as well as coal and surface lands in Western Canada, Illinois and West Virginia that resulted in income of $112 million. 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 detail of these sales. The remaining $3 million change was related to various transactions that occurred throughout both periods, none of which were individually material.

•

For the year ended December 31, 2012, $12 million of income was recognized related to contracts from certain thermal coal customers that were unable to take delivery of previously contracted coal tonnage. These customers agreed to buy out their contracts in order to be released from the requirements of taking delivery of previously committed tons. No such transactions were entered into in the year ended December 31, 2011.


•	Gain on issuances of pipeline right-of-ways to third parties decreased $8 million in the year-to-year comparison, primarily due to a $10 million pipeline right-of-way to a third party issued in the year ended December 31, 2011.


•	The remaining $1 million decrease in a year-to-year comparison is due to several transactions, none of which are individually material.

Other coal segment total costs were $525 million for the year ended December 31, 2012 compared to $508 million for the year ended December 31, 2011. The increase of $17 million was due to the following items:



	For the Years Ended December 31,
	2012		2011		Variance
Closed and idle mines	$	134	$	73	$	61
Bailey Belt Incident	42		—		42
Voluntary Incentive Separation Program	13		—		13
Litigation Contingencies	17		12		5
General and Administrative Expense	102		123		(21		)
Purchased Coal	41		63		(22		)
Freight expense	107		175		(68		)
Other	69		62		7
Total other coal segment costs	$	525	$	508	$	17

•

Closed and idle mine costs increased approximately $61 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. The increase was the result of $30 million additional costs related to reclamation liabilities and on-going idling costs incurred at the Fola Complex for the year ended December 31, 2012. Closed and idle mine costs increased $20 million as the result of a 2012 decision to temporarily idle Buchanan Mine in 2012. Closed and idle mine costs increased $11 million due to other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material.


•	Bailey Belt incident costs represents expenses related to continued advancement of the mines and on-going projects at the mines that took place during the idled phase when belt reconstruction was occurring.

•

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 will receive a severance payment equal to one year's salary and the 2013 accrued vacation earned as of December 31, 2012. Approximately 100 employees volunteered for the program. Severance and vacation pay was approximately $13 million and was recognized for the year ended December 31, 2012. This was paid in January 2013.


•	Litigation contingencies increased $5 million in the year-to-year comparison due to various items. 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 additional details related to total Company expense.


•	General and Administrative Expense related to the other coal segment decreased by $21 million primarily due to a reduction of wages and related expenses.


•	Purchased coal costs decreased approximately $22 million in the year-to-year comparison primarily due to differences in the quality of coal purchased, decreases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.

•

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is almost completely offset in freight revenue. The $68 million decrease in freight revenue was due to decreased shipments which CONSOL Energy contractually provides transportation services.


•	Other costs related to the coal segment increased $7 million due to various other transactions that occurred throughout both periods, none of which are individually material.

OTHER SEGMENT ANALYSIS for the year ended December 31, 2012 compared to the year ended December 31, 2011:

The other segment includes activity from the sales of industrial supplies, coal terminal operations and various other corporate activities that are not allocated to the gas or coal segment. The other segment had a loss before income tax of $224 million for the year ended December 31, 2012 compared to a loss before income tax of $289 million for the year ended December 31, 2011. The other segment also includes total company income tax expense of $89 million for the year ended December 31, 2012 compared to $191 million for the year ended December 31, 2011.



	For the Years Ended December 31,
	2012			2011			Variance			Percent Change
Sales—Outside	$	294		$	285		$	9		3.2	%
Other Income	6			8			(2		)	(25.0	)%
Total Revenue	300			293			7			2.4	%
Cost of Goods Sold and Other Charges	289			320			(31		)	(9.7	)%
Depreciation, Depletion & Amortization	15			12			3			25.0	%
Taxes Other Than Income Tax	5			11			(6		)	(54.5	)%
Interest Expense	215			239			(24		)	(10.0	)%
Total Costs	524			582			(58		)	(10.0	)%
Loss Before Income Tax	(224		)	(289		)	65			22.5	%
Income Tax	89			191			(102		)	(53.4	)%
Net Loss	$	(313	)	$	(480	)	$	167		34.8	%

Industrial supplies:

Total revenue from industrial supplies was $244 million for the year ended December 31, 2012 compared to $236 million for the year ended December 31, 2011. The increase was related to higher sales volumes.

Total costs related to industrial supply sales were $239 million for the year ended December 31, 2012 compared to $235 million for the year ended December 31, 2011. The increase of $4 million was primarily related to higher sales volumes and various changes in inventory costs, none of which were individually material.

Transportation operations:

Total revenue from transportation operations was $52 million for the year ended December 31, 2012 compared to $51 million for the year ended December 31, 2011. The increase of $1 million was primarily due to an increase in thru-put rates at the CNX Marine Terminal.

Total costs related to the transportation operations were $43 million for the year ended December 31, 2012 compared to $36 million for the year ended December 31, 2011. The increase of $7 million was primarily attributable to an increase in thru-put costs at the CNX Marine Terminal offset, in part, by a decrease in thru-put tons.

Miscellaneous other:

Additional other income of $4 million was recognized for the year ended December 31, 2012 compared to $6 million for the year ended December 31, 2011. The $2 million decrease was primarily due to various transactions that have occurred throughout both periods, none of which were individually material.

Other corporate costs in the other segment include interest expense, transaction and financing fees and various other miscellaneous corporate charges. Total other costs were $242 million for the year ended December 31, 2012 compared to $311 million for the year ended December 31, 2011. Other corporate costs decreased due to the following items:



	For the Years Ended December 31,
	2012		2011		Variance
Interest expense	$	215	$	239	$	(24	)
Loss on extinguishment of debt	—		16		(16		)
Transaction and financing fees	—		15		(15		)
Bank fees	13		18		(5		)
Evaluation fees for non-core asset dispositions	4		6		(2		)
Other	10		17		(7		)
	$	242	$	311	$	(69	)


•	Interest Expense decreased $24 million in the period-to-period comparison. Interest expense decreased due to an increase in capitalized interest related to higher capital expenditures for major construction projects in the current period. Capital expenditures for coal activities increased $310 million in the period-to-period comparison.


•	On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes.


•	The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held to maturity.


•	Transaction and financing fees of $15 million incurred in the year ended December 31, 2011 related to the solicitation of consents of the long-term bonds needed in order to clarify the indentures that relate to joint arrangements with respect to its oil and gas properties.


•	Bank fees decreased $5 million mainly due to lower borrowings on the revolving credit facilities in the period-to-period comparison and also due to the refinancing and extension of the credit facility on April 12, 2011.


•	Evaluation fees for non-core asset dispositions and other legal charges decreased $2 million in the period-to-period comparison due to various corporate initiatives.


•	Various other corporate expenses decreased $7 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 21.8% for the year ended December 31, 2012 compared to 21.9% for the year ended December 31, 2011. The decrease in the effective tax rate for the year ended December 31, 2012 as compared to the year ended December 31, 2011 was primarily attributable to various discrete transactions that occurred in both periods. The discrete transactions included an Internal Revenue Service audit settlement for years 2006 and 2007 and the corresponding impacts to the previously accrued tax positions which resulted in higher percentage depletion deductions. Discrete transactions also included the reversal of a valuation allowance for certain state net operating loss carryforwards and future temporary deductions as well as the reversal of certain uncertain tax positions. 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.



	For the Years Ended December 31,
	2012			2011			Variance			Percent Change
Total Company Earnings Before Income Tax	$	407		$	873		$	(466	)	(53.4	)%
Income Tax Expense	$	89		$	191		$	(102	)	(53.3	)%
Effective Income Tax Rate	21.8		%	21.9		%	(0.1		)%

Critical Accounting Policies

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)

On March 31, 2012, the salaried OPEB plan was amended to reduce medical and prescription drug benefits as of January 1, 2014. The plan amendment calls for a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The amount of the contribution will be 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. Employees who work or worked in corporate or operational support positions at retirement and who are age 50 or older at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug benefits described above upon meeting the eligibility requirements at retirement. Employees who work or worked in corporate or operational support positions who are under age 50 at December 31, 2013 will receive no retiree medical or prescription drug benefits.

On December 5, 2013, the OPEB obligation was reduced due to the sale of Consolidation Coal Company and its subsidiaries (comprised of five West Virginia Coal Mines, the River Division and various other locations) to Murray Energy. The OPEB obligation was reduced by $1,891.1 million. The plan was remeasured on the date of the sale using a discount rate of 4.91% compared to December 31, 2012 discount rate of 4.05% .

As of December 31, 2013, we conducted our annual review of the various actuarial assumptions, including discount rate, expected trend in health care costs, average remaining service period, average remaining life expectancy, per capita costs and participation level in each future year used by our independent actuary to estimate the cost and benefit obligations for our retiree health plans. Expected trends in future health care cost assumptions were adjusted from prior year to reflect recent experience and future expectations. The initial expected trend in health care costs at this year's measurement date was 6.17% with an ultimate trend rate of 4.50% expected to be reached in 2026. The initial expected trend rate at last year's measurement date was 6.30% with an ultimate trend rate of 4.50% expected to be reached in 2026. A 1.0% decrease in the health care trend rate would have decreased interest and service cost for 2013 by approximately $14.3 million. A 1.0% increase in the health care trend rate would have increased the interest and service cost by approximately $17.3 million. The discount rate is determined each year at the measurement date, or subsequent remeasurement date, if applicable. The discount rate is determined using a Company-specific yield curve model (above-mean) developed with assistance of an external actuary. The Company-specific yield curve model (above-mean) 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, and the underlying cash flows of the bonds included in the model exceed the cash flows needed to satisfy the Company plans' obligations. The OPEB plan was remeasured at December 5, 2013 to reflect

the curtailment of a portion of the plan related to the sale of five West Virginia Coal mines, the River Divison and various other locations. At December 31, 2013 and December 5, 2013 (remeasurement date), the discount rate used to calculate the period end liability and the following year's expense was 4.88% and 4.91%, respectively. A 0.25% increase in the discount rate would have decreased 2013 net periodic postretirement benefit costs by approximately $3.7 million. A 0.25% decrease in the discount rate would have increased 2013 net periodic postretirement benefit costs by approximately $3.8 million. Deferred gains and losses are primarily due to historical changes in the discount rate and medical cost inflation differing from expectations in prior years. Changes to interest rates for the rates of returns on instruments that could be used to settle the actuarially determined plan obligations introduce substantial volatility to our costs. Accumulated actuarial gains or losses in excess of a pre-established corridor are amortized on a straight-line basis over the expected future service of active salary and non-represented employees to their assumed retirement age. At December 31, 2013, the average remaining service period is approximately 13 years for our non-represented plans. The accumulated actuarial gains or losses related to the portion of the plan that was transferred in the sale mention above, was recognized in Income from Discontinued Operations.

CONSOL Energy benefits are under self-insured arrangements. The self-insured benefits weighted average per capita costs used to value the December 31, 2013 OPEB liability was approximately 1% less than previously expected based on our trend assumption. The fully insured benefits reflect the 2014 premium rates guaranteed by the respective insurance companies to value the December 31, 2013 OPEB liability. If future per capita cost or premium rates are significantly greater or less than the projected trend rates, the per capita cost and premium rate assumptions would need to be adjusted, which could have a significant effect on the costs and liabilities recorded in the financial statements.

The estimated liability recognized in the December 31, 2013 financial statements was $1.0 billion. For the year ended December 31, 2013, we paid approximately $161.9 million for other postretirement benefits, all of which were paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2013. CONSOL Energy does not expect to contribute to the other postretirement plan in 2014. We intend to pay benefit claims as they are due.

Salaried Pensions

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer plans. The benefits for these plans are based primarily on years of service and employee's pay near retirement. CONSOL Energy's salaried plan allows for lump-sum distributions of benefits earned up until December 31, 2005, at the employees' election. The Restoration Plan was frozen effective December 31, 2006 and was replaced prospectively with the CONSOL Energy Supplemental Retirement Plan. CONSOL Energy's Restoration Plan allows only for lump-sum distributions earned up until December 31, 2006. Effective September 8, 2009, the Supplemental Retirement Plan was amended to include employees of CNX Gas. The Supplemental Retirement Plan was frozen effective December 31, 2011 for certain employees and was replaced prospectively with the CONSOL Energy Defined Contribution Restoration Plan.

Our independent actuaries calculate the actuarial present value of the estimated retirement obligation based on assumptions including rates of compensation, mortality rates, retirement age and interest rates. For the year ended December 31, 2013, compensation increases are assumed to range from 3% to 6% depending on age and job classification. The discount rate is determined each year at the measurement date, or subsequent remeasurement date, if applicable. The discount rate is determined using a Company-specific yield curve model (above-mean) developed with assistance of an external actuary. The Company-specific yield curve model (above-mean) 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, and the underlying cash flows of the bonds included in the model exceed the cash flows needed to satisfy the Company plans'. For the years ended December 31, 2013 and 2012, the discount rate used to calculate the period end liability and the following year's expense was 4.87% and 4.00%, respectively. The discount rate was reset at the end of each quarter due to pension settlement accounting, see below for further discussion. A 0.25% increase in the discount rate would have decreased the 2013 net periodic pension cost by $1.8 million. A 0.25% decrease in the discount rate would have increased the 2013 net periodic pension cost by $1.8 million. Deferred gains and losses are primarily due to historical changes in the discount rate and earnings on assets differing from expectations. At December 31, 2013 the average remaining service period is approximately 12 years. Changes to any of these assumptions introduce substantial volatility to our costs.

The assumed rate of return on plan assets can also impact CONSOL Energy's pension liability. The rate of return on plan assets was 7.75% at December 31, 2013 and 8.00% at December 31, 2012. A reduction of 0.25% would have increased 2013 expense by $1.7 million. An increase of 0.25% would have decreased 2013 expense by $1.7 million. The market related asset value is derived by taking the cost value of assets as of December 31, 2013 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, 2013 consisted of 61% equity securities and 39% debt securities.

As a result of lump sum settlements in 2013 (including those associated with the 2012 VSIP), a pension settlement charge of $39.5 million was recognized for both the Qualified and Non-Qualified salaried pension plans. When lump sum payments from the pension plan exceed the service and interest expense, pension settlement accounting requires unamortized actuarial gains and loss related to the lump sum payouts be amortized immediately. At the end of each quarter in 2013, the pension plan was remeasured using the then current discount rate. The rates used were 4.87% at December 31, 2013, 4.80% at September 30, 2013, 4.84% at June 30, 2013 and 4.12% at March 31, 2013. A settlement charge is also reasonably possible to occur in 2014 related to the sale of CCC and subsidiaries, discussed above, and related reduction in administrative staffing levels. The 2014 threshold for pension settlement recognition is $53 million. If the threshold for pension settlement is reached, the pension settlement charge could be material to the financial results of CONSOL Energy. Also, if pension settlement is triggered in 2014, pension settlement would require the pension plan to be remeasured using updated assumptions, which would include resetting the discount rate used in the actuarial calculation.

The estimated liability recognized in the December 31, 2013 financial statements was $43.8 million, which is net of the $9 million of over funded Qualified Plan assets which is included in Other Assets. Also, the estimated asset for the overfund Qualified Salaried Pension Plan of $9.0 million is included in Other Assets in December 31, 2013 financial statements. For the year ended December 31, 2013, we contributed approximately $55.5 million to defined benefit retirement plans other than multi-employer plans and to other pension benefits. Our obligations with respect to the Non-Qualified Plan liabilities are non-funded at December 31, 2013. Our Qualified Plan liabilities are over funded at December 31, 2013. CONSOL Energy intends to contribute an amount that will avoid benefit restrictions for the following plan year.

Workers' Compensation and Coal Workers' Pneumoconiosis (CWP)

Workers' compensation is a system by which individuals who sustain employment related physical injuries or some type of occupational diseases are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation. Workers' compensation will also compensate the survivors of workers who suffer employment related deaths. The 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 records an actuarially calculated liability, which is determined using various assumptions, including discount rate, future healthcare cost trends, benefit duration and recurrence of injuries. The discount rate is determined each year at the measurement date, or subsequent remeasurement date, if applicable. The discount rate is determined using a Company-specific yield curve model (above-mean) developed with assistance of an external actuary. The Company-specific yield curve model (above-mean) 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, and the underlying cash flows of the bonds included in the model exceed the cash flows needed to satisfy the Company plans' obligations. For the years ended December 31, 2013 and 2012, the discount rate used to calculate the period end liability and the following year's expense was 4.57% and 3.95%, respectively. A 0.25% increase in the discount rate would have decreased the 2013 workers compensation expense cost by $0.4 million. A 0.25% decrease in the discount rate would have increased the 2013 workers compensation expense by $0.4 million. Deferred gains and losses are primarily due to historical changes in the discount rates, several years of favorable claims experience, various favorable state legislation changes and an overall lower incident rate than our assumptions. Accumulated actuarial gains or losses are amortized on a straight-line basis over the expected future service of active employees that are eligible to file a future workers' compensation claim. At December 31, 2013, the average remaining service period is approximately 13 years.

On December 5, 2013, the Workers’ Compensation obligation was reduced due to the sale of Consolidation Coal Company and its subsidiaries as discussed above. The Workers’ Compensation obligation was reduced by $105.3 million. The plan was remeasured on the date of the sale using a discount rate of 4.67% compared to December 31, 2012 discount rate of 3.95% .

The estimated liability recognized in the financial statements at December 31, 2013 was approximately $85.1 million. CONSOL Energy's policy has been to provide for workers' compensation benefits from operating cash flow. For the year ended December 31, 2013, we made payments for workers' compensation benefits and other related fees of approximately $28.7 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2013.

regarding disability incidence, medical costs, mortality, death benefits, dependents and discount rates. The discount rate is determined each year at the measurement date, or subsequent remeasurement date, if applicable. The discount rate is determined using a Company-specific yield curve model (above-mean) developed with assistance of an external actuary. The Company-specific yield curve model (above-mean) 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, and the underlying cash flows of the bonds included in the model exceed the cash flows needed to satisfy the Company plans' obligations. For the years ended December 31, 2013 and 2012, the discount rate used to calculate the period end liability and the following year's expense was 4.75% and 4.03%, respectively. A 0.25% increase in the discount rate would have increased 2013 coal workers' pneumoconiosis benefit by $0.6 million. A 0.25% decrease in the discount rate would have decreased 2013 coal workers' pneumoconiosis benefit by $0.5 million. Actuarial gains associated with coal workers' pneumoconiosis have resulted from numerous legislative changes over many years which have resulted in lower approval rates for filed claims than our assumptions originally reflected. Actuarial gains have also resulted from lower incident rates and lower severity of claims filed than our assumptions originally reflected. Accumulated actuarial gains or losses are amortized on a straight-line basis over the expected future service of active employees.

On December 5, 2013, the CWP obligation was reduced due to the sale of Consolidation Coal Company and its subsidiaries as discussed above. The CWP obligation was reduced by $49.7 million. The plan was remeasured on the date of the sale using a discount rate of 4.86% compared to December 31, 2012 discount rate of 4.03% .

The estimated liability recognized in the financial statements at December 31, 2013 was $121.2 million. For the year ended December 31, 2013, we paid coal workers' pneumoconiosis benefits of approximately $10.4 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2013.

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. On December 5, 2013, these obligations were reduced by $146.6 million due to the sale of Consolidation Coal Company and its subsidiaries discussed above. Estimates of our total reclamation, mine-closing liabilities, and gas well closing which are based upon permit requirements and CONSOL Energy engineering expertise related to these requirements, including the current portion, were approximately $601.0 million at December 31, 2013. 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 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, 2013, CONSOL Energy has deferred tax liabilities in excess of deferred tax assets of approximately $31.3 million. The change from the company reporting a net deferred tax asset for 2012 to a net deferred tax liability for 2013 is mainly attributable to the assumption of certain long-term liabilities by Murray Energy Corporation as part of the sale that closed in December 2013. In total, $414.5 million of net

deferred tax assets (including the deferred tax assets reported in Other Comprehensive Income) were removed in relation to the sale. The deferred tax assets are evaluated periodically to determine if a valuation allowance is necessary.

Deferred tax valuation allowances changed significantly for the year ended December 31, 2013 compared to December 31, 2012 due to the sale to Murray Energy Corporation of certain subsidiaries with state net operating loss carry forwards of $28 million subject to a full valuation allowance. CONSOL Energy continues to report a deferred tax asset of approximately $51.8 million relating to its state net operating loss carry forwards subject to a valuation allowance of $7.5 million. A review of positive and negative evidence regarding these benefits, primarily the history of financial and tax losses on a separate company basis, concluded that a partial valuation allowance was warranted. The net operating loss carry forwards expire at various times from 2018 to 2032. Management will continue to assess the realization of deferred tax assets attributable to state net operating loss carry forwards and future tax deductible differences based upon updated income forecast data and the feasibility of future tax planning strategies, and may record adjustments to valuation allowances against these deferred tax assets in future periods that could materially impact net income.

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. Estimates of our uncertain tax liabilities, including interest and the current portion, were approximately $29 million at December 31, 2013.

Stock-Based Compensation

As of December 31, 2013, 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, 2013, $24.6 million of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.67 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.

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.

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.

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's $1.0 billion Senior Secured Credit Agreement, as amended by Amendment No.1 dated December 5, 2013, expires April 12, 2016. The amendment on December 5, 2013 reduced the availability from $1,500,000 to $1,000,000 resulting in an acceleration of previously deferred financing charges of $3,195. 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 $1.0 billion of borrowings and letters of credit. CONSOL Energy can request an additional $250 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing adjusted earnings before interest, taxes, depreciation, depletion and amortization (Adjusted EBITDA), measured quarterly. Financial covenant debt is comprised of the outstanding indebtedness and specific letters of credit, less cash on hand, of CONSOL Energy and certain of its subsidiaries. The facility includes a minimum interest coverage ratio covenant of no less than 1.50 to 1.00, measured quarterly through March 30, 2015 and 2.00 to 1.00 thereafter. 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 2.21 to 1.00 at December 31, 2013. 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 and includes cash distributions received from affiliates, excluding cash distributions from CNX Gas and its subsidiaries, plus pro-rata earnings from material acquisitions. The facility also includes a senior secured leverage ratio covenant of no more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio is calculated as the ratio of secured debt to Adjusted EBITDA. Secured debt is defined as financial covenant debt, excluding indebtedness not secured by a lien, of CONSOL Energy and certain of its subsidiaries. The senior secured leverage ratio was less than 1.00 to 1.00 at December 31, 2013. Covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another company and amend, modify or restate, in any material way, the senior unsecured notes. At December 31, 2013, the facility had no outstanding borrowings and $207 million of letters of credit outstanding, leaving $793 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.

CONSOL Energy also has an accounts receivable securitization facility. This facility allows the Company to receive, on a revolving basis, up to $200 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, 2013, eligible accounts receivable totaled approximately $115 million. At December 31, 2013, the facility had no outstanding borrowings and $66 million of letters of credit outstanding, leaving $49 million of unused capacity.

CNX Gas' $1.0 billion Senior Secured Credit Agreement expires April 12, 2016. The facility is secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1.0 billion of borrowings and letters of credit. CNX Gas can request an additional $250 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. The interest coverage ratio is calculated as the ratio of Adjusted EBITDA to cash interest expense for CNX Gas and its subsidiaries. The interest coverage ratio was 25.33 to 1.00 at December 31, 2013. The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00, measured quarterly. The leverage ratio is calculated as the ratio of financial covenant debt to twelve-month trailing Adjusted EBITDA for CNX Gas and its subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and letters of credit, less cash on hand, of CNX Gas and its subsidiaries. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, gains and losses on the sale of assets, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 0.61 to 1.00 at December 31, 2013. Covenants in the facility limit CNX Gas' ability to dispose of assets, make investments, pay dividends and merge with another company. The credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems and provides for up to $600 million of loans, advances and dividends from CNX Gas to CONSOL Energy. Investments in CONE are unrestricted. At December 31, 2013, the facility had no amounts drawn and $88 million of letters of credit outstanding, leaving $912 million of unused capacity.

Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. The risks include declines in our stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact our collection of trade receivables. As a result, CONSOL Energy regularly monitors the creditworthiness of our customers. We believe that our current group of customers are financially sound and represent no abnormal business risk.

CONSOL Energy believes that cash generated from operations, asset sales and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments and to provide required letters of credit. Nevertheless, the ability of CONSOL Energy to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the coal and gas industries and other financial and business factors, some of which are beyond CONSOL Energy's control.

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap 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 $65 million at December 31, 2013. The $5 million ineffective portion of these contracts was insignificant to earnings in the year ended December 31, 2013. No issues related to our 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 (in millions)



	For the Years Ended December 31,
	2013			2012			Change
Cash flows from operating activities	$	659		$	728		$	(69	)
Cash used in investing activities	$	(202	)	$	(1,000	)	$	798
Cash used in financing activities	$	(151	)	$	(82	)	$	(69	)

Cash flows provided by operating activities decreased $69 million in the period-to-period comparison primarily due to the following items:


•	Net income increased $271 million in the period-to-period comparison;


•	Discontinued operations changes decreased $675 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 $214 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; 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 decreased $798 million in the period-to-period comparison primarily due to the following items:


•	Capital expenditures increased $251 million due to:

•

Gas segment capital expenditures increased $441 million. The increase was comprised of increased drilling costs in the Marcellus and Utica plays, CONSOL Energy's agreement to lease oil and gas rights from the Allegheny County Airport Authority, land acquisitions in Monroe and Noble Counties in Ohio, additional gas drilling rights acquired from Dominion Transmission in West Virginia and various other individually insignificant projects;


•	Coal segment capital expenditures decreased $196 million. The decrease was comprised of a $27 million decrease in Bailey Mine Expansion projects. Longwall shield projects decreased $71 million as well as an additional $98 million decrease in various miscellaneous transactions that occurred throughout both periods, none of which were individually material; and

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•	Other capital expenditures increased $6 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.


•	Proceeds from sale of assets decreased $161 million due to various items that occurred throughout 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 more information.


•	Discontinued operations changes increased $1,106 million primarily as a result of the gain on the sale of CCC and certain subsidiaries to Murray Energy Corporation in December 2013.


•	Distributions from/investments in equity affiliates decreased $12 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

•

Restricted cash increased $116 million due to the release of $69 million of restricted cash of which $48 million is associated with the Ram River & Scurry Canadian asset proceeds received during December 2012 and $21 million is associated with the Ryerson Dam Settlement. 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.

Net cash used in financing activities decreased $69 million in the period-to-period comparison primarily due to the following items:


•	In 2013, CONSOL Energy repaid $32 million of borrowings related to miscellaneous borrowings. In 2012, CONSOL Energy received $16 million of borrowings.


•	The accelerated declaration and payment of the regular quarterly dividend in the fourth quarter of 2012 resulted in no dividends paid in the first quarter of 2013. Total dividends paid in the year ended December 31, 2013 were $86 million as compared to $142 million in dividends paid in the period ended December 31, 2012.


•	In 2013, CONSOL Energy repaid $38 million of borrowings under its Securitization Facility. In 2012, CONSOL Energy had proceeds of $38 million from the Securitization Facility.


•	The remaining change is due to various other transactions that occurred throughout both periods, none of which were individually material.

The following is a summary of our significant contractual obligations at December 31, 2013 (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	167,658		125,505		61,768		14,637		369,568
Gas Firm Transportation	73,212		134,713		137,376		568,696		913,997
Long-Term Debt	3,489		6,553		1,503,562		1,605,316		3,118,920
Interest on Long-Term Debt	245,385		490,600		310,280		240,117		1,286,382
Capital (Finance) Lease Obligations	8,498		15,334		13,096		19,166		56,094
Interest on Capital (Finance) Lease Obligations	3,557		5,493		3,790		2,110		14,950
Operating Lease Obligations	102,454		177,781		119,230		95,669		495,134
Long-Term Liabilities—Employee Related (a)	87,751		181,311		188,171		791,444		1,248,677
Other Long-Term Liabilities (b)	298,584		211,363		97,815		318,321		926,083
Total Contractual Obligations (c)	$	990,588	$	1,348,653	$	2,435,088	$	3,655,476	$	8,429,805

_________________________


(a)	Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2014 contributions are expected to approximate $25 million to $35 million.


(b)	Other long-term liabilities include mine reclamation and closure and other long-term liability costs.


(c)	The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

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Debt

At December 31, 2013, CONSOL Energy had total long-term debt and capital lease obligations of $3.175 billion outstanding, including the current portion of long-term debt and capital lease obligations of $11 million. This long-term debt consisted of:


•	An aggregate principal amount of $1.50 billion of 8.00% senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.


•	An aggregate principal amount of $1.25 billion of 8.25% senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.


•	An aggregate principal amount of $250 million of 6.375% notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.


•	An aggregate principal amount of $103 million of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at 5.75% per annum and mature in September 2025. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by CONSOL Energy.


•	Advance royalty commitments of $11 million with an average interest rate of 7.93% per annum.


•	An aggregate principal amount of $5 million on other various rate notes maturing through June 2031.


•	An aggregate principal amount of $56 million of capital leases with a weighted average interest rate of 6.19% per annum.

At December 31, 2013, CONSOL Energy had no outstanding borrowings and approximately $207 million of letters of credit outstanding under the $1 billion senior secured revolving credit facility.

At December 31, 2013, CONSOL Energy had no outstanding borrowings and had $66 million of letters of credit outstanding under the accounts receivable securitization facility.

At December 31, 2013, CNX Gas, a wholly owned subsidiary, had no outstanding borrowings and approximately $88 million of letters of credit outstanding under the $1 billion secured revolving credit facility.

Total Equity and Dividends

CONSOL Energy had total equity of $5.0 billion at December 31, 2013 and $4.0 billion at December 31, 2012. Total equity increased primarily due to net income, adjustments to actuarial liabilities and the amortization of stock-based compensation awards. These increases were offset, in part, by the declaration of dividends and changes in the fair value of cash flow hedges. 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:



Declaration Date	Amount Per Share	Record Date	Payment Date
February 3, 2014	$0.0625	February 14, 2014	February 28, 2014
November 1, 2013	$0.125	November 15, 2013	December 4, 2013
July 26, 2013	$0.125	August 9, 2013	August 23, 2013
April 26, 2013	$0.125	May 10, 2013	May 24, 2013

On October 28, 2013, CONSOL Energy announced that in conjunction with the sale to Murray Energy, CONSOL Energy is realigning its dividend policy to reflect the company's increased emphasis on growth. CONSOL Energy intends to pay a regular quarterly rate of $0.0625 per common share, for an annual rate of $0.25 per share.

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dividend payments in the event of default. The indentures to the 2017, 2020 and 2021 notes limit dividends to $0.40 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, 2013.

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 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at December 31, 2013. 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, 2013. 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.

Recent Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board issued Update 2013-04 - Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The objective of the amendments in this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. generally accepted accounting principles (GAAP). The guidance in this update requires an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of the following: (a.) The amount the reporting entity agreed to pay on the basis of its arrangement amount with its co-obligors, and (b.) Any additional amount the reporting entity expects to pay on behalf of its co-obligors. The guidance in this update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments in this update should be applied retrospectively to all prior periods presented for those obligations resulting from joint and several liability arrangements within the update's scope that exist at the beginning of an entity's fiscal year of adoption. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

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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 of changing commodity prices, interest rates and foreign exchange rates.

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

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

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

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

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at December 31, 2013. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $70 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $72 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At December 31, 2013, CONSOL Energy had $3.175 billion aggregate principal amount of debt outstanding under fixed-rate instruments and no debt outstanding under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were no borrowings outstanding at December 31, 2013. A 100 basis-point increase in the average rate for CONSOL Energy’s revolving credit facility would not have significantly decreased net income for the period. CNX Gas also had borrowings during the period under its revolving credit facility which bears interest at a variable rate. CNX Gas’ facility had no outstanding borrowings at December 31, 2013 and bore interest at a weighted average rate of 1.66% per annum during the year ended December 31, 2013. Due to the level of borrowings against this facility and the low weighted average interest rate in the year ended December 31, 2013, a 100 basis-point increase in the average rate for CNX Gas’ revolving credit facility would not have significantly decreased net income for the period.

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

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Hedging Volumes

As of January 21, 2014 our hedged volumes for the periods indicated are as follows:



	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2014 Fixed Price Volumes
Hedged Bcf	31.9		32.2		32.6		32.6		129.3
Weighted Average Hedge Price/Mcf	$	4.61	$	4.61	$	4.61	$	4.61	$	4.61
2015 Fixed Price Volumes
Hedged Bcf	19.4		19.6		19.8		19.8		78.6
Weighted Average Hedge Price/Mcf	$	4.10	$	4.10	$	4.10	$	4.10	$	4.10
2016 Fixed Price Volumes
Hedged Bcf	17.7		17.8		17.9		17.9		71.3
Weighted Average Hedge Price/Mcf	$	4.20	$	4.20	$	4.20	$	4.20	$	4.20

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
Report of Independent Registered Public Accounting Firm		107
Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011		108
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011		109
Consolidated Balance Sheets at December 31, 2013 and 2012		110
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2013, 2012 and 2011		112
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011		113
Notes to the Audited Consolidated Financial Statements		114

106

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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 7, 2014 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 7, 2014

107

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)



	For the Years Ended December 31,
	2013			2012		2011
Sales—Outside	$	3,015,551		$	3,122,550	$	3,991,007
Sales—Gas Royalty Interests	63,202			49,405		66,929
Sales—Purchased Gas	6,531			3,316		4,344
Freight—Outside	35,438			107,079		175,633
Other Income (Note 4)	178,963			395,176		139,132
Total Revenue and Other Income	3,299,685			3,677,526		4,377,045
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	2,228,952			2,221,859		2,266,560
Gas Royalty Interests Costs	53,028			38,867		59,331
Purchased Gas Costs	4,837			2,711		3,831
Freight Expense	35,438			107,079		175,444
Selling, General and Administrative Expenses	90,408			90,740		114,643
Depreciation, Depletion and Amortization	461,122			427,115		430,577
Interest Expense (Note 5)	219,198			220,042		248,344
Taxes Other Than Income (Note 6)	160,627			162,426		174,392
Loss on Debt Extinguishment (Note 14)	—			—		16,090
Transaction and Financing Fees (Note 14)	—			—		14,907
Total Costs	3,253,610			3,270,839		3,504,119
Earnings Before Income Taxes	46,075			406,687		872,926
Income Taxes (Note 7)	(33,189		)	88,728		191,251
Income from Continuing Operations	79,264			317,959		681,675
Income (Loss) from Discontinued Operations, net of tax (Note 2)	579,792			70,114		(49,178		)
Net Income	659,056			388,073		632,497
Less: Net Loss Attributable to Noncontrolling Interest	1,386			397		—
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	660,442		$	388,470	$	632,497
Earnings Per Share (Note 1):
Basic:
Income from Continuing Operations	$	0.35		$	1.40	$	3.01
Income (Loss) from Discontinued Operations	2.54			0.31		(0.22		)
Net Income	$	2.89		$	1.71	$	2.79
Dilutive:
Income from Continuing Operations	$	0.35		$	1.39	$	2.98
Income (Loss) from Discontinued Operations	2.52			0.31		(0.22		)
Net Income	$	2.87		$	1.70	$	2.76
Weighted Average Number of Common Shares Outstanding (Note 1):
Basic	228,728,628			227,593,524		226,680,369
Dilutive	230,077,942			229,141,767		229,003,599
Dividends Paid Per Share	$	0.375		$	0.625	$	0.425

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

108

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)




	For the Years Ended December 31,
	2013			2012			2011
Net Income	$	659,056		$	388,073		$	632,497
Other Comprehensive Income:
Treasury Rate Lock (Net of tax: $-, $-, $59)	—			—			(96		)
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($276,928), ($77,871), $20,259)	456,493			129,231			(32,813		)
Net Increase in the Value of Cash Flow Hedge (Net of tax: ($29,407), ($73,593), ($129,235))	45,631			114,240			200,700
Reclassification of Cash Flow Hedges from Other Comprehensive Income to Earnings (Net of tax: $53,990, $121,484, $60,925)	(79,899		)	(189,259		)	(95,007		)

Other Comprehensive Income	422,225			54,212			72,784

Comprehensive Income	1,081,281			442,285			705,281

Less: Comprehensive Loss Attributable to Noncontrolling Interest	1,386			397			—

Comprehensive Income Attributable to CONSOL Energy Inc. Shareholders	$	1,082,667		$	442,682		$	705,281

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

109

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)




	December 31, 2013		December 31, 2012
ASSETS
Current Assets:
Cash and Cash Equivalents	$	327,420	$	21,862
Accounts and Notes Receivable:
Trade	332,574		428,328
Notes Receivable	25,861		318,387
Other Receivables	243,973		131,131
Accounts Receivable—Securitized (Note 10)	—		37,846
Inventories (Note 9)	157,914		170,808
Deferred Income Taxes (Note 7)	211,303		84,777
Recoverable Income Taxes	10,705		—
Restricted Cash (Note 1)	—		48,294
Prepaid Expenses	135,842		148,431
Current Assets of Discontinued Operations (Note 2)	—		149,230
Total Current Assets	1,445,592		1,539,094
Property, Plant and Equipment (Note 11):
Property, Plant and Equipment	13,578,509		12,121,557
Less—Accumulated Depreciation, Depletion and Amortization	4,136,247		3,613,499
Property, Plant and Equipment of Discontinued Operations, Net (Note 2)	—		1,682,909
Total Property, Plant and Equipment—Net	9,442,262		10,190,967
Other Assets:
Restricted Cash (Note 1)	—		20,379
Investment in Affiliates	291,675		222,830
Notes Receivable	125		25,977
Other	214,013		216,235
Other Assets of Discontinued Operations (Note 2)	—		782,112
Total Other Assets	505,813		1,267,533

TOTAL ASSETS	$	11,393,667	$	12,997,594

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

110

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)



	December 31, 2013			December 31, 2012
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	514,580		$	498,515
Current Portion of Long-Term Debt (Note 14 and Note 15)	11,455			12,484
Short-Term Notes Payable (Note 12)	—			25,073
Accrued Income Taxes	—			34,219
Borrowings Under Securitization Facility (Note 10)	—			37,846
Other Accrued Liabilities (Note 13)	565,697			545,748
Current Liabilities of Discontinued Operations (Note 2)	28,239			233,214
Total Current Liabilities	1,119,971			1,387,099
Long-Term Debt:
Long-Term Debt (Note 14)	3,115,963			3,123,600
Capital Lease Obligations (Note 15)	47,596			49,413
Long-Term Debt of Discontinued Operations (Note 2)	—			1,573
Total Long-Term Debt	3,163,559			3,174,586
Deferred Credits and Other Liabilities:
Deferred Income Taxes (Note 7)	242,643			326,685
Postretirement Benefits Other Than Pensions (Note 16)	961,127			882,600
Pneumoconiosis Benefits (Note 17)	111,971			114,136
Mine Closing (Note 8)	320,723			289,818
Gas Well Closing (Note 8)	175,603			146,002
Workers’ Compensation (Note 17)	71,468			60,396
Salary Retirement (Note 16)	48,252			218,004
Reclamation (Note 8)	40,706			47,965
Other	131,355			118,307
Deferred Credits and Other Liabilities of Discontinued Operations (Note 2)	—			2,278,251
Total Deferred Credits and Other Liabilities	2,103,848			4,482,164
TOTAL LIABILITIES	6,387,378			9,043,849
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 229,145,736 Issued and Outstanding at December 31, 2013; 228,129,467 Issued and 228,094,712 Outstanding at December 31, 2012	2,294			2,284
Capital in Excess of Par Value	2,364,592			2,296,908
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding	—			—
Retained Earnings	2,964,520			2,402,551
Accumulated Other Comprehensive Loss - Continuing Operations	(325,117		)	(747,342		)
Common Stock in Treasury, at Cost—No Shares at December 31, 2013 and 34,755 Shares at December 31, 2012	—			(609		)
Total CONSOL Energy Inc. Stockholders’ Equity	5,006,289			3,953,792
Noncontrolling Interest	—			(47		)
TOTAL EQUITY	5,006,289			3,953,745

TOTAL LIABILITIES AND EQUITY	$	11,393,667		$	12,997,594

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

111

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands, except per share data)



	Common Stock		Capital in Excess of Par Value			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Common Stock in Treasury			Total CONSOL Energy Inc. Stockholders’ Equity			Non- Controlling Interest			Total Equity
Balance at December 31, 2010	$	2,273	$	2,178,604		$	1,680,597		$	(874,338	)	$	(42,659	)	$	2,944,477		$	(8,464	)	$	2,936,013
Net Income	—		—			632,497			—			—			632,497			—			632,497
Treasury Rate Lock (Net of $59 Tax)	—		—			—			(96		)	—			(96		)	—			(96		)
Gas Cash Flow Hedge (Net of ($68,310) Tax)	—		—			—			105,693			—			105,693			—			105,693
Actuarially Determined Long-Term Liability Adjustments (Net of $20,259 Tax)	—		—			—			(32,813		)	—			(32,813		)	—			(32,813		)
Comprehensive Income (Loss)	—		—			632,497			72,784			—			705,281			—			705,281
Issuance of Treasury Stock	—		—			(32,001		)	—			33,313			1,312			—			1,312
Tax Benefit from Stock-Based Compensation	—		7,329			—			—			—			7,329			—			7,329
Amortization of Stock-Based Compensation Awards	—		48,842			—			—			—			48,842			—			48,842
Net Change in Noncontrolling Interest	—		—			—			—			—			—			8,464			8,464
Dividends ($0.425 per share)	—		—			(96,356		)	—			—			(96,356		)	—			(96,356		)
Balance at December 31, 2011	2,273		2,234,775			2,184,737			(801,554		)	(9,346		)	3,610,885			—			3,610,885
Net Income	—		—			388,470			—			—			388,470			(397		)	388,073
Gas Cash Flow Hedge (Net of $47,891 Tax)	—		—			—			(75,019		)	—			(75,019		)	—			(75,019		)
Actuarially Determined Long-Term Liability Adjustments (Net of ($77,871) Tax)	—		—			—			129,231			—			129,231			—			129,231
Comprehensive Income (Loss)	—		—			388,470			54,212			—			442,682			(397		)	442,285
Issuance of Treasury Stock	—		—			(28,378		)	—			8,737			(19,641		)	—			(19,641		)
Issuance of Common Stock	11		8,267			—			—			—			8,278			—			8,278
Tax Benefit from Stock-Based Compensation	—		6,028			—			—			—			6,028			—			6,028
Amortization of Stock-Based Compensation Awards	—		47,838			—			—			—			47,838			—			47,838
Net Change in Noncontrolling Interest	—		—			—			—			—			—			350			350
Dividends ($0.625 per share)	—		—			(142,278		)	—			—			(142,278		)	—			(142,278		)
Balance at December 31, 2012	2,284		2,296,908			2,402,551			(747,342		)	(609		)	3,953,792			(47		)	3,953,745
Net Income	—		—			660,442			—			—			660,442			(1,386		)	659,056
Gas Cash Flow Hedge (Net of $24,583 Tax)	—		—			—			(34,268		)	—			(34,268		)	—			(34,268		)
Actuarially Determined Long-Term Liability Adjustments (Net of ($276,928) Tax)	—		—			—			456,493			—			456,493			—			456,493
Comprehensive Income (Loss)	—		—			660,442			422,225			—			1,082,667			(1,386		)	1,081,281
Issuance of Treasury Stock	—		—			(12,641		)	—			609			(12,032		)	—			(12,032		)
Issuance of Common Stock	10		3,717			—			—			—			3,727			—			3,727
Tax Cost from Stock-Based Compensation	—		(2,075		)	—			—			—			(2,075		)	—			(2,075		)
Amortization of Stock-Based Compensation Awards	—		66,042			—			—			—			66,042			—			66,042
Net Change in Noncontrolling Interest	—		—			—			—			—			—			1,433			1,433
Dividends ($0.375 per share)	—		—			(85,832		)	—			—			(85,832		)	—			(85,832		)
Balance at December 31, 2013	$	2,294	$	2,364,592		$	2,964,520		$	(325,117	)	$	—		$	5,006,289		$	—		$	5,006,289

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

112

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



(Dollars in thousands)	For the Years Ended December 31,
	2013			2012			2011
Cash Flows from Operating Activities:
Net Income	$	659,056		$	388,073		$	632,497
Adjustments to Reconcile Net Income to Net Cash Provided By Continuing Operating Activities:
Net (Loss) Income from Discontinued Operations	(579,792		)	(70,114		)	49,178
Depreciation, Depletion and Amortization	461,122			427,115			430,577
Stock-Based Compensation	56,987			41,127			42,131
Gain on Sale of Assets	(67,480		)	(282,006		)	(45,673		)
Loss on Debt Extinguishment	—			—			16,090
Deferred Income Taxes	(36,777		)	10,899			(2,373		)
Equity in Earnings of Affiliates	(33,133		)	(27,048		)	(24,663		)
Changes in Operating Assets:
Accounts and Notes Receivable	135,970			(20,218		)	(83,770		)
Inventories	12,894			21,166			5,509
Prepaid Expenses	(3,219		)	12,435			3,047
Changes in Other Assets	31,146			(7,041		)	23,534
Changes in Operating Liabilities:
Accounts Payable	(99,944		)	(23,918		)	142,843
Other Operating Liabilities	(31,701		)	(50,790		)	78,530
Changes in Other Liabilities	5,844			12,876			38,413
Other	42,597			24,786			23,001
Net Cash Provided by Continuing Operations	553,570			457,342			1,328,871
Net Cash Provided by Discontinued Operating Activities	105,206			270,771			198,735
Net Cash Provided by Operating Activities	658,776			728,113			1,527,606
Cash Flows from Investing Activities:
Capital Expenditures	(1,496,056		)	(1,245,497		)	(1,178,375		)
Change in Restricted Cash	68,673			(48,294		)	—
Proceeds from Sales of Assets	483,969			645,621			747,285
(Investments in) Distributions from Equity Affiliates	(35,712		)	(23,451		)	55,876
Net Cash Used in Continuing Operations	(979,126		)	(671,621		)	(375,214		)
Net Cash Provided by (Used In) Discontinued Investing Activities	777,145			(328,789		)	(203,310		)
Net Cash Used in Investing Activities	(201,981		)	(1,000,410		)	(578,524		)
Cash Flows from Financing Activities:
Payments on Short-Term Borrowings	—			—			(284,000		)
(Payments on) Proceeds from Miscellaneous Borrowings	(31,544		)	16,195			(11,080		)
(Payments on) Proceeds from Securitization Facility	(37,846		)	37,846			(200,000		)
Payments on Long-Term Notes, Including Redemption Premium	—			—			(265,785		)
Proceeds from Issuance of Long-Term Notes	—			—			250,000
Tax Benefit from Stock-Based Compensation	2,929			8,678			8,281
Dividends Paid	(85,832		)	(142,278		)	(96,356		)
Proceeds from Issuance of Common Stock	3,727			8,278			—
(Purchases) Issuance of Treasury Stock	(2,151		)	(9,485		)	9,033
Debt Issuance and Financing Fees	—			(210		)	(15,686		)
Net Cash Used in Continuing Operations	(150,717		)	(80,976		)	(605,593		)
Net Cash Used in Discontinued Financing Activities	(520		)	(601		)	(547		)
Net Cash Used in Financing Activities	(151,237		)	(81,577		)	(606,140		)
Net Increase (Decrease) in Cash and Cash Equivalents	305,558			(353,874		)	342,942
Cash and Cash Equivalents at Beginning of Period	21,862			375,736			32,794
Cash and Cash Equivalents at End of Period	$	327,420		$	21,862		$	375,736

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

113

CONSOL ENERGY INC. AND SUBSIDIARIES

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. 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 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 does not expect any significant continuing involvement with these businesses following their divestiture, and these businesses are expected to be disposed of within one year.

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 business combinations, 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 coal and gas reserves value.

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. There were no material financing receivables with a contractual maturity greater than one year.

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.

114

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 amortized on a units-of-production method. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, or at a minimum once a year; those 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. We employ 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 a 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 to 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. We also make advance payments (advanced mining royalties) to lessors under certain lease agreements that are recoupable against future production, and we make payments that are generally based upon a specified rate per ton or a percentage of gross realization from the sale of the coal. We evaluate our 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-production method over proven and probable coal reserves. Advance mining royalties and leased coal interests are evaluated periodically, or at a minimum once a 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:

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		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, 2013, 2012, and 2011.

Capitalized costs of unproved gas properties are evaluated for recoverability on a prospect 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 $61,119, $39,029 and $18,095 for the years ended December 31, 2013, 2012 and 2011, 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.

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, 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 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 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 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.

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Postretirement Benefits Other Than Pensions:

Postretirement benefits other than pensions, except for those established pursuant to the Coal Industry Retiree Health Benefit Act of 1992 (the Health Benefit Act), are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the 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. Postretirement benefit obligations established by 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. 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 Cost of Goods Sold and Other Operating Charges 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 employees. 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 period. 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 reflected net on the income statement in Cost of Goods Sold and Other Operating Charges.

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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 Purchased Gas Revenue and Purchased Gas Costs 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 belonging to royalty interest owners sold by CONSOL Energy.

Freight Revenue and Expense:

Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight Revenue and Freight Expense, respectively.

Royalty Recognition:

Royalty expenses for gas rights are included in Gas Royalty Interest 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:

CONSOL Energy, or our subsidiaries, from time to time 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 managements 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.

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 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 the assumed exercise of stock options and performance stock options and the assumed vesting of restricted and performance stock 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 and performance share 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:

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	For the Years Ended
	December 31,
	2013	2012	2011
Anti-Dilutive Options	1,976,549	2,411,963	1,156,018
Anti-Dilutive Restricted Stock Units	282,230	8,822	—
Anti-Dilutive Performance Share Units	—	445,847	—
Anti-Dilutive Performance Share Options	802,804	501,744	—
	3,061,583	3,368,376	1,156,018

The computations for basic and dilutive earnings per share are as follows:



	For the Years Ended
	December 31,
	2013		2012		2011
Income from Continuing Operations	79,264		317,959		681,675
Income (Loss) from Discontinuing Operations	579,792		70,114		(49,178		)
Less: Net Loss Attributable to Noncontrolling Interest	1,386		397		—
Net income attributable to CONSOL Energy Inc. shareholders	$	660,442	$	388,470	$	632,497
Weighted average shares of common stock outstanding:
Basic	228,728,628		227,593,524		226,680,369
Effect of stock-based compensation awards	1,349,314		1,548,243		2,323,230
Dilutive	230,077,942		229,141,767		229,003,599
Earnings per share:
Basic (Continuing Operations)	$	0.35	$	1.40	$	3.01
Basic (Discontinuing Operations)	2.54		0.31		(0.22		)
Total Basic	$	2.89	$	1.71	$	2.79

Dilutive (Continuing Operations)	$	0.35	$	1.39	$	2.98
Dilutive (Discontinuing Operations)	2.52		0.31		(0.22		)
Total Dilutive	$	2.87	$	1.70	$	2.76

Shares of common stock outstanding were as follows:



	2013	2012	2011
Balance, beginning of year	228,094,712	227,056,212	226,162,133
Issuance related to Stock-Based Compensation(1)	1,051,024	1,038,500	894,079
Balance, end of year	229,145,736	228,094,712	227,056,212

(1) See Note 19–Stock-Based Compensation for additional information.

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Other Comprehensive Income (Loss):

Changes in Accumulated Other Comprehensive Income / (Loss) by component, net of tax, were as follows:



	Gains and Losses on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2012	$	76,761		$	(824,103	)	$	(747,342	)
Other comprehensive income before reclassifications	45,631			140,250			185,881
Amounts reclassified from accumulated other comprehensive income	(79,899		)	316,243			236,344
Other comprehensive income	(34,268		)	456,493			422,225
Balance at December 31, 2013	$	42,493		$	(367,610	)	$	(325,117	)

The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:



	For the Years Ended December 31,
	2013			2012			2011
Derivative Instruments (Note 23)
Natural gas price swaps	$	(133,889	)	$	(310,743	)	$	(155,932	)
Tax benefit	53,990			121,484			60,925
Net of tax	$	(79,899	)	$	(189,259	)	$	(95,007	)
Actuarially Determined Long-Term Liability Adjustments*(Note 16 and Note 17)
Amortization of prior service costs	$	(32,164	)	$	(53,853	)	$	(47,792	)
Recognized net actuarial loss	86,481			106,299			119,262
Settlement loss	39,482			—			—
Total	93,799			52,446			71,470
Tax expense	(35,806		)	(19,720		)	(27,416		)
Net of tax	$	57,993		$	32,726		$	44,054

*Excludes amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the years ended December 31, 2013, December 31, 2012 and December 31, 2011. 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 accounts for derivative instruments in accordance with the Derivatives and Hedging Topic of the FASB Accounting Standards Codification. This requires CONSOL Energy to measure every derivative instrument (including certain derivative instruments embedded in other contracts) at fair value and record them in 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 cash flow hedges, the effective portions of changes in fair value of the derivative are reported in other comprehensive income. The ineffective portions of hedges are 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 in offsetting changes in fair values or 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.

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

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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:

Reclassifications:

Certain amounts in prior periods have been reclassified to conform with the report classifications of the years ended December 31, 2013, 2012 and 2011, respectively, with no effect on previously reported net income or stockholders' equity.

Subsequent Events:

We have 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 includes all five of its longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy). CONSOL Energy retained overriding royalty interests in certain reserves sold in the agreement. Murray Energy also assumed $2,050,656 of CONSOL Energy's employee benefit obligations valued as of December 5, 2013 and its UMWA 1974 Pension Trust obligations. Murray Energy is primarily liable for all 1993 Coal Act liabilities. Cash proceeds of $825,285 were received related to this transaction, which were net of $24,715 in transaction fees. Proceeds are subject to adjustments related to working capital. A pre-tax gain of $1,035,346 was included in Income from Discontinued Operations on the Consolidated Statement of Income.

For all periods presented in the accompanying Consolidated Statement of Income, the sale of CCC was classified as discontinued operations. There were no other active businesses classified as discontinued operations in the three-year period ended December 31, 2013.

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.

The following table details selected financial information for the divested business included within discontinued operations:

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	For the Years Ended December 31,
	2013			2012			2011
Sales	$	2,598,875		$	1,717,926		$	1,740,196
Income (Loss) from operations before income taxes	$	969,685		$	90,587		$	(84,972	)
Income taxes (expense) benefit	(389,893		)	(20,473		)	35,794
Income (loss) from discontinued operations	$	579,792		$	70,114		$	(49,178	)

The major classes of assets and liabilities of discontinued operations are as follows:



	December 31, 2013		December 31, 2012
Assets:
Inventory	$	—	$	76,958
Current Deferred Income Tax Asset	—		63,327
Other Current Assets	—		8,945
Properties, plants, and equipment	—		1,682,909
Deferred Income Tax Asset	—		771,270
Other assets	—		10,842
Assets of discontinued operations	$	—	$	2,614,251
Liabilities:
Current Liabilities	$	28,239	$	233,214
Long Term Debt	—		1,573
Postretirement Benefits Other Than Pensions	—		1,949,801
Pneumoconiosis Benefits	—		60,645
Workers' Compensation	—		95,252
Mine Closing	—		156,909
Other liabilities	—		15,644
Liabilities of discontinued operations	$	28,239	$	2,513,038

NOTE 3—ACQUISITIONS AND DISPOSITIONS:

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 million 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. Noble Energy, our joint venture partner, acquired 50% of the acres and accordingly will reimburse CONSOL Energy for 50% of the associated costs. CONSOL Energy paid $91,243 in 2013 related to this transaction.

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

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

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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 is currently pending.

In March 2013, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed negotiations with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for the lease of the oil and gas rights on approximately 9.3 thousand acres. A majority of these contiguous acres are in the liquids area of the Marcellus Shale play. CNX Gas Company paid $46,315 as an up-front bonus payment at closing. Approximately 7.6% of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title. CNX Gas Company 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.

In January 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Bailey Mine. Cash proceeds for the sale were $71,166. A loss of $358 was recognized due to transaction fees and was included in Other Income in the Consolidated Statement of Income. The lease has been accounted for as an operating lease. The lease term is five years.

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. A note receivable of $24,500 was included in Accounts and Notes Receivables - Notes Receivables in the Consolidated Balance Sheet at December 31, 2013. The gain on the transaction was $89,943 and was included in Other Income 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 Other Income 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 Other Income in the Consolidated Statement of Income for the year ended December 31, 2012.

On February 9, 2012, CONSOL Energy completed the disposition of its Burning Star No. 4 property in Illinois, which consisted of 4.3 thousand acres of coal lands and surface rights, for proceeds of $13,023. The gain on the transaction was $11,261 and is included in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012.

On September 30 2011, CNX Gas Company and Noble formed CONE Gathering LLC (CONE), a joint venture established to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CNX Gas Company's 50% ownership interest in CONE is accounted for under the equity method of accounting. CNX Gas contributed its existing Marcellus Shale gathering infrastructure which had a net book value of $119,740 and Noble contributed cash of approximately $67,545. CONE made a cash distribution to CNX Gas in the amount of $67,545. The cash proceeds were recorded as cash inflows of $59,870 and $7,675 in Distributions from Equity Affiliates and Proceeds from the Sale of Assets, respectively, on the Consolidated Statements of Cash Flow. The gain on the transaction was $7,161 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011.

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On September 21, 2011, CONSOL Energy entered into an agreement with Antero Resources Appalachian Corp. (Antero), pursuant to which CONSOL Energy assigned to Antero overriding royalty interests (ORRI) of approximately 7% in approximately 116 thousand net acres of Marcellus Shale located in nine counties in southwestern Pennsylvania and north central West Virginia, in exchange for proceeds of $193,000 before transaction fees of $2,619. The net gain on the transaction was $41,057 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011.

NOTE 4—OTHER INCOME:



	For the Years Ended December 31,
	2013		2012		2011
Gain on disposition of assets (a)	$	67,480	$	282,006	$	45,673
Equity in earnings of affiliates	33,133		27,048		24,663
Royalty income	16,906		16,853		17,969
Interest income	15,889		28,937		8,919
Pennsylvania Turnpike Settlement	9,000		—		—
Right-of-way issuance	4,536		3,966		12,157
Other	32,019		36,366		29,751
Total Other Income	$	178,963	$	395,176	$	139,132

(a) See Note 3 - Acquisitions and Dispositions for additional information.

NOTE 5—INTEREST EXPENSE:



	For the Years Ended December 31,
	2013			2012			2011
Interest on debt	$	260,233		$	256,800		$	264,080
Interest on other payables	2,682			1,296			(189		)
Interest capitalized	(43,717		)	(38,054		)	(15,547		)
Total Interest Expense	$	219,198		$	220,042		$	248,344

Interest on other payables for the year ended December 31, 2013 includes interest expense of $1,369 related to uncertain tax positions. Interest on other payables for the years ended December 31, 2012 and December 31, 2011 includes a reversal of interest expense of $543 and $3,096, respectively, related to uncertain tax positions. See Note 7–Income Taxes, for further discussion.

NOTE 6—TAXES OTHER THAN INCOME:



	For the Years Ended December 31,
	2013			2012			2011
Production taxes	$	84,984		$	77,629		$	99,442
Property taxes	36,338			43,679			35,495
Payroll taxes	32,779			32,478			33,155
Capital stock & franchise tax	6,833			9,013			3,670
Virginia employment enhancement tax credit	(4,683		)	(4,311		)	(6,109		)
Other	4,376			3,938			8,739
Total Taxes Other Than Income	$	160,627		$	162,426		$	174,392

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NOTE 7—INCOME TAXES:

Income tax (benefit) expense provided on earnings from continuing operations consisted of:



	For The Years Ended December 31,
	2013			2012			2011
Current:
U.S. Federal	$	6,728		$	44,727		$	161,474
U.S. State	(10,903		)	1,508			32,150
Non-U.S	7,763			31,594			—
	3,588			77,829			193,624
Deferred:
U.S. Federal	(32,125		)	23,300			30,034
U.S. State	(4,652		)	(14,166		)	(32,407		)
Non-U.S.	—			1,765			—
	(36,777		)	10,899			(2,373		)

Total Income (Benefit) Expense	$	(33,189	)	$	88,728		$	191,251

The components of the net deferred tax liabilities are as follows:



	December 31,
	2013			2012
Deferred Tax Assets:
Postretirement benefits other than pensions	$	337,836		$	347,584
Mine closing	37,306			57,370
Alternative minimum tax	159,933			54,609
Pneumoconiosis benefits	44,580			46,164
Workers' compensation	31,008			25,191
Salary retirement	14,330			83,077
Net operating loss	168,658			27,277
Mine subsidence	35,655			20,804
Reclamation	20,978			26,716
Capital lease	22,489			23,103
Other	160,567			149,435
Total Deferred Tax Assets	1,033,340			861,330
Valuation Allowance**	(7,532		)	(4,500		)
Net Deferred Tax Assets	1,025,808			856,830

Deferred Tax Liabilities:
Property, plant and equipment	(954,007		)	(976,505		)
Gas hedge	(27,741		)	(51,006		)
Advance mining royalties	(38,105		)	(33,950		)
Other	(37,295		)	(37,277		)
Total Deferred Tax Liabilities	(1,057,148		)	(1,098,738		)

Net Deferred Tax Liability	$	(31,340	)	$	(241,908	)

**Valuation allowance of $(7,532) has been allocated to long-term deferred tax asset for 2013. Valuation allowance of $(4,500) has been allocated to long-term deferred tax asset for 2012.

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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, 2013 and 2012, 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 federal operating losses of $116,893 and state operating losses of $51,765 with a related valuation allowance of $7,532 at December 31, 2013. The deferred tax asset related to state operating losses, on an after tax adjusted basis, was $27,277 with a related valuation allowance of $4,500 at December 31, 2012. 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 2018 and 2032.

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 $4, after federal tax adjusted basis, has also been recorded for 2013. No valuation allowance was recognized in 2012. No allowances were recognized through other comprehensive income in 2013 or 2012. 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.

The following is a reconciliation stated as a percentage of pretax income from continuing operations, of the United States statutory federal income tax rate to CONSOL Energy's effective tax rate:



	For the Years Ended December 31,
	2013					2012					2011
	Amount			Percent		Amount			Percent		Amount			Percent
Statutory U.S. federal income tax rate	$	16,126		35.0	%	$	142,340		35.0	%	$	305,524		35.0	%
Excess tax depletion	(51,104		)	(110.9	)	(49,572		)	(12.2	)	(72,577		)	(8.3	)
Effect of medicare prescription drug, improvement and modernization act of 2003	2,112			4.6		2,112			0.5		2,112			0.2
Effect of domestic production activities	5,680			12.3		(7,215		)	(1.8	)	(21,938		)	(2.5	)
Federal and state tax accrual to tax return reconciliation	(1,406		)	(3.1	)	6,004			1.5		2,257			0.3
IRS and state tax examination settlements	3			—		(925		)	(0.2	)	(5,188		)	(0.6	)
Net effect of state income taxes	(2,399		)	(5.2	)	(8,737		)	(2.1	)	2,926			0.3
Effect of releasing valuation allowance	(4,659		)	(10.1	)	—			—		(22,618		)	(2.6	)
Effect of foreign tax	—			—		1,765			0.4		(1,822		)	(0.2	)
Other	2,458			5.3		2,956			0.7		2,575			0.3
Income Tax Expense / Effective Rate	$	(33,189	)	(72.1	)%	$	88,728		21.8	%	$	191,251		21.9	%

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A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:



	For the Years Ended
	December 31,
	2013		2012
Balance at beginning of period	$	34,786	$	37,586
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	—		—
Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations	—		(2,800		)
Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities	—		—
Balance at end of period	$	34,786	$	34,786

If these unrecognized tax benefits were recognized, CONSOL Energy's effective tax rate would be impacted by $2,071 at December 31, 2013 and 2012.

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 2008.

In 2013, CONSOL Energy recognized no changes in unrecognized tax benefits. The IRS is continuing its audit of tax years 2008 and 2009 in 2014. During the next year, the statute of limitations for assessing additional income tax deficiencies will expire for certain tax years in several state tax jurisdictions. The expiration of the statute of limitations for these years will have an insignificant impact on CONSOL Energy's net income for the twelve-month period.

CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. At December 31, 2013 and 2012, the Company had an accrued liability of $6,200 and $4,831 respectively, for interest related to uncertain tax positions. The accrued interest liabilities include $1,369 , $(543) and $(3,096) that were recorded in the Company's Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011, respectively. During the year ended December 31, 2013, CONSOL Energy paid no interest related to income tax deficiencies.

CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2013, 2012 and 2011, 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, net of the associated accumulated depreciation. 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, 2013 and 2012 is as follows:



	As of December 31,
	2013			2012
Balance at beginning of period	$	539,177		$	500,648
Accretion expense	41,909			37,922
Payments	(38,198		)	(36,086		)
Revisions in estimated cash flows	42,558			40,832
Other	15,429			(4,139		)
Balance at end of period	$	600,875		$	539,177

For the year ended December 31, 2013, Other includes $15,429 related to a contractual agreement between CONSOL Energy and Murray Energy whereas CONSOL Energy will retain the obligation of water treatment at sixteen locations sold to Murray Energy.

127

For the year ended December 31, 2012, Other includes $(4,139) related to the disposition of the non-producing Elk Creek property. See Note 3 - Acquisitions and Dispositions for additional details.

NOTE 9—INVENTORIES:

Inventory components consist of the following:



	December 31,
	2013		2012
Coal	$	31,944	$	53,452
Merchandise for resale	38,263		35,363
Supplies	87,707		81,993
Total Inventories	$	157,914	$	170,808

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $18,836 and $19,700 at December 31, 2013 and December 31, 2012, respectively.

NOTE 10—ACCOUNTS RECEIVABLE SECURITIZATION:

CONSOL Energy and certain of our U.S. subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The facility allows CONSOL Energy to receive, on a revolving basis, up to $200,000. The facility also allows for the issuance of letters of credit against the $200,000 capacity. At December 31, 2013, there were letters of credit outstanding against the facility of $66,055. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on the Company's financial condition. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements.

CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, buys and sells eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocably and without recourse, sell all of their eligible trade accounts receivable to CNX Funding Corporation, 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, our collection experience history and the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable. CONSOL Energy will continue to service the sold trade receivables for the financial institutions for a fee based upon market rates for similar services.

In accordance with the Transfers and Servicing 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.

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 $1,737, $1,723 and $1,986 for the years ended December 31, 2013, 2012 and 2011, respectively. These costs have been recorded as financing fees which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in March 2017 with the underlying liquidity agreement renewing annually each March.

At December 31, 2013 and December 31, 2012, eligible accounts receivable totaled $115,000 and $200,000, respectively. There was $48,945 in subordinated retained interest at December 31, 2013 and there was no subordinated retained interest at December 31, 2012. There were no borrowings under the securitization facility recorded on the Consolidated

128

Balance Sheets at December 31, 2013 and $37,846 borrowings under the securitization facility recorded on the Consolidated Balance Sheets at December 31, 2012. Also, a $37,846 decrease, a $37,846 increase, and a $200,000 decrease in the accounts receivable securitization facility for the years ended December 31, 2013, 2012 and 2011, respectively, are reflected in the Net Cash Used In Financing Activities in the Consolidated Statement of Cash Flows. In accordance with the facility agreement, the Company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.

NOTE 11—PROPERTY, PLANT AND EQUIPMENT:



	December 31,
	2013		2012
Coal & Other Plant and Equipment	$	3,681,051	$	3,414,940
Intangible Drilling Cost	1,937,336		1,550,297
Proven Properties	1,670,404		1,596,838
Unproven Properties	1,463,406		1,266,017
Coal Properties and Surface Lands	1,404,056		1,164,107
Gathering Equipment	1,058,008		1,006,882
Wells and Related Equipment	688,548		492,364
Airshafts	397,466		366,054
Leased Coal Lands	393,372		529,758
Coal Advance Mining Royalties	381,348		381,343
Mine Development	354,607		262,511
Other Gas Assets	126,239		82,217
Gas Advance Royalties	22,668		8,229
Total Property, Plant and Equipment	13,578,509		12,121,557
Less Accumulated Depreciation, Depletion and Amortization	4,136,247		3,613,499
Total Net Property, Plant and Equipment	$	9,442,262	$	8,508,058

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, 2013 and 2012, respectively.



	December 31,
	2013		2012
Unproven gas properties	$	1,487,166	$	1,266,017
Coal properties	273,242		317,676
Mine Development	238,356		145,940
Leased coal lands	99,506		118,697
Coal advance mining royalties	48,043		55,749
Airshafts	38,794		21,866
Gas advance royalties	22,668		8,229
Total	$	2,207,775	$	1,934,174

As of December 31, 2013 and 2012, plant and equipment includes gross assets under capital lease of $96,015 and $93,745, respectively. For the years ended December 31, 2013 and 2012, the Gas segment 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, 2013 and 2012, the Gas segment also maintains a capital lease for vehicles of $10,652 and $9,248, respectively, which are included in Other gas assets. For the years ended December 31, 2013 and 2012, the All Other segment maintains capital leases for vehicles and computer equipment of $18,444 and $17,578, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was $50,371 and $44,726 at December 31, 2013 and 2012, 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.

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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.

On October 21, 2011, CNX Gas Company, a wholly owned subsidiary of CONSOL Energy, completed a sale to Hess Ohio Developments, LLC (Hess) a 50% interest in nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54,254, which were net of $5,719 in transaction fees. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to pay approximately $534,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. The net gain on the transaction was $53,095 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011. CONSOL Energy and Hess have agreed to focus their development efforts on six core counties in southeastern Ohio, in which the joint venture holds approximately 73,000 mostly fee acres. To this end, the parties have agreed to pursue the sale of approximately 63,000 acres outside of the focus areas. In addition, as previously disclosed, based on title work performed by Hess as part of the title defect process, we believe that there are chain of title issues with respect to approximately 39,000 of the joint venture acres representing approximately $153,000 of carry, most of which likely cannot be cured. These acres, together with another 26,000 acres of allegedly defective acres have been reassigned to CONSOL Energy. CONSOL Energy may elect to cure the alleged defects related to these acres and develop them, or sell the acres for its own account. After taking into account the reassignment of approximately 65,000 acres, the parties have agreed that the total carry remaining after these adjustments is $335,000. The loss of these Utica Shale acres will not have a material impact on the Company's financial statements.

On September 30, 2011, CNX Gas Company completed a sale to Noble Energy, Inc. (Noble) of 50% of the Company's undivided interest in certain Marcellus Shale oil and gas properties in West Virginia and Pennsylvania covering approximately 628 thousand net acres and 50% of the Company's undivided interest in certain of its existing Marcellus Shale wells and related leases. In September 2011, cash proceeds of $485,464 were received related to this transaction, which were net of $34,998 transaction fees. Additionally, a note receivable was recognized related to the two additional cash payments to be received on the first and second anniversary of the transaction closing date. In September 2013, cash proceeds of $327,964 were received related to the second anniversary note receivable. In September 2012, cash proceeds of $327,964 were received related to the first anniversary note receivable. During December 2011, an additional receivable of $16,703 and a payable of $980 were recorded for closing adjustments and were included in Accounts and Notes Receivable - Other and Accounts Payable, respectively. Adjusted cash proceeds of $15,598 related to the additional receivable were received in April 2012. The net loss on the transaction was $64,142 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011. As part of the transaction, CNX Gas Company also received a commitment from Noble to pay one-third of the Company's working interest share of certain drilling and completion costs, up to approximately $2,100,000 with certain restrictions. These restrictions include the suspension of carry if average Henry Hub natural gas prices are below $4.00 per million British thermal units (MMbtu) for three consecutive months. The carry is currently suspended and will remain suspended until average natural gas prices are above $4.00/MMbtu for three consecutive months. Restrictions also include a $400,000 annual maximum on Noble's carried cost obligation.

The following unaudited pro forma combined financial statements are based on CONSOL Energy's historical consolidated financial statements and adjusted to give effect to the September 30, 2011 sale of a 50% interest in certain Marcellus Shale assets. The unaudited pro forma results for the periods presented below are prepared as if the transaction occurred as of January 1, 2010 and do not include material, non-recurring charges.



	Year Ended
	December 31,
	2011
Total Revenue and Other Income	$	6,073,904
Earnings Before Income Taxes	$	775,807
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	623,114
Basic Earnings Per Share	$	2.75
Dilutive Earnings Per Share	$	2.72

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The pro forma results are not necessarily indicative of what actually would have occurred if the transaction had been completed as of January 1, 2010, nor are they necessarily indicative of future consolidated results.

Under our joint venture agreement with Noble, Noble had the right to perform due diligence on the title to the oil and gas interests which we conveyed to them and to assert that title to the acreage is defective. CONSOL Energy could then review and respond to the asserted title defects, or cure them, and ultimately, if the claim is not resolved, either party could submit the defect to an arbitrator for resolution. We have completed our review of the title defect notice asserted by Noble, and working in collaboration with them, we have addressed defects with respect to approximately 87,851 gross deal acres, having a carry value of approximately $551,000, and successfully resolved such defects to the satisfaction of both parties. We have conceded defects which have an aggregate value of approximately $216,000 in excess of the applicable deductibles and the carry payable by Noble Energy to CONSOL Energy has been reduced by this amount. The impact of these conceded defects was $23,058 and $3,526 of expense for the years ended December 31, 2013 and 2012, respectively, and is included in Cost of Goods Sold and Other Charges in the Consolidated Statements of Income. The parties have resolved substantially all outstanding asserted defects.

The following table provides information about our industry participation agreements as of December 31, 2013:



	Industry	Industry
	Participation	Participation	Drilling
Shale	Agreement	Agreement	Carries
Play	Partner	Date	Remaining
Marcellus	Noble	September 30, 2011	$	1,873,785
Utica	Hess	October 21, 2011	$	230,353

NOTE 12—SHORT-TERM NOTES PAYABLE:

CONSOL Energy's $1,000,000 Senior Secured Credit Agreement, as amended by Amendment No. 1 dated December 5, 2013, expires April 12, 2016. The amendment reduced the availability from $1,500,000 to $1,000,000 resulting in an acceleration of previously deferred financing charges of $3,195 during the year ended December 31, 2013. 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 $1,000,000 of borrowings and letters of credit. CONSOL Energy can request an additional $250,000 increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (Adjusted EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 1.50 to 1.00, measured quarterly through March 30, 2015 and 2.00 to 1.00 thereafter. The interest coverage ratio was 2.21 to 1.00 at December 31, 2013. The facility also includes a senior secured leverage ratio covenant of not more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio was less than 1.00 to 1.00 at December 31, 2013. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. At December 31, 2013, the $1,000,000 facility had no borrowings outstanding and $206,988 of letters of credit outstanding, leaving $793,012 of capacity available for borrowings and the issuance of letters of credit. At December 31, 2012, the former $1,500,000 facility had no borrowings outstanding and $100,292 of letters of credit outstanding, leaving $1,399,708 of capacity available for borrowings and the issuance of letters of credit.

CNX Gas Corporation's (CNX Gas) $1,000,000 Senior Secured Credit Agreement expires April 12, 2016. The facility is secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1,000,000 of borrowings and letters of credit. CNX Gas can request an additional $250,000 increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas' ability to dispose of assets, make investments, pay dividends and merge with another corporation. The credit facility allows investments in joint ventures for the development and operation of gas gathering systems and provides for $600,000 of loans, advances and dividends from CNX Gas to CONSOL Energy. Investments in CONE are unrestricted. The facility includes a maximum leverage ratio covenant of not more than 3.50 to 1.00, measured quarterly. The leverage ratio was 0.61 to 1.00 at December 31, 2013. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 25.33 to 1.00 at December 31, 2013. At December 31, 2013, the $1,000,000 facility had no borrowings outstanding and $87,643 of letters of credit outstanding, leaving $912,357 of capacity available for borrowings and the issuance of letters of credit. At December 31, 2012, the $1,000,000 facility had no borrowings outstanding

131

and $70,203 of letters of credit outstanding, leaving $929,797 of capacity available for borrowings and the issuance of letters of credit.

CONSOL Energy entered into an interim funding arrangement for longwall shields. At December 31, 2012, CONSOL Energy had a note payable of $25,073 related to this funding arrangement. The interim funding arrangement bore a weighted average interest rate of 2.46% as of December 31, 2012. There were no interim funding agreements outstanding at December 31, 2013.

NOTE 13—OTHER ACCRUED LIABILITIES:



	December 31,
	2013		2012
Subsidence liability	$	98,573	$	88,939
Accrued interest	63,600		63,687
Accrued payroll and benefits	38,953		39,172
Short-term incentive compensation	30,371		28,744
Uncertain income tax positions	28,530		2,100
Accrued other taxes	26,305		35,943
Other	122,902		144,352
Current portion of long-term liabilities:
Postretirement benefits other than pensions	60,847		58,452
Mine closing	30,320		25,081
Gas well closing	23,971		9,729
Workers' compensation	13,628		9,176
Reclamation	9,552		20,582
Pneumoconiosis benefits	9,212		8,838
Salary retirement	4,593		6,937
Long-term disability	4,340		4,016
Total Other Accrued Liabilities	$	565,697	$	545,748

NOTE 14—LONG-TERM DEBT:



	December 31,
	2013		2012
Debt:
Senior notes due April 2017 at 8.00%, issued at par value	$	1,500,000	$	1,500,000
Senior notes due April 2020 at 8.25%, issued at par value	1,250,000		1,250,000
Senior notes due March 2021 at 6.375%, issued at par value	250,000		250,000
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (7.93% and 7.43% weighted average interest rate for December 31, 2013 and 2012, respectively)	11,182		19,103
Other long-term notes maturing at various dates through 2031 (total value of $5,923 and $7,300 less unamortized discount of $1,050 and $1,542 at December 31, 2013 and December 31,2012, respectively).	4,873		5,758
	3,118,920		3,127,726
Less amounts due in one year *	2,957		4,126
Long-Term Debt	$	3,115,963	$	3,123,600

* Excludes current portion of Capital Lease Obligations of $8,498 and $8,358 at December 31, 2013 and December 31, 2012, respectively.

132

Annual undiscounted maturities on long-term debt during the next five years are as follows:



Year ended December 31,	Amount
2014	$	3,364
2015	4,276
2016	3,457
2017	1,502,484
2018	1,403
Thereafter	1,609,159
Total Long-Term Debt Maturities	$	3,124,143

In August 2011, CONSOL Energy paid $16,090 which was the remaining principal balance on the 6.10% Notes due December 2012. The early debt retirement was completed as a condition of a drilling services contract termination with a variable interest entity.

Transaction and financing fees of $14,907 were incurred during the year ended December 31, 2011 related to the solicitation of consents from the holders of CONSOL Energy's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020 and 6.375% Senior Notes due 2021. The consents allowed an amendment of the indentures for each of those notes, clarifying that the joint venture transactions with Noble and Hess were permissible under those indentures. See Note 2–Acquisitions and Dispositions for additional information.

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, 2013, are as follows:



	Capital		Operating
	Leases		Leases
Year Ended December 31,
2014	$	12,059	$	90,565
2015	10,984		85,225
2016	9,842		73,158
2017	8,758		66,536
2018	8,128		41,221
Thereafter	21,272		81,321
Total minimum lease payments	$	71,043	$	438,026
Less amount representing interest (0.63% – 7.36%)	14,949
Present value of minimum lease payments	56,094
Less amount due in one year	8,498
Total Long-Term Capital Lease Obligation	$	47,596

Rental expense under operating leases was $90,128, $83,064, and $75,696 for the years ended December 31, 2013, 2012 and 2011, respectively.

At December 31, 2013, 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:




2014		2015		2016		2017		2018		Thereafter		Total
$	33,084	$	33,084	$	33,084	$	26,685	$	26,685	$	13,343	$	165,965

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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 $53,484, with no accumulated depreciation at December 31, 2013.

At December 31, 2013, scheduled minimum rental payments for operating leases related to this equipment were as follows:



2014		2015		2016		2017		2018		Thereafter		Total
$	8,561	$	8,561	$	7,637	$	4,496	$	2,992	$	2,328	$	34,575

NOTE 16—PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all salaried employees. The benefits for these plans are based primarily on years of service and employees' pay near retirement. CONSOL Energy's salaried plan allows for lump-sum distributions of benefits earned up until December 31, 2005, at the employees' election. The Restoration Plan was frozen effective December 31, 2006 and was replaced prospectively with the CONSOL Energy Supplemental Retirement Plan. CONSOL Energy's Restoration Plan allows only for lump-sum distributions earned up until December 31, 2006. Effective September 8, 2009, the Supplemental Retirement Plan was amended to include employees of CNX Gas. The Supplemental Retirement Plan was frozen effective December 31, 2011 for certain employees and was replaced prospectively with the CONSOL Energy Defined Contribution Restoration Plan.

Certain subsidiaries of CONSOL Energy provide medical and life insurance benefits to retired employees not covered by the Coal Industry Retiree Health Benefit Act of 1992. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare. For salaried or non-represented hourly employees hired before January 1, 2007, the eligibility requirement is either age 55 with 20 years of service or age 62 with 15 years of service. Also, salaried employees and 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. In 2012, the salaried OPEB plan was amended to reduce medical and prescription drug benefits as of January 1, 2014. The plan amendment calls for a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The amount of the contribution will be 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. Employees who work or worked in corporate or operational support positions at retirement and who are age 50 or older at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug benefits described above upon meeting the eligibility requirements at retirement. Employees who work or worked in corporate or operational support positions who are under age 50 at December 31, 2013 will receive no retiree medical or prescription drug benefits. In addition, any salaried or non-represented hourly employees that were hired or rehired effective January 1, 2007 or later and do not work in a corporate or operational support position are not eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees will receive a retiree medical spending allowance of $2,250 per year for each year of service at retirement.

On March 31, 2012, the salaried OPEB plan was remeasured to reflect the announced plan amendment, which is described above. The remeasurement reflected the reduction in benefits and the change in discount rate to 4.57% at March 31, 2012 from 4.51% at December 31, 2011. The remeasurement resulted in an $80,571 reduction in the OPEB liability with a corresponding adjustment of $50,276 in other comprehensive income, net of $30,295 in deferred taxes. The change resulted in a $9,425 reduction in OPEB expense compared to what was originally expected to be recognized for the year ended December 31, 2012.

The OPEB liability includes $3,000 and $12,400 as of December 31, 2013 and 2012, respectively, due to the PPACA reform legislation; in particular, the estimated impact of the potential excise tax beginning in 2018. The estimated liability for the excise tax was calculated using the following assumptions: testing pre-Medicare and Medicare covered retirees on a combined basis; assuming individual participants have an average claim cost and future healthcare trend assumptions equal to those used in the year-end valuation; assuming the 2018 tax threshold amount to increase for inflation in later years. These assumptions may change once additional guidance becomes available. The 2013 and 2012 OPEB liability also includes the estimated impact of PPACA legislation regarding the fees to support the Transitional Reinsurance Program. Due to the fact that the state-based exchanges are expected to incur losses during their first few years of existence, the legislation provides for a temporary fee on health insurance issuers and self-insured group health plans that will be used to support these exchanges. The fee is payable for plan years 2014 through 2016. The fee for 2014 is $63 per covered pre-Medicare person, and is estimated to drop to $42 and $26 per covered pre-65 person in 2015 and 2016, respectively.

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According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (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 exceeded this threshold during the year ended December 31, 2013. Accordingly, CONSOL Energy recognized expense of $39,482 for the year ended December 31, 2013 in Costs of Goods Sold and Other Operating Charges in the Consolidated Statement 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 2013.

On December 5, 2013, CONSOL Energy completed the sale of its Consolidation Coal Company and certain other subsidiaries to Murray Energy Corporation. As a result of the 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 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.

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The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2013 and 2012, is as follows:



	Pension Benefits						Other Postretirement Benefits
	at December 31,						at December 31,
	2013			2012			2013			2012
Change in benefit obligation:
Benefit obligation at beginning of period	$	953,102		$	857,352		$	3,018,172		$	3,242,200
Service cost	20,865			20,466			18,680			18,817
Interest cost	36,829			37,586			111,687			135,695
Actuarial loss (gain)	(82,718		)	90,502			(73,632		)	(131,150		)
Plan amendments	—			—			—			(80,570		)
Plan curtailments	(6,551		)	—			—			—
Plan settlements	(86,925		)	—			(1,891,057		)	—
Participant contributions	—			—			6,150			5,651
Benefits and other payments	(21,958		)	(52,804		)	(168,026		)	(172,471		)
Benefit obligation at end of period	$	812,644		$	953,102		$	1,021,974		$	3,018,172

Change in plan assets:
Fair value of plan assets at beginning of period	$	728,161		$	582,571		$	—		$	—
Actual return on plan assets	94,084			87,935			—			—
Company contributions	55,469			110,459			161,876			166,820
Participant contributions	—			—			6,150			5,651
Benefits and other payments	(21,958		)	(52,804		)	(168,026		)	(172,471		)
Plan Settlements	(86,925		)	—			—			—
Fair value of plan assets at end of period	$	768,831		$	728,161		$	—		$	—

Funded status:
Noncurrent assets	$	9,032		$	—		$	—		$	—
Current liabilities	(4,593		)	(6,937		)	(60,847		)	(58,452		)
Noncurrent liabilities	(48,252		)	(218,004		)	(961,127		)	(882,600		)
Liabilities of discontinued operations	—			—			—			(2,077,120		)
Net obligation recognized	$	(43,813	)	$	(224,941	)	$	(1,021,974	)	$	(3,018,172	)

Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial loss	$	286,637		$	495,511		$	433,073		$	1,116,051
Prior service credit	(4,629		)	(6,614		)	(34,086		)	(104,288		)
Net amount recognized (before tax effect)	$	282,008		$	488,897		$	398,987		$	1,011,763

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The components of net periodic benefit costs are as follows:



	Pension Benefits									Other Postretirement Benefits
	For the Years Ended December 31,									For the Years Ended December 31,
	2013			2012			2011			2013			2012			2011
Components of net periodic benefit cost:
Service cost	$	20,865		$	20,466		$	17,457		$	18,680		$	18,817		$	13,677
Interest cost	36,829			37,586			37,744			111,687			135,695			179,739
Expected return on plan assets	(51,814		)	(46,157		)	(38,522		)	—			—			—
Amortization of prior service (credits)	(1,611		)	(1,630		)	(666		)	(30,552		)	(51,828		)	(46,397		)
Recognized net actuarial loss	37,853			47,834			38,102			66,417			80,875			105,364
Curtailment gain	(374		)	—			—			(39,650		)	—			—
Settlement loss (gain)	39,482			—			—			(1,348,129		)	—			—
Net periodic benefit cost (credit)	$	81,230		$	58,099		$	54,115		$	(1,221,547	)	$	183,559		$	252,383

Expenses (income) attributable to discontinued operations included in the net periodic cost (credit) above (including settlements and curtailments associated with the sale of CCC and certain subsidiaries to Murray Energy) were $8,231, $11,587, and $10,693 for the years ended December 31, 2013, 2012, and 2011, respectively, for the Pension Plans and were $(1,293,975), $101,418, and $140,524 for the years ended December 31, 2013, 2012, and 2011, respectively, for the Other Postretirement Benefits Plan.

Amounts included in accumulated other comprehensive loss, expected to be recognized in 2014 net periodic benefit costs:



				Other
	Pension			Postretirement
	Benefits			Benefits
Prior Service (credit) recognition	$	(1,384	)	$	(8,784	)
Actuarial loss recognition	$	23,564		$	25,474

The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan assets:



	As of December 31,
	2013		2012
Projected benefit obligation	$	52,845	$	953,102
Accumulated benefit obligation	$	50,820	$	895,493
Fair value of plan assets	$	—	$	728,161

Assumptions:

The weighted-average assumptions used to determine benefit obligations are as follows:



	Pension Benefits				Other Postretirement Benefits
	For the Year Ended				For the Year Ended
	December 31,				December 31,
	2013		2012		2013		2012
Discount rate	4.87	%	4.00	%	4.88	%	4.05	%
Rate of compensation increase	4.23	%	3.77	%	—		—

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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:



	Pension Benefits at						Other Postretirement Benefits at
	December 31,						December 31,
	2013		2012		2011		2013		2012		2011
Discount rate	4.00	%	4.50	%	5.30	%	4.05	%	4.51	%	5.33	%
Expected long-term return on plan assets	7.75	%	8.00	%	8.00	%	—		—		—
Rate of compensation increase	3.77	%	3.82	%	3.66	%	—		—		—

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:



	At December 31,
	2013		2012		2011
Health care cost trend rate for next year	6.17	%	6.30	%	6.85	%
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	$	17,296	$	(14,297	)
Effect on accumulated postretirement benefit obligation	$	123,355	$	(103,788	)

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:



	0.25 Percentage			0.25 Percentage
	Point Increase			Point Decrease
Pension benefit costs (decrease) increase	$	(1,797	)	$	1,798
Other postemployment benefits costs (decrease) increase	$	(3,690	)	$	3,830

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,

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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, 2013 and 2012 by asset category are as follows:



	Fair Value Measurements at December 31, 2013								Fair Value Measurements at December 31, 2012
			Quoted								Quoted
			Prices in								Prices in
			Active								Active
			Markets for		Significant		Significant				Markets for		Significant		Significant
			Identical		Observable		Unobservable				Identical		Observable		Unobservable
			Assets		Inputs		Inputs				Assets		Inputs		Inputs
	Total		(Level 1)		(Level 2)		(Level 3)		Total		(Level 1)		(Level 2)		(Level 3)
Asset Category
Cash/Accrued Income	$	634	$	634	$	—	$	—	$	610	$	610	$	—	$	—
US Equities (a)	14		14		—		—		11		11		—		—
Mercer Collective Trusts
US Large Cap Growth Equity (b)	56,006		—		56,006		—		63,726		—		63,726		—
US Large Cap Value Equity (c)	56,802		—		56,802		—		64,381		—		64,381		—
US Small/Mid Cap Growth Equity (d)	28,530		—		28,530		—		26,406		—		26,406		—
US Small/Mid Cap Value Equity (e)	28,552		—		28,552		—		26,411		—		26,411		—
US Core Fixed Income (f)	35,533		—		35,533		—		38,045		—		38,045		—
Non-US Core Equity (g)	126,712		—		126,712		—		146,009		—		146,009		—
Emerging Markets Equity (h)	29,778		—		29,778		—		33,541		—		33,541		—
Global Low Volatility Equity (i)	70,138		—		70,138		—		—		—		—		—
US Long Duration Investment Grade Fixed Income (j)	55,593		—		55,593		—		39,925		—		39,925		—
US Long Duration Fixed Income (k)	33,489		—		33,489		—		30,675		—		30,675		—
US Large Cap Passive Equity (l)	75,468		—		75,468		—		81,067		—		81,067		—
US Passive Fixed Income (m)	20,287		—		20,287		—		20,415		—		20,415		—
US Long Duration Passive Fixed Income (n)	34,108		—		34,108		—		29,483		—		29,483		—
US Ultra Long Duration Fixed Income (o)	7,656		—		7,656		—		34,595		—		34,595		—
US Active Long Corporate Investment (p)	105,412		—		105,412		—		92,861		—		92,861		—
Long Strips Fixed Income (q)	2,022		—		2,022		—		—		—		—		—
Opportunistic Fixed Income (r)	2,097		—		2,097		—		—		—		—		—
Total	$	768,831	$	648	$	768,183	$	—	$	728,161	$	621	$	727,540	$	—

__________


(a)	This category includes investments in US common stocks and corporate debt.

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(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 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 11 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.

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(n)	This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 11 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 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 US 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, 2013 or 2012.

There are no assets in the other postretirement benefit plans at December 31, 2013 or 2012.

Cash Flows:

CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Currently, depending on asset values and asset returns held in the trust, we expect to contribute $25,000 - $35,000 to our pension plan trust in 2014. Pension benefit payments are primarily funded from the trust. CONSOL Energy does not expect to contribute to the other postemployment plan in 2014. We intend 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
2014	$	90,347	$	60,847
2015	$	50,080	$	62,914
2016	$	48,952	$	65,493
2017	$	49,415	$	67,623
2018	$	50,741	$	68,395
Year 2019-2023	$	262,986	$	338,544

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. The calculation is based on assumptions regarding disability incidence, medical costs, indemnity levels, mortality, death benefits, dependents and interest rates. These assumptions are derived from actual company experience and outside sources. Actuarial gains associated with CWP have resulted from numerous legislative changes over many years which have resulted in lower approval rates for filed claims than our assumptions originally reflected. Actuarial gains have also resulted from lower incident rates and lower severity of claims filed than our assumptions originally reflected.

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CONSOL Energy is also responsible to 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. The assumptions include discount rate, future healthcare trend rate, benefit duration and recurrence of injuries. Actuarial gains associated with workers' compensation have resulted from discount rate changes, several years of favorable claims experience, various favorable state legislation changes and overall lower incident rates than our assumptions.

On December 5, 2013, CONSOL Energy completed the sale of its Consolidation Coal Company and certain other subsidiaries to Murray Energy Corporation. As a result of the sale, the obligations for certain participants of the CWP and Workers' Compensation plans now belong to Murray Energy. This reduced CONSOL Energy's CWP and Workers' Compensation liabilities by $49,652 and $105,308 respectively at December 31, 2013. These plan settlements resulted in adjustments of $43,892 and $13,768 in Other Comprehensive Income, net of $26,337 and $8,262 in deferred taxes for CWP and Workers' Compensation, respectively, at December 31, 2013. The settlements were included in the results of discontinued operations.



	CWP						Workers' Compensation
	at December 31,						at December 31,
	2013			2012			2013			2012
Change in benefit obligation:
Benefit obligation at beginning of period	$	184,079		$	183,580		$	179,589		$	174,069
State administrative fees and insurance bond premiums	—			—			5,324			6,727
Service, legal and administrative cost	8,168			7,711			15,943			17,126
Interest cost	7,031			7,964			6,401			7,113
Actuarial (gain) loss	(18,020		)	(3,919		)	11,806			6,754
Benefits paid	(10,423		)	(11,257		)	(28,659		)	(32,200		)
Settlements	(49,652		)	—			(105,308		)	—
Benefit obligation at end of period	$	121,183		$	184,079		$	85,096		$	179,589

Current liabilities	$	(9,212	)	$	(8,838	)	$	(13,628	)	$	(9,176	)
Noncurrent liabilities	(111,971		)	(114,136		)	(71,468		)	(60,396		)
Liabilities of discontinued operations	—			(61,105		)	—			(110,017		)
Net obligation recognized	$	(121,183	)	$	(184,079	)	$	(85,096	)	$	(179,589	)

Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial gain	$	(80,363	)	$	(148,955	)	$	(13,569	)	$	(44,535	)
Net amount recognized (before tax effect)	$	(80,363	)	$	(148,955	)	$	(13,569	)	$	(44,535	)

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The components of the net periodic cost (credit) are as follows:



	CWP									Workers’ Compensation
	For the Years Ended									For the Years Ended
	December 31,									December 31,
	2013			2012			2011			2013			2012			2011
Service cost	$	8,168		$	7,711		$	7,620		$	15,943		$	17,126		$	20,015
Interest cost	7,031			7,964			9,330			6,401			7,113			8,238
Amortization of prior service cost	—			(395		)	(728		)	—			—			—
Recognized net actuarial gain	(16,384		)	(19,338		)	(21,182		)	(2,630		)	(3,944		)	(3,907		)
State administrative fees and insurance bond premiums	—			—			—			5,324			6,727			7,035
Settlement gain	(119,881		)	—			—			(121,838		)	—			—
Net periodic cost (credit)	$	(121,066	)	$	(4,058	)	$	(4,960	)	$	(96,800	)	$	27,022		$	31,381

(Income) expenses attributable to discontinued operations included in the net periodic cost (credit) (including settlements and curtailments associated with the sale of CCC and certain subsidiaries to Murray Energy) above were $(120,496), $(2,374), and $(2,887) for the years ended December 31, 2013, 2012, and 2011, respectively, for CWP and $(113,097), $10,132, and $12,722 for the years ended December 31, 2013, 2012, and 2011, respectively, for Workers' Compensation.

Amounts included in accumulated other comprehensive income, expected to be recognized in 2014 net periodic benefit costs:



				Workers'
	CWP			Compensation
	Benefits			Benefits
Prior Service benefit recognition	$	—		$	—
Actuarial gain recognition	$	(6,196	)	$	(382	)

Assumptions:

The weighted-average discount rates used to determine benefit obligations and net periodic (benefit) cost are as follows:



	CWP						Workers' Compensation
	For the Years Ended						For the Years Ended
	December 31,						December 31,
	2013		2012		2011		2013		2012		2011
Benefit obligations	4.75	%	4.03	%	4.46	%	4.57	%	3.95	%	4.40	%
Net periodic (benefit) cost	4.03	%	4.46	%	5.21	%	3.95	%	4.40	%	5.13	%

Assumed discount rates have a significant effect on the amounts reported for both CWP benefits and Workers' Compensation costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:



	0.25 Percentage			0.25 Percentage
	Point Increase			Point Decrease
CWP benefit increase (decrease)	$	585		$	(530	)
Workers' Compensation costs (decrease) increase	$	(379	)	$	398

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Cash Flows:

CONSOL Energy does not intend to make contributions to the CWP or Workers' Compensation plans in 2014. We intend 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
2014	$	9,211	$	18,635	$	13,628	$	5,007
2015	$	9,204	$	18,479	$	13,347	$	5,132
2016	$	9,185	$	18,602	$	13,341	$	5,261
2017	$	9,163	$	18,815	$	13,423	$	5,392
2018	$	9,156	$	19,000	$	13,473	$	5,527
Year 2019-2023	$	45,090	$	99,249	$	69,471	$	29,778

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 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 who actually 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. Total contributions under the Act were $11,435, $12,358, and $13,609 for the years ended December 31, 2013, 2012 and 2011, respectively. Based on available information at December 31, 2013, CONSOL Energy's obligation for the Act is estimated to be approximately $120,394.

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 2006 Act and the 1992 Benefit Plan, the outstanding letters of credit to secure our obligation were $60,741, $63,614, and $67,349 for years ended December 31, 2013, 2012 and 2011, respectively. The 2013, 2012 and 2011 security amounts were based on the annual cost of providing health care benefits and included a reduction in the number of eligible employees.

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. Effective January 1, 2006, the company matching contribution was 6% of eligible compensation contributed for all non-represented employees except for those employees of Fairmont Supply Company, whose contribution remains a match of 50% of the first 12% of eligible compensation contributed by the employee. Total payments and costs were $23,748, $24,127, and $23,394 for the years ended December 31, 2013, 2012 and 2011, respectively.

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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.



	For the Years Ended
	December 31,
	2013			2012			2011
Benefit (Credit) Cost	$	(687	)	$	6,122		$	6,439
Discount rate assumption used to determine net periodic benefit costs	3.04		%	3.62		%	4.04		%

Expenses attributable to discontinued operations included in the net periodic cost (credit) above were $2,073, $1,816, and $2,048 for the years ended December 31, 2013, 2012, and 2011.

Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities–Other and Other Accrued Liabilities and amounted to $20,425 and $24,144 at December 31, 2013 and 2012, respectively. On December 5, 2013, CONSOL Energy completed the sale of its Consolidation Coal Company and certain other subsidiaries to Murray Energy Corporation. As a result of the sale, the obligations for certain participants of the Long-Term Disability plan now belong to Murray Energy. This reduced CONSOL Energy's Long-Term Disability liability by $10,140 at December 31, 2013. These plan settlements resulted in adjustments of $1,338 in Other Comprehensive Income, net of $803 in deferred taxes 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, and were paid in 2013.

NOTE 19—STOCK-BASED COMPENSATION:

CONSOL Energy adopted the CONSOL Energy Inc. Equity Incentive Plan on April 7, 1999. The plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments to the plan have been approved by the Board of Directors since the commencement of the plan. In 2012, the Board of Directors approved an increase in the total number of shares by 8,000,000 bringing the total number of shares of common stock that can be covered by grants to 31,800,000. At December 31, 2013, 6,072,413 shares are available for all awards. The Plan provides that the aggregate number of shares available for issuance under the Plan will be reduced by one share for each share issued in settlement of stock options. The Plan, as amended on May 1, 2012, provides the aggregate number of shares available for issuance under the Plan will be reduced 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 plan after the tenth anniversary of the effective date of the award.

CONSOL Energy recognizes stock-based compensation costs for only those shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the option vesting term, or to an employee's eligible retirement date, if earlier and applicable. The total stock-based compensation expense recognized was $56,987, $41,127 and $42,131 for the years ended December 31, 2013, 2012 and 2011, respectively. The related deferred tax benefit totaled $21,769, $15,464 and $15,841, for the years ended December 31, 2013, 2012 and 2011, respectively.

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. CONSOL Energy uses the Black-Scholes option pricing model to value the options for each of the employee populations. The table below presents the weighted average expected term in years of the two employee populations. The expected term computation is based upon historical exercise patterns and post-vesting termination behavior of the 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. There were no options granted in 2013. Total fair value of options granted during the years ended December 31, 2012 and 2011 were $8,515 and $9,913, respectively. The fair value of share-based payment awards was estimated using the Black-Scholes option pricing model with the following assumptions and weighted average fair values:

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	December 31,
	2012			2011
Weighted average fair value of grants	$	14.58		$	20.47
Risk-free interest rate	0.73		%	1.61		%
Expected dividend yield	1.18		%	0.82		%
Expected forfeiture rate	2.00		%	2.00		%
Expected volatility	54.80		%	55.10		%
Expected term in years	4.40			4.26

A summary of the status of stock options granted is presented below:



					Weighted
					Average
			Weighted		Remaining	Aggregate
			Average		Contractual	Intrinsic
			Exercise		Term (in	Value (in
	Shares		Price		years)	thousands)
Balance at December 31, 2012	5,111,214		$	36.54
Granted	—		$	—
Exercised	(310,376	)	$	11.99
Forfeited	(23,612	)	$	38.64
Balance at December 31, 2013	4,777,226		$	38.12	4.20	$	28,398
Vested and expected to vest	4,765,963		$	38.13	4.19	$	28,398
Exercisable at December 31, 2013	4,344,749		$	38.45	3.76	$	28,839

These stock options will expire ten years after the date on which they were granted. The employee stock options, covered by the Equity Incentive Plan adopted April 7, 1999, vest 25% per year, beginning one year after the grant date for awards granted prior to 2007. Employee stock options awarded after December 31, 2006, vest 33% per year, beginning one year after the grant date. There are 4,529,216 stock options outstanding under the Equity Incentive Plan. Additionally, there are 192,934 fully vested employee stock options outstanding which vested under terms ranging from six months to one year. Non-employee director stock options vest 33% per year, beginning one year after the grant date. There are 53,895 stock options outstanding under these grants. The vesting of all options, including performance options, will accelerate in the event of death, disability or retirement and may accelerate upon a change in control of CONSOL Energy.

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, 2013, 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, 2013. This amount varies based on the fair market value of CONSOL Energy's stock. Total intrinsic value of options exercised for the year ended December 31, 2013, 2012 and 2011 was $6,820, $18,562 and $18,049, respectively.

Cash received from option exercises for the years ended December 31, 2013, 2012 and 2011 was $3,720, $8,383 and $9,033, respectively. The tax impact from option exercises totaled $2,929, $8,678, and $8,281, for the years ended December 31, 2013, 2012 and 2011, respectively. This excess tax benefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.

Under the Equity Incentive Plan, CONSOL Energy granted certain employees and non-employee directors restricted stock unit awards. These awards entitle the holder to receive shares of common stock as the award vests. Compensation expense is recognized over the vesting period of the units. The total fair value of the restricted stock units granted during the years ended December 31, 2013, 2012 and 2011 was $20,687, $26,426 and $24,882, respectively. The total fair value of shares vested during the years ended December 31, 2013, 2012 and 2011 was $37,002, $23,097 and $16,496, respectively. The following represents the unvested restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant:

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	Number of		Weighted Average
	Shares		Grant Date Fair Value
Nonvested at December 31, 2012	1,326,953		$40.39
Granted	654,656		$31.60
Vested	(930,390	)	$39.77
Forfeited	(169,649	)	$32.93
Nonvested at December 31, 2013	881,570		$35.95

Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance share unit awards. These awards entitle the holder to receive 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, 2013, 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, 2013, 2012 and 2011 was $1,270, $16,794 and $11,648, respectively. The following represents the unvested performance share unit awards and their corresponding fair value (based upon the closing share price) at the date of grant:



	Number of		Weighted Average
	Shares		Grant Date Fair Value
Nonvested at December 31, 2012	702,194		$50.76
Granted	40,514		$31.35
Vested	(159,228	)	$68.45
Nonvested at December 31, 2013	583,480		$38.19

Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance stock options. These awards entitle the holder to receive shares of common stock subject to the achievement of certain performance goals. Compensation expense is recognized over the vesting period of the units. The annual performance goals for the performance stock options include a gas cost goal and a gas production goal. Achievement of the gas production goal for the year ended December 31, 2012 did not occur. A reversal of compensation expense of $1,671 was recognized in Cost of Goods Sold and Other Operating Charges for the year ended December 31, 2012. The achievement of all goals is believed to be probable at December 31, 2013. The total fair value of performance share options vested during the year ended December 31, 2013, 2012, 2011 was $1,650, $6,599, $3,299. The following represents the unvested performance options and their corresponding fair value (based upon the closing share price) at the date of grant:



	Number of		Weighted Average
	Shares		Grant Date Fair Value
Nonvested at December 31, 2012	401,392		$16.44
Vested	(100,349	)	$16.44
Nonvested at December 31, 2013	301,063		$16.44

Under the Equity Incentive Plan, CONSOL Energy granted certain employees CONSOL Stock Unit Awards. These awards entitle the holder to receive 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, 2013, the achievement of the market and performance goals is believed to be probable. The total fair value of CONSOL Stock Units granted during the year ended December 31, 2013 was $28,381. The following represents the unvested CONSOL Stock Unit awards and their corresponding fair value (based upon the closing share price) at the date of the grant:

147



	Number of		Weighted Average
	Shares		Grant Date Fair Value
Nonvested at December 31, 2012	—		—
Granted	842,167		$33.70
Forfeited	(8,614	)	$33.39
Nonvested at December 31, 2013	833,553		$33.70

As of December 31, 2013, $20,508 of total unrecognized compensation cost related to all unvested stock-based awards is expected to be recognized over a weighted-average period of 1.79 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.

NOTE 20—SUPPLEMENTAL CASH FLOW INFORMATION:

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, 2013, 2012 and 2011, CONSOL Energy entered into non-cash capital lease arrangements of $4,178, $3,583, and $4,649, respectively.

As of December 31, 2013, 2012 and 2011, CONSOL Energy purchased goods and services related to capital projects in the amount of $175,371, $63,051 and $61,690, 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 during the year for:



	For the Years Ended December 31,
	2013		2012		2011
Interest (Net of Amounts Capitalized)	$	209,580	$	212,364	$	242,587
Income Taxes	$	35,079	$	121,245	$	144,405

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.

Concentration of credit risk is summarized below:



	December 31,
	2013		2012
Thermal coal utilities	$	154,738	$	247,955
Steel and coke producers	10,963		47,203
Coal brokers and distributors	52,233		65,057
Gas wholesalers	71,441		51,718
Various other	43,199		16,395
Total Accounts Receivable Trade (including Accounts Receivable—Securitized)	$	332,574	$	428,328

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.

For the year ended December 31, 2013, Xcoal Energy Resources and Duke Energy Carolinas each comprised over 10% of our revenues from continuing operations. Coal sales to Xcoal Energy Resources were $495,242 and coal sales to Duke Energy

148

Carolinas were $346,424 during 2013. For the year ended December 31, 2012 and 2011, coal sales to Xcoal Energy Resources comprised over 10% of our revenues from continuing operations. Coal sales to Xcoal Energy Resources were $382,843 and $655,596 for the year ended December 31, 2012 and 2011, respectively.

NOTE 22—FAIR VALUE OF FINANCIAL INSTRUMENTS:

The financial instruments measured at fair value on a recurring basis are summarized below:



	Fair Value Measurements at December 31, 2013						Fair Value Measurements at December 31, 2012
Description	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges (Note 23)	$	—	$	65,449	$	—	$	—	$	128,945	$	—

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.

Restricted cash: The carrying amounts reported in the balance sheets for restricted cash, both current and long-term approximates its fair value.

Short-term notes payable: The carrying amount reported in the balance sheets for short-term notes payable approximates its fair value due to the short-term maturity of these instruments.

Borrowings under Securitization Facility: The carrying amount reported in the balance sheets for borrowings under the securitization facility 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:



	December 31, 2013						December 31, 2012
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	327,420		$	327,420		$	21,862		$	21,862
Restricted cash (a)	$	—		$	—		$	68,673		$	68,673
Short-term notes payable	$	—		$	—		$	(25,073	)	$	(25,073	)
Borrowings under securitization facility	$	—		$	—		$	(37,846	)	$	(37,846	)
Long-term debt	$	(3,118,920	)	$	(3,299,875	)	$	(3,127,726	)	$	(3,376,767	)

(a) The 2012 restricted cash balance includes $48,294 and $20,379 located in current assets and other assets of the Consolidated Balance Sheet, respectively

NOTE 23—DERIVATIVE INSTRUMENTS:

CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. The fair value of CONSOL Energy's derivatives (natural gas price swaps) are based on intra-bank pricing models which utilize inputs that are either readily available in the public market, such as natural gas forward curves, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by our counterparties for reasonableness. Changes in the fair value of the derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item

149

are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in the fair value of the derivatives are reported in Other Comprehensive Income or Loss (OCI) on the Consolidated Balance Sheets and reclassified into Outside Sales on the Consolidated Statements of Income in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current period. CONSOL Energy currently utilizes only cash flow hedges that are considered highly effective.

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

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

None of our counterparty master agreements currently require CONSOL Energy to post collateral for any of its hedges. However, as stated in the counterparty master agreements, if CONSOL Energy's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CONSOL Energy would have to post collateral for hedges in a liabilities position in excess of defined thresholds. All of our derivative instruments are subject to master netting arrangements with our counterparties. CONSOL Energy recognizes all financial derivative instruments as either assets or liabilities at fair value on the Consolidated Balance Sheets on a gross basis.

Each of CONSOL Energy's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CONSOL Energy and the applicable counterparty would net settle all open hedge positions.

CONSOL Energy has entered into swap contracts for natural gas to manage the price risk associated with the forecasted natural gas revenues. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted sales from the underlying commodity. As of December 31, 2013, the total notional amount of the Company’s outstanding natural gas swap contracts was 279.3 billion cubic feet. These swap contracts are forecasted to settle through December 31, 2016 and meet the criteria for cash flow hedge accounting. As these contracts settle, the cash received and/or paid will be shown on the Consolidated Statements of Cash Flows as Changes in Prepaid Expenses, Changes in Other Assets, Changes in Other Operating Liabilities and/or Changes in Other Liabilities. Assuming no changes in price during the next twelve months, $30,333 of unrealized gain is expected to be reclassified from Other Comprehensive Income on the Consolidated Balance Sheets and into Outside Sales on the Consolidated Statements of Income, as a result of the gross settlement of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

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

The gross fair value at December 31, 2012 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $135,969 and a liability of $7,024. The total asset is comprised of $80,057 and $55,912 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $970 and $6,054 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

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

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	Year Ended December 31,
	2013			2012		2011
Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	$	76,761		$	151,780	$	46,087
Gain recognized in Accumulated OCI	$	45,631		$	114,240	$	200,700
Less: Gain reclassified from Accumulated OCI into Outside Sales	$	79,899		$	189,259	$	95,007
Ending Balance – Accumulated OCI	$	42,493		$	76,761	$	151,780
Gain recognized in Outside Sales for ineffectiveness	$	(4,645	)	$	579	$	1,034

There were no amounts recognized in earnings related to the amount excluded from the assessment of hedge effectiveness in 2013, 2012 or 2011.

NOTE 24—COMMITMENTS AND CONTINGENGENT 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 $318,786.

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

Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 6,900 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Texas and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Based on over 15 years of experience with this litigation, we have established an accrual to cover our estimated liability for these cases. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheet. Past payments by Fairmont with respect to asbestos cases have not been material.

Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia styled Hale v. CNX Gas Company, et. al. The lawsuit alleges that the plaintiff class consists of forced-pooled unleased gas owners whose gas ownership is in conflict, the Virginia Supreme Court and General Assembly have decided that coalbed methane (CBM) belongs to the owner of the gas estate, the Virginia Gas and Oil Act of 1990 unconstitutionally provides only a 1/8 net proceeds royalty to CBM owners for gas produced under the forced-pooled orders, and CNX Gas Company relied upon control of only the coal estate in force pooling the CBM notwithstanding decisions by the Virginia Supreme Court. The lawsuit seeks a judicial declaration of ownership of the CBM and that the entire net proceeds of CBM production (that is, the 1/8 royalty and the 7/8 of net revenues since production began) be distributed to the class members. The lawsuit also alleges 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. The Magistrate Judge issued a Report and Recommendation in which she recommended that the District Judge decide that the deemed lease provision of the Gas and Oil Act is constitutional as is the 1/8 royalty. The Magistrate Judge recommended against the dismissal of certain other claims. The District Judge affirmed the Magistrate Judge's recommendations in their entirety. An amended complaint was filed, which added additional allegations that include gas hedging receipts should have been used as the basis for royalty payments, severance tax should not be allowed as a post-

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production deduction from royalties, and damages incurred because gas was produced prior to the entry of pooling orders. A motion to dismiss the Amended Complaint was filed and denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for Class Certification. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013. The District Judge heard argument on the Objections on September 12, 2013, and on September 30, 2013, entered an Order overruling the Objections, adopting the Report & Recommendation and certifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a class action and filed a Petition asking the U.S. Court of Appeals for the Fourth Circuit to review the class certification Order. On November 13, 2013, the Fourth Circuit entered an Order deferring a ruling on the Petition; assigning the case to a merits panel; and, requesting full briefing of the class certification challenge. At the same time, Plaintiffs have filed Motions for Summary Judgment on the issue of “ownership” of the gas royalty escrow accounts and seeking an accounting. The Fourth Circuit denied a Motion to Stay the trial court proceedings while it considers the class certification issues, and the District Judge held argument on the summary judgment motions for January 6, 2014. CONSOL Energy believes that the case has meritorious defenses and intends to defend it vigorously. We have established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in the United States District Court in Abingdon, Virginia styled Addison v. CNX Gas Company, et al. The lawsuit alleges that the plaintiff class consists of gas lessors whose gas ownership is in conflict. The lawsuit alleges that the Virginia Supreme Court and General Assembly have decided that the plaintiff owns the gas and is entitled to royalties held in escrow by the Commonwealth of Virginia or CNX Gas Company. The lawsuit also alleges 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. Plaintiff seeks a declaratory judgment regarding ownership, an accounting and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking) for improperly asserting that conflicting ownership exists, negligence (breach of duties as an operator); breach of fiduciary duties; and unjust enrichment. The Magistrate Judge issued a Report and Recommendation recommending dismissing some claims and allowing others to proceed. The District Judge affirmed the Magistrate Judge's recommendations in their entirety. An Amended Complaint was filed which added an additional allegation that gas hedging receipts should have been used as the basis for royalty payments. A motion to dismiss those claims was filed and was denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for Class Certification. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013. The District Judge heard argument on the Objections on September 12, 2013, and on September 30, 2013, entered an Order overruling the Objections, adopting the Report & Recommendation and certifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a class action and filed a Petition asking the U.S. Court of Appeals for the Fourth Circuit to review the class certification Order. On November 13, 2013, the Fourth Circuit entered an Order deferring a ruling on the Petition; assigning the case to a merits panel; and, requesting full briefing of the class certification challenge. At the same time, Plaintiffs have filed Motions for Summary Judgment on the issue of “ownership” of the gas royalty escrow accounts and seeking an accounting. The Fourth Circuit denied a Motion to Stay the trial court proceedings while it considers the class certification issues, and the District Judge held argument on the summary judgment motions for January 6, 2014. CONSOL Energy believes that the case has meritorious defenses and intends to defend it vigorously. We have established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheet.

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 March 22, 2012, the Company was served with four complaints filed on May 31, 2011 by four individuals against Consolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, subsidiaries of CONSOL Energy, as well as CONSOL Energy itself in the Circuit Court of Russell County, Virginia. The complaints seek damages and injunctive relief in connection with the deposit of water from mining activities at CCC's Buchanan Mine into nearby void spaces at some of the mines of ICCC. The suits allege damage to coal and coalbed methane and seek recovery in tort, contract and assumpsit (quasi-contract). The cases were removed to federal court, motions to dismiss

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were filed by CCC, and then were voluntarily dismissed by the plaintiffs. On January 30, 2013, the four plaintiffs filed a single consolidated complaint against the same defendants in the United States District Court for the Western District of Virginia, alleging the same damage and theories of recovery for storage of water in the mine voids ostensibly underlying their property. The suit seeks damages ranging from $4,000 to $8,000 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. Based on Plaintiffs’ challenge, the Court on August 1, 2013, entered a Certificate pursuant to 28 USC Section 2304 notifying the Virginia Attorney General that the Mine Void Statute had been called into question and advising the Commonwealth of its right to intervene in the proceedings for the limited purpose of addressing the constitutionality of the statute. To date, the Virginia Attorney General has not responded. 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 plaintiffs are seeking to appeal that dismissal. The suit also seeks a determination that the Pittsburgh 8 coal seam does not include the “roof/rider” coal. The court denied the plaintiff's summary judgment motion on that issue. The court held a bench trial on the “roof/rider” coal issue in November 2011 and ruled for CNX Gas Company and CONSOL Energy, holding that the “roof/rider” coal is included in the Pittsburgh 8 coal seam. The plaintiffs have indicated that they intend to appeal that decision. A Motion for Summary Judgment on all remaining counts was argued on January 10, 2014, and remains pending. Should the Motion be denied, a trial on the issue of whether a drilling that deviates from the coal seam results in damage to the gas owner is anticipated for first quarter 2014. CNX Gas Company and CONSOL Energy believe this lawsuit to be without merit and intends to vigorously defend it. Consequently, we have not recognized any liability related to these actions.

Rowland Litigation: Rowland Land Company filed a complaint in May 2011 against CONSOL Energy, CNX Gas Company, Dominion Resources Inc., and EQT Production Company (EQT) in Raleigh County Circuit Court, West Virginia. Rowland is the lessor on a 33,000 acre oil and gas lease in southern West Virginia. EQT was the original lessee, but farmed out the development of the lease to Dominion Resources in exchange for an overriding royalty. Dominion Resources sold the indirect subsidiary that held the lease to a subsidiary of CONSOL Energy on April 30, 2010. Subsequent to that acquisition, the subsidiary that held the lease was merged into CNX Gas Company as part of an internal reorganization. Rowland alleges that (i) Dominion Resources' sale of the subsidiary to CONSOL Energy was a change in control that required its consent under the terms of the farmout agreement and lease, and/or (ii) the subsequent merger of the subsidiary into CNX Gas Company was an assignment that required its consent under the lease. Rowland has recently been permitted to file its Third Amended Complaint to include additional allegations that CONSOL Energy has slandered Rowland's title. A motion to dismiss will be filed. Initial mediation efforts have been unsuccessful. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liability related to these actions.

At December 31, 2013, 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. 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.

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	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	$	190,358	$	164,852	$	25,506	$	—	$	—
Environmental	56,293		23,075		33,218		—		—
Other	114,106		76,460		37,646		—		—
Total Letters of Credit	360,757		264,387		96,370		—		—
Surety Bonds:
Employee-Related	204,884		204,884		—		—		—
Environmental	610,209		610,209		—		—		—
Other	32,492		32,481		10		—		1
Total Surety Bonds	847,585		847,574		10		—		1
Gurantees:
Coal	333,460		200,400		133,060		—		—
Other	70,523		35,611		10,846		9,718		14,348
Total Guarantees	403,983		236,011		143,906		9,718		14,348
Total Commitments	$	1,612,325	$	1,347,972	$	240,286	$	9,718	$	14,349

Included in the above table are commitments and guarantees entered into in conjunction with the sale of Consolidation Coal Company (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), CONSOL Energy has guaranteed certain equipment lease obligations and coal sales agreement that are being 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, such as certain Murray Energy collateral and/or Murray Energy indemnifications. At December 31, 2013, the fair value of these guarantees was $3,000 and are included in Other Accrued Liabilities on the Consolidated Balance Sheet. The fair value of certain of the 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 cried 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 Sheet. As of December 31, 2013, the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	240,870
1 - 3 years	260,218
3 - 5 years	199,144
More than 5 years	583,333
Total Purchase Obligations	$	1,283,565

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Costs related to these purchase obligations include:



	For The Years Ended December 31,
	2013		2012		2011
Gas drilling obligations	$	109,609	$	110,975	$	108,167
Firm transportation expense	126,766		78,475		59,606
Major equipment purchases	12,668		101,367		34,219
Other	—		492		891
Total costs related to purchase obligations	$	249,043	$	291,309	$	202,883

NOTE 25—SEGMENT INFORMATION:

CONSOL Energy has two principal business divisions: Gas and Coal. The principal activity of the Gas division is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The Gas division includes four reportable segments. These reportable segments are Marcellus, Coalbed Methane, Shallow Oil and Gas and Other Gas. The Other Gas segment includes our purchased gas activities, general and administrative activities as well as various other activities assigned to the 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 four reportable segments. These reportable segments are Thermal, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the twelve months ended December 31, 2013, the Thermal aggregated segment includes the following mines: Bailey, Enlow Fork, Fola Complex, and Miller Creek Complex. For the twelve months ended December 31, 2013, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine and Amonate Complex. For the twelve months ended December 31, 2013, the High Volatile Metallurgical aggregated segment includes: Bailey, Enlow Fork, and Fola Complex coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, general and administrative activities as well as various other activities assigned to the Coal division but not allocated to each individual mine. CONSOL Energy’s All Other segment includes industrial supplies, coal terminal operations and various other corporate activities that are not allocated to the gas or coal segment. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at the division level only (coal, gas and other) and are not allocated between each individual segment. This presentation is consistent with the information regularly reviewed by the chief operating decision maker. The assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy where each individual asset may service more than one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.

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Industry segment results for the year ended December 31, 2013 are:



	Marcellus Shale		Coalbed Methane		Shallow Oil and Gas			Other Gas			Total Gas			Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	251,846	$	335,730	$	131,135		$	18,990		$	737,701		$	1,388,005	$	447,417	$	159,888	$	22,757		$	2,018,067	$	259,783		$	—		$	3,015,551	(A)
Sales—purchased gas	—		—		—			6,531			6,531			—		—		—		—			—		—			—			6,531
Sales—gas royalty interests	—		—		—			63,202			63,202			—		—		—		—			—		—			—			63,202
Freight—outside	—		—		—			—			—			—		—		—		35,438			35,438		—			—			35,438
Intersegment transfers	—		—		—			3,167			3,167			—		—		—		—			—		127,553			(130,720		)	—
Total Sales and Freight	$	251,846	$	335,730	$	131,135		$	91,890		$	810,601		$	1,388,005	$	447,417	$	159,888	$	58,195		$	2,053,505	$	387,336		$	(130,720	)	$	3,120,722
Earnings (Loss) Before Income Taxes	$	79,439	$	81,392	$	(17,829	)	$	(144,616	)	$	(1,614	)	$	375,787	$	121,285	$	40,500	$	(201,048	)	$	336,524	$	(47,468	)	$	(241,367	)	$	46,075	(B)
Segment assets											$	6,334,468											$	4,187,285	$	293,486		$	578,428		$	11,393,667	(C)
Depreciation, depletion and amortization											$	229,562											$	218,414	$	13,146		$	—		$	461,122
Capital expenditures											$	968,607											$	458,653	$	68,796		$	—		$	1,496,056


(A)	Included in the Coal segment are sales of $495,242 to Xcoal Energy & Resources and $346,424 to Duke Energy each comprising over 10% of sales.


(B)	Includes equity in earnings of unconsolidated affiliates of $17,346, $14,684 and $1,102 for Coal, Gas and All Other, respectively.


(C)	Includes investments in unconsolidated equity affiliates of $20,512, $206,060 and $65,103 for Coal, Gas and All Other, respectively.

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Industry segment results for the year ended December 31, 2012 are:



	Marcellus Shale		Coalbed Methane		Shallow Oil and Gas			Other Gas			Total Gas		Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	134,080	$	379,595	$	135,412		$	9,733		$	658,820	$	1,430,912	$	505,670	$	210,153	$	22,890		$	2,169,625	$	294,105	$	—		$	3,122,550	(D)
Sales—purchased gas	—		—		—			3,316			3,316		—		—		—		—			—		—		—			3,316
Sales—gas royalty interests	—		—		—			49,405			49,405		—		—		—		—			—		—		—			49,405
Freight—outside	—		—		—			—			—		—		—		—		107,079			107,079		—		—			107,079
Intersegment transfers	—		—		—			1,622			1,622		—		—		—		—			—		142,014		(143,636		)	—
Total Sales and Freight	$	134,080	$	379,595	$	135,412		$	64,076		$	713,163	$	1,430,912	$	505,670	$	210,153	$	129,969		$	2,276,704	$	436,119	$	(143,636	)	$	3,282,350
Earnings (Loss) Before Income Taxes	$	29,546	$	125,970	$	(13,390	)	$	(102,675	)	$	39,451	$	396,748	$	210,133	$	57,163	$	(72,417	)	$	591,627	$	10,997	$	(235,388	)	$	406,687	(E)
Segment assets											$	5,768,882										$	4,104,981	$	363,676	$	2,760,055		$	12,997,594	(F)
Depreciation, depletion and amortization											$	202,956										$	211,831	$	12,328	$	—		$	427,115
Capital expenditures											$	532,636										$	662,888	$	49,973	$	—		$	1,245,497


(D)	Included in the Coal segment are sales of $382,843 to Xcoal Energy & Resources comprising over 10% of sales.


(E)	Includes equity in earnings of unconsolidated affiliates of $17,318, $9,562 and $168 for Coal, Gas and All Other, respectively.


(F)	Includes investments in unconsolidated equity affiliates of $19,517, $143,876 and $59,437 for Coal, Gas and All Other, respectively.

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Industry segment results for the year ended December 31, 2011 are:



	Marcellus Shale		Coalbed Methane		Shallow Oil and Gas			Other Gas			Total Gas		Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	118,973	$	462,677	$	155,444		$	11,370		$	748,464	$	1,495,480	$	1,071,570	$	324,377	$	66,333		$	2,957,760	$	284,783	$	—		$	3,991,007	(G)
Sales—purchased gas	—		—		—			4,344			4,344		—		—		—		—			—		—		—			4,344
Sales—gas royalty interests	—		—		—			66,929			66,929		—		—		—		—			—		—		—			66,929
Freight—outside	—		—		—			—			—		—		—		—		175,633			175,633		—		—			175,633
Intersegment transfers	—		—		—			3,303			3,303		—		—		—		—			—		194,857		(198,160		)	—
Total Sales and Freight	$	118,973	$	462,677	$	155,444		$	85,946		$	823,040	$	1,495,480	$	1,071,570	$	324,377	$	241,966		$	3,133,393	$	479,640	$	(198,160	)	$	4,237,913
Earnings (Loss) Before Income Taxes	$	41,566	$	185,761	$	(14,732	)	$	(82,811	)	$	129,784	$	421,683	$	692,249	$	129,119	$	(210,354	)	$	1,032,697	$	3,408	$	(292,963	)	$	872,926	(H)
Depreciation, depletion and amortization											$	206,821										$	214,285	$	9,471	$	—		$	430,577
Capital expenditures											$	664,612										$	472,591	$	41,172	$	—		$	1,178,375

(G) Included in the Coal segment are sales of $655,596 to Xcoal Energy & Resources comprising over 10% of sales.

(H) Includes equity in earnings of unconsolidated affiliates of $19,629, $4,231 and $803 for Coal, Gas and All Other, respectively.

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Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Income:



	For the Years Ended December 31,
	2013		2012		2011
Total segment sales and freight from external customers	$	3,120,722	$	3,282,350	$	4,237,913
Other income not allocated to segments (Note 4)	178,963		395,176		139,132
Total Consolidated Revenue and Other Income	$	3,299,685	$	3,677,526	$	4,377,045

Earnings Before Income Taxes:



	For the Years Ended December 31,
	2013			2012			2011
Segment Earnings Before Income Taxes for total reportable business segments	$	334,910		$	631,078		$	1,162,481
Segment Earnings Before Income Taxes for all other businesses	(47,468		)	10,997			3,408
Interest income (expense), net and other non-operating activity (I)	(226,199		)	(228,804		)	(258,308		)
Transaction and Financing Fees (I)	—			—			(14,907		)
Evaluation fees for non-core asset dispositions (I)	(15,168		)	(6,584		)	(5,780		)
Loss on debt extinguishment	—			—			(16,090		)
Lease Settlement	—			—			2,122
Earnings Before Income Taxes	$	46,075		$	406,687		$	872,926



Total Assets:	December 31,
Total Assets:	2013		2012
Segment assets for total reportable business segments	$	10,521,753	$	9,873,863
Segment assets for all other businesses	293,486		363,676
Items excluded from segment assets:
Cash and other investments (I)	321,992		19,252
Recoverable income taxes	10,705		—
Deferred tax assets	211,303		84,777
Bond issuance costs	34,428		41,775
Discontinued Operations	—		2,614,251
Total Consolidated Assets	$	11,393,667	$	12,997,594

_________________________

(I) Excludes amounts specifically related to the gas segment.

159

Enterprise-Wide Disclosures:

CONSOL Energy's Revenues by geographical location (J):



	For the Years Ended December 31,
	2013		2012		2011
United States (K)	$	2,999,674	$	2,898,341	$	3,460,871
Europe	83,878		187,313		366,384
South America	29,787		169,591		400,307
Canada	3,575		5,692		10,351
Other	3,808		21,413		—
Total Revenues and Freight from External Customers (K)	$	3,120,722	$	3,282,350	$	4,237,913

_________________________

(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.

CONSOL Energy's Property, Plant and Equipment by geographical location are:



	December 31,
	2013		2012
United States	$	9,431,238	$	8,487,614
Canada	11,024		20,444
Discontinued Operations	—		1,682,909
Total Property, Plant and Equipment, net	$	9,442,262	$	10,190,967

NOTE 26—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $1,500,000, 8.000% per annum senior notes due April 1, 2017, the $1,250,000, 8.250% per annum senior notes due April 1, 2020, and the $250,000, 6.375% per annum senior notes due March 1, 2021 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.

160

Income Statement for the Year Ended December 31, 2013:



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	740,869		$	2,061,652		$	216,419	$	(3,389	)	$	3,015,551
Sales—Gas Royalty Interests	—			63,202			—			—		—			63,202
Sales—Purchased Gas	—			6,531			—			—		—			6,531
Freight—Outside	—			—			35,438			—		—			35,438
Other Income	930,481			57,592			100,757			20,614		(930,481		)	178,963
Total Revenue and Other Income	930,481			868,194			2,197,847			237,033		(933,870		)	3,299,685
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	170,702			493,416			1,313,601			219,450		31,783			2,228,952
Gas Royalty Interests Costs	—			53,069			—			—		(41		)	53,028
Purchased Gas Costs	—			4,837			—			—		—			4,837
Related Party Activity	35,678			—			(112,626		)	1,767		75,181			—
Freight Expense	—			—			35,438			—		—			35,438
Selling, General and Administrative Expenses	—			44,733			44,357			1,318		—			90,408
Depreciation, Depletion and Amortization	12,857			229,562			216,726			1,977		—			461,122
Interest Expense	211,449			8,605			(423		)	47		(480		)	219,198
Taxes Other Than Income	3,669			35,176			118,675			3,107		—			160,627
Total Costs	434,355			869,398			1,615,748			227,666		106,443			3,253,610
Earnings (Loss) Before Income Taxes	496,126			(1,204		)	582,099			9,367		(1,040,313		)	46,075
Income Tax (Benefit) Expense	(164,316		)	1,420			126,164			3,543		—			(33,189		)
Income (Loss) from Continuing Operations	660,442			(2,624		)	455,935			5,824		(1,040,313		)	79,264
Income from Discontinued Operations, net of tax	—			—			—			579,792		—			579,792
Net Income (Loss)	660,442			(2,624		)	455,935			585,616		(1,040,313		)	659,056
Less: Net Loss Attributable to Noncontrolling Interest	—			1,386			—			—		—			1,386
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	660,442		$	(1,238	)	$	455,935		$	585,616	$	(1,040,313	)	$	660,442

161

Balance Sheet for December 31, 2013:



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	320,473		$	6,238		$	—		$	709	$	—		$	327,420
Accounts and Notes Receivable:
Trade	—			71,911			—			260,663		—			332,574
Notes Receivable	1,238			—			24,623			—		—			25,861
Other Receivables	17,657			207,128			14,969			4,219		—			243,973
Inventories	—			15,185			99,320			43,409		—			157,914
Deferred Income Taxes	219,566			(8,263		)	—			—		—			211,303
Recoverable Income Taxes	(16,262		)	26,967			—			—		—			10,705
Prepaid Expenses	43,698			65,701			24,915			1,528		—			135,842
Total Current Assets	586,370			384,867			163,827			310,528		—			1,445,592
Property, Plant and Equipment:
Property, Plant and Equipment	220,355			6,919,972			6,412,378			25,804		—			13,578,509
Less-Accumulated Depreciation, Depletion and Amortization	145,754			1,188,464			2,783,043			18,986		—			4,136,247
Total Property, Plant and Equipment-Net	74,601			5,731,508			3,629,335			6,818		—			9,442,262
Other Assets:
Investment in Affiliates	11,965,054			206,060			70,222			—		(11,949,661		)	291,675
Notes Receivable	125			—			—			—		—			125
Other	145,401			30,728			28,831			9,053		—			214,013
Total Other Assets	12,110,580			236,788			99,053			9,053		(11,949,661		)	505,813
Total Assets	$	12,771,551		$	6,353,163		$	3,892,215		$	326,399	$	(11,949,661	)	$	11,393,667
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	180,261		$	324,226		$	493		$	9,600	$	—		$	514,580
Accounts Payable (Recoverable)—Related Parties	4,563,327			23,287			(5,055,923		)	136,822		332,487			—
Current Portion Long-Term Debt	1,029			6,258			3,372			796		—			11,455
Short-Term Notes Payable	—			332,487			—			—		(332,487		)	—
Other Accrued Liabilities	144,612			89,080			322,606			9,399		—			565,697
Current Liabilities of Discontinued Operations	—			—			—			28,239		—			28,239
Total Current Liabilities	4,889,229			775,338			(4,729,452		)	184,856		—			1,119,971
Long-Term Debt:
Long-Term Debt	3,004,213			—			111,750			—		—			3,115,963
Capital Lease Obligations	1,245			42,852			1,724			1,775		—			47,596
Total Long-Term Debt	3,005,458			42,852			113,474			1,775		—			3,163,559
Deferred Credits and Other Liabilities
Deferred Income Taxes	(232,904		)	475,547			—			—		—			242,643
Postretirement Benefits Other Than Pensions	—			—			961,127			—		—			961,127
Pneumoconiosis Benefits	—			—			111,971			—		—			111,971
Mine Closing	—			—			320,723			—		—			320,723
Gas Well Closing	—			119,429			56,174			—		—			175,603
Workers’ Compensation	—			—			71,136			332		—			71,468
Salary Retirement	48,252			—			—			—		—			48,252
Reclamation	—			—			40,706			—		—			40,706
Other	55,227			61,190			14,938			—		—			131,355
Total Deferred Credits and Other Liabilities	(129,425		)	656,166			1,576,775			332		—			2,103,848
Total CONSOL Energy Inc. Stockholders’ Equity	5,006,289			4,878,807			6,931,418			139,436		(11,949,661		)	5,006,289
Total Liabilities and Equity	$	12,771,551		$	6,353,163		$	3,892,215		$	326,399	$	(11,949,661	)	$	11,393,667

162

Condensed Statement of Cash Flows For the Year Ended December 31, 2013:



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash Provided by (Used in) Continuing Operations	$	51,093		$	440,763		$	572,683		$	(843,456	)	$	332,487		$	553,570
Net Cash Provided by Discontinued Operating Activities	—			—			—			105,206			—			105,206
Net Cash Provided by (Used in) Operating Activities	$	51,093		$	440,763		$	572,683		$	(738,250	)	$	332,487		$	658,776
Cash Flows from Investing Activities:
Capital Expenditures	$	(68,796	)	$	(968,607	)	$	(458,653	)	$	—		$	—		$	(1,496,056	)
Change in Restricted Cash	—			—			68,673			—			—			68,673
Proceeds From Sales of Assets	327,964			350,975			(195,082		)	112			—			483,969
(Investments in), net of Distributions from, Equity Affiliates	—			(47,500		)	11,788			—			—			(35,712		)
Net Cash (Used in) Provided by Continuing Operations	259,168			(665,132		)	(573,274		)	112			—			(979,126		)
Net Cash Provided by Discontinued Investing Activities	—			—			—			777,145			—			777,145
Net Cash (Used in) Provided by Investing Activities	$	259,168		$	(665,132	)	$	(573,274	)	$	777,257		$	—		$	(201,981	)
Cash Flows from Financing Activities:
Dividends (Paid)	$	14,168		$	(100,000	)	$	—		$	—		$	—		$	(85,832	)
Payments on Short-Term Borrowings	—			332,487			—			—			(332,487		)	—
Payments on Miscellaneous Borrowings	(25,952		)	—			(4,800		)	(792		)	—			(31,544		)
Proceeds from Securitization Facility	—			—			—			(37,846		)	—			(37,846		)
Proceeds from Issuance of Common Stock	3,727			—			—			—			—			3,727
Other Financing Activities	778			(5,232		)	5,232			—			—			778
Net Cash (Used in) Provided by Continuing Operations	(7,279		)	227,255			432			(38,638		)	(332,487		)	(150,717		)
Net Cash Used in Discontinued Financing Activities	—			—			—			(520		)	—			(520		)
Net Cash (Used in) Provided by Financing Activities	$	(7,279	)	$	227,255		$	432		$	(39,158	)	$	(332,487	)	$	(151,237	)

163

Income Statement for the Year Ended December 31, 2012:



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	660,442	$	2,221,421		$	243,059	$	(2,372	)	$	3,122,550
Sales—Gas Royalty Interests	—			49,405		—			—		—			49,405
Sales—Purchased Gas	—			3,316		—			—		—			3,316
Freight—Outside	—			—		107,079			—		—			107,079
Other Income	613,340			56,946		316,592			21,639		(613,341		)	395,176
Total Revenue and Other Income	613,340			770,109		2,645,092			264,698		(615,713		)	3,677,526
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	127,372			407,045		1,417,519			239,502		30,421			2,221,859
Gas Royalty Interests Costs	—			38,922		—			—		(55		)	38,867
Purchased Gas Costs	—			2,711		—			—		—			2,711
Related Party Activity	12,865			—		(22,466		)	1,814		7,787			—
Freight Expense	—			—		107,079			—		—			107,079
Selling, General and Administrative Expenses	—			40,101		49,222			1,417		—			90,740
Depreciation, Depletion and Amortization	12,172			202,956		209,923			2,064		—			427,115
Interest Expense	208,894			5,098		6,470			44		(464		)	220,042
Taxes Other Than Income	401			33,892		125,288			2,845		—			162,426
Total Costs	361,704			730,725		1,893,035			247,686		37,689			3,270,839
Earnings (Loss) Before Income Taxes	251,636			39,384		752,057			17,012		(653,402		)	406,687
Income Tax Expense (Benefit)	(136,834		)	15,021		204,105			6,436		—			88,728
Income (Loss) from Continuing Operations	388,470			24,363		547,952			10,576		(653,402		)	317,959
Income from Discontinued Operations, net of tax	—			—		—			70,114		—			70,114
Net Income (Loss)	388,470			24,363		547,952			80,690		(653,402		)	388,073
Less: Net Loss Attributable to Noncontrolling Interest	—			397		—			—		—			397
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	388,470		$	24,760	$	547,952		$	80,690	$	(653,402	)	$	388,470

164

Balance Sheet for December 31, 2012:



	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	17,491	$	3,352		$	159		$	860	$	—		$	21,862
Accounts and Notes Receivable:
Trade	—		58,126			—			370,202		—			428,328
Securitized	—		—			—			37,846		—			37,846
Notes Receivable	154		315,730			2,503			—		—			318,387
Other Receivables	6,335		214,748			33,289			5,159		(128,400		)	131,131
Inventories	—		14,133			121,311			35,364		—			170,808
Deferred Income Taxes	174,176		(26,072		)	(63,327		)	—		—			84,777
Restricted Cash	—		—			48,294			—		—			48,294
Prepaid Expenses	29,589		86,186			31,286			1,370		—			148,431
Current Assets of Discontinued Operations	—		—			—			149,230		—			149,230
Total Current Assets	227,745		666,203			173,515			600,031		(128,400		)	1,539,094
Property, Plant and Equipment:
Property, Plant and Equipment	216,448		5,956,207			5,923,723			25,179		—			12,121,557
Less-Accumulated Depreciation, Depletion and Amortization	126,048		960,613			2,508,769			18,069		—			3,613,499
Property, Plant and Equipment of Discontinued Operations, net	—		—			—			1,682,909		—			1,682,909
Total Property, Plant and Equipment-Net	90,400		4,995,594			3,414,954			1,690,019		—			10,190,967
Other Assets:
Restricted Cash	—		—			20,379			—		—			20,379
Investment in Affiliates	9,917,050		143,876			769,058			—		(10,607,154		)	222,830
Notes Receivable	239		—			25,738			—		—			25,977
Other	118,938		65,935			21,174			10,188		—			216,235
Other Assets of Discontinued Operations	—		—			—			782,112		—			782,112
Total Other Assets	10,036,227		209,811			836,349			792,300		(10,607,154		)	1,267,533
Total Assets	$	10,354,372	$	5,871,608		$	4,424,818		$	3,082,350	$	(10,735,554	)	$	12,997,594

165

Balance Sheet for December 31, 2012 (Continued):



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	177,734		$	166,182		$	145,469		$	9,130	$	—		$	498,515
Accounts Payable (Recoverable)-Related Parties	3,599,216			23,981			(3,749,584		)	254,787		(128,400		)	—
Short-Term Notes Payable	25,073			—			—			—		—			25,073
Current Portion of Long-Term Debt	1,554			5,953			4,221			756		—			12,484
Accrued Income Taxes	20,488			13,731			—			—		—			34,219
Borrowings under Securitization Facility	—			—			—			37,846		—			37,846
Other Accrued Liabilities	135,407			57,074			343,739			9,528		—			545,748
Current Liabilities of Discontinued Operations	—			—			—			233,214		—			233,214
Total Current Liabilities	3,959,472			266,921			(3,256,155		)	545,261		(128,400		)	1,387,099
Long-Term Debt:
Long-Term Debt	3,004,798			—			118,802			—		—			3,123,600
Capital Lease Obligations	717			46,081			1,148			1,467		—			49,413
Long-Term Debt of Discontinued Operations	—			—			—			1,573		—			1,573
Total Long-Term Debt	3,005,515			46,081			119,950			3,040		—			3,174,586
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(884,310		)	439,725			771,270			—		—			326,685
Postretirement Benefits Other Than Pensions	—			—			882,600			—		—			882,600
Pneumoconiosis Benefits	—			—			114,136			—		—			114,136
Mine Closing	—			—			289,818			—		—			289,818
Gas Well Closing	—			80,097			65,905			—		—			146,002
Workers’ Compensation	—			—			60,090			306		—			60,396
Salary Retirement	218,004			—			—			—		—			218,004
Reclamation	—			—			47,965			—		—			47,965
Other	101,899			24,518			(8,110		)	—		—			118,307
Deferred Credits and Other Liabilities of Discontinued Operations	—			—			—			2,278,251		—			2,278,251
Total Deferred Credits and Other Liabilities	(564,407		)	544,340			2,223,674			2,278,557		—			4,482,164
Total CONSOL Energy Inc. Stockholders’ Equity	3,953,792			5,014,313			5,337,349			255,492		(10,607,154		)	3,953,792
Noncontrolling Interest	—			(47		)	—			—		—			(47		)
Total Liabilities and Equity	$	10,354,372		$	5,871,608		$	4,424,818		$	3,082,350	$	(10,735,554	)	$	12,997,594

166

Condensed Statement of Cash Flows For the Year Ended December 31, 2012:



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash Provided by (Used in) Continuing Operations	$	(58,410	)	$	82,036		$	412,293		$	21,423		$	—		$	457,342
Net Cash Provided by Discontinued Operating Activities	—			—			—			270,771			—			270,771
Net Cash Provided by (Used in) Operating Activities	$	(58,410	)	$	82,036		$	412,293		$	292,194		$	—		$	728,113
Cash Flows from Investing Activities:
Capital Expenditures	$	(49,973	)	$	(532,636	)	$	(662,888	)	$	—		$	—		$	(1,245,497	)
Change in Restricted Cash	—			—			(48,294		)	—			—			(48,294		)
Proceeds From Sales of Assets	—			360,129			285,238			254			—			645,621
(Investments in), net of Distributions from, Equity Affiliates	200,000			(37,400		)	13,949			—			(200,000		)	(23,451		)
Net Cash (Used in) Provided by Continuning Operations	$	150,027		$	(209,907	)	$	(411,995	)	$	254		$	(200,000	)	$	(671,621	)
Net Cash Used in Discontinued Investing Activities	—			—			—			(328,789		)	—			(328,789		)
Net Cash (Used in) Provided by Investing Activities	$	150,027		$	(209,907	)	$	(411,995	)	$	(328,535	)	$	(200,000	)	$	(1,000,410	)
Cash Flows from Financing Activities:
Dividends (Paid)	$	(142,278	)	$	(200,000	)	$	—		$	—		$	200,000		$	(142,278	)
Proceeds from Issuance of Common Stock	8,278			—			—			—			—			8,278
Other Financing Activities	22,532			(5,504		)	(1,408		)	37,404			—			53,024
Net Cash (Used in) Provided by Continuing Operations	$	(111,468	)	$	(205,504	)	$	(1,408	)	$	37,404		$	200,000		$	(80,976	)
Net Cash Used in Discontinued Financing Activities	—			—			—			(601		)	—			(601		)
Net Cash (Used in) Provided by Financing Activities	$	(111,468	)	$	(205,504	)	$	(1,408	)	$	36,803		$	200,000		$	(81,577	)

167

Income Statement for the Year Ended December 31, 2011:



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Sales—Outside	$	—		$	751,767	$	3,009,104		$	234,998		$	(4,862	)	$	3,991,007
Sales—Gas Royalty Interests	—			66,929		—			—			—			66,929
Sales—Purchased Gas	$	—		$	4,344	$	—		$	—		$	—		$	4,344
Freight—Outside	—			—		175,633			—			—			175,633
Other Income	876,233			58,923		48,673			26,309			(871,006		)	139,132
Total Revenue and Other Income	876,233			881,963		3,233,410			261,307			(875,868		)	4,377,045
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion, and amortization shown below)	108,681			388,507		1,443,472			228,291			97,609			2,266,560
Gas Royalty Interests Costs	—			59,377		—			—			(46		)	59,331
Purchased Gas Costs	—			3,831		—			—			—			3,831
Related Party Activity	4,767			—		(25,720		)	1,986			18,967			—
Freight Expense	—			—		175,444			—			—			175,444
Selling, General and Administrative Expenses	—			50,429		62,729			1,485			—			114,643
Depreciation, Depletion and Amortization	12,194			206,821		209,159			2,403			—			430,577
Interest Expense	235,370			9,398		3,911			53			(388		)	248,344
Taxes Other Than Income	950			34,023		136,382			3,037			—			174,392
Transaction and Financing Fees	14,907			—		—			—			—			14,907
Loss on Debt Extinguishment	16,090			—		—			—			—			16,090
Total Costs	392,959			752,386		2,005,377			237,255			116,142			3,504,119
Earnings (Loss) Before Income Taxes	483,274			129,577		1,228,033			24,052			(992,010		)	872,926
Income Tax Expense (Benefit)	(149,223		)	51,876		279,500			9,098			—			191,251
Income (Loss) from Continuing Operations	632,497			77,701		948,533			14,954			(992,010		)	681,675
Loss from Discontinued Operations, net of tax	—			—		—			(49,178		)	—			(49,178		)
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	632,497		$	77,701	$	948,533		$	(34,224	)	$	(992,010	)	$	632,497

168

Condensed Statement of Cash Flows For the Year Ended December 31, 2011:



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash Provided by (Used in) Continuing Operations	$	530,444		$	329,360		$	465,847		$	3,220		$	—	$	1,328,871
Net Cash Provided by Discontinued Operating Activities	$	—		$	—		$	—		$	198,735		$	—	198,735
Net Cash Provided by (Used in) Operating Activities	$	530,444		$	329,360		$	465,847		$	201,955		$	—	$	1,527,606
Cash Flows from Investing Activities:
Capital Expenditures	$	(41,172	)	$	(664,612	)	$	(472,591	)	$	—		$	—	$	(1,178,375	)
Proceeds From Sales of Assets	10			746,956			(1,155		)	1,474			—		747,285
Distributions from, net of Investments in, Equity Affiliates	—			50,626			5,250			—			—		55,876
Net Cash (Used in) Provided by Continuing Operations	$	(41,162	)	$	132,970		$	(468,496	)	$	1,474		$	—	$	(375,214	)
Net Cash Used in Discontinued Investing Activities	—			—			—			(203,310		)	—		(203,310		)
Net Cash (Used in) Provided by Investing Activities	$	(41,162	)	$	132,970		$	(468,496	)	$	(201,836	)	$	—	$	(578,524	)
Cash Flows from Financing Activities:
Dividends Paid	$	(96,356	)	$	—		$	—		$	—		$	—	$	(96,356	)
Payments on Short-Term Borrowings	(155,000		)	(129,000		)	—			—			—		(284,000		)
Payments on Securitization Facility	(200,000		)	—			—			—			—		(200,000		)
Proceeds from Long-Term Notes	250,000			—			—			—			—		250,000
Payments on Long Term Notes, including Redemption Premium	(265,785		)	—			—			—			—		(265,785		)
Other Financing Activities	5,749			(13,162		)	(1,246		)	(793		)	—		(9,452		)
Net Cash Used in Continuing Operations	$	(461,392	)	$	(142,162	)	$	(1,246	)	$	(793	)	$	—	$	(605,593	)
Net Cash Used in Discontinued Financing Activities	—			—			—			(547		)	—		(547		)
Net Cash Used in Financing Activities	$	(461,392	)	$	(142,162	)	$	(1,246	)	$	(1,340	)	$	—	$	(606,140	)

Statement of Comprehensive Income for the Year Ended December 31, 2013:



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net Income (Loss)	$	660,442		$	(2,624	)	$	455,935	$	585,616	$	(1,040,313	)	$	659,056
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	456,493			—			456,493		—		(456,493		)	456,493
Net Increase (Decrease) in the Value of Cash Flow Hedge	45,631			45,631			—		—		(45,631		)	45,631
Reclassification of Cash Flow Hedge from OCI to Earnings	(79,899		)	(79,899		)	—		—		79,899			(79,899		)
Other Comprehensive Income (Loss):	$	422,225		$	(34,268	)	$	456,493	$	—	$	(422,225	)	$	422,225
Comprehensive Income (Loss)	1,082,667			(36,892		)	912,428		585,616		(1,462,538		)	1,081,281
Less: Comprehensive Loss Attributable to Noncontrolling Interest	—			1,386			—		—		—			1,386
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	1,082,667		$	(35,506	)	$	912,428	$	585,616	$	(1,462,538	)	$	1,082,667

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Statement of Comprehensive Income for the Year Ended December 31, 2012:



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non-Guarantors		Elimination			Consolidated
Net Income (Loss)	$	388,470		$	24,363		$	547,952	$	80,690	$	(653,402	)	$	388,073
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	129,231			—			129,231		—		(129,231		)	129,231
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: Comprehensive Income Attributable to Noncontrolling Interest	—			397			—		—		—			397
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	442,682		$	(50,259	)	$	677,183	$	80,690	$	(707,614	)	$	442,682

Statement of Comprehensive Income for the Year Ended December 31, 2011:



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Income (Loss)	$	632,497		$	77,701		$	948,533		$	(34,224	)	$	(992,010	)	$	632,497
Other Comprehensive Income (Loss):
Treasury Rate Lock	(96		)	—			—			—			—			(96		)
Actuarially Determined Long-Term Liability Adjustments	(32,813		)	—			(32,813		)	—			32,813			(32,813		)
Net Increase (Decrease) in the Value of Cash Flow Hedge	200,700			200,700			—			—			(200,700		)	200,700
Reclassification of Cash Flow Hedge from OCI to Earnings	(95,007		)	(95,007		)	—			—			95,007			(95,007		)
Other Comprehensive Income (Loss):	$	72,784		$	105,693		$	(32,813	)	$	—		$	(72,880	)	$	72,784
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	705,281		$	183,394		$	915,720		$	(34,224	)	$	(1,064,890	)	$	705,281

NOTE 27—RELATED PARTY TRANSACTIONS

CONE Gathering LLC Related Party Transactions

During the years ended December 31, 2013, 2012 and 2011, CONE Gathering LLC (CONE) a 50% owned affiliate, provided CNX Gas Company LLC (CNX Gas Company) gathering services in the ordinary course of business. Gathering services received from CONE were $34,062, $20,408 and $4,267 in the years ended December 31, 2013, 2012 and 2011 respectively, which were included in Cost of Goods Sold on the Consolidated Statements of Income.

As of December 31, 2013 and 2012, CONSOL Energy and CNX Gas had a net payable of $5,448 and $3,142, respectively, due to CONE which is comprised of the following items:

170



	December 31,			December 31,
	2013			2012			Location on Balance Sheet
Reimbursement for CONE Expenses	$	(2,168	)	$	(1,336	)	Accounts Receivable–Other
Reimbursement for Services Provided to CONE	(265		)	(341		)	Accounts Receivable–Other
CONE Gathering Capital Reimbursement	—			(18		)	Accounts Receivable–Other
CONE Gathering Fee Payable	7,881			4,837			Accounts Payable
Net Payable due CONE	$	5,448		$	3,142

Supplemental Gas Data (unaudited):

The following information was prepared in accordance with the Financial Accounting Standards Board's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).”

Capitalized Costs:



	As of December 31,
	2013			2012
Proven properties	$	1,670,404		$	1,596,838
Unproven properties	1,463,406			1,266,017
Intangible drilling costs	1,937,336			1,550,297
Wells and related equipment	688,548			492,364
Gathering assets	1,058,008			1,006,882
Gas Well Plugging	113,481			70,753
Total Property, Plant and Equipment	6,931,183			5,983,151
Accumulated Depreciation, Depletion and Amortization	(1,187,409		)	(959,291		)
Net Capitalized Costs	$	5,743,774		$	5,023,860

Costs incurred for property acquisition, exploration and development (*):



	For the Years Ended December 31,
	2013		2012		2011
Property acquisitions
Proven properties	$	—	$	50,005	$	6,673
Unproven properties	260,477		28,634		58,731
Development	629,100		339,608		463,401
Exploration	95,413		130,312		131,419
Total	$	984,990	$	548,559	$	660,224

__________


(*)	Includes costs incurred whether capitalized or expensed.

171

Results of Operations for Producing Activities:



	For the Years Ended December 31,
	2013		2012		2011
Production Revenue	$	740,869	$	660,442	$	751,767
Royalty Interest Gas Revenue	63,202		49,405		66,929
Purchased Gas Revenue	6,531		3,316		4,344
Total Revenue	810,602		713,163		823,040
Lifting Costs	96,600		90,835		106,477
Ad Valorem, Severance & Other Taxes	28,677		26,145		26,261
Gathering Costs	201,023		160,575		142,339
Royalty Interest Gas Costs	53,069		38,922		59,377
Direct Administrative, Selling & Other Costs	49,092		47,567		60,355
Other Costs	61,119		39,029		18,095
Purchased Gas Costs	4,837		2,711		3,831
DD&A	229,562		202,956		206,821
Total Costs	723,979		608,740		623,556
Pre-tax Operating Income	86,623		104,423		199,484
Income Taxes	32,917		39,827		79,873
Results of Operations for Producing Activities excluding Corporate and Interest Costs	$	53,706	$	64,596	$	119,611

The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:



	For the Years Ended December 31,
	2013		2012		2011
Production (MMcfe)	172,380		156,325		153,504
Average gas sales price before effects of financial settlements (per Mcf)	$	3.85	$	3.00	$	4.27
Average effects of financial settlements (per Mcf)	$	0.45	$	1.22	$	0.63
Average gas sales price including effects of financial settlements (per Mcf)	$	4.30	$	4.22	$	4.90
Average lifting costs, excluding ad valorem and severance taxes (per Mcf)	$	0.56	$	0.58	$	0.68

During the years ended December 31, 2013, 2012 and 2011, we drilled 139.8, 95.5, and 254.9 net development wells, respectively. There were no net dry development wells in 2013, 2012, or 2011.

During the years ended December 31, 2013, 2012 and 2011, we drilled 5.5, 22.0, and 69.5 net exploratory wells, respectively. There were zero net dry exploratory wells in 2013, seven net dry exploratory wells in 2012 and two net dry exploratory wells in 2011.

At December 31, 2013, there were 31.0 net development wells in the process of being drilled.

At December 31, 2013, there were 1.0 net exploratory wells in the process of being drilled.

CONSOL Energy is committed to provide 60.3 bcf of gas under existing sales contracts or agreements over the course of the next four years. CONSOL Energy expects 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

172

or other term commitments are satisfied. The following table sets forth, at December 31, 2013, the number of producing wells, developed acreage and undeveloped acreage:



	Gross	Net(1)
Producing Wells (including gob wells)	15,063	12,874
Proved Developed Acreage	542,388	527,693
Proved Undeveloped Acreage	105,019	59,346
Unproved Acreage	5,396,659	4,212,030
Total Acreage	6,044,066	4,799,069

____________


(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 our 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 2013 gas reserves results, which are reported in the Supplemental Gas Data year ended December 31, 2013 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:

173



					Condensate		Consolidated
	Natural Gas		NGLs		& Crude Oil		Operations
	(MMcfe)		(Mbbls)		(Mbbls)		(MMcfe)
Balance December 31, 2010	3,724,361		—		1,206		3,731,597
Revisions (a)	(76,486	)	25		416		(73,837	)
Price Changes	(9,976	)	—		—		(9,976	)
Extensions and Discoveries (c)	517,023		—		27		517,178
Production	(152,940	)	—		(94	)	(153,504	)
Sales of Reserves In-Place	(531,431	)	—		—		(531,431	)
Balance December 31, 2011 (d)	3,470,551		25		1,555		3,480,027
Revisions (b)	243,442		469		(710	)	241,989
Price Changes	(526,608	)	—		(1	)	(526,611	)
Extensions and Discoveries (c)	873,104		12,992		553		954,378
Production	(155,052	)	(111	)	(100	)	(156,325	)
Sales of Reserves In-Place	—		—		—		—
Balance December 31, 2012 (d)	3,905,437		13,375		1,297		3,993,458
Revisions (b)	176,045		(1,017	)	336		171,953
Price Changes	104,728		4		1		104,757
Extensions and Discoveries (c)	1,567,634		9,623		1,343		1,633,426
Production	(168,737	)	(438	)	(170	)	(172,380	)
Sales of Reserves In-Place	—		—		—		—
Balance December 31, 2013 (d)	5,585,107		21,547		2,807		5,731,214

Proved developed reserves:
December 31, 2011	2,126,330		—		1,579		2,135,805
December 31, 2012	2,149,912		1,717		878		2,165,483
December 31, 2013	2,470,412		5,939		1,375		2,514,294

Proved undeveloped reserves:
December 31, 2011	1,344,222		—		—		1,344,222
December 31, 2012	1,755,525		12,075		—		1,827,975
December 31, 2013	3,114,695		15,607		1,431		3,216,920

__________


(a)	Revisions are primarily due corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas and reservoirs. These changes were partially offset by upward revisions attributable to efficiencies in operations and well performance and had the total affect of a negative revision for 2011.


(b)	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 and had the total affect of the positive revisions for 2013 and 2012.


(c)	Extensions and Discoveries are primarily due to the addition of wells on our Marcellus Shale acreage more than one offset location away with reliable technology.

(d)

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.

174



	For the Year
	Ended
	December 31,
	2013
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves	1,827,975
Undeveloped reserves transferred to developed(a)	(230,333	)
Price Changes	11,410
Plan and other revisions (b)	88,187
Extension and discoveries (c)	1,519,681
Ending proved undeveloped reserves(d)	3,216,920

_________


(a)	During 2013, various exploration and development drilling and evaluations were completed. Approximately, $202,066 of capital was spent in the year ended December 31, 2013 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)

Extensions and discoveries include approximately 683 Bcfe which were initially classified as unproved related to the DTI and Airport lease acquisitions. These reserves were subsequently reclassified to proved undeveloped reserves utilizing reliable technologies which include wire line open hole log data, performance data, log cross sections, core data, and statistical analysis. The statistical method utilized production performance from Consol Energy's and competitors' wells. Geophysical data include data from Consol's wells, published documents, state data-sites and were used to confirm continuity of the formation.

(d)

Included in proved undeveloped reserves at December 31, 2013 are approximately 226,063 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.

The following table represents the capitalized exploratory well cost activity as indicated:



	December 31,
	2013
Costs pending the determination of proved reserves at December 31, 2013
For a period one year or less	$	17,728
For a period greater than one year but less than five years	—
For a period greater than five years	—
Total	$	17,728



	December 31,
	2013		2012		2011
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves	$	12,140	$	14,447	$	189
Costs expensed due to determination of dry hole or abandonment of project	$	8,596	$	3,320	$	5,108

CONSOL Energy's proved gas reserves are located in the United States.

175

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, 2013. 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 a 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.



	December 31,
	2013			2012			2011
Future Cash Flows:
Revenues	$	21,602,594		$	11,777,550		$	14,804,398
Production costs	(7,105,962		)	(4,823,670		)	(5,262,635		)
Development costs	(3,902,875		)	(2,450,589		)	(1,674,829		)
Income tax expense	(4,025,626		)	(1,711,251		)	(2,989,435		)
Future Net Cash Flows	6,568,131			2,792,040			4,877,499
Discounted to present value at a 10% annual rate	(4,887,320		)	(2,055,834		)	(3,130,318		)
Total standardized measure of discounted net cash flows	$	1,680,811		$	736,206		$	1,747,181

The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:



	December 31,
	2013			2012			2011
Balance at beginning of period	$	736,206		$	1,747,181		$	1,660,821
Net changes in sales prices and production costs	1,295,956			(1,480,573		)	(339,098		)
Sales net of production costs	(365,477		)	(104,518		)	(217,186		)
Net change due to revisions in quantity estimates	132,900			(104,158		)	(83,580		)
Net change due to extensions, discoveries and improved recovery	383,308			14,645			324,755
Net change due to (divestiture) acquisition	—			—			(559,132		)
Development costs incurred during the period	625,824			333,640			463,401
Difference in previously estimated development costs compared to actual costs incurred during the period	(123,976		)	(96,749		)	154,137
Changes in estimated future development costs	(486,518		)	(153,104		)	155,619
Net change in future income taxes	(578,951		)	619,045			130,746
Accretion of discount and other	61,539			(39,203		)	56,698
Total discounted cash flow at end of period	$	1,680,811		$	736,206		$	1,747,181

176

Supplemental Coal Data (unaudited)



	Millions of Tons
	For the Year Ended December 31,
	2013		2012		2011		2010		2009
Proved and probable reserves at beginning of period	4,229		4,314		4,229		4,350		4,372
Purchased reserves	1		—		6		4		5
Reserves sold in place	(1,199	)	(155	)	—		(41	)	(3	)
Production	(55	)	(55	)	(62	)	(62	)	(58	)
Revisions and other changes	56		125		141		(22	)	34
Consolidated proved and probable reserves at end of period*	3,032		4,229		4,314		4,229		4,350

Proportionate share of proved and probable reserves of unconsolidated equity affiliates*	57		41		145		172		170

______________

* 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. Proved and probable reserves of unconsolidated equity affiliates are included in this number.

CONSOL Energy's coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2013, 382 million tons were assigned to mines either in production, temporarily idle, or under development. The proved and probable reserves at December 31, 2013 include 2,511 million tons of steam 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), 18 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu and an additional 77 percent has a sulfur content equivalent to greater than 2.5 pounds sulfur dioxide per million Btu. The reserves also include 521 million tons of metallurgical coal in consolidated reserves, of which approximately 49 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu and an additional 51 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. A significant portion of this metallurgical coal can also serve the steam coal market.

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Supplemental Quarterly Information (unaudited):

(Dollars in thousands, except per share data)



	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
	2013			2013			2013			2013
Sales	$	799,997		$	759,948		$	753,080		$	772,258
Freight Revenue	$	14,061		$	10,125		$	11,563		$	3,946
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests' Costs and Purchased Gas Costs)	$	612,000		$	552,126		$	560,247		$	562,386
Freight Expense	$	14,061		$	10,125		$	11,563		$	3,946
(Loss) Income from Continuing Operations	$	(3,725	)	$	8,562		$	(72,169	)	$	146,595
Income (Loss) from Discontinued Operations	$	1,904		$	(21,375	)	$	8,120		$	591,144
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		$	2.58
Net (Loss) Income	$	(0.01	)	$	(0.05	)	$	(0.28	)	$	3.22
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		$	2.56
Net (Loss) Income	$	(0.01	)	$	(0.05	)	$	(0.28	)	$	3.20



	Three Months Ended
	March 31,		June 30,			September 30,			December 31,
	2012		2012			2012			2012
Sales	$	878,118	$	807,198		$	681,717		$	808,238
Freight Revenue	$	49,293	$	49,472		$	27,430		$	13,426
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests' Costs and Purchased Gas Costs)	$	601,723	$	565,601		$	543,158		$	557,094
Freight Expense	$	49,293	$	49,472		$	27,430		$	13,426
Income (Loss) from Continuing Operations	$	80,906	$	155,789		$	(26,316	)	$	107,580
Income (Loss) from Discontinued Operations	$	16,290	$	(3,050	)	$	14,814		$	42,060
Net Income (Loss) Attributable to CONSOL Energy Inc Shareholders	$	97,196	$	152,739		$	(11,368	)	$	149,903
Earnings Per Share
Basic:
Income (Loss) from Continuing Operations	$	0.36	$	0.68		$	(0.12	)	$	0.47
Income (Loss) from Discontinued Operations	$	0.07	$	(0.01	)	$	0.07		$	0.19
Net Income (Loss)	$	0.43	$	0.67		$	(0.05	)	$	0.66
Dilutive:
Income (Loss) from Continuing Operations	$	0.35	$	0.68		$	(0.12	)	$	0.47
Income (Loss) from Discontinued Operations	$	0.07	$	(0.01	)	$	0.07		$	0.18
Net Income (Loss)	$	0.42	$	0.67		$	(0.05	)	$	0.65

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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, 2013 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, 2013. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (1992 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, 2013.

The effectiveness of CONSOL Energy's internal control over financial reporting as of December 31, 2013 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.

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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, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 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.

In our opinion, CONSOL Energy Inc. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, 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, 2013 and 2012, 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, 2013 of CONSOL Energy Inc. and Subsidiaries and our report dated February 7, 2014 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 7, 2014

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ITEM 9B.	OTHER INFORMATION

CONSOL Energy Inc. adopted a recoupment policy that generally provides the Compensation Committee of the Company’s Board of Directors with the discretion to seek recovery of performance-based cash and equity incentive compensation (the “Awards”) paid to an executive officer in the three years prior to a financial restatement if such executive officer engaged in intentional or unlawful misconduct which materially contributed to the need for such restatement and such Award(s) would have been lower if calculated based on such restated results (the “Clawback Policy”). The Clawback Policy will apply to Awards granted in January 2014 and thereafter.

PART III


ITEM 10.	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-BOARD OF DIRECTORS AND ITS COMMITTEES-Corporate Governance Web Page and Available Documents,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-BOARD OF DIRECTORS AND ITS COMMITTEES–Audit Committee,” "BOARD OF DIRECTORS AND COMPENSATION INFORMATION - BOARD OF DIRECTORS AND ITS COMMITTEES - Membership and Meetings of the Board of Directors and its Committees," and “SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the Proxy Statement for the annual meeting of shareholders to be held on May 7, 2014 (the “Proxy Statement”).

Executive Officers of CONSOL Energy

The following is a list of CONSOL Energy executive officers, their ages as of February 1, 2014 and their positions and offices held with CONSOL Energy.



Name	Age	Position
J. Brett Harvey	63	Chairman of the Board and Chief Executive Officer
Nicholas J. DeIuliis	45	President
Stephen W. Johnson	55	Executive Vice President - Chief Legal and Corporate Affairs Officer
David M. Khani	50	Executive Vice President and Chief Financial Officer
James C. Grech	52	Executive Vice President and Chief Commercial Officer

J. Brett Harvey has been Chief Executive Officer and a Director of CONSOL Energy since January 1998. He was elected Chairman of the Board of CONSOL Energy on June 29, 2010. Mr. Harvey was the President of CONSOL Energy from January 1998 until February 23, 2011. He has been a Director of CNX Gas Corporation since June 30, 2005 and he became Chairman of the Board and Chief Executive Officer of CNX Gas Corporation on January 16, 2009. Mr. Harvey is a Director of Barrick Gold Corporation, the world's largest gold producer, and Allegheny Technologies Incorporated, a specialty metals producer.

Nicholas J. DeIuliis has been President of CONSOL Energy since February 23, 2011. He was Executive Vice President and Chief Operating Officer of CONSOL Energy from January 16, 2009 until February 23, 2011. Prior to that time, Mr. DeIuliis served as Senior Vice President - Strategic Planning of CONSOL Energy from November 2004 until August 2005, Vice President Strategic Planning from April 2002 until November 2004, Director-Corporate Strategy from October 2001 until April 2002, Manager-Strategic Planning from January 2001 until October 2001 and Supervisor-Process Engineering from April 1999 until January 2001. He resigned from his position with CONSOL Energy as of August 8, 2005. He was a Director and President and Chief Executive Officer of CNX Gas Corporation from June 30, 2005 to January 16, 2009, when he became President and Chief Operating Officer of CNX Gas Corporation, a position which he continues to hold.

Stephen W. Johnson became Executive Vice President and Chief Legal and Corporate Affairs Officer of CONSOL Energy and CNX Gas Corporation on January 1, 2013. 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, Senior Vice President from December 5, 2005 through September 13, 2007 and Executive Vice President from September 13, 2007.

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

181

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.

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, on August 15, 2005.

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.

By certification dated May 31, 2013, 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-DIRECTOR COMPENSATION TABLE-2013,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-UNDERSTANDING OUR DIRECTOR COMPENSATION TABLE,” and “EXECUTIVE COMPENSATION INFORMATION” 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.


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-Related Party Policy and Procedures” and “PROPOSAL NO. 1-ELECTION OF DIRECTORS-Determination of Director Independence” 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.

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PART IV


ITEM 15.	EXHIBIT INDEX

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.
2.10		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.
2.20		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.
2.30		Asset Acquisition Agreement dated August 17, 2011 between CNX Gas Company LLC and Noble Energy, Inc., incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on August 18, 2011.
2.40		Joint Development Agreement by and among CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011, incorporated by reference to Exhibit 2.2 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2011, filed on October 31, 2011.
2.50		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.
3.10		Restated Certificate of Incorporation of CONSOL Energy Inc., incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on May 8, 2006.
3.20		Amended and Restated Bylaws of CONSOL Energy Inc., dated as of February 23, 2011, incorporated by reference to Exhibit 3.2 to Form 8-K (file no. 001-14901) filed on March 1, 2011.
4.10		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.
4.20		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.
4.30		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.
4.40		Supplemental Indenture No. 3, dated as of August 24, 2011, to Indenture dated as of April 1, 2010 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on August 29, 2011.

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4.50		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.
4.60		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.
4.70		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.
4.80		Supplemental Indenture No. 3, dated as of August 24, 2011, to Indenture dated as of April 1, 2010 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.250% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on August 29, 2011.
4.90		Indenture, dated as of March 9, 2011, among CONSOL Energy Inc., the Subsidiaries named therein and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 6.375% Senior Notes due 2021, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on March 11, 2011.
4.10		Supplemental Indenture No. 1, dated as of August 24, 2011, to Indenture dated as of March 9, 2011 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 6.375% Senior Notes due 2021, incorporated by reference to Exhibit 4.3 to Form 8-K (file no. 001-14901) filed on August 29, 2011.
4.11		Rights Agreement, dated as of December 22, 2003, between CONSOL Energy Inc., and Equiserve Trust Company, N.A., as Rights Agent, incorporated by reference to Exhibit 4 to Form 8-K (file no. 001-14901) filed on December 22, 2003.
4.12		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.
4.13		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.
4.14		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.
4.15		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.
4.16		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.
4.17		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.

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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.
10.5		Services Agreement, dated as of April 1, 2010, by and among CONSOL Energy Inc. and its subsidiaries (other than CNX Gas Corporation and its subsidiaries) and (b) CNX Gas Corporation and its subsidiaries, incorporated by reference to Exhibit 99(D)(11) of the Schedule TO filed on April 28, 2010.
10.6		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.
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.

185



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		Letter Agreement re: Receivables Purchase Agreement - Dilution Ratio, dated June 21, 2012, incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2012 (file no. 001-14901), filed on August 1, 2012.
10.15		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.
10.16		Share Tender Agreement, dated as of March 21, 2010, by and between CONSOL Energy Inc., and T. Rowe Price Associates, Inc., incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 22, 2010 (Film No. 10695706).
10.17		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.
10.18		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.
10.19		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.
10.20		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.
10.21		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.
10.22		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.
10.23		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.

186



10.24		Guaranty and Suretyship Agreement, dated as of April 30, 2003, by CONSOL Energy Inc., as guarantor in favor of CNX Funding Corporation, incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2011, filed on May 3, 2011.
10.25		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.
10.26		CNX Gas Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, by CNX Gas Corporation and certain of its subsidiaries, incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.27		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.
10.28		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.
10.29		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.
10.30		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.
10.31		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.
10.32		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.
10.33		CONSOL Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, by CONSOL Energy and certain of its subsidiaries, incorporated by reference to Exhibit 10.4 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.34		Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, among CNX Gas Company LLC and certain of its subsidiaries, incorporated by reference to Exhibit 10.5 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.35		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.
10.36		Closing Agreement by and between CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011, incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2011, filed on October 31, 2011.
10.37		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.
10.38		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.

187



10.39		Amendment No. 1, dated April 19, 2013, to the Asset Acquisition Agreement, dated August 17, 2011, between CNX Gas Company LLC and Noble Energy, Inc, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2013, filed on August 5, 2013.
10.40		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.
10.41		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.
10.42		Employment Agreement, dated December 2, 2008, between CONSOL Energy Inc. and J. Brett Harvey incorporated by reference to Exhibit 10.14 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
10.43		Time Sharing Agreement, dated as of May 1, 2007, by and between CONSOL Energy Inc. and J. Brett Harvey, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 7, 2007.
10.44		Consulting Agreement dated, as July 1, 2010, by and between CONSOL Energy Inc., and John Whitmire, incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2010, filed on November 1, 2010.
10.45		Letter Agreement, dated August 24, 2007, by and between CONSOL Energy Inc. and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on August 24, 2007.
10.46		Offer Letter, dated February 14, 2005, between CONSOL Energy Inc. and P. Jerome Richey, incorporated by reference to Exhibit 10.58 to Form 8-K (file no. 001-14901), filed on March 4, 2005.
10.47		Executive Officer Term Sheet with P. Jerome Richey incorporated by reference to Exhibit 10.12 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
10.48		Change in Control Agreement by and between CONSOL Energy Inc. and J. Brett Harvey, incorporated by reference to Exhibit 10.3 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
10.49		Change in Control Agreement by and between CONSOL Energy Inc. and William J. Lyons, incorporated by reference to Exhibit 10.4 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
10.50		Change in Control Agreement by and between CONSOL Energy Inc. and P. Jerome Richey, incorporated by reference to Exhibit 10.6 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
10.51		Change in Control Agreement by and between CONSOL Energy Inc. and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.7 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
10.52		Change in Control Agreement by and among CNX Gas Corporation, CONSOL Energy Inc. and Robert Pusateri, incorporated by reference to Exhibit 10.8 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
10.53		Change in Control Severance Agreement, dated as of December 2, 2008 and amended as of February 23, 2010, between CONSOL Energy Inc. and Robert Pusateri, incorporated by reference to Exhibit 10.9 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2010, filed on May 4, 2010.
10.54		Form of Indemnification Agreement for Directors and Executive Officers of CONSOL Energy Inc., incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.
10.55		Form of Indemnification Agreement for Directors and Executive Officers of CNX Gas Corporation, incorporated by reference to Exhibit 10.7 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.
10.56		Equity Incentive Plan, As Amended and Restated, effective May 1, 2012 incorporated by reference to Exhibit 10.1 to the Form 8-K (file no. 001-14901) filed on March 21, 2012.
10.57		Long-Term Incentive Program (2010 - 2012), incorporated by reference to Exhibit 10.8 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2010, filed on May 4, 2010.
10.58		Long-Term Incentive Program (2011 - 2013) (corrected for typographical error), incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2012, filed on April 30, 2012.

188



10.59		Long-Term Incentive Program (2012 - 2014), incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2012, filed on April 30, 2012.
10.60		Non-Employee Director Option Grant Notice, as amended, incorporated by reference to Exhibit 10.84 to the Form 8-K (file no. 001-14901) filed on October 24, 2005.
10.61		Form of Non-Qualified Stock Option Award Agreement For Employees, incorporated by reference to Exhibit 10.26 to the Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.
10.62		Form of Non-Qualified Stock Option Award Agreement for Employees (February 17, 2009 and after), incorporated by reference to Exhibit 10.28 to Form S-4 (file no. 333-157894) filed on June 26, 2009.
10.63		Form of Employee Non-Qualified Performance Stock Option Agreement, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on June 21, 2010.
10.64		Form of Restricted Stock Unit Award Agreement for Employees, incorporated by reference to Exhibit 10.28 to the Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.
10.65		Form of Restricted Stock Unit Award for Employees (February 17, 2009 and after), incorporated by reference to Exhibit 10.31 to Amendment No. 1 to Form S-4 (file no. 333-157894) filed on June 26, 2009.
10.66		Form of Restricted Stock Unit Award Agreement for Directors, incorporated by reference to Exhibit 10.30 to the Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.
10.67		Form of Election and Restricted Stock Unit Award Agreement (Exchange Offer), incorporated by reference to Exhibit 99.1 to Form S-4/A (file no. 333-157894) filed on June 26, 2009.
10.68		Form of Performance Share Unit Award Agreement, incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2012, filed on April 30, 2012.
10.69		Summary of Non-Employee Director Compensation.
10.70		Directors Deferred Compensation Plan (1999 Plan), incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.71		Hypothetical Investment Election Form Relating to Directors' Deferred Compensation Plan (1999 Plan), incorporated by reference to Exhibit 10.53 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.72		Directors' Deferred Fee Plan (2004 Plan) (Amended and Restated on December 4, 2007), incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.73		Hypothetical Investment Election Form Relating to Directors' Deferred Fee Plan (2004 Plan), incorporated by reference to Exhibit 10.50 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.74		Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.95 to the Form 8-K (file no. 001-14901) filed on May 8, 2006.
10.75		Trust Agreement (Amended and Restated on March 20, 2008) (1999 Directors Deferred Compensation Plan), incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.76		Trust Agreement (Amended and Restated on March 20, 2008) (2004 Directors Deferred Fee Plan), incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.77		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.
10.78		Amended and Restated Supplemental Retirement Plan of CONSOL Energy Inc. effective January 1, 2007, as amended and restated on September 8, 2009, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on September 11, 2009.
10.79		Amendment to CONSOL Energy Inc. Supplemental Retirement Plan, dated as of October 17, 2011, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901), for the quarter ended September 30, 2011, filed on October 31, 2011.
10.80		Discretionary Bonus Agreement - William J. Lyons, dated as of December 19, 2012, incorporated by reference to Exhibit 10.80 to Form 10-K (file no. 001-14901) for the year ended December 31, 2012, filed on February 7, 2013.
10.81		Form of CONSOL Stock Unit Award Agreement under the Equity Incentive Plan, incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.
10.82		Amended and Restated CONSOL Energy Inc. Executive Annual Incentive Plan, incorporated by reference to Appendix A to the Form DEF 14A (file no. 001-14901) filed on March 29, 2013.
10.83		Retirement Letter, dated January 29, 2013, by and between CONSOL Energy Inc. and P. Jerome Richey, incorporated by reference to Exhibit 10.3 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.

189



10.84		Retirement and Consulting Agreement, dated February 28, 2013, by and between CONSOL Energy Inc. and William J. Lyons, incorporated by reference to Exhibit 10.4 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.
10.85		Retirement and Consulting Agreement, dated February 20, 2013, by and between CONSOL Energy Inc. and Robert F. Pusateri, incorporated by reference to Exhibit 10.5 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.
12		Computation of Ratio of Earnings to Fixed Charges.
14.1		Code of Employee Business Conduct, incorporated by reference to Exhibit 14.1 to Form 8-K (file no. 001-14901)filed on December 5, 2008.
21		Subsidiaries of CONSOL Energy Inc.
23.1		Consent of Ernst & Young LLP
23.2		Consent of Netherland Sewell & Associates, Inc.
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
95		Mine Safety Disclosure Exhibit
99		Engineers' Audit Letter
101		Interactive Data File (Form 10-K for the year ended December 31, 2013 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.

190

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 7th day of February, 2014.



	CONSOL ENERGY INC.

	By:		/S/ J. BRETT HARVEY
			J. Brett Harvey
			Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 7th day of February, 2014, by the following persons on behalf of the registrant in the capacities indicated:



Signature		Title

/S/ J. BRETT HARVEY		Chairman of the Board and Chief Executive Officer
J. Brett Harvey		(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)

/S/ PHILIP W. BAXTER		Lead Independent Director
Philip W. Baxter

/S/ JAMES E. ALTMEYER, SR.		Director
James E. Altmeyer, Sr.

/s/ ALVIN R. CARPENTER		Director
Alvin R. Carpenter

/S/ WILLIAM E. DAVIS		Director
William E. Davis

/S/ RAJ K. GUPTA		Director
Raj K. Gupta

/S/ DAVID C. HARDESTY, JR.		Director
David C. Hardesty, Jr.

/s/ MAUREEN E. LALLY-GREEN		Director
Maureen E. Lally-Green

/S/ JOHN T. MILLS		Director
John T. Mills

/s/ WILLIAM P. POWELL		Director
William P. Powell

/S/ JOSEPH T. WILLIAMS		Director
Joseph T. Williams

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SCHEDULE II

CONSOL ENERGY INC. AND SUBSIDIARIES

Valuation and Qualifying Accounts

(Dollars in thousands)



			Additions		Deductions
	Balance at				Release of						Balance at
	Beginning		Charged to		Valuation			Charged to			End
	of Period		Expense		Allowance			Expense			of Period
Year Ended December 31, 2013
State operating loss carry-forwards	$	7,793	$	1,987	$	(1,410	)	$	(843	)	$	7,527
Deferred deductible temporary differences	170		—		—			(165		)	5
Total	$	7,963	$	1,987	$	(1,410	)	$	(1,008	)	$	7,532

Year Ended December 31, 2012
State operating loss carry-forwards	$	7,801	$	224	$	(232	)	$	—		$	7,793
Deferred deductible temporary differences	72		153		(55		)	—			170
Total	$	7,873	$	377	$	(287	)	$	—		$	7,963

Year Ended December 31, 2011
State operating loss carry-forwards	$	10,147	$	301	$	(2,647	)	$	—		$	7,801
Deferred deductible temporary differences	50		22		—			—			72
Total	$	10,197	$	323	$	(2,647	)	$	—		$	7,873

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