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•	deterioration in economic conditions in any of the industries in which our customers operate may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital;

•	prices for natural gas, natural gas liquids and coal are volatile and can fluctuate widely based upon a number of factors beyond our control including oversupply relative to the demand available for our products, weather and the price and availability of alternative fuels;

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

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

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

•	our reliance on major customers;

•	our inability to collect payments from customers if their creditworthiness declines or if they fail to honor their contracts;

•	the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our natural gas, natural gas liquids 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 environmental regulations including any relating to greenhouse gas emissions on our operating costs as well as on the market for natural gas and coal and for our securities;

•	the risks inherent in natural gas and coal operations, including our reliance upon third party contractors, being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant

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

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

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

•	our ability to find adequate water sources for our use in natural 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 our operations;

•	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 natural gas, oil and coal reserves;

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

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

•	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;

•	divestitures we anticipate may not occur or produce anticipated benefits;

•	the terms of our existing joint ventures restrict our flexibility, actions taken by the other party in our natural 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 and oil reserves, which if not replaced, will cause our natural gas and oil reserves and production to decline;

•	declines in our borrowing base could occur for a variety of reasons, including lower natural gas or oil prices, declines in natural gas and oil proved reserves, and lending regulations requirements or regulations;

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

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

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

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

•	information theft, data corruption, operational disruption and/or financial loss resulting from a terrorist attack or cyber incident;

•	operating in a single geographic area;

•	certain provisions in our multi-year sales contracts may provided limited protection during adverse economic conditions, and may result in economic penalties or permit the customer to terminate the contract;

•	our common units in CNX Coal Resources LP and CONE Midstream Partners LP are subordinated, and we may not receive distributions from CNX Coal Resources LP or CONE Midstream Partners LP;

•	other factors discussed in this 2015 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.

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ITEM 1.	Business

•	Total average production of 900,430 Mcfe per day, an increase of 39% over 2014;

•	87% Natural Gas, 13% Liquids; and

•	51% Marcellus, 23% coalbed methane, 17% Utica, and 9% other.

•	5.6 Tcfe of proved reserves;

•	89.7% natural gas;

•	65.5% proved developed;

•	66.3% operated; and

•	A reserve life ratio of 17.17 years (based on 2015 production).

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

•	Production of 29.3 million tons of coal;

•	Coal reserve holdings of 3.0 billion tons;

•	67% of coal sales to domestic utilities; and

•	In July 2015, CNX Coal Resources LP (CNXC) closed its initial public offering.

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•	Safety,

•	Compliance, and

•	Continuous Improvement.

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•	24 wells in Southwestern Pennsylvania,

•	13 wells in Central Pennsylvania,

•	7 wells in Northern West Virginia, and

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

•	CONSOL Energy and Hess, our joint venture partner, drilled 24 gross wells. CONSOL Energy drilled seven of those wells,

•	CONSOL Energy and Noble Energy, drilled one gross well, and

•	CONSOL Energy drilled an additional six gross wells in the deep dry Utica area that were not part of either Joint Venture.

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(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, Utica, Marcellus, etc.). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect the acres in the strata we expect to produce. As more information is obtained or circumstances change, the acreage classification may change.

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(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.

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(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.

(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 Principles (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

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(1)

The heat values shown for Assigned Operating reserves are based on the 2015 actual quality and five-year forecasted quality for each mine/reserve, assuming that the coal is washed to an extent consistent with normal full-capacity operation of each mine's/complex's preparation plant. Actual quality is based on laboratory analysis of samples collected from coal shipments delivered in 2015. Forecasted quality is derived from exploration sample analysis results, which have been adjusted to account for anticipated moisture and for the effects of mining and coal preparation. The heat values shown for Accessible Reserves are based on as received, dry values obtained from drill hole analyses, adjusted for moisture, and prorated by the associated Assigned Operating product values to account for similar mining and processing methods.

(2)

Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include an 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 reported only for those coal seams that are controlled by ownership or leases.

(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 are 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 reported only for those coal seams that are controlled by ownership or leases.

(3)

140.8 Million tons of the Northern Appalachia leased tons are controlled by Consolidation Coal Company, a former subsidiary of CONSOL Energy that was sold in December 2013. As of filing these tons are still controlled by Consolidation Coal Company but are shown in CONSOL Energy's reserves due to a binding agreement that these tons will be released to CONSOL Energy following the change in name of the Lease Holder.

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(1)	143.3 Million tons for the Mason Dixon Project are controlled by Consolidation Coal Company, a former subsidiary of CONSOL Energy that was sold in December 2013. As of this filing, these tons are still controlled by Consolidation Coal Company but are shown in CONSOL Energy's reserves due to a binding agreement that these tons will be released to CONSOL Energy upon consent of the lessor.

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•	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.

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•	the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and

•	environmental and government regulation;

•	coal quality;

•	transportation costs from the mine to the customer;

•	the reliability of fuel supply;

•	worldwide demand for steel;

•	natural disasters/weather; and

•	political changes in international governments.

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•	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 purchase and installation of proximity detection services on continuous miner machines;

•	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;

•	more stringent rock dusting requirements; and

•	the purchase of personal dust monitors for collecting respirable dust samples from certain miners.

•	current and former coal miners totally disabled from black lung disease;

•	certain survivors of a coal 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 coal 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.

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ITEM 1A.	Risk Factors

•	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;

•	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

•	a decline in our creditworthiness, which may require us to post letters of credit, cash collateral, or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.

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

•	weather conditions in our markets which affect the demand for natural gas and thermal coal (for example, the unusually warm 2011 - 2012 winter left utilities with large coal stockpiles and depressed the demand for thermal coal);

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

•	with respect to thermal coal, the price and availability of natural gas and the price and supply of imported liquefied natural gas;

•	with respect to natural gas, the price and availability of thermal coal;

•	technological advances affecting energy consumption;

•	the costs, availability and capacity of transportation infrastructure;

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

•	the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and regulations affecting the coal mining industry and coal-fired power plants, and delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits; and

•	increased utilization by the steel industry of electric arc furnaces or pulverized coal injection processes to make steel which reduce or eliminate the use of furnace coke, an intermediate product produced from metallurgical coal,and decreases the demand for metallurgical coal.

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•	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.

•	variations in thickness of the layer, or seam, of coal;

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adverse geological conditions, including amounts of rock and other natural materials intruding into the coal that could affect the stability of the roof and the side walls of the mine - for example, unit costs were negatively impacted in 2014 due to adverse geological conditions at the Enlow Fork mine, primarily related to sandstone intrusions, along with adverse geological conditions and equipment issues at the Harvey mine, primarily related to sandstone intrusions, which resulted in reduced coal production at both the Enlow Fork and Harvey mines;

•	environmental hazards;

•	equipment failures or unexpected maintenance problems;

•	fires or explosions, including as a result of methane, coal, coal dust or other explosive materials and/or other accidents;

•	inclement or hazardous weather conditions and natural disasters or other force majeure events;

•	seismic activities, ground failures, rock bursts or structural cave-ins or slides;

•	delays in moving our longwall equipment;

•	railroad derailments;

•	security breaches or terroristic acts; and

•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

•	personal injury or loss of life;

•	damage to and destruction of property, natural resources and equipment, including our coal properties and our coal production or transportation facilities;

•	pollution and other environmental damage to our properties or the properties of others;

•	potential legal liability and monetary losses;

•	regulatory investigations and penalties;

•	suspension of our operations; and

•	repair and remediation costs.

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•	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.

•	geologic conditions;

•	historical production from the area compared with production from other producing areas;

•	the assumed effects of regulations and taxes by governmental agencies;

•	our ability to obtain, maintain and renew all required permits;

•	future improvements in mining technology;

•	assumptions governing future prices; and

•	future operating costs, including the cost of materials and capital expenditures.

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•	postretirement medical and life insurance ($672 million);

•	coal workers' black lung benefits ($123 million);

•	salaried retirement benefits ($94 million); and

•	workers' compensation ($83 million).

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•	increasing our vulnerability to general adverse economic and industry conditions;

•	requiring us to dedicate a substantial portion of our cash flow from operations to the payment of interest and principal due under our outstanding debt, which will limit our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our gas and coal reserves or other general corporate requirements;

•	limiting our flexibility in planning for, or reacting to, changes in our business and in the coal and gas industries;

•	placing us at a competitive disadvantage compared to our competitors with lower leverage and better access to capital resources; and

•	limiting our ability to implement our business strategy.

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•	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.

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ITEM 1B.	Unresolved Staff Comments

ITEM 2.	Properties

ITEM 3.	Legal Proceedings

ITEM 4.	Mine Safety and Health Administration Safety Data

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

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ITEM 6.	Selected Financial Data

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(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: 0.0 million tons, 0.2 million tons, 0.6 million tons, 0.5 million tons, and 0.6 million tons for the years ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively.

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

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

•	Record total gas production of 328.7 Bcfe in 2015, 39.5% higher than 2014.

•	Record Marcellus Shale production of 168.7 Bcfe in 2015, 51.0% higher than 2014.

•

On July 7, 2015, CNX Coal Resources LP (CNXC) closed its initial public offering. Additionally, Greenlight Capital entered into a common unit purchase agreement with CNXC pursuant to which Greenlight Capital agreed to purchase, and CNXC agreed to sell, 5,000,000 common units at a price per unit equal to $15.00, which equates to $75,000 in net proceeds. CNXC's general partner is CNX Coal Resources GP, a wholly owned subsidiary of CONSOL Energy. The underwriters of the IPO filing exercised an over-allotment option of 561,067 common units to the public at $15.00 per unit. The total net proceeds distributed to CONSOL Energy related to this transaction, along with CNXC entering into a new senior secured revolving credit facility, were $342,711.

•	CONSOL now has 7 Utica wells online with two dry Utica PA wells. The Gaut 4I well in Westmoreland County, PA had an initial 24-hour flow test to sales of 61.4 MMcf per day at an average flowing casing pressure of 7,968 psi. The GH9 well in Greene County, PA had an initial 24-hour flow test of 61.9 MMcf per day at an average flowing casing pressure of 8,312 psi.

•	Gas production costs continue to decline - for the year ended December 31, 2015, total gas production costs were $2.73 per Mcfe, a 17.5% decline from the prior year.

•	Our 2016 annual gas production is expected to be approximately 15% higher than 2015.

•	Our 2016 E&P capital investment is expected to be between $205 - $325 million.

•	Our 2016 coal production is expected to be between 27.0 - 32.0 million tons.

•	Our 2016 coal and other capital investment is expected to be between $170 - $190 million.

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•

The improvement in unit costs is primarily due to the shift to lower cost Marcellus and Utica Shale production and the 39.5% increase in total volumes sold in the period-to-period comparison. Marcellus production made up 51.3% of natural gas and liquid sales volumes in the year ended December 31, 2015 compared to 47.4% in the year ended December 31, 2014. Utica production made up 17.1% of natural gas and liquid sales volumes in the year ended December 31, 2015 compared to 7.1% in the year ended December 31, 2014.

•

Depreciation, depletion and amortization decreased on a unit basis primarily due to the adjustment to our shallow oil and gas rates following impairment in the carrying value that was recognized in the second quarter of 2015, as well as the increase in sales volumes from our lower cost Marcellus and Utica production. The decrease was offset, in part, by an increase in total dollars as production continued to grow.

•	Lifting costs also decreased on a unit basis in the period-to-period comparison due to the overall increase in gas sales volumes. The decrease in unit costs was partially offset by an increase in repairs and maintenance, salt water disposal, and contractual services related to well tending.

•	Direct administrative costs decreased on a unit basis primarily due to ongoing cost reduction efforts, the Company reorganization that occurred in the 2015 period, as well as the increase in gas sales volumes.

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•

Contributions decreased $9 million primarily due to a charitable contribution of $6 million to the Boy Scouts of America that was recorded during the year ended December 31, 2014. The remaining $3 million decrease is due to various transactions that occurred throughout both periods, none of which were individually material, including a general decrease in prepaid trade association dues during the year ended December 31, 2015.

•	Consulting and professional services decreased $7 million due to various transactions that occurred throughout both periods, none of which were individually material, including a general decrease in legal expenses during the year ended December 31, 2015.

•	Employee wages and related expenses decreased $7 million due to the Company reorganization that occurred in the year ended December 31, 2015.

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

•	Miscellaneous costs decreased $3 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Gathering revenue decreased $17 million primarily due to a decrease in revenue related to certain gathering arrangements.

•	Equity in Earnings of Affiliates increased $15 million primarily due to an increase in earnings from CONE Midstream Partners LP and CONE Gathering LLC. See Note 27 - Related Party Transactions in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Other increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Lease expiration costs decreased by $5 million in the period-to-period comparison, primarily due to a decreased number of leases expiring in the year ended December 31, 2015 as compared to the year ended December 31, 2014.

•	Seismic activity decreased by $5 million in the period-to-period comparison, primarily due to cost reduction efforts in the 2015 period.

•	Land rental costs remained consistent in the period-to-period comparison.

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

•	Impairment of exploration and production properties primarily related to the write down of the Company's shallow oil and gas asset values in the second quarter of 2015 including impairments to unproved property. See Note 1 - Significant Accounting Policies in Item 8 of this Form 10-K for additional information.

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•	Idle rig fees are related to the temporary idling of some of the Company's natural gas rigs during the year ended December 31, 2015 in response to market conditions. There were no idle rig fees for the year ended December 31, 2014.

•	Severance expense was a result of the Company reorganization that occurred in the 2015 period. There was no such expense in the 2014 period.

•	Stock-based compensation decreased $3 million in the period-to-period comparison primarily due to less accelerated expense for retiree eligible employees under our current plan.

•	Bank fees decreased $4 million due to the termination of the CNX Gas Senior Secured Credit Agreement on June 18, 2014.

•

Unutilized firm transportation costs represent pipeline transportation capacity the E&P segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. Unutilized firm transportation and processing fees decreased $5 million in the period-to-period comparison due to an increase in the utilization of the capacity.

•	Short-term incentive compensation expense decreased in the period-to-period comparison due to a reduction in payouts in the current period.

•	Other corporate related expenses increased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Income of $129 million related to OPEB plan changes was the result of modifications made to the OPEB plan in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this annual report for more information.

•	Coal Reserve Holding Costs increased $2 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

•	Other decreased $3 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Income of $67 million related to OPEB plan changes was the result of modifications made to the OPEB plan in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this annual report for more information.

•	Closed and idle mines increased $2 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

•	Other increased $2 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Equity in earnings of affiliates decreased $11 million due to the sale of the Company's interest in one equity affiliate in the year ended December 31, 2015, compared to the sale of two equity affiliates in year ended December 31, 2014.

•	During the year ended December 31, 2014, $10 million of business interruptions proceeds were received related to the Blacksville No. 2 Mine fire that occurred in March 2013.

•	Rental income decreased $5 million due to a decrease in revenue received from the buyout of certain equipment that was leased by CONSOL Energy and then subleased to a third-party.

•	Royalty income decreased $5 million primarily due to the overall decrease in domestic coal pricing.

•	Right of way sales increased $1 million due to additional revenue earned from the sale of several right of ways during the year ended December 31, 2015.

•	Other income increased $3 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Income of $48 million related to OPEB plan changes was the result of modifications made to the OPEB plan in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this annual report for more information.

•	Closed and idle mine costs decreased approximately $14 million primarily due to a $7 million decrease in property taxes and a $5 million decrease in permitting and compliance costs. The remaining decrease was due to various transactions that occurred throughout both periods, none of which were individually material.

•	Purchased coal costs decreased $12 million due to lower coal volumes that were purchased in the current year to fulfill various contracts.

•	Coal terminal operations costs decreased $6 million due to decreased thru-put volumes in the current period.

•	Coal reserve holding costs decreased $4 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

•	Lease rental expense decreased $3 million primarily due to the buyout of certain equipment in the current year that was leased by CONSOL Energy.

•	UMWA OPEB expense increased $47 million primarily due to a change in the allocation methodology. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this annual report for more information.

•	Other decreased $16 million in the period-to-period comparison primarily due to a property tax reimbursement in the 2015 period related to property dispositions along with various transactions that occurred throughout both periods, none of which were individually material.

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•

No Industrial Supplies expense were incurred during the year ended December 31, 2015. Industrial Supplies expense was $231 million in the year ended December 31, 2014. The decrease is due to the divestiture of the Company's industrial supplies subsidiary in December 2014. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.

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Long-Term Liability Plan Changes include $36 million of income as a result of amendments to the pension and OPEB plans, which were adopted during the third quarter of 2014, offset by $46 million of expense for cash payments made to active employees related to changes in the OPEB plan during the year ended December 31, 2014. See Note 16—Pension and Other Postretirement Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to the total Company expense.

•

Corporate initiative fees and other legal charges reflect various fees for services related to corporate initiatives to evaluate structure changes and various asset sales. These fees also include legal charges related to land title issues raised by the Company's joint venture partners in the prior period. The $10 million decrease was due to various transactions that occurred throughout both periods, none of which were individually material. See Note 11 - Property, Plant and Equipment and Note 24 - Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Pension settlement expense is required when lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. Settlement accounting was triggered in both periods. See Note 16 - Pension and Other Postretirement Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional detail.

•	Revolver modification fees decreased $3 million due to an acceleration of previously deferred financing fees in the prior period.

•	Bank fees decreased $2 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

•	Industrial supplies working capital settlement of $6 million is the settlement of working capital adjustments and other matters in the year ended December 31, 2015 related to the divestiture of the Company's industrial supplies subsidiary in December 2014.

•	Actuarially-calculated amortization of $6 million was included in the Other division in the year ended December 31, 2015 due to modifications made to the Pension plan in September 2014. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this Annual Report on Form 10-K for more information.

•	Severance Payments increased $8 million due to the Company reorganization that occurred in the year ended December 31, 2015.

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

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•	The improvement in the unit costs is primarily due to the 36.7% increase in volumes in the period-to-period comparison and the shift to lower cost Marcellus and Utica Shale production. Marcellus production made up 47.4% of natural gas and liquid sales volume for the year ended December 31, 2014 compared to 33.6% in the year ended December 31, 2013.

•	Lifting costs per unit decreased in the period-to-period comparison due to the increase in sales volumes. The decrease was offset, in part, by an increase in total dollars relating to higher salt water disposal, well site maintenance costs, and costs related to wells operated by our joint-venture partners.

•	Gathering expense per unit also decreased in the period-to-period comparison due to the increase in sales volumes. The decrease in unit costs was partially offset by an increase in total dollars related to an increase in firm transportation costs and increased processing fees associated with natural gas liquids (NGLs).

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•	Gathering revenue increased $23 million primarily due to an increase in revenue related to certain gathering arrangements.

•	Earnings from our equity affiliates increased $17 million primarily due to an increase in earnings from CONE Midstream Partners, LP. See Note 27 - Related Party Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Interest income decreased $13 million primarily due to the 2013 collection of the final installment on the notes receivable from the 2011 Noble Energy joint venture transaction.

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

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•	CONSOL Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $23 million for the year ended December 31, 2013.

•	Dry hole costs decreased $7 million due to various transactions that occurred throughout both periods, none of which were individually material.

•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary lease term to expire because of unfavorable drilling economics. The $1 million decrease is due to various transactions that occurred throughout both periods, none of which were individually material.

•	Land Rentals decreased $1 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

•	Seismic Activity increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

•	Other expenses decreased $8 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Litigation settlements decreased $8 million due to various transactions that occurred throughout both periods, none of which were individually material.

•	Stock-based compensation decreased $7 million in the period-to-period comparison primarily due to a reduction in non-cash amortization expense and less accelerated expense for retiree eligible employees under our current plans.

•	Bank fees decreased $3 million due to various items that occurred throughout both periods, none of which were individually material.

•	Unutilized firm transportation and processing fees represent pipeline transportation capacity the E&P segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The $2 million increase was primarily due to increased firm transportation capacity which has not been utilized by active operations.

•	The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for, among other things, safety, production, compliance and unit costs. Short-term incentive compensation expense increased $3 million in the period-to-period comparison due to higher projected payouts.

•	Other corporate related expenses increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	For the year ended December 31, 2014, $30 million of income was related to a coal customer contract buyout. The discontinued contract was a long term contract that created pricing risks for both parties. The parties agreed to an amicable settlement. No such transactions were entered into in the year ended December 31, 2013.

•	Rental/Royalty income increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

•	Business interruption proceeds of $5 million were received in the prior year-to-date period related to the 2012 Bailey Mine Conveyor Belt accident.

•	Other income increased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.

•	Supplies expense decreased $6 million primarily due to the prior year-to-date period including additional supplies needed for repairs related to the 2012 Bailey Mine Belt Conveyor accident which was not included in active mining costs.

•	Property and other taxes remained consistent in the period-to-period comparison.

•	Other expense decreased $9 million due to various items that occurred throughout both periods, none of which were individually material.

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•	Idle mine costs are costs related to the temporary idling of the Amonate Complex which remained consistent year over year.

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

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•	Rental income increased $41 million primarily due to equipment subleased to a third-party. These arrangements began in December 2013.

•	During the year ended December 31, 2014, $10 million of insurance proceeds were received related to the Blacksville No. 2 Mine fire that occurred in March 2013.

•	Royalty income increased $3 million due to various transactions that occurred throughout both periods, none of which were individually material.

•	Land rental income primarily consists of income related to the sale of right of ways on property that CONSOL Energy owns. The $2 million increase was due to an increase in land activity in the period-to-period comparison.

•	Equity in earnings of affiliates increased $1 million due to various transactions completed by our equity partners, none of which were individually material.

•	Other decreased $6 million due to various activities that occurred in the current period, none of which were individually material.

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•	Purchased coal costs decreased $28 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.

•	Closed and idle mine costs decreased approximately $8 million for the year ended December 31, 2014 compared to the year ended December 31, 2013. This was primarily due to changes in the Company's perpetual care liability at the Fola Mining Complex and changes in the operational status of various mines, between idled and operating throughout both periods, none of which were individually material.

•	Coal terminal operations costs decreased $5 million due to decreased thru-put volumes in the current year.

•	Coal reserve holding costs which primarily consists of property and other taxes, increased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.

•	Lease rental expense increased $30 million primarily due to equipment leases that were subleased to a third-party. The third-party subleases began in December 2013.

•	Other expenses related to the Other coal segment increased $6 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Pennsylvania turnpike settlement relates to mediation with the PA Turnpike Commission that was settled for $9 million in 2013.

•	Interest income decreased $2 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

•	Equity in earnings of affiliates decreased $2 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

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

•

Industrial supplies expense represent costs from our industrial supplies subsidiary which was sold in December 2014. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details. The $16 million increase in expense was due to higher sales volumes in the current period along with various changes in inventory costs, none of which were individually material.

•

Long-Term Liability Plan Changes include $36 million of income as a result of amendments to the pension and OPEB plans, which were adopted during the third quarter of 2014, offset by $46 million of expense for cash payments made to active employees related to changes in the OPEB plan. See Note 16—Pension and Other Postretirement Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to the total Company expense.

•	Revolver modification fees resulted in a $3 million acceleration of previously deferred financing fees. No such transactions occurred in the prior period.

•	Bank fees increased $1 million primarily due to various transactions that occurred throughout both periods, none of which were individually material.

•

Corporate initiative fees and other legal charges reflect various fees for services related to corporate initiatives to evaluate structure changes and various asset sales. These fees also include legal charges related to land title issues raised by our joint venture partners and the CNX Gas shareholder settlement case. The $5 million decrease was due to various transactions that occurred in both periods, none of which were individually material. See Note 11 - Property, Plant, and Equipment and Note 24 - Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•

Pension settlement expense is required when the lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. Settlement accounting was triggered in both periods. See Note 16 - Pension and Other Post-Employment Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional detail.

•

The CNX Gas shareholder settlement was the result of an agreement for resolution of the class actions brought by shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010. The total settlement provided for payment to the plaintiffs of $43 million, of which the Company's portion was $20 million.

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

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•	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.

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•	Net income decreased $528 million in the period-to-period comparison;

•

Adjustments to reconcile net income to cash flow provided by operating activities increased $829 million due to the impairment of exploration and production properties (see Note 11 - Property, Plant and Equipment, in the Notes to Audited Financial Statements in Item 8 of this Form 10-K for more information), offset, in part, by a decrease of $142 million related to changes in deferred taxes, a decrease of $197 million due to the unrealized gain on commodity derivative instruments, a decrease of $216 million in other post-employment benefits plan amendments, and additional depreciation, depletion, and amortization of $44 million.

•	Other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both periods also contributed to the decrease in operating cash flows.

•	Gas segment capital expenditures decreased $271 million due to a decrease in drilling and completion costs in the Marcellus and Utica plays as the Company temporarily suspended these operations in August 2015 due to depressed commodity prices. In the fourth quarter of 2015, the Company resumed completions operations on its inventory of drilled but uncompleted wells.

•	Coal segment capital expenditures decreased $200 million primarily due to the completion of the Harvey Mine in the prior period, as well as, decreased maintenance of production capital at the PA operations complex.

•

Proceeds from the sale of assets decreased $247 million. Sales in 2015 include $76 million received in September 2015 related to the sale of CONSOL Energy's interest in its Western Allegheny Energy joint venture as well as various other smaller transactions which occurred in 2015. Significant sales in 2014 include $75 million received in March 2014 related to the Harvey Mine shield sale-leaseback as well as $46 million received in January 2014 as reimbursement from Noble Energy for 50% of the Dominion Resources lease acquisition and $14 million received in June 2014 related to the McElroy shields buyout. Additionally, the fourth quarter of 2014 included $97 million in proceeds from the sale of coal mines and reserves in Illinois and a $52 million sale of the Company’s interest in Shaft Drillers International, as well as various other transactions that occurred throughout 2014. See Note 3 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information. The remaining increase was due to various items that occurred throughout both periods, none of which were individually material.

•	Cash provided by equity affiliates decreased $179 million primarily due to a $204 million decrease in return of investments due to the IPO of CONE Midstream Partners, LP occurring in September 2014 along with an $18 million reduction in

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•	During the year ended December 31, 2015, CONSOL Energy received $952 million of proceeds from the senior secured credit facility compared to payments on short-term borrowings of $12 million during the year ended December 31, 2014.

•

In the year ended December 31, 2015, CONSOL Energy had net payments of $771 million related to the partial extinguishment of the 2020 and 2021 bonds offset, in part, by the issuance of the 2023 bonds. In the year ended December 31, 2014, CONSOL Energy had net proceeds from long-term borrowings of $41 million. See Note 14 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements of this Form 10-K for additional details.

•	In the year ended December 31, 2015, CONSOL Energy received $185 million of net proceeds under the CNX Coal Resources LP credit facility.

•	In the year ended December 31, 2015, CONSOL Energy received proceeds of $148 million from the IPO of CNX Coal Resources LP.

•	In the year ended December 31, 2015, CONSOL Energy repurchased $72 million of its common stock on the open market under the previously announced share repurchase program. No repurchases were made in the year ended December 31, 2014.

•	In 2015, CONSOL Energy paid four quarterly dividends totaling $33 million at an amount per share of $0.145. In 2014, CONSOL Energy paid four quarterly dividends totaling $58 million at an amount per share of $0.250.

•	The remaining changes are due to various transactions that occurred throughout both periods.

(a)	Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. CONSOL Energy does not expect to contribute to the pension in 2016.

(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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•	An aggregate principal amount of $74 million of 8.25% senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CONSOL Energy’s subsidiaries.

•	An aggregate principal amount of $21 million of 6.375% senior unsecured notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CONSOL Energy's subsidiaries.

•	An aggregate principal amount of $1,850 million of 5.875% senior unsecured notes due in April 2022 plus $6 million of unamortized bond premium. Interest on the notes is payable April 15 and October 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CONSOL Energy's subsidiaries.

•	An aggregate principal amount of $500 million of 8.00% senior unsecured notes due in April 2023 less $7 million of unamortized bond discount. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CONSOL Energy's subsidiaries.

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

•	Advance royalty commitments of $10 million with an average interest rate of 16.35% per annum.

•	An aggregate principal amount of $3 million on a note maturing through March 2018.

•	An aggregate principal amount of $43 million of capital leases with a weighted average interest rate of 5.93% per annum.

•	An aggregate principal amount of $185 million in outstanding borrowings under the revolver for CNXC. CONSOL Energy is not a guarantor of CNXC's revolving credit facility.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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(a)	This category includes investments in US common stocks and corporate debt.

(b)

This category invests primarily in common stock of large cap companies in the U.S. with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Russell 1000 Growth Index.

(c)

This category invests primarily in U.S. large cap companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Russell 1000 Value Index.

(d)

This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The smaller cap orientation of the strategy requires the

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(e)

This category invests in small to mid-sized U.S. companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Value Index.

(f)

This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targeted to be within 20% of the benchmark’s duration. Total exposure to high yield issues is typically less than 10%, inclusive of direct investment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.

(g)

This category invests in all cap companies primarily operating in developed non-US markets, with some exposure to emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the MSCI EAFE Index.

(h)

This category invests in companies operating in non-US emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the MSCI Emerging Markets Index.

(i)	This category invests in companies operating in developed markets, globally. The strategy targets a diversified portfolio of equity securities issued by companies which the investment managers believe will exhibit less volatility in their price performance relative to the broad equity market as described by the MSCI World Index. The strategy is benchmarked to the MSCI World Index.

(j)

This category invests in a passively managed U.S. long duration corporate investment grade portfolio at a 90% weight and a passively managed U.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing for short term liquidity through a strategic allocation to US Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% to the Barclays Capital Long Treasury.

(k)

This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 15 years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds, and TIPs. The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.

(l)	This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.

(m)	This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Aggregate Index.

(n)	This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 15 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.

(o)

This category seeks to reduce the volatility of the plan’s funded status and extend the duration of the assets by investing in a series of ultra long duration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return in excess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets to the plan’s liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.

(p)	This category invests in a U.S. long duration corporate investment grade portfolio at a 90% weight and a U.S. long treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade corporate bonds with an emphasis on reducing default risk through active management while allowing for short term liquidity through a

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(q)	This category invests primarily in long dated U.S. Treasury STRIPS often with maturities greater than 20 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital U.S. 20+ Year STRIPS Index.

(r)	This category invests primarily in fixed income securities from issuers either located in developing/emerging markets or those rated below investment grade (high yield), globally. The strategy is benchmarked to a blended index of 50% JP Morgan Government Bond Index Emerging Markets Global Diversified and 50% Bank of America/Merrill Lynch Global High Yield Index.

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(A)	Included in the Coal segment are sales of $356,151 to Xcoal Energy Resources and sales of $352,192 to Duke Energy, each comprising over 10% of sales.

(B)	Includes equity in earnings of unconsolidated affiliates of $46,614 and $8,283 for E&P and Coal, respectively.

(C)	Includes investments in unconsolidated equity affiliates of $234,803 and $2,527 for E&P and Coal, respectively.

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(D)	Included in the Coal segment are sales of $394,849 to Duke Energy and sales of $344,617 to Xcoal Energy Resources, each comprising over 10% of sales.

(E)	Includes equity in earnings of unconsolidated affiliates of $32,217, $19,324 and $(1,750) for E&P, Coal, and All Other, respectively.

(F)	Includes investments in unconsolidated equity affiliates of $121,721 and $31,237 for E&P and Coal, respectively.

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(*)	Includes costs incurred whether capitalized or expensed.

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(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.

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(a)	Revisions are primarily due to corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas and reservoirs. These changes along with upward revisions attributable to efficiencies in operations and well performance had the total affect of the positive revisions for 2013.

(b)	Extensions and Discoveries in 2013 are primarily due to the addition of wells on our Marcellus Shale acreage more than one offset location away with reliable technology.

(c)

Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CONSOL Energy cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are reserves expected to be recovered through existing wells, with existing equipment and operating methods.

(d)	Revisions for 2014 are primarily due to efficiencies in operations and well optimization and had the total effect of positive revisions. Additionally, the 2014 revisions include a reclassification of ethane volumes from natural gas to NGLs.

(e)	Extensions and Discoveries in 2014 are primarily due to the addition of wells on our Marcellus and Utica Shale acreage. We also included Marcellus Shale wells which are more than one offset location away due to continued use of reliable technology.

(f)	The upward revisions in 2015 are attributable to efficiencies in operations and well performance.

(g)	Extensions and Discoveries in 2015 are due mainly to the high grading of locations which resulted in the addition of wells on our Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.

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(h)	Included in our proved developed reserves at December 31, 2015 are producing wells with negative undiscounted cash flows that represent 258.1 Bcfe of natural gas and equivalents which represents 4.6% of our total reserves quantities. These consist primarily of conventional wells and the company includes these wells in our reserves as we continue to produce the properties.

(a)	During 2015, various exploration and development drilling and evaluations were completed. Approximately, $330,686 of capital was spent in the year ended December 31, 2015 related to undeveloped reserves that were transferred to developed.

(c)	Extensions and discoveries in 2015 are due mainly to the high grading of locations which resulted in the addition of wells on our Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.

(d)

Included in proved undeveloped reserves at December 31, 2015 are approximately 215,987 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 resulting from an external factor. These reasons constitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.

(e)

Included in proved undeveloped reserves at December 31, 2015 are 293 gross proved undeveloped locations that generate positive future net revenue but have negative present worth discounted at 10 percent as of December 31, 2015, representing 36.0% of our total proved undeveloped reserves. Additionally, the 700.9 Bcfe of natural gas and equivalents attributable to these locations represent approximately 12.4% of our total proved reserves. The Company includes these well sites in its current drilling plans and currently intends to drill these sites as our economic modeling of these well locations generate positive future cash flows.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

ITEM 9A.	CONTROLS AND PROCEDURES

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ITEM 9B.	OTHER INFORMATION

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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ITEM 11.	EXECUTIVE COMPENSATION

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

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ITEM 15.	EXHIBIT INDEX

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