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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 and natural gas liquids 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 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 coal mining and natural gas 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;

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•	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;

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

•	joint ventures that we are party to now or in the future may restrict our flexibility, actions taken by our joint ventures may impact our financial position and operational results;

•	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 near-term 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 coal sales contracts may provide limited protection during adverse economic conditions, and may result in economic penalties or permit the customer to terminate the contract;

•	the majority of 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;

•	with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC, any disruption to our business, including customer, employee and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating results;

•	there is no assurance that the potential drop-downs,spin-off or sale of the coal business will occur, or if it does occur that we will be able to negotiate favorable terms;

•	with respect to the termination of the joint venture with NOBLE, any disruption to our business, including customer and supplier relationships from this transaction, and the impact of the transaction on our future operating and financial results and liquidity; and

•	other factors discussed in this 2016 Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file at the Securities and Exchange Commission.

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ITEM 1.	Business

•	Total average production of 1,080,512 Mcfe per day, an increase of 20% over 2015;

•	88% Natural Gas, 12% Liquids; and

•	54% Marcellus, 23% Utica, 17% coalbed methane, and 6% other.

•	6.3 Tcfe of proved reserves;

•	93.2% natural gas;

•	58.9% proved developed;

•	87.6% operated; and

•	A reserve life ratio of 15.85 years (based on 2016 production).

•	Production of 24.6 million tons of coal;

•	Coal reserve holdings of 2.4 billion tons; and

•	75% of coal sales to domestic utilities.

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•	Safety,

•	Compliance, and

•	Continuous Improvement.

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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 only included under the target strata CONSOL Energy expects to produce with the exception of certain CBM acres governed by separate leases, although the reported acres may include rights to multiple gas seams (e.g. we have rights to Marcellus segment that are disclosed under the Utica segment and we have rights to Utica segment that are disclosed under the Marcellus segment). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect the acres in the strata we expect to primarily 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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(1)	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 2016 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 the complex's preparation plant. Actual quality is based on laboratory analysis of samples collected from coal shipments delivered in 2016. 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. Reserves tons are reported on an as-received basis, based on the anticipated product moisture. Reserves are reported only for those coal seams that are controlled by ownership or leases.

(1)

The heat value (gross calorific values) 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 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 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;

•	Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices, or other negotiated indices; or

•	Netback pricing.

•	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;

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•	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

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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;

•	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 natural 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 of electricity and natural gas;

•	weather conditions in our markets which affect the demand for natural gas and thermal coal (for example, the unusually warm 2015 - 2016 winter left utilities with large coal stockpiles and depressed the demand for thermal coal);

•	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; and

•	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.

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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;

•	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 2016 due to adverse geological conditions at Enlow Fork mine, primarily related to sandstone intrusions, which resulted in reduced coal production at that mine;

•	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.

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•	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;

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•	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 ($700 million);

•	coal workers' black lung benefits ($119 million);

•	salaried retirement benefits ($115 million); and

•	workers' compensation ($80 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 natural 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;

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

•	counterparties have credit limits that may constrain our ability to hedge additional volumes.

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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

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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)	Represents proven and probable coal reserves at period end, including discontinued operations and 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 394.4 Bcfe in 2016, 20.0% higher than 2015.

•	Record Marcellus Shale production of 212.5 Bcfe in 2016, 23.3% higher than 2015.

•	Record Utica Shale production of 90.8 Bcfe in 2016, 61.6% higher than 2015.

•	In March 2016, CONSOL Energy completed the sale of its membership interests in CONSOL Buchanan Mining Company, LLC (BMC), which owned and operated the Buchanan Mine located in Mavisdale, Virginia, various assets relating to the Amonate Mining Complex located in Amonate, Virginia; and various coal reserves. Cash proceeds of $402,799 were received at closing.

•	In August 2016, CONSOL Energy completed the sale of its Miller Creek Mining Complex and Fola Mining Complex subsidiaries. CONSOL Energy paid $28,271 of cash at closing. In addition, CONSOL Energy will pay a total of $17,200 in installments over the next four years.

•	In November 2016, cash proceeds of $70,000 were received in connection with our equity affiliate CONE Midstream Partners LP acquiring an additional 25% interest in CONE Midstream DevCo I LP, commonly referred to as the “Anchor Systems.”

•

In December 2016, with an effective date of October 1, 2016, CONSOL Energy terminated the 50-50 Joint Venture that was formed in 2011, with Noble Energy, Inc., for the exploration, development, and operation of primarily Marcellus Shale properties in Pennsylvania and West Virginia. Highlights include: each party will own and operate a 100% interest in its properties and wells in two separate operating areas; each party will have independent control and flexibility with respect to the scope and timing of future development over its operating area; and all acreage operated by CONSOL Energy and Noble Energy, Inc. in their respective operating areas will remain fully dedicated to CONE Midstream Partners LP. Cash proceeds of $213,295 were received at closing.

•	Gas production costs continue to decline - for the year ended December 31, 2016, total gas production costs were $2.32 per Mcfe, an 11.5% decline from the prior year.

•	Made payments on the senior secured credit facility of $952,000, resulting in zero drawings at the end of 2016, increasing liquidity.

•	Our 2017 annual gas production is expected to increase to approximately 415 Bcfe.

•	Our 2017 E&P capital investment is expected to be approximately $555 million.

•	Our 2017 coal production is expected to be approximately 26.0 million tons.

•	Our 2017 coal capital investment is expected to be approximately $135 million.

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The improvement in unit costs is primarily due to the continuing shift towards lower cost Marcellus and dry Utica Shale production, ongoing cost reduction efforts and the 20.0% increase in total volumes sold in the period-to-period comparison. Marcellus production made up 53.9% of E&P sales volumes in the year ended December 31, 2016, compared to 52.4% in the year ended December 31, 2015. Utica production made up 23.0% of E&P sales volumes in the year ended December 31, 2016, compared to 17.1% in the year ended December 31, 2015.

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

•

Transportation, gathering and compression expense decreased on a per unit basis in the period-to-period comparison due to the overall increase in E&P sales volumes, the shift towards dry Utica Shale production which has lower gathering costs since there are no associated processing fees and a decrease in pipeline and facility maintenance expense. The decrease in unit costs was partially offset by an increase in total dollars related to an increase in utilized firm transportation costs, increased processing fees associated with NGLs, and an increase in CONE gathering expense directly related to the increase in Marcellus production. See Note 25 - Related Party Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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•	The decrease in Short-Term Incentive Compensation was a result of lower payouts in the current year.

•	Employee Wages and Related Expenses decreased $8 million primarily due to the Company reorganization that occurred in the second half of 2015 and the first quarter of 2016, which resulted in an overall decrease in employees.

•	Stock-Based Compensation increased $6 million in the period-to-period comparison primarily due to additional non-cash amortization expense recorded in the current period for the Performance Share Unit (PSU) program.

•	Other increased $10 million in the period-to-period comparison primarily due to a 401(k) discretionary contribution in the current period.

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•	Right of Way Sales increased $13 million in the period-to-period comparison due to an initiative in the current year to generate additional revenue from our unutilized surface rights.

•	Equity in Earnings of Affiliates increased $5 million primarily due to an increase in earnings from CONE Midstream Partners LP and CONE Gathering LLC. See Note 25 - Related Party Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Lease Expiration Costs increased by $3 million in the period-to-period comparison, primarily due to an increase in the number of leases allowed to expire in the year ended December 31, 2016 as compared to the year ended December 31, 2015.

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•	Severance Expense decreased $4 million in the period-to-period comparison primarily due to the Company reorganization that occurred in the third quarter of 2015. Amounts recorded in the current period are primarily due to the Company's first quarter 2016 reorganization.

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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 natural gas liquids. The increase in the period-to-period comparison was primarily due to the decrease in the utilization of capacity. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included in Gathering Revenue in miscellaneous other income above.

•	Transaction Fees of $4 million are associated with the dissolution of the Noble Energy Marcellus Shale joint venture.

•	Idle Rig Expense related to temporary idling of some of the Company's natural gas rigs. The total idle rig expense increased in the period-to-period comparison due to unfavorable market conditions in the first half of the current period.

•	Other increased $5 million in the period-to-period comparison primarily due to a 401(k) discretionary contribution in the current period, as well as 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 made in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net Loss Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation. No such transactions occurred during the year ended December 31, 2016.

•	Idle Mine Costs increased $19 million, due to the temporary idling of one longwall at the PA Mining Operations complex for approximately 90 days in the first half of 2016 to optimize operating schedules.

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•	Purchased Coal Costs increased $6 million due to higher volumes of coal that needed to be purchased to fulfill various contracts.

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Litigation expense relates to approximately $3 million of costs which were incurred during the year ended December 31, 2016 related to the proposed consent decree with respect to the Bailey mine complex. See Note 22 - Commitments and Contingent Liabilities of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. The remaining change was the result of various transactions that occurred, none of which were individually material.

•	Severance Expense of $1 million was incurred during the year ended December 31, 2016 in connection with the Company's ongoing cost reduction efforts. No such transactions occurred in the prior period.

•	Other increased $10 million in the period-to-period comparison primarily due to a 401(k) discretionary contribution in the current period.

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•	Equity in Earnings of Affiliates decreased $7 million due to the sale of the Company's 49% interest in Western Allegheny Energy in September 2015. 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.

•	Purchased Coal Sales decreased $2 million due to lower volumes of coal that needed to be purchased to fulfill various contracts in the current period.

•	Right of Way Sales increased $4 million in the period-to-period comparison due to an initiative in the current year to generate additional revenue from the Company's unutilized surface rights.

•	Royalty Income increased $5 million primarily due to additional royalties received in the current year resulting from the sale of Buchanan Mine. See Note 2 - Discontinued Operations in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.

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Income of $125 million 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 Attributable to CONSOL Energy Shareholders" of this annual report and Note 14 - Pension and Other Postretirement Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information. No such transactions occurred in the current period.

•	Coal Reserve Holding Costs increased $11 million in the period-to-period comparison, primarily as a result of the surrender of various leases in the current period.

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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 14 - Pension and Other Postretirement Benefits Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Purchased Coal decreased $1 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.

•	Lease Rental Expense decreased $1 million primarily due to the buyout of certain leased equipment in the current period.

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•	Coal Terminal Operations decreased $2 million due to a reduction in labor costs.

•	UMWA OPEB Expense decreased $4 million primarily due to a decrease in interest costs.

•	Severance Payments decreased $5 million in the period-to-period comparison, primarily related to the company reorganization that occurred in the year ended December 31, 2015.

•	Industrial Supplies Working Capital Settlement of $6 million represents 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.

•	Pension Expense decreased $20 million in the period-to-period comparison due to a decrease in actuarially-calculated amortization related to modifications made to the pension plan in May 2015. See Note 14 - Pension and Other Postretirement Benefits Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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The improvement in unit costs is primarily due to the continuing shift towards lower cost Marcellus and Utica Shale production, ongoing cost reduction efforts and the 39.5% increase in total volumes sold in the period-to-period comparison. Marcellus production made up 52.4% of E&P 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 E&P sales volumes in the year ended December 31, 2015, compared to 7.1% in the year ended December 31, 2014.

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Depreciation, depletion and amortization decreased on a per-unit basis primarily due to the adjustment to the Company's shallow oil and gas rates following the impairment in carrying value that was recognized in the second quarter of 2015 (see Note 9 - Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information), as well as the increase in E&P sales volumes from the Company's lower cost Marcellus and Utica production. The decrease was offset, in part, by an overall increase in rates due to the reduction in the 2015 year-end reserves, as well as an increase in total dollars as production continued to grow.

•	Lease operating expenses decreased on a per-unit basis in the period-to-period comparison due to the overall increase in E&P sales volumes. The decrease in unit costs was partially offset by an increase in repairs and maintenance, salt water disposal costs, and contractual services related to well tending.

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•	The decrease in Short-Term Incentive Compensation was a result of lower payouts in the current period.

•	Stock-Based Compensation decreased $15 million in the period-to-period comparison primarily due to accelerated non-cash amortization recorded in the prior period for employees who received awards under the Company's Equity Incentive Plan.

•	Contributions decreased $8 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 $2 million decrease is due to various transactions that occurred throughout both periods, none of which were individually material.

•	Employee Wages and Related Expenses decreased $8 million primarily due to the Company reorganization that occurred in the year ended December 31, 2015.

•	Consulting and Professional Services decreased $5 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.

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•	Equity in Earnings of Affiliates increased $15 million due to an increase in earnings from CONE Midstream Partners LP and CONE Gathering LLC. See Note 25 - Related Party Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Gathering Revenue primarily relates to the release (sale) of unutilized firm transportation capacity when possible and when beneficial in order to minimize unutilized firm transportation expense. Gathering revenue decreased $14 million in the period-to-period comparison, primarily due to a decrease in the release of capacity.

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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.

•	Idle rig fees are related to the temporary idling of some of the Company's natural gas rigs. The Company incurred $19 million of idle rig fees during the year ended December 31, 2015 in response to declining market conditions. No idle rig fees were incurred during 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.

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

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Unutilized firm transportation costs represent pipeline transportation capacity that the E&P division 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. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. This revenue is included in Gathering Revenue in miscellaneous other income above.

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•	Equity in Earnings of Affiliates decreased $10 million due to the sale of the Company's 49% interest in Western Allegheny Energy in September 2015, and the sale of two equity affiliates during the year ended December 31, 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.

•	Purchased Coal Sales decreased $7 million due to lower volumes of coal that needed to be purchased to fulfill various contracts in the current period.

•	Rental Income decreased $6 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 related to non-operated coal properties decreased $5 million primarily due to the overall decrease in domestic coal pricing.

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•	The decrease in Industrial Supplies 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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Income of $125 million was the result of modifications made to the OPEB plan in May 2015 for retired employees. Income of $36 million was the result of changes made to the OPEB plan during the year ended December 31, 2014, offset by $46 million of expense for cash payments made to active 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 and Note 14—Pension and Other Postretirement Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

•	Purchased Coal costs decreased $13 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.

•	Closed and Idle Mines decreased $11 million, primarily due to a $7 million decrease in property taxes and a $5 million decrease in permitting and compliance costs. The remaining change was due to various transactions that occurred throughout both periods, none of which were individually material.

•	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 14 - 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.

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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. See Note 9 - Property, Plant and Equipment and Note 22 - Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Coal Terminal Operations costs decreased $6 million due to decreased throughput volumes in the current period.

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

•	Lease Rental Expense decreased $2 million primarily due to the buyout of certain leased equipment in the current period.

•	Workers' Compensation increased $3 million primarily due to a change in the allocation methodology in the current period. 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.

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•	Severance Payments increased $5 million in the period-to-period comparison, primarily related to the company reorganization that occurred in the year ended December 31, 2015.

•	Industrial Supplies Working Capital Settlement of $6 million represents 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.

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Pension Expense increased $6 million in the period-to-period comparison primarily due to a change in the allocation methodology in 2015, offset in part, by 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.

•	OPEB Expense increased $31 million primarily due to a change in the allocation methodology in 2015. 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.

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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 loss increased $475 million in the period-to-period comparison.

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Adjustments to reconcile net income to cash provided by operating activities decreased $829 million due to the impairment of exploration and production properties recorded in 2015. (See Note 9 - Property, Plant, And Equipment, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information). This adjustment was offset by an increase in the (gain) loss on commodity derivative instruments of $534 million, a net change in discontinued operations of $293 million (See Note 2 - Discontinued Operations in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information), an increase of $262 million in other post-employee benefits plan amendments recorded in 2015, and an increase of $261 million related to changes in deferred taxes.

•	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.

•	Capital expenditures decreased $756 million in the period-to-period comparison due to the following:

◦	E&P division capital expenditures decreased $667 million due to decreased expenditures in both the Marcellus and Utica plays resulting from decreased drilling activity, as well as other various transactions that occurred throughout both periods none of which were individually material.

◦	PA Mining Operations division capital expenditures decreased $85 million primarily due to a $37 million decrease in equipment purchases and rebuilds, a $25 million decrease in land project expenditures, and various other items that occurred throughout both periods, none of which were individually material.

◦	Other capital expenditures decreased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.

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Proceeds from the sale of assets increased $163 million primarily due to the $213 million received in December 2016 related to the separation of the Marcellus Shale Joint Venture with Noble Energy. This was offset, in part, by the $76 million received in September 2015 related to the sale of CONSOL Energy's interest in its Western Allegheny Energy joint venture. 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 remaining change was due to various land and equipment asset sales that occurred throughout both periods, none of which were individually material.

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Net investment in equity affiliates changed $158 million in the period-to-period comparison due to $70 million received in November 2016 in connection with equity affiliate CONE Midstream Partners, LP acquiring an additional 25% interest in CONE Midstream DevCo I LP, commonly referred to as the "Anchor Systems" (See Note 25 - Related Party Transactions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information), as well as the sale of the Company's 49% interest in Western Allegheny Energy in September 2015 discussed above.

•	Discontinued Operations increased $407 million primarily as a result of the sale of the Buchanan Mine and certain other metallurgical coal reserves and the sale of the Miller Creek and Fola mining complexes in the year ended December

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•	In the year ended December 31, 2016, CONSOL Energy made payments on the senior secured credit facility of $952 million compared to proceeds from the senior secured credit facility of $952 million in the year ended December 31, 2015.

•	In the year ended December 31, 2015, CONSOL Energy made 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. No such transactions occurred in the 2016 period. (See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details).

•	In the year ended December 31, 2016, there were $16 million of net proceeds under the CNX Coal Resources LP credit facility, compared with $185 million in the year ended December 31, 2015.

•	In the year ended December 31, 2015, CONSOL Energy received proceeds of $148 million from the IPO of CNX Coal Resources LP. No such transaction occurred in the 2016 period.

•	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, 2016.

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

(a)	Employee related long-term liabilities 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 2017.

(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 $5 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 $6 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 $3 million with an average interest rate of 7.73% per annum.

•	An aggregate principal amount of $2 million on a note maturing through March 2018.

•	An aggregate principal amount of $49 million of capital leases with a weighted average interest rate of 6.45% per annum.

•	An aggregate principal amount of $201 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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•	In March 2016, the FASB issued Update 2016-08 - Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which clarifies how an entity determines whether it is a principal or an agent for goods or services promised to a customer as well as the nature of the goods or services promised to their customers.

•	In April 2016, the FASB issued Update 2016-10 - Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing, which seeks to address implementation issues in the areas of identifying performance obligations and licensing.

•	In May 2016, the FASB issued Update 2016-12 - Revenue from Contracts with Customers: Narrow Scope Improvements and Practical Expedients, which seeks to address implementation issues in the areas of collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition.

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In December 2016, the FASB issued Update 2016-20 - Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which includes amendments related to loan guarantee fees, contract costs, provisions for losses on construction and production-type contracts, scope, disclosures, contract modification, contract asset versus receivable, refund liability and advertising costs.

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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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•	In March 2016, the FASB issued Update 2016-08 - Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which clarifies how an entity determines whether it is a principal or an agent for goods or services promised to a customer as well as the nature of the goods or services promised to their customers.

•	In April 2016, the FASB issued Update 2016-10 - Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing, which seeks to address implementation issues in the areas of identifying performance obligations and licensing.

•	In May 2016, the FASB issued Update 2016-12 - Revenue from Contracts with Customers: Narrow Scope Improvements and Practical Expedients, which seeks to address implementation issues in the areas of collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition.

•

In December 2016, the FASB issued Update 2016-20 - Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which includes amendments related to loan guarantee fees, contract costs, provisions for losses on construction and production-type contracts, scope, disclosures, contract modification, contract asset versus receivable, refund liability and advertising costs.

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

(b)	Certain investments that are measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy but are included in the total.

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(A)	Includes equity in earnings of unconsolidated affiliates of $51,742 and $1,336 for Total E&P and Other, respectively.

(B)	Includes investments in unconsolidated equity affiliates of $188,376 and $2,588 for Total E&P and Other, respectively.

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(C)	Included in the PA Mining Operations segment are sales of $242,020 to Duke Energy, which comprises over 10% of sales.

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

(E)	Includes investments in unconsolidated equity affiliates of $234,803 and $2,527 for Total E&P and Other, 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)

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.

(b)	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.

(c)	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.

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

(e)	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.

(f)	The net downward revisions for 2016 are primarily due to changes in plans related to future locations.

(g)	Extensions and Discoveries in 2016 are due to the addition of wells on our Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.

(h)	Purchases and Sales of Reserves In-Place in 2016 is the result of our fourth quarter realignment of the Marcellus Shale properties as part of dissolving our joint venture with Noble Energy.

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(i)	Included in our proved developed reserves at December 31, 2016 are producing wells with negative undiscounted cash flows that represent 199.3 Bcfe of natural gas and equivalents which represents 3.2% 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 2016, various exploration and development drilling and evaluations were completed. Approximately, $58,694 of capital was spent in the year ended December 31, 2016 related to undeveloped reserves that were transferred to developed.

(c)	Extensions and discoveries 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, 2016 are approximately 215,861 MMcfe of reserves that have been reported for more than five years. These reserves specifically relate 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 that was sold in March 2016 to Coronado IV LLC (See Note 2 - Discontinued Operations for more information) with the rights to this gas being retained by the Company. 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 the specific circumstances that exist to continue recognizing these reserves for CONSOL Energy.

(e)

Included in proved undeveloped reserves at December 31, 2016 are 175 gross proved undeveloped locations that generate positive future net revenue but have negative present worth discounted at 10 percent as of December 31, 2016, representing 58.9% of our total proved undeveloped reserves. Additionally, the 1,511.8 Bcfe of natural gas and equivalents attributable to these locations represent approximately 24.2% 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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(a)	For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016, adjusted for energy content and a regional price differential. For 2016, this adjusted natural gas price was $1.73 per mcf, the adjusted oil price was $25.04 per barrel and the adjusted NGL price was $15.77 per barrel.

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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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