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

•	our dependence on gathering, processing and transportation facilities and other midstream facilities owned by CNX Midstream Partners LP (NYSE: CNXM) (CNXM) and others;

•	uncertainties in estimating our economically recoverable natural gas reserves, and inaccuracies in our estimates;

•	the high-risk nature of drilling natural gas wells;

•	our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling;

•	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 for our securities;

•	environmental regulations introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities;

•	the risks inherent in natural gas 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 that could impact financial results;

•	decreases in the availability of, or increases in the price of, required personnel, services, equipment, parts and raw materials to support our operations;

•	if natural gas prices remain depressed or drilling efforts are unsuccessful, we may be required to record writedowns of our proved natural gas properties;

•	a loss of our competitive position because of the competitive nature of the natural gas industry or overcapacity in this industry impairing our profitability;

•	deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, or negative credit market conditions;

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

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

•	existing and future government laws, regulations and other legal requirements that govern our business may increase our costs of doing business and may restrict our operations;

•	significant costs and liabilities may be incurred as a result of pipeline and related facility integrity management program testing and any related pipeline repair or preventative or remedial measures;

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

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

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

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•	risks associated with our debt;

•	failure to find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves;

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

•	we may operate a portion of our business with one or more joint venture partners or in circumstances where we are not the operator, which may restrict our operational and corporate flexibility and we may not realize the benefits we expect to realize from a joint venture;

•	changes in federal or state income tax laws;

•	challenges associated with strategic determinations, including the allocation of capital and other resources to strategic opportunities;

•	our development and exploration projects, as well as CNXM’s midstream system development, require substantial capital expenditures;

•	terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations;

•	construction of new gathering, compression, dehydration, treating or other midstream assets by CNXM may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks;

•	our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel;

•	we may not achieve some or all of the expected benefits of the separation of CONSOL Energy;

•	CONSOL Energy may fail to perform under various transaction agreements that were executed as part of the separation;

•	CONSOL Energy may not be able to satisfy its indemnification obligations in the future and such indemnities may not be sufficient to hold us harmless from the full amount of liabilities for which CONSOL Energy will be allocated responsibility;

•	the separation of CONSOL Energy could result in substantial tax liability; and

•	other factors discussed in this 2017 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 1,115,523 Mcfe per day;

•	90% Natural Gas, 10% Liquids; and

•	59% Marcellus, 20% Utica, 16% coalbed methane, and 5% other.

•	7.6 Tcfe of proved reserves;

•	93.9% natural gas;

•	58.2% proved developed;

•	95.5% operated; and

•	A reserve life ratio of 18.62 years (based on 2017 production).

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•	Responsibility: Be a safe and compliant operator; be a trusted community partner and respected corporate citizen; act with pride and integrity;

•	Ownership: Be accountable for our actions and learn from our outcomes, both positive and negative; be calculated risk-takers and seek creative ways to solve problems; and

•	Excellence: Be prudent capital allocators; be a lean, efficient, nimble organization; be a disciplined, reliable, performance-driven company.

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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.

(2)

Acreage amounts are only included under the target strata CNX 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.

(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.

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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 standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.

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ITEM 1A.	Risk Factors

•	weather conditions in our markets which affect the demand for natural gas;

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

•	with respect to natural gas, the price and availability of alternative fuel sources used by electricity generators;

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•	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 delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits.

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•	geological conditions;

•	changes in governmental regulations and taxation;

•	the amount and timing of actual production;

•	future prices and our hedging position;

•	future operating costs; and

•	capital costs of drilling, completion and gathering assets.

•	the results of delineation efforts and the acquisition, review and analysis of seismic data;

•	the availability of sufficient capital resources to us and any other participants in a well for the drilling of the well;

•	whether we are able to acquire on a timely basis all of the leasehold interests and obtain all of the permits required to drill the wells;

•	economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews; and

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•	unexpected drilling conditions;

•	title problems;

•	pressure or irregularities in geologic formations;

•	equipment failures or repairs;

•	fires, ruptures, landslides, mine subsidence, explosions or other accidents;

•	adverse weather conditions;

•	reductions in natural gas prices;

•	pressure or irregularities in formations;

•	security breaches or terroristic acts;

•	damage to pipelines, compressor stations, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism and acts of third parties;

•	lack of adequate capacity for treatment or disposal of waste water generated in drilling, completion and production operations;

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environmental conditions, including contamination from surface spillage of fluids used in well drilling, completion or operation including fracturing fluids used in hydraulic fracturing of wells, leaks of natural gas or condensate or losses of natural gas or condensate as a result of the malfunction of, or other disruptions associated with, equipment or facilities or other contamination of groundwater or the environment resulting from our use of such fluids;

•	delays in the issuance of permits at the state or local level and the resolution of regulatory concerns; and

•	lack of availability or high cost of drilling rigs, other field services, personnel and equipment.

•	personal injury or loss of life;

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

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

•	potential legal liability and monetary losses;

•	damage to our reputation within the industry or with customers;

•	regulatory investigations and penalties;

•	suspension of our operations; and

•	repair and remediation costs.

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•	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 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 reserves; and

•	a decline in our creditworthiness 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.

•	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; and

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

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•	perform ongoing assessments of pipeline and related facility integrity;

•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•	improve data collection, integration and analysis;

•	repair and remediate the pipeline as necessary; and

•	implement preventive and mitigating actions.

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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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•	a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;

•	a cyber-attack on our facilities may result in equipment damage or failure;

•	a cyber-attack on midstream or downstream pipelines could prevent our product from being delivered, resulting in a loss of revenues;

•	a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

•	a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

•	business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our units.

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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

(A)	Represents average net sales price including the effect of derivative transactions.

(B)	Represents proved developed and undeveloped gas reserves at period end.

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

•	Record total gas production of 407.2 Bcfe in 2017, 3.2% higher than 2016.

•	Record Marcellus Shale production of 239.4 Bcfe in 2017, 12.7% higher than 2016.

•	Increased proved reserves to 7.6 Tcfe, 20.6% higher than 2016.

•

On November 28, 2017, CNX completed the tax-free spin-off of its coal business resulting in two independent, publicly traded companies: CONSOL Energy, a coal company, formerly known as CONSOL Mining Corporation; and CNX, a natural gas exploration and production company. As a result of the separation of the two companies, CONSOL Energy and its subsidiaries now hold the coal assets previously held by CNX, including its Pennsylvania Mining Complex, Baltimore Marine Terminal, its direct and indirect ownership interest in CONSOL Coal Resources LP, formerly known as CNXC Coal Resources LP, and other related coal assets previously held by CNX. CNX's shareholders received one share of CONSOL Energy common stock for every eight shares of CNX’s common stock held as of the close of business on November 15, 2017, the record date for the separation and distribution. The coal company, previously reported as the Company's Pennsylvania Mining Operations division, has been reclassified in the Audited Consolidated Financial Statements in Item 8 of this Form 10-K to discontinued operations for all periods presented.

•	Gas production costs continue to decline - for the year ended December 31, 2017, total gas production costs were $2.23 per Mcfe, a 3.9% decline from the prior year.

•	Repurchased $103 million of common stock on the open market.

•	Our 2018 annual gas production is expected to increase to approximately 520-550 Bcfe.

•	Our 2018 E&P capital investment is expected to be approximately $790-$880 million..

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•	Depreciation, depletion, and amortization decreased on a per-unit basis primarily due to a reduction in Marcellus rates as a result of an increase in the Company's Marcellus reserves. See Note 7 - Property, Plant, and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.

•	Lease operating expense decreased on a per unit basis in the period-to-period comparison due to a decrease in well tending costs and salt water disposal costs, as well as a decrease in both Company operated and joint venture operated repairs and maintenance costs.

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•	Water Income increased $4 million due to increased sales of freshwater to third parties for hydraulic fracturing.

•	Equity in Earnings of Affiliates decreased $3 million primarily due to a decrease in earnings from Buchanan Generation, LLC.

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Lease Expiration Costs relate to leases where the primary term expired or will expire within the next 12 months. The $33 million increase in the period-to-period comparison is due to an increase in the number of leases that were allowed to expire in the year ended December 31, 2017, or will expire within the next 12 months, because they were no longer in the Company's future drilling plan. Additionally, approximately $10 million of the $33 million increase is associated with leases which have ceased production.

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•	Idle Rig Expense increased $8 million due to the temporary idling of some of the Company's natural gas rigs. Additionally, the total idle rig expense increased in the period-to-period comparison due to a settlement that was reached with a former joint-venture partner that resulted in CNX recording additional expense.

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Unutilized Firm Transportation and Processing Fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. 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 Income in other operating income above.

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•	Depreciation, depletion, and amortization decreased on a per-unit basis primarily due to a reduction in Marcellus rates as a result of an increase in the Company's Marcellus reserves. See Note 7 - Property, Plant, and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.

•	Lease operating expense decreased on a per unit basis in the period-to-period comparison due to a decrease in well tending costs and salt water disposal costs, as well as a decrease in both Company operated and joint venture operated repairs and maintenance costs.

•	Transportation, gathering, and compression expense decreased on a per unit basis in the period-to-period comparison due to the overall increase in sales volumes, the shift towards dry Utica Shale production which has lower gathering costs, and a decrease in pipeline and facility maintenance expense.

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•	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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•	Idle Rig Expense is 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 year ended December 31, 2016.

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Unutilized Firm Transportation and Processing Fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. 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 Income in other operating income above.

•	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. The Company also had a first quarter 2016 reorganization that was less significant.

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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 (loss) increased $1,229 million in the period-to-period comparison.

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Adjustments to reconcile net income (loss) to cash provided by operating activities primarily consisted of a $634 million net change in commodity derivative instruments, a $219 million change in deferred income taxes, and a $174 million change in the gain on the sale of assets. These adjustments were offset, in part, by a $138 million impairment in the carrying value of Knox Energy (see Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information) and a $19 million change in discontinued operations primarily related to the spin-off of its coal business (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).

•	Capital expenditures increased $460 million in the period-to-period comparison primarily due to increased expenditures in both the Marcellus and Utica Shale plays resulting from increased drilling and completions activity.

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Proceeds from the sale of assets increased $154 million primarily due to proceeds of $322 million related to the sale of approximately 35,900 net undeveloped acres in Ohio, Pennsylvania, and West Virginia, proceeds of $24 million related to the sale of approximately 22,000 acres in Colorado and proceeds of $19 million related to the sale of Knox Energy in the current period (See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information). In the year ended December 31, 2016, proceeds of $213 million were received related to the separation of the Marcellus Shale joint venture with Noble Energy.

•

Net Distributions from (Investments in) Equity Affiliates decreased $31 million in the period-to-period comparison primarily due to distributions of $25 million received from CNXM and distributions of $14 million from CNX Gathering LLC in the year ended December 31, 2017. During the year ended December 31, 2016, $70 million was received in connection with equity affiliate CNXM acquiring an additional 25% interest in CNX Midstream DevCo I LP, commonly referred to as the "Anchor Systems." See Note 20 - Related Party Transactions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Discontinued Operations changed $372 million primarily related to the spin-off of CONSOL Energy, Inc. (See Note 2 - Discontinued Operations in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

•	In the year ended December 31, 2016, CNX made payments on the senior secured credit facility of $952 million. No such payments were made in the year ended December 31, 2017.

•	In the year ended December 31, 2017, CNX received proceeds of $425 million related to the spin-off of its coal business. See Note 2 - Discontinued Operations in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•

In the year ended December 31, 2017, CNX had net payments of $144 million related to the partial extinguishment of the 2022 bonds, $74 million related to the extinguishment of the 2020 bonds and $21 million related to the extinguishment of the 2021 bonds. See Note 10 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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•	In the year ended December 31, 2017, CNX repurchased $103 million of its common stock on the open market. No repurchases were made in the year ended December 31, 2016.

(a)	Employee related long-term liabilities includes 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. CNX does not expect to contribute to the pension in 2017.

(b)	Other long-term liabilities include gas well 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.

•	An aggregate principal amount of $1,706 million of 5.875% senior unsecured notes due in April 2022 plus $3 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 CNX's subsidiaries.

•	An aggregate principal amount of $500 million of 8.00% senior unsecured notes due in April 2023 less $5 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 CNX's subsidiaries.

•	An aggregate principal amount of $0.5 million on a note maturing in March 2018.

•	An aggregate principal amount of $27 million of capital leases with a weighted average interest rate of 7.01% per annum.

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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)	Included in Total Operating are sales of $153,565 to Direct Energy Business Marketing LLC and $147,595 to NJR Energy Services Company, each of which comprises over 10% of sales.

(B)	Includes equity in earnings of unconsolidated affiliates of $49,830.

(C)	Includes investments in unconsolidated equity affiliates of $197,921.

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(D)	Included in Total Operating are sales of $106,280 to NJR Energy Services Company, which comprises over 10% of sales.

(E)	Includes equity in earnings of unconsolidated affiliates of $53,078.

(F)	Includes investments in unconsolidated equity affiliates of $190,964.

(G)	Included in Total Operating are sales of $131,299 to NJR Energy Services Company, which comprises over 10% of sales.

(H)	Includes equity in earnings of unconsolidated affiliates of $54,897.

(I)	Includes investments in unconsolidated equity affiliates of $237,330.

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(*)	Includes costs incurred whether capitalized or expensed.

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(1)	Net acres include acreage attributable to the Company's working interests of the properties. Additional adjustments (either increases or decreases) may be required as the Company further develops title to and further confirms its rights with respect to its various properties in anticipation of development. The Company believes that its 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. CNX 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)

The upward revisions in 2015 of 1,369 Bcfe were due to 611 Bcfe increase in both performance and operating cost reductions for developed properties, a 1,200 Bcfe increase for undeveloped properties due to operating cost reductions and expected increases in well performance. These upward revisions in 2015 were offset by a 442 Bcfe downward revision for undeveloped properties that were removed from our operational plans due to "high-grading" and selecting our highest rate of return properties for future development.

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

(d)	The net downward revision of 99.8 Bcfe was the result of 255 Bcfe downward revision for wells that were removed from both internal and JV partner development plans, 113 Bcfe downward revision related to economics for producing properties offset by 268 Bcfe of improved analog performance.

(e)	Extensions and Discoveries in 2016 and 2017 are due to the addition of wells on the Company's Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.

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

(g)	The downward revisions for 2017 is due to corporate planning changes by our JV partner in Ohio Utica which resulted in all PUD's being removed, causing a 458 Bcfe downward revision, offset, in part by improved well performance due to the enhanced RCS completions and improved operating costs.

(a)	During 2017, various exploration and development drilling and evaluations were completed. Approximately, $247,459 of capital was spent in the year ended December 31, 2017 related to undeveloped reserves that were transferred to developed.

(c)	Extensions and discoveries are due mainly to 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, 2017 are approximately 301,063 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 CNX.

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(a)	For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017, adjusted for energy content and a regional price differential. For 2017, this adjusted natural gas price was $2.44 per mcf, the adjusted oil price was $38.65 per barrel and the adjusted NGL price was $23.61 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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