UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 __________________________________________________
FORM 10-K
  __________________________________________________ 
(Mark One)
xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
For the fiscal year ended December 31, 20162017
OR
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                     
Commission file number: 001-14901
  __________________________________________________
CONSOL Energy Inc.CNX Resources Corporation
(Exact name of registrant as specified in its charter)
Delaware 51-0337383
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
CNX Center
1000 CONSOL Energy Drive Suite 400
Canonsburg, PA 15317-6506
(724) 485-4000
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 __________________________________________________ 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class   Name of exchange on which registered
Common Stock ($.01 par value)   New York Stock Exchange
Preferred Share Purchase Rights   New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  x    No  o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  o    No  x
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x    No  o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  x    No   o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  x    Accelerated filer  o    Non-accelerated filer  o    Smaller Reporting Company  o

Emerging Growth Company o If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  o    No  x
The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 20162017, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price of the common stock on the New York Stock Exchange on such date was $1,829,987,445.$1,685,654,421.
The number of shares outstanding of the registrant's common stock as of January 20, 201722, 2018 is 229,443,008223,758,284 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of CONSOL Energy'sCNX's Proxy Statement for the Annual Meeting of Shareholders to be held on May 9, 2017,2018, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III.
 



TABLE OF CONTENTS

  Page
PART I 
ITEM 1.Business
6
ITEM 1A.Risk Factors
2820
ITEM 1B.Unresolved Staff Comments
4835
ITEM 2.Properties
4835
ITEM 3.Legal Proceedings
4835
ITEM 4.Mine Safety and Health Administration Safety Data
4835
  
PART II 
ITEM 5.Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
4936
ITEM 6.Selected Financial Data
5138
ITEM 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
5339
ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk
9871
ITEM 8.Financial Statements and Supplementary Data
10073
ITEM 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
174123
ITEM 9A.Controls and Procedures
174123
ITEM 9B.Other Information
176125
   
PART III 
ITEM 10.Directors and Executive Officers of the Registrant
176125
ITEM 11.Executive Compensation
177126
ITEM 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
177126
ITEM 13.Certain Relationships and Related Transactions and Director Independence
177126
ITEM 14.Principal Accounting Fees and Services
177126
   
PART IV 
ITEM 15.Exhibits and Financial Statement Schedules
178127
ITEM 16.Form 10-K Summary
133
SIGNATURES
186134


2


GLOSSARY OF CERTAIN OIL AND GAS TERMS

The following are certain terms and abbreviations commonly used in the oil and gas industry and included within this Form 10-K:

Bbl - One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf - One billion cubic feet of natural gas.
Bcfe - One billion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
Btu - One British Thermal unit.
Mbbls - One thousand barrels of oil or other liquid hydrocarbons.
Mcf - One thousand cubic feet of natural gas.
Mcfe - One thousand cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
MMbtu - One million British Thermal units.
MMcfe - One million cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
NGL - Natural gas liquids - those hydrocarbons in natural gas that are separated from the gas as liquids through the proces.
net - “net” natural gas or “net” acres are determined by adding the fractional ownership working interests the Company has in gross wells or acres.
proved reserves - quantities of oil, natural gas, and NGLs which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
proved developed reserves (PDPs) - proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
proved undeveloped reserves (PUDs) - proved reserves that can be estimated with reasonable certainty to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
reservoir - a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Tcfe - One trillion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.



3



FORWARD-LOOKING STATEMENTS

We are including the following cautionary statement in this Annual Report on Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of us. With the exception of historical matters, the matters discussed in this Annual Report on Form 10-K are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act)) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” "will," or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

deterioration in economic conditions in any of the industries in which our customers operate may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital;
prices for natural gas and 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 coaldependence 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 delivermidstream 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 liquids and coalwells;
our identified drilling locations are scheduled out over multiple years, making them susceptible to market;
a lossuncertainties that could materially alter the occurrence or timing 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;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 coal 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 and coal operations, including our reliance upon third partythird-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 whichthat could impact financial results;
decreases in the availability of, or increases in the price of, commodities or capitalrequired personnel, services, equipment, used inparts and raw materials to support our coal mining andoperations;
if natural gas operations;
obtaining and renewing governmental permits and approvals forprices 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 coalmay 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;
the effectssignificant costs and liabilities may be incurred as a result of government regulation on the discharge into the waterpipeline and related facility integrity management program testing and any related pipeline repair or air, and the disposal and clean-up of, hazardous substances and wastes generated during our natural gas and coal operations;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 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;


4


the outcomes of various legal proceedings, including those which are more fully described in our reports filed under the Securities Exchange Act of 1934;Act;
exposure to employee-related long-term liabilities;
divestituresacquisitions and acquisitionsdivestitures 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;

4


risks associated with our debt;
replacing ourfailure to find or acquire economically recoverable natural gas and oil reserves which if not replaced, will causeto replace our current natural gas and oil reserves and production to decline;reserves;
declinesa decrease in our borrowing base, which could occurdecrease 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;
we may operate a portion of our hedging activitiesbusiness with one or more joint venture partners or in circumstances where we are not the operator, which may prevent usrestrict our operational and corporate flexibility and we may not realize the benefits we expect to realize from benefiting from near-term price increases and may expose us to other risks;a joint venture;
changes in federal or state income tax laws, particularly inlaws;
challenges associated with strategic determinations, including the areaallocation 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 to strategic opportunities;
our strategic opportunities may adversely affectdevelopment 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;
failure by Murray Energy to satisfy liabilities it acquired from us,condition 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;operations;
information theft, data corruption, operational disruption and/construction of new gathering, compression, dehydration, treating or financial loss resulting from a terrorist attack or cyber incident;
operatingother midstream assets by CNXM may not result in a single geographic area;
certain provisions in our multi-year coal sales contracts may provide limited protection during adverse economic conditions,revenue increases and may result inbe subject to regulatory, environmental, political, legal and economic penalties or permit the customer to terminate the contract;risks;
the majorityour success depends on key members of our common units in CNX Coal Resources LPmanagement and CONE Midstream Partners LP are subordinated,our ability to attract and retain experienced technical and other professional personnel;
we may not receive distributions from CNX Coal Resources LPachieve some or CONE Midstream Partners LP;
with respect to the saleall 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 impactexpected benefits of the separation of CONSOL Energy;
CONSOL Energy may fail to perform under various transaction on our future operating results;
there is no assuranceagreements that the potential drop-downs,spin-off or salewere executed as part of the coal business will occur, or if it does occur that we willseparation;
CONSOL Energy may not be able to negotiate favorable terms;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;
with respect to the terminationseparation 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;CONSOL Energy could result in substantial tax liability; and
other factors discussed in this 20162017 Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file at the Securities and Exchange Commission.

.



5


PART I

ITEM 1.Business

General

CONSOL Energy Inc., (CONSOL EnergyCNX Resources Corporation, (CNX or the Company) is an integrated energy company operated through two primary divisions,one of the largest independent oil and natural gas explorationcompanies in the United States and production (E&P) and Pennsylvania (PA) Mining Operations. The E&P division is focused on Appalachian area natural gas and liquids activities, includingthe exploration, development, production, gathering, processing and acquisition of natural gas properties in the Appalachian Basin. The PA Mining Operations division is focusedOur operations are centered on unconventional shale formations, primarily the extractionMarcellus Shale and preparation of coal, also in the Appalachian Basin.Utica Shale.

CONSOL EnergyCNX was incorporated in Delaware in 1991 under the name CONSOL Energy Inc. (CONSOL Energy), but its predecessors had been mining coal, primarily in the Appalachian Basin, since 1864. CONSOL EnergyCNX entered the natural gas business in the 1980s initially to increase the safety and efficiency of ourits Virginia coal mines by capturing methane from coal seams prior to mining, which makes the mining process safer and more efficient. Over the past ten years, CONSOL Energy'sThe natural gas business has grown by approximately 617% to produce 394.4 net Bcfe in 2016. This business has growngrew from the coalbed methane production in Virginia into other unconventional production, including hydraulic fracturing in the Marcellus Shale and Utica Shale in the Appalachian Basin. This growth was accelerated with the 2010 asset acquisition of the Appalachian Exploration & Production business of Dominion Resources, Inc. Subsequently, on December 5, 2013, we sold Consolidation Coal Company and certain subsidiaries, including five active coal mines in West Virginia.

Our E&POn 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. To effect the separation, 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 Annual Report on Form 10-K (the Form 10-K) to discontinued operations for all periods presented.

CNX operates, develops and explores for natural gas primarily in Appalachia (Pennsylvania, West Virginia, Ohio, Virginia and Tennessee)Virginia). Currently, ourOur primary focus is the continued development of our Marcellus Shale acreage and the delineation and development of our unique Utica Shale acreage.acreage and stacked pay opportunity set. We believe that our concentrated operating area, our legacy surface acreage position, our regional operating expertise, our extensive data set from development, joint ventures,as well as from non-operated participation wells and our held by productionheld-by-production acreage position and our ability to coordinate gas drilling with coal mining activity givesprovides us a significant operating advantage over our competitors. Over the past ten years, CNX's natural gas business has grown by approximately 625% to produce a total of 407.2 net Bcfe in 2017.

Our land holdings in the Marcellus Shale and Utica Shale plays cover large areas, provide multi-year drilling opportunities and, collectively, have sustainable lower risk growth profiles. We currently control approximately 413,000530,000 net acres in the Marcellus Shale and approximately 683,000652,000 net acres that have Utica Shale potential in Ohio, West Virginia, and Pennsylvania. We also have approximately 2.2 million net acres in our coalbed methane play.

Highlights of our 20162017 production include the following:
Total average production of 1,080,5121,115,523 Mcfe per day, an increase of 20% over 2015;day;
88%90% Natural Gas, 12%10% Liquids; and
54%59% Marcellus, 23%20% Utica, 17%16% coalbed methane, and 6%5% other.

At December 31, 2016,2017, our proved natural gas, NGL, condensate and oil reserves (collectively, "natural gas reserves") had the following characteristics:
6.37.6 Tcfe of proved reserves;
93.2%93.9% natural gas;
58.9%58.2% proved developed;
87.6%95.5% operated; and
A reserve life ratio of 15.8518.62 years (based on 20162017 production).

Highlights of coal activities in 2016 include the following:
Production of 24.6 million tons of coal;
Coal reserve holdings of 2.4 billion tons; and
75% of coal sales to domestic utilities.

Additionally, we provide energy services, including coal terminal services (the Baltimore Terminal), water services and land resource management services.








6



The following map provides the location of CONSOL Energy'sCNX's E&P and coal operations by region:
CONSOL EnergyCNX defines itself through its core values which are:serve as the compass for our road map and guide every aspect of our business as we strive to achieve our corporate mission:

Safety,Responsibility: Be a safe and compliant operator; be a trusted community partner and respected corporate citizen; act with pride and integrity;
Compliance,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
Continuous Improvement.Excellence: Be prudent capital allocators; be a lean, efficient, nimble organization; be a disciplined, reliable, performance-driven company.

These values are the foundation of CONSOL Energy'sCNX's identity and are the basis for how management defines continued success. We believe CONSOL Energy'sCNX's rich resource base, coupled with these core values, allows management to create value for the long-term. The electric power industry generates approximately two-thirds of its output by burning natural gas or coal, the two fuelsfossil fuels. Because of this we produce. We believe that the use of natural gas and coal will continue for many years as one of the principal fuel sources for electricity in the United States. Additionally, we believe that as worldwide economies grow, the demand for electricity from fossil fuels will grow as well, resultingwhich could result in the expansion of worldwide demand for our coalnatural gas. Natural gas is also the dominant choice for primary heating fuel in the domestic residential sector. CNG (compressed natural gas)-powered vehicles are already in use in many major cities, saving money on fuel and potentiallyreducing emission levels, while the demand for ourCNG is expected to grow further through additional fleet conversion to this cleaner-burning fuel. Finally, plentiful natural gas.gas feedstock is creating emerging opportunities for chemicals and plastics manufacturing (in addition to the other uses previously noted) in the United States and abroad as the United States becomes a net exporter of the fuel.

CONSOL Energy'sCNX's Strategy

CONSOL Energy'sCNX's strategy is to increase shareholder value through the development and growth of its existing natural gas assets and selective acquisition of natural gas and natural gas liquid acreage leases within its footprint,footprint. Our mission is to empower our team to embrace and through the participation in global coal markets. Ultimately, we intend to separatedrive innovative change that creates long-term value for our E&P divisionshareholders, while enhancing our communities and our PA Mining Operations division


7


delivering energy solutions for today and to focus on the growth of our E&P division.tomorrow. We also will continue to focus on monetization of non-core assets to accelerate value creation and to minimize the shortfall between operating cash flows and our growth capital requirements.

We expect natural gas to become a more significant contributor to the domestic electric generation mix, as well aswhile fueling industrial growth in the U.S. economy. With the recent growth of natural gas exports to Mexico and Canada and the United States becoming a net exporter of natural gas in 2016, we expect new markets to open up in the coming years. We feel that our significant increases in natural gas production, our reductions in drilling and operating costs and our vast acreage position will allow CONSOL EnergyCNX to take advantage of these markets.


7


CONSOL Energy’s coal assets align with the PA Mining Operations division's long-term strategic objectives. The production, which include the Bailey, Enlow Fork, and Harvey mines, can be sold domestically or abroad, as either thermal coal or high volatile metallurgical coal. These low-cost mines, with five longwalls, produce a high-Btu Pittsburgh-seam coal that is lower in sulfur than many Northern Appalachian coals.

These mines, along with our 100%-owned Baltimore Terminal, will continue to allow CONSOL Energy to participate in the world’s thermal and metallurgical coal markets. The ability to serve both domestic and international markets with premium thermal and metallurgical coal provides tremendous optionality.

CONSOL Energy's E&PCNX's Capital Expenditure Budget    

In 2017, the E&P division2018, CNX expects capital expenditures of approximately $555$790-$880 million. The E&P division capital expenditures are comprised2018 budget includes $515-$580 million of the following: $465 million for drilling and completion activity; $40("D&C") capital and approximately $275-$300 million forof capital associated with land, midstream, includingand water infrastructure. The 2018 D&C capital contributionsbudget is allocated approximately 65% to CONE Midstream Partners, LP;the Marcellus Shale and $50 million for other activities related35% to land, permitting, and business development.the Utica Shale.  
DETAIL E&P OPERATIONS

Our E&P operations are located throughout Appalachia and include the following plays:

Marcellus Shale

We have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 413,000530,000 net Marcellus Shale acres at December 31, 2016.2017.

The Upper Devonian Shale formation, which includes both the Burkett Shale and Rhinestreet Shale, lies above the Marcellus Shale formation in southwestern Pennsylvania and northern West Virginia. The companyCompany holds a large number of acres that have Upper Devonian potential; however, these acres have not been disclosed separately as they generally coincide with our Marcellus acreage.

In December 2016, CONSOL EnergyCNX 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. As a result of the termination, each party now owns and operates a 100% interest in its properties and wells in two separate operating areas; and each party will now have independent control and flexibility with respect to the scope and timing of future development over its operating area. In June 2017, Noble Energy announced that it has closed on a transaction divesting its upstream assets in northern West Virginia and southern Pennsylvania to HG Energy II Appalachia, LLC, a portfolio company of Quantum Energy Partners.

We also hold aOn January 3, 2018, the Company acquired the remaining 50% membership interest in anCONE Gathering LLC (which has since been renamed CNX Gathering LLC), which holds the general partner interest and incentive distribution rights in CNXM, the entity that constructs and operates the gathering system for most of our Marcellus shale production. As of September 30, 2011, we contributed our existing Marcellus Shale gathering assets to this company. In September of 2014, the majority of these assets were contributed to CONE Midstream Partners LP. See ""Midstream Gas ServicesServices"" for a more detailed explanation.

Utica Shale

We have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 683,000652,000 net Utica Shale acres at December 31, 2016.2017. Approximately 305,000341,000 Utica acres coincide with Marcellus Shale acreage in Pennsylvania, West Virginia, and Ohio.

Coalbed Methane (CBM)

We have the rights to extract CBM in Virginia from approximately 268,000267,000 net CBM acres which cover a portion of our coal reserves in Central Appalachia. We produce CBM natural gas primarily from the Pocahontas #3 seam.

We also have the rights to extract CBM in West Virginia, southwestern Pennsylvania, and Ohio from approximately 912,000906,000 net CBM acres. In central Pennsylvania we have the right to extract CBM from approximately 260,000 net CBM acres. In addition, we control approximately 584,000 net CBM acres in Illinois, Kentucky, Indiana, and Tennessee. We also have the right to extract CBM on approximately139,000 net acres in the San Juan Basin in New Mexico. We have no current plans to drill CBM wells in these areas in 2017.



2018.


8


Other Gas

Shallow Oil and Gas

We have the rights to extract natural gas from other shale and shallow oil and gas positions primarily in Illinois, Indiana, Kentucky, New York, Ohio, Pennsylvania, Virginia, and West Virginia Virginia and New York from approximately 766,0001,360,000 net acres at December 31, 2016.2017. The majority of our shallow oil and gas leasehold position is held by production and all of it is extensively overlain by existing third-party gas gathering and transmission infrastructure.

Chattanooga

We have the rights to extract natural gas in Tennessee from approximately 95,000 net Chattanooga Shale acres at December 31, 2016.

Huron

We have approximately 503,000 net acres of Huron Shale potential in Kentucky, West Virginia, and Virginia; a portion of this acreage has tight sands potential.
Summary of Properties as of December 31, 20162017
 Marcellus Utica CBM Other Gas   Marcellus Utica CBM Other Gas  
 Segment Segment Segment Segment Total Segment Segment Segment Segment Total
Estimated Net Proved Reserves (MMcfe) 3,137,336
 1,371,978
 1,254,633
 487,701
 6,251,648
 4,396,130
 1,372,261
 1,353,366
 459,855
 7,581,612
Percent Developed 60% 28% 75% 100% 59% 51% 54% 72% 100% 58%
Net Producing Wells (including oil and gob wells) 283
 54
 4,359
 8,180
 12,876
 316
 76
 4,454
 8,019
 12,865
Net Acreage Position:                    
Net Proved Developed Acres 30,737
 9,649
 257,019
 243,877
 541,282
 34,010
 14,943
 259,638
 235,346
 543,937
Net Proved Undeveloped Acres 11,763
 12,836
 5,439
 —
 30,038
 28,435
 8,449
 3,819
 —
 40,703
Net Unproved Acres(1) 370,263
 355,332
 1,900,260
 1,119,678
 3,745,533
 467,365
 286,943
 1,893,140
 1,169,567
 3,817,015
Total Net Acres(2) 412,763
 377,817
 2,162,718
 1,363,555
 4,316,853
 529,810
 310,335
 2,156,597
 1,404,913
 4,401,655
_________
(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 EnergyCNX 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.

Producing Wells and Acreage

Most of our development wells and proved acreage are located in Virginia, West Virginia, Ohio and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied.







9


The following table sets forth, at December 31, 2016,2017, the number of producing wells, developed acreage and undeveloped acreage:
 Gross Net(1) Gross Net(1)
Producing Gas Wells (including gob wells) 17,314
 12,846
 17,013
 12,853
Producing Oil Wells 189
 30
 171
 12
Net Acreage Position:        
Proved Developed Acreage 549,816
 541,282
 551,900
 543,937
Proved Undeveloped Acreage 34,467
 30,038
 41,066
 40,703
Unproved Acreage 4,804,804
 3,745,533
 4,434,714
 3,817,015
Total Acreage 5,389,087
 4,316,853
 5,027,680
 4,401,655

(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.


9



The following table represents the terms under which we hold these acres:    
 Net Unproved Acres Net Proved Undeveloped Acres Gross Unproved Acres Net Unproved Acres Net Proved Undeveloped Acres
Held by production/fee 3,644,799
 13,967
 4,278,446
 3,736,526
 25,688
Expiration within 2 years 68,084
 9,347
 94,486
 43,118
 8,447
Expiration beyond 2 years 32,650
 6,724
 61,782
 37,371
 6,568
Total Acreage 3,745,533
 30,038
 4,434,714
 3,817,015
 40,703

The leases reflected above as Gross and Net Unproved Acres with expiration dates are included in our current drill plan or active land program. Leases with expiration dates within two years represent approximately 2%1% of our total net unproved acres in the above categories and leases with expiration dates beyond two years represent approximately 1% of our total acres in the above categories.net unproved acres. In each case, we deemed this acreage to not be material to our overall acreage position. Additionally, based on our current drill plans and lease management we do not anticipate any material impact to our consolidated financial statements from the expiration of such leases.

Development Wells (Net)

During the years ended December 31, 2017, 2016 2015 and 2014,2015, we drilled 90.0, 36.0 132.8 and 180.3132.8 net development wells, respectively. Gob wells and wells drilled by operators other than our primary joint venture partners at that time Noble Energy and Hess Corporation, are excluded from net development wells. In 2016,2017, there were 68 gross3.9 net development wells and 1.8 exploratory wells drilled but uncompleted. There were no dry development wells in 2017, 2016, 2015, or 2014.2015. As of December 31, 2016,2017, there are 3.013.0 gross completed developmental wells ready to be turned in-line. The following table illustrates the net wells drilled by well classification type:
  For the Year
  Ended December 31,
  201620152014
Marcellus segment —
 44.0
 84.0
Utica segment 13.0
 15.8
 18.8
CBM segment 23.0
 73.0
 75.0
Other Gas segment —
 —
 2.5
     Total Development Wells (Net) 36.0
 132.8
 180.3







10

  For the Year
  Ended December 31,
  201720162015
Marcellus segment 9.0
 —
 44.0
Utica segment 17.0
 13.0
 15.8
CBM segment 64.0
 23.0
 73.0
Other Gas segment —
 —
 —
     Total Development Wells (Net) 90.0
 36.0
 132.8

Exploratory Wells (Net)

There were 4.0 net exploratory wells drilled during the year ended December 31, 2017. There were no exploratory wells drilled during the year ended December 31, 2016. During2016 and 2.5 net exploratory wells drilled during the yearsyear ended December 31, 2015 and 2014, we drilled, in the aggregate, 2.5, and 8.5 net exploratory wells, respectively.2015. As of December 31, 2016,2017, there are no1.8 net exploratory wells in process. The following table illustrates the exploratory wells drilled by well classification type:
 For the Year Ended December 31, For the Year Ended December 31,
 2016 2015 2014 2017 2016 2015
 Producing Dry Still Eval. Producing Dry Still Eval. Producing Dry Still Eval. Producing Dry Still Eval. Producing Dry Still Eval. Producing Dry Still Eval.
Marcellus segment —
 —
 —
 —
 —
 —
 1.5
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Utica segment —
 —
 —
 2.5
 —
 —
 1.0
 —
 —
 2.2
 —
 1.8
 —
 —
 —
 2.5
 —
 —
CBM segment —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Other Gas segment —
 —
 —
 —
 —
 —
 6.0
—
—
 —
 —
 —
 —
 —
 —
 —
 —
—
—
 —
Total Exploratory Wells (Net) —
 —
 —
 2.5
 —
 —
 8.5
 —
 —
 2.2
 —
 1.8
 —
 —
 —
 2.5
 —
 —







10


Reserves

The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the Securities and Exchange Commission (SEC).
 Net Reserves Net Reserves
 (Million cubic feet equivalent) (Million cubic feet equivalent)
 as of December 31, as of December 31,
 2016 2015 2014 2017 2016 2015
Proved developed reserves 3,683,302
 3,697,152
 3,198,706
 4,409,065
 3,683,302
 3,697,152
Proved undeveloped reserves 2,568,346
 1,945,837
 3,628,910
 3,172,547
 2,568,346
 1,945,837
Total proved developed and undeveloped reserves(1) 6,251,648
 5,642,989
 6,827,616
 7,581,612
 6,251,648
 5,642,989
___________
(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.

Discounted Future Net Cash Flows

The following table shows our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%:
 Discounted Future Discounted Future
 Net Cash Flows Net Cash Flows
 (Dollars in millions) (Dollars in millions)
 2016 2015 2014 2017 2016 2015
Future net cash flows $2,419
 $2,499
 $9,321
 $7,841
 $2,419
 $2,500
Total PV-10 measure of pre-tax discounted future net cash flows (1) $1,559
 $1,659
 $4,884
 $4,140
 $1,559
 $1,659
Total standardized measure of after tax discounted future net cash flows $955
 $1,019
 $2,984
 $3,131
 $955
 $1,019
____________
(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.









11


standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.
Reconciliation of PV-10 to Standardized Measure
 As of December 31, As of December 31,
 2016 2015 2014 2017 2016 2015
 (Dollars in millions) (Dollars in millions)
Future cash inflows $11,303
 $11,838
 $28,503
 $19,262
 $11,303
 $11,838
Future production costs (5,851) (6,585) (10,101) (7,234) (5,851) (6,585)
Future development costs (including abandonments) (1,550) (1,220) (3,369) (1,711) (1,550) (1,220)
Future net cash flows (pre-tax) 3,902
 4,033
 15,033
 10,317
 3,902
 4,033
10% discount factor (2,343) (2,374) (10,149) (6,177) (2,343) (2,374)
PV-10 (Non-GAAP measure) 1,559
 1,659
 4,884
 4,140
 1,559
 1,659
Undiscounted income taxes (1,483) (1,534) (5,712) (2,476) (1,483) (1,534)
10% discount factor 879
 894
 3,812
 1,467
 879
 894
Discounted income taxes (604) (640) (1,900) (1,009) (604) (640)
Standardized GAAP measure $955
 $1,019
 $2,984
 $3,131
 $955
 $1,019

Gas Production

The following table sets forth net sales volumes produced for the periods indicated:
  For the Year
  Ended December 31,
  2016 2015 2014
GAS      
Marcellus Sales Volumes (MMcf) 186,812
 145,747
 99,370
Utica Sales Volumes (MMcf) 71,277
 38,344
 10,303
CBM Sales Volumes (MMcf) 68,971
 74,910
 79,459
Other Sales Volumes (MMcf) 21,693
 28,286
 27,128
LIQUIDS*      
NGLs Sales Volumes (MMcfe) 40,260
 33,180
 15,475
Oil Sales Volumes (MMcfe) 410
 592
 681
Condensate Sales Volumes (MMcfe) 4,964
 7,598
 3,298
TOTAL (MMcfe) 394,387
 328,657
 235,714
  For the Year
  Ended December 31,
  2017 2016 2015
Natural Gas      
  Sales Volume (MMcf)      
      Marcellus 209,687
 186,812
 149,332
      Utica 70,708
 71,277
 38,344
      CBM 65,373
 68,971
 74,910
      Other 19,125
 21,693
 24,701
          Total 364,893
 348,753
 287,287
       
NGL      
  Sales Volume (Mbbls)      
      Marcellus 4,604
 3,922
 3,175
      Utica 1,851
 2,787
 2,354
      Other 1
 1
 1
          Total 6,456
 6,710
 5,530
       
Oil and Condensate      
  Sales Volume (Mbbls)      
      Marcellus 346
 360
 650
      Utica 204
 470
 627
      Other 39
 65
 88
          Total 589
 895
 1,365
       
Total Sales Volume (MMcfe)      
      Marcellus 239,387
 212,504
 172,280
      Utica 83,038
 90,820
 56,229
      CBM 65,373
 68,971
 74,910
      Other 19,368
 22,092
 25,238
          Total 407,166
 394,387
 328,657
*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas.

CONSOL EnergyCNX expects 20172018 annual natural gas production volumes of 520-550 Bcfe, or an approximately 31% annual increase, compared to grow to approximately 415 Bcfe and increase to approximately 485 Bcfe in 2018.2017 volumes, based on the midpoint of guidance.




12


Average Sales Price and Average Lifting Cost

The following table sets forth the total average sales price and the total average lifting cost for all of our natural gas and liquidsNGL production for the periods indicated, including intersegment transactions.indicated. Total lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization. See Part II Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K for a breakdown by segment.


12


 For the Year For the Year
 Ended December 31, Ended December 31,
 2016 2015 2014 2017 2016 2015
Average Sales Price - Gas (Mcf) $1.92
 $2.17
 $4.02
 $2.59
 $1.92
 $2.17
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf) $0.70
 $0.68
 $0.11
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf) $(0.11) $0.70
 $0.68
Average Sales Price - NGLs (Mcfe)* $2.42
 $2.05
 $5.95
 $4.03
 $2.42
 $2.05
Average Sales Price - Oil (Mcfe)* $6.15
 $7.99
 $14.85
 $7.56
 $6.15
 $7.99
Average Sales Price - Condensate (Mcfe)* $4.58
 $4.42
 $11.16
 $6.59
 $4.58
 $4.42
            
Total Average Sales Price (per Mcfe) $2.63
 $2.81
 $4.37
Average Lifting Costs excluding ad valorem and severance taxes (per Mcfe) $0.24
 $0.37
 $0.59
Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments $2.66
 $2.63
 $2.81
Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments $2.76
 $2.01
 $2.22
Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe) $0.22
 $0.24
 $0.37
      
Average Sales Price - NGLs (Bbl) $24.18
 $14.52
 $12.30
Average Sales Price - Oil (Bbl) $45.36
 $36.90
 $47.94
Average Sales Price - Condensate (Bbl) $39.54
 $27.48
 $26.52
*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas.

Sales of NGLs, condensates and oil enhance our reported natural gas equivalent sales price. Across all volumes, when excluding the impact of hedging, sales of liquids added $0.17 per Mcfe, $0.09 per Mcfe, and $0.05 per Mcfe for 2017, 2016, and $0.25 per Mcfe for 2016, 2015, and 2014, respectively, to average gas sales prices. CONSOL EnergyCNX expects to continue to realize a liquids uplift benefit as additional wells are brought online in the liquid-rich areas of the Marcellus and Utica shales.shale. We continue to sell the majority of our NGLs through the large midstream companies that process our natural gas. This approach allows us to take advantage of the processors’ transportation efficiencies and diversified markets. CONSOL Energy’sCertain of CNX’s processing contracts provide for the ability to take our NGLs “in kind”“in-kind” and market them directly if desired. The processed purity products are ultimately sold to industrial, commercial, and petrochemical markets.

We enter into physical natural gas sales transactions with various counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, we have delivered quantities required under these contracts. We also enter into various natural gas swap transactions. These gas swap transactions exist parallel to the underlying physical transactions and represented approximately 312.2 Bcf of our produced gas sales volumes for the year ended December 31, 2017 at an average price of $2.60 per Mcf. The notional volumes associated with these gas swaps represented approximately 264.9 Bcf of our produced gas sales volumes for the year ended December 31, 2016 at an average price of $3.04 per Mcf. The notional volumes associated with these gas swaps represented approximately 173.1 Bcf of our produced gas sales volumes for the year ended December 31, 2015 at an average price of $3.68 per Mcf. As of January 17, 2017,15, 2018, we expect these transactions will represent approximately 311.3 Bcf of our estimated 2017 production at an average price of $2.61 per Mcf, 220.6388.6 Bcf of our estimated 2018 production at an average price of $2.75$2.77 per Mcf, 161.7273.0 Bcf of our estimated 2019 production at an average price of $2.76$2.74 per Mcf, approximately 85198.3 Bcf of our estimated 2020 production at an average price of $2.91$2.78 per Mcf, and approximately 6.8166.5 Bcf of our estimated 2021 production at an average price of $3.08$2.62 per Mcf, and approximately 153.4 Bcf of our estimated 2022 production at an average price of $2.83 per Mcf.
 
The hedging strategy and information regarding derivative instruments used are outlined in Part II, Item 7A Qualitative and Quantitative Disclosures About Market Risk and in Note 2117 - Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.







13


Midstream Gas Services

CONSOL EnergyCNX has traditionally designed, built and operated natural gas gathering systems to move gas from the wellhead to interstate pipelines or other local sales points. In addition, CONSOL EnergyCNX has acquired extensive gathering assets. CONSOL EnergyCNX now owns or operates approximately 5,000 miles of natural gas gathering pipelines as well as 250,000 horsepower of compression, of which, approximately 75% is wholly owned with the balance being leased. Along with this compression capacity, CONSOL EnergyCNX owns and operates a number of natural gas processing facilities. This infrastructure is capable of delivering approximately 750 billion cubic feet per year of pipeline quality gas.

CONSOL Energy ownsOn January 3, 2018, CNX closed its previously announced acquisition of Noble Energy’s (Noble) 50% ofmembership interest in CONE Gathering LLC ("CONE"(CONE or "CONE Gathering") alongCONE Gathering), which holds the general partner interest and incentive distribution rights in CONE Midstream Partners LP. In conjunction with Noble Energy owning the other 50% interest. CONE Gathering develops, operates and owns substantially all of Noble Energy's and CONSOL Energy's Marcellus Shale gathering systems. CONSOL Energy operates this equity affiliate. We believe that the network of right-of-ways, vast surface holdings and experience in building and operating gathering systems in the Appalachian basin will give CONE Gathering an advantage in building the midstream assets required to develop our Marcellus Shale position. On September 30, 2014,closing, CONE Midstream Partners LP (the Partnership) closed its initial public offering. Seewas renamed CNX Midstream Partners LP (CNX Midstream or CNXM) and CONE Gathering LLC was renamed CNX Gathering LLC (CNX Gathering) (See Note 2521 - Related Party TransactionsSubsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.information). Also on January 3, 2018, the Company’s board of directors authorized CNX Midstream to enter into an amendment to its gas gathering agreement with CNX Gas Company LLC, a wholly-owned subsidiary of CNX.



13

CNX Gathering develops, operates and owns substantially all of CNX’s Marcellus Shale gathering systems. Prior to its acquisition of Noble’s interest, CNX operated this equity affiliate. Subsequent to the acquisition, CNX is the single sponsor of CNXM, and beginning in the first quarter of 2018 CNX Gathering will be fully consolidated into the Company’s financial statements. We believe that the network of right-of-ways, vast surface holdings, experience in building and operating gathering systems in the Appalachian basin, and increased control and flexibility will give CNX Gathering an advantage in building the midstream assets required to execute our Marcellus Shale development plan.

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

CONSOL EnergyCNX has developed a diversified portfolio of firm transportation capacity options to support its production growth plan. CONSOL EnergyCNX plans to selectively acquire as needed firm capacity on an as-needed basis, while minimizing transportation costs and long-term financial obligations and, inobligations. In the near term, if appropriate, CNX also plans to optimize and/or release firm transportation to others. CONSOL EnergyCNX also benefits from the strategic location of our primary production areas in Southwestsouthwestern Pennsylvania, Northernnorthern West Virginia, and Easterneastern Ohio. These areas are currently served by a large concentration of major pipelines that provide us with the capacity to move our production to the major gas markets, and it is expected that recently-approved and pending pipeline projects will increase the take-away capacity from our region. In addition to firm transportation capacity, CONSOL EnergyCNX has developed a processing portfolio to support the projected volumes from its wet production areas and has operational and contractual flexibility to potentially convert a portion of currently processed wet gas volumes to be marketed as dry gas volumes.
CONSOL Energy
CNX has the advantage of having gas production from CBM, which can be lower Btu than pipeline specification, as well as higher Btu Marcellus and Utica shale production. These types of gas can be complementary by reducing and in some cases eliminating the need for the costly processing of CBM. In addition, our lower Btu CBM and dry Marcellus and Utica production offer an opportunity to blend ethane back into the gas stream when pricing or capacity in ethane markets dictate. In developing a diversified approach to managing ethane, CONSOL EnergyCNX has entered into ethane supply agreements and is also discussingregularly assesses future outlet opportunities with ethane customers and midstream companies. These different gas types allow us more flexibility in bringing Marcellus and Utica shale wells on-line at qualities that meet interstate pipeline specifications.

Natural Gas Competition

The United States natural gas industry is highly competitive. CONSOL EnergyCNX competes with other large producers, as well as a myriad of smaller producers and marketers. CONSOL EnergyCNX also competes for pipeline and other services to deliver its products to customers. According to data from the Natural Gas Supply Association and the Energy Information Agency (EIA), the five largest U.S. producers of natural gas produced about 16%14% of dry natural gas production during the first nine months of 2016.2017. The EIA reported 554,201552,506 producing natural gas wells in the United States at December 31, 20152016 (the latest year for which government statistics are available), which is approximately twofour percent lower than 2014.2015.
CONSOL Energy
CNX expects natural gas to be a significant contributor to the domestic electric generation mix in the long-term, as well as to fuel industrial growth in the U.S. economy. According to the EIA, based on preliminary results, natural gas represented 34%32% of U.S. electricity generation during 20162017 compared with 33%34% in 2015.2016. With the recent growth of natural gas exports to Mexico, and Canada and increased liquefied natural gas exports, and declining pipeline imports from Canada, the U.S. became a net exporter of gas in 2016. CONSOL2016 and is projected by the EIA to be a net exporter of gas for 2017 and 2018. CNX also expects the high level of U.S. gas exports to continue in the future. In addition, there is potential for natural gas to become a significant contributor to the transportation market.


14


The EIA expects overall demand for U.S. natural gas to be 4.3% higher in 2018 compared with 2017. Our increasing gas production will allow CONSOL EnergyCNX to participate in these growing markets.
CONSOL Energy's
CNX gas operations are primarily located in the eastern United States. The gas market is highly fragmented and not dominated by any single producer. We believe that competition within our market is based primarily on natural gas commodity trading fundamentals and pipeline transportation availability to the various markets.

Continued demand for CONSOL Energy'sCNX's natural gas and the prices that CONSOL EnergyCNX obtains are affected by natural gas use in the production of electricity, pipeline capacity, U.S. manufacturing and the overall strength of the economy, environmental and government regulation, technological developments, the availability and price of competing alternative fuel supplies, and national and regional supply/demand dynamics.


14


DETAIL COAL OPERATIONS

Coal Reserves

At December 31, 2016, CONSOL Energy had an estimated 2.4 billion tons of proven and probable coal reserves. Reserves are the portion of the proven and probable tonnage that meet CONSOL Energy's economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels.

Spacing of points of observation for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). Our estimates for proved reserves have the highest degree of geologic assurance. Estimates for proved reserves are based on points of observation that are equal to or less than 0.5 miles apart. Estimates for probable reserves have a moderate degree of geologic assurance and are computed from points of observation that are between 0.5 to 1.5 miles apart.

An exception is made concerning spacing of observation points with respect to our Pittsburgh coal seam reserves. Because of the well-known continuity of this seam, spacing requirements are 3,000 feet or less for proved reserves and between 3,000 and 8,000 feet for probable reserves.

CONSOL Energy's estimates of proven and probable coal reserves do not rely on isolated points of observation. Small pods of reserves based on a single observation point are not considered; continuity between observation points over a large area is necessary for proved or probable reserves.

CONSOL Energy's proven and probable coal reserves fall within the range of commercially marketed coals in the United States. The marketability of coal depends on its value-in-use for a particular application, and this is affected by coal quality, such as sulfur content, ash and heating value. Modern power plant boiler design aspects can compensate for coal quality differences that occur. Therefore, any of CONSOL Energy's coals can be marketed for the electric power generation industry. Additionally, the growth in worldwide demand for metallurgical coal allows some of our proven and probable coal reserves, currently classified as thermal coals, that possess certain qualities to be sold as metallurgical coal. The addition of this cross-over market adds additional assurance to CONSOL Energy that all of its proven and probable coal reserves are commercially marketable.   

CONSOL Energy assigns coal reserves to our mining complex. The amount of coal we assign to the mining complex generally is sufficient to support mining through the duration of our current mining permit. Under federal law, we must renew our mining permits every five years. All assigned reserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured.

In addition, our mining complex may have access to additional reserves that have not yet been assigned. We refer to these reserves as accessible. Accessible reserves are proven and probable coal reserves that can be accessed by an existing mining complex, utilizing the existing infrastructure of the complex to mine and to process the coal in this area. Mining an accessible reserve does not require additional capital spending beyond that required to extend or to continue the normal progression of the mine, such as the sinking of airshafts or the construction of portal facilities.

Some reserves may be accessible by more than one mine because of the proximity of many of our mines to one another. In the table below, the accessible reserves indicated for a mine are based on our review of current mining plans and reflect our best judgment as to which mine is most likely to utilize the reserve.

Assigned and unassigned coal reserves are proven and probable coal reserves which are either owned or leased. The leases have terms extending up to 30 years and generally provide for renewal through the anticipated life of the associated mine. These renewals are exercisable by the payment of minimum royalties. Under current mining plans, assigned reserves reported will be mined out within the period of existing leases or within the time period of probable lease renewal periods.


15


Mining Complexes

The following table provides the location of CONSOL Energy's active mining complexes and the coal reserves associated with each of the continuing operations.
CONSOL ENERGY MINING COMPLEXES 
Proven and Probable Assigned and Accessible Coal Reserves as of December 31, 2016 and 2015 
                      
            Recoverable 
        Average As Received Heat Reserves(2) 
  Preparation     Seam Value(1)     Tons in 
  Facility Reserve Coal Thickness (Btu/lb) Owned Leased Millions 
Mine/Reserve Location Class Seam (feet) Typical Range (%) (%) 12/31/2016 12/31/2015 
ASSIGNED–OPERATING                     
PA Mining Operations                     
Bailey Enon, PA Assigned Operating Pittsburgh 7.5 12,950 12,860 – 13,030 43% 57% 89.0
 101.1
 
    Accessible Pittsburgh 7.5 12,910 12,700 – 13,170 78% 22% 170.7
 170.7
 
Harvey Enon, PA Assigned Operating Pittsburgh 6.3 13,040 12,920 – 13,160 86% 14% 20.4
 23.4
 
    Accessible Pittsburgh 7.6 12,900 12,840 – 13,130 99% 1% 180.1
 180.1
 
Enlow Fork Enon, PA Assigned Operating Pittsburgh 7.8 12,980 12,820 – 13,190 99% 1% 31.2
 10.9
 
    Accessible Pittsburgh 7.6 13,040 12,780 – 13,180 76% 24% 275.3
 305.3
 
Total Assigned Operating and Accessible                 766.7
 791.5
 


16


_____________
(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.

The following table sets forth our unassigned proven and probable coal reserves by region:
CONSOL Energy UNASSIGNED Recoverable Coal Reserves as of December 31, 2016 and 2015
           
          Recoverable
    Recoverable Reserves(2) Reserves
        Tons in (Tons in
  As Received Heat Owned Leased Millions Millions)
Coal Producing Region Value(1) (Btu/lb) (%) (%) 12/31/2016 12/31/2015
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia) (3) 11,400 – 13,400 85% 15% 1,054.0
 1,216.7
Central Appalachia (Virginia, Southern West Virginia) 12,400 – 14,100 77% 23% 157.2
 322.2
Illinois Basin (Illinois, Western Kentucky, Indiana) 11,600 – 12,000 79% 21% 348.7
 396.1
Total   83% 17% 1,559.9
 1,935.0
_______________
(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.








17


The following table classifies CONSOL Energy coals by rank, projected sulfur dioxide emissions and heating value (British thermal units per pound). The table also classifies bituminous coals as high, medium and low volatile which is based on fixed carbon and volatile matter.
CONSOL Energy Proven and Probable Recoverable Coal Reserves
By Product (In Millions of Tons) as of December 31, 2016
                        
   ≤ 1.20 lbs. > 1.20 ≤ 2.50 lbs. > 2.50 lbs.    
   S02/MMBtu S02/MMBtu S02/MMBtu    
   Low Med High Low Med High Low Med High   Percent By
By Region Btu Btu Btu Btu Btu Btu Btu Btu Btu Total Product
Metallurgical(1):                      
 High Vol A Bituminous —
 —
 —
 —
 —
 39.6
 —
 —
 —
 39.6
 1.7%
 Med Vol Bituminous —
 5.1
 —
 —
 —
 —
 —
 —
 —
 5.1
 0.2%
 Low Vol Bituminous —
 —
 16.0
 —
 —
 26.3
 —
 —
 —
 42.3
 1.8%
    Total Metallurgical —
 5.1
 16.0
 —
 —
 65.9
 —
 —
 —
 87.0
 3.7%
Thermal(1):                      
 High Vol A Bituminous —
 46.0
 —
 6.1
 65.4
 12.9
 44.5
 1,134.4
 611.7
 1,921.0
 81.4%
 High Vol B Bituminous —
 —
 —
 —
 101.1
 —
 —
 139.3
 —
 240.4
 10.3%
 High Vol C Bituminous —
 —
 —
 —
 —
 —
 108.3
 —
 —
 108.3
 4.6%
 Low Vol Bituminous —
 —
 —
 —
 —
 —
 —
 —
 4.5
 4.5
 0.2%
    Total Thermal —
 46.0
 —
 6.1
 166.5
 12.9
 152.8
 1,273.7
 616.2
 2,274.2
 96.3%
       Total —
 51.1
 16.0
 6.1
 166.5
 78.8
 152.8
 1,273.7
 616.2
 2,361.2
 100.0%
 Percent of Total —% 2.2% 0.7% 0.3% 7.1% 3.2% 6.5% 53.9% 26.1% 100.0%  
_______________
(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.

Title to coal properties that we lease or purchase and the boundaries of these properties are verified by law firms retained by us at the time we lease or acquire the properties. Consistent with industry practice, abstracts and title reports are reviewed and updated approximately five years prior to planned development or mining of the property. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine reserves could be adversely affected.

The following table sets forth, with respect to properties that we lease to other coal operators, the total royalty tonnage, acreage leased and the amount of income (net of related expenses) we received from royalty payments for the years ended December 31, 2016, 2015 and 2014.
  Total Total Total
  Royalty Coal Royalty
  Tonnage Acreage Income
Year (in thousands) Leased (in thousands)
2016 3,530 213,371 $9,684
2015 7,459 235,066 $14,914
2014 10,230 281,894 $18,460

Royalty tonnage leased to third parties is not included in the amounts of produced tons that we report. Proven and probable reserves do not include reserves attributable to properties that we lease to third parties.





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Production

In the year ended December 31, 2016, 100% of CONSOL Energy's production came from underground mines equipped with longwall mining systems. CONSOL Energy employs longwall mining systems in our underground mines where the geology is favorable and reserves are sufficient. Underground longwall systems are highly mechanized, capital intensive operations. Mines using longwall systems have a low variable cost structure compared with other types of mines and can achieve high productivity levels compared with those of other underground mining methods. Because CONSOL Energy has substantial reserves readily suitable to these operations, CONSOL Energy believes that these longwall mines can increase capacity at a low incremental cost.
The following table shows the production from continuing operations, in millions of tons, for CONSOL Energy's mines for the years ended December 31, 2016, 2015 and 2014, the location of each mine, the type of mine, the type of equipment used at each mine, method of transportation and the year each mine was established or acquired by us.
  Preparation       Tons Produced Year
  Facility Mine Mining   (in millions) Established
Mine Location Type Equipment Transportation 2016
 2015
 2014
 or Acquired
PA Mining Operations                
Bailey Enon, PA U LW/CM R R/B 12.1
 10.2
 12.3
 1984
Enlow Fork Enon, PA U LW/CM R R/B 9.6
 9.0
 10.6
 1990
Harvey (3) Enon, PA U LW/CM R R/B 3.0
 3.6
 3.2
 2014
Total         24.7
 22.8
 26.1
  
                 
CONSOL Energy Portion of Equity Affiliates              
Harrison Resources (1)(2) Cadiz, OH S S/L R T —
 —
 0.3
 2007
Western Allegheny (1)(2) Young Township, PA U CM R T —
 0.4
 0.5
 2010
Total CONSOL Energy Portion of Equity Affiliates         —
 0.4
 0.8
  

S–Surface
U–Underground
LW–Longwall
CM–Continuous Miner
S/L–Stripping Shovel and Front End Loaders
R–Rail
R/B–Rail to Barge
T–Truck
(1)–Harrison Resources,and Western Allegheny (includes facilities operated by independent contractors).
(2)–Production amounts represent CONSOL Energy's 49% ownership interest. Interest in Harrison Resources was sold in October 2014. Interest in Western Allegheny was sold in September 2015.
(3)–Completed development work and was placed in service in March 2014.

Coal Capital

In 2017, CONSOL Energy expects to invest $135 million in the PA Mining Operation division: $120 million allocated to production and $15 million allocated to other activities related to land, safety and water.

Coal Marketing and Sales

The following table sets forth the Company produced tons sold and average sales price for the period indicated:
  Years Ended December 31,
  2016 2015 2014
Company Produced PA Mining Operations Tons Sold (in millions) 24.6
 22.9
 26.1
Average Sales Price Per Ton Sold– PA Mining Operations $43.31
 $56.36
 $61.88



19


We sell coal produced by our mines and additional coal that is purchased by us for resale from other producers. We maintain United States sales offices in Philadelphia and Pittsburgh. In addition, we sell coal through agents and to brokers and unaffiliated trading companies.

Approximately 75% of our 2016 coal sales were made to U. S. electric generators, 22% of our 2016 coal sales were priced on export markets and 3% of our coal sales were made to other domestic customers. We had sales to over 35 customers from our 2016 coal operations. During 2016, two customers each comprised over 10% of our coal sales, and the top four coal customers accounted for over 40% of our coal sales.

Coal Contracts

We sell coal to an established customer base through opportunities as a result of strong business relationships, or through a formalized bidding process. Contract volumes range from a single shipment to multi-year agreements for millions of tons of coal. The average contract term is between one to three years. As a normal course of business, efforts are made to renew or extend contracts scheduled to expire. Although there are no guarantees, we generally have been successful in renewing or extending contracts in the past. For the year ended December 31, 2016, over 65% of all the coal we produced was sold under contracts with terms of one year or more.
CONSOL Energy expects total consolidated PA Mining Operations annual sales to be approximately 26.0 million tons for both 2017 and 2018.

Coal pricing for contracts with terms of one year or less are generally fixed. Coal pricing for multiple-year agreements generally provide the opportunity to periodically adjust the contract prices through pricing mechanisms consisting of one or more of the following:

Fixed price contracts with pre-established prices;
Periodically negotiated prices that reflect market conditions at the time;
Price restricted to an agreed-upon percentage increase or decrease;
Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices, or other negotiated indices; or
Netback pricing.

The volume of coal to be delivered is specified in each of our coal contracts. Although the volume to be delivered under the coal contracts is stipulated, the parties may vary the timing of the deliveries within specified limits.

Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include, but are not limited to, unexpected significant geological conditions or natural disasters. Depending on the language of the contract, some contracts may terminate upon continuance of an event of force majeure that extends for a period greater than three to twelve months.

Distribution

Coal is transported from CONSOL Energy's mining operations to customers by railroad cars, trucks or a combination of these means of transportation. Most customers negotiate their own transportation rates and we employ transportation specialists who negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines, terminal operators, ocean vessel brokers and trucking companies for certain customers.

Coal Competition

Both the domestic and international coal industries are highly competitive, with numerous producers selling into all markets that use coal. CONSOL Energy competes against several other large producers and numerous small producers in the United States and overseas. Demand for our coal by our principal customers is affected by many factors including:

the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and
renewable energy sources, such as hydroelectric power, wind or solar;
environmental and government regulation;
coal quality;
transportation costs from the mine to the customer;


20


the reliability of fuel supply;
worldwide demand for steel;
natural disasters/weather; and
political changes in international governments.

Continued demand for CONSOL Energy's coal and the prices that CONSOL Energy obtains are affected by demand for electricity, technological developments, environmental and governmental regulation, and the availability and price of competing coal and alternative fuel supplies. We sell coal to foreign electricity generators which are significantly affected by international demand and competition.

Other Operations

CONSOL EnergyCNX provides other services, including both land and water services, to both our own operations and to others. These include land services, coal terminal services and water services.

Non-Core Mineral Assets and Surface Properties

CONSOL EnergyCNX owns significant natural gas and coal assets that are not in our short or medium term development plans. We continually explore the monetization of these non-core assets by means of sale, lease, contribution to joint ventures, or a combination of the foregoing in order to bring the value of these assets forward for the benefit of our shareholders. We also control a significant amount of surface acreage. This surface acreage is valuable to us in the development of the gathering system for our Marcellus Shale and Utica Shale production. We also derive value from this surface control by granting rights of way or development rights to third-parties when we are able to derive appropriate value for our shareholders.

Terminal Services

In 2016, approximately 8.1 million tons of coal were shipped through CONSOL Energy's subsidiary, CNX Marine Terminals Inc.'s, exporting terminal in the Port of Baltimore. Approximately 63% of the tonnage shipped was produced by CONSOL Energy's PA Mining Operations. The terminal can either store coal or load coal directly into vessels from rail cars. It is also one of the few terminals in the United States served by two railroads, Norfolk Southern Corporation and CSX Transportation Inc.
 
Water Division

CNX Water Assets LLC, doing business as CONVEY Water Systems LLC, is a wholly-owned subsidiary of CONSOL EnergyCNX and supplies turnkey solutions for water sourcing, delivery and disposal for our E&Pnatural gas operations, and supplies solutions for water sourcing as well as delivery and disposal for third-parties and also provides supplemental water sourcing and marketing efforts on behalf of CNXC.third-parties. In coordination with our midstream operations, CONVEY Water Systems works to develop solutions that coincide with our midstream operations to offer gas gathering and water delivery solutions in one package to third-parties.

Employee and Labor Relations

At December 31, 2016, CONSOL Energy2017, CNX had 2,307 employees. There were no561 employees, represented by the United Mine Workersnone of America (UMWA) at December 31, 2016.which are subject to a collective bargaining agreement.

Industry Segments

Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years ended December 31, 2017, 2016 2015 and 20142015 is included in Note 2319 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K and incorporated herein.

Financial Information about Geographic Areas

All of the Company's assets and operations are located in the continental United States.



2115


Laws and Regulations

Overview

Our natural gas and coal mining operations are subject to various types of federal, state and local laws and regulations. Regulations relating to our operations include permitting, bonding and other licensing requirements; water withdrawal and procurement for well stimulation purposes; well drilling, casing and casing;hydraulic fracturing; stormwater management; well production; well plugging; venting or flaring of natural gas; pipeline compression and transmission of natural gas and liquids; reclamation and restoration of properties after natural gas or coal mining operations are completed; handling, storage, transportation and disposal of materials used or generated by natural gas and mining operations; the calculation, reporting and disbursement of taxes; gathering of natural gas production in certain circumstances; surface subsidence from underground mining; discharge of water from coal mining operations; air quality standards; protection of wetlands; crossing of waterways; endangered plant and wildlife protection; use of public roads; and employee health and safety. Numerous governmental permits, authorizations and approvals under these laws and regulations are required for natural gas and mining operations. Lastly, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our natural gas and coal products.gas.

Compliance with these laws has substantially increased the cost of natural gas production and mining of coal for all domestic natural gas and coal producers. We also post performance bonds or letters of credit pursuant to state oil and gas laws and regulations to guarantee reclamation of gas well sites and plugging of gas wells. We post surety performance bonds or letters of credit pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, often including the cost of treating mine water discharge. We endeavor to conduct our natural gas and mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements against a backdrop of variable geologic and seasonal conditions, permit exceedances and violations during natural gas and mining operations can and do occur. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on our natural gas and coal mining operations or our customers' ability to use our natural gas and coal and may require us or our customers to change their operations significantly or incur substantial costs.

CONSOL EnergyIn July 2010, U.S. Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), which established federal oversight and regulation of the over-the-counter derivative market and entities, such as the Company, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC), the SEC and other regulatory agencies to promulgate rules and regulations implementing this legislation. As of the filing date of this Annual Report on Form 10-K, the CFTC has finalized certain regulations that impose regulatory obligations on all market participants, including the Company, while other regulations remain to be finalized or implemented. Because certain CFTC rules relevant to natural gas hedging activities have yet to be promulgated, it is committednot possible at this time to complyingpredict the extent of the impact of the regulations on the Company’s hedging program or regulatory compliance obligations. The Company has experienced, and expects to continue to experience, increased compliance costs in connection with all laws and regulations. This commitment is evident in CONSOL Energy's demonstrated cost and effortchanges to abate and control pollution and/or contamination at its facilities. CONSOL Energy made capital expenditures for environmental control facilities of approximately $0.6 million, $18.4 million, and $19.0 million in the years ended December 31, 2016, 2015 and 2014, respectively. CONSOL Energy does not expectcurrent market practices as participants continue to have any capital expenditures in 2017 for environmental control facilities.adapt to a changing regulatory environment.

Environmental Laws

CNX has established protocols for ongoing assessments to identify potential environmental exposures. These assessments evaluate compliance with laws and regulations and other industry and internal best management practices, and include evaluation of compliance by waste management facilities and other third-party service providers.

Clean Air Act and Related Regulations. The federal Clean Air Act (CAA) and corresponding state laws and regulations regulate air emissions primarily through permitting and/or emissions control requirements. This affects natural gas production and processing operations. The federal CAA and corresponding state laws and regulations regulate air emissions primarily through permitting and/or emissions control requirements. This affects natural gas production and processing operations. Various activities in our operations as well as coal mining, coal handling,are subject to regulation, including pipeline compression, venting and processing.flaring of natural gas, hydraulic fracturing and completion processes, and fugitive emissions. We obtain permits, typically from state or local authorities, to conduct these activities. Additionally, we are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions. Further, some states and the federal government have proposed that emissions from certain sources should be aggregated to provide for regulation and permitting of a single, major source. Federal and state governmental agencies continue to investigate the potential for emissions from oil and natural gas activities, and further regulation could increase our cost or restrict our ability to produce.

We are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions. On August 16, 2012, the U.S. Environmental Protection Agency (EPA) published final revisions to the New Source Performance Standards (NSPS) to regulate emissions of volatile organic compounds (VOCs) and sulfur dioxide (SO2) from various oil and gas exploration, production, processing and transportation facilities. Additionally, revisions were made to the National Emission Standards for Hazardous Air Pollutants (NESHAPS) to further regulate emissions from the oil and natural gas production sector and the transmission and storage of natural gas. Section 111 of the CAA authorized the EPA to develop technology based standards which apply to specific


16


categories of stationary sources. On June 3, 2016, the EPA finalized updates to the final New Source Performance Standards (NSPS) that created new standards for the regulation of methane and VOC emission sources. The rule includes requirements for new fugitive emission and leak detection testing and reporting requirements. Also on June 3, 2016, the EPA published the final Source Determination Rule which clarified the use of the term “adjacent” in determining Title V air permitting requirements as they apply to the oil and natural gas industry for major sources of air emissions. On August 1, 2016 these updates to the NSPS were challenged in the D.C. Circuit Court of Appeals by industry and state associations and a request for administrative reconsideration was also filed. Additionally, 15 states filed suit and asked the Court of Appeals to review the need for the changes.

On November 30, 2016, the EPA finalized amendments to the Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse Gas Reporting Program (GHGRP). This final rule adds new monitoring methods for detecting leaks from oil and gas equipment in the petroleum and natural gas systems source category consistent with the leak detection methods in the NSPS. The action also adds emission factors for leaking equipment to be used in conjunction with these monitoring methods to calculate and report greenhouse gas (GHG) emissions resulting from equipment leaks. The NSPS final rule would add reporting


22


of GHG emissions from certain gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.

The CAA also indirectly and more significantly affects the U.S. coal industry by extensively regulating the air emissions of coal-fired electric power generating plants operated by our customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. Carbon dioxide (CO2), a regulated GHG, is also emitted when coal is burned. Environmental regulations governing emissions from coal-fired electric generating plants increase the costs to operate and could affect demand for coal as a fuel source and affect the volume of our sales. Moreover, additional environmental regulations increase the likelihood that existing coal-fired electric generating plants will be decommissioned, including plants to which CONSOL Energy sells coal to, and reduce the likelihood that new coal-fired plants will be built in the future.

In early 2012, the EPA promulgated or finalized several rules for New Source Performance Standards (NSPS) for coal- and oil- fired power plants which also have a negative effect on coal-generating facilities. The Utility Maximum Control Technology (UMACT) rule requires more stringent NSPS for particulate matter (PM), SO2 and nitrogen oxides (NOX) and the Mercury and Air Toxics Standards (MATS) rule requires new mercury and air toxic standards. In November 2012, the EPA published a notice of reconsideration of certain aspects of the UMACT and MATS rules. Following reconsideration in April 2013 and again in April 2014, the EPA promulgated final UMACT and MATS rules in November 2014 at which point the standards become applicable to new power plants. The final rules have higher emission limits, but the standards are still stringent and compliance with the rules is expensive.

The CAA requires the EPA to set National Ambient Air Quality Standards (NAAQS) for certain pollutants and the CAA identifies two types of NAAQS. Primary standards provide public health protection, including protecting the health of "sensitive" populations such as asthmatics, children, and the elderly. Secondary standards provide public welfare protection, including protection against decreased visibility and damage to animals, crops, vegetation, and buildings. On October 1, 2015, the EPA finalized the NAAQS for ozone pollution and reduced the limit to 70 parts per billion (ppb) from the previous 75 ppb standard. The final rule could have a large impact on both the oil and gas and coal mining industriesindustry as states would be required to update their permitting standards to meet these potentially unachievable limits. Six states have now filed a petition for review in the Court of Appeals for the D.C. Circuit.

On July 6, 2011, the EPA finalized a rule known as the Cross-State Air Pollution Rule (CSAPR). CSAPR regulates cross-border emissions of criteria air pollutants such as SO2 and NOX, as well as byproducts, fine particulate matter (PM2.5) and ozone by requiring states to limit emissions from sources that "contribute significantly" to noncompliance with air quality standards for the criteria air pollutants. If the ambient levels of criteria air pollutants are above the thresholds set by the EPA, a region is considered to be in "nonattainment" for that pollutant and the EPA applies more stringent control standards for sources of air emissions located in the region. In April 2014, the Supreme Court reversed a decision of the D.C. Circuit Court of Appeals that vacated the rule. Following remand and briefing the D.C. Circuit Court of appeals, in October 2014, granted a motion to lift a stay of the rule and allow the EPA to modify the CSAPR compliance deadline by three-years, setting the stage for issuance of the proposed rule. Implementation of CSAPR Phase 1 began in 2015, with Phase 2 scheduled to begin in 2017. On September 7, 2016, the EPA finalized an update to the CSAPR for the 2008 ozone NAAQS by issuing the final CSAPR Update. Starting in May 2017, this rule will reduce summertime (May - September) NOX emissions from power plants in 22 states in the eastern United States.

On March 27, 2012, the EPA published its proposed NSPS for CO2 emissions from new coal-powered electric generating units. The proposed rule would have applied to new power plants and to existing plants that make major modifications. If the rule had been adopted as proposed, only new coal-fired power plants with CO2 capture and storage (CCS) could have met the proposed emission limits. Commercial scale CCS is not likely to be available in the near future, and if available, it may make coal-fired electric generation units uneconomical compared to new gas-fired electric generation units. On January 8, 2014, the EPA re-proposed NSPS for CO2 for new fossil fuel fired power plants and rescinded the rules that were proposed on April 12, 2012.

On September 20, 2013, the EPA issued a new proposal to control carbon emissions from new power plants. Under the Clean Power Plan (CPP) proposal, the EPA would establish separate NSPS for CO2 emissions for natural gas-fired turbines and coal-fired units. However, in April 2017, the U.S. Court of Appeals for the D.C. Circuit granted the EPA’s motion to hold a pending appeal in abeyance while the EPA undertakes a review of the proposal. The proposed “Carbon Pollution Standard for New Power Plants” replaces the earlier proposal released by the EPA in 2012. On August 3, 2015, the EPA finalized the Carbon Pollution Standards to cut carbon emissions from new, modified and reconstructed power plants, which would have become effective on October 23, 2015.

Climate Change. Climate change continues to be a legislative and regulatory focus. There are a number of proposed and final laws and regulations that limit greenhouse gas emissions, and regulations that restrict emissions could increase our costs should the requirements necessitate the installation new equipment or the purchase of emission allowances. Additional regulation could also lead to permitting delays and additional monitoring and administrative requirements, as well as to impacts on electricity generating operations.

On June 2, 2014,November 30, 2016, the EPA proposed additional CPP legislationfinalized amendments to cut carbonthe Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse Gas Reporting Program (GHGRP). This final rule adds new monitoring methods for detecting leaks from oil and gas equipment in the petroleum and natural gas systems source category consistent with the leak detection methods in the NSPS. The action also adds emission factors for leaking equipment to be used in conjunction with these monitoring methods to calculate and report greenhouse gas (GHG) emissions resulting from existing power plants. Under this proposedequipment leaks. The NSPS final rule the EPA would create emission guidelines for states to follow in developing plans to addressadd reporting of GHG emissions from existing fossil fuel-fired electric generating units. Specifically, the EPA is proposing state-specific rate-based goals for CO2 emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve the state-specific goals.


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On August 3, 2015, the EPA finalized the CPP Rule to cut carbon pollution from existing power plants, which would have become effective on December 22, 2015. Numerous petitions challenging the CPP Rule have been consolidated into one case, West Virginia v. EPA. While the litigation is still ongoing at the circuit court level, a mid-litigation application to the Supreme Court resulted in a staycertain gathering and boosting systems, completions and workovers of the Clean Power Plan Rule. On September 27, 2016, the en banc D.C. Circuit heard oral argument in the caseoil wells using hydraulic fracturing, and a decision is expected in early 2017.blowdowns of natural gas transmission pipelines.

Clean Water Act. The federal Clean Water Act (CWA) and corresponding state laws affect our natural gas and coal operations by regulating discharges into surface waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. The CWA and corresponding state laws include requirements for: improvement of designated "impaired waters" (i.e., not meeting state water quality standards) through the use of effluent limitations; anti-degradation regulations which protect state designated "high quality/exceptional use" streams by restricting or prohibiting discharges; requirements to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids; requirements to minimize impacts and compensate for unavoidable impacts resulting from discharges of fill materials to regulated streams and wetlands;stormwater controls; and requirements to dispose of produced wastes and other oil and gas wastes at approved disposal facilities. In addition,These requirements impact the development of infrastructure, well-drilling, and hydraulic


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fracturing operations. The CWA and similar state laws provide for civil, criminal and administrative penalties for unauthorized discharges of pollutants or reportable quantities of oil and/or other hazardous substances. The Spill Prevention, Control and Countermeasure (SPCC) requirements of the CWA apply to all CONSOL Energy operations that use or produce fluids of threshold quantities and require the implementation of plans to address any spillsprevent and the installation of secondary containment around all storage tanks.contain spills. These requirements (or changes to current regulations) may cause CONSOL EnergyCNX to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.

Pursuant to a Congressional requirement in the EPA's 2010 budget appropriation, the EPA must conduct a comprehensive study of the potential adverse impact that hydraulic fracturing may have on water quality and public health. Hydraulic fracturing is a way of producing natural gas from tight rock formations such as the Marcellus shale and Utica shale. The EPA initiated the study in early January 2011 and the final assessment report was published on June 4, 2015. The draft report stated that hydraulic fracturing activities have not led to widespread, systemic impacts to drinking water resources. On December 13, 2016, the EPA released its final report on the impacts of hydraulic fracturing on drinking water. While the language was changed and included the possibility of impacts from hydraulic fracturing, it also included the guidance to industry and regulators on how the process can be done safely.

CONSOL EnergyCNX utilizes pipelines extensively for its natural gas water and coalwater businesses. Mitigation permits from the Army Corps of Engineers (ACOE) are typically required for certain impacts these pipelines cause to streams and wetlands, including the crossing of such streams and wetlands. On April 21, 2014 the EPA published a proposed rule called “DefinitionAny expansion of ‘Waters of the United States’ (WoUS) Under the Clean Water Act.” The proposal would expand the scope of the CWAregulation of pipeline development to include previously non-jurisdictional streams, wetlands and waters, making these areas jurisdictional inter-coastal waters of the U.S. In February 2015 the EPAcould adversely affect our operating results, financial condition and ACOE issued a memorandum of understandingcash flows.

Endangered Species Act. The Endangered Species Act and related state regulation protect plant and animal species that are threatened or endangered. New or additional species that may be identified as requiring protection or consideration may lead to withdraw the WoUS Interpretive Rule. The EPA published the latest version of the WoUS rule (the Clean Water Rule) on June 29, 2015, which was to become effective on August 28, 2015. However, on August 27, 2015, the District Court of North Dakota blocked implementation of the ruledelays in 13 states. On October 9, 2015, the Court of Appeals for the Sixth Circuit blocked implementation of the rule nationwide. The U.S. Supreme Court will now decide which court has jurisdiction - federal appeals court permits and/or district courts. A decision is expected sometime in mid 2017.other restrictions.

Safety of Gas Transmission and Gathering Pipelines. On April 8, 2016, The U.S. Department of Transportation (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) published in the Federal Register a Notice of Proposed Rule Making (NPRM) that would significantly modify existing regulations related to reporting, impact, design, construction, maintenance, operations and integrity management of gas transmission and gathering pipelines. The proposed rule addresses four congressional mandates and six recommendations by the National Transportation Safety Board. The proposed rule broadens the scope of safety coverage both by adding new assessment and repair criteria for gas transmission pipelines, and by expanding these protocols to include pipelines not formerly regulated by the federal standards. This means extending regulatory requirements to transmission and gathering pipelines of 8eight inches and greater in rural class 1 areas, which could increase timeframestime frames and cost to complete projects. It is unclear what action may be taken on this proposal in the new administration. Additionally, certain states, such as West Virginia, also maintain jurisdiction over intrastate natural gas lines.

Resource Conservation and Recovery Act. The federal Resource Conservation and Recovery Act (RCRA) and corresponding state laws and regulations affect natural gas operations and coal mining by imposing requirements for the management, treatment, storage and disposal of hazardous wastes.and non-hazardous wastes, including wastes generated by natural gas operations. Facilities at which hazardous wastes have been treated, stored or disposed of are subject to corrective action orders issued by the EPA that could adversely affect our financial results, financial condition and cash flows. On December 28, 2016 the EPA entered into a consent order to resolve outstanding litigation brought by environmental and citizen groups regarding the applicability of RCRA to wastes from oil and gas development activities. The consent order requires the EPA to revise the applicability determination by March 15, 2019.



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In 2010, the EPA proposed options for the regulation of Coal Combustion Residuals (CCRs) from the electric power sector as either hazardous waste or non-hazardous waste. On December 19, 2014, the EPA announced the first national regulations for the disposal of CCRs from electric utilities and independent power producers under RCRA. On April 17, 2015, the EPA finalized these regulations under the solid waste provisions (Subtitle D) of RCRA and not the hazardous waste provisions (Subtitle C) which became effective on October 19, 2015. The EPA affirms in the preamble to the final rule that “this rule does not apply to CCR placed in active or abandoned underground or surface mines.” Instead, “the U.S. Department of Interior (DOI) and the EPA will address the management of CCR in mine fills in a separate regulatory action(s).” On November 3, 2015, the EPA published the final rule Effluent Limitations Guidelines and Standards (ELG), revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. The combined effect of the CCR and ELG regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal burning power plants that can’t comply with the new standards.

Surface Mining Control and Reclamation Act. The federal Surface Mining Control and Reclamation Act (SMCRA) establishes minimum national operational and reclamation standards for all surface mines, as well as most aspects of underground mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. Permits for all mining operations must be obtained from the U.S. Office of Surface Mining (OSM) or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards which are more stringent than the requirements of SMCRA and OSM's regulations and in many instances have done so. Our active mining complexes are located in Pennsylvania which has primary jurisdiction for enforcement of SMCRA through its approved state program. In addition, SMCRA imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund (AML Fund), which is used to restore unreclaimed and abandoned mine lands mined before 1977. The current per ton fee is $0.28 per ton for surface mined coal and $0.12 per ton for underground mined coal. These fees are currently scheduled to be in effect until September 30, 2021.

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. Surety bond costs have increased while the market terms of surety bonds have generally become less favorable. It is possible that surety-bond issuers may refuse to renew bonds or may demand additional collateral. Any failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could adversely affect our business, financial condition, results of operations, liquidity and cash flows.

Excess Spoil, Coal Mine Waste, Diversions, and Buffer Zones for Perennial and Intermittent Streams. The OSM has issued final amendments to regulations concerning stream buffer zones, stream channel diversions, excess spoil, and coal mine waste to comply with an order issued by the U.S. District Court for the District of Columbia on February 20, 2014, which vacated the stream buffer zone rule that was published December 12, 2008. On July 27, 2015, the OSM published the proposed Stream Protection Rule (SPR). After much debate and thousands of comments, the final SPR was published by the OSM in the Federal Register on December 20, 2016. The final SPR requires the restoration of the physical form, hydrologic function, and ecological function of the segment of a perennial or intermittent stream that a permittee mines through. Additionally, it requires that the post-mining surface configuration of the reclaimed mine site include a drainage pattern, including ephemeral streams, similar to the pre-mining drainage pattern, with exceptions for stability, topographical changes, fish and wildlife habitat, etc. The rule also requires the establishment of a 100-foot-wide streamside vegetative corridor of native species (including riparian species, when appropriate) along each bank of any restored or permanently-diverted perennial, intermittent, or ephemeral stream. This rulemaking is highly anticipated to be subject to Legislative and Executive branch actions to overturn or significantly modify the rule.

Federal Regulation of the Sale and Transportation of Natural Gas

Regulations and orders set forthissued by the Federal Energy Regulatory Commission (FERC) impact our natural gas business to a certain degree. Although the FERC does not directly regulate our natural gas production activities, the FERC has stated that it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the FERC continues to review itshas jurisdiction over the transportation regulations,of natural gas in interstate commerce, and regulates the terms, conditions of service, and rates for the interstate transportation of our natural gas production. The FERC possesses regulatory oversight over natural gas markets, including whether to allocate all short-term capacity on the basis of competitive auctions and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts.anti-market manipulation regulation. The FERC has also issued numerous orders confirming the saleability to assess civil penalties, order disgorgement of profits and abandonmentrecommend criminal penalties for violations of the Natural Gas Act or the FERC’s regulations and policies thereunder.
Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities previously ownedfrom regulation by interstate pipelines and acknowledging that if the FERC does not have jurisdiction over services provided by these facilities, then suchFERC. However, the distinction between federally unregulated gathering facilities and services may beFERC-regulated transmission facilities is a fact-based determination, and the classification of facilities is the subject to regulation by state authorities in accordance with state law.of ongoing litigation. We own certain natural gas pipeline facilities that we believe meet the traditional tests which the FERC has used to establish a pipeline's status as a gatherer not subject to the FERC jurisdiction.



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Natural gas prices are currently unregulated, but Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas sales might be enacted in the future or what effect, if any, any such legislation might have on our operations.

Health and Safety Laws

Occupational Safety and Health Act. Our natural gas operations are subject to regulation under the federal Occupational Safety and Health Act (OSHA) and comparable state laws in some states, all of which regulate health and safety of employees at our natural gas operations. Also,Additionally, OSHA's hazardous communication standard, requiresthe EPA community right-to-know


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regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state laws require that information be maintained about hazardous materials used or produced by our natural gas operations and that this information be provided to employees, state and local governments and the public.

Mine Safety. Legislative and regulatory changes have required us to purchase additional safety equipment, construct stronger seals to isolate mined out areas, and engage in additional training. We have also experienced more aggressive inspection protocols and with new regulations the amount of civil penalties has increased. The actions taken thus far by federal and state governments include requiring:

the caching of additional supplies of self-contained self-rescuer (SCSR) devices underground;
the purchase and installation of electronic communication and personal tracking devices underground;
the 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.

On October 2, 2015, the Mine Safety and Health Administration (MSHA) published proposed rules for underground coal mining operations concerning proximity detection systems for coal hauling machines and scoops. On January 15, 2015, MSHA published a final rule requiring underground coal mine operations to equip continuous mining machines, except full-face continuous mining machines, with proximity detection systems. The proximity detection system strengthens protection for miners by reducing the potential of pinning, crushing and striking hazards that result in accidents involving life-threatening injuries and death. The final rule became effective March 15, 2015 and included a phased in schedule for newly manufactured and in-service equipment. In 2010 MSHA rolled out the “End Black Lung, Act Now” initiative. As a result, MSHA implemented a new final rule on August 1, 2014 to lower miners’ exposure to respirable coal mine dust including using the new Personal Dust Monitor (PDM) technology. This final rule was implemented in three phases. The first phase began August 1, 2014 and utilizes the current gravimetric sampling device to take full shift dust samples from the current designated occupations and areas. It also requires additional record keeping and immediate corrective action in the event of overexposure. The second phase began February 1, 2016 and requires additional sampling for designated and other occupations using the new continuous personal dust monitor (CPDM) technology, which provides real time dust exposure information to the miner. CONSOL Energy ordered the necessary CPDM equipment required to meet compliance with the new rule at a cost of $2 million. We also hired Dust Coordinators and Dust Technicians to meet the staffing demand to manage compliance with the new rule. The final phase of the rule was effective on August 1, 2016. when the current respirable dust standard was reduced from 2.0 to 1.5mg/m3 for designated occupations and from 1.0 to 0.5mg/m3 for Part 90 Miners.
Black Lung Legislation. Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to:

current and former coal miners totally disabled from black lung disease;
certain survivors of a coal miner who dies from black lung disease or pneumoconiosis; and
a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a coal miner's last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

The Patient Protection and Affordable Care Act (PPACA) made two changes to the Federal Black Lung Benefits Act. First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and suffer from a totally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner's work. Second, it changed the law so black lung benefits will continue to be paid to dependent survivors when the miner passes away, regardless of the cause of the miner's death. The changes have increased the


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cost to CONSOL Energy of complying with the Federal Black Lung Benefits Act. In addition to the federal legislation, we are also liable under various state statutes for black lung claims.

Other State and Local Laws Related to Our Natural Gas Business

Regulation Affecting Gas Operations. Our natural gas operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the siting and construction of well pads, impoundments, tanks and roads,roads; pooling and unitizations; drilling of wells,wells; bonding requirements,requirements; protection of ground water and surface water resources and protection of drinking water supplies,supplies; the method of drilling and casing wells,wells; the surface use and restoration of well sites,sites; gas flaring,flaring; the plugging and abandoning of wells,wells; the disposal of fluids used in connection with operationsoperations; and natural gas operations producing coalbed methane in relation to active mining. A number of states have either enacted new laws or may be considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory take requirements but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. Our gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although we do not believe that they would be affected by such regulation any differently than other natural gas producers or gatherers. However, these regulatory burdens may affect profitability, and we are unable to predict the future cost or impact of complying with such regulations.

Regulation of Horizontal Drilling. State regulations for horizontal well drilling and well site construction have been proposed and finalized. In September 2015, Pennsylvania published a final rulemaking on the revisions to the Environmental Protection Performance Standards at Oil and Gas Well Sites (Chapters 78 and 78a). Chapter 78 rules affecting conventional drillers were eliminated under SB279, and may be readdressed by the Pennsylvania Department of Environmental Protection in 2018. Chapter 78a rules are the subject of pending litigation, with oral argument before the Pennsylvania Supreme Court in October 2017. Ohio passed Horizontal Well Site Construction Rules which became effective in July 2015. Ohio is also in the process of reviewing and possibly adopting additional horizontal development rules. Additionally, West Virginia adopted Rules Governing Horizontal Well Development.

Ownership of Mineral Rights. CONSOL EnergyCNX acquires ownership or leasehold rights to oil and gas properties and coal properties prior to conducting operations on those properties. The legal requirements of such ownership or leasehold rights generally are established by state statutory or common law. As is customary in the natural gas and coal industries,industry, we have generally conducted only a summary review of the title to oil and gas rights and coal rights that are not yet in our development plans, but which we believe we control. This summary review is conducted at the time of acquisition or as part of a review of our land records to determine control of mineral rights. Given CONSOL Energy's long history as a coal producer, we believe we have a well-developed ownership position relating to our coal control; however,records. However, our ownership of certain oil and gas rights, particularly those rights that we acquired in connection with our historic coal operations and some of the rights we acquired in 2010, as part of an acquisition, aremay be less developed. As we continue to conduct our standard review ourof land records and confirm title in anticipation of development, we expect that adjustments to our ownership position (either increases or decreases) will be required.

Prior to the commencement of development operations on natural gas and coalcoalbed methane properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. We generally will not commence operations on a property until we have cured any material title defects on such property. We are typically responsible for the cost of curing any title defects. In addition, the acquisition of the necessary rights to affect such a cure may not be feasible in some cases. Our discovering natural gas title defects which we are unable to cure may adversely impact our ability to develop those properties and we may have to reduce our estimated gas reserves including our proved undeveloped reserves. WeIn accordance with the foregoing, we have completed title work on substantially all of our natural gas and coalcoalbed methane properties that are currently producing, properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry.

Available Information

CONSOL EnergyCNX maintains a website on the World Wide Web at www.consolenergy.com. CONSOL Energywww.cnx.com. CNX makes available, free of charge, on this website our annual reportreports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, of 1934, as amended (the 1934 Act), as soon as reasonably practicable after such reports are available, electronically filed with, or furnished to the SEC, and are also available at the SEC's website www.sec.gov. Apart from SEC filings, we also use our website to publish information which may be important to investors, such as presentations to analysts.






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Executive Officers of the Registrant

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



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ITEM 1A.Risk Factors

Investment in our securities is subject to various risks, including risks and uncertainties inherent in our business. The following sets forth factors related to our business, operations, financial position or future financial performance or cash flows which could cause an investment in our securities to decline and result in a loss.
Deterioration in the global economic conditions in any of the industries in which our customers operate, or a worldwide financial downturn, or negative credit market conditions may have a materially adverse effect on our liquidity, results of operations, business and financial condition that we cannot predict.
Economic conditions in a number of industries in which our customers operate, such as electric power generation and steel-making, substantially deteriorated in recent years and reduced the demandPrices for natural gas and coal. The general economic challenges for some of our customers continued in 2016 and the outlook is uncertain. In addition, liquidity is essential to our business and developing our assets. Renewed or continued weakness in the economic conditions of any of the industries we serve or are served by our customers could adversely affect our business, financial condition, results of operation and liquidity in a number of ways. For example:

demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas and thermal coal business;
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.

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 and natural gas liquids and coal will adversely affect our business, operating results, financial condition and cash flows.

Our financial results are significantly affected by the prices we receive for our natural gas natural gas liquids and coal.
Our E&P division’s products (natural gas, natural gas liquids, oil and condensate) accounted for approximately 42% of the total company outside sales revenues from continuing operations in 2016, with natural gas and natural gas liquids representing 97% of the E&P division’s outside sales revenues.liquids. Natural gas, natural gas liquids, oil and condensate prices are very volatile and can fluctuate widely based upon supply from energy producers relative to demand for these products and other factors beyond our control. The sale to Murray Energydisposition in 2013 of almost one half2017 of our thermalentire coal production and the sale of our Buchanan Mine in 2016operations has increased our exposure to fluctuations in the price of natural gas, natural gas liquids, oil and condensate.

In particular, while demand for natural gas has recovered to pre-recession levels, the U.S. natural gas industry continues to face concerns of oversupply due to the success of Marcellus and other new shale plays. The oversupply of natural gas in 2012 resulted in domestic prices hovering around ten year lows, and drilling continued in these plays, despite these lower gas prices, to meet drilling commitments. Although gas prices recovered somewhat during 2013 and the first quarter of 2014, they again significantly declined in the latter part of 2014 due to oversupply and have remained at depressed levels throughout 2015 and 2016.

since 2015.
Our natural gas operationsproducing properties are geographically concentrated in the mid-Atlantic states.Appalachian Basin, which exacerbates the impact of regional supply and demand factors on our business, including the pricing of our gas. The success of the Marcellus Shale and Utica plays has resulted in growth in natural gas production in this region, with production per day in Pennsylvania, West Virginia and Ohio more than doublingtripling since 2011. Traditionally,Not all of the natural gas produced in the mid-Atlantic statesthis region can be consumed by regional demand and must therefore be exported to other regions through pipelines. This export causes gas purchased and sold locally to be priced at a premiumdiscount to many other market hubs, such as the benchmark Louisiana Henry Hub prices. However, as Appalachian production increased this premium narrowed and during 2014 and continuing into 2015 and 2016, the spot prices at some Appalachian hubs fell below Henry Hub prices.price. This decline,discount, or negative basis, to the Henry Hub price is forecasted to continue in future years. The oversupply inWhile we expect many of the Appalachian Basin may persistplanned interstate pipeline projects to reduce this discount, it could widen further if current pipelinethese projects to move gas out of the basin are delayed byfor any reason, such as permitting issues or environmental lawsuits.

An extended period of lower natural gas prices can negatively affect us in several other ways. These include reduced cash flow, which decreases funds available for capital expenditures to replace reserves or increase production. For example, in light of the low natural gas prices continuing from 2014 intothrough 2015, we substantially decreasedresulted in our decreasing 2016 and 2017 capital expenditures and the drilling of new shale wells. In 2017, we expect our capital expenditures to increase to approximately $555 million from $227


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million in 2016. Also, our access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable. Additionally, lower natural gas prices may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management's
Our drilling plans change with respect to those assets. For example, in the second quarter of 2015, we had an impairment charge of approximately $829 million for our natural gas assets, primarily shallow oil and gas assets. We may incur impairment charges in the future, which could have an adverse effect on our results of operations in the period taken.

We have increased developmentalso include some activity in areas of shale formations whichthat may also contain natural gas liquids, condensate and/or oil. The prices for natural gas liquids, condensate and oil are also volatile for reasons similar to those described above regarding natural gas. As a result of increasing supply, condensate and oil prices have exhibited great volatility. In addition, similar to the oversupply of natural gas, increased drilling activity by third-parties in formations containing natural gas liquids has led to a decline of over 60%30% since 2014 in the uplift we receive, on an Mcfe equivalent basis when excluding hedging impact, from natural gas liquids. Our results of operation may be adversely affected by a continued depressed level of, or further downward fluctuations in, natural gas liquids, condensate and oil prices.

Apart from issues with respect to the supply of products we produce, demand can fluctuate widely due to a number of matters beyond our control, including:

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;
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;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 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.

The coal industry also faces concerns with respect to oversupply from time to time. For example, U.S. coal exports decreased by 32% during the first half of 2016 compared with the first half of 2015, as global supply exceeded demand for both thermal and metallurgical coal. Our average sales price per ton sold in 2016 declined 23% from 2015 due to imbalanced supply and demand, and a substantial or extended decline in the prices we receive for our coal could adversely affect our business, results of operations, financial condition, cash flows and liquidity.
Foreign currency fluctuations could adversely affect the competitiveness of our coal and natural gas liquids abroad.

We compete in international markets against coal produced in other countries. Coal is sold internationally in U.S. dollars and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our foreign competitors with a competitive advantage. As a result, mining costs in competing producing countries may be reduced in U.S. dollar terms based on currency exchange rates, providing an advantage to foreign coal producers. If our competitors’ currencies decline against the U.S. dollar or against our foreign customers’ local currencies, those competitors may be able to continue to offer lower prices for coal to our customers. Furthermore, if the currencies of our overseas customers were to significantly decline in value in comparison to the U.S. dollar, those customers may seek decreased prices for the coal we sell to them. We also expect in the future that an international market will develop for exporting domestic natural gas and natural gas liquids. Consequently, currency fluctuations could adversely affect the competitiveness of our products in international markets, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.





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If our coal customers do not extend existing contracts or do not enter into new multi-year coal sales contracts on favorable terms, profitability of CONSOL Energy's operations could be adversely affected.

During the year ended December 31, 2016, approximately 65% of the coal CONSOL Energy produced from continued operations was sold under multi-year sales contracts. If a substantial portion of our multi-year sales contracts are modified or terminated, if force majeure is exercised, or if we are unable to replace or extend the contracts or new contracts are priced at lower levels, our profitability would be adversely affected. The profitability of our multi-year sales coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production costs and other factors. Price changes, if any, provided in long-term supply contracts may not reflect our cost increases, and therefore, increases in our costs may reduce our profit margins. In addition, during periods of declining market prices, provisions in our long-term coal contracts for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price and electric power price volatility. As a result, we may not be able to obtain long-term agreements at favorable prices compared to either market conditions, as they may change from time to time, or our cost structure, which may reduce our profitability.

The loss of, or significant reduction in, purchases by our largest coal customers or the failure of any of our customers to buy and pay for coal they committed to purchase could adversely affect our business, financial condition, results of operation and cash flows.

For the year ended December 31, 2016, we derived over 10% of our coal sales revenue from two coal customers individually and approximately 40% of our total sales revenue were derived from our four largest coal customers. At December 31, 2016, we had approximately nine coal supply agreements with these top two customers that expire at various times from 2017 to 2018. There are inherent risks whenever a significant percentage of total revenues are concentrated with a limited number of customers. Revenues from our largest customers may fluctuate from time to time based on numerous factors, including market conditions, which may be outside of our control. If any of our largest customers experience declining revenues due to market, economic or competitive conditions, we could be pressured to reduce the prices that we charge for our coal, which could have an adverse effect on our margins, profitability, cash flows and financial position. In addition, if any customers were to significantly reduce their purchases of coal from us, including by failing to buy and pay for coal they committed to purchase in sales contracts, our business, financial condition, results of operations and cash flows could be adversely affected.

Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.

Our ability to receive payment for natural gas and coal sold and delivered depends on the continued creditworthiness of our customers. Many utilities have sold their power plants to non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear with respect to payment default. These new power plant owners may have credit ratings that are below investment grade. In addition, some of our customers have been adversely affected by the current economic downturn, which may impact their ability to fulfill their contractual obligations. Competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear with respect to payment default. We also have a contract to supply coal to an energy trading and brokering customer under which that customer sells coal to end users. If the creditworthiness of our energy trading and brokering customer declines, we may not be able to collect payment for all coal sold and delivered to this customer. If the creditworthiness of our customers declines significantly, our business could be adversely affected. In addition, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customers’ contractual obligations are honored. Our inability to collect payment from counterparties to our sales contracts may have a materially adverse effect on our business, financial condition, results of operations and cash flows.

Our natural gas business depends on gathering, processing and transportation facilities and other midstream facilities owned by othersCNXM and theothers. The disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas and natural gas liquids. Similarly, theliquids, and any decrease in availability and reliability of transportationthird-party pipelines or other midstream facilities and fluctuationsinterconnected to third parties’ or CNXM’s gathering systems could adversely affect our operations or our investment in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.

CNXM.
We gather, process and transport our natural gas to market by utilizing pipelines and facilities owned by others.others, including CNXM. If pipeline or facility capacity is limited, or if pipeline or facility capacity is unexpectedly disrupted for any reason, our natural gas sales and/or sales of natural gas liquids could be limited, reducingreduced, which could negatively affect our profitability. If we cannot access processing pipeline transportation facilities, we may have to reduce our production of natural gas. If our sales of natural gas or natural gas liquids are reduced because of transportation or processing constraints, our revenues will be reduced and our unit costs will also increase. If pipeline quality standards change, we might be required to install additional processing equipment which could increase our


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costs. The pipeline could also curtail our flows until the natural gas delivered to their pipeline is in compliance. Any reduction in our production of natural gas or increase in our costs could materially adversely affect our business, financial condition, results of operations and cash flows.

Further, a significant portion of our natural gas is sold on or through a single pipeline, Texas Eastern Transmission, which could experience capacity issues, operational disruptions and unexpected downtime. Any reduction in capacity on the Texas Eastern pipeline could result in curtailments and reduce our production of natural gas. A reduction in capacity could also reduce the demand for our natural gas, which would reduce the price we receive for our production.
Additionally, we have various third-party firm transportation, natural gas processing, gathering and other agreements in place, many of which have minimum volume delivery commitments. Lower commodity prices may lead to reductions in our drilling program, which may result in insufficient production to utilize our full firm transportation and processing capacity. We are obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput. Reductions in our drilling program may result in insufficient production to utilize our full firm transportation and processing capacity. If we have insufficient production to meet the minimum volumes, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect our business, financial condition, results of operations and cash flows.
Our investment in midstream infrastructure through CNXM is intended to connect our wells to other existing gathering and transmission pipelines. Our infrastructure development and maintenance programs, through CNXM, can involve significant risks, including those relating to timing, cost overruns and operational efficiency, which risks can be further affected by other issues. For example, approximately 41% of our 2017 production flowed through CNXM’s Majorsville and McQuay Stations. An operational issue at either of those stations would materially impact CNX’s production, cash flow and results of operation. CNXM’s assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of third-party pipelines, processing and fractionation plants, compressor stations and other midstream facilities is not within our or CNXM’s control. These third-party pipelines, processing and fractionation plants, compressor stations and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, changes to operating conditions, delivery or receipt parameters, unavailability of firm transportation, lack of operating capacity, force majeure events, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues.
We face uncertainties in estimating our economically recoverable natural gas reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.
Natural gas reserves are economically recoverable when the price at which they are expected to be sold exceeds their expected cost of production and sales. Natural gas reserves require subjective estimates of underground accumulations of natural gas assumptions concerning natural gas prices, production levels, reserve estimates and operating and development costs. As a result, estimated quantities of proved natural gas reserves and projections of future production rates and the timing of development expenditures may be incorrect. For example, a significant amount of our proved undeveloped reserves extensions and discoveries during the last three years were due to the addition of wells on our Marcellus Shale acreage more than one offset location away from existing production with reliable technology, which may be more susceptible to positive and negative changes in reserve estimates than our proved developed reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing and production. Also, we make certain assumptions regarding natural gas prices, production

Transportation logistics play an important role

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levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our natural gas reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of natural gas reserves based on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in allowingthe actual quantities of natural gas we ultimately recover being different from reserve estimates. The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved natural gas reserves on historical average prices and costs. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:
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 timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. If natural gas prices decline by $0.10 per Mcf, then the pre-tax present value using a 10% discount rate of our proved natural gas reserves as of December 31, 2017 would decrease from $4.1 billion to supply coal$3.9 billion.
Each of the factors which impacts reserve estimation may in fact vary considerably from the assumptions used in estimating the reserves. For these reasons, estimates of natural gas reserves may vary substantially. Actual production, revenues and expenditures with respect to our customers. Any significant delays, interruptionsnatural gas reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual natural gas reserves.
Drilling natural gas wells is a high-risk activity.
Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that an encountered well does not produce in sufficient quantities to make the well economically viable. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or other limitationscanceled as a result of a variety of factors beyond our control, including those discussed in “Our operations are subject to operating risks...” set forth below.

Our future drilling activities may not be successful, and if they are unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate within a particular geographic area may decline. We may be unable to drill identified or budgeted wells within our expected time frame, or at all. We may be unable to drill a particular well because, in some cases, we identify a drilling location before we have leased all of the abilityinterests required to transportdrill the well in that location. Similarly, our coal could negatively affect our operations. Our coal is transporteddrilling schedule may vary from our mining complex by rail, truckcapital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a combinationnumber of these methods. To reach marketsfactors, including:

the results of delineation efforts and end customers, 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
our coal may also be transported by barge or by ocean vessels loaded at terminals. Disruption of transportation services because of weather-related problems, strikes, lock-outs, terrorism, governmental regulation, third-party action or other events could temporarily impairfinancial resources and results.

Our business strategy focuses on horizontal drilling and production in the Marcellus and Utica Shale plays in the Appalachian Basin. Drilling horizontal wells is technologically difficult and involves risks relating to our ability to supply coalfracture stimulate the planned number of stages and to customerssuccessfully run casing the length of the well bore and involves a higher risk of failure. Additionally, drilling a horizontal well involves higher costs, which results in the risks of our drilling program being spread over a smaller number of wells, and that, in order to be economic, each horizontal well will need to produce at a higher level in order


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to cover the higher drilling costs. Similarly, the average lateral length of the horizontal wells we drill has generally been increasing. Longer-lateral wells are typically more expensive and require more time for preparation and permitting. In addition, we use multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our profitability. In addition, transportation costsoverall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by drilling horizontal wells using multi-well pads, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program.

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.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant portionpart of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the deliveredavailability and cost of coalcapital, drilling and asproduction costs, the acquisition on acceptable terms of any leasehold interests we do not control necessary to complete the drilling unit, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory and zoning approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled. We will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful or result the cost of delivery is a critical factorin our ability to add additional proved reserves or may result in a customers’ purchasing decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuation in the pricedownward revision of diesel fuel and demurrage, could make our coal less competitive. Any disruption of the transportation services we use or increase in transportation costsestimated proved reserves, which could have a materially adverse effect on our business financial condition, results of operations and cash flows.

Competition within the natural gas and coal industries may adversely affect our ability to sell our products. Increased competition or a loss of our competitive position could adversely affect our sales of, or our prices for, our natural gas and coal products, which could impair our profitability.

The natural gas industry is intensely competitive with companies from various regions of the United States. We compete with these companies and we may compete with foreign companies for domestic sales. Many of the companies we compete with are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, our operating results and financial position may be adversely affected. In addition, larger companies may be able to pay more to acquire new natural gas properties for future exploration, limiting our ability to replace the natural gas we produce or to grow our production. Our ability to acquire additional properties and to discover new natural gas resources also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.

We compete with other coal producers primarily on the basis of price, coal quality, transportation costs and reliability. We compete with coal producers in various regions of the United States and with some foreign coal producers for domestic sales primarily to electric power generators. Demand for our thermal coal by our principal electric power generator customers is affected by the delivered price of competing coals, other fuel supplies and alternative generating sources, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric and wind power. The domestic coal industry has experienced consolidation in recent years, including consolidation among some of our major competitors. In addition, substantial overcapacity exists in the coal industry and most large coal companies have filed bankruptcy proceedings which could enable them to lower their production costs and thereby reduce the price for their coal. We cannot assure you that the result of current or further consolidation in the coal industry or current or future bankruptcy proceedings of our coal competitors will not adversely affect our competitive position. We also compete with both domestic and foreign coal producers for sales in international markets. We sell coal to foreign electricity generators, which sales are significantly affected by international demand and competition. Potential changes to international trade agreements, trade concessions or other political and economic arrangements may benefit coal producers operating in countries other than the United States. We cannot assure you that we will be able to compete on the basis of price or other factors with companies that in the future may benefit from favorable foreign trade policies or other arrangements.

Any reduction in our ability to compete in natural gas or coal markets could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The characteristics of coal may make it costly for electric power generators and other coal users to comply with various environmental standards regarding the emissions of impurities released when coal is burned which could cause utilities to replace coal-fired power plants with alternative fuels. In addition, various incentives have been proposed to encourage the generation of electricity from renewable energy sources. A reduction in the use of coal


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for electric power generation could decrease the volume of our domestic coal sales and adversely affect our results of operations.

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air along with fine particulate matter and carbon dioxide when it is burned. Complying with regulations on these emissions can be costly for electric power generators. For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase) or switch to other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which electric power generators switch to alternative fuel could materially affect us. Recent EPA rulemaking proceedings requiring additional reductions in permissible emission levels of impurities by coal-fired plants will likely make it more costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative for electric power generation in the future. Examples are (i) implementation of Phase 1 of the Cross-State Air Pollution Rule (CSAPR) that began in May 2015 with implementation of Phase 2 planned to begin in 2017; (ii) on December 3, 2015 the EPA issued the proposed CSAPR Update Rule to require reductions of seasonal nitrogen oxides (NOX) emissions from power plants in 23 of the original 28 proposed Eastern states to address interstate ozone air quality impacts for downwind states; (iii) on October 1, 2015 the EPA finalized a revised National Ambient Air Quality Standards (NAAQS) for ozone pollution and reduced the limit to 70 parts per billion from the previous 75 parts per billion standard; and (iv) promulgation in 2011 of the Utility Maximum Achievable Control Technology (Utility MACT) rule, better known as the Mercury and Air Toxics Standard (MATS) rule, which included more stringent new source performance standards (NSPS) for particulate matter (PM), mercury, sulfur dioxide (SO2) and nitrogen oxides (NOX), for new and existing coal-fired power plants (amended in November 2014). On June 29, 2015, the U.S. Supreme Court rejected the EPA MATS rule, ruling that the agency unreasonably overlooked the costs associated with the regulation, and sent the rule back to the D.C. Circuit Court to determine whether to remand and allow the EPA to address the rule's deficiencies or to vacate and nullify the rule; nevertheless most coal-fired electric power generators have already taken steps to comply with the rule. Six states have filed petitions for review of the new EPA NAAQS ozone pollution standard with the D.C. Circuit Court.

On October 14, 2014, the EPA Clean Water Act Section 316(b) rulemaking went into effect which requires new and existing power plants, including coal and natural gas-fired plants to reduce fish mortality caused by their cooling water intake structures through either the installation of technologies or the reduction of intake velocity.

Apart from actual and potential regulation of emissions, waste water, and solid wastes from coal-fired plants, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reductions in the amount of coal consumed by domestic electric power generators as a result of current or new standards for the emission of impurities or incentives to switch to alternative fuels or renewable energy sources could reduce the demand for our coal, thereby reducing our revenues and adversely affecting our business and results of operations.

Regulation of greenhouse gas emissions may increase our operating costs and reduce the value of our natural gas and coal assets and such regulation, as well as uncertainty concerning such regulation, could adversely impact the market for natural gas, and coal, as well as for our securities.

While climate change legislation in the U.S. is unlikely in the next several years, the issue of global climate change continues to attract considerable public and scientific attention with widespreadunderlying concern about the impacts of human activity, especially the emissions of greenhouse gases (GHGs) such as carbon dioxide and methane. Combustion of fossil fuels, such as the natural gas and coal we produce, results in the creation of carbon dioxide emissions into the atmosphere by natural gas and coal end-users, such as coal-fired electric power generation plants. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Other states have elected to participate in voluntary regional cap-and-trade programs like the Regional Greenhouse Gas Initiative (RGGI) in the northeastern U.S.



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The EPA, under the Climate Action Plan, has elected to regulate GHGs under the Clean Air Act (CAA) to limit emissions of carbon dioxide (CO2) from coal-fired and natural gas-fired power plants. On September 20, 2013, the EPA re-proposed New Source Performance Standards (NSPS) for CO2 from new power plants and on June 2, 2014, the EPA re-proposed NSPS for CO2 from existing and modified/reconstructed power plants, which rescinded the rules that were originally proposed in 2012. On August 3, 2015, the EPA finalized the Carbon Pollution Standards to cut carbon emissions from new, modified and reconstructed power plants, which became effective on October 23, 2015. In another proposed rulemaking related to CO2 emissions, on June 2, 2014, the EPA proposed the Clean Power Plan Rule to cut carbon emissions from existing power plants. Under this proposed rule, the EPA would create emission guidelines for states to follow in developing plans to address greenhouse gas emissions from existing fossil fuel-fired electric generating units. Specifically, the EPA is proposing state-specific rate-based goals for CO2 emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve the state-specific goals. On August 3, 2015, the EPA finalized the Clean Power Plan Rule to cut carbon pollution from existing power plants, which became effective on December 22, 2015. Numerous petitions challenging the Clean Power Plan Rule have been consolidated into one case, West Virginia v. EPA. While the litigation is still ongoing at the circuit court level, a mid-litigation application to the Supreme Court resulted in a stay of the Clean Power Plan Rule. On September 27, 2016, an en banc panel of the U.S. Court of Appeals for the D.C. Circuit heard oral arguments in the case. In April 2017, the D.C. Circuit granted the EPA’s motion to hold the case and a decision is expected in early 2017.abeyance while the EPA undertakes its review of the regulations.

The EPA has adopted regulations under existing provisions of the federal Clean Air Act that establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permits for large stationary sources. Facilities requiring PSD permits may also be required to meet “best available control technology” (BACT) standards. Rulemaking related to GHG could alter or delay our ability to obtain new and/or modified source permits.
Internationally,As part of the Kyoto Protocol, which set binding emission targets for developed countries (whichObama administration’s initiative to reduce methane emissions from the oil and natural gas industry, the EPA adopted rules to control volatile organic compound emissions from certain oil and gas equipment and operations. In June 2017, the EPA issued a 90-day stay of certain requirements under the methane rule. The stay was not ratifiedvacated in July 2017 by the United States) was nominally extended past its expiration dateU.S. Court of December 2012 with a requirement for a new legal construct to be put into place by 2015. In December 2015, the United Nations Climate Change Conference was held and an agreement was reached between the countries participating in the conference, including the United States, to limit global warming to less than 2 degrees Celsius (3.6° Fahrenheit) compared to pre-industrial levels. This agreement, known as the Paris Agreement, calls for zero net anthropogenic greenhouse gas emission to be reached during the second half of the 21st century. Each party is to prepare a plan on its contributions to reach this goal; each plan is to be filed in a publicly available registry. In addition, in November 2014, President Obama announced that the United States would seek to cut net greenhouse gas emissions 26-28 percent below 2005 levels by 2025 in return for China's commitment to seek to peak emissions around 2030, with concurrent increases in renewable energy. The United States participation in the Paris Agreement is unclear with the change in Administration in January 2017.

Additionally, coalbed methane must be expelled from our underground coal mines for mining safety reasons and is vented into the atmosphere when the coal is mined. Coalbed methane has a greater GHG effect than carbon dioxide. If regulation of GHG emissions does not exempt the release of coalbed methane, we may have to further reduce our methane emissions, pay higher taxes, incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines or perhaps curtail coal production.

Apart from governmental regulation, investment banks based both domestically and internationally have announced that they have adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants.

Adoption of comprehensive legislation or regulation focusing on GHG emission reductionsAppeals for the United States or other countries where we sell coal (including by adopting plansD.C. Circuit. In the interim, in July 2017 the EPA issued a proposed rule that would stay the methane rule for two years, but this rule is not yet final, is subject to implement the Paris Agreement), or the inability of utilitiespublic notice and comment and may be subject to obtain financing in connection with coal-fired plants, may make it more costly to operate fossil fuel fired (especially coal-fired) electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural gas-fueled power generation could become more economically attractive than coal-fueled power generation, substantially increasing the demand for natural gas. Apart from actual regulation, uncertainty over the extent of regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal or possibly natural gas consumed by domestic electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. We or our customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal or natural gas and comply with future GHG emission standards.

In addition, there have also been efforts in recent years affecting the investment community, including investment advisers, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.


legal challenges.


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Additionally, applicability of CNX and CNXM facilities under the CAA, as well as state sponsored permitting programs are subject to regulatory uncertainty and therefore present risk, including hitting production objectives, and cost for controls and compliance. Some states in which we operate are contemplating measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and potential cap-and-trade programs. Most of these types programs require major source of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available being reduced each year until a target goal is achieved. The cost of these allowances could increase over time. While new laws and regulations that are aimed at reducing GHG emissions will increase demand for natural gas, they may also result in increased costs for permitting, equipping, monitoring and reporting GHGs.
Environmental regulations introduce uncertainty that could adversely impact the market for natural gas and coal with potential short and long-term liabilities.
We and CNXM are subject to various stringent federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. These laws and regulations may impose numerous obligations that are applicable to our, CNXM’s and our respective customers' operations. Failure to comply with these laws, regulations and permits may result in joint and several or strict liability or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and/or the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which CNXM’s gathering systems pass, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.
Our operations, and those of CNXM, also pose risks of environmental liability due to leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to investigate, remediate, and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may also be subject to fines and penalties for such releases. We may be required to remediate contaminated properties currently or formerly operated by us regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations.

The Federal Endangered Species Act (ESA) and similar state laws protect species endangered or threatened with extinction. Protection of endangered and threatened species may cause us to modify gas well pad siting or pipeline right of ways, mining plans, or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. On January 14, 2016, the US Fish and Wildlife Service (USFWS) finalized a rule exempting certain types of “take” of northern long-eared bats from the requirement to obtain an incidental take permit, pursuant to Section 4(d) of the Endangered Species Act. This listing could lead to significant timing and critical path hurdles, ultimately limiting the ability to clear timber for construction activities in our operations area.

Other species that are being consideredFurther consideration for listing as endangered under the ESA are the Big Sandy Crayfish, the Guyandotte River Crayfishspecies within our operating region is expected, and the Rusty Patched Bumble Bee, all of which if listed have the potential to interfere with the proposed layout of our mine plans and surface facilities, including natural gas well pads, compressor stations and pipelines,CNX considers this uncertainty, as well as the manner in which we operate our minescost to comply with stringent mitigation requirements a risk to cost and facilities. USFWS has stated that the primary threats to crayfishes throughout their respective ranges are land-disturbing activities that increase erosion and sedimentation, which degrades the stream habitat required by both species. Identified sources of ongoing erosion and sedimentation that occur throughout the ranges of the species include active surface coal mining, commercial forestry, unpaved roads, natural gas and oil development, and road construction. This has the potential to disrupt future mining and natural gas activities in Appalachia.operational timing.

On December 19, 2016, the federal Office of Surface Mining released final regulations to the Stream Protection Rule, which is intended to prevent or minimize impacts to surface water and groundwater from coal mining. The rule will require companies to restore streams and return mined areas to the uses they were capable of supporting prior to mining activities, and replant these areas with native trees and vegetation, unless that would conflict with the implemented land use. The rule requires the testing and monitoring of the condition of streams that might be affected by mining - before, during and after their operations - to provide baseline data that ensures operators can detect and correct problems that could arise, and restore mined areas to their previous condition. The final SPR requires the restoration of the physical form, hydrologic function, and ecological function of the segment of a perennial or intermittent stream that a permittee mines through. Additionally, it requires that the post-mining surface configuration of the reclaimed mine site include a drainage pattern, including ephemeral streams, similar to the pre-mining drainage pattern, with exceptions for stability, topographical changes, fish and wildlife habitat, etc. The rule also requires the establishment of a 100-foot-wide streamside vegetative corridor of native species (including riparian species, when appropriate) along each bank of any restored or permanently-diverted perennial, intermittent, or ephemeral stream. This rulemaking is highly anticipated to be subject to Legislative and Executive branch actions to overturn or significantly modify the rule.

CONSOL EnergyCNX utilizes pipelines extensively for its natural gas and water businesses. Stream encroachment and coal businesses. Mitigationcrossing permits from the Army Corps of Engineers (ACOE) are typicallyoften required for certain impacts these pipelines cause to streams and wetlands. On April 21, 2014 the EPA published a proposed rule called “Definition of ‘Waters of the United States’ (WoUS) Under the Clean Water Act.” The proposal would expand the scope of the CWA to include previously non-jurisdictional streams, wetlands, and waters, making these areas jurisdictional inter-coastal waters of the U.S. In February 2015 the EPA and ACOE issued a memorandum of understanding to withdraw the WoUS Interpretive Rule. The EPA published the latest version of the WoUS rule (the Clean Water Rule) on June 29, 2015, which was to become effective on August 28, 2015. However, on August 27, 2015, the District Court of North Dakota blocked implementation of the rule in 13 states. On October 9, 2015, the Court of Appeals for the Sixth Circuit blocked implementation of the rule nationwide. The Trump administration has proposed replacing the October 2015 definition with the prior definition. Additionally, in January 2017, the U.S. Supreme Court will nowagreed to decide whichwhether the federal court has jurisdiction -of appeals or federal appeals court or district courts. Acourts have jurisdiction. Oral argument was heard in October 2017, and a decision is expected sometime in mid 2017.

Management and regulation of point source discharges covered undercalendar year 2018. If the National Pollutant Discharge Eliminations System (NPDES)EPA moves forward with implementation of the CWA have undergone recent2015 rule, or if states make any similar changes to their regulatory programs, this could lead to additional mitigation costs for us and proposed changesCNXM, and severely limit our and CNXM’s operations.
Other regulations applicable to the natural gas industry are under constant review for amendment or expansion at both the federal and state levels. Any future changes may increase the costs of producing natural gas and federal level that have the potential to affect the long-term treatmentother hydrocarbons, which would adversely impact our cash flows and dischargeresults of water from coal mines. States are required by the CWA to conduct a comprehensive review of the state water quality standards every three years (the "Triennial Review"). WV has issuedoperations. For example, hydraulic fracturing is an emergency rule effective June 21, 2014important and proposed amendments under 47 CSR 2 with specific requirements for the discharge of aluminum and selenium that pose potential impacts on the coal industry. Ohio (OH) is currently reviewing the current 401 and 404 permitting program to propose new amendments.

In April 2015, the EPA proposed a CWA regulation (Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category) establishing pretreatment standards that would prohibit the indirect discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned treatment works (POTWs). While dischargescommon


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practice that is used to POTWs are not currently utilized,stimulate production of hydrocarbons from tight unconventional shale formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas extraction wastewater can be generatedagencies. The disposal of produced water and other wastes in large quantities. Itunderground injection disposal wells is unclear howregulated by the newly proposed ruleEPA under the federal Safe Drinking Water Act or by various states in which we conduct operations under counterpart state laws and regulations. The imposition of new environmental initiatives and regulations could affect future water use and disposal practices.

State regulations for horizontal well drilling and well site construction have been proposed and finalized. In September, 2015, PA published a final rulemakinginclude restrictions on the revisionsour ability to the Environmental Protection Performance Standards at Oil and Gas Well Sites (Chapters 78 and 78a). These rules are the subjectconduct hydraulic fracturing operations or to dispose of pending litigation. OH passed Horizontal Well Site Construction Rules which will become effective in July 2015. OH is also in the process of reviewing and possibly adopting additional horizontal development rules.

waste resulting from such operations.
Our natural gas and coal mining operations are subject to operating risks, including our reliance upon third-party contractors, which could increase our operating expenses and decrease our production levels which could adversely affect our results of operations. Our natural gas and coal operations are also subject to hazards and any losses or liabilities we suffer from hazards, which occur in our operations may not be fully covered by our insurance policies.

Our exploration for and production of natural gas involvesand CNXM’s gathering, compression and transportation operations involve numerous operating risks. The cost of drilling, completing and operating our shale gas wells, shallow oil and gas wells and coalbed methane (CBM) wells is often uncertain, and a number of factors can delay or prevent drilling operations, decrease production and/or increase the cost of our natural gas operations at particular sites for varying lengths of time thereby adversely affecting our operating results. The operating risks that may have a significant impact on our natural gas operations include:

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;
pipeline ruptures;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;
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
unavailabilitylack of availability or high cost of drilling rigs, other field services, personnel and equipment.

Our coal mining operations are underground mines. Underground mining and related processing activities present inherent risks of injury to persons and damage to property and equipment. Our mines are subject to a number of operating risks that could disrupt operations, decrease production and increase the cost of mining at particular mines for varying lengths of time thereby adversely affecting our operating results. In addition, if an operating risk occurs in our mining operations, we may not be able to produce sufficient amounts of coal to deliver under our multi-year coal contracts. Our inability to satisfy contractual obligations could result in our customers initiating claims against us or canceling their contracts. The operating risks that may have a significant impact on our coal operations include:

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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The occurrencerealization of any of these risks at our natural gas or coal mining operations could adversely affect our ability to conduct natural gas or coal miningour operations, materially increase our costs, or result in substantial loss to us as a result of claims for:

personal injury or loss of life;
damage to and destruction of property, natural resources and equipment, including our coal properties and our coalnatural 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.

In addition, theThe occurrence of any of these events in our coal mininggas operations which prevents our delivery of coalnatural gas to a customer and which is not excusable as a force majeure event under our coal salessupply agreement, could result in economic penalties, suspension or cancellation of shipments or ultimately termination of the coal salessupply agreement.

Although we and CNXM maintain insurance for a number of risks and hazards, we may not be insured or fully insured against the losses or liabilities that could arise from a significant accident in our natural gas and coal operations. We may elect not to obtain insurance


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for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Moreover, a significant mine accident could potentially cause a mine shutdown. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We also rely upon third-party contractors to provide key services to our natural gas operations. We contract with third-parties for well services, related equipment, and qualified experienced field personnel to drill wells and conduct field operations. The demand for these field services in the natural gas and oil industry can fluctuate significantly. Higher oil and natural gas prices generally stimulate increased demand causing periodic shortages. These shortages may lead to escalating prices for drilling equipment, crews and associated supplies, equipment and services. Shortages may lead to poor service and inefficient drilling operations and increase the possibility of accidents due to the hiring of inexperienced personnel and overuse of equipment by contractors. In addition, the costs and delivery times of equipment and supplies are substantially greater in periods of peak demand. Accordingly, we cannot assure that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or increases in the costs of, drilling equipment, crews and associated supplies, equipment and field services in the future. We utilize third-party contractors to provide land acquisition and related services to support our land operational needs for both natural gas and coal segments. We also use third-party contractors to provide construction and specialized services to our coal mining operations. A decrease in the availability of field services or equipment and supplies, an increase in the prices charged for field services, equipment and supplies, or the failure of third-party contractors to provide quality field services to us, could decrease our natural gas and coal production, increase our costs of natural gas and coal production, and decrease our anticipated profitability.

We attempt to mitigate the risks involved with increased natural gas industrialproduction activity by entering into “take or pay” contracts with well service providers which commit them to provide field services to us at specified levels and commit us to pay for field services at specified levels even if we do not use those services. However, these types of contracts expose us to economic risk during a downturn in demand or during periods of oversupply. For example, in 20162017 due to the oversupply of gas in our markets, we made payments under these types of contracts of approximately $33$40 million for field services that we did not use. Having to pay for services we do not use decreases our cash flow and increases our costs of production.costs.

We may not be able to obtain required personnel, services, equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs to support our coal mining and natural gas operations.

Coal mining consumes large quantities of commodities including steel, copper, rubber products and liquid fuels and requires the use of capital equipment. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for commodities and capital equipment are strongly impacted by the global market. A rapid or significant increase in the costs of commodities or capital equipment we use in our operations could impact our mining operations costs because we may have a limited ability to negotiate lower prices, and, in some cases, may not have a ready substitute.

We use equipment in our coal mining and transportation operations such as continuous mining units, conveyors, shuttle cars, rail cars, locomotives, roof bolters, shearers and shields. We procure this equipment from a concentrated group of suppliers, and obtaining this equipment often involves long lead times. Occasionally, demand for such equipment by mining companies


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can be high and some types of equipment may be in short supply. Delays in receiving or shortages of this equipment, as well as the raw materials used in the manufacturing of supplies and mining equipment, which, in some cases, do not have ready substitutes, or the cancellation of our supply contracts under which we obtain equipment and other consumables, could limit our ability to obtain these supplies or equipment. In addition, if any of our suppliers experiences an adverse event, or decides to no longer do business with us, we may be unable to obtain sufficient equipment and raw materials in a timely manner or at a reasonable price to allow us to meet our production goals and our revenues may be adversely impacted. We use considerable quantities of steel in the mining process. If the price of steel or other materials increases substantially or if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses could increase. Any of the foregoing events could materially and adversely impact our business, financial condition, results of operations or cash flows.

Additionally, we rely on a supply of drilling rigs,third-party contractors to provide key services and equipment for our operations. We contract with third parties for well services, related equipment, and qualified experienced field personnel to drill wells, construct pipelines and conduct field operations. We also utilize third-party contractors to provide land acquisition and related services into support our naturual gas operations.land operational needs. The demand for these services, this equipment and for qualified and experienced field personnel to drill wells, construct pipelines and conduct field operations, geologists, geophysicists, engineers, and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Weather may also play a role with respect to the relative availability of certain materials. Historically, there have been shortages of drilling and workover rigs, pipe, compressors and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. WeThe costs and delivery times of equipment and supplies are substantially greater in periods of peak demand, including increased demand for plays outside of our area of geographic focus. Accordingly, we cannot predict whether these conditionsassure that we will existbe able to obtain necessary services, drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or increases in the futurecosts of, drilling equipment, crews and if so, what their timingassociated supplies, equipment and duration will be.field services in the future.

Any of the above shortages may lead to escalating prices for drilling equipment, land services, crews and associated supplies, equipment and services. Shortages may lead to poor service and inefficient drilling operations and increase the possibility of accidents due to the hiring of inexperienced personnel and overuse of equipment by contractors. Additionally, a decrease in the availability of these services, equipment and personnel could lead to a decrease in our natural gas production, increase our costs of natural gas production, and decrease our anticipated profitability. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which events could materially and adversely impact our business, financial condition, results of operations, or cash flows.

ForIf natural gas prices remain depressed or drilling and mining operations, CONSOL Energy must obtain, maintain, and renew governmental permits and approvals which ifefforts are unsuccessful, we cannot obtain in a timely manner would reducemay be required to record writedowns of our production, cash flow and results of operations.proved natural gas properties.

State and local authorities regulate various aspectsLower natural gas prices or wells that produce less than expected quantities of natural gas drilling and production activities, includingmay reduce the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or poolingamount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management's plans change with respect to those assets. For example, in the second quarter of 2015, we had an impairment charge of approximately $829 million for certain of our natural gas assets, primarily shallow oil and gas assets. We may incur impairment charges in the future, which could have an adverse effect on our results of operations in the period taken.

Competition within the natural gas industry may adversely affect our ability to sell our products and midstream services. Increased competition or a loss of our competitive position could adversely affect our sales of, or our prices for, our products, which could impair our profitability.

The natural gas and midstream industries are intensely competitive with companies from various regions of the United States. Many of the companies with which we and CNXM compete are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, our operating results and financial position may be adversely affected. In addition, larger companies may be able to pay more to acquire new natural gas properties environmental matters, safety standards, market sharingfor future exploration, limiting our ability to replace the natural gas we produce or to grow our production. The highly competitive environment in which


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we operate may negatively impact our ability to acquire additional properties at prices or upon terms we view as favorable. The competitive environment can also make it more challenging to discover new natural gas resources, evaluate and well site restoration. Delaysselect suitable properties and to consummate these transactions. Any reduction in our ability to compete in current or denialsfuture natural gas markets could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Additionally, CNXM’s ability to increase throughput on its midstream systems and any related revenue from third-parties is subject to capacity availability on their existing systems, its ability to expand its existing systems, contractual limitations to its existing customers and competition from third parties, primarily operators of other natural gas gathering systems. The fact that a substantial majority of the capacity of CNXM’s midstream systems will be necessary to service the production of CNX and one third-party customer and we and that third-party will receive priority of service for the provision of CNXM midstream services over other third-parties, may result in CNXM not having the capacity to provide services to other third-party customers. In addition, potential third-party customers who are significant producers of natural gas permitsand condensate may develop their own midstream systems in lieu of using CNXM’s systems. All of these competitive pressures could reduce our production,have a material adverse effect on CNXM’s business, results of operations, financial condition, cash flows and results of operations.ability to make cash distributions and therefore, could have a material adverse effect on our investment in CNXM.

Our coalDeterioration 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 may have a materially adverse effect on our liquidity, results of operations, business and financial condition that we cannot predict.

Economic conditions in a number of industries in which our customers operate, such as electric power generation, have experienced substantial deterioration in and the past, resulting in reduced demand for natural gas. In addition, liquidity is essential to our business and developing our assets. Renewed or continued weakness in the economic conditions of any of the industries we serve or that are served by our customers could adversely affect our business, financial condition, results of operation and liquidity in a number of ways. For example:

demand for natural gas and electricity in the United States is impacted by industrial production, is dependent onwhich 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 obtain various federalcollect 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 state permits
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 hedging activities may prevent us from benefiting from price increases and approvalsmay expose us to mineother risks.
To manage our coal reserves. The permitting rules, andexposure to fluctuations in the interpretationsprice of these rules, are complex, change frequently and are often subject to discretionary interpretations by regulators. The EPA also has the authority to veto permits issued by the U.S. Army Corps of Engineers under the Clean Water Act’s Section 404 program that prohibits the discharge of dredged or fill materialnatural gas, we enter into regulated waters without a permit. In addition, the public, including non-governmental organizations and individuals, have certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. The pacehedging arrangements with which the government issues permits needed for new operations for  on-going operations  to  continue  mining continues to pose significant negative effects. Further, in 2011 the EPA revoked an ACOE-issued Section 404 permitrespect to a coal mining operator. Followingportion of our expected production. As of January 15, 2018, we expect these transactions will represent approximately 388.6 Bcf of our estimated 2018 production at an average price of $2.77 per Mcf, 273.0 Bcf of our estimated 2019 production at an average price of $2.74 per Mcf, 198.3 Bcf of our estimated 2020 production at an average price of $2.78 per Mcf, approximately 166.5 Bcf of our estimated 2021 production at an average price of $2.62 per Mcf, and approximately 153.4 Bcf of our estimated 2022 production at an average price of $2.83 per Mcf. To the U.S. Supreme Court’s refusalextent that we engage in March 2012hedging activities, we may be prevented from realizing the near-term benefits of price increases above the levels of the hedges. If we choose not to hear an appeal from the D.C. Circuit Court’s ruling upholding the EPA’s power to revoke a permit,engage in, September 2014 the U.S. Courtor reduce our use of Appeals upheld the EPA’s action to revoke the permit. In addition, in July 2014 the D.C Circuit reversed a lower court’s decision and affirmed the EPA’s authority to adopt the Enhanced Coordination Process governing coordination with the ACOEhedging arrangements in the processing of CWA permits. The Court also rejected challengesfuture, we may be more adversely affected by changes in natural gas prices than our competitors who engage in hedging arrangements to EPA’s 2012 “Final Guidance” document regarding appropriate permit conditions, namely those affecting acceptable conductivity limits (e.g., acceptable ionic strength to support aquatic life). However, the Court left it up to the states on whether to adopt the guideline recommendations when issuing final NPDES permits. This decision has left coal mining permits in some degree of uncertainty whether the EPA will concur with a state’s draft permit conditions should they not contain specified limits regarding conductivity, further increasing operational uncertainty and costs.

The pace with which the government issues permits needed for new operations and for on-going operations to continue coal mining has negatively impacted expected production. These delays or denials of coal mining permits could reduce our production, cash flows and results of operations.

greater extent than we do.
In addition, such transactions may expose us to the risk of financial loss in 2005, certain circumstances, including instances in which:
our production is less than expected;
the Pennsylvania Department of Environmental Protection (“PADEP”) issued a technical guidance document that imposes standards in the material mining permits that we hold relatingcounterparties to our Pennsylvania Operations, including costly stream mitigationcontracts fail to perform the contracts;
the creditworthiness of our counterparties or their guarantors is substantially impaired; and monitoring requirements
counterparties have credit limits that may constrain our ability to hedge additional volumes.
Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.
Our ability to receive payment for natural gas sold and alterationsdelivered depends on the continued creditworthiness of our customers. Many utilities have sold their power plants to non-regulated affiliates or third-parties that may be less creditworthy,


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thereby increasing the risk we bear with respect to potential payment default. These new power plant owners may have credit ratings that are below investment grade. If the creditworthiness of our customers or their ability to pay declines significantly, our business could be adversely affected. Our inability to collect payment from counterparties to our longwall mining plans.

sales contracts may have a materially adverse effect on our business, financial condition, results of operations and cash flows.
Existing and future government laws, regulations and other legal requirements relating to protection of the environment, and others that govern our business may increase our costs of doing business for coal and may restrict our coal operations.



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WeThere are subject to laws,numerous governmental regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authorities relating to protection of the environment. These include those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, threatened and endangered plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, the installation of various safety equipment in our mines, remediation of impacts of surface subsidence from underground mining, and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitive position.

In addition, there is the possibility that we could incur substantial costs as a result of violations under environmental laws. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authorities or new interpretations of existing legal requirements by regulatory bodies relating to the protection of the environment could further affect our costs of operations and competitive position. The Clean Water Act is being used by opponents of mountain top removal mining as a means to challenge permits and bring citizen suits to make coal mining more expensive. At CONSOL Energy’s subsidiary Fola Coal Company, LLC, six citizen suits have been filed challenging water discharge permits. Two of those suits were settled in 2014, and at least two are potentially affected by recent settlements by another mining operator in a similar case.

Existing and future government laws, regulations and other legal requirements relating to protection of the environment, and others that govern our business may increase our costs of doing business for natural gas, and may restrict our natural gas operations.

Regulations applicable to the natural gas industry that are not directly related to environmental regulation, many of which are under constant review for amendment or expansion at the federal and state level. Any future changes may affect, among other things, the pricing or marketing of natural gas production. For example, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as the Marcellus Shale. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. Hydraulic fracturing is currently
Currently, CNXM’s gathering operations are exempt from regulation by the Federal Energy Regulatory Commission (FERC) under the federal Safe Drinking WaterNatural Gas Act except for hydraulic fracturing using diesel fuel. The disposal(NGA). Although FERC has not made any formal determinations with respect to any of produced water, drilling fluidsCNXM’s facilities considered to be gathering facilities, CNXM believes that the natural gas pipelines in its gathering systems meet the traditional tests FERC has used to establish that a natural gas pipeline is a gathering pipeline not subject to FERC jurisdiction. However, this this issue has been the subject of substantial litigation, and other wastes in underground injection disposal wells is regulatedif FERC were to consider the status of an individual facility and determine that the facility or services provided by the EPAit are not exempt from FERC regulation under the federal Safe Drinking Water Act orNGA, the rates for, and terms and conditions of, services provided by the states under counterpart state laws and regulations. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing operations or to dispose of waste resulting from such operations. The EPA commenced a study of the potential environmental impacts of hydraulic fracturing activities and the final report was issued in December 2016.

We are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions. On August 16, 2012, the U.S. Environmental Protection Agency (EPA) published final revisions to the New Source Performance Standards (NSPS) to regulate emissions of volatile organic compounds (VOCs) and sulfur dioxide (SO2) from various oil and gas exploration, production, processing and transportation facilities. Additionally, revisions were made to the National Emission Standards for Hazardous Air Pollutants (NESHAPS) to further regulate emissions from the oil and natural gas production sector and the transmission and storage of natural gas. Section 111 of the CAA authorized the EPA to develop technology based standards which apply to specific categories of stationary sources. In September 2009, the EPA finalized the Mandatory Reporting of Greenhouse Gas Rule. The current version of this rule requires annual reporting of emissions from natural gas wells, coal mines and associated facilities.

The EPA has proposed to amend the Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse Gas Reporting Program (GHGRP). This proposed rulefacility would add reporting of greenhouse gas emissions from certain gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. The rule would also require operators to utilize new monitoring equipment in order to comply with Subpart W. On September 18, 2015, the EPA proposed updates to the New Source Performance Standards (NSPS) that would create new standards for the regulation of methane and VOC emission sources. The proposed rule includes requirements for new fugitive emission and leak detection testing and reporting requirements. On September 18, 2015, the EPA proposed the Source Determination Rule which would clarify the use of the term “adjacent” in determining Title V air permitting requirements as they apply to the oil and natural gas industry for major sources of air emissions. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (DOE), the U.S. Government Accountability Office and the Department of the Interior. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. If hydraulic fracturing is


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regulated at the federal, state or local level, our fracturing activities could become subject to additional permit requirements or operational restrictionsregulation by FERC. Such regulation could decrease revenue, increase operating costs, and, also to associated permitting delaysdepending upon the facility in question, could adversely affect results of operations and potential increases in costs.

Further, air emissions that stem from hydraulic fracturing and completions processes, as well as from midstream activities such as the gathering and transmission of natural gas, are regulated by federal and state rules. However, interpretations of those rules, as well as additional changes to the regulations, could negatively impact our ability to meet our stated production objectivescash flows for the company. For example, source aggregation of air emissions to determine whether, under the Clean Air Act a source comprises a single stationary source and is therefore a major source of air pollution, and thereby subject to the applicability of Nonattainment Prevention of Significant Deterioration and Title V permitting requirements, has and continues to be debated by the EPA, state regulatory agencies and the courts. Recently, the Pennsylvania Environmental Hearing Board determined the emission sources of an upstream subsidiary and a midstream subsidiary of a company were aggregated as a single source, given the dynamic nature of the issue. Federal and state activities, as well as court decisions could impact the development and transmission of plans of CONSOL Energy, our joint venture partners, and gathering systems being installed and operated by CONE Midstream Partners, LP.

CNXM.
Additionally, some states have begun to adopt more stringent regulation and oversight of natural gas gathering lines than is currently required by federal standards. Pennsylvania, under Act 127, authorized the Public Utility Commission (PUC) oversight of Class I gathering lines, as well as requiring standards and fees associated with Class II and Class III pipelines. The state of Ohio also moved to regulate natural gas gathering lines in a similar manner pursuant to Ohio Senate Bill 315 (SB315). SB315 expanded the Ohio PUC's authority over rural natural gas gathering lines. These changes in interpretation and regulation affect CONSOL Energy'sour midstream activities, requiring changes in reporting, as well as increased costs.
We may incur significant costs and liabilities as a result of pipeline and related facility integrity management program testing and any related pipeline repair or preventative or remedial measures.
PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines and related facilities located where a leak or rupture could do the most harm, i.e., in “high consequence areas.” The regulations require operators to:
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.

Further, someThe 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. In 2017, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $209,002 per violation per day, with a maximum of $2,909,022 for a related series of violations. Should our or CNXM's operations fail to comply with PHMSA or comparable state regulations, we could be subject to substantial penalties and local governmentsfines. PHMSA has also published notices and advanced notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to extend the integrity management program requirements to additional types of facilities, such as gathering pipelines and related facilities. In January 2017, in the Marcellus Shale region in Pennsylvania and New York have considered or imposed a temporary moratorium on drilling operations using hydraulic fracturing until further studyfinal week of the potential for environmental and human health impacts by the EPA or the relevant agencies are completed. Further, states could elect to prohibit hydraulic fracturing altogether, as Governor Andrew CuomoObama Administration, PHMSA released a pre-publication copy of the State of New York announced in December 2014 with regard to fracturing activities in New York. No assurance can be given as to whether or not similar measures might be considered or implemented in jurisdictions in which our gas properties are located. If new laws orits final hazardous liquid pipeline safety regulations that would significantly restrict or otherwise impact hydraulic fracturingextend the integrity management requirements to previously exempt pipelines and would impose additional obligations on hazardous liquid pipeline operators that are passed by Congress or adoptedalready subject to the integrity management requirements, including periodic integrity assessments and leak detection for pipelines outside of high consequence areas, inspections of pipelines after extreme weather events, expanded reporting, and more stringent integrity management repair and data collection requirements. Due to the change in statesPresidential administrations, PHMSA’s final hazardous liquid pipeline safety rule was never published in which we operate, such legal requirements could make it more difficult or costlythe Federal Register and has not yet taken effect. PHMSA is expected to finalize its hazardous liquid pipeline safety rule this year. PHMSA’s proposed rule would


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also require annual reporting of safety-related conditions and incident reports for us to perform hydraulic fracturing activitiesall hazardous liquid gathering lines and thereby could affect the determination of whethergravity lines, including pipelines that are currently exempt from PHMSA regulations. PHMSA issued a well is commercially viable. New laws or regulations could also cause delays or interruptions or terminations of operations, the extent of which cannot be predicted,separate regulatory proposal in July 2015 that would impose pipeline incident prevention and could reduce the amount of oil andresponse measures on natural gas that we ultimately are able to produceand hazardous liquid pipeline operators. Additionally, in commercially paying quantities from our natural gas properties, all of which could have a materially adverse effect on our results of operations and financial condition.

On April 8, 2016, The U.S. Department of Transportation (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA)PHMSA published in the Federal Register a Notice of Proposed Rule Making (NPRM)(“NPRM”) that would significantly modify existing regulations related to reporting, impact, design, construction, maintenance, operations and integrity management of natural gas transmission and gathering pipelines. The proposed rule addresses four congressional mandates and six recommendations by the National Transportation Safety Board to broaden the scope of safety coverage by adding new assessment and repair criteria for gas transmission pipelines, and by expanding these protocols to include pipelines not formerly regulated by the federal standards. This includes extending regulatory requirements to transmission and gathering pipelines of 8eight inches and greater in rural class 1Class I areas. Compliance with the rule, as proposed, may prove challenging and costly for operators of older pipelines due to the difficulty of locating historic records. Compliance could involve significant upfront costs and service disruptions. The relatively short 2-year timeframe for compliance for gathering pipelines could also be difficult to meet. Costs ofAs proposed, compliance with the proposed rule could potentially affect shippershave a material adverse effect on pipelines as well as operators themselves, asour or CNXM's operations. However, the Federal Energy Regulatory Commission has allowed many interstate transmission pipelines to pass along costs attributable to safety measures directly to shippers. If implemented as proposed, CONSOL Energy (CONE & CNX Coal Resources) will be affected by this rulemaking. However, long-term costs for compliance will be dependentultimate impact of the rule on the finalized versionus and CNXM remains uncertain until the rulemaking is finalized. PHMSA is expected to finalize its natural gas pipeline safety rule this year. The adoption of regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. While we cannot predict the rule.outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow.

Our shale gas drilling and production operations require both adequate sources of water to use in the fracturing process, as well as the ability to dispose of or recycle the water and other wastes after hydraulic fracturing. Our CBM gas drilling and production operations also require the removal and disposal of water from the coal seams from which we produce gas. If we cannot find adequate sources of water for our use or we are unable to dispose of or recycle the water we use or remove it from the strata at a reasonable cost and within applicable environmental rules, our ability to produce natural gas economically and in commercial quantities could be impaired.



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As part of our drilling and production in shale formations, we use hydraulic fracturing processes. Thus, we needThese processes require access to adequate sources of water, which may not be available in proximity to useour operations or at certain times of the year. To ensure that we have adequate water available for our operations, we may be required to invest substantial amounts of capital in water pipelines which are used for relatively short periods of time. Alternatively, we may be required to truck water, and we may not be able to contract for sufficient water hauling trucks to meet our shale operations. needs.

Further, we must remove and dispose of the portion of the water that we use to fracture our shale gas wells that flows back to the well-bore,well bore, as well as drilling fluids and other wastes associated with the exploration, development or production of natural gas. This water can be either disposed of or recycled for use in other hydraulic fracturing operations. In the event we are forced to dispose of water rather than recycle water, our costs may increase. In addition, in our CBM drilling and production, coal seams frequently contain water that must be removed and disposed of in order for the natural gas to detach from the coal and flow to the well bore.

Our inability to locateobtain sufficient amounts of water with respect to our shale operations, or the inability to dispose of or recycle water and other wastes used in our shale and our CBM operations, could increase our costs and delay our operations, which will adversely impact our operations.

Our mines are subject to stringent federalcash flow and state safety regulations that increase our cost of doing business at active operations and may place restrictions on our methods of operation. In addition, government inspectors under certain circumstances, have the ability to order our operations to be shutdown based on safety considerations.

The Federal Coal Mine Safety and Health Act and Mine Improvement and New Emergency Response Act impose stringent health and safety standards on mining operations. Regulations that have been adopted are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in mine emergency procedures and other matters. Most states in which we operate have programs for mine safety and health regulation and enforcement. The various requirements mandated by law or regulation can place restrictions on our methods of operations, and potentially lead to fees and civil penalties for the violation of such requirements, creating a significant effect on operating costs and productivity. In addition, government inspectors under certain circumstances, have the ability to order our operation to be shutdown based on safety considerations. If an incident were to occur at one of our coal mines, it could be shut down for an extended period of time and our reputation with our customers could be materially damaged.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in liabilities to us.

Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage.” We could become subject to claims for toxic torts, natural resource damages and other damages, as well as for the investigation and clean-up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or for the entire share.

We maintain coal refuse areas and slurry impoundments at a number of our coal mining complexes. Such areas and impoundments are subject to extensive regulation. Structural failure of a slurry impoundment or coal refuse area could result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to claims for the resulting environmental contamination and associated liability, as well as for fines and penalties. Our coal refuse areas and slurry impoundments are designed, constructed, and inspected by our company and by regulatory authorities according to stringent environmental and safety standards.

In West Virginia there are areas where drainage from coal mining operations contains concentrations of selenium that without treatment would result in violations of state water quality standards that are set to protect fish and other aquatic life. We have several operations with selenium discharges. We and other coal companies have worked to expeditiously develop cost effective means to remove selenium from mine water.

These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us. An example of this is Naturally Occurring Radioactive Material (NORM) or Technologically-Enhanced, Naturally Occurring Radioactive Material (TENORM). NORM or TENORM is produced when activities such as deep drilling concentrate or expose radioactive materials that occur naturally in ores, soils, water, or other natural materials. State and federal agencies are examining the possibility for worker exposure or associated environmental hazards due to processing and disposal of wastes containing NORM or TENORM, as well as silica dust associated with natural gas well completions activities.

We have reclamation, mine closing and gas well plugging obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.



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The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all our coal mining operations. Also, state laws require us to plug natural gas wells and reclaim well sites after the useful life of our natural gas wells has ended. We accrue for the costs of current mine disturbance, gas well plugging and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing liabilities and gas well plugging, which are based upon permit requirements and our experience, were approximately $474 million at December 31, 2016. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs, estimated proved reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected.

Most states where we operate require us to post bonds for the full cost of coal mine reclamation (full cost bonding).

West Virginia is not a full cost bonding state. West Virginia has an alternative bond system (ABS) for coal mine reclamation which consists of (i) individual site bonds posted by the permittee that are less than the full estimated reclamation cost plus (ii) a bond pool (Special Reclamation Fund) funded by a per ton fee on coal mined in the State which is used to supplement the site specific bonds if needed in the event of bond forfeiture. In an effort to settle a citizen suit filed in 2012 before the U.S. District Court in West Virginia related to the Special Reclamation Fund being underfunded the WV legislature authorized an increase in the per ton fee levied on coal production to make up the shortfall. The Special Reclamation Fund became fully funded in June of 2016. There remains the possibility that WV may move to full cost bonding in the future which could cause individual mining companies and/or surety companies to exceed bonding capacity and would result in the need to post cash bonds or letters of credit which would reduce operating capital.

Pennsylvania is expanding its full cost bonding program to cover all coal mine bonding, further increasing the amount of surety bonds we must seek in order to permit its mining activities.

We have been able to post surety bonds with the states to secure our reclamation obligations. If our creditworthiness declines, states may seek to require us to post letters of credit or cash collateral to secure those obligations, or we may be unable to obtain surety bonds, in which case we would be required to post letters of credit. Additionally, the sureties that post bonds on our behalf may require us to post security in order to secure the obligations underlying these bonds. Posting letters of credit in place of surety bonds or posting security to support these surety bonds would have an adverse effect on our liquidity.

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

Natural gas and coal reserves are economically recoverable when the price at which they are expected to be sold exceeds their expected cost of production and selling.

Natural gas reserves require subjective estimates of underground accumulations of natural gas assumptions concerning natural gas prices, production levels, reserve estimates and operating and development costs. As a result, estimated quantities of proved natural gas reserves and projections of future production rates and the timing of development expenditures may be incorrect. For example, a significant amount of our proved undeveloped reserves extensions and discoveries during the last three years were due to the addition of wells on our Marcellus Shale acreage more than one offset location away from existing production with reliable technology, which may be more susceptible to positive and negative changes in reserve estimates than our proved developed reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing and production. Also, we make certain assumptions regarding natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our natural gas reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of natural gas reserves based on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas we ultimately recover being different from reserve estimates. The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved natural gas reserves on historical average prices and costs. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:operations.

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.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. If natural gas prices decline by $0.10 per Mcf, then the pre-tax present value using a 10% discount rate of our proved natural gas reserves as of December 31, 2016 would decrease from $1.6 billion to $1.4 billion.

We base our coal reserve information on geologic data, coal ownership information and current and proposed mine plans. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Similar to natural gas reserves, there are uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include:

geologic conditions;
historical production from the area compared with production from other producing areas;
the assumed effects of regulations and taxes by governmental agencies;
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.

In addition, we hold substantial coal reserves in areas containing Marcellus Shale and other shales. These areas are currently the subject of substantial exploration for oil and natural gas, particularly by horizontal drilling. If a natural gas well is in the path of our mining for coal, we may not be able to mine through the well unless we purchase it. Although in the past we have purchased vertical wells, the cost of purchasing a producing horizontal well could be substantially greater. Horizontal wells with multiple laterals extending from the well pad may access larger natural gas reserves than a vertical well which could result in higher costs. In future years, the cost associated with purchasing natural gas wells which are in the path of our coal mining may make mining through those wells uneconomical thereby effectively causing a loss of significant portions of our coal reserves.

Each of the factors which impacts reserve estimation may in fact vary considerably from the assumptions used in estimating the reserves. For these reasons, estimates of natural gas and coal reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal and natural gas reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual coal and natural gas reserves

Defects may exist in our chain of title for our natural gas estate or undeveloped coal reserves where we have not done a thorough chain of title examination of our natural gas estate or undeveloped coal reserves. We may incur additional costs and delays to produce natural gas or mine coal because we have to acquire additional property rights to perfect our title to natural gas or coal rights. If we fail to acquire additional property rights to perfect our title to natural gas or coal rights, we may have to reduce our estimated reserves.

Substantial amounts of acreage in which we believe we control natural gas rights are in areas where we have not yet done a thorough chain of title examination of the natural gas estate. A number of our natural gas properties were acquired primarily for the coal rights with the focus on the coal estate title, and, in many cases were acquired years ago. In addition, we have acquired natural gas rights in substantial acreage from third parties who had not performed thorough chain of title work on their natural gas properties. Our practice, and we believe industry practice, is not to perform a thorough title examination on natural gas properties until shortly before the commencement of drilling activities at which time we seek to acquire any additional rights needed to perfect our ownership of the natural gas estate for development and production purposes. When we perform a thorough chain of title examination, we may discover material defects in our title which would require us to acquire additional property rights. We may incur substantial costs to acquire these additional property rights. In addition, the acquisition of the necessary rights may not be feasible in some cases. Our discovering of title defects which we are unable to cure may adversely impact our ability to develop those properties and we may have to reduce our estimated natural gas reserves including our proved undeveloped reserves.



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Some states (West Virginia and Virginia) permit us to produce coalbed methane gas without perfected ownership under an administrative process known as “pooling,” which requires us to give notice to all potential claimants and pay royalties into escrow until the undetermined rights are resolved. As a result, we may have to pay royalties to produce coalbed methane gas on acreage that we control and these costs may be material. Further, the pooling process is time-consuming and may delay our drilling program in the affected areas.

Likewise, title to most of our owned or leased properties and mineral rights is not usually verified until we make a commitment to mine a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantor's. Our right to mine certain of our reserves has in the past been, and may again in the future be, adversely affected if defects in title, boundaries or other rights necessary for mining exist or if a lease expires. Any challenge to our title or leasehold interests could delay the mining of the property and could ultimately result in the loss of some or all of our interest in the property. From time to time we also may be in default with respect to leases for properties on which we have mining operations. In such events, we may have to close down or significantly alter the sequence of such mining operations which may adversely affect our future coal production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining and be subject to regulatory sanction and penalties.

In order to obtain, maintain or renew leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. As a result, our results of operations, business and financial condition may be materially adversely affected.

CONSOL EnergyCNX and its subsidiaries are subject to various legal proceedings, which may have an adverse effect on our business.

We are party to a number of legal proceedings in the normal course of business activities. Defending these actions, especially purported class actions, can be costly, and can distract management. For example, we are a defendant in three pending purported class action lawsuits dealing with claimants’ alleged entitlements to, and accounting for, natural gas royalties. There is also the possibility that we may become involved in future suits, including, for example, those being brought by coastal communities against oil, coal and other fossil fuel producers relating to climate change, which are beginning to gain prevalence in the courts. There is the potential that the costs of defending litigation in an individual matter or the aggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position. See Note 22-18- Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal proceedings.

We have obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, could result in our being required to expense greater amounts than anticipated.

We provide various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. At December 31, 2016, the current and non-current portions of these obligations included:

postretirement medical and life insurance ($700 million);
coal workers' black lung benefits ($119 million);
salaried retirement benefits ($115 million); and
workers' compensation ($80 million).

However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Salary retirement benefits are funded in accordance with Employer Retirement Income Security Act of 1974 (ERISA) regulations. The other obligations are unfunded. In addition, the federal government and several states in which we operate consider changes in workers' compensation and black lung laws from time to time. Such changes, if enacted, could increase our benefit expense and our collateral requirements. We post letters of credit and surety bonds as collateral for some of these liabilities that reduce our profitability and liquidity.

We do not control the timing of divestitures that we plan to engage in and they may not provide anticipated benefits. Additionally, we may be unable to acquire additional properties in the future and any acquired properties may not provide the anticipated benefits.

Our business and financing plans include divesting certain assets over time. However, we do not control the timing of divestitures and delays in entering intocompleting divestitures may reduce the benefits we may receive from them.them, such as elimination of management distraction by selling non-core assets and the receipt of cash proceeds that contribute to our liquidity. Additionally, if assets are held jointly with another party, we may not be permitted to dispose of these assets without the consent of our joint venture partner. Also, there can


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venture partner. Also, there can be no assurance that the assets we divest will produce anticipated proceeds. In addition, the terms of divestitures may cause a substantial portion of the benefits we anticipate receiving from them to be subject to future matters that we do not control.

In the future we may make acquisitions of assets or businesses that complement or expand our current business. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire the identified targets. The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses or assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to make acquisitions in the future and successfully integrate the acquired businesses andor assets into our existing operations could have a material adverse effect on our financial condition and results of operations

We may operate a material portion of our business with one or more joint venture partners. A joint venture may restrict our operational and corporate flexibility; actions taken by a joint venture partner may materially impact our financial position and results of operations; and we may not realize the benefits we expect to realize from a joint venture.
As is common in the industry we may operate one or more of our properties with a joint venture partner. These joint ventures could require us to share operational and other control with our joint venture partner, such that we may no longer have the flexibility to control completely the development of these properties. If we do not timely meet our financial commitments in a joint venture, our rights to participate in such joint venture will be adversely affected and the other party to the joint venture may have a right to acquire a share of our interest in such joint venture proportionate to, and in satisfaction of, our unmet financial obligations. If our joint venture partner is unable or fails to pay its portion of development costs, our costs of operations could be increased and it could result loss of rights to develop the properties held by that joint venture. We could also incur liability as a result of actions taken by our joint venture partner. Disputes between us and our joint venture partner may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.

The provisions of our debt agreements and those of CNXM, and the risks associated with our debttherewith could adversely affect our business, financial condition, liquidity and results of operations.

As of December 31, 2016,2017, our total long-term indebtedness was approximately $2.80$    2.22 billion of which approximately $1.85$1.71 billion was under our 5.875% senior unsecured notes due 2022 plus $5$4 million of unamortized bond premium, $500 million was under our 8.000% senior unsecured notes due 2023 less $6$5 million of unamortized bond discount, $74 million was under our 8.250% senior unsecured notes due 2020, $21 million was under our 6.375% senior unsecured notes due 2021, $103 million was under our Maryland Economic Development Corporation Port Facilities Refunding Revenue Bonds (MEDCO) 5.75% revenue bonds due September 2025, $49and $20 million of capitalized leases due through 2021, $5 million of miscellaneous debt and $201 million in outstanding borrowings under the revolver for CNXC of which we are not a guarantor.2021. The degree to which we are leveraged could have important consequences, including, but not limited to:

increasing our vulnerability to general adverse economic and industry conditions;
requiring us to dedicate a substantial portion of our cash flow from operations to the payment of interest and principal due under our outstanding debt, which will limit our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our gas and coal reserves or other general corporate requirements;
limiting our flexibility in planning for, or reacting to, changes in our business and in the coal and 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.

Our senior secured credit facility and the indentures governing our 5.875% and 8.000% senior unsecured notes limit the incurrence of additional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreement and the indentures governing our 5.875% and 8.000% senior unsecured notes subject us to financial and/or other restrictive covenants. Under our senior secured credit agreement, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio, and a minimum current ratio, as defined therein. Our senior secured credit agreement and the indentures governing our 5.875% and 8.000% senior unsecured notes impose a number of restrictions upon us, such as restrictions on granting liens on our assets, making investments, paying dividends, stock repurchases, selling assets and engaging in acquisitions. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on us.


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Further, CNXM’s existing $250.0 million revolving credit facility subjects it to certain financial and/or other restrictive covenants and other restrictions similar to those in our senior secured credit agreement and indentures.
If our or CNXM’s cash flows and capital resources are insufficient to fund our respective debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our senior secured credit agreement and the indentures governing our 5.875% and 8.000% senior unsecured notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

Unless weFailure to find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves will cause our natural gas reserves and production willto decline, which would adversely affect our business, financial condition, results of operations, liquidity and cash flows.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2016,2017, production is expected to decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore,


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our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional economically recoverable reserves. We may not be able to develop, find or acquire additional economically recoverable reserves to replace our current and future production at acceptable costs.

In addition, the level of natural gas and condensate volumes handled through the CNXM midstream systems depends on the level of production from natural gas wells dedicated to such midstream systems, which may be less than expected and which will naturally decline over time. In order to maintain or increase throughput levels on CNXM’s midstream systems, CNXM must obtain production from new wells completed by us and any third-party customers on acreage dedicated to the CNXM midstream systems or execute agreements with other third parties in CNXM’s areas of operation. CNXM has no control over producers’ levels of development and completion activity in its areas of operations, the amount of reserves associated with wells connected to CNXM’s systems or the rate at which production from a well declines.
Our lenders use the loan value of our proved natural gas reserves to determine the borrowing base under our $2.0$1.5 billion senior secured credit facility. Our borrowing base could decrease for a variety of reasons including lower natural gas prices, declines in natural gas proved reserves, and lending requirements or regulations. Significant reductions in our borrowing base below $2.0$1.5 billion could have a material adverse effect on our results of operations, financial condition and liquidity.

Our ability to borrow and have letters of credit issued under our $2.0$1.5 billion senior secured credit facility is generally limited to a borrowing base. Our borrowing base is determined by the required number of lenders in good faith calculating a loan value of the Company’s proved natural gas reserves. The borrowing base under our senior secured credit facility is currently $2.0 billion. Our borrowing base is redetermined by the lenders twice per year, and the next scheduled borrowing base redetermination is expected to occur in May 2017.2018. The various matters which we describe in other risk factors that can decrease our proved natural gas reserves including lower natural gas prices, operating difficulties, and failure to replace our proved reserves could decrease our borrowing base. Please read: “Risk Factors - We face uncertainties in estimating our economically recoverable natural gas and coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability”profitability” and - “Unless“Unless we replace our natural gas reserves, our natural gas reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.flows.” Our borrowing base could also decrease as a result of new lending requirements or regulations or the issuance of new indebtedness. If our borrowing base declined significantly below $2.0$1.5 billion, we may be unable to implement our drilling and development plans, make acquisitions or otherwise carry out our business plan which could have a material adverse effect on our financial condition and results of operation.operations. We also could be required to repay any outstanding indebtedness in excess of the redetermined borrowing base. We could face substantial liquidity problems, might not be able to access the equity or debt capital markets and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and thesethose proceeds may not be adequate to meet any debt service obligations then due.
Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

To manage our exposure to fluctuations in the price of natural gas, we enter into hedging arrangements with respect toWe may operate a portion of our expected production. 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; actions taken by the other partner or third-party operator may materially impact our financial position and results of operations; and we may not realize the benefits we expect to realize from a joint venture.

As of January 17, 2017,is common in the industry we had hedges on approximately 311.3 Bcfmay operate one or more of our 2017 natural gas production, 220.6 Bcf of our 2018 natural gas production, 161.7 Bcf of our 2019 natural gas production, 85.0 Bcf of our 2020properties with a joint venture partner, or contract with a third-party to control operations. These relationships could require us to share operational and natural gas production and 6.8 Bcf of our 2021 and natural gas production. To the extentother control, such that we engagemay no longer have the flexibility to control completely the development of these properties. If we do not timely meet our financial commitments in hedging activities, wesuch circumstances, our rights to participate may be preventedadversely affected. If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator does not operate in accordance with our expectations, our costs of operations could be increased. We could also incur liability as a result of actions taken by a joint venture partner or third-party operator. Disputes between us and the other party may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from realizing the near-term benefits of price increases above the levels of the hedges. If we choose not to engage in, or reducefocusing their time and effort on our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas prices than our competitors who engage in hedging arrangements to a greater extent than we do.





45


In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

our production is less than expected;
the counterparties to our contracts fail to perform the contracts;
the creditworthiness of our counterparties or their guarantors is substantially impaired;
counterparties have credit limits that may constrain our ability to hedge additional volumes.

business.
Changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs, could cause our financial position and profitability to deteriorate.
The passage of legislation or any other similar changes in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas oil or coal exploration and development. Any such change could negatively affect our financial condition and results of operations. For instance, recent tax law changes effective as of the beginning of 2018 will limit the ability of corporations to take certain interest deductions and have eliminated a corporation’s ability to take deductions for income attributable to domestic production activities.



31


Additionally, legislation has been proposed from time to time in the states in which we operate - primarily Pennsylvania, Ohio and Pennsylvania to introduce a newWest Virginia - that would impose severance taxtaxes or increased severance taxes on the oil and gas industry.production from our wells. The proposed tax rates have varied from 2.5 - 7.5 percent andbut would represent a significant increasedgreater financial burden on the economics of the wells we drill in these states.

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition. Additionally, our development and exploration projects require substantial capital expenditures and if we fail to obtain required capital or financing on satisfactory terms, our natural gas reserves may decline.

Our future growth prospects are dependent upon our ability to identify optimal strategies for investing our business.capital resources to produce superior rates of return. In developing our business plan, we consider allocating capital and other resources to various aspects of our businesses including well development (primarily drilling), reserve acquisitions, exploratory activity, coal development, corporate items and other alternatives. We also consider our likely sources of capital, including cash generated from operations and borrowings under our credit facilities. Notwithstanding the determinations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and future growth may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

Our development and exploration projects, as well as CNXM’s midstream system development, require substantial capital expenditures and if we fail to generate sufficient cash flow, or obtain required capital or financing on satisfactory terms, our natural gas reserves may decline and financial results may suffer.
As part of our strategic determinations, we expect to continue to make substantial capital expenditures in the development and acquisition of natural gas reserves. Further, CNXM will need to make substantial capital expenditures to fund its share of growth capital expenditures associated with its Anchor Systems, as well as to fund its share of expenditures associated with its 5% controlling interests in each of the Growth Systems and Additional Systems or to purchase or construct new midstream systems. If CNXM is unable to make sufficient or effective capital expenditures, it will be unable to maintain and grow its business.

CNXM's gathering agreement with us, CNXM's largest customer, as amended, includes minimum well commitments; however, that gas gathering agreement and the gas gathering agreements with third-parties impose obligations on CNXM to invest capital which is not fully protected against volumetric risks associated with lower-than-forecast volumes flowing through its gathering systems. To the extent CNXM’s customers are not contractually obligated to develop their properties in the areas covered by CNXM’s acreage dedications, and determine that it is more attractive to direct their capital spending and resources to other areas, such decreases in development of reserves by CNXM customers could result in reduced volumes serviced by CNXM and a commensurate decline in revenues and cash flows.

We cannot assure you that we or CNXM will have sufficient cash from operations, borrowing capacity under oureach company’s respective credit facilities or the ability to raise additional funds in the capital markets.markets to meet our capital requirements. If cash flow generated by our operations or available borrowings under oureither company’s credit facilities are not sufficient to meet our capital requirements, or we are unable to obtain additional financing, we could be required to curtail the pace of the development of our natural gas properties and midstream activities, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

Any failure by Murray Energy to satisfy the liabilities it assumed from us, as well as to perform its obligations under various agreements whose performance by Murray Energy we guaranteed,Terrorist attacks or under various agreements with us,cyber-attacks could materially increasehave a material adverse effect on our liabilities and materially adversely affect ourbusiness, financial condition or results of operations, financial position and cash flows.

In 2013, Murray Energy and its subsidiaries (Murray Energy) acquired approximately $2.4 billion of liabilities which had been reflected on our books. The consolidated balance sheet liabilities at the time of sale were comprised of approximately $2.1 billion of OPEB and other liabilities. In addition to these assumed liabilities, (i) Murray Energy acquired our obligations to make payments per hour worked to the multi-employer defined benefit pension plan for United Mine Workers of America (1974 Pension Plan), (ii) we guaranteed performance by Murray Energy under various West Virginia and Pennsylvania operational surety bonds and workers compensation obligations, under various equipment leases and to reclaim an impoundment site, (iii) we leased or subleased various mining equipment to Murray Energy, and (iv) we guaranteed performance by Murray Energy of certain coal supply agreements that Murray Energy acquired in the transaction. At the time of sale, if the hourly payment obligations acquired by Murray Energy to the 1974 Pension Plan were to be capitalized, they would have had a present value of approximately


46


$941 million, assuming a discount rate of 4.02%.We believe our maximum estimated exposure under our Murray Energy guarantees as of December 31, 2016 was approximately $74 million. The leases and subleases we entered into with Murray Energy relate to approximately $106 million of equipment. Murray Energy is primarily liable for the acquired retiree medical liabilities under the Coal Industry Retiree Health Benefits Act of 1992, which we call the Coal Act, but CONSOL Energy remains secondarily liable. At the time of the sale, the Coal Act liabilities Murray Energy acquired were approximately $307 million and it was estimated that the servicing cost for these liabilities would be approximately $26 million for 2017 and would decline thereafter since the beneficiaries principally are miners who retired prior to 1994. On November 12, 2013, in connection with the transaction, Moody’s assigned Murray Energy a family credit rating of B3 (speculative and subject to high credit risk) and its secured second lien notes due 2021 a rating of Caa1 (poor standing and subject to very high credit risk). Since the transaction, Murray Energy’s credit ratings have been downgraded by Moody’s. In November, 2016, Moody’s upgraded Murray Energy to a family credit rating of Caa2 and the rating on its secured second lien notes to Caa3 with a stable outlook. Any failure by Murray Energy to satisfy these assumed liabilities or perform under these agreements could result in substantial claims against us by third-parties and if, successful, could materially adversely affect our results of operations, financial position and cash flows. In addition, we regularly evaluate the likelihood of default by Murray Energy under the guarantees we have provided. The results of the evaluation may materially impact our results of operations. If Murray Energy defaults under the obligations we guaranteed, our cash flows may also be materially impacted.

Terrorist attacks or acyber-attacks may significantly affect the energy industry, and economic conditions, including our operations and our customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

We haveThe oil and natural gas industry has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of natural gas reserves, and coal reserves, as well asperform other activities related to our businesses. Strategic targets,Our business partners, including vendors, service providers, and financial institutions, are also dependent on digital technology.


32


As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA (supervisory control and data acquisition) based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations.

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as energy-related assets,surveillance, may be at greater risk of future physical attacks by terrorists or cyber attacks than other targets in the United States. remain undetected for an extended period.

Deliberate attacks on our assets, or security breaches in our systems or infrastructure, or the systems or infrastructure of third-parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third -party liability. Our insurancethird-party liability, including the following:

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 not protect us against such occurrences. Consequently, it is possible that anyresult 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 these occurrences,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 combinationnegative impact on the price of them, could haveour units.

Our implementation of various controls and processes, including globally incorporating a material adverse effect onrisk-based cyber security framework, to monitor and mitigate security threats and to increase security for our business, financial conditioninformation, facilities and results of operations. Further, asinfrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber incidentsthreats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.information security vulnerabilities.

A substantial majorityConstruction of sales of thermal coal are from three mines at one location in Pennsylvania, making us vulnerable to risks associated with operating in a single geographic area.

The substantial majority of our sales of thermal coal, as well as our thermal coal reserves, are from our Bailey Mine, Enlow Fork Mine and HarveyMine located in Greene County, Pennsylvania. In addition, we also rely upon one coal processing plant and rail load facility, located in Enon, Pennsylvania for shipping coal from all of these mines. Any disruption in the functioning of this coal processing plant and rail load-out facility such as the structural failure at the above ground conveyor system which occurred in 2012new gathering, compression, dehydration, treating or in transportation in this area could significantly reduce our sales of thermal coal and adversely affect our results of operation and financial condition.

Certain provisions in our multi-year coal sales contractsother midstream assets by CNXM may provide limited protection during adverse economic conditions, maynot result in revenue increases and may be subject to regulatory, environmental, political, legal and economic penalties to us or permit the customer to terminate the contract.

Price adjustment, “price reopener” and other similar provisions in our multi-year coal sales contracts may reduce the protection from coal price volatility traditionally provided by coal supply contracts. Price reopener provisions are present in several of our multi-year coal sales contracts. These price reopener provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range of prices. In a limited number of agreements, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract pricerisks, which could adversely affect CNXM‘s cash flows, results of operations and our profitability.financial condition.
The construction of additions or modifications to CNXM’s existing systems involves numerous regulatory, environmental, political and legal uncertainties beyond its control and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If these projects are undertaken, they may not be completed on schedule, at the budgeted cost or at all.
Revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. For instance, if a processing facility is built, the construction may occur over an extended period of time, and CNXM may not receive any material increases in revenues until the project is completed. Additionally, facilities may be constructed to capture anticipated future production growth in an area in which such growth does not materialize. As a result, new gathering, compression, dehydration, treating or other midstream assets may not be able to attract enough throughput to achieve the expected investment return, which could adversely affect CNXM’s business, financial condition, results of operations, cash flows and ability to make cash distributions.
The construction of additions to CNXM’s existing assets may require it to obtain new rights-of-way prior to constructing new pipelines or facilities, which may not be obtained in a timely fashion or in a way that allows CNXM to connect new natural gas supplies to existing gathering pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, cash flows could be adversely affected.

Most of our coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal quality characteristics such as heat content, sulfur, ash, moisture, volatile matter, grindability, ash fusion temperature and size consist. Failure to meet these conditions could result in penalties or rejection of the coal at the election of the customer. Our coal



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sales contractsOur success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.
Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.
We may not achieve some or all of the expected benefits of the separation of CONSOL Energy, and failure to realize such benefits in a timely manner may materially adversely affect our business.
We may not be able to achieve the full strategic and financial benefits expected to result from the separation of our coal business, now operated by CONSOL Energy Inc., or such benefits may be delayed or not occur at all. The separation is expected to provide the following benefits, among others: (i) position management of each company to more effectively pursue its own focused, industry-specific strategy, creating additional operational flexibility and enabling our management team to focus on strengthening our core business, operations and other needs, and to pursue distinct and targeted opportunities for long-term growth and profitability; (ii) permit each company to efficiently allocate its capital to meet the unique needs of its own business, allowing each company to intensify its focus on its distinct business priorities and facilitate each business having a more appropriate capital aligned with its target capital levels and those of its peers, which is expected to increase access to capital; (iii) better position each company to recruit and retain executives and other employees with expertise more directly applicable to the needs of its business; allow each company more consistent application of incentive structures and targets, due to the common nature of the underlying businesses; clearer articulation of talent requirements for potential employees and understanding of the prerequisites and opportunities associated with each business; and (iv) improve understanding of each business in the capital markets and allow for a stronger, more focused investor base for each business; creation of two independent equity structures, enabling each business to use its own business-focused stock as consideration in acquisitions and equity compensation programs and creating a more efficient and valuable transaction currency and compensation tool.
We may not achieve these and other anticipated benefits for a variety of reasons, including, among others: (i) we may be more susceptible to market fluctuations and other adverse events than if CONSOL Energy were still a part of the company because our business is less diversified than it was prior to the completion of the separation; and (ii) as a smaller, independent company, we may be more susceptible to fluctuations in the prices of natural gas, without having the coal business to mitigate such volatility. If we fail to achieve some or all of the benefits expected to result from the separation, or if such benefits are delayed, it could have a material adverse effect on our competitive position, business, financial condition, results of operations and cash flows.
CONSOL Energy may fail to perform under various transaction agreements that were executed as part of the separation.
In connection with the separation, CNX and CONSOL Energy entered into a Separation and Distribution Agreement and also typically contain force majeure provisions allowingentered into various other agreements, including a Transition Services Agreement, a Tax Matters Agreement, an Employee Matters Agreement, an Intellectual Property Matters Agreement, intellectual property license agreements, a real estate sublease, and Master Cooperation and Safety Agreements. The Separation and Distribution Agreement, the Tax Matters Agreement and the Employee Matters Agreement, together with the documents and agreements by which the internal reorganization of the Company prior to the separation was effected, determined the allocation of assets and liabilities between the companies following the separation for those respective areas and included any necessary indemnifications related to liabilities and obligations in connection therewith. The Transition Services Agreement provides for the suspensionperformance of performancecertain services by either partyeach company for the duration of specified events. Force majeure events include, but are not limited to, floods, earthquakes, storms, fire, faults in the coal seam or other geologic conditions, other natural catastrophes, wars, terrorist acts, civil disturbances or disobedience, strikes, railroad transportation delays caused by a force majeure event and actions or restraints by court order and governmental authority or arbitration award. Depending on the languagebenefit of the contract, some contracts may terminate upon continuance of an event of force majeure that extendsother for a period greater than threeof time after the separation. We will rely on CONSOL Energy to twelve monthssatisfy its performance and some contractspayment obligations under these agreements. If CONSOL Energy is unable or unwilling to satisfy its obligations under these agreements, including its indemnification obligations, we could incur operational difficulties and/or losses.

In connection with the separation, CONSOL Energy has agreed to indemnify us for certain liabilities and we have agreed to indemnify CONSOL Energy for certain liabilities. If we are required to pay under these indemnities to CONSOL Energy, our financial results could be negatively impacted. The CONSOL Energy indemnity may obligatenot be sufficient to hold us harmless from the full amount of liabilities for which CONSOL Energy has been allocated responsibility, and CONSOL Energy may not be able to satisfy its indemnification obligations in the future.

Pursuant to the Separation and Distribution Agreement and certain other agreements with CONSOL Energy, CONSOL Energy has agreed to indemnify us for certain liabilities, and we have agreed to indemnify CONSOL Energy for certain liabilities, in each case for uncapped amounts. More specifically, CONSOL Energy assumed all liabilities related to their current and our former coal business, including liabilities having a book value of $955 million and liabilities that may arise due to the failure of purchasers of coal assets that we had previously disposed. Additionally, we remain liable as a guarantor on certain liabilities that


34


were assumed by CONSOL Energy in connection with the separation. The estimated value of these guarantees was approximately $192 Million at the time of the separation. Although CONSOL Energy agreed to indemnify us to perform notwithstanding whatthe extent that we are called upon to pay any of these liabilities, there is no assurance that CONSOL Energy will satisfy its obligations to indemnify us in these situations. For example we could be liable for liabilities assumed by Murray Energy and its subsidiaries (Murray Energy) in connection with the disposition of certain mines to Murray Energy in 2013 in the event that both Murray Energy and CONSOL Energy are unable to satisfy those liabilities.

Indemnities that we may be required to provide CONSOL Energy are not subject to any cap, may be significant and could negatively impact our business. Third-parties could also seek to hold us responsible for any of the liabilities that CONSOL Energy has agreed to retain. Any amounts we are required to pay pursuant to these indemnification obligations and other liabilities could require us to divert cash that would typicallyotherwise have been used in furtherance of our operating business. Further, the indemnity from CONSOL Energy may not be a force majeur event.sufficient to protect us against the full amount of such liabilities, and CONSOL Energy may not be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from CONSOL Energy any amounts for which we are held liable, we may be temporarily required to bear such losses. Each of these risks could negatively affect our business, results of operations and financial condition.

The majorityseparation of CONSOL Energy could result in substantial tax liability.

Under current U.S. federal income tax law, even if the distribution, together with certain related transactions, otherwise qualifies for tax-free treatment under Sections 355 and 368(a)(1)(D) of the Internal Revenue Code, the distribution may nevertheless be rendered taxable to us and our common unitsshareholders as a result of certain post-distribution transactions, including certain acquisitions of shares or assets of CNX or CONSOL Energy. The possibility of rendering the distribution taxable as a result of such transactions may limit our ability to pursue certain equity issuances, strategic transactions or other transactions that would otherwise maximize the value of our business. Under the Tax Matters Agreement that we entered into with CONSOL Energy, CONSOL Energy may be required to indemnify us against any additional taxes and related amounts resulting from (i) an acquisition of all or a portion of the equity securities or assets of CONSOL Energy, whether by merger or otherwise (and regardless of whether CONSOL Energy participated in CNX Coal Resources LPor otherwise facilitated the acquisition), (ii) issuing equity securities beyond certain thresholds, (iii) repurchasing shares of CONSOL Energy stock other than in certain open-market transactions, (iv) ceasing to actively conduct certain of its businesses, (v) other actions or failures to act by CONSOL Energy or (vi) any of CONSOL Energy’s representations, covenants or undertakings contained in any of the separation-related agreements and CONE Midstream Partners LP are subordinateddocuments or in any documents relating to other common units and wethe IRS private letter ruling and/or the opinions of tax advisors being incorrect or violated. However, the indemnity from CONSOL Energy may not receive distributions from CNX Coal Resources LPbe sufficient to protect us against the full amount of such additional taxes or CONE Midstream Partners LP.

As of December 31, 2016, we hold 11.6 million subordinated units (representing a 42.7 percent limited partnership interest) in CNX Coal Resources LP, which we call CNXC. The balance of our CNXC limited partnership interests are held in the form of preferredrelated liabilities, and common units. Subordinated units areCONSOL Energy may not entitled to any distribution from CNXC unless CNXC makes a minimum quarterly distribution of $0.4678 per Class A Preferred Unit and $0.5125 per common unit. CNXC made minimum distributions per subordinated unit equal to the distribution per common unit for five of the six quarters since CNXC’s IPO.  CNXC did not met the requirement for a subordinated unit distribution with respect to fiscal quarter ended June 30, 2016 and we did not receive a distribution per subordinated unit, however, CNXC was able to make minimum distributions per subordinated unit equal to the distribution per common unit with respect to the fiscal quarter ended September 30, 2016 and declared minimum distributions per subordinated unit equal to the distribution per common unit with respect to the fiscal quarter ended December 31, 2016. We cannot assure you that CNXC will continue to be able to make or will make the required minimum quarterly distribution onfully satisfy its preferred and common units or thatindemnification obligations. Moreover, even if we will receiveultimately succeed in recovering from CONSOL Energy any future distributions on our subordinated units. Failure by CNXC to make distributions to us on our subordinated units could adversely affect our liquidity. 

We hold 14.6 million subordinated units (representing 23.0 percent limited partnership interest) in CONE Midstream Partners LP,amounts for which we call CONE. The balance of CONE's limited partnership interests are held either by NOBLE Energy or in the formliable, we may be temporarily required to bear such losses. Each of common units. Subordinated units are not entitled to any distribution from CONE unless CONE makes a minimum quarterly distribution on its common unitsthese risks could negatively affect CNX’s business, results of $0.2125 per unit. CONE has met this requirement with respect to each of its fiscal quartersoperations and we received a distribution per subordinated unit equal to the distribution per common unit. However, we cannot assure you that CONE will continue to be able to make or will make the required minimum quarterly distribution on its common units or that we will receive any future distributions on our subordinated units. Failure by CONE to make distributions to us on our subordinated units could adversely affect our liquidity.financial condition.

ITEM 1B.Unresolved Staff Comments

None.

ITEM 2.Properties

See “E&P Operations” and “Coal Operations”Detail Operations in Item 1 of this 10-K for a description of CONSOL Energy'sCNX's properties.

ITEM 3.Legal Proceedings

The first through the seventh paragraphs of Note 22–18–Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K areis incorporated herein by reference.

ITEM 4.Mine Safety and Health Administration Safety Data

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this annual report.



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PART II

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

The Company's common stock is listed on the New York Stock Exchange under the symbol CNX. The following table sets forth, for the periods indicated, the range of high and low sales prices per share of our common stock as reported on the New York Stock Exchange and the cash dividends declared on the common stock for the periods indicated:
 High Low Dividends
Year Period Ended December 31, 2017Year Period Ended December 31, 2017      
Quarter Ended March 31, 2017 $17.11
 $12.77
 $—
Quarter Ended June 30, 2017 $15.16
 $11.73
 $—
Quarter Ended September 30, 2017 $14.88
 $12.03
 $—
 High Low DividendsQuarter Ended December 31, 2017 $16.11
 $13.00
 $—
Year Period Ended December 31, 2016Year Period Ended December 31, 2016      Year Period Ended December 31, 2016      
Quarter Ended March 31, 2016 $12.42
 $4.54
 $0.0100
Quarter Ended March 31, 2016 $10.75
 $3.93
 $0.0100
Quarter Ended June 30, 2016 $16.40
 $10.53
 $—
Quarter Ended June 30, 2016 $14.20
 $9.12
 $—
Quarter Ended September 30, 2016 $19.76
 $15.03
 $—
Quarter Ended September 30, 2016 $17.11
 $13.01
 $—
Quarter Ended December 31, 2016 $22.34
 $16.14
 $—
Quarter Ended December 31, 2016 $19.34
 $13.97
 $—
Year Period Ended December 31, 2015      
Quarter Ended March 31, 2015 $34.56
 $26.11
 $0.0625
Quarter Ended June 30, 2015 $34.14
 $21.44
 $0.0625
Quarter Ended September 30, 2015 $22.04
 $9.29
 $0.0100
Quarter Ended December 31, 2015 $11.99
 $6.30
 $0.0100

As of December 31, 2016,2017, there were 127120 holders of record of our common stock.

The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the common stock of CONSOL EnergyCNX to the cumulative shareholder return for the same period of a peer group and the Standard & Poor's 500 Stock Index. The peer group has changed from last year as a result of the spin-off of the 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). The current peer group is comprised of CONSOL Energy, Arch Coal Inc.,CNX, Antero Resources Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corp., DevonCorporation, Energen Corporation, EQT Corporation, Gulfport Energy Corp., EOG Resources Inc., NobleCorporation, PDC Energy, Inc., PeabodyRange Resources Corporation, SM Energy Corp.,Company, Southwestern Energy Co., QEP Resources Inc.,Whiting Petroleum Corporation, and WPX Energy, Inc., Teck Resources Limited, EQT, Range Resources Corp., Cabot Oil & Gas Corp., and Antero Resources Corp. The graph assumes that the value of the investment in CONSOL EnergyCNX common stock and each index was $100 at December 31, 2011.2012. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2016.2017.
  2011 2012 2013 2014 2015 2016
CONSOL Energy Inc. 100.0
 88.1
 103.4
 91.7
 21.7
 49.1
Peer Group 100.0
 96.8
 111.0
 76.5
 35.0
 87.3
S&P 500 Stock Index 100.0
 111.4
 144.4
 160.8
 159.7
 174.9



  2012 2013 2014 2015 2016 2017
CNX Resources Corporation 100.0
 119.9
 107.4
 25.7
 59.3
 55.0
Peer Group 100.0
 129.1
 88.3
 38.8
 53.1
 40.4
S&P 500 Stock Index 100.0
 129.6
 144.4
 143.4
 157.0
 187.4
Previous Peer Group 100.0
 116.4
 105.1
 44.8
 65.9
 119.0



















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Cumulative Total Shareholder Return Among CONSOL Energy Inc.,CNX Resources Corporation, Peer Group and S&P 500 Stock Index


The above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).

The declaration and payment of dividends by CONSOL EnergyCNX is subject to the discretion of CONSOL Energy’sCNXs Board of Directors, and no assurance can be given that CONSOL EnergyCNX will pay dividends in the future. CONSOL EnergyCNX suspended its quarterly dividend following the sale of the Buchanan Mine on March 31, 2016 to further reflect the Company's increased emphasis on growth. CONSOL Energy’sCNX’s Board of Directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’sCNX’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy,CNX, planned investments by CONSOL EnergyCNX and such other factors as the Board of Directors deems relevant. The Company's credit facility limits CONSOL Energy'sCNX's ability to pay dividends in excess of an annual rate of $0.50 per share when the Company's leverage ratio exceeds 3.50 to 1.00 and subject to an aggregate amount up to the then cumulative credit calculation. The total leverage ratio was 4.534.08 to 1.00 and the cumulative credit was approximately $781$389 million at December 31, 2016. The calculation of this ratio excludes CNXC.2017. The credit facility does not permit dividend payments in the event of default. The indentures to the 2022 and 2023 notes limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the year ended December 31, 2016.2017.
See Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information relating to CONSOL Energy'sCNX's equity compensation plans.


5037


ITEM 6.Selected Financial Data

The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the years ended December 31, 2017, 2016, 2015, 2014 2013 and 20122013 are derived from our audited Consolidated Financial Statements. Certain reclassifications of prior year data have been made to conform to the year ended December 31, 20162017 presentation. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes included in this Annual Report.
(Dollars in thousands, except per share data) For the Years Ended December 31, For the Years Ended December 31,
 2016 2015 2014 2013 2012 2017 2016 2015 2014 2013
Operating revenues from Continuing Operations $1,839,571
 $2,474,815
 $2,953,365
 $2,400,187
 $2,387,093
(Loss) Income from Continuing Operations $(535,965) $(350,266) $164,947
 $(16,393) $245,663
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders $(848,102) $(374,885) $163,090
 $660,442
 $388,470
Earnings (Loss) per share:          
Revenue and Other Operating Income from Continuing Operations $1,455,131
 $759,968
 $1,198,737
 $1,080,351
 $730,917
Income (Loss) from Continuing Operations $295,039
 $(550,945) $(650,198) $(269,625) $(442,539)
Net Income (Loss) $380,747
 $(848,102) $(374,885) $163,090
 $660,442
Earnings per share:          
Basic:                    
(Loss) Income from Continuing Operations $(2.38) $(1.57) $0.72
 $(0.07) $1.08
(Loss) Income from Discontinued Operations (1.32) (0.07) (0.01) 2.96
 0.63
Net (Loss) Income $(3.70) $(1.64) $0.71
 $2.89
 $1.71
Income (Loss) from Continuing Operations $1.29
 $(2.40) $(2.84) $(1.17) $(1.93)
Income (Loss) from Discontinued Operations 0.37
 (1.30) 1.20
 1.88
 4.82
Net Income (Loss) $1.66
 $(3.70) $(1.64) $0.71
 $2.89
Dilutive:                    
(Loss) Income from Continuing Operations $(2.38) $(1.57) $0.71
 $(.07) $1.07
(Loss) Income from Discontinued Operations (1.32) (0.07) (0.01) 2.94
 0.63
Net (Loss) Income $(3.70) $(1.64) $0.70
 $2.87
 $1.70
Income (Loss) from Continuing Operations $1.28
 $(2.40) $(2.84) $(1.17) $(1.92)
Income (Loss) from Discontinued Operations 0.37
 (1.30) 1.20
 1.87
 4.79
Net Income (Loss) $1.65
 $(3.70) $(1.64) $0.70
 $2.87
                    
Assets from Continuing Operations $9,183,898
 $9,908,082
 $10,645,099
 $10,105,731
 $8,593,069
 $6,931,913
 $6,682,770
 $7,302,119
 $7,968,069
 $7,991,623
Assets from Discontinued Operations 83
 1,021,820
 1,009,546
 1,042,204
 3,770,061
 —
 2,496,921
 3,627,783
 3,686,576
 3,156,312
Total Assets $9,183,981
 $10,929,902
 $11,654,645
 $11,147,935
 $12,363,130
 $6,931,913
 $9,179,691
 $10,929,902
 $11,654,645
 $11,147,935
                    
Long-Term Debt from Continuing Operations (including current portion) $2,774,069
 $3,700,192
 $3,247,407
 $3,137,522
 $3,140,656
 $2,214,484
 $2,456,354
 $2,460,633
 $3,129,433
 $3,030,165
Long-Term Debt from Discontinued Operations (including current portion) —
 6,665
 3,171
 3,063
 5,640
 —
 317,715
 294,222
 120,128
 110,420
Total Long-Term Debt (including current portion) $2,774,069
 $3,706,857
 $3,250,578
 $3,140,585
 $3,146,296
 $2,214,484
 $2,774,069
 $2,754,855
 $3,249,561
 $3,140,585
Cash Dividends Declared Per Share of Common Stock $0.010
 $0.145
 $0.250
 $0.375
 $0.625
 $—
 $0.010
 $0.145
 $0.250
 $0.375
See Item 1A, “Risk Factors” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations��Operations” for a discussion of an adjustment to operating revenuesincome for all periods and other matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.

















51



OTHER OPERATING DATA
(unaudited)
  Years Ended December 31,
  2016 2015 2014 2013 2012
Gas:          
Net sales volumes produced (in Bcfe) 394.4
 328.7
 235.7
 172.4
 156.3
Average sales price ($ per Mcfe) (A) $2.63
 $2.81
 $4.37
 $4.30
 $4.22
Average cost ($ per Mcfe) $2.32
 $2.62
 $3.13
 $3.42
 $3.28
Proved reserves (in Bcfe) (B) 6,252
 5,643
 6,828
 5,731
 3,993
           
Coal:          
Tons sold from continuing operations (in thousands) 24,604
 22,873
 26,133
 21,230
 19,570
Tons produced from continuing operations (in thousands) 24,666
 22,790
 26,066
 21,433
 19,582
Average sales price of tons produced ($ per ton produced) $43.31
 $56.36
 $61.88
 $63.93
 $67.67
Average Cost of Goods Sold ($ per ton produced) $34.35
 $41.78
 $43.63
 $44.53
 $44.62
Recoverable coal reserves (tons in millions) (C) 2,361
 3,047
 3,238
 3,032
 4,229
Number of active mining complexes (at end of period) 1
 1
 1
 1
 1
  Years Ended December 31,
  2017 2016 2015 2014 2013
Gas:          
Net sales volumes produced (in Bcfe) 407.2
 394.4
 328.7
 235.7
 172.4
Average sales price ($ per Mcfe) (A) $2.66
 $2.63
 $2.81
 $4.37
 $4.30
Average cost ($ per Mcfe) $2.23
 $2.32
 $2.62
 $3.13
 $3.42
Proved reserves (in Bcfe) (B) 7,582
 6,252
 5,643
 6,828
 5,731
____________
(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.



5238



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

General

20162017 Highlights

Record total gas production of 394.4407.2 Bcfe in 2016, 20.0%2017, 3.2% higher than 2015.2016.
Record Marcellus Shale production of 212.5239.4 Bcfe in 2016, 23.3%2017, 12.7% higher than 2015.2016.
Record Utica Shale production of 90.8 Bcfe in 2016, 61.6%Increased proved reserves to 7.6 Tcfe, 20.6% higher than 2015.
2016.
In March 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, completeda coal company, formerly known as CONSOL Mining Corporation; and CNX, a natural gas exploration and production company. As a result of the saleseparation 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 bycompanies, CONSOL Energy and Nobleits 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 Inc.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 their respective operating areas will remain fully dedicatedthe Audited Consolidated Financial Statements in Item 8 of this Form 10-K to CONE Midstream Partners LP. Cash proceeds of $213,295 were received at closing.discontinued operations for all periods presented.
Gas production costs continue to decline - for the year ended December 31, 2016,2017, total gas production costs were $2.32$2.23 per Mcfe, an 11.5%a 3.9% decline from the prior year.
Made paymentsRepurchased $103 million of common stock on the senior secured credit facility of $952,000, resulting in zero drawings at the end of 2016, increasing liquidity.open market.


20172018 Outlook:

Our 20172018 annual gas production is expected to increase to approximately 415520-550 Bcfe.
Our 20172018 E&P capital investment is expected to be approximately $555 million.$790-$880 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.












5339


Results of Operations: Year Ended December 31, 20162017 Compared with the Year Ended December 31, 20152016
Net Loss AttributableIncome (Loss)
CNX reported net income of $381 million, or a earnings per diluted share of $1.65, for the year ended December 31, 2017, compared to CONSOL Energy Shareholders
CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $848 million, or a loss per diluted shareshared of $3.70, for the year ended December 31, 2016, compared to a net loss attributable to CONSOL Energy shareholders of $375 million, or a loss per diluted shared of $1.64, for the year ended December 31, 2015.2016.
 For the Years Ended December 31,
(Dollars in thousands)2016 2015 Variance
Loss from Continuing Operations$(535,965) $(350,266) $(185,699)
Loss from Discontinued Operations(303,183) (14,209) (288,974)
Net Loss$(839,148) $(364,475) $(474,673)
Less: Net Income Attributable to Noncontrolling Interests8,954
 10,410
 (1,456)
Net Loss Attributable to CONSOL Energy Shareholders$(848,102) $(374,885) $(473,217)
 For the Years Ended December 31,
(Dollars in thousands)2017 2016 Variance
Income (Loss) from Continuing Operations$295,039
 $(550,945) $845,984
Income (Loss) from Discontinued Operations85,708
 (297,157) 382,865
Net Income (Loss)$380,747
 $(848,102) $1,228,849

CONSOL Energy consists of twoCNX's principal business divisions: Exploration and Production (E&P) and Pennsylvania (PA) Mining Operations.activity is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The E&P division includes fourCompany's reportable segments:segments are Marcellus Shale, Utica Shale, Coalbed Methane, (CBM) and Other Gas.

The E&P divisionCNX had a lossincome from continuing operations before income tax of $379$119 million for the year ended December 31, 2016,2017, compared to a loss from continuing operations before income tax of $679$585 million for the year ended December 31, 2015.2016. Included in the2017 was an unrealized gain on commodity derivative instruments of $248 million and a gain on sale of assets of $188 million. Included in 2016 net loss before income tax was an unrealized loss on commodity derivative instruments of $386 million, partially offset by a gain on sale of assets of $14 million. IncludedSee Note 3 - Acquisitions and Dispositions in the 2015 net loss before income tax was a loss of $829 million primarily related to the impairment of the carrying value of CONSOL Energy's shallow oil and natural gas assets due to depressed NYMEX forward strip prices (see Note 9 - Property, Plant and Equipment of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). The impairment loss was partially off-set by an unrealized gain on commodity derivative instruments of $197 million.information.

The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s natural gas production and sales portfolio.

 For the Years Ended December 31, For the Years Ended December 31,
in thousands (unless noted) 2016 2015 Variance Percent
Change		 2017 2016 Variance Percent
Change
LIQUIDS                
NGLs:                
Sales Volume (MMcfe) 40,260
 33,180
 7,080
 21.3 % 38,736
 40,260
 (1,524) (3.8)%
Sales Volume (Mbbls) 6,710
 5,530
 1,180
 21.3 % 6,456
 6,710
 (254) (3.8)%
Gross Price ($/Bbl) $14.52
 $12.30
 $2.22
 18.0 % $24.18
 $14.52
 $9.66
 66.5 %
Gross Revenue $97,580
 $68,057
 $29,523
 43.4 % $156,132
 $97,580
 $58,552
 60.0 %
                
Oil:                
Sales Volume (MMcfe) 410
 592
 (182) (30.7)% 421
 410
 11
 2.7 %
Sales Volume (Mbbls) 68
 99
 (31) (31.3)% 70
 68
 2
 2.9 %
Gross Price ($/Bbl) $36.90
 $47.94
 $(11.04) (23.0)% $45.36
 $36.90
 $8.46
 22.9 %
Gross Revenue $2,521
 $4,736
 $(2,215) (46.8)% $3,179
 $2,521
 $658
 26.1 %
                
Condensate:                
Sales Volume (MMcfe) 4,964
 7,598
 (2,634) (34.7)% 3,116
 4,964
 (1,848) (37.2)%
Sales Volume (Mbbls) 827
 1,266
 (439) (34.7)% 519
 828
 (309) (37.3)%
Gross Price ($/Bbl) $27.48
 $26.52
 $0.96
 3.6 % $39.54
 $27.48
 $12.06
 43.9 %
Gross Revenue $22,748
 $33,586
 $(10,838) (32.3)% $20,531
 $22,748
 $(2,217) (9.7)%
                
GAS                
Sales Volume (MMcf) 348,753
 287,287
 61,466
 21.4 % 364,893
 348,753
 16,140
 4.6 %
Sales Price ($/Mcf) $1.92
 $2.17
 $(0.25) (11.5)% $2.59
 $1.92
 $0.67
 34.9 %
Gross Revenue $670,823
 $622,080
 $48,743
 7.8 % $945,382
 $670,823
 $274,559
 40.9 %
                
Hedging Impact ($/Mcf) $0.70
 $0.68
 $0.02
 2.9 % $(0.11) $0.70
 $(0.81) (115.7)%
Gain on Commodity Derivative Instruments - Cash Settlement $245,212
 $196,348
 $48,864
 24.9 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement $(41,174) $245,212
 $(286,386) (116.8)%




5440


The E&P division naturalNatural gas, NGLs, and oil sales were $794$1,125 million for the year ended December 31, 2016,2017, compared to $729$793 million for the year ended December 31, 2015.2016. The increase was primarily due to the 20.0%34.9% increase in total E&P sales volumes, offset in part by the 11.5% decrease in the average gas sales price per Mcf without the impact of derivative instruments fromand the table above. The decrease3.2% increase in averagetotal sales price was the result of the overall decrease in general market prices.volumes.
The E&P division salesSales volumes, average sales price (including the effects of derivatives instruments), and average costs for all active E&P operations were as follows: 
For the Years Ended December 31,For the Years Ended December 31,
2016 2015 Variance 
Percent
Change
2017 2016 Variance 
Percent
Change
E&P Sales Volumes (Bcfe)394.4
 328.7
 65.7
 20.0 %
Sales Volumes (Bcfe)407.2
 394.4
 12.8
 3.2 %
              
Average Sales Price (per Mcfe)$2.63
 $2.81
 $(0.18) (6.4)%$2.66
 $2.63
 $0.03
 1.1 %
Average Costs (per Mcfe)2.32
 2.62
 (0.30) (11.5)%2.23
 2.32
 (0.09) (3.9)%
Average Margin$0.31
 $0.19
 $0.12
 63.2 %$0.43
 $0.31
 $0.12
 38.7 %

The increase in average sales price was primarily the result of a $0.67 per Mcf increase in general natural gas market prices in the Appalachian basin during the current period, as well as an overall increase in natural gas liquids pricing. The increase was offset, in part, by a $0.81 per Mcf decrease in the realized (loss) gain on commodity derivative instruments related to the Company's hedging program.

Changes in the average costs per Mcfe were primarily related to the following items:
The improvement in unit costs isDepreciation, depletion, and amortization decreased on a per-unit basis primarily due to the continuing shift towards lower costa reduction in 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 wellrates 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, byresult of an increase in total dollars relatingthe Company's Marcellus reserves. See Note 7 - Property, Plant, and Equipment in the Notes to higher salt water disposal costs.the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
Transportation, gathering and compressionLease operating 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 pipelinewell tending costs and facility maintenance expense. Thesalt water disposal costs, as well as a decrease in both Company operated and joint venture operated repairs and maintenance costs.

Certain costs and expenses such as selling, general and administrative, other expense, gain on sale of assets, loss on debt extinguishment, interest expense and income taxes are unallocated expenses and therefore are excluded from the per unit costs was partially offset by an increaseabove as well as segment reporting. Below is a summary of these costs and expenses:

Selling, General and Administrative

Selling, general and administrative (SG&A) costs include costs such as overhead, including employee wages and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, and legal compliance expenses. SG&A costs also include noncash equity-based compensation expense.

SG&A costs were $93 million for the year ended December 31, 2017, compared to $105 million for the year ended December 31, 2016. SG&A costs decreased due to a decrease in total dollarsemployee wages and benefits costs in the current year related to ana reduction in headcount as well as a decrease in equity-based compensation expense.


















41


Other Expense
 For the Years Ended December 31,
 (in millions)2017 2016 Variance 
Percent
Change
Other Income       
Royalty Income$10
 $10
 $—
 — %
Right of Way Sales2
 15
 (13) (86.7)%
Interest Income9
 —
 9
 100.0 %
Other6
 4
 2
 50.0 %
Total Other Income$27
 $29
 $(2) (6.9)%
        
Other Expense       
Bank Fees$13
 $13
 $—
 — %
Other Corporate Expense12
 16
 (4) (25.0)%
Other Land Rental Expense6
 5
 1
 20.0 %
Total Other Expense$31
 $34
 $(3) (8.8)%
        
       Total Other Expense$4
 $5
 $(1) (20.0)%

Gain on Sale of Assets

CNX recognized a gain on sale of assets of $188 million in the year ended December 31, 2017 compared to a gain of $14 million in the year ended December 31, 2016. The $174 million increase in utilized firm transportation costs, increased processing fees associated with NGLs, and an increase in CONE gathering expense directly relatedwas primarily due to the increasesale of approximately 35,900 net undeveloped acres in Marcellus production.Ohio, Pennsylvania, and West Virginia in the current period. No individually significant transactions occurred in the year ended December 31, 2016. See Note 253 - Related Party Transactions ofAcquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

The PA Mining Operations division had earnings before income taxLoss on Debt Extinguishment

Loss on debt extinguishment of $131$2 million forwas recognized in the year ended December 31, 2016, compared2017 due to earnings before income tax of $405 million for the year ended December 31, 2015.
Sales tons, average sales price and average cost of goods sold per ton for the PA Mining Operations division were as follows:
 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Company Produced PA Mining Operations Tons sold (in millions)24.6
 22.9
 1.7
 7.4 %
        
Average Sales Price per ton sold$43.31
 $56.36
 $(13.05) (23.2)%
Average Costs of Goods Sold per ton sold34.35
 41.78
 (7.43) (17.8)%
Average Margin$8.96
 $14.58
 $(5.62) (38.5)%

The lower average sales price per ton sold in the 2016 period was primarily the resultredemption of the overall decline8.25% senior notes due in April 2020, the domestic and global thermal coal markets, particularly in the first half of 2016. This decline was primarily related to higher customer inventories and lower gas prices after persistently mild 2015 weather. This was off-set by an increase in overall tons sold reflecting the improvement in both domestic and international coal demand throughout the second half of 2016.

The PA Mining Operations division priced 5.4 million tons on the export market for the year ended December 31, 2016, compared to 5.5 million tons for the year ended December 31, 2015. All other tons were sold on the domestic market.



55


Changes in the average cost of goods sold per ton were primarily driven by the idling of one longwall at the PA Mining Operations complex for approximately 90 days, a reduction of staffing levels and a realignment of employee benefits in the current year. Allredemption of the above steps resulted6.375% senior notes due in more consistent operating schedules, reduced labor costs,March 2021 and improved productivity.
The Other division includes other business activities not assigned to the E&P or PA Mining Operations division and income taxes. The Other division hadpurchase of a net loss of $287 million for the year ended December 31, 2016, compared to a net loss of $77 million for the year ended December 31, 2015.
Selling, general and administrative (SG&A) costs are allocated to the PA Mining Operations division based upon a shared service agreement that CONSOL Energy entered into with CNX Coal Resources LP (CNXC) upon executionportion of the CNXC initial public offering (IPO). The shared service agreement calls for CONSOL Energy to provide certain selling, general and administrative services that are paid for monthly, based on an agreed upon fixed fee that is reset at least annually.5.875% senior notes due in April 2022. See Note 2510 - Related Party Transactions ofLong Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. The remaining SG&A costs are allocated between the E&P and Other divisions based primarily on a percentage of total revenue and a percentage of total projected capital expenditures.

SG&A costs are excluded fromInterest Expense
Interest expense of $161 million was recognized in the E&Pyear ended December 31, 2017, compared to $182 million in the year ended December 31, 2016. The $21 million decrease was primarily due to the redemption of the 2020 and PA Mining Operations unit costs above. SG&A costs were $153 million2021 senior notes and the payoff of a portion of the 2022 senior notes during the year ended December 31, 2017.

Income Taxes

The effective income tax rate for continuing operations was (148.9)% for the year ended December 31, 2016,2017, compared to $158 million6.0% for the year ended December 31, 2015. SG&A costs decreased due2016. During the year ended December 31, 2017, CNX recognized favorable benefits of $279 million related to the following items:
 For the Years Ended December 31,
 (in millions)2016 2015 Variance 
Percent
Change
Short-Term Incentive Compensation$29
 $40
 $(11) (27.5)%
Employee Wages and Related Expenses54
 62
 (8) (12.9)%
Advertising and Promotion5
 7
 (2) (28.6)%
Rent8
 8
 —
 — %
Consulting and Professional Services15
 15
 —
 — %
Contributions1
 1
 —
 — %
Stock-Based Compensation31
 25
 6
 24.0 %
Other10
 —
 10
 100.0 %
       Total Company Selling, General and Administrative Expense$153
 $158
 $(5) (3.2)%
impacts of income tax reform.

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.

Total Company long-term liabilities, such as Other Post-Employment Benefits (OPEB), the salary retirement plan, workers' compensation, Coal Workers' Pneumoconiosis (CWP), and long-term disability are actuarially calculated for the Company as a whole. In general, the expenses are then allocated to the segments based upon criteria specific to each liability. Total CONSOL Energy continuing operations expense related to actuarial liabilities was $74 million forDuring the year ended December 31, 2016, comparedCNX settled a Federal audit of the years 2010-2013 and received a favorable private letter ruling from the IRS related to incomebonus depreciation. Overall, the Company received approximately $21 million in refunds during 2016. Some of $162the factors contributing to the refunds received during 2016 put pressure on deferred tax assets related to alternative minimum tax credits. As management could not demonstrate sufficient positive evidence to ensure realizability of these assets, the Company recorded a valuation allowance of $167 million at December 31, 2016 on alternative minimum tax credits as well as an additional $38 million valuation allowance against state deferred tax assets and federal charitable contribution and foreign tax credit carry-forwards.



42


On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the "Act") which, among other things, lowered the U.S. Federal tax rate from 35% to 21%, repealed the corporate alternative minimum tax, and provided for a refund of previously accrued alternative minimum tax credits. The Company recorded a net tax benefit to reflect the impact of the Act as of December 31, 2017, as it is required to reflect the change in the period in which the law is enacted. Largely, the benefits recorded in the current period related to tax reform are in recognition of the revaluation of deferred tax assets and liabilities, a benefit of $115 million, and the benefit for reversal of valuation allowance previously recorded against alternative minimum tax credits which are now refundable, a benefit of $154 million. At December 31, 2017, the Company has not finalized its accounting for the year ended December 31, 2015. The increasetax effects of $236 million is primarily due to modifications madethe Act. However, as described in Note 5 - Income Taxes in the Notes to the OPEB and Pension plansAudited Consolidated Financial Statements in May 2015. Item 8 of this Form 10-K, CNX has made a reasonable estimate of the tax effects of the Act, including the impact on existing deferred tax balances. The Company is still analyzing certain aspects of the Act, which could potentially affect the measurement of the Company's income tax balances.

See Note 14—Pension and Other Postretirement Benefit Plans and Note 15—Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation5 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.information.

 For the Years Ended December 31,
 2017 2016 Variance 
Percent
Change
Total Company Earnings (Loss) Before Income Tax$119
 $(585) $704
 (120.3)%
Income Tax Benefit$(176) $(34) $(142) 417.6 %
Effective Income Tax Rate(148.9)% 6.0% (154.9)%  


5643


TOTAL E&P DIVISIONOPERATING SEGMENT ANALYSIS for the year ended December 31, 20162017 compared to the year ended December 31, 2015:2016:
The E&P divisionCNX operating segments had a lossearnings before income tax of $379$191 million for the year ended December 31, 20162017 compared to a loss before income tax of $679$308 million for the year ended December 31, 2015.2016. Variances by individual E&Poperating segment are discussed below.
For the Year Ended Difference to Year EndedFor the Year Ended Difference to Year Ended
December 31, 2016 December 31, 2015December 31, 2017 December 31, 2016
(in millions)Marcellus Utica CBM 
Other
Gas
 
Total
E&P
 Marcellus Utica CBM 
Other
Gas
 
Total
E&P
Marcellus Utica CBM 
Other
Gas
 Total Marcellus Utica CBM 
Other
Gas
 Total
Natural Gas, NGLs and Oil Sales$415
 $163
 $175
 $41
 $794
 $36
 $70
 $(27) $(14) $65
$646
 $217
 $209
 $53
 $1,125
 $231
 $54
 $34
 $13
 $332
Gain (Loss) on Commodity Derivative Instruments147
 29
 52
 (369) (141) 46
 23
 (15) (588) (534)
(Loss) Gain on Commodity Derivative Instruments(30) 1
 (10) 246
 207
 (177) (28) (62) 615
 348
Purchased Gas Sales—
 —
 —
 43
 43
 —
 —
 —
 29
 29
—
 —
 —
 54
 54
 —
 —
 —
 11
 11
Miscellaneous Other Income—
 —
 —
 81
 81
 —
 —
 —
 19
 19
Gain on Sale of Assets—
 —
 —
 14
 14
 —
 —
 —
 1
 1
Total Revenue and Other Income562
 192
 227
 (190) 791
 82
 93
 (42) (553) (420)
Other Operating Income—
 —
 —
 69
 69
 —
 —
 —
 4
 4
Total Revenue and Other Operating Income616
 218
 199
 422
 1,455
 54
 26
 (28) 643
 695
Lease Operating Expense34
 22
 25
 15
 96
 (10) —
 (8) (8) (26)32
 19
 25
 13
 89
 (2) (3) —
 (2) (7)
Production, Ad Valorem, and Other Fees17
 5
 6
 3
 31
 (1) 3
 (1) —
 1
15
 5
 7
 2
 29
 (2) —
 1
 (1) (2)
Transportation, Gathering and Compression228
 51
 72
 23
 374
 28
 16
 (13) —
 31
256
 45
 64
 18
 383
 28
 (6) (8) (5) 9
Depreciation, Depletion and Amortization211
 86
 86
 35
 418
 49
 27
 2
 (31) 47
222
 84
 83
 23
 412
 11
 (2) (3) (14) (8)
Impairment of Exploration and Production Properties—
 —
 —
 138
 138
 —
 —
 —
 138
 138
Exploration and Production Related Other Costs—
 —
 —
 15
 15
 —
 —
 —
 5
 5
—
 —
 —
 48
 48
 —
 —
 —
 33
 33
Purchased Gas Costs—
 —
 —
 43
 43
 —
 —
 —
 32
 32
—
 —
 —
 53
 53
 —
 —
 —
 10
 10
Other Corporate Expenses—
 —
 —
 88
 88
 —
 —
 —
 22
 22
Impairment of Exploration and Production Properties—
 —
 —
 —
 —
 —
 —
 —
 (829) (829)
Selling, General and Administrative Costs—
 —
 —
 102
 102
 —
 —
 —
 —
 —
Total Exploration and Production Costs490
 164
 189
 324
 1,167
 66
 46
 (20) (809) (717)
Interest Expense—
 —
 —
 3
 3
 —
 —
 —
 (3) (3)
Total E&P Division Costs490
 164
 189
 327
 1,170
 66
 46
 (20) (812) (720)
Other Operating Expense—
 —
 —
 112
 112
 —
 —
 —
 23
 23
Total Operating Costs and Expenses525
 153
 179
 407
 1,264
 35
 (11) (10) 182
 196
Earnings (Loss) Before Income Tax$72
 $28
 $38
 $(517) $(379) $16
 $47
 $(22) $259
 $300
$91
 $65
 $20
 $15
 $191
 $19
 $37
 $(18) $461
 $499



5744


MARCELLUS SEGMENT
The Marcellus segment had earnings before income tax of $91 million for the year ended December 31, 2017 compared to earnings before income tax of $72 million for the year ended December 31, 2016 compared to earnings before income tax of $56 million for the year ended December 31, 2015.2016.
For the Years Ended December 31,For the Years Ended December 31,
2016 2015 Variance 
Percent
Change
2017 2016 Variance 
Percent
Change
Marcellus Gas Sales Volumes (Bcf)186.8
 149.4
 37.4
 25.0 %209.7
 186.8
 22.9
 12.3 %
NGLs Sales Volumes (Bcfe)*23.5
 19.0
 4.5
 23.7 %27.6
 23.5
 4.1
 17.4 %
Condensate Sales Volumes (Bcfe)*2.2
 3.9
 (1.7) (43.6)%2.1
 2.2
 (0.1) (4.5)%
Total Marcellus Sales Volumes (Bcfe)*212.5
 172.3
 40.2
 23.3 %239.4
 212.5
 26.9
 12.7 %
              
Average Sales Price - Gas (Mcf)$1.87
 $2.09
 $(0.22) (10.5)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)$0.79
 $0.67
 $0.12
 17.9 %
Average Sales Price - NGLs (Mcfe)*$2.38
 $2.54
 $(0.16) (6.3)%
Average Sales Price - Condensate (Mcfe)*$4.32
 $5.02
 $(0.70) (13.9)%
Average Sales Price - Gas (per Mcf)$2.50
 $1.87
 $0.63
 33.7 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$(0.14) $0.79
 $(0.93) (117.7)%
Average Sales Price - NGLs (per Mcfe)*$3.96
 $2.38
 $1.58
 66.4 %
Average Sales Price - Condensate (per Mcfe)*$6.44
 $4.32
 $2.12
 49.1 %
              
Total Average Marcellus Sales Price (per Mcfe)$2.64
 $2.79
 $(0.15) (5.4)%$2.57
 $2.64
 $(0.07) (2.7)%
Average Marcellus Lease Operating Expenses (per Mcfe)0.16
 0.26
 (0.10) (38.5)%0.13
 0.16
 (0.03) (18.8)%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)0.08
 0.10
 (0.02) (20.0)%0.07
 0.08
 (0.01) (12.5)%
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe)1.07
 1.16
 (0.09) (7.8)%1.07
 1.07
 —
 — %
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)0.99
 0.94
 0.05
 5.3 %0.92
 0.99
 (0.07) (7.1)%
Total Average Marcellus Costs (per Mcfe)$2.30
 $2.46
 $(0.16) (6.5)%$2.19
 $2.30
 $(0.11) (4.8)%
Average Margin for Marcellus (per Mcfe)$0.34
 $0.33
 $0.01
 3.0 %$0.38
 $0.34
 $0.04
 11.8 %
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

The Marcellus segment had natural gas, NGLs and oil sales of $646 million for the year ended December 31, 2017 compared to $415 million for the year ended December 31, 2016 compared to $379 million for the year ended December 31, 2015.2016. The $36$231 million increase is primarily due to a 23.3%the 33.7% increase in the average gas sales price as well as the 12.7% increase in total Marcellus sales volumes partially offset by a 10.5% decrease in the average gas sales price in the period-to-period comparison. The increase in total sales volumes iswas primarily due to additional wells coming on-line in the current year, as well as the termination of the Marcellus Joint Venture that CONSOL Energy had with Noble Energy (Seein the fourth quarter of 2016, which resulted in each party owning and operating a 100% interest in certain wells in two separate operating areas (see Note 97 - Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details). The joint venture termination was effective October 1st, 2016 and resulted in additional production for the fourth quarter of 2016, as well as additional wells being turned in line in the applicable sales and production costs.current period.

The decrease in the total average Marcellus sales price was primarily the result of changes in the $0.22fair value of commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 177.6 Bcf of the Company's produced Marcellus gas sales volumes for the year ended December 31, 2017 at an average loss of $0.17 per Mcf. For the year ended December 31, 2016, these financial hedges represented approximately 160.8 Bcf at an average gain of $0.92 per Mcf. The $0.93 per Mcf decreasechange in the fair value of the commodity derivative instruments was offset, in part, by the $0.63 per Mcf increase in gas market prices, along with a $0.03$0.12 per Mcf decreaseMcfe increase in the uplift from NGLs and condensate sales volumes, when excluding the impact of hedging. These decreases

Total operating costs and expenses for the Marcellus segment were offset, in part, by a $0.12 per Mcf increase in the gain on commodity derivative instruments resulting from the Company's hedging program. The increase in the gain was due to an increase in volumes hedged and lower market prices. The notional amounts associated with these financial hedges represented approximately 160.8 Bcf of the Company's produced Marcellus gas sales volumes$525 million for the year ended December 31, 2016 at an average gain of $0.92 per Mcf. For the year ended December 31, 2015, these financial hedges represented approximately 90.3 Bcf at an average gain of $1.09 per Mcf.

Total exploration and production costs for the Marcellus segment were2017 compared to $490 million for the year ended December 31, 2016 compared to $424 million for the year ended December 31, 2015.2016. The increase in total dollars and decrease in unit costs for the Marcellus segment were due primarily to the following items:

•Marcellus lease operating expense was $32 million for the year ended December 31, 2017 compared to $34 million for the year ended December 31, 2016 compared to $44 million for the year ended December 31, 2015.2016. The decrease in total dollars was primarily due to a reduction in employee related costs, well tendingsalt water disposal costs and repairs and maintenanceequipment rental expense in the current period. The reductiondecrease in employee relatedunit costs was primarily due to the company reorganization that occurred in the second half of 2015 and the first quarter of 2016. The decrease in unit costs


58


was primarily due to the 23.3%12.7% increase in total Marcellus sales volumes, along with the decreaseddecrease in total dollars described above. The decreases were offset, in part, by an increase in salt water disposal costs in the period-to-period comparison.



45


•Marcellus production, ad valorem, and other fees were $15 million for the year ended December 31, 2017 compared to $17 million for the year ended December 31, 2016 compared to $18 million for the year ended December 31, 2015.2016. The decrease in total dollars was primarily due to a change in production mix by state as a result of the decrease in total averagetermination of the Marcellus sales price,joint venture with Noble Energy, offset, in part, by the increase in average gas sales price. The decrease in unit costs was due to the decrease in total dollars described above, as well as the 12.7% increase in total Marcellus sales volumes.

•Marcellus transportation, gathering and compression costs were $256 million for the year ended December 31, 2017 compared to $228 million for the year ended December 31, 2016 compared to $200 million for the year ended December 31, 2015.2016. The $28 million increase in total dollars was primarily related to an increase in the CONECNXM gathering fee due to the increase in total Marcellus sales volumes (See Note 2520 - Related Party Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information), and an increase in processing fees associated with natural gas liquidsNGLs primarily due to the 23.7%17.4% increase in NGLsNGL sales volumes, and an increase in utilized firm transportation expense. The decrease in unit costs was due to the increase in total Marcellus sales volumes, offset, in part, by the increase in total dollars.volumes.

•Depreciation, depletion and amortization costs attributable to the Marcellus segment were $222 million for the year ended December 31, 2017 compared to $211 million for the year ended December 31, 2016 compared to $162 million for the year ended December 31, 2015 driven primarily by the overall increase in production.2016. These amounts included depletion on a unit of production basis of $0.98$0.91 per Mcf and $0.92$0.98 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.

UTICA SEGMENT

The Utica segment had earnings before income tax of $65 million for the year ended December 31, 2017 compared to earnings before income tax of $28 million for the year ended December 31, 2016 compared to a loss before income tax of $19 million for the year ended December 31, 2015.2016.
For the Years Ended December 31,For the Years Ended December 31,
2016 2015 Variance 
Percent
Change
2017 2016 Variance 
Percent
Change
Utica Gas Sales Volumes (Bcf)71.3
 38.3
 33.0
 86.2 %70.7
 71.3
 (0.6) (0.8)%
NGLs Sales Volumes (Bcfe)*16.7
 14.1
 2.6
 18.4 %11.1
 16.7
 (5.6) (33.5)%
Oil Sales Volumes (Bcfe)*—
 0.1
 (0.1) (100.0)%0.2
 —
 0.2
 100.0 %
Condensate Sales Volumes (Bcfe)*2.8
 3.7
 (0.9) (24.3)%1.0
 2.8
 (1.8) (64.3)%
Total Utica Sales Volumes (Bcfe)*90.8
 56.2
 34.6
 61.6 %83.0
 90.8
 (7.8) (8.6)%
              
Average Sales Price - Gas (Mcf)$1.52
 $1.52
 $—
 — %
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)$0.41
 $0.17
 $0.24
 141.2 %
Average Sales Price - NGLs (Mcfe)*$2.49
 $1.39
 $1.10
 79.1 %
Average Sales Price - Oil (Mcfe)*$—
 $6.58
 $(6.58) (100.0)%
Average Sales Price - Condensate (Mcfe)*$4.78
 $3.79
 $0.99
 26.1 %
Average Sales Price - Gas (per Mcf)$2.29
 $1.52
 $0.77
 50.7 %
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$0.02
 $0.41
 $(0.39) (95.1)%
Average Sales Price - NGLs (per Mcfe)*$4.20
 $2.49
 $1.71
 68.7 %
Average Sales Price - Oil (per Mcfe)*$7.31
 $—
 $7.31
 100.0 %
Average Sales Price - Condensate (per Mcfe)*$6.88
 $4.78
 $2.10
 43.9 %
              
Total Average Utica Sales Price (per Mcfe)$2.12
 $1.75
 $0.37
 21.1 %$2.63
 $2.12
 $0.51
 24.1 %
Average Utica Lease Operating Expenses (per Mcfe)0.25
 0.39
 (0.14) (35.9)%0.23
 0.25
 (0.02) (8.0)%
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)0.05
 0.04
 0.01
 25.0 %0.06
 0.05
 0.01
 20.0 %
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)0.57
 0.61
 (0.04) (6.6)%0.54
 0.57
 (0.03) (5.3)%
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)0.94
 1.06
 (0.12) (11.3)%1.02
 0.94
 0.08
 8.5 %
Total Average Utica Costs (per Mcfe)$1.81
 $2.10
 $(0.29) (13.8)%$1.85
 $1.81
 $0.04
 2.2 %
Average Margin for Utica (per Mcfe)$0.31
 $(0.35) $0.66
 188.6 %$0.78
 $0.31
 $0.47
 151.6 %
*NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

The Utica segment had natural gas, NGLs and oil sales of $217 million for the year ended December 31, 2017 compared to $163 million for the year ended December 31, 2016 compared to $93 million for the year ended December 31, 2015.2016. The $70$54 million increase was primarily due to the 61.6%50.7% increase in average gas sales price, offset, in part, by the 8.6% decrease in total


59


Utica sales volumes. The 34.67.8 Bcfe increasedecrease in total Utica sales volumes was dueprimarily related to additional wells coming on-line, primarilynormal well declines in the wet gas joint venture production areas offset in part by increased production in the 100% CNX controlled dry Utica production areas inresulting from the current period.Company’s 2017 capital investments.



46


The increase in the total average Utica sales price was primarily due to a $0.24the $0.77 increase in average gas sales price, offset, in part, by the $0.39 per Mcf increasedecrease in the gain on commodity derivative instruments in the current period, as well as a $0.16 per Mcf increase in the uplift from NGLs and condensate sales volumes.period. The increase in the hedging gain was due to an increase in the volumes hedged that were designated as Utica volumes. Financialnotional amounts associated with these financial hedges represented approximately 31.639.8 Bcf of the Company's produced Utica gas sales volumes for the year ended December 31, 2017 at an average gain of $0.04 per Mcf. For the year ended December 31, 2016, these financial hedges represented approximately 31.6 Bcf at an average gain of $0.93 per Mcf. For

Total operating costs and expenses for the Utica segment were $153 million for the year ended December 31, 2015, these financial hedges represented approximately 5.9 Bcf at an average gain of $1.08 per Mcf.

Total exploration and production costs for the Utica segment were2017 compared to $164 million for the year ended December 31, 2016 compared to $118 million for the year ended December 31, 2015.2016. The increasedecrease in total dollars and decreaseincrease in unit costs for the Utica segment are due to the following items:

•Utica lease operating expense remained flat atdecreased to $19 million for the year ended December 31, 2017, compared to $22 million for each of the yearsyear ended December 31, 20162016. The decrease in total dollars was due to a reduction in repairs and December 31, 2015.maintenance costs and lower production volumes. The decrease in unit costs was primarily due to the 61.6% increasedecrease in totalrepairs and maintenance costs and a shift in production mix to lower cost dry Utica sales volumes.production.

•Utica production, ad valorem, and other fees were $5 million for each of the yearyears ended December 31, 2016 compared to $2 million for the year ended2017 and December 31, 2015. The increase in total dollars was primarily due to the 61.6% increase in total Utica sales volumes.2016. The increase in unit costs was also due to a credit received from a joint venture partnerthe decrease in the 2015 period, related to an over-billing of ad valorem taxes.total Utica sales volumes

•Utica transportation, gathering and compression costs were $45 million for the year ended December 31, 2017 compared to $51 million for the year ended December 31, 2016 compared to $352016. The $6 million for the year ended December 31, 2015. The $16 million increasedecrease in total dollars was primarily related to increaseddecreased gathering and processing fees associated with the increaseddecreased Utica NGLs and gas sales volumes. The decrease in unit costs was due to the increasedecrease in total Utica sales volumes, predominantly dry Utica, which wasin the wet areas that require additional processing offset, in part, by the increase in total dollars.the lower cost dry Utica production.

•Depreciation, depletion and amortization costs attributable to the Utica segment were $84 million for the year ended December 31, 2017 compared to $86 million for the year ended December 31, 2016 compared to $59 million for the year ended December 31, 2015 driven primarily by the overall increase in production.2016. These amounts included depletion on a unit of production basis of $0.93$1.01 per Mcf and $1.05$0.93 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $20 million for the year ended December 31, 2017 compared to earnings before income tax of $38 million for the year ended December 31, 2016 compared to earnings before income tax of $60 million for the year ended December 31, 2015.2016.
For the Years Ended December 31,For the Years Ended December 31,
2016 2015 Variance 
Percent
Change
2017 2016 Variance 
Percent
Change
CBM Gas Sales Volumes (Bcf)69.0
 74.9
 (5.9) (7.9)%65.4
 69.0
 (3.6) (5.2)%
              
Average Sales Price - Gas (Mcf)$2.53
 $2.70
 $(0.17) (6.3)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)$0.76
 $0.90
 $(0.14) (15.6)%
Average Sales Price - Gas (per Mcf)$3.19
 $2.53
 $0.66
 26.1 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$(0.15) $0.76
 $(0.91) (119.7)%
              
Total Average CBM Sales Price (per Mcf)$3.29
 $3.60
 $(0.31) (8.6)%$3.05
 $3.29
 $(0.24) (7.3)%
Average CBM Lease Operating Expenses (per Mcf)0.36
 0.44
 (0.08) (18.2)%0.39
 0.36
 0.03
 8.3 %
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)0.09
 0.10
 (0.01) (10.0)%0.11
 0.09
 0.02
 22.2 %
Average CBM Transportation, Gathering and Compression Costs (per Mcf)1.04
 1.13
 (0.09) (8.0)%0.98
 1.04
 (0.06) (5.8)%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)1.25
 1.13
 0.12
 10.6 %1.26
 1.25
 0.01
 0.8 %
Total Average CBM Costs (per Mcf)$2.74
 $2.80
 $(0.06) (2.1)%$2.74
 $2.74
 $—
 — %
Average Margin for CBM (per Mcf)$0.55
 $0.80
 $(0.25) (31.3)%$0.31
 $0.55
 $(0.24) (43.6)%

The CBM segment had natural gas sales of $209 million for the year ended December 31, 2017 compared to $175 million for the year ended December 31, 2016 compared to $2022016. The $34 million for the year ended December 31, 2015. The $27 million decreaseincrease was primarily due to a 6.3% decrease26.1% increase in the average gas sales


60


price, as well as a 7.9%offset, in part, by the 5.2% decrease in CBM gas sales volumes. The decrease in CBM sales volumes was primarily due to normal well declines and less drilling activity.



47


The total average CBM sales price decreased $0.31$0.24 per Mcf due primarily to a $0.17 per Mcf decreasechanges in gas market prices, as well as a $0.14 per Mcf decrease infair value of the gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 55.056.3 Bcf of the Company's produced CBM sales volumes for the year ended December 31, 2017 at an average loss of $0.17 per Mcf. For the year ended December 31, 2016, these financial hedges represented approximately 55.0 Bcf at an average gain of $0.95 per Mcf. ForThe $0.91 per Mcf change in fair value of the commodity derivative instruments was offset, in part, by a $0.66 per Mcf increase in market prices.

Total operating costs and expenses for the CBM segment were $179 million for the year ended December 31, 2015, these financial hedges represented approximately 57.5 Bcf at an average gain of $1.17 per Mcf.

Total exploration and production costs for the CBM segment were2017 compared to $189 million for the year ended December 31, 2016 compared to $209 million for the year ended December 31, 2015.2016. The decrease in total dollars and decrease in unit costs for the CBM segment werewas due to the following items:
 
•CBM lease operating expense wasremained consistent at $25 million for the yearyears ended December 31, 2016 compared to $33 million for the year ended2017 and December 31, 2015.2016. The decrease in total dollars was primarily related to a decrease in contractual services related to well tending, a decrease in repairs and maintenance expense, a decrease in employee related costs, and a decrease in salt water disposal costs. The decreaseincrease in unit costs was due to the decrease in total dollars, partially offset by the decrease in CBM gas sales volumes.

•CBM production, ad valorem, and other fees were $7 million for the year ended December 31, 2017 compared to $6 million for the year ended December 31, 2016 compared to $7 million for the year ended December 31, 2015.2016. The $1 million decreaseincrease was due to a decreasean increase in severance tax expense resulting from the decreaseincrease in boththe average gas sales volumes and average sales price. Unit costs were positively impactedprice, partially offset by the decrease in production volumes. Unit costs were negatively impacted by the increase in total average CBMgas sales price which was offset, in part, by the decrease in CBM gas sales volumes.

•CBM transportation, gathering and compression costs were $64 million for the year ended December 31, 2017 compared to $72 million for the year ended December 31, 2016 compared to $85 million for the year ended December 31, 2015.2016. The $13$8 million decrease was primarily related to a decrease in repairs and maintenance expense and power andfees resulting from cost cutting measures implemented by management as well as a decrease in utilized firm transportation expense resulting from the decrease in CBM gas sales volumes. Unit costs were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in CBM gas sales volumes.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $83 million for the year ended December 31, 2017 compared to $86 million for the year ended December 31, 2016 compared to $84 million for the year ended December 31, 2015.2016. These amounts included depletion on a unit of production basis of $0.82$0.78 per Mcf and $0.73$0.82 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.



6148


OTHER GAS SEGMENT
The Other Gas segment had a lossearnings before income tax of $517$15 million for the year ended December 31, 20162017 compared to a loss before income tax of $776$446 million for the year ended December 31, 2015.2016.
For the Years Ended December 31,For the Years Ended December 31,
2016 2015 Variance Percent
Change		2017 2016 Variance Percent
Change
Other Gas Sales Volumes (Bcf)21.7
 24.7
 (3.0) (12.1)%19.2
 21.7
 (2.5) (11.5)%
Oil Sales Volumes (Bcfe)*0.4
 0.5
 (0.1) (20.0)%0.2
 0.4
 (0.2) (50.0)%
Total Other Sales Volumes (Bcfe)*22.1
 25.2
 (3.1) (12.3)%19.4
 22.1
 (2.7) (12.2)%
              
Average Sales Price - Gas (Mcf)$1.79
 $2.03
 $(0.24) (11.8)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)$0.75
 $0.88
 $(0.13) (14.8)%
Average Sales Price - Oil (Mcfe)*$6.23
 $8.15
 $(1.92) (23.6)%
Average Sales Price - Gas (per Mcf)$2.69
 $1.79
 $0.90
 50.3 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$(0.14) $0.75
 $(0.89) (118.7)%
Average Sales Price - Oil (per Mcfe)*$7.75
 $6.23
 $1.52
 24.4 %
              
Total Average Other Sales Price (per Mcfe)$2.61
 $3.03
 $(0.42) (13.9)%$2.62
 $2.61
 $0.01
 0.4 %
Average Other Lease Operating Expenses (per Mcfe)0.69
 0.90
 (0.21) (23.3)%0.63
 0.69
 (0.06) (8.7)%
Average Other Production, Ad Valorem, and Other Fees (per Mcfe)0.12
 0.14
 (0.02) (14.3)%0.12
 0.12
 —
 — %
Average Other Transportation, Gathering and Compression Costs (per Mcfe)1.07
 0.96
 0.11
 11.5 %0.90
 1.07
 (0.17) (15.9)%
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe)1.49
 2.34
 (0.85) (36.3)%1.05
 1.49
 (0.44) (29.5)%
Total Average Other Costs (per Mcfe)$3.37
 $4.34
 $(0.97) (22.4)%$2.70
 $3.37
 $(0.67) (19.9)%
Average Margin for Other (per Mcfe)$(0.76) $(1.31) $0.55
 42.0 %$(0.08) $(0.76) $0.68
 89.5 %

*Oil is converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.

The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes purchased gas activity, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, other corporate expensesimpairment of exploration and miscellaneousproduction properties and other operational activity not assigned to a specific E&P segment.

Other Gas sales volumes are primarily related to shallow oil and gas production, as well as the Chattanooga shale in Tennessee.production. Natural gas, NGLs and oil sales related to the Other Gas segment were $41$53 million for the year ended December 31, 20162017 compared to $55$40 million for the year ended December 31, 2015.2016. The decreaseincrease in natural gas and oil sales primarily related toresulted from the $0.24$0.90 per Mcf decreaseincrease in average gas sales price. Total exploration and production costs related to these other sales were $76$56 million for the year ended December 31, 20162017 compared to $115$78 million for the year ended December 31, 2015.2016. The decrease was primarily due to a decrease in depreciation, depletion and amortization costs related to the adjustment to the Company's shallow oil and gas rates after an impairmentas a result of certain assets becoming fully depreciated in the carrying value was recognizedcurrent period as well as the sale of Knox Energy in the second quarter of 2015 (see2017 (See Note 93 - Property, PlantAcquisitions and Equipment ofDispositions in the Notes to the  Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $248 million as well as cash settlements paid of $2 million for the year ended December 31, 2017. For the year ended December 31, 2016, the Company recognized an unrealized loss on commodity derivative instruments of $386 million as well as cash settlements received of $17 million for the year ended December 31, 2016. For the year ended December 31, 2015, the Company recognized an unrealized gain on commodity derivative instruments of $197 million as well as cash settlements of $22 million. The unrealized loss/gaingain/loss on commodity derivative instruments represents changes in the fair value of all of the Company's existing commodity hedges on a mark-to-market basis and is the result of the December 31, 2014 de-designation of all derivative positions as cash flow hedges. Changes in fair value were recorded in Accumulated Other Comprehensive Income prior to de-designation.basis.

Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers. Purchased gas sales revenues were $54 million for the year ended December 31, 2017 compared to $43 million for the year ended December 31, 2016 compared to $142016. Purchased gas costs were $53 million for the year ended December 31, 2015. Purchased gas costs were2017 compared to $43 million for the year ended December 31, 2016 compared to $11 million for the year ended December 31, 2015.2016. The period-to-period increase in purchased gas sales revenue was primarily due to the increase in market prices, as well as the increase in purchased gas sales volumes, offset, in part, by the decrease in market prices.volumes.


6249


For the Years Ended December 31,For the Years Ended December 31,
2016 2015 Variance 
Percent
Change
2017 2016 Variance 
Percent
Change
Purchased Gas Sales Volumes (in billion cubic feet)21.7
 6.8
 14.9
 219.1 %22.0
 21.7
 0.3
 1.4%
Average Sales Price (per Mcf)$1.99
 $2.14
 $(0.15) (7.0)%$2.44
 $1.99
 $0.45
 22.6%
Average Cost (per Mcf)$1.97
 $1.59
 $0.38
 23.9 %$2.39
 $1.97
 $0.42
 21.3%

Miscellaneous otherOther operating income was $81$69 million for the year ended December 31, 20162017 compared to $62$65 million for the year ended December 31, 2015.2016. The $19$4 million increase was primarily due to the following items:
For the Years Ended December 31,For the Years Ended December 31,
(in millions)2016 2015 Variance 
Percent
Change
2017 2016 Variance 
Percent
Change
Right of Way Sales$15
 $2
 $13
 650.0%
Water Income$5
 $1
 $4
 400.0 %
Gathering Income11
 11
 —
 — %
Equity in Earnings of Affiliates52
 47
 5
 10.6%50
 53
 (3) (5.7)%
Gathering Revenue11
 10
 1
 10.0%
Other3
 3
 —
 —%3
 —
 3
 100.0 %
Total Miscellaneous Other Income$81
 $62
 $19
 30.6%
Total Other Operating Income$69
 $65
 $4
 6.2 %

Right of Way SalesWater Income increased $13$4 million in the period-to-period comparison due to an initiative in the current yearincreased sales of freshwater to generate additional revenue from our unutilized surface rights.third parties for hydraulic fracturing.
Equity in Earnings of Affiliates increased $5decreased $3 million primarily due to an increasea decrease in earnings from CONE Midstream Partners LPBuchanan Generation, LLC. 

Impairment of Exploration and CONE Gathering LLC.Production Properties of $138 million for the year ended December 31, 2017 related to an impairment in the carrying value of Knox Energy in the first quarter of 2017. See Note 251 - Related Party Transactions ofSignificant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Gain on sale of assets was $14 million forNo such impairments occurred in the year ended December 31, 2016 compared to $13 million for the year ended December 31, 2015. The $1 million increase was due to various land asset sales that occurred throughout both periods, none of which were individually material.prior year.
Exploration and production related other costs were $48 million for the year ended December 31, 2017 compared to $15 million for the year ended December 31, 2016 compared to $10 million for the year ended December 31, 2015.2016. The $5$33 million increase in costs is primarily related to the following items:
For the Years Ended December 31,For the Years Ended December 31,
(in millions)2016 2015 Variance 
Percent
Change
2017 2016 Variance 
Percent
Change
Lease Expiration Costs$7
 $4
 $3
 75.0 %$40
 $7
 $33
 471.4 %
Land Rentals4
 4
 —
 — %
Permitting Expense2
 1
 1
 100.0 %1
 2
 (1) (50.0)%
Land Rentals4
 5
 (1) (20.0)%
Other2
 —
 2
 100.0 %3
 2
 1
 50.0 %
Total Exploration and Other Costs$15
 $10
 $5
 50.0 %
Total Exploration and Production Related Other Costs$48
 $15
 $33
 220.0 %

Lease Expiration Costs increased by $3relate 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 primarilyis due to an increase in the number of leases that were allowed to expire in the year ended December 31, 2016 as compared to2017, or will expire within the year ended December 31, 2015.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.













50


Other corporate expenses were $88operating expense was $112 million for the year ended December 31, 20162017 compared to $66$89 million for the year ended December 31, 2015.2016. The $22$23 million increase in the period-to-period comparison was made up of the following items:


63

 For the Years Ended December 31,
 2017 2016 Variance 
Percent
Change
Idle Rig Expense$41
 $33
 $8
 24.2%
Unutilized Firm Transportation and Processing Fees50
 37
 13
 35.1%
Litigation Settlements3
 1
 2
 200.0%
Severance Expense1
 1
 —
 —%
Insurance Expense3
 3
 —
 —%
Other14
 14
 —
 —%
Total Other Operating Expense$112
 $89
 $23
 25.8%

 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Severance Expense$1
 $5
 $(4) (80.0)%
Litigation Settlements1
 2
 (1) (50.0)%
Insurance Expense3
 3
 —
 — %
Unutilized Firm Transportation and Processing Fees37
 33
 4
 12.1 %
Transaction Fees4
 —
 4
 100.0 %
Idle Rig Expense33
 19
 14
 73.7 %
Other9
 4
 5
 125.0 %
Total Other Corporate Expenses$88
 $66
 $22
 33.3 %

SeveranceIdle Rig Expense decreased $4increased $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 primarily due to the Company reorganizationa settlement that occurredwas reached with a former joint-venture partner that resulted in the third quarter of 2015. Amounts recorded in the current period are primarily due to the Company's first quarter 2016 reorganization.
CNX recording additional expense.
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.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 RevenueIncome in miscellaneous other operating income above.
Transaction Fees




51


Results of $4 million are associatedOperations: Year Ended December 31, 2016 Compared with the dissolutionYear Ended December 31, 2015
Net Loss
CNX reported a net loss of $848 million, or a loss per diluted share of $3.70, for the Noble Energyyear ended December 31, 2016, compared to a net loss of $375 million, or a loss of $1.64 per diluted share, for the year ended December 31, 2015.
 For the Years Ended December 31,
(Dollars in thousands)2016 2015 Variance
Loss from Continuing Operations$(550,945) $(650,198) $99,253
(Loss) Income from Discontinued Operations, net(297,157) 275,313
 (572,470)
Net Loss$(848,102) $(374,885) $(473,217)

CNX's principal activity is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The Company's reportable segments are Marcellus Shale, joint venture.Utica Shale, Coalbed Methane, and Other Gas.
Idle Rig Expense related to temporary idling
CNX had a loss from continuing operations before income tax 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.

Impairment of Exploration and Production Properties of $829$585 million for the year ended December 31, 2016, compared to a loss from continuing operations before income tax of $931 million for the year ended December 31, 2015. Included in the 2016 net loss before income tax was an unrealized loss on commodity derivative instruments of $386 million and a gain on sale of assets of $14 million. Included in the 2015 relatesloss before income tax was a loss of $829 million primarily related to the write downimpairment of the Company'scarrying value of CNX's shallow oil and natural gas asset valuesassets due to depressed NYMEX forward strip prices (see Note 1 - Significant Accounting Policies in June 2015. See Note 9- Property, Plant and Equipment of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such write downs occurred in the current period.
Selling, general and administrative (SG&A) costs are allocated to the total E&P segment based on percentage of total revenue and percentage of total projected capital expenditures. SG&A costs were $102 million for each of the years ended December 31, 2016 and December 31, 2015. Refer to the discussion of total company selling, general and administrative costs contained in the section "Net Loss Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation.

Interest expense related to the E&P divisioninformation). The impairment loss was $3 million for the year ended December 31, 2016 compared to $6 million for the year ended December 31, 2015. Interest was incurred by the Other Gas segment on interest allocated to the E&P division under CONSOL Energy's credit facility.



64


TOTAL PA MINING OPERATIONS DIVISION ANALYSIS for the year ended December 31, 2016 compared to the year ended December 31, 2015:
The PA Mining Operations division principal activities consist of mining, preparation and marketing of thermal coal to power generators. The division also includes selling, general and administrative costs, as well as various other activities assigned to the PA Mining Operations division but not included in the cost components on a per unit basis.

The PA Mining Operations division had earnings before income tax of $131 million for the year ended December 31, 2016, compared to earnings before income tax of $405 million for the year ended December 31, 2015. Variances are discussed below.
 For the Years Ended December 31,
 (in millions)2016 2015 Variance
Sales:     
Coal Sales$1,066
 $1,289
 $(223)
Freight Revenue46
 20
 26
Miscellaneous Other Income13
 4
 9
Total Revenue and Other Income1,125
 1,313
 (188)
Operating Costs and Expenses:    
Operating Costs691
 789
 (98)
Depreciation, Depletion and Amortization154
 167
 (13)
Total Operating Costs and Expenses845
 956
 (111)
Other Costs and Expenses:    

Other Costs42
 (122) 164
Depreciation, Depletion and Amortization14
 10
 4
Total Other Costs and Expenses56
 (112) 168
Freight Expense46
 20
 26
Selling, General and Administrative Costs38
 41
 (3)
Total PA Mining Operations Costs985
 905
 80
Interest Expense9
 3
 6
Total PA Mining Operations Division Expense994
 908
 86
Earnings Before Income Tax$131
 $405
 $(274)

The PA Mining Operations coal revenue and cost components on a per unit basis for these periods were as follows:
 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Company Produced PA Mining Operations Tons Sold (in millions)24.6
 22.9
 1.7
 7.4%
Average Sales Price Per PA Mining Operations Ton Sold$43.31
 $56.36
 $(13.05) (23.2%)
        
Total Operating Costs Per Ton Sold$28.09
 $34.47
 $(6.38) (18.5%)
Total Depreciation, Depletion and Amortization Costs Per Ton Sold6.26
 7.31
 (1.05) (14.4%)
     Total Costs Per PA Mining Operations Ton Sold$34.35
 $41.78
 $(7.43) (17.8%)
     Average Margin Per PA Mining Operations Ton Sold$8.96
 $14.58
 $(5.62) (38.5%)

Coal Sales

PA Mining Operations coal sales were $1,066 million for the year ended December 31, 2016, compared to $1,289 million for the year ended December 31, 2015. The $223 million decrease was attributable to a $13.05 per ton lower average sales price,partially offset by a 1.7an unrealized gain on commodity derivative instruments of $197 million increase in tons sold. The lower average sales price per PA Mining Operations ton sold was primarily the result of the continued decline in both the domestic and global thermal coal markets, particularly in the first half of 2016. The decline was related to higher customer inventories and lower gas prices after persistently mild 2015 weather.


65


The increase in overall tons sold reflects the improvement in both domestic and international coal demand throughout the second half of 2016.

Freight Revenue and Freight Expense

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on the weight of coal shipped, negotiated freight rates and method of transportation, primarily rail, used by the customers to which the Company contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue and freight expense were both $46 million for the year ended December 31, 2016, compared to $20 million for the year ended December 31, 2015. The $26 million increase was due to increased shipments where transportation services were contractually provided.

Miscellaneous Other Income

Miscellaneous other income was $13 million for the year ended December 31, 2016, compared to $4 million for the year ended December 31, 2015. Approximately $6 million of the increase was the result of a partial coal contract buyout in the current period. The remaining $3 million increase was the result of various transactions that occurred during both periods, none of which were individually material.

Operating Costs and Expenses

Operating costs and expenses are comprised of costs related to produced tons sold, along with changes in both the volumes and carrying values of coal inventory. Operating costs and expenses include items such as direct operating costs, royalty and production taxes, employee-related expenses and depreciation, depletion, and amortization costs. Total operating costs and expenses for the PA Mining Operations division were $845 million for the year ended December 31, 2016, or $111 million lower than the $956 million for the year ended December 31, 2015. Total costs per PA Mining Operations ton sold were $34.35 per ton in the year ended December 31, 2016, compared to $41.78 per ton in the year ended December 31, 2015. The decrease in the cost of coal sold was driven by the idling of one longwall at the PA Mining Operations complex for approximately 90 days, a reduction of staffing levels, vendor concessions and a realignment of employee benefits. All of the above steps resulted in more consistent operating schedules, reduced labor costs and improved productivity. Productivity for the year ended December 31, 2016, as measured by tons per employee hour, improved by 17% compared to the year earlier period, despite the reduced number of longwalls in operation.
Other Costs and Expenses
Other costs and expenses include items that are assigned to the PA Mining Operations division but are not included in unit costs. Other costs and expenses increased $168 million in the year ended December 31, 2016 compared to the year ended December 31, 2015. The increase was due to the following:
  For the Years Ended December 31,
  2016 2015 Variance
OPEB Plan Changes $—
 $(129) $129
Idle Mine Costs 19
 —
 19
Purchased Coal Costs 6
 —
 6
Litigation Expense 4
 —
 4
Severance Expense 1
 —
 1
Amortization of Capitalized Interest 9
 9
 —
Coal Reserve Holding Costs 4
 5
 (1)
Other 13
 3
 10
   Other Costs and Expenses $56
 $(112) $168
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.


66


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

Selling, General and Administrative Costs

Upon execution of the CNXC IPO, CNXC entered into a service agreement with CONSOL Energy that required CONSOL Energy to provide certain selling, general and administrative services. These services are paid monthly basedgain on an agreed-upon fixed fee that is reset at least annually. 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. The amount of selling, general and administrative costs related to PA Mining Operations was $38 million for the year ended December 31, 2016, compared to $41 million for the year ended December 31, 2015. Refer to the discussion of total Company selling, general and administrative costs contained in the section "Net Loss Attributable to CONSOL Energy Shareholders"of this annual report for a detailed cost explanation.

Interest Expense
Interest expense, net of amounts capitalized, of $9 million and $3 million for the years ended December 31, 2016 and 2015, respectively, is primarily comprised of interest on the CNXC revolving credit facility that was drawn upon after the CNXC IPO on July 7, 2015.


67


OTHER DIVISION ANALYSIS for the year ended December 31, 2016 compared to the year ended December 31, 2015:
The Other division includes expenses from various corporate and diversified business activities that are not allocated to the E&P or PA Mining Operations divisions. The diversified business activities include coal terminal operations, closed and idle mine activities, water operations, selling, general and administrative activities, income tax expense (benefit), as well as various other non-operated activities.

The Other division had a loss before income tax of $277 million for the year ended December 31, 2016, compared to a loss before income tax of $202 million for the year ended December 31, 2015. The Other division also includes total Company income tax expense related to continuing operations of $10 million for the year ended December 31, 2016, compared to an income tax benefit of $125 million for the year ended December 31, 2015.

 For the Years Ended December 31,
(in millions)2016 2015 Variance 
Percent
Change
Other Outside Sales$32
 $31
 $1
 3.2 %
Miscellaneous Other Income73
 78
 (5) (6.4)%
Gain on Sale of Assets5
 61
 (56) (91.8)%
Total Revenue110
 170
 (60) (35.3)%
Miscellaneous Operating Expense183
 79
 104
 131.6 %
Selling, General, and Administrative Costs13
 15
 (2) (13.3)%
Depreciation, Depletion and Amortization12
 20
 (8) (40.0)%
Loss on Debt Extinguishment—
 68
 (68) (100.0)%
Interest Expense179
 190
 (11) (5.8)%
Total Other Costs387
 372
 15
 4.0 %
Loss Before Income Tax(277) (202) (75) (37.1)%
Income Tax Expense (Benefit)10
 (125) 135
 108.0 %
Net Loss$(287) $(77) $(210) (272.7)%

Other Outside Sales
Other outside sales primarily consists of sales from the Company's coal terminal operations. Coal terminal operations sales were $32 million for the year ended December 31, 2016, compared to $31 million for the year ended December 31, 2015. The $1 million increase in the period-to-period comparison was primarily due to an increase in throughput rates in the current period.

Miscellaneous Other Income
Miscellaneous other income was $73 million for the year ended December 31, 2016, compared to $78 million for the year ended December 31, 2015. The change is due to the following items:

  For the Years Ended December 31,
(in millions) 2016 2015 Variance
Equity in Earnings of Affiliates $1
 $8
 $(7)
Purchased Coal Sales —
 2
 (2)
Rental Income 36
 37
 (1)
Interest Income 1
 2
 (1)
Right of Way Sales 12
 8
 4
Royalty Income 20
 15
 5
Other Income 3
 6
 (3)
Total Miscellaneous Other Income $73
 $78
 $(5)




68


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.assets of $61 million. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional 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.

Gain on Sale of Assets

Gain on sale of assets decreased $56 million in the period-to-period comparison, primarily 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.

Miscellaneous Operating Expense

Miscellaneous operating expense related to the Other division was $183 million for the year ended December 31, 2016, compared to $79 million for the year ended December 31, 2015. Miscellaneous operating expense increased in the period-to-period comparison due to the following items:
  For the Years Ended December 31,
(in millions) 2016 2015 Variance
OPEB Plan Changes $—
 $(125) $125
Coal Reserve Holding Costs 19
 8
 11
Litigation Expense 5
 —
 5
Pension Settlement 22
 19
 3
Bank Fees 18
 17
 1
Closed and Idle Mines 9
 9
 —
Purchased Coal —
 1
 (1)
UMWA Expenses 9
 10
 (1)
Workers' Compensation 6
 7
 (1)
Lease Rental Expense 30
 31
 (1)
Coal Terminal Operations 18
 20
 (2)
UMWA OPEB Expense 43
 47
 (4)
Severance Payments 1
 6
 (5)
Industrial Supplies Working Capital Settlement —
 6
 (6)
Pension Expense (14) 6
 (20)
Other 17
 17
 —
Miscellaneous Operating Expense $183
 $79
 $104

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.
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.


69


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.

Selling, General and Administrative Costs
Selling, general and administrative costs allocated to the Other division were $13 million for the year ended December 31, 2016, compared to $15 million for the year ended December 31, 2015. Refer to the discussion of total Company selling, general and administrative costs contained in the section "Net Loss Attributable to CONSOL Energy Shareholders"of this annual report for more information.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased $8 million in the period-to-period comparison, primarily related to a reduction of the asset retirement obligations at various closed and idled mine locations.

Loss on Debt Extinguishment

Loss on debt extinguishment of $68 million was recognized in the year ended December 31, 2015 due to the partial purchase of the 8.25% senior notes that were due in 2020 at an average price equal to 104.6% of the principal amount, and the partial purchase of the 6.375% senior notes that were due in 2021 at an average price equal to 105.0% of the principal amount. No such transactions occurred in the current period.

Interest Expense

Interest expense of $179 million was recognized in the year ended December 31, 2016, compared to $190 million in the year ended December 31, 2015. The $11 million decrease in the period-to-period comparison was due to the partial payoff of the 2020 and 2021 bonds in March and April 2015. Also contributing to the decrease was a decrease in the average outstanding balance on the Company's revolving credit facility, as well as lower interest rates on the 2023 bonds issued in March 2015 when compared to the interest rate on the 2020 bonds.

Income Taxes
The effective income tax rate for continuing operations when excluding non-controlling interest was (1.9)% for the year ended December 31, 2016, compared to 26.3% for the year ended December 31, 2015. During the year ended December 31, 2016, CONSOL Energy settled a Federal audit of the years 2010-2013 and received a favorable private letter ruling from the IRS related to bonus depreciation. Overall, the Company received approximately $21 million in refunds during 2016 and anticipates additional cash refunds in 2017.
Some of the factors contributing to these refunds put pressure on deferred tax assets related to AMT credits. Although these credits never expire, at December 31, 2016, management could not demonstrate sufficient positive evidence to ensure realizability of these assets in the foreseeable future. As CONSOL Energy was in a three-year cumulative pre-tax loss, the Company did not consider future generation of income to support the realization of these credits. As a result, the Company recorded a valuation allowance of $167 million at December 31, 2016. These credits can be fully utilized when sufficient operating income is generated by the Company.
An additional $38 million valuation allowance was recorded against state deferred tax assets related to state net operating losses and other temporary differences, Federal charitable contribution and foreign tax credit carryforwards.
See Note 6-Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. 


70


 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Total Company Loss Before Income Tax excluding Noncontrolling Interest$(535) $(476) $(59) 12.4 %
Income Tax Expense (Benefit)$10
 $(125) $135
 (108.0)%
Effective Income Tax Rate(1.9)% 26.3% (28.2)%  



71


Results of Operations: Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014
Net (Loss) Income Attributable to CONSOL Energy Shareholders
CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $375 million, or a loss per diluted share of $1.64, for the year ended December 31, 2015, compared to net income attributable to CONSOL Energy shareholders of $163 million, or earnings of $0.70 per diluted share, for the year ended December 31, 2014.
 For the Years Ended December 31,
(Dollars in thousands)2015 2014 Variance
(Loss) Income from Continuing Operations$(350,266) $164,947
 $(515,213)
Loss from Discontinued Operations(14,209) (1,857) (12,352)
Net (Loss) Income$(364,475) $163,090
 $(527,565)
Less: Net Income Attributable to Noncontrolling Interests10,410
 —
 10,410
Net (Loss) Income Attributable to CONSOL Energy Shareholders$(374,885) $163,090
 $(537,975)

CONSOL Energy consists of two principal business divisions: Exploration and Production (E&P) and Pennsylvania (PA) Mining Operations. The E&P division includes four reportable segments: Marcellus, Utica, Coalbed Methane (CBM) and Other Gas.

The E&P division contributed a loss before income tax of $679 million for the year ended December 31, 2015, compared to earnings before income tax of $190 million for the year ended December 31, 2014. Included in the 2015 net loss before income tax was a loss of $829 million primarily related to the impairment of the carrying value of CONSOL Energy's shallow oil and natural gas assets due to depressed NYMEX forward strip prices (see Note 9 - Property, Plant and Equipment of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s natural gas production and sales portfolio.
 For the Years Ended December 31, For the Years Ended December 31,
in thousands (unless noted) 2015 2014 Variance Percent
Change		 2016 2015 Variance Percent
Change
LIQUIDS     

 

     

 

NGLs:     

 

     

 

Sales Volume (MMcfe) 33,180
 15,475
 17,705
 114.4 % 40,260
 33,180
 7,080
 21.3 %
Sales Volume (Mbbls) 5,530
 2,579
 2,951
 114.4 % 6,710
 5,530
 1,180
 21.3 %
Gross Price ($/Bbl) $12.30
 $35.70
 $(23.40) (65.5)% $14.52
 $12.30
 $2.22
 18.0 %
Gross Revenue $68,057
 $92,136
 $(24,079) (26.1)% $97,580
 $68,057
 $29,523
 43.4 %
                
Oil:                
Sales Volume (MMcfe) 592
 681
 (89) (13.1)% 410
 592
 (182) (30.7)%
Sales Volume (Mbbls) 99
 114
 (15) (13.2)% 68
 99
 (31) (31.3)%
Gross Price ($/Bbl) $47.94
 $89.10
 $(41.16) (46.2)% $36.90
 $47.94
 $(11.04) (23.0)%
Gross Revenue $4,736
 $10,108
 $(5,372) (53.1)% $2,521
 $4,736
 $(2,215) (46.8)%
                
Condensate:                
Sales Volume (MMcfe) 7,598
 3,298
 4,300
 130.4 % 4,964
 7,598
 (2,634) (34.7)%
Sales Volume (Mbbls) 1,266
 550
 716
 130.2 % 827
 1,266
 (439) (34.7)%
Gross Price ($/Bbl) $26.52
 $66.96
 $(40.44) (60.4)% $27.48
 $26.52
 $0.96
 3.6 %
Gross Revenue $33,586
 $36,808
 $(3,222) (8.8)% $22,748
 $33,586
 $(10,838) (32.3)%
                
GAS                
Sales Volume (MMcf) 287,287
 216,260
 71,027
 32.8 % 348,753
 287,287
 61,466
 21.4 %
Sales Price ($/Mcf) $2.17
 $4.02
 $(1.85) (46.0)% $1.92
 $2.17
 $(0.25) (11.5)%
Gross Revenue $622,080
 $868,329
 $(246,249) (28.4)% $670,823
 $622,080
 $48,743
 7.8 %
                
Hedging Impact ($/Mcf) $0.68
 $0.11
 $0.57
 518.2 % $0.70
 $0.68
 $0.02
 2.9 %
Gain on Commodity Derivative Instruments - Cash Settlement $196,348
 $23,193
 $173,155
 746.6 % $245,212
 $196,348
 $48,864
 24.9 %


7252


The E&P division naturalNatural gas, NGLs, and oil sales were $729$793 million for the year ended December 31, 2015,2016, compared to $1,008$727 million for the year ended December 31, 2014.2015. The decreaseincrease was primarily due to the 46.0%20.0% increase in total sales volumes, offset in part by the 11.5% decrease in the average Gasgas sales price per Mcf without the impact of derivative instruments, offset in part, by the 39.5% increase in total E&P sales volumes.instruments. The decrease in average sales price was the result of the overall decrease in general market prices.

The E&P division salesSales volumes, average sales price (including the effects of derivative instruments), and average costs for all active E&P operations were as follows: 
For the Years Ended December 31,For the Years Ended December 31,
2015 2014 Variance 
Percent
Change
2016 2015 Variance 
Percent
Change
E&P Sales Volumes (Bcfe)328.7
 235.7
 93.0
 39.5 %
Sales Volumes (Bcfe)394.4
 328.7
 65.7
 20.0 %
              
Average Sales Price (per Mcfe)$2.81
 $4.37
 $(1.56) (35.7)%$2.63
 $2.81
 $(0.18) (6.4)%
Average Costs (per Mcfe)2.62
 3.13
 (0.51) (16.3)%2.32
 2.62
 (0.30) (11.5)%
Average Margin$0.19
 $1.24
 $(1.05) (84.7)%$0.31
 $0.19
 $0.12
 63.2 %

The decrease in average sales price was primarily the result of a $0.25 Mcf decrease in general market prices in the Appalachian basin during the current period, as well as an overall decrease in natural gas liquids pricing. The increase was offset, in part, by a $0.02 Mcf increase in the realized gain on commodity derivative instruments related to the Company's hedging program.

Changes in the average costs per Mcfe were primarily related to the following items:
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.
Depreciation, depletion, and amortization decreased on a per-unit basis primarily due to the adjustment toa reduction in Marcellus rates as a result of an increase in the Company's shallow oil and gas rates following the impairment in carrying value that was recognized in the second quarter of 2015 (seeMarcellus reserves. See Note 97 - Property, Plant, and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information),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 the increasea decrease in E&P sales volumes from the Company's lower cost Marcellusboth Company operated 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.joint venture operated repairs and maintenance costs.
Lease operating expensesTransportation, gathering, and compression expense decreased on a per-unitper unit basis in the period-to-period comparison due to the overall increase in E&P sales volumes. Thevolumes, the shift towards dry Utica Shale production which has lower gathering costs, and a decrease in unit costs was partially offset by an increase in repairspipeline and facility maintenance salt water disposal costs, and contractual services related to well tending.expense.

The PA Mining Operations division had earnings beforeCertain costs and expenses such as selling, general and administrative, other expense, gain on sale of assets, loss on debt extinguishment, interest expense and income taxtaxes are unallocated expenses and therefore are excluded from the per unit costs above as well as segment reporting. Below is a summary of $405these costs and expenses:

Selling, General and Administrative

SG&A costs include costs such as overhead, including employee wages and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, and legal compliance expenses. SG&A costs also includes noncash equity-based compensation expense.
SG&A costs were $105 million for the year ended December 31, 2015,2016, compared to earnings before income tax of $431$102 million for the year ended December 31, 2014.
Sales tons, average sales price and average cost of goods sold per ton for the PA Mining Operations division were as follows:
 For the Years Ended December 31,
 2015 2014 Variance 
Percent
Change
Company Produced PA Mining Operations Tons sold (in millions)22.9
 26.1
 (3.2) (12.3)%
        
Average Sales Price per ton sold$56.36
 $61.88
 $(5.52) (8.9)%
Average Cost of Goods Sold per ton41.78
 43.63
 (1.85) (4.2)%
Average Margin$14.58
 $18.25
 $(3.67) (20.1)%

The lower average sales price per ton sold2015. SG&A costs increased due to an increase in the 2015 period was primarily the result of the continued declineshort-term incentive compensation expense offset, in both the domestic and global thermal coal markets. Due to the weak domestic thermal spot market, the PA Mining Operations division priced 5.5 million tons on the export market for the year ended December 31, 2015, compared to 3.3 million tons for the year ended December 31, 2014. All other tons were sold on the domestic market.

Changes in the average cost of goods sold per ton were primarily drivenpart, by improved operational efficiencies, better geological conditions, a reduced workforce, a decrease in stream subsidence expenseemployee wages and other ongoing cost reduction efforts. In orderbenefit costs due to preserve margins, PA Mining Operations moved to a four-day work weekthe Company reorganization that occurred in Maythe second half of 2015 compared to a normal five-day per week schedule. Theand first quarter of 2016, which resulted in an overall decrease in unit costs was primarily the result of Pension and OPEB plan modifications for active employees inemployees.












7353


September 2014. Refer to the discussionOther Expense
 For the Years Ended December 31,
 (in millions)2016 2015 Variance 
Percent
Change
Other Income       
Royalty Income$10
 $—
 $10
 100.0 %
Right of Way Sales15
 6
 9
 150.0 %
Interest Income—
 2
 (2) (100.0)%
Other4
 4
 —
 — %
Total Other Income$29
 $12
 $17
 141.7 %
        
Other Expense       
Bank Fees$13
 $13
 $—
 — %
Severance1
 6
 (5) (83.3)%
Other Corporate Expense15
 17
 (2) (11.8)%
Other Land Rental Expense5
 14
 (9) (64.3)%
Total Other Expense$34
 $50
 $(16) (32.0)%
        
       Total Other Expense$5
 $38
 $(33) (86.8)%

Gain on Sale of total Company long-term liabilities below for more informationAssets

CNX recognized a gain on the effectsale of the Pension and OPEB plan modifications.
The Other division includes other business activities not assigned to the E&P or PA Mining Operations divisions, income taxes, and industrial supplies activity (this subsidiary was soldassets of $14 million in December 2014). The Other division had a net loss of $77 million for the year ended December 31, 2015,2016 compared to a net lossgain of $452$61 million forin the year ended December 31, 2014.
Selling, general and administrative (SG&A) costs are allocated2015. The $47 million decrease was primarily due to sale of CNX's interest in its Western Allegheny Energy joint venture that occurred in the PA Mining Operations division based upon a shared service agreement that CONSOL Energy entered into with CNX Coal Resources LP (CNXC) upon execution ofyear ended December 31, 2015. No individually significant transactions occurred in the CNXC initial public offering (IPO). The shared service agreement calls for CONSOL Energy to provide certain selling, general and administrative services that are paid for monthly, based on an agreed upon fixed fee that is reset at least annually.year ended December 31, 2016. See Note 253 - Related Party Transactions ofAcquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. The remaining SG&A costs are allocated between the E&P and Other divisions based primarily on a percentage of total revenue and a percentage of total projected capital expenditures.

SG&A costs are excluded from the E&P and PA Mining Operations unit costs above. SG&A costs were $158Loss on Debt Extinguishment

Loss on debt extinguishment of $68 million forwas recognized in the year ended December 31, 2015 compareddue to $211the purchase of a portion of the 8.25% senior notes due in April 2020 and the 6.375% senior notes due in March 2021.

Interest Expense
Interest expense of $182 million forwas recognized in the year ended December 31, 2014. SG&A costs decreased2016, compared to $199 million in the year ended December 31, 2015. The $17 million decrease was primarily due to the following items:
 For the Years Ended December 31,
 (in millions)2015 2014 Variance 
Percent
Change
Short-Term Incentive Compensation$40
 $55
 $(15) (27.3)%
Stock-Based Compensation25
 40
 (15) (37.5)%
Contributions1
 9
 (8) (88.9)%
Employee Wages and Related Expenses62
 70
 (8) (11.4)%
Consulting and Professional Services15
 20
 (5) (25.0)%
Advertising and Promotion7
 7
 —
 — %
Rent8
 8
 —
 — %
Other—
 2
 (2) (100.0)%
Total Company Selling, General and Administrative Expense$158
 $211
 $(53) (25.1)%

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 recordedrevolving credit facility having no outstanding borrowings during the year ended December 31, 2014. The remaining $22016, compared to $952 million of outstanding borrowings at December 31, 2015. This 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 primarilywas also due to the Company reorganization that occurred inpartial payoff of the year ended December 31, 2015.
Consulting2020 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 expenses2021 bonds during the year ended December 31, 2015.

Total Company long-term liabilities, such as Other Post-Employment Benefits (OPEB), the salary retirement plan, workers' compensation, Coal Workers' Pneumoconiosis (CWP), and long-term disability are actuarially calculatedIncome Taxes

The effective income tax rate for the Company as a whole. In general, the expenses are then allocated to the segments based upon criteria specific to each liability. Total CONSOL Energy continuing operations expense related to actuarial liabilities was income of $162 million6.0% for the year ended December 31, 2015,2016, compared to expense of $96 million30.2% for the year ended December 31, 2014. The decrease2015. During the year ended December 31, 2016, CNX settled a Federal audit of $258the years 2010-2013 and received a favorable private letter ruling from the IRS related to bonus depreciation. Overall, the Company received approximately $21 million was primarily due to modifications madein refunds during 2016. Some of the factors contributing to the OPEB and Pension plans in September 2014 and May 2015. Not includedrefunds received during 2016 put pressure on deferred tax assets related to alternative minimum tax credits. Although these credits never expire, management could not demonstrate sufficient positive evidence to ensure realizability of these assets in the 2014 long-term liability expense totals discussed above is $46foreseeable future and as a result, the Company recorded a valuation allowance of $167 million of expense for cash payments made to active employees in the fourth quarter of 2014. at December 31, 2016. An additional $38 million valuation allowance was recorded at December 31, 2016 against state deferred tax assets, as well as federal charitable contributions and foreign tax credit carry-forwards.



54


See Note 14—Pension and Other Postretirement Benefit Plans and Note 15—Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation5 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.

information.

 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Total Company Loss Before Income Tax$(585) $(931) $346
 (37.2)%
Income Tax Benefit$(34) $(280) $246
 (87.7)%
Effective Income Tax Rate6.0% 30.2% (24.2)%  

74


TOTAL E&P DIVISIONOPERATING SEGMENT ANALYSIS for the year ended December 31, 20152016 compared to the year ended December 31, 2014:2015:
The E&P divisionCNX operating segments had a loss before income tax of $679$308 million for the year ended December 31, 20152016 compared to earningsa loss before income tax of $190$585 million for the year ended December 31, 2014.2015. Variances by individual E&Poperating segment are discussed below.
For the Year Ended Difference to Year EndedFor the Year Ended Difference to Year Ended
December 31, 2015 December 31, 2014December 31, 2016 December 31, 2015
(in millions)Marcellus Utica CBM 
Other
Gas
 
Total
E&P
 Marcellus Utica CBM 
Other
Gas
 
Total
E&P
Marcellus Utica CBM 
Other
Gas
 Total Marcellus Utica CBM 
Other
Gas
 Total
Natural Gas, NGLs and Oil Sales$379
 $93
 $202
 $55
 $729
 $(78) $6
 $(141) $(66) $(279)$415
 $163
 $175
 $40
 $793
 $36
 $70
 $(27) $(13) $66
Gain on Commodity Derivative Instruments101
 6
 67
 219
 393
 86
 5
 63
 216
 370
Gain (Loss) on Commodity Derivative Instruments147
 29
 52
 (369) (141) 46
 23
 (15) (588) (534)
Purchased Gas Sales—
 —
 —
 14
 14
 —
 —
 —
 5
 5
—
 —
 —
 43
 43
 —
 —
 —
 29
 29
Miscellaneous Other Income—
 —
 —
 62
 62
 —
 —
 ��
 2
 2
Gain on Sale of Assets—
 —
 —
 13
 13
 —
 —
 —
 (33) (33)
Total Revenue and Other Income480
 99
 269
 363
 1,211
 8
 11
 (78) 124
 65
Other Operating Income—
 —
 —
 65
 65
 —
 —
 —
 —
 —
Total Revenue and Other Operating Income562
 192
 227
 (221) 760
 82
 93
 (42) (572) (439)
Lease Operating Expense44
 22
 33
 23
 122
 (2) 4
 (9) (10) (17)34
 22
 25
 15
 96
 (10) —
 (8) (8) (26)
Production, Ad Valorem, and Other Fees18
 2
 7
 3
 30
 —
 1
 (5) (5) (9)17
 5
 6
 3
 31
 (1) 3
 (1) —
 1
Transportation, Gathering and Compression200
 35
 85
 23
 343
 96
 28
 (11) (9) 104
228
 51
 72
 23
 374
 28
 16
 (13) —
 31
Depreciation, Depletion and Amortization162
 59
 84
 66
 371
 30
 41
 (5) (19) 47
211
 86
 86
 37
 420
 49
 27
 2
 (30) 48
Impairment of Exploration and Production Properties—
 —
 —
 —
 —
 —
 —
 —
 (829) (829)
Exploration and Production Related Other Costs—
 —
 —
 10
 10
 —
 —
 —
 (13) (13)—
 —
 —
 15
 15
 —
 —
 —
 5
 5
Purchased Gas Costs—
 —
 —
 11
 11
 —
 —
 —
 4
 4
—
 —
 —
 43
 43
 —
 —
 —
 32
 32
Other Corporate Expenses—
 —
 —
 66
 66
 —
 —
 —
 19
 19
Impairment of Exploration and Production Properties—
 —
 —
 829
 829
 —
 —
 —
 829
 829
Selling, General and Administrative Costs—
 —
 —
 102
 102
 —
 —
 —
 (27) (27)
Total Exploration and Production Costs424
 118
 209
 1,133
 1,884
 124
 74
 (30) 769
 937
Interest Expense—
 —
 —
 6
 6
 —
 —
 —
 (3) (3)
Total E&P Division Costs424
 118
 209
 1,139
 1,890
 124
 74
 (30) 766
 934
Other Operating Expense—
 —
 —
 89
 89
 —
 —
 —
 22
 22
Total Operating Costs and Expenses490
 164
 189
 225
 1,068
 66
 46
 (20) (808) (716)
Earnings (Loss) Before Income Tax$56
 $(19) $60
 $(776) $(679) $(116) $(63) $(48) $(642) $(869)$72
 $28
 $38
 $(446) $(308) $16
 $47
 $(22) $236
 $277



7555


MARCELLUS SEGMENT
The Marcellus segment had earnings before income tax of $72 million for the year ended December 31, 2016 compared to earnings before income tax of $56 million for the year ended December 31, 2015 compared to earnings before income tax of $172 million for the year ended December 31, 2014.2015.
For the Years Ended December 31,For the Years Ended December 31,
2015 2014 Variance 
Percent
Change
2016 2015 Variance 
Percent
Change
Marcellus Gas Sales Volumes (Bcf)149.4
 99.4
 50.0
 50.3 %186.8
 149.4
 37.4
 25.0 %
NGLs Sales Volumes (Bcfe)*19.0
 10.9
 8.1
 74.3 %23.5
 19.0
 4.5
 23.7 %
Condensate Sales Volumes (Bcfe)*3.9
 1.4
 2.5
 178.6 %2.2
 3.9
 (1.7) (43.6)%
Total Marcellus Sales Volumes (Bcfe)*172.3
 111.7
 60.6
 54.3 %212.5
 172.3
 40.2
 23.3 %
              
Average Sales Price - Gas (Mcf)$2.09
 $3.82
 $(1.73) (45.3)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)$0.67
 $0.15
 $0.52
 346.7 %
Average Sales Price - NGLs (Mcfe)*$2.54
 $5.77
 $(3.23) (56.0)%
Average Sales Price - Condensate (Mcfe)*$5.02
 $10.47
 $(5.45) (52.1)%
Average Sales Price - Gas (per Mcf)$1.87
 $2.09
 $(0.22) (10.5)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$0.79
 $0.67
 $0.12
 17.9 %
Average Sales Price - NGLs (per Mcfe)*$2.38
 $2.54
 $(0.16) (6.3)%
Average Sales Price - Condensate (per Mcfe)*$4.32
 $5.02
 $(0.70) (13.9)%
              
Total Average Marcellus Sales Price (per Mcfe)$2.79
 $4.23
 $(1.44) (34.0)%$2.64
 $2.79
 $(0.15) (5.4)%
Average Marcellus Lease Operating Expenses (per Mcfe)0.26
 0.41
 (0.15) (36.6)%0.16
 0.26
 (0.10) (38.5)%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)0.10
 0.16
 (0.06) (37.5)%0.08
 0.10
 (0.02) (20.0)%
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe)1.16
 0.93
 0.23
 24.7 %1.07
 1.16
 (0.09) (7.8)%
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)0.94
 1.19
 (0.25) (21.0)%0.99
 0.94
 0.05
 5.3 %
Total Average Marcellus Costs (per Mcfe)$2.46
 $2.69
 $(0.23) (8.6)%$2.30
 $2.46
 $(0.16) (6.5)%
Average Margin for Marcellus (per Mcfe)$0.33
 $1.54
 $(1.21) (78.6)%$0.34
 $0.33
 $0.01
 3.0 %
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

The Marcellus segment had natural gas, NGLs and oil sales of $415 million for the year ended December 31, 2016 compared to $379 million for the year ended December 31, 2015 compared to $4572015. The $36 million for the year ended December 31, 2014. The $78 million decreaseincrease was primarily due to a 45.3%23.3% increase in total Marcellus sales volumes, partially offset by a 10.5% decrease in the average gas sales price in the period-to-period comparison, partially offset by a 54.3% increase in total Marcellus sales volumes.comparison. The increase in total sales volumes iswas primarily due to additional wells coming on-line in the current period.year, as well as the termination of the Marcellus Joint Venture that CNX had with Noble Energy in 2016. 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. The joint venture termination was effective October 1st, 2016 and resulted in additional production for the fourth quarter of 2016, as well as the applicable sales and production costs.

The decrease in the total average Marcellus sales price was primarily the result of the $1.73$0.22 per Mcf decrease in gas market prices, along with a $0.17$0.03 per McfeMcf decrease in the uplift from NGLs and condensate sales volumes, when excluding the impact of hedging. These decreases were offset, in part, by a $0.52$0.12 per Mcf increase in the gain on commodity derivative instruments resulting from the Company's hedging program. The increase in the gain was due to an increase in volumes hedged and lower market prices. TheseThe notional amounts associated with these financial hedges represented approximately 90.3160.8 Bcf of the Company's produced Marcellus gas sales volumes for the year ended December 31, 2016 at an average gain of $0.92 per Mcf. For the year ended December 31, 2015, these financial hedges represented approximately 90.3 Bcf at an average gain of $1.09 per Mcf. For

Total operating costs and expenses for the Marcellus segment were $490 million for the year ended December 31, 2014, these financial hedges represented approximately 70.4 Bcf at an average gain of $0.21 per Mcf.

Total exploration and production costs for the Marcellus segment were2016 compared to $424 million for the year ended December 31, 2015 compared to $300 million for the year ended December 31, 2014.2015. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

•Marcellus lease operating expense was $34 million for the year ended December 31, 2016 compared to $44 million for the year ended December 31, 2015 compared to $46 million for the year ended December 31, 2014.2015. The decrease in total dollars was primarily due to a reduction in employee related costs, well tending costs and repairs and maintenance expense in the year ended December 31, 2015.current period. The decreasereduction in unitemployee related costs was primarily due to the 54.3%company reorganization that occurred in the second half of 2015 and the first quarter of 2016. The decrease in unit costs


56


was primarily due to the 23.3% increase in total Marcellus sales volumes.volumes, along with the decreased total dollars described above. The decreases were offset, in part, by an increase in salt water disposal costs in the period-to-period comparison.

•Marcellus production, ad valorem, and other fees were $17 million for the year ended December 31, 2016 compared to $18 million for the yearsyear ended December 31, 2015 and 2014.2015. The decrease in unit coststotal dollars was primarily due to the 54.3% increase in total Marcellus sales volumes offset, in part, by the decrease in total average Marcellus sales price.price, offset, in part, by the increase in total Marcellus sales volumes.



76


•Marcellus transportation, gathering and compression costs were $228 million for the year ended December 31, 2016 compared to $200 million for the year ended December 31, 2015 compared to $104 million for the year ended December 31, 2014.2015. The $96$28 million increase in total dollars was primarily related to an increase in the CONECNXM gathering fee due to the increase in total Marcellus sales volumes (See(see Note 2520 - Related Party Transactions ofin the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information), an increase in processing fees associated with natural gas liquids primarily due to the 74.3%23.7% increase in NGLs sales volumes, and an increase in utilized firm transportation expense. The increasedecrease in unit costs was due to the overallincrease in total Marcellus sales volumes, offset, in part, by the increase in total dollars.

•Depreciation, depletion and amortization costs attributable to the Marcellus segment were $211 million for the year ended December 31, 2016 compared to $162 million for the year ended December 31, 2015 compared to $132 million fordriven primarily by the year ended December 31, 2014.overall increase in production. These amounts included depreciation on a unit of production basis of $0.92$0.98 per Mcf and $1.16$0.92 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.

UTICAOTHER GAS SEGMENT

The UticaOther Gas segment had a lossearnings before income tax of $19$15 million for the year ended December 31, 20152017 compared to earningsa loss before income tax of $44$446 million for the year ended December 31, 2014.2016.
 For the Years Ended December 31,
 2015 2014 Variance Percent
Change
Utica Gas Sales Volumes (Bcf)38.3
 10.3
 28.0
 271.8 %
NGLs Sales Volumes (Bcfe)*14.1
 4.6
 9.5
 206.5 %
Oil Sales Volumes (Bcfe)*0.1
 —
 0.1
 100.0 %
Condensate Sales Volumes (Bcfe)*3.7
 1.8
 1.9
 105.6 %
Total Utica Sales Volumes (Bcfe)*56.2
 16.7
 39.5
 236.5 %
        
Average Sales Price - Gas (Mcf)$1.52
 $3.46
 $(1.94) (56.1)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)$0.17
 $0.12
 $0.05
 41.7 %
Average Sales Price - NGLs (Mcfe)*$1.39
 $6.39
 $(5.00) (78.2)%
Average Sales Price - Oil (Mcfe)*$6.58
 $—
 $6.58
 100.0 %
Average Sales Price - Condensate (Mcfe)*$3.79
 $11.69
 $(7.90) (67.6)%
        
Total Average Utica Sales Price (per Mcfe)$1.75
 $5.27
 $(3.52) (66.8)%
Average Utica Lease Operating Expenses (per Mcfe)0.39
 1.05
 (0.66) (62.9)%
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)0.04
 0.08
 (0.04) (50.0)%
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)0.61
 0.42
 0.19
 45.2 %
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)1.06
 1.11
 (0.05) (4.5)%
   Total Average Utica Costs (per Mcfe)$2.10
 $2.66
 $(0.56) (21.1)%
   Average Margin for Utica (per Mcfe)$(0.35) $2.61
 $(2.96) (113.4)%
 For the Years Ended December 31,
 2017 2016 Variance Percent
Change
Other Gas Sales Volumes (Bcf)19.2
 21.7
 (2.5) (11.5)%
Oil Sales Volumes (Bcfe)*0.2
 0.4
 (0.2) (50.0)%
Total Other Sales Volumes (Bcfe)*19.4
 22.1
 (2.7) (12.2)%
        
Average Sales Price - Gas (per Mcf)$2.69
 $1.79
 $0.90
 50.3 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$(0.14) $0.75
 $(0.89) (118.7)%
Average Sales Price - Oil (per Mcfe)*$7.75
 $6.23
 $1.52
 24.4 %
        
Total Average Other Sales Price (per Mcfe)$2.62
 $2.61
 $0.01
 0.4 %
Average Other Lease Operating Expenses (per Mcfe)0.63
 0.69
 (0.06) (8.7)%
Average Other Production, Ad Valorem, and Other Fees (per Mcfe)0.12
 0.12
 —
 — %
Average Other Transportation, Gathering and Compression Costs (per Mcfe)0.90
 1.07
 (0.17) (15.9)%
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe)1.05
 1.49
 (0.44) (29.5)%
   Total Average Other Costs (per Mcfe)$2.70
 $3.37
 $(0.67) (19.9)%
   Average Margin for Other (per Mcfe)$(0.08) $(0.76) $0.68
 89.5 %

*NGLs and Condensate areOil is converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.

The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes purchased gas activity, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, impairment of exploration and production properties and other operational activity not assigned to a specific segment.

Other Gas sales volumes are primarily related to shallow oil and gas production. Natural gas, NGLs and oil sales related to the Other Gas segment were $53 million for the year ended December 31, 2017 compared to $40 million for the year ended December 31, 2016. The increase in natural gas and oil sales resulted from the $0.90 per Mcf increase in average gas sales price. Total exploration and production costs related to these other sales were $56 million for the year ended December 31, 2017 compared to $78 million for the year ended December 31, 2016. The decrease was primarily due to a decrease in depreciation, depletion and amortization costs as a result of certain assets becoming fully depreciated in the current period as well as the sale of Knox Energy in the second quarter of 2017 (See Note 3 - Acquisitions and Dispositions in the Notes to the  Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $248 million as well as cash settlements paid of $2 million for the year ended December 31, 2017. For the year ended December 31, 2016, the Company recognized an unrealized loss on commodity derivative instruments of $386 million as well as cash settlements received of $17 million. The unrealized gain/loss on commodity derivative instruments represents changes in the fair value of all of the Company's existing commodity hedges on a mark-to-market basis.

Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers. Purchased gas sales revenues were $54 million for the year ended December 31, 2017 compared to $43 million for the year ended December 31, 2016. Purchased gas costs were $53 million for the year ended December 31, 2017 compared to $43 million for the year ended December 31, 2016. The period-to-period increase in purchased gas sales revenue was primarily due to the increase in market prices, as well as the increase in purchased gas sales volumes.


49


 For the Years Ended December 31,
 2017 2016 Variance 
Percent
Change
Purchased Gas Sales Volumes (in billion cubic feet)22.0
 21.7
 0.3
 1.4%
Average Sales Price (per Mcf)$2.44
 $1.99
 $0.45
 22.6%
Average Cost (per Mcf)$2.39
 $1.97
 $0.42
 21.3%

Other operating income was $69 million for the year ended December 31, 2017 compared to $65 million for the year ended December 31, 2016. The $4 million increase was primarily due to the following items:
 For the Years Ended December 31,
(in millions)2017 2016 Variance 
Percent
Change
Water Income$5
 $1
 $4
 400.0 %
Gathering Income11
 11
 —
 — %
Equity in Earnings of Affiliates50
 53
 (3) (5.7)%
Other3
 —
 3
 100.0 %
Total Other Operating Income$69
 $65
 $4
 6.2 %

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. 

Impairment of Exploration and Production Properties of $138 million for the year ended December 31, 2017 related to an impairment in the carrying value of Knox Energy in the first quarter of 2017. See Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such impairments occurred in the prior year.
Exploration and production related other costs were $48 million for the year ended December 31, 2017 compared to $15 million for the year ended December 31, 2016. The $33 million increase in costs is primarily related to the following items:
 For the Years Ended December 31,
(in millions)2017 2016 Variance 
Percent
Change
Lease Expiration Costs$40
 $7
 $33
 471.4 %
Land Rentals4
 4
 —
 — %
Permitting Expense1
 2
 (1) (50.0)%
Other3
 2
 1
 50.0 %
Total Exploration and Production Related Other Costs$48
 $15
 $33
 220.0 %

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.













50


Other operating expense was $112 million for the year ended December 31, 2017 compared to $89 million for the year ended December 31, 2016. The $23 million increase in the period-to-period comparison was made up of the following items:
 For the Years Ended December 31,
 2017 2016 Variance 
Percent
Change
Idle Rig Expense$41
 $33
 $8
 24.2%
Unutilized Firm Transportation and Processing Fees50
 37
 13
 35.1%
Litigation Settlements3
 1
 2
 200.0%
Severance Expense1
 1
 —
 —%
Insurance Expense3
 3
 —
 —%
Other14
 14
 —
 —%
Total Other Operating Expense$112
 $89
 $23
 25.8%

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.
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.





51


Results of Operations: Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015
Net Loss
CNX reported a net loss of $848 million, or a loss per diluted share of $3.70, for the year ended December 31, 2016, compared to a net loss of $375 million, or a loss of $1.64 per diluted share, for the year ended December 31, 2015.
 For the Years Ended December 31,
(Dollars in thousands)2016 2015 Variance
Loss from Continuing Operations$(550,945) $(650,198) $99,253
(Loss) Income from Discontinued Operations, net(297,157) 275,313
 (572,470)
Net Loss$(848,102) $(374,885) $(473,217)

CNX's principal activity is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The Company's reportable segments are Marcellus Shale, Utica Shale, Coalbed Methane, and Other Gas.
CNX had a loss from continuing operations before income tax of $585 million for the year ended December 31, 2016, compared to a loss from continuing operations before income tax of $931 million for the year ended December 31, 2015. Included in the 2016 net loss before income tax was an unrealized loss on commodity derivative instruments of $386 million and a gain on sale of assets of $14 million. Included in the 2015 loss before income tax was a loss of $829 million primarily related to the impairment of the carrying value of CNX's shallow oil and natural gas assets due to depressed NYMEX forward strip prices (see Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). The impairment loss was partially offset by an unrealized gain on commodity derivative instruments of $197 million and a gain on sale of assets of $61 million. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s natural gas production and sales portfolio.
  For the Years Ended December 31,
 in thousands (unless noted) 2016 2015 Variance Percent
Change
LIQUIDS     

 

NGLs:     

 

Sales Volume (MMcfe) 40,260
 33,180
 7,080
 21.3 %
Sales Volume (Mbbls) 6,710
 5,530
 1,180
 21.3 %
Gross Price ($/Bbl) $14.52
 $12.30
 $2.22
 18.0 %
Gross Revenue $97,580
 $68,057
 $29,523
 43.4 %
         
Oil:        
Sales Volume (MMcfe) 410
 592
 (182) (30.7)%
Sales Volume (Mbbls) 68
 99
 (31) (31.3)%
Gross Price ($/Bbl) $36.90
 $47.94
 $(11.04) (23.0)%
Gross Revenue $2,521
 $4,736
 $(2,215) (46.8)%
         
Condensate:        
Sales Volume (MMcfe) 4,964
 7,598
 (2,634) (34.7)%
Sales Volume (Mbbls) 827
 1,266
 (439) (34.7)%
Gross Price ($/Bbl) $27.48
 $26.52
 $0.96
 3.6 %
Gross Revenue $22,748
 $33,586
 $(10,838) (32.3)%
         
GAS        
Sales Volume (MMcf) 348,753
 287,287
 61,466
 21.4 %
Sales Price ($/Mcf) $1.92
 $2.17
 $(0.25) (11.5)%
Gross Revenue $670,823
 $622,080
 $48,743
 7.8 %
         
Hedging Impact ($/Mcf) $0.70
 $0.68
 $0.02
 2.9 %
Gain on Commodity Derivative Instruments - Cash Settlement $245,212
 $196,348
 $48,864
 24.9 %


52


Natural gas, NGLs, and oil sales were $793 million for the year ended December 31, 2016, compared to $727 million for the year ended December 31, 2015. The increase was primarily due to the 20.0% increase in total sales volumes, offset in part by the 11.5% decrease in the average gas sales price per Mcf without the impact of derivative instruments. The decrease in average sales price was the result of the overall decrease in general market prices.

Sales volumes, average sales price (including the effects of derivative instruments), and average costs for all active operations were as follows: 
 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Sales Volumes (Bcfe)394.4
 328.7
 65.7
 20.0 %
        
Average Sales Price (per Mcfe)$2.63
 $2.81
 $(0.18) (6.4)%
Average Costs (per Mcfe)2.32
 2.62
 (0.30) (11.5)%
Average Margin$0.31
 $0.19
 $0.12
 63.2 %

The decrease in average sales price was primarily the result of a $0.25 Mcf decrease in general market prices in the Appalachian basin during the current period, as well as an overall decrease in natural gas liquids pricing. The increase was offset, in part, by a $0.02 Mcf increase in the realized gain on commodity derivative instruments related to the Company's hedging program.

Changes in the average costs per Mcfe were primarily related to the following items:
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.

Certain costs and expenses such as selling, general and administrative, other expense, gain on sale of assets, loss on debt extinguishment, interest expense and income taxes are unallocated expenses and therefore are excluded from the per unit costs above as well as segment reporting. Below is a summary of these costs and expenses:

Selling, General and Administrative

SG&A costs include costs such as overhead, including employee wages and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, and legal compliance expenses. SG&A costs also includes noncash equity-based compensation expense.
SG&A costs were $105 million for the year ended December 31, 2016, compared to $102 million for the year ended December 31, 2015. SG&A costs increased due to an increase in short-term incentive compensation expense offset, in part, by a decrease in employee wages and benefit costs due to the Company reorganization that occurred in the second half of 2015 and first quarter of 2016, which resulted in an overall decrease in employees.












53


Other Expense
 For the Years Ended December 31,
 (in millions)2016 2015 Variance 
Percent
Change
Other Income       
Royalty Income$10
 $—
 $10
 100.0 %
Right of Way Sales15
 6
 9
 150.0 %
Interest Income—
 2
 (2) (100.0)%
Other4
 4
 —
 — %
Total Other Income$29
 $12
 $17
 141.7 %
        
Other Expense       
Bank Fees$13
 $13
 $—
 — %
Severance1
 6
 (5) (83.3)%
Other Corporate Expense15
 17
 (2) (11.8)%
Other Land Rental Expense5
 14
 (9) (64.3)%
Total Other Expense$34
 $50
 $(16) (32.0)%
        
       Total Other Expense$5
 $38
 $(33) (86.8)%

Gain on Sale of Assets

CNX recognized a gain on sale of assets of $14 million in the year ended December 31, 2016 compared to a gain of $61 million in the year ended December 31, 2015. The $47 million decrease was primarily due to sale of CNX's interest in its Western Allegheny Energy joint venture that occurred in the year ended December 31, 2015. No individually significant transactions occurred in the year ended December 31, 2016. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Loss on Debt Extinguishment

Loss on debt extinguishment of $68 million was recognized in the year ended December 31, 2015 due to the purchase of a portion of the 8.25% senior notes due in April 2020 and the 6.375% senior notes due in March 2021.

Interest Expense
Interest expense of $182 million was recognized in the year ended December 31, 2016, compared to $199 million in the year ended December 31, 2015. The $17 million decrease was primarily due to the Company's revolving credit facility having no outstanding borrowings during the year ended December 31, 2016, compared to $952 million of outstanding borrowings at December 31, 2015. This decrease was also due to the partial payoff of the 2020 and 2021 bonds during the year ended December 31, 2015.

Income Taxes

The effective income tax rate for continuing operations was 6.0% for the year ended December 31, 2016, compared to 30.2% for the year ended December 31, 2015. During the year ended December 31, 2016, CNX settled a Federal audit of the years 2010-2013 and received a favorable private letter ruling from the IRS related to bonus depreciation. Overall, the Company received approximately $21 million in refunds during 2016. Some of the factors contributing to the refunds received during 2016 put pressure on deferred tax assets related to alternative minimum tax credits. Although these credits never expire, management could not demonstrate sufficient positive evidence to ensure realizability of these assets in the foreseeable future and as a result, the Company recorded a valuation allowance of $167 million at December 31, 2016. An additional $38 million valuation allowance was recorded at December 31, 2016 against state deferred tax assets, as well as federal charitable contributions and foreign tax credit carry-forwards.



54


See Note 5 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Total Company Loss Before Income Tax$(585) $(931) $346
 (37.2)%
Income Tax Benefit$(34) $(280) $246
 (87.7)%
Effective Income Tax Rate6.0% 30.2% (24.2)%  

TOTAL OPERATING SEGMENT ANALYSIS for the year ended December 31, 2016 compared to the year ended December 31, 2015:
CNX operating segments had a loss before income tax of $308 million for the year ended December 31, 2016 compared to a loss before income tax of $585 million for the year ended December 31, 2015. Variances by individual operating segment are discussed below.
 For the Year Ended Difference to Year Ended
 December 31, 2016 December 31, 2015
 (in millions)Marcellus Utica CBM 
Other
Gas
 Total Marcellus Utica CBM 
Other
Gas
 Total
Natural Gas, NGLs and Oil Sales$415
 $163
 $175
 $40
 $793
 $36
 $70
 $(27) $(13) $66
Gain (Loss) on Commodity Derivative Instruments147
 29
 52
 (369) (141) 46
 23
 (15) (588) (534)
Purchased Gas Sales—
 —
 —
 43
 43
 —
 —
 —
 29
 29
Other Operating Income—
 —
 —
 65
 65
 —
 —
 —
 —
 —
Total Revenue and Other Operating Income562
 192
 227
 (221) 760
 82
 93
 (42) (572) (439)
Lease Operating Expense34
 22
 25
 15
 96
 (10) —
 (8) (8) (26)
Production, Ad Valorem, and Other Fees17
 5
 6
 3
 31
 (1) 3
 (1) —
 1
Transportation, Gathering and Compression228
 51
 72
 23
 374
 28
 16
 (13) —
 31
Depreciation, Depletion and Amortization211
 86
 86
 37
 420
 49
 27
 2
 (30) 48
Impairment of Exploration and Production Properties—
 —
 —
 —
 —
 —
 —
 —
 (829) (829)
Exploration and Production Related Other Costs—
 —
 —
 15
 15
 —
 —
 —
 5
 5
Purchased Gas Costs—
 —
 —
 43
 43
 —
 —
 —
 32
 32
Other Operating Expense—
 —
 —
 89
 89
 —
 —
 —
 22
 22
Total Operating Costs and Expenses490
 164
 189
 225
 1,068
 66
 46
 (20) (808) (716)
Earnings (Loss) Before Income Tax$72
 $28
 $38
 $(446) $(308) $16
 $47
 $(22) $236
 $277



55


MARCELLUS SEGMENT
The Marcellus segment had earnings before income tax of $72 million for the year ended December 31, 2016 compared to earnings before income tax of $56 million for the year ended December 31, 2015.
 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Marcellus Gas Sales Volumes (Bcf)186.8
 149.4
 37.4
 25.0 %
NGLs Sales Volumes (Bcfe)*23.5
 19.0
 4.5
 23.7 %
Condensate Sales Volumes (Bcfe)*2.2
 3.9
 (1.7) (43.6)%
Total Marcellus Sales Volumes (Bcfe)*212.5
 172.3
 40.2
 23.3 %
        
Average Sales Price - Gas (per Mcf)$1.87
 $2.09
 $(0.22) (10.5)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$0.79
 $0.67
 $0.12
 17.9 %
Average Sales Price - NGLs (per Mcfe)*$2.38
 $2.54
 $(0.16) (6.3)%
Average Sales Price - Condensate (per Mcfe)*$4.32
 $5.02
 $(0.70) (13.9)%
        
Total Average Marcellus Sales Price (per Mcfe)$2.64
 $2.79
 $(0.15) (5.4)%
Average Marcellus Lease Operating Expenses (per Mcfe)0.16
 0.26
 (0.10) (38.5)%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)0.08
 0.10
 (0.02) (20.0)%
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe)1.07
 1.16
 (0.09) (7.8)%
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)0.99
 0.94
 0.05
 5.3 %
   Total Average Marcellus Costs (per Mcfe)$2.30
 $2.46
 $(0.16) (6.5)%
   Average Margin for Marcellus (per Mcfe)$0.34
 $0.33
 $0.01
 3.0 %
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

The UticaMarcellus segment had natural gas, NGLs and oil sales of $93$415 million for the year ended December 31, 20152016 compared to $87$379 million for the year ended December 31, 2014.2015. The $6$36 million increase was primarily due to the 236.5%a 23.3% increase in total UticaMarcellus sales volumes, partially offset by the 56.1%a 10.5% decrease in the average gas sales price.price in the period-to-period comparison. The 39.5 Bcfe increase in total Utica sales volumes was primarily due to additional wells coming on-line primarily in dry Utica areas, in the current year, ended December 31, 2015.as well as the termination of the Marcellus Joint Venture that CNX had with Noble Energy in 2016. 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. The joint venture termination was effective October 1st, 2016 and resulted in additional production for the fourth quarter of 2016, as well as the applicable sales and production costs.

The decrease in the total average UticaMarcellus sales price was primarily due to the $1.94result of the $0.22 per Mcf decrease in averagegas market prices, along with a $1.61$0.03 per Mcf decrease in the uplift from NGLs and condensate sales volumes, when excluding the impact of hedging. These decreases were offset, in part, by a $0.05 per Mcf increase in the gain on commodity derivative instruments in the current period. Financial hedges represented approximately 5.9 Bcf of the Company's produced Utica gas sales volumes for the year ended December 31, 2015 at an average gain of $1.08 per Mcf. For the year ended December 31, 2014, these financial hedges represented approximately 3.5 Bcf at an average gain of $0.35 per Mcf.


77



Total exploration and production costs for the Utica segment were $118 million for the year ended December 31, 2015 compared to $44 million for the year ended December 31, 2014. The increase in total dollars and decrease in unit costs for the Utica segment are due to the following items:

•Utica lease operating expense was $22 million for the year ended December 31, 2015 compared to $18 million for the year ended December 31, 2014. The increase in total dollars was primarily due to the increase in production which resulted in increased repair and maintenance costs, as well as increased contractual services related to well tending. The decrease in unit costs was primarily due to the 236.5% increase in total Utica sales volumes.

•Utica production, ad valorem, and other fees were $2 million for the year ended December 31, 2015 compared to $1 million for the year ended December 31, 2014. The increase in total dollars was primarily due to an increase in severance tax expense caused by the increase in total Utica sales volumes. Unit costs were positively impacted by both the increased sales volumes and the decreased average sales price.

•Utica transportation, gathering and compression costs were $35 million for the year ended December 31, 2015 compared to $7 million for the year ended December 31, 2014. The $28 million increase in total dollars was primarily related to increased gathering and processing fees associated with the increased Utica NGLs and gas sales volumes. The increase in unit costs was due to the increase in total dollars and was offset, in part, by the increase in total Utica sales volumes.

•Depreciation, depletion and amortization costs attributable to the Utica segment were $59 million for the year ended December 31, 2015 compared to $18 million for the year ended December 31, 2014. These amounts included depreciation on a unit of production basis of $1.05 per Mcf and $1.09 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.    

COALBED METHANE (CBM) SEGMENT
The CBM segment had earnings before income tax of $60 million for the year ended December 31, 2015 compared to earnings before income tax of $108 million for the year ended December 31, 2014.
 For the Years Ended December 31,
 2015 2014 Variance 
Percent
Change
CBM Gas Sales Volumes (Bcf)74.9
 79.5
 (4.6) (5.8)%
        
Average Sales Price - Gas (Mcf)$2.70
 $4.32
 $(1.62) (37.5)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)$0.90
 $0.05
 $0.85
 1,700.0 %
        
Total Average CBM Sales Price (per Mcf)$3.60
 $4.37
 $(0.77) (17.6)%
Average CBM Lease Operating Expenses (per Mcf)0.44
 0.52
 (0.08) (15.4)%
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)0.10
 0.15
 (0.05) (33.3)%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)1.13
 1.20
 (0.07) (5.8)%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)1.13
 1.14
 (0.01) (0.9)%
   Total Average CBM Costs (per Mcf)$2.80
 $3.01
 $(0.21) (7.0)%
   Average Margin for CBM (per Mcf)$0.80
 $1.36
 $(0.56) (41.2)%

The CBM segment had natural gas sales of $202 million for the year ended December 31, 2015 compared to $343 million for the year ended December 31, 2014. The $141 million decrease was primarily due to a 37.5% decrease in the average gas sales price, as well as a 5.8% decrease in CBM gas sales volumes. The decrease in CBM sales volumes was primarily due to normal well declines and less drilling activity.

The total average CBM sales price decreased $0.77 per Mcf due primarily to a $1.62 per Mcf decrease in gas market prices. The decrease was offset, in part, by a $0.85$0.12 per Mcf increase in the gain on commodity derivative instruments resulting from the Company's hedging program. The increase in the gain was due to an increase in volumes hedged and lower market prices. TheseThe notional amounts associated with these financial hedges represented approximately 57.5160.8 Bcf of the Company's produced CBMMarcellus gas sales volumes for the year ended December 31, 20152016 at an average gain


78


of $1.17$0.92 per Mcf. For the year ended December 31, 2014,2015, these financial hedges represented approximately 70.090.3 Bcf at an average gain of $0.06$1.09 per Mcf.

Total explorationoperating costs and production costsexpenses for the CBMMarcellus segment were $209$490 million for the year ended December 31, 20152016 compared to $239$424 million for the year ended December 31, 2014.2015. The decreaseincrease in total dollars and decrease in unit costs for the CBMMarcellus segment wereare due to the following items:

•CBMMarcellus lease operating expense was $33$34 million for the year ended December 31, 20152016 compared to $42$44 million for the year ended December 31, 2014.2015. The decrease in total dollars was primarily relateddue to a decreasereduction in contractual servicesemployee related tocosts, well tending costs and a decrease in repairs and maintenance expense in the current period. The reduction in employee related costs was primarily due to the company reorganization that occurred in the second half of 2015 and the first quarter of 2016. The decrease in unit costs


56


was primarily due to the 23.3% increase in total Marcellus sales volumes, along with the decreased total dollars described above. The decreases were offset, in part, by an increase in salt water disposal costs in the period-to-period comparison.

•Marcellus production, ad valorem, and other fees were $17 million for the year ended December 31, 2016 compared to $18 million for the year ended December 31, 2015. The decrease in total dollars was primarily due to the decrease in total average Marcellus sales price, offset, in part, by the increase in total Marcellus sales volumes.

•Marcellus transportation, gathering and compression costs were $228 million for the year ended December 31, 2016 compared to $200 million for the year ended December 31, 2015. The $28 million increase in total dollars was primarily related to an increase in the CNXM gathering fee due to the increase in total Marcellus sales volumes (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), an increase in processing fees associated with natural gas liquids primarily due to the 23.7% increase in NGLs sales volumes, and an increase in utilized firm transportation expense. The decrease in unit costs was due to the decreaseincrease in total dollars, partially offset by the decrease in CBM gasMarcellus sales volumes.

•CBM production, ad valorem, and other fees were $7 million for the year ended December 31, 2015 compared to $12 million for the year ended December 31, 2014. The $5 million decrease was due to a decrease in severance tax expense resulting from the decrease in both gas sales volumes, and average sales price. Unit costs were positively impacted by the decrease in total average CBM sales price which was offset, in part, by the decreaseincrease in CBM gas sales volumes.total dollars.

•CBM transportation, gathering and compression costs were $85 million for the year ended December 31, 2015 compared to $96 million for the year ended December 31, 2014. The $11 million decrease was primarily related to a decrease in repairs and maintenance, power and utilized firm transportation expense resulting from the decrease in CBM gas sales volumes. Unit costs were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in CBM gas sales volumes.
•Depreciation, depletion and amortization costs attributable to the CBMMarcellus segment were $84$211 million for the year ended December 31, 2016 compared to $162 million for the year ended December 31, 2015 compared to $89 million fordriven primarily by the year ended December 31, 2014.overall increase in production. These amounts included depreciation on a unit of production basis of $0.73$0.98 per Mcf and $0.75$0.92 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.

OTHER GAS SEGMENT

The Other Gas segment had a lossearnings before income tax of $776$15 million for the year ended December 31, 20152017 compared to a loss before income tax of $134$446 million for the year ended December 31, 2014.2016.
For the Years Ended December 31,For the Years Ended December 31,
2015 2014 Variance Percent
Change		2017 2016 Variance Percent
Change
Other Gas Sales Volumes (Bcf)24.8
 27.1
 (2.3) (8.5)%19.2
 21.7
 (2.5) (11.5)%
Oil Sales Volumes (Bcfe)*0.5
 0.7
 (0.2) (28.6)%0.2
 0.4
 (0.2) (50.0)%
Total Other Sales Volumes (Bcfe)*25.3
 27.8
 (2.5) (9.0)%19.4
 22.1
 (2.7) (12.2)%
              
Average Sales Price - Gas (Mcf)$2.03
 $4.04
 $(2.01) (49.8)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)$0.88
 $0.11
 $0.77
 700.0 %
Average Sales Price - Oil (Mcfe)*$8.15
 $14.81
 $(6.66) (45.0)%
Average Sales Price - Gas (per Mcf)$2.69
 $1.79
 $0.90
 50.3 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$(0.14) $0.75
 $(0.89) (118.7)%
Average Sales Price - Oil (per Mcfe)*$7.75
 $6.23
 $1.52
 24.4 %
              
Total Average Other Sales Price (per Mcfe)$3.03
 $4.40
 $(1.37) (31.1)%$2.62
 $2.61
 $0.01
 0.4 %
Average Other Lease Operating Expenses (per Mcfe)0.90
 1.24
 (0.34) (27.4)%0.63
 0.69
 (0.06) (8.7)%
Average Other Production, Ad Valorem, and Other Fees (per Mcfe)0.14
 0.27
 (0.13) (48.1)%0.12
 0.12
 —
 — %
Average Other Transportation, Gathering and Compression Costs (per Mcfe)0.96
 1.17
 (0.21) (17.9)%0.90
 1.07
 (0.17) (15.9)%
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe)2.34
 2.85
 (0.51) (17.9)%1.05
 1.49
 (0.44) (29.5)%
Total Average Other Costs (per Mcfe)$4.34
 $5.53
 $(1.19) (21.5)%$2.70
 $3.37
 $(0.67) (19.9)%
Average Margin for Other (per Mcfe)$(1.31) $(1.13) $(0.18) (15.9)%$(0.08) $(0.76) $0.68
 89.5 %

*Oil is converted to Mcfe at the rate of one barrel equals six Mcfmcf based upon the approximate relative energy content of oil and natural gas,which is not indicative of the relationship of oil and natural gas prices.



79


The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes purchased gas activity, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, other corporate expensesimpairment of exploration and miscellaneousproduction properties and other operational activity not assigned to a specific E&P segment.

Other Gas sales volumes are primarily related to shallow oil and gas production, as well as the Chattanooga shale in Tennessee.production. Natural gas, NGLs and oil sales related to the Other Gas segment were $55$53 million for the year ended December 31, 20152017 compared to $121$40 million for the year ended December 31, 2014.2016. The decreaseincrease in natural gas and oil sales primarily related toresulted from the 49.8% decrease$0.90 per Mcf increase in average gas sales price. Total exploration and production costs related to these other sales were $115$56 million for the year ended December 31, 2017 compared to $78 million for the year ended December 31, 2016. The decrease was primarily due to a decrease in depreciation, depletion and amortization costs as a result of certain assets becoming fully depreciated in the current period as well as the sale of Knox Energy in the second quarter of 2017 (See Note 3 - Acquisitions and Dispositions in the Notes to the  Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $248 million as well as cash settlements paid of $2 million for the year ended December 31, 2017. For the year ended December 31, 2016, the Company recognized an unrealized loss on commodity derivative instruments of $386 million as well as cash settlements received of $17 million. The unrealized gain/loss on commodity derivative instruments represents changes in the fair value of all of the Company's existing commodity hedges on a mark-to-market basis.

Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers. Purchased gas sales revenues were $54 million for the year ended December 31, 2017 compared to $43 million for the year ended December 31, 2016. Purchased gas costs were $53 million for the year ended December 31, 2017 compared to $43 million for the year ended December 31, 2016. The period-to-period increase in purchased gas sales revenue was primarily due to the increase in market prices, as well as the increase in purchased gas sales volumes.


49


 For the Years Ended December 31,
 2017 2016 Variance 
Percent
Change
Purchased Gas Sales Volumes (in billion cubic feet)22.0
 21.7
 0.3
 1.4%
Average Sales Price (per Mcf)$2.44
 $1.99
 $0.45
 22.6%
Average Cost (per Mcf)$2.39
 $1.97
 $0.42
 21.3%

Other operating income was $69 million for the year ended December 31, 2017 compared to $65 million for the year ended December 31, 2016. The $4 million increase was primarily due to the following items:
 For the Years Ended December 31,
(in millions)2017 2016 Variance 
Percent
Change
Water Income$5
 $1
 $4
 400.0 %
Gathering Income11
 11
 —
 — %
Equity in Earnings of Affiliates50
 53
 (3) (5.7)%
Other3
 —
 3
 100.0 %
Total Other Operating Income$69
 $65
 $4
 6.2 %

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. 

Impairment of Exploration and Production Properties of $138 million for the year ended December 31, 2017 related to an impairment in the carrying value of Knox Energy in the first quarter of 2017. See Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such impairments occurred in the prior year.
Exploration and production related other costs were $48 million for the year ended December 31, 2017 compared to $15 million for the year ended December 31, 2016. The $33 million increase in costs is primarily related to the following items:
 For the Years Ended December 31,
(in millions)2017 2016 Variance 
Percent
Change
Lease Expiration Costs$40
 $7
 $33
 471.4 %
Land Rentals4
 4
 —
 — %
Permitting Expense1
 2
 (1) (50.0)%
Other3
 2
 1
 50.0 %
Total Exploration and Production Related Other Costs$48
 $15
 $33
 220.0 %

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.













50


Other operating expense was $112 million for the year ended December 31, 2017 compared to $89 million for the year ended December 31, 2016. The $23 million increase in the period-to-period comparison was made up of the following items:
 For the Years Ended December 31,
 2017 2016 Variance 
Percent
Change
Idle Rig Expense$41
 $33
 $8
 24.2%
Unutilized Firm Transportation and Processing Fees50
 37
 13
 35.1%
Litigation Settlements3
 1
 2
 200.0%
Severance Expense1
 1
 —
 —%
Insurance Expense3
 3
 —
 —%
Other14
 14
 —
 —%
Total Other Operating Expense$112
 $89
 $23
 25.8%

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.
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.





51


Results of Operations: Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015
Net Loss
CNX reported a net loss of $848 million, or a loss per diluted share of $3.70, for the year ended December 31, 2016, compared to a net loss of $375 million, or a loss of $1.64 per diluted share, for the year ended December 31, 2015.
 For the Years Ended December 31,
(Dollars in thousands)2016 2015 Variance
Loss from Continuing Operations$(550,945) $(650,198) $99,253
(Loss) Income from Discontinued Operations, net(297,157) 275,313
 (572,470)
Net Loss$(848,102) $(374,885) $(473,217)

CNX's principal activity is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The Company's reportable segments are Marcellus Shale, Utica Shale, Coalbed Methane, and Other Gas.
CNX had a loss from continuing operations before income tax of $585 million for the year ended December 31, 2016, compared to a loss from continuing operations before income tax of $931 million for the year ended December 31, 2015. Included in the 2016 net loss before income tax was an unrealized loss on commodity derivative instruments of $386 million and a gain on sale of assets of $14 million. Included in the 2015 loss before income tax was a loss of $829 million primarily related to the impairment of the carrying value of CNX's shallow oil and natural gas assets due to depressed NYMEX forward strip prices (see Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). The impairment loss was partially offset by an unrealized gain on commodity derivative instruments of $197 million and a gain on sale of assets of $61 million. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s natural gas production and sales portfolio.
  For the Years Ended December 31,
 in thousands (unless noted) 2016 2015 Variance Percent
Change
LIQUIDS     

 

NGLs:     

 

Sales Volume (MMcfe) 40,260
 33,180
 7,080
 21.3 %
Sales Volume (Mbbls) 6,710
 5,530
 1,180
 21.3 %
Gross Price ($/Bbl) $14.52
 $12.30
 $2.22
 18.0 %
Gross Revenue $97,580
 $68,057
 $29,523
 43.4 %
         
Oil:        
Sales Volume (MMcfe) 410
 592
 (182) (30.7)%
Sales Volume (Mbbls) 68
 99
 (31) (31.3)%
Gross Price ($/Bbl) $36.90
 $47.94
 $(11.04) (23.0)%
Gross Revenue $2,521
 $4,736
 $(2,215) (46.8)%
         
Condensate:        
Sales Volume (MMcfe) 4,964
 7,598
 (2,634) (34.7)%
Sales Volume (Mbbls) 827
 1,266
 (439) (34.7)%
Gross Price ($/Bbl) $27.48
 $26.52
 $0.96
 3.6 %
Gross Revenue $22,748
 $33,586
 $(10,838) (32.3)%
         
GAS        
Sales Volume (MMcf) 348,753
 287,287
 61,466
 21.4 %
Sales Price ($/Mcf) $1.92
 $2.17
 $(0.25) (11.5)%
Gross Revenue $670,823
 $622,080
 $48,743
 7.8 %
         
Hedging Impact ($/Mcf) $0.70
 $0.68
 $0.02
 2.9 %
Gain on Commodity Derivative Instruments - Cash Settlement $245,212
 $196,348
 $48,864
 24.9 %


52


Natural gas, NGLs, and oil sales were $793 million for the year ended December 31, 2016, compared to $727 million for the year ended December 31, 2015. The increase was primarily due to the 20.0% increase in total sales volumes, offset in part by the 11.5% decrease in the average gas sales price per Mcf without the impact of derivative instruments. The decrease in average sales price was the result of the overall decrease in general market prices.

Sales volumes, average sales price (including the effects of derivative instruments), and average costs for all active operations were as follows: 
 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Sales Volumes (Bcfe)394.4
 328.7
 65.7
 20.0 %
        
Average Sales Price (per Mcfe)$2.63
 $2.81
 $(0.18) (6.4)%
Average Costs (per Mcfe)2.32
 2.62
 (0.30) (11.5)%
Average Margin$0.31
 $0.19
 $0.12
 63.2 %

The decrease in average sales price was primarily the result of a $0.25 Mcf decrease in general market prices in the Appalachian basin during the current period, as well as an overall decrease in natural gas liquids pricing. The increase was offset, in part, by a $0.02 Mcf increase in the realized gain on commodity derivative instruments related to the Company's hedging program.

Changes in the average costs per Mcfe were primarily related to the following items:
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.

Certain costs and expenses such as selling, general and administrative, other expense, gain on sale of assets, loss on debt extinguishment, interest expense and income taxes are unallocated expenses and therefore are excluded from the per unit costs above as well as segment reporting. Below is a summary of these costs and expenses:

Selling, General and Administrative

SG&A costs include costs such as overhead, including employee wages and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, and legal compliance expenses. SG&A costs also includes noncash equity-based compensation expense.
SG&A costs were $105 million for the year ended December 31, 2016, compared to $102 million for the year ended December 31, 2015. SG&A costs increased due to an increase in short-term incentive compensation expense offset, in part, by a decrease in employee wages and benefit costs due to the Company reorganization that occurred in the second half of 2015 and first quarter of 2016, which resulted in an overall decrease in employees.












53


Other Expense
 For the Years Ended December 31,
 (in millions)2016 2015 Variance 
Percent
Change
Other Income       
Royalty Income$10
 $—
 $10
 100.0 %
Right of Way Sales15
 6
 9
 150.0 %
Interest Income—
 2
 (2) (100.0)%
Other4
 4
 —
 — %
Total Other Income$29
 $12
 $17
 141.7 %
        
Other Expense       
Bank Fees$13
 $13
 $—
 — %
Severance1
 6
 (5) (83.3)%
Other Corporate Expense15
 17
 (2) (11.8)%
Other Land Rental Expense5
 14
 (9) (64.3)%
Total Other Expense$34
 $50
 $(16) (32.0)%
        
       Total Other Expense$5
 $38
 $(33) (86.8)%

Gain on Sale of Assets

CNX recognized a gain on sale of assets of $14 million in the year ended December 31, 2016 compared to a gain of $61 million in the year ended December 31, 2015. The $47 million decrease was primarily due to sale of CNX's interest in its Western Allegheny Energy joint venture that occurred in the year ended December 31, 2015. No individually significant transactions occurred in the year ended December 31, 2016. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Loss on Debt Extinguishment

Loss on debt extinguishment of $68 million was recognized in the year ended December 31, 2015 due to the purchase of a portion of the 8.25% senior notes due in April 2020 and the 6.375% senior notes due in March 2021.

Interest Expense
Interest expense of $182 million was recognized in the year ended December 31, 2016, compared to $199 million in the year ended December 31, 2015. The $17 million decrease was primarily due to the Company's revolving credit facility having no outstanding borrowings during the year ended December 31, 2016, compared to $952 million of outstanding borrowings at December 31, 2015. This decrease was also due to the partial payoff of the 2020 and 2021 bonds during the year ended December 31, 2015.

Income Taxes

The effective income tax rate for continuing operations was 6.0% for the year ended December 31, 2016, compared to 30.2% for the year ended December 31, 2015. During the year ended December 31, 2016, CNX settled a Federal audit of the years 2010-2013 and received a favorable private letter ruling from the IRS related to bonus depreciation. Overall, the Company received approximately $21 million in refunds during 2016. Some of the factors contributing to the refunds received during 2016 put pressure on deferred tax assets related to alternative minimum tax credits. Although these credits never expire, management could not demonstrate sufficient positive evidence to ensure realizability of these assets in the foreseeable future and as a result, the Company recorded a valuation allowance of $167 million at December 31, 2016. An additional $38 million valuation allowance was recorded at December 31, 2016 against state deferred tax assets, as well as federal charitable contributions and foreign tax credit carry-forwards.



54


See Note 5 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Total Company Loss Before Income Tax$(585) $(931) $346
 (37.2)%
Income Tax Benefit$(34) $(280) $246
 (87.7)%
Effective Income Tax Rate6.0% 30.2% (24.2)%  

TOTAL OPERATING SEGMENT ANALYSIS for the year ended December 31, 2016 compared to the year ended December 31, 2015:
CNX operating segments had a loss before income tax of $308 million for the year ended December 31, 2016 compared to a loss before income tax of $585 million for the year ended December 31, 2015. Variances by individual operating segment are discussed below.
 For the Year Ended Difference to Year Ended
 December 31, 2016 December 31, 2015
 (in millions)Marcellus Utica CBM 
Other
Gas
 Total Marcellus Utica CBM 
Other
Gas
 Total
Natural Gas, NGLs and Oil Sales$415
 $163
 $175
 $40
 $793
 $36
 $70
 $(27) $(13) $66
Gain (Loss) on Commodity Derivative Instruments147
 29
 52
 (369) (141) 46
 23
 (15) (588) (534)
Purchased Gas Sales—
 —
 —
 43
 43
 —
 —
 —
 29
 29
Other Operating Income—
 —
 —
 65
 65
 —
 —
 —
 —
 —
Total Revenue and Other Operating Income562
 192
 227
 (221) 760
 82
 93
 (42) (572) (439)
Lease Operating Expense34
 22
 25
 15
 96
 (10) —
 (8) (8) (26)
Production, Ad Valorem, and Other Fees17
 5
 6
 3
 31
 (1) 3
 (1) —
 1
Transportation, Gathering and Compression228
 51
 72
 23
 374
 28
 16
 (13) —
 31
Depreciation, Depletion and Amortization211
 86
 86
 37
 420
 49
 27
 2
 (30) 48
Impairment of Exploration and Production Properties—
 —
 —
 —
 —
 —
 —
 —
 (829) (829)
Exploration and Production Related Other Costs—
 —
 —
 15
 15
 —
 —
 —
 5
 5
Purchased Gas Costs—
 —
 —
 43
 43
 —
 —
 —
 32
 32
Other Operating Expense—
 —
 —
 89
 89
 —
 —
 —
 22
 22
Total Operating Costs and Expenses490
 164
 189
 225
 1,068
 66
 46
 (20) (808) (716)
Earnings (Loss) Before Income Tax$72
 $28
 $38
 $(446) $(308) $16
 $47
 $(22) $236
 $277



55


MARCELLUS SEGMENT
The Marcellus segment had earnings before income tax of $72 million for the year ended December 31, 2016 compared to earnings before income tax of $56 million for the year ended December 31, 2015.
 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Marcellus Gas Sales Volumes (Bcf)186.8
 149.4
 37.4
 25.0 %
NGLs Sales Volumes (Bcfe)*23.5
 19.0
 4.5
 23.7 %
Condensate Sales Volumes (Bcfe)*2.2
 3.9
 (1.7) (43.6)%
Total Marcellus Sales Volumes (Bcfe)*212.5
 172.3
 40.2
 23.3 %
        
Average Sales Price - Gas (per Mcf)$1.87
 $2.09
 $(0.22) (10.5)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$0.79
 $0.67
 $0.12
 17.9 %
Average Sales Price - NGLs (per Mcfe)*$2.38
 $2.54
 $(0.16) (6.3)%
Average Sales Price - Condensate (per Mcfe)*$4.32
 $5.02
 $(0.70) (13.9)%
        
Total Average Marcellus Sales Price (per Mcfe)$2.64
 $2.79
 $(0.15) (5.4)%
Average Marcellus Lease Operating Expenses (per Mcfe)0.16
 0.26
 (0.10) (38.5)%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)0.08
 0.10
 (0.02) (20.0)%
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe)1.07
 1.16
 (0.09) (7.8)%
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)0.99
 0.94
 0.05
 5.3 %
   Total Average Marcellus Costs (per Mcfe)$2.30
 $2.46
 $(0.16) (6.5)%
   Average Margin for Marcellus (per Mcfe)$0.34
 $0.33
 $0.01
 3.0 %
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

The Marcellus segment had natural gas, NGLs and oil sales of $415 million for the year ended December 31, 2016 compared to $379 million for the year ended December 31, 2015. The $36 million increase was primarily due to a 23.3% increase in total Marcellus sales volumes, partially offset by a 10.5% decrease in the average gas sales price in the period-to-period comparison. The increase in total sales volumes was primarily due to additional wells coming on-line in the current year, as well as the termination of the Marcellus Joint Venture that CNX had with Noble Energy in 2016. 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. The joint venture termination was effective October 1st, 2016 and resulted in additional production for the fourth quarter of 2016, as well as the applicable sales and production costs.

The decrease in the total average Marcellus sales price was primarily the result of the $0.22 per Mcf decrease in gas market prices, along with a $0.03 per Mcf decrease in the uplift from NGLs and condensate sales volumes, when excluding the impact of hedging. These decreases were offset, in part, by a $0.12 per Mcf increase in the gain on commodity derivative instruments resulting from the Company's hedging program. The increase in the gain was due to an increase in volumes hedged and lower market prices. The notional amounts associated with these financial hedges represented approximately 160.8 Bcf of the Company's produced Marcellus gas sales volumes for the year ended December 31, 2016 at an average gain of $0.92 per Mcf. For the year ended December 31, 2015, these financial hedges represented approximately 90.3 Bcf at an average gain of $1.09 per Mcf.

Total operating costs and expenses for the Marcellus segment were $490 million for the year ended December 31, 2016 compared to $424 million for the year ended December 31, 2015. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

•Marcellus lease operating expense was $34 million for the year ended December 31, 2016 compared to $44 million for the year ended December 31, 2015. The decrease in total dollars was primarily due to a reduction in employee related costs, well tending costs and repairs and maintenance expense in the current period. The reduction in employee related costs was primarily due to the company reorganization that occurred in the second half of 2015 and the first quarter of 2016. The decrease in unit costs


56


was primarily due to the 23.3% increase in total Marcellus sales volumes, along with the decreased total dollars described above. The decreases were offset, in part, by an increase in salt water disposal costs in the period-to-period comparison.

•Marcellus production, ad valorem, and other fees were $17 million for the year ended December 31, 2016 compared to $18 million for the year ended December 31, 2015. The decrease in total dollars was primarily due to the decrease in total average Marcellus sales price, offset, in part, by the increase in total Marcellus sales volumes.

•Marcellus transportation, gathering and compression costs were $228 million for the year ended December 31, 2016 compared to $200 million for the year ended December 31, 2015. The $28 million increase in total dollars was primarily related to an increase in the CNXM gathering fee due to the increase in total Marcellus sales volumes (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), an increase in processing fees associated with natural gas liquids primarily due to the 23.7% increase in NGLs sales volumes, and an increase in utilized firm transportation expense. The decrease in unit costs was due to the increase in total Marcellus sales volumes, offset, in part, by the increase in total dollars.

•Depreciation, depletion and amortization costs attributable to the Marcellus segment were $211 million for the year ended December 31, 2016 compared to $162 million for the year ended December 31, 2015 compareddriven primarily by the overall increase in production. These amounts included depreciation on a unit of production basis of $0.98 per Mcf and $0.92 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to $158gas well closing.

UTICA SEGMENT

The Utica segment had earnings before income tax of $28 million for the year ended December 31, 2014.2016 compared to a loss before income tax of $19 million for the year ended December 31, 2015.
 For the Years Ended December 31,
 2016 2015 Variance Percent
Change
Utica Gas Sales Volumes (Bcf)71.3
 38.3
 33.0
 86.2 %
NGLs Sales Volumes (Bcfe)*16.7
 14.1
 2.6
 18.4 %
Oil Sales Volumes (Bcfe)*—
 0.1
 (0.1) (100.0)%
Condensate Sales Volumes (Bcfe)*2.8
 3.7
 (0.9) (24.3)%
Total Utica Sales Volumes (Bcfe)*90.8
 56.2
 34.6
 61.6 %
        
Average Sales Price - Gas (per Mcf)$1.52
 $1.52
 $—
 — %
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$0.41
 $0.17
 $0.24
 141.2 %
Average Sales Price - NGLs (per Mcfe)*$2.49
 $1.39
 $1.10
 79.1 %
Average Sales Price - Oil (per Mcfe)*$—
 $6.58
 $(6.58) (100.0)%
Average Sales Price - Condensate (per Mcfe)*$4.78
 $3.79
 $0.99
 26.1 %
        
Total Average Utica Sales Price (per Mcfe)$2.12
 $1.75
 $0.37
 21.1 %
Average Utica Lease Operating Expenses (per Mcfe)0.25
 0.39
 (0.14) (35.9)%
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)0.05
 0.04
 0.01
 25.0 %
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)0.57
 0.61
 (0.04) (6.6)%
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)0.94
 1.06
 (0.12) (11.3)%
   Total Average Utica Costs (per Mcfe)$1.81
 $2.10
 $(0.29) (13.8)%
   Average Margin for Utica (per Mcfe)$0.31
 $(0.35) $0.66
 188.6 %
*NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

The Utica segment had natural gas, NGLs and oil sales of $163 million for the year ended December 31, 2016 compared to $93 million for the year ended December 31, 2015. The $70 million increase was primarily due to the 61.6% increase in total


57


Utica sales volumes. The 34.6 Bcfe increase in total Utica sales volumes was due to additional wells coming on-line, primarily in dry Utica areas, in 2016.

The increase in the total average Utica sales price was primarily due to a $0.24 per Mcf increase in the gain on commodity derivative instruments in 2016, as well as a $0.16 per Mcf increase in the uplift from NGLs and condensate sales volumes. The increase in the hedging gain was due to an increase in the volumes hedged that were designated as Utica volumes. Financial hedges represented approximately 31.6 Bcf of the Company's produced Utica gas sales volumes for the year ended December 31, 2016 at an average gain of $0.93 per Mcf. For the year ended December 31, 2015, these financial hedges represented approximately 5.9 Bcf at an average gain of $1.08 per Mcf.

Total operating costs and expenses for the Utica segment were $164 million for the year ended December 31, 2016 compared to $118 million for the year ended December 31, 2015. The increase in total dollars and decrease in unit costs for the Utica segment was due to the following items:

•Utica lease operating expense remained flat at $22 million for each of the years ended December 31, 2016 and December 31, 2015. The decrease in unit costs was primarily due to the 61.6% increase in total Utica sales volumes.

•Utica production, ad valorem, and other fees were $5 million for the year ended December 31, 2016 compared to $2 million for the year ended December 31, 2015. The increase in total dollars was primarily due to the 61.6% increase in total Utica sales volumes. The increase in unit costs was also due to a credit received from a joint venture partner in the 2015 period, related to an over-billing of ad valorem taxes.

•Utica transportation, gathering and compression costs were $51 million for the year ended December 31, 2016 compared to $35 million for the year ended December 31, 2015. The $16 million increase in total dollars was primarily related to increased gathering and processing fees associated with the increased Utica NGLs and gas sales volumes. The decrease in unit costs was due to the increase in total Utica sales volumes, predominantly dry Utica, which was offset, in part, by the increase in total dollars.

•Depreciation, depletion and amortization costs attributable to the Utica segment were $86 million for the year ended December 31, 2016 compared to $59 million for the year ended December 31, 2015 driven primarily by the overall increase in production. These amounts included depreciation on a unit of production basis of $0.93 per Mcf and $1.05 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.    

COALBED METHANE (CBM) SEGMENT
The CBM segment had earnings before income tax of $38 million for the year ended December 31, 2016 compared to earnings before income tax of $60 million for the year ended December 31, 2015.
 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
CBM Gas Sales Volumes (Bcf)69.0
 74.9
 (5.9) (7.9)%
        
Average Sales Price - Gas (per Mcf)$2.53
 $2.70
 $(0.17) (6.3)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$0.76
 $0.90
 $(0.14) (15.6)%
        
Total Average CBM Sales Price (per Mcf)$3.29
 $3.60
 $(0.31) (8.6)%
Average CBM Lease Operating Expenses (per Mcf)0.36
 0.44
 (0.08) (18.2)%
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)0.09
 0.10
 (0.01) (10.0)%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)1.04
 1.13
 (0.09) (8.0)%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)1.25
 1.13
 0.12
 10.6 %
   Total Average CBM Costs (per Mcf)$2.74
 $2.80
 $(0.06) (2.1)%
   Average Margin for CBM (per Mcf)$0.55
 $0.80
 $(0.25) (31.3)%

The CBM segment had natural gas sales of $175 million for the year ended December 31, 2016 compared to $202 million for the year ended December 31, 2015. The $27 million decrease was primarily due to a 6.3% decrease in the average gas sales


58


price, as well as a 7.9% decrease in CBM gas sales volumes. The decrease in CBM sales volumes was primarily due to normal well declines and less drilling activity.

The total average CBM sales price decreased $0.31 per Mcf due primarily to a $0.17 per Mcf decrease in gas market prices, as well as a $0.14 per Mcf decrease in the gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 55.0 Bcf of the Company's produced CBM sales volumes for the year ended December 31, 2016 at an average gain of $0.95 per Mcf. For the year ended December 31, 2015, these financial hedges represented approximately 57.5 Bcf at an average gain of $1.17 per Mcf.

Total operating costs and expenses for the CBM segment were $189 million for the year ended December 31, 2016 compared to $209 million for the year ended December 31, 2015. The decrease in total dollars and decrease in unit costs for the CBM segment were due to the following items:
•CBM lease operating expense was $25 million for the year ended December 31, 2016 compared to $33 million for the year ended December 31, 2015. The decrease in total dollars was primarily related to a decrease in contractual services related to well tending, a decrease in repairs and maintenance expense, a decrease in employee related costs, and a decrease in salt water disposal costs. The decrease in unit costs was due to the decrease in total dollars, partially offset by the decrease in CBM gas sales volumes.

•CBM production, ad valorem, and other fees were $6 million for the year ended December 31, 2016 compared to $7 million for the year ended December 31, 2015. The $1 million decrease was due to a decrease in severance tax expense resulting from the decrease in both gas sales volumes and average sales price. Unit costs were positively impacted by the decrease in total average CBM sales price which was offset, in part, by the decrease in CBM gas sales volumes.

•CBM transportation, gathering and compression costs were $72 million for the year ended December 31, 2016 compared to $85 million for the year ended December 31, 2015. The $13 million decrease was primarily related to a decrease in repairs and maintenance, power and utilized firm transportation expense resulting from the decrease in CBM gas sales volumes. Unit costs were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in CBM gas sales volumes.
•Depreciation, depletion and amortization costs attributable to the CBM segment were $86 million for the year ended December 31, 2016 compared to $84 million for the year ended December 31, 2015. These amounts included depletion on a unit of production basis of $0.82 per Mcf and $0.73 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.



59


OTHER GAS SEGMENT

The Other Gas segment had a loss before income tax of $446 million for the year ended December 31, 2016 compared to a loss before income tax of $682 million for the year ended December 31, 2015.
 For the Years Ended December 31,
 2016 2015 Variance Percent
Change
Other Gas Sales Volumes (Bcf)21.7
 24.7
 (3.0) (12.1)%
Oil Sales Volumes (Bcfe)*0.4
 0.5
 (0.1) (20.0)%
Total Other Sales Volumes (Bcfe)*22.1
 25.2
 (3.1) (12.3)%
        
Average Sales Price - Gas (per Mcf)$1.79
 $2.03
 $(0.24) (11.8)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$0.75
 $0.88
 $(0.13) (14.8)%
Average Sales Price - Oil (per Mcfe)*$6.23
 $8.15
 $(1.92) (23.6)%
        
Total Average Other Sales Price (per Mcfe)$2.61
 $3.03
 $(0.42) (13.9)%
Average Other Lease Operating Expenses (per Mcfe)0.69
 0.90
 (0.21) (23.3)%
Average Other Production, Ad Valorem, and Other Fees (per Mcfe)0.12
 0.14
 (0.02) (14.3)%
Average Other Transportation, Gathering and Compression Costs (per Mcfe)1.07
 0.96
 0.11
 11.5 %
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe)1.49
 2.34
 (0.85) (36.3)%
   Total Average Other Costs (per Mcfe)$3.37
 $4.34
 $(0.97) (22.4)%
   Average Margin for Other (per Mcfe)$(0.76) $(1.31) $0.55
 42.0 %

*Oil is converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.

The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes purchased gas activity, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, impairment of exploration and production properties and other operational activity not assigned to a specific segment.

Other Gas sales volumes are primarily related to shallow oil and gas production. Natural gas, NGLs and oil sales related to the Other Gas segment were $40 million for the year ended December 31, 2016 compared to $53 million for the year ended December 31, 2015. The decrease in natural gas and oil sales primarily related to the $0.24 per Mcf decrease in average gas sales price as well as the 12.1% decrease in Other Gas sales volumes. Total exploration and production costs related to these other sales were $78 million for the year ended December 31, 2016 compared to $116 million for the year ended December 31, 2015. The decrease was primarily due to a decrease in depreciation, depletion and amortization related costs related to the adjustment to the Company's shallow oil and gas rates after an impairment in the carrying value was recognized in the second quarter of 2015 (see Note 91 - Property, Plant and Equipment ofSignificant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information), as well as a decrease in lease operating expense due to a decrease in employee related costs.

The Other Gas segment recognized an unrealized loss on commodity derivative instruments of $386 million as well as cash settlements received of $17 million for the year ended December 31, 2016. For the year ended December 31, 2015, the Company recognized an unrealized gain on commodity derivative instruments of $197 million as well as cash settlements received of $22 million for the year ended December 31, 2015. For the year ended December 31, 2014, the Company recognized cash settlements of $3 million. The unrealized loss/gain on commodity derivative instruments representsrepresented changes in the fair value of all of the Company's existing commodity hedges on a mark-to-market basis and is the result of the December 31, 2014 de-designation of all derivative positions as cash flow hedges. Changes in fair value were recorded in Accumulated Other Comprehensive Income prior to de-designation.basis.

Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers. Purchased gas sales revenues were $43 million for the year ended December 31, 2016 compared to $14 million for the year ended December 31, 2015 compared to $92015. Purchased gas costs were $43 million for the year ended December 31, 2014. Purchased gas costs were2016 compared to $11 million for the year ended December 31, 2015 compared to $7 million for the year ended December 31, 2014.2015. The period-to-period increase in purchased gas sales revenue was due to the increase in purchased gas sales, volumes, offset, in part, by the decrease in market prices.
 For the Years Ended December 31,
 2015 2014 Variance 
Percent
Change
Purchased Gas Sales Volumes (in billion cubic feet)6.8
 1.9
 4.9
 257.9 %
Average Sales Price (per Mcf)$2.14
 $4.65
 $(2.51) (54.0)%
Average Cost (per Mcf)$1.59
 $3.75
 $(2.16) (57.6)%

Miscellaneous other income was $62 million for the year ended December 31, 2015 compared to $60 million for the year ended December 31, 2014. The $2 million increase was primarily due to the following items:
 For the Years Ended December 31,
(in millions)2015 2014 Variance 
Percent
Change
Equity in Earnings of Affiliates$47
 $32
 $15
 46.9 %
Gathering Revenue10
 24
 (14) (58.3)%
Other5
 4
 1
 25.0 %
Total Miscellaneous Other Income$62
 $60
 $2
 3.3 %

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.
Gain on sale of assets was $13 million for the year ended December 31, 2015 compared to $46 million for the year ended December 31, 2014. The $33 million decrease was primarily due to the sale of Utica rights in Marshall County, WV to Noble Energy, which closed in December 2014 and resulted in a pre-tax gain of $25 million. The remaining decrease was due to various land asset sales that occurred throughout both periods, none of which were individually material.



8060


Exploration and production related other costs were $10
 For the Years Ended December 31,
 2016 2015 Variance 
Percent
Change
Purchased Gas Sales Volumes (in billion cubic feet)21.7
 6.8
 14.9
 219.1 %
Average Sales Price (per Mcf)$1.99
 $2.14
 $(0.15) (7.0)%
Average Cost (per Mcf)$1.97
 $1.59
 $0.38
 23.9 %

Other operating income was $65 million for each of the yearyears ended December 31, 2015 compared to $23 million for the year ended2016 and December 31, 2014. The $13 million decrease is due to the following items:
 For the Years Ended December 31,
(in millions)2015 2014 Variance 
Percent
Change
Lease Expiration Costs$4
 $9
 $(5) (55.6)%
Seismic Activity—
 5
 (5) (100.0)%
Land Rentals5
 5
 —
 — %
Permitting Expense1
 1
 —
 — %
Other—
 3
 (3) (100.0)%
Total Exploration and Other Costs$10
 $23
 $(13) (56.5)%

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.
2015. Other corporate expenses were $66 million for the year ended December 31, 2015 compared to $47 million for the year ended December 31, 2014. The $19 million increase in the period-to-period comparison was made upoperating income consisted of the following items:
 For the Years Ended December 31,
(in millions)2015 2014 Variance 
Percent
Change
Idle Rig Expense$19
 $—
 $19
 100.0 %
Severance Expense5
 —
 5
 100.0 %
Litigation Expense2
 —
 2
 100.0 %
Insurance Expense3
 4
 (1) (25.0)%
Bank Fees—
 4
 (4) (100.0)%
Unutilized Firm Transportation and Processing Fees33
 38
 (5) (13.2)%
Other4
 1
 3
 300.0 %
Total Other Corporate Expenses$66
 $47
 $19
 40.4 %

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.
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.

 For the Years Ended December 31,
(in millions)2016 2015 Variance 
Percent
Change
Equity in Earnings of Affiliates$53
 $55
 $(2) (3.6)%
Gathering Income11
 10
 1
 10.0 %
Water Income1
 —
 1
 100.0 %
Total Other Operating Income$65
 $65
 $—
 — %
Impairment of Explorationexploration and Production Propertiesproduction properties of $829 million for the year ended December 31, 2015 relatesrelated to the write down of the Company's shallow oil and gas asset values in June 2015. See Note 9- Property, Plant and Equipment of1- Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such write downs occurred in the year ended December 31, 2014.
Selling, general and administrative (SG&A) costs are allocated to the total E&P segment based on percentage of total revenue and percentage of total projected capital expenditures. SG&A costs were $102 million for the year ended December 31, 2015 compared to $129 million for the year ended December 31, 2014. Refer to the discussion of total company selling, general and administrative costs contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders"of this annual report for a detailed cost explanation.2016.


81



Interest expense related to the E&P division was $6 million for the year ended December 31, 2015 compared to $9 million for the year ended December 31, 2014. Interest expense was incurred by the Other Gas segment on interest allocated to the E&P division under CONSOL Energy's credit facility.

TOTAL PA MINING OPERATIONS DIVISION ANALYSIS for the year ended December 31, 2015 compared to the year ended December 31, 2014:
The PA Mining Operations division principal activities consist of mining, preparation and marketing of thermal coal to power generators. The division also includes selling, general and administrative costs, as well as various other activities assigned to the PA Mining Operations division but not included in the cost components on a per unit basis.

The PA Mining Operations division had earnings before income tax of $405 million for the year ended December 31, 2015, compared to earnings before income tax of $431 million for the year ended December 31, 2014. Variances are discussed below.
 For the Years Ended December 31,
 (in millions)2015 2014 Variance
Sales:     
Coal Sales$1,289
 $1,617
 $(328)
Freight Revenue20
 23
 (3)
Miscellaneous Other Income4
 38
 (34)
Gain on Sale of Assets—
 1
 (1)
Total Revenue and Other Income1,313
 1,679
 (366)
Operating Costs and Expenses:     
Operating Costs789
 975
 (186)
Depreciation, Depletion and Amortization167
��165
 2
Total Operating Costs and Expenses956
 1,140
 (184)
Other Costs and Expenses:     
Other Costs(122) 8
 (130)
Depreciation, Depletion and Amortization10
 8
 2
Total Other Costs and Expenses(112) 16
 (128)
Freight Expense20
 23
 (3)
Selling, General and Administrative Costs41
 69
 (28)
Total PA Mining Operations Costs905
 1,248
 (343)
Interest Expense3
 —
 3
Total PA Mining Operations Division Expense908
 1,248
 (340)
Earnings Before Income Tax$405
 $431
 $(26)

The PA Mining Operations coal revenue and cost components on a per unit basis for these periods were as follows:
 For the Years Ended December 31,
 2015 2014 Variance 
Percent
Change
Company Produced PA Mining Operations Tons Sold (in millions)22.9
 26.1
 (3.2) (12.3%)
Average Sales Price Per PA Mining Operations Ton Sold$56.36
 $61.88
 $(5.52) (8.9%)
        
Total Operating Costs Per Ton Sold$34.47
 $37.29
 $(2.82) (7.6%)
Total Depreciation, Depletion and Amortization Costs Per Ton Sold7.31
 6.34
 0.97
 15.3%
     Total Costs Per PA Mining Operations Ton Sold$41.78
 $43.63
 $(1.85) (4.2%)
     Average Margin Per PA Mining Operations Ton Sold$14.58
 $18.25
 $(3.67) (20.1%)



82


Coal Sales
PA Mining Operations coal sales were $1,289 million for the year ended December 31, 2015, compared to $1,617 million for the year ended December 31, 2014. The $328 million decrease was attributable to a 3.2million decrease in company produced tons sold and a $5.52 lower average sales price per ton sold. The lower tons sold and average sales price per PA Mining Operations ton sold were primarily the result of the continued decline in both the domestic and global thermal coal markets. Due to the weak domestic thermal spot market, 5.5 million tons were sold on the export market for the year ended December 31, 2015, compared to 3.3 million tons for the year ended December 31, 2014.
Freight Revenue and Freight Expense
Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on the weight of coal shipped, negotiated freight rates and method of transportation, primarily rail, used by the customers to which the Company contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue and freight expense were both $20 million for the year ended December 31, 2015, compared to $23 million for the year ended December 31, 2014. The $3 million decrease was due to decreased shipments where transportation services were contractually provided.

Miscellaneous Other Income

Miscellaneous other income was $4 million for the year ended December 31, 2015, compared to $38 million for the year ended December 31, 2014. Approximately $30 million of the decrease related to a coal customer contract buyout in the prior period. The remaining $4 million decrease was the result of various transactions that occurred during both periods, none of which were individually material.

Operating Costs and Expenses

Operating costs and expenses are comprised of costs related to produced tons sold, along with changes in both the volumes and carrying values of coal inventory. Operating costs and expenses include items such as direct operating costs, royaltyExploration and production taxes, employee-related expenses and depreciation, depletion, and amortization costs. Total operating costs and expenses for the PA Mining Operations division were $956 million for the year ended December 31, 2015, or $184 million lower than the $1,140 million for the year ended December 31, 2014. Total costs per PA Mining Operations ton sold were $41.78 per ton in the year ended December 31, 2015, compared to $43.63 per ton in the year ended December 31, 2014. The decrease in the cost of coal sold was driven by improved operational efficiencies, better geological conditions, a reduced workforce, a decrease in stream subsidence expense and other ongoing cost reduction efforts. In order to preserve margins, PA Mining Operations moved to a four-day work week in May 2015, compared to a normal five-day per week schedule. The decrease in unit costs was primarily the result of a change in allocation methodology, whereby OPEB plan changes are no longer included in unit costs.

Other Costs And Expenses
Other costs and expenses include items that are assigned to the PA Mining Operations division but are not included in unit costs, such as OPEB plan changes (beginning in the 2015 period), coal reserve holding costs and purchased coal costs. Totalrelated other costs and expenses decreased $128 million in the year ended December 31, 2015 compared to the year ended December 31, 2014. The decrease was primarily due to 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) Income Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation. No such transactions occurred during the year ended December 31, 2014.

Selling, General and Administrative Costs
Upon execution of the CNXC IPO, CNXC entered into a service agreement with CONSOL Energy that required CONSOL Energy to provide certain selling, general and administrative services. These services are paid monthly based on an agreed-upon fixed fee that is reset at least annually. 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. The amount of selling, general and administrative costs related to PA Mining Operations was $41 million for the year ended December 31, 2015, compared to $69 million for the year ended December 31, 2014. Refer to the discussion of total Company selling, general and administrative costs contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders"of this annual report for a detailed cost explanation.



83


Interest Expense
Interest expense, net of amounts capitalized, of $3 million for the year ended December 31, 2015 is primarily comprised of interest on the CNXC revolving credit facility that was drawn upon after the CNXC IPO on July 7, 2015.
OTHER DIVISION ANALYSIS for the year ended December 31, 2015 compared to the year ended December 31, 2014:
The Other division includes expenses from various corporate and diversified business activities that are not allocated to the E&P or PA Mining Operations divisions. The diversified business activities include coal terminal operations, closed and idle mine activities, water operations, selling, general and administrative activities, income tax (benefit) expense, as well as various other non-operated activities. In previous periods, this division included activity from the sales of industrial supplies (this subsidiary was sold in December 2014).

The Other division had a loss before income tax of $202 million for the year ended December 31, 2015, compared to a loss before income tax of $437 million for the year ended December 31, 2014. The Other division also includes a total Company income tax benefit related to continuing operations of $125 million for the year ended December 31, 2015, compared to total Company income tax expense ofwere $15 million for the year ended December 31, 2014.
 For the Years Ended December 31,
(in millions)2015 2014 Variance 
Percent
Change
Other Outside Sales$31
 $276
 $(245) (88.8)%
Miscellaneous Other Income78
 109
 (31) (28.4)%
Gain (Loss) on Sale of Assets61
 (4) 65
 (1,625.0)%
   Total Revenue170
 381
 (211) (55.4)%
Miscellaneous Operating Expense79
 460
 (381) (82.8)%
Selling, General and Administrative Costs15
 13
 2
 15.4 %
Depreciation, Depletion and Amortization20
 36
 (16) (44.4)%
Loss on Debt Extinguishment68
 95
 (27) (28.4)%
Interest Expense190
 214
 (24) (11.2)%
   Total Other Costs372
 818
 (446) (54.5)%
Loss Before Income Tax(202) (437) 235
 (53.8)%
Income Tax (Benefit) Expense(125) 15
 (140) (933.3)%
Net Loss$(77) $(452) $375
 (83.0)%

Other Outside Sales

In the year ended December 31, 2015, other outside sales revenue primarily consists of sales from the Company's coal terminal operations. Coal terminal operations sales were $312016 compared to $10 million for the year ended December 31, 2015,2015. The $5 million increase is due to the following items:
 For the Years Ended December 31,
(in millions)2016 2015 Variance 
Percent
Change
Lease Expiration Costs$7
 $4
 $3
 75.0 %
Permitting Expense2
 1
 1
 100.0 %
Land Rentals4
 5
 (1) (20.0)%
Other2
 —
 2
 100.0 %
Total Exploration and Production Related Other Costs$15
 $10
 $5
 50.0 %

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 $41the year ended December 31, 2015.














61


Other operating expense was $89 million for the year ended December 31, 2014.2016 compared to $67 million for the year ended December 31, 2015. The $10$22 million decreaseincrease in the period-to-period comparison was made up of the following items:
 For the Years Ended December 31,
(in millions)2016 2015 Variance 
Percent
Change
Idle Rig Expense$33
 $19
 $14
 73.7 %
Unutilized Firm Transportation and Processing Fees37
 33
 4
 12.1 %
Insurance Expense3
 3
 —
 — %
Litigation Settlements1
 2
 (1) (50.0)%
Severance Expense1
 5
 (4) (80.0)%
Other14
 5
 9
 180.0 %
Total Other Operating Expense$89
 $67
 $22
 32.8 %

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.
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 athe decrease in through-put volumesthe utilization of capacity. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and rates in the current period.

In the year ended December 31, 2014, other outside sales revenue of $235 million was generated from the Company's industrial supplies subsidiary. This subsidiary was sold in December 2014. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.

Miscellaneous Other Income

Miscellaneous other income was $78 million for the year ended December 31, 2015, compared to $109 million for the year ended December 31, 2014.when beneficial. The change is due to the following items:


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  For the Years Ended December 31,
(in millions) 2015 2014 Variance
Equity in Earnings of Affiliates $8
 $18
 $(10)
Purchased Coal Sales 2
 9
 (7)
Rental Income 37
 43
 (6)
Royalty Income 15
 20
 (5)
Interest Income 2
 2
 —
Right of Way Sales 8
 7
 1
Other Income 6
 10
 (4)
Total Miscellaneous Other Income $78
 $109
 $(31)

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.when this capacity is released (sold) is included in Gathering Income in other operating income above.
Royalty Income related to non-operated coal propertiesSeverance Expense decreased $5 million primarily due to the overall decrease in domestic coal pricing.

Gain (Loss) on Sale of Assets

Gain (loss) on sale of assets increased $65$4 million in the period-to-period comparison primarily 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.

Miscellaneous Operating Expense

Miscellaneous operating expense related to the Other division was $79 million for the year ended December 31, 2015, compared to $460 million for the year ended December 31, 2014. Miscellaneous operating expense decreased in the period-to-period comparison due to the following items:


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  For the Years Ended December 31,
(in millions) 2015 2014 Variance
Industrial Supplies $—
 $231
 $(231)
OPEB Plan Changes (125) 10
 (135)
Purchased Coal 1
 14
 (13)
Closed and Idle Mines 9
 20
 (11)
Pension Settlement 19
 29
 (10)
Corporate Initiative Fees and Other Legal Charges —
 10
 (10)
Coal Terminal Operations 20
 26
 (6)
Coal Reserve Holding Costs 8
 11
 (3)
Revolver Modification Fees —
 3
 (3)
Litigation Expense —
 3
 (3)
Bank Fees 17
 19
 (2)
Lease Rental Expense 31
 33
 (2)
UMWA Expenses 10
 10
 —
Workers' Compensation 7
 4
 3
Severance Payments 6
 1
 5
Industrial Supplies Working Capital Settlement 6
 —
 6
Pension Expense 6
 —
 6
OPEB Expense 47
 16
 31
Other 17
 20
 (3)
Miscellaneous Operating Expense $79
 $460
 $(381)

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.
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.
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,third quarter of 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 increased $6 million in the period-to-period comparison primarily due to The Company also had 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.first quarter 2016 reorganization that was less significant.

Selling, General and Administrative Costs

Selling, general and administrative costs allocated to the Other division were $15 million for the year ended December 31, 2015, compared to $13 million for the year ended December 31, 2014. Refer to the discussion of total Company selling, general and administrative costs contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this annual report for more information.

Depreciation, Depletion and Amortization

Deprecation, depletion, and amortization decreased $16 million in the period-to-period comparison, primarily related to a reduction of the asset retirement obligations at various closed and idled mine locations. The decrease was also the result of the Company's divestiture of its industrial supplies subsidiary in December 2014, as well as fewer assets placed in service in the period-to-period comparison.

Loss on Debt Extinguishment

Loss on debt extinguishment of $68 million was recognized in the year ended December 31, 2015 due to the partial purchase of the 8.25% senior notes that were due in 2020 at an average price equal to 104.6% of the principal amount, and the partial purchase of the 6.375% senior notes that were due in 2021 at an average price equal to 105.0% of the principal amount. Loss on debt extinguishment of $95 million was recognized in the year ended December 31, 2014 due to the purchase of all of the 8.00% senior notes that were due in 2017 at an average premium of 104.0% of the principal amount, and the partial purchase of the 8.25% senior notes that were due in 2020 at an average premium of 107.5% of the principal amount.

Interest Expense
Interest expense of $190 million was recognized in the year ended December 31, 2015, compared to $214 million in the year ended December 31, 2014. The $24 million decrease was primarily due to the partial payoff of the 2020 and 2021 bonds in the year ended December 31, 2015 and the early payoff of the 2017 bonds, issued in March 2015, and the 2022 bonds, issued in April and August 2014. The decrease was offset, in part, by interest on short-term borrowings.

Income Taxes

The effective income tax rate for continuing operations when excluding noncontrolling interest was 26.3% for the year ended December 31, 2015, compared to 8.3% for the year ended December 31, 2014. The effective rates for the years ended December 31, 2015 and 2014 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. For the year ended December 31, 2015, CONSOL Energy recognized certain tax benefits related to a prior-year tax provision. In order to maximize cash flow, CONSOL Energy elected to take bonus depreciation upon filing the 2014 tax return. As a result, CONSOL Energy realized a cash refund of $24 million for 2014. The bonus depreciation also created a net operating loss which was carried back to 2012. The carryback resulted in an additional cash refund of $31 million. However, these changes resulted in an expense of $27 million related to decreased percentage depletion deductions, offset, in part, by $5 million of tax benefit due to changes in the deduction for certain stock-related compensation.

For the year ended December 31, 2014, CONSOL Energy recognized certain tax benefits as a result of changes in estimates related to a prior-year tax provision that resulted in a benefit of $10 million primarily related to increased percentage of depletion. Also, the Internal Revenue Service issued its audit report relating to the examination of CONSOL Energy's 2008 and 2009 U.S. income tax returns during the year ended December 31, 2014. The result of these findings was a change in timing of certain tax


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deductions which increased the tax benefit of percentage of depletion by $7 million. Also, as a result of closing the IRS audit, CONSOL Energy filed amended state income tax returns. The Company filed the required amended returns and realized a discrete state income tax charge of $5 million which was offset by a federal income tax benefit of $2 million. See Note 6 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. 

Upon changes in facts and circumstances, management may conclude that deferred tax assets for which no valuation allowance is currently recorded may not be realizable in future periods, resulting in a future charge to record a valuation allowance. A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. Positive evidence considered includes financial and tax earnings generated over the past three years, future income projections based on existing fixed price contracts and forecasted expenses, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence includes financial and tax losses generated in prior periods and the inability to achieve forecasted results for those periods. Existing valuation allowances are re-examined under the same standards of positive and negative evidence. If it is determined that it is more likely than not that a deferred tax asset will be realized, the appropriate amount of the valuation allowance, if any, is released. Deferred tax assets and liabilities are also re-measured to reflect changes in underlying tax rates due to law changes. For the year ended December 31, 2015, a review of positive and negative evidence regarding these tax benefits concluded that the valuation allowances for various CONSOL Energy subsidiaries was warranted. As a result, CONSOL Energy recorded a valuation allowance of $65 million against certain deferred tax assets that the Company determined would not be realized.
 For the Years Ended December 31,
 2015 2014 Variance 
Percent
Change
Total Company (Loss) Earnings Before Income Tax excluding Noncontrolling Interest$(476) $180
 $(656) (364.4)%
Income Tax (Benefit) Expense$(125) $15
 $(140) (933.3)%
Effective Income Tax Rate26.3% 8.3% 18.0%  

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities in the Consolidated Financial Statements and at the date of the financial statements. See Note 1-Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making the judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates on an on-going basis. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.
Other Post Employment Benefits (OPEB), Salaried Pensions, Workers’ Compensation and Coal Workers’ Pneumoconiosis (CWP)Pension
Liabilities and expenses for OPEB, pension workers’ compensation and CWP are determined using actuarial methodologies and incorporate significant assumptions, including the interest rate used to discount the future estimated liability the expected long-term rate of return on plan assets, and several assumptions relating to the employee workforce (salary increases, health care cost trend rates, retirement age, and mortality).
The interest rate used to discount future estimated liabilities is determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve uses a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody’s or Standard & Poor’s as of the measurement date. The yield curve model parallels the plans’ projected cash flows.
The assumed rate of return on plan assets can also impact CONSOL Energy’s pension liability. The market related asset value is derived by taking the cost value of assets as of December 31, 2016 and multiplying it by the average 36-month ratio of the market value of assets to the cost value of assets. CONSOL Energy’s pension plan weighted average asset allocations at December 31, 2016 consisted of 50% equity securities and 50% debt securities.



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The estimated liabilities recognized at December 31, 2016 and the benefit payments made for the year end December 31, 2016 were as follows:
Plan Estimated Liability as of December 31, 2016 Benefit Payments for the year ended December 31, 2016
OPEB $700,085 $45,387
Pension $115,447 $2,726
Workers’ Compensation $79,693 $17,028
CWP $118,836 $11,409
Mine Closure and Gas Well ClosingAsset Retirement Obligations

The Surface Mining Control and Reclamation Act established operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. CONSOL Energy accrues for the costs of current coal mine disturbance and final coal mine and gas well closure, including the cost of treating mine water discharge where necessary. Estimates of our total mine-closing and gas well closing liabilities, which are based upon permit requirements and CONSOL Energy engineering expertise related to these requirements, including the current portion, were approximately $473.5 million at December 31, 2016. This liability is reviewed annually, or when events and circumstances indicate an adjustment is necessary, by CONSOL Energy management and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental regulations change significantly.

Accounting for Asset Retirement Obligations requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate to the closure of mines and gas wells and the reclamation of land upon exhaustion of coal and gas reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the mine closing and gas well closing liabilities.liability. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proved reserves, assumptions involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rate.

Accounting for Asset Retirement Obligations also requires depreciation ofThe Company believes that the capitalizedaccounting estimates related to asset retirement costobligations are “critical accounting estimates” because the Company must assess the expected amount and accretiontiming of the asset retirement obligation over time. The depreciation will generallyobligations.  In addition, the Company must determine the estimated present value of future liabilities.  Future results of operations for any particular quarterly or annual period could be determined on a units-of-production basis, whereasmaterially affected by changes in the accretion to be recognized will escalate over the life of the producing assets, typically as production declines.Company’s assumptions.

Income Taxes

Deferred tax assets and liabilities are recognized using enacted tax rates for the estimated future tax effects of temporary differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2016, CONSOL Energy2017, CNX has deferred tax assets in excess of deferred tax liabilities of approximately $4$92 million. At December 31, 2016, CONSOL Energy2017, CNX had a valuation allowance of $283$137 million on deferred tax assets.

CONSOL EnergyCNX evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement is determined. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax liability. Actual results could differ from those estimates upon subsequent resolution of identified matters. CONSOL EnergyCNX has $9$38 million of uncertain tax liabilities at December 31, 2016.2017.



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The Company believes that accounting estimates related to income taxes are “critical accounting estimates” because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income and exercise judgment regarding the amount of financial statement benefit to record for uncertain tax positions.  When evaluating whether or not a valuation allowance must be established on deferred tax assets, the Company exercises judgment in determining whether it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized. The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed, including carrybacks, tax planning strategies, reversal of deferred tax assets and liabilities and forecasted future taxable income. In making the determination related to uncertain tax positions, the Company considers the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. To the extent that an uncertain tax position or valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement.  Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.

Stock-Based Compensation

As of December 31, 2016, we have issued four types of share-based payment awards: options, restricted stock units, performance stock options, and performance share units. 


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The fair value of each restricted stock unit awarded is equivalent to the closing market price of a share of the Company's stock on the date of the grant. The fair value of each performance share unit is determined by a Monte Carlo simulation method. The fair value of each option is determined using the Black-Scholes option pricing model. All outstanding performance stock options are fully vested.

As of December 31, 2016, $40,234 of total unrecognized compensation costThe Company believes that the accounting estimates related to unvestedshare-based compensation are “critical accounting estimates” because they may change from period to period based on changes in assumptions about factors affecting the ultimate payout of awards, is expectedincluding the number of awards to ultimately vest and the market price and volatility of the Company’s common stock.  Future results of operations for any particular quarterly or annual period could be recognized over a weighted-average period of 2.73 years.materially affected by changes in the Company’s assumptions. See Note 1713 - Stock-basedStock-Based Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.additional information regarding the Company’s share-based compensation.

Contingencies

CONSOL EnergyCNX is currently involved in certain legal proceedings. We haveThe Company has accrued our estimate of the probable costs for the resolution of these claims. This estimate has been developed in consultation with legal counsel involved in the defense of these matters and is based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters, and management's intended response. Future results of operations for any particular quarter or annual period could be materially affected by changes in our assumptions or the outcome of these proceedings. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.

The Company believes that the accounting estimates related to contingencies are “critical accounting estimates” because the Company must assess the probability of loss related to contingencies. In addition, the Company must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions. See Note 22-Commitments18 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

Derivative Instruments

CONSOL EnergyCNX enters into financial derivative instruments to manage exposure to natural gas and oil price volatility. We measure every derivative instrument at fair value and record them on the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges,Prior to December 31, 2014, the effective portions of changes in fair value of the derivative arederivatives designated as cash flow hedges were reported in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted transaction affectsaffected earnings. The ineffective portions of hedges arewere recognized in earnings in the current year. Prior to de-designation CONSOL Energy utilized only cash flow hedges that were considered highly effective.

CONSOL Energy formally assesses, both at inceptionThe Company believes that the accounting estimates related to derivative instruments are “critical accounting estimates” because the Company’s financial condition and results of operations can be significantly impacted by changes in the market value of the hedge and on an ongoing basis, whether eachCompany’s derivative is highly effective in offsettinginstruments due to the volatility of natural gas prices. Future results of operations for any particular quarterly or annual period could be materially affected by changes in fair values or cash flows of the hedge item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.Company’s assumptions.

On December 31, 2014, CONSOL Energy de-designated all of its derivative positions as hedging instruments. Subsequent changes in fair value were recorded in current earnings. Deferred gains and losses in other comprehensive income as of that date were recorded in earnings when the related physical transaction occured.


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Natural Gas, NGL, Condensate and Oil Reserve ("Natural Gas Reserve") Values

Proved oil and Coal Reserve Valuesgas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable natural gas and coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable natural gas and coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Our natural gas reserves are reviewed by independent experts each year. Our coal reserves are periodically reviewed by an independent third party consultant. Some of the factors and assumptions which impact economically recoverable reserve estimates include:


geological conditions;
historical production from the area compared with production from other producing areas;
the assumed effects of regulations and taxes by governmental agencies;
assumptions governing future prices; and
future operating costs.

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of gas and coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual


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production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. See "Risk Factors" in Item 1A of this report for a discussion of the uncertainties in estimating our reserves.

The Company believes that the accounting estimate related to oil and gas reserves is a “critical accounting estimate” because the Company must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the estimated timing of development expenditures. Future results of operations and strength of the balance sheet for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions. See "Impairment of Long-lived Assets" below for additional information regarding the Company’s oil and gas reserves.

Impairment of Long-lived Assets:

CONSOL Energy performs a quantitative annualThe carrying values of the Company's proved oil and gas properties are reviewed for impairment test during the fourth quarter of each year over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. During interim periods, management updates these annual tests whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. Impairment tests require that the Company first compare future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using a market-specific weighted average cost of capital. During the year ended December 31, 2015, certain of the Company’s proved properties, primarily shallow oil and gas assets, failed the undiscounted cash flow portion of the test. After performing the discounted cash flow portion of the test, CONSOL EnergyCNX recorded an impairment of $824,742 in the Impairment of Exploration and Production Properties in the Consolidated Statements of Income. 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.

In February 2017, the Company approved a plan to sell subsidiaries Knox Energy LLC and Coalfield Pipeline Company (collectively, "Knox"). As part of the required evaluation under the held for sale guidance, Knox's book value was evaluated and it was determined that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold. The resulting impairment of $137,865 was included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. 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.

There were no other additional impairments related to proved properties in the year ended December 31, 2015. There were no such impairments for the years ended December 31, 2017, 2016 or 2014.2015.

CONSOL EnergyCNX evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis. Indicators of potential impairment include potential shifts in business strategy, overall economic factors and historical experience. If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period the determination is made. For the year ended December 31, 2015, unproved property impairments related to the determination that the properties will not yield proved


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reserves were $4,163 and are included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. No such impairments occurred in the year ended December 31, 2016. 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.

There were no other additional impairments related to unproved properties in the year ended December 31, 2015. There were no such impairments for the years ended December 31, 2017, 2016 and 2014.



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or 2015.

Liquidity and Capital Resources

CONSOL EnergyCNX generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. On June 18, 2014, CONSOL EnergyCNX entered into a five year Credit Agreement for a $2.0 billion senior secured revolving credit facility. In November 2016, the Company's lending group reaffirmed the $2.0 billion borrowing base of the facility, which expires on June 18, 2019. The facility is secured by substantially all of the assets of CONSOL EnergyCNX and certain of its subsidiaries. CONSOL Energy's creditIn November 2017, the facility allowswas amended to allow for upthe spin-off of the Company's coal business. At that time, the lenders' commitments to the facility were reduced from $2.0 billion of borrowings, which includesto $1.5 billion and the borrowing base remained unchanged from $2.0 billion, including a $750$650 million letters of credit aggregate sub-limit. CONSOL EnergyCNX can request an additional $500 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is limited to a borrowing base, which is determined by the lenders syndication agent and approved by the required number of lenders in good faith by calculating a value of CONSOL Energy'sCNX's proved gas reserves. The facility includes a minimum interest coverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The interest coverage ratio is calculated as the ratio of Adjusted EBITDA to cash interest expense of CONSOL EnergyCNX and certain of its subsidiaries, excluding CNXC.subsidiaries. The interest coverage ratio was 3.494.01 to 1.00 at December 31, 2016.2017. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, extraordinary gains and losses, gains and losses on discontinued operations, gains and losses on debt extinguishment and includes cash distributions received from affiliates, plus pro-rata earnings from material acquisitions. The facility also includes a minimum current ratio covenant of no less than 1.00 to 1.00, measured quarterly. The minimum current ratio is calculated as the ratio of current assets, plus revolver availability, to current liabilities excluding borrowings under the revolver. This calculation also excludes all of CNXC's current assets, current liabilities and revolver availability. The current ratio was 2.594.78 to 1.00 at December 31, 2016.2017. Affirmative and negative covenants in the facility limit the Company's ability to dispose of assets, make investments, purchase or redeem CONSOL EnergyCNX common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. The credit facility allows unlimited investments in joint ventures for the development and operation of natural gas gathering systems. The facility permits CONSOL Energy to separate its natural gas and coal businesses if the leverage ratio (which, is essentially the ratio of debt to EBITDA) of the natural gas business immediately after the separation would not be greater than 2.75 to 1.00. At December 31, 2016,2017, the facility had $326no borrowings outstanding and $239 million letters of credit outstanding, and no outstanding borrowings, leaving $1,674$1,261 million of unused capacity. From time to time, CONSOL EnergyCNX is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies' statutes and regulations. CONSOL EnergyCNX sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.

InThe April 2016 the facility was amended to requireamendment requires that the Company to:must: (i) prepay outstanding loans under the revolving credit facility to the extent that cash on hand exceeds $150 million for two consecutive business days; (ii) mortgage 85% of its proved reserves and 80% of its proved developed producing reserves, in each case, which are included in the borrowing base; (iii) maintain applicable deposit, securities and commodities accounts with the lenders or affiliates thereof; and (iv) enter into control agreements with respect to such applicable accounts. In addition, the Company pledged the equity interest it holds in CONECNX Gathering, LLC, and CONECNX Midstream Partners, LP as collateral to secure loans under the credit agreement.
CONSOL Energy terminated its accounts receivable securitization facility effective July 7, 2015. The outstanding borrowings were repaid, and the outstanding letters of credit were transferred against the revolving credit facility.

Uncertainty in the financial markets brings additional potential risks to CONSOL Energy.CNX. These risks include declines in the Company's stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact the Company's collection of trade receivables. As a result, CONSOL EnergyCNX regularly monitors the creditworthiness of its customers and counterparties and manages credit exposure through payment terms, credit limits, prepayments and security. CONSOL EnergyCNX believes that its current group of customers is financially sound and represents no abnormal business risk.

CONSOL EnergyCNX believes that cash generated from operations, asset sales and the Company's borrowing capacity will be sufficient to meet the Company's working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments and to provide required letters of credit. Nevertheless, the ability of CONSOL EnergyCNX to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures, or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the natural gas and coal industriesindustry and other financial and business factors, some of which are beyond CONSOL Energy’sCNX's control.
In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL EnergyCNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL EnergyCNX has also entered into various natural gas and NGL swap and option transactions, which exist parallel to the underlying physical


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transactions. The fair value of these contracts was a net asset of $60 million at December 31, 2017 and a net liability of $188 million at December 31, 2016 and a net asset of $267 million at December 31, 2015.2016. The Company has not experienced any issues of non-performance by derivative counterparties.

CONSOL Energy

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CNX frequently evaluates potential acquisitions. CONSOL EnergyCNX has funded acquisitions with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance that additional capital resources, including debt and equity financing, will be available to CONSOL EnergyCNX on terms which CONSOL EnergyCNX finds acceptable, or at all.

Cash Flows (in millions)
 For the Years Ended December 31,
 2016 2015 Change
Cash provided by operating activities$469
 $506
 $(37)
Cash provided by (used in) investing activities$487
 $(996) $1,483
Cash (used in) provided by financing activities$(969) $386
 $(1,355)
 For the Years Ended December 31,
 2017 2016 Change
Cash provided by operating activities$649
 $464
 $185
Cash (used in) provided by investing activities$(222) $487
 $(709)
Cash provided by (used in) financing activities$36
 $(970) $1,006

Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:

Net lossincome (loss) increased $475$1,229 million in the period-to-period comparison.
Adjustments to reconcile net income (loss) to cash provided by operating activities decreased $829primarily consisted of a $634 million due tonet 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 exploration and production properties recorded in 2015. (SeeKnox Energy (see Note 91 - Property, Plant, And Equipment,Significant Accounting Policies 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 and a $19 million a net change in discontinued operations primarily related to the spin-off of $293 million (Seeits 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), 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.

Cash (used in) provided by (used in) investing activities changed in the period-to-period comparison primarily due to the following items:

Capital expenditures decreased $756increased $460 million in the period-to-period comparison primarily due to increased expenditures in both 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.

Marcellus and Utica Shale plays resulting from increased drilling and completions activity.
Proceeds from the sale of assets increased $163$154 million primarily due to the $213proceeds of $322 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 interestapproximately 35,900 net undeveloped acres in its Western AlleghenyOhio, 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 joint venture. Seein 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 additional details. The remaining change was duemore information). In the year ended December 31, 2016, proceeds of $213 million were received related to various land and equipment asset sales that occurred throughout both periods, nonethe separation of which were individually material.the Marcellus Shale joint venture with Noble Energy.
Net investment in equity affiliates changed $158Distributions 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 November 2016 in connection with equity affiliate CONE Midstream Partners, LPCNXM acquiring an additional 25% interest in CONECNX Midstream DevCo I LP, commonly referred to as the "Anchor Systems" (SeeSystems." See Note 2520 - 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.information.
Discontinued Operations increased $407changed $372 million primarily as a resultrelated to the spin-off 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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31, 2016.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).

Cash provided by (used in) provided by financing activities changed in the period-to-period comparison primarily due to the following items:

In the year ended December 31, 2016, CONSOL EnergyCNX made payments on the senior secured credit facility of $952 million compared to proceeds from the senior secured credit facility of $952 millionmillion. No such payments were made in the year ended December 31, 2015.2017.
In the year ended December 31, 2015, CONSOL Energy made2017, 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 $771$144 million related to the partial extinguishment of the 2020 and 20212022 bonds, offset, in part, by$74 million related to the issuanceextinguishment of the 20232020 bonds and $21 million related to the extinguishment of the 2021 bonds. No such transactions occurred in the 2016 period. (SeeSee Note 1210 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details).information.


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In the year ended December 31, 2016, there were $16 million of net proceeds under the2017, 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$103 million of its common stock on the open market under the previously announced share repurchase program.market. No repurchases were made in the year ended December 31, 2016.
The remaining changes are due to various transactions that occurred throughout both periods.

The following is a summary of ourthe Company's significant contractual obligations at December 31, 20162017 (in thousands):
 
Payments due by YearPayments due by Year
Less Than
1 Year
 1-3 Years 3-5 Years 
More Than
5 Years
 Total
Less Than
1 Year
 1-3 Years 3-5 Years 
More Than
5 Years
 Total
Purchase Order Firm Commitments$62,680
 $31,989
 $1,542
 $—
 $96,211
$45,562
 $7,347
 $394
 $—
 $53,303
Gas Firm Transportation and Processing147,117
 253,235
 241,992
 622,509
 1,264,853
135,741
 257,426
 237,231
 513,744
 1,144,142
Long-Term Debt1,677
 920
 296,565
 2,453,209
 2,752,371
263
 (174) 1,704,963
 499,773
 2,204,825
Interest on Long-Term Debt170,229
 340,319
 318,432
 139,181
 968,161
140,217
 280,418
 234,489
 19,999
 675,123
Capital (Finance) Lease Obligations10,323
 20,389
 18,685
 —
 49,397
6,848
 13,877
 6,471
 —
 27,196
Interest on Capital (Finance) Lease Obligations2,915
 4,030
 1,280
 —
 8,225
1,714
 2,024
 236
 —
 3,974
Operating Lease Obligations103,325
 101,792
 54,537
 80,693
 340,347
7,497
 11,899
 10,816
 41,433
 71,645
Long-Term Liabilities—Employee Related (a)67,655
 133,280
 130,222
 586,601
 917,758
332
 573
 569
 579
 2,053
Other Long-Term Liabilities (b)532,174
 93,028
 57,140
 340,999
 1,023,341
183,915
 45,111
 10,626
 178,768
 418,420
Total Contractual Obligations (c)$1,098,095
 $978,982
 $1,120,395
 $4,223,192
 $7,420,664
$522,089
 $618,501
 $2,205,795
 $1,254,296
 $4,600,681
 _________________________
(a)Employee related long-term liabilities include other post-employment benefits,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. CONSOL EnergyCNX does not expect to contribute to the pension in 2017.
(b)Other long-term liabilities include mine reclamation andgas 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.



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Debt
At December 31, 2016, CONSOL Energy2017, CNX had total long-term debt and capital lease obligations of $2,802$2,232 million outstanding, including the current portion of long-term debt of $12$7 million. This long-term debt consisted of:
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$1,706 million of 5.875% senior unsecured notes due in April 2022 plus $5$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 CONSOL Energy'sCNX's subsidiaries.
An aggregate principal amount of $500 million of 8.00% senior unsecured notes due in April 2023 less $6$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 CONSOL Energy'sCNX'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$0.5 million on a note maturing throughin March 2018.
An aggregate principal amount of $49$27 million of capital leases with a weighted average interest rate of 6.45%7.01% 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.

At December 31, 2016, CONSOL Energy2017, CNX had no borrowings outstanding and approximately $326$239 million of letters of credit outstanding under the $2$1.5 billion senior secured revolving credit facility.


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Total Equity and Dividends
CONSOL EnergyCNX had total equity of $3,900 million at December 31, 2017 compared to $3,941 million at December 31, 2016 compared to $4,856 million at December 31, 2015.2016. See the Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for additional details.
Dividend information for the current year to date is as follows:
Declaration DateAmount Per ShareRecord DatePayment Date
February 1, 2016$0.0100February 16, 2016March 3, 2016

The declaration and payment of dividends by CONSOL EnergyCNX is subject to the discretion of CONSOL Energy’sCNX's Board of Directors, and no assurance can be given that CONSOL EnergyCNX will pay dividends in the future. CONSOL Energy’sCNX's Board of Directors determines whether dividends will be paid quarterly. CONSOL EnergyCNX suspended its quarterly dividend following the sale of the Buchanan Mine onin March 31, 2016 to further reflect the Company's increased emphasis on growth. The determination to pay dividends in the future will depend upon, among other things, general business conditions, CONSOL Energy’sCNX's financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy,CNX, planned investments by CONSOL EnergyCNX, and such other factors as the Board of Directors deems relevant. The Company's credit facility limits CONSOL Energy'sCNX's ability to pay dividends in excess of an annual rate of $0.50 per share when the Company's leverage ratio exceeds 3.50 to 1.00 and subject to an aggregate amount up to a cumulative credit calculation set forth in the facility. The total leverage ratio was 4.534.08 to 1.00 and the cumulative credit was approximately $781$389 million at December 31, 2016. The calculation of this leverage ratio excludes CNXC.2017. The credit facility does not permit dividend payments in the event of default. The indentures to the 2022 and 2023 notes limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the year ended December 31, 2016.2017.
On January 20, 201723, 2018 the Board of Directors of CONECNX Midstream GP LLC, the general partner of CONECNX Midstream Partners LP, announced the declaration of a cash distribution of $0.2724$0.3133 per unit with respect to the fourth quarter of 2016.2017. The distribution will be made on February 14, 20172018 to unitholders of record as of the close of business on February 6, 2017.5, 2018. The distribution, which equates to an annual rate of $1.0896$1.2532 per unit, represents an increase of 3.6% over the prior quarter, and an increase of 15.3%15% over the distribution paid with respect to the fourth quarter of 2015.


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On January 24, 2017, the Board of Directors of CNXC declared a cash distribution of $0.5125 per unit to all common and subordinated partner unitholders, including the holder of the general partner interest, and $0.4678 per preferred unit. The cash distribution will be made on February 15, 2017 to such holders of record at the close of business on February 9, 2017.2016.

Off-Balance Sheet Transactions
CONSOL EnergyCNX does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’sthe Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Audited Consolidated Financial Statements. CONSOL Energy participates in the UMWA Combined Benefit Fund and the UMWA 1992 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at December 31, 2016. The various multi-employer benefit plans are discussed in Note 16—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K. CONSOL Energy alsoCNX uses a combination of surety bonds, corporate guarantees and letters of credit to secure ourthe Company's financial obligations for employee-related, environmental, performance and various other items which are not reflected on the balance sheetConsolidated Balance Sheet at December 31, 2016.2017. Management believes these items will expire without being funded. See Note 22—18 - Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details of the various financial guarantees that have been issued by CONSOL Energy.CNX.
Recent Accounting Pronouncements
    
In JanuaryMay 2017, the Financial Accounting Standards Board (FASB) issued Update 2017-09 - Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting, which reduces diversity in practice and cost and complexity when applying the guidance in this Topic to a change to the terms or conditions of a share-based payment award. The amendments in this Update provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The amendments in the Update are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and should be applied prospectively to an award modification on or after the adoption date. Early adoption is permitted. The adoption of this guidance is not expected to have a material impact on the Company's financial statements.
In March 2017, the FASB issued Update 2017-012017-07 - Business CombinationsCompensation - Retirement Benefits (Topic 805). This update clarifies715): Improving the definitionPresentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which improves the presentation of net periodic pension cost and net periodic postretirement benefit cost. The amendments in the Update require that an employer report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented separately from the service cost component and outside a business withsubtotal of income from operations, if one is presented. Because CNX does not present an income from operations subtotal, that requirement is not applicable. Additionally, the objectiveCompany's service cost component is deemed immaterial, and therefore, the other components of adding guidance to assist entities with evaluating whether transactions shouldnet benefit cost will not be accounted for as acquisitions (or disposals) of assets or businesses.presented separately. For public business entities, the amendments in thisthe Update are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted as of the beginning of a fiscal year for which financial statements have not been issued. The adoption of this new guidance is not expected to have a materialan impact on CONSOL Energy'sthe Company's financial statements.
In December 2016, the FASB issued Update 2016-19 - Technical Corrections and Improvements, which covers a wide range of Topics in the Accounting Standards Codification (ASC). The amendments in this Update represent changes to clarify, correct errors, or make minor improvements to the ASC, making it easier to understand and apply by eliminating inconsistencies and providing clarifications. The amendments generally fall into one of the following categories: amendments related to differences between original guidance and the ASC, guidance clarification and reference corrections, simplification, or minor improvements. Most of the amendments in this Update do not require transition guidance and are effective upon issuance of this Update.
In October 2016, the FASB issued Update 2016-17 - Consolidation (Topic 810): Interests Held through Related Parties that are Under Common Control, which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The Update requires the reporting entity, in determining whether it satisfies the second characteristic of a primary beneficiary, to include its indirect variable interests in a VIE held through related parties that are under common control on a proportionate basis as opposed to in their entirety. The amendments in this Update will be applied retrospectively and are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The adoption of this new guidance is not expected to have a material impact on CONSOL Energy's financial statements.

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In August 2016, the FASB issued Update 2016-15 - Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The amendments relate to debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, and beneficial interests in securitization transactions. The Update also states that, in the absence of specific guidance for cash receipts and payments that have aspects of more than one class of cash flows, an entity should classify each separately identifiable source or use within the cash receipts and payments on the basis of their nature in financing, investing, or operating activities. In situations in which cash receipts or payments cannot be separated by source or use, the appropriate classification should depend on the activity that is likely to be the predominant source or use of cash flows for the item. The amendments in the Update will be applied using a retrospective transition method to each period presented and, for public entities, are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Earlyyears.The adoption is permitted, including adoption in an interim period. The Company is currently evaluating the impactof this guidance mayis not expected to have an impact on CONSOL Energy'sthe Company's financial statements.


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In June 2016, the FASB issued Update 2016-13 - Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this, the amendments in this Update replace the incurred loss impairment methodology in current Generally Accepted Accounting Principals (GAAP) with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. The amendments in this Update will be applied using a modified-retrospective approach and, for public entities, are effective for fiscal years beginning after December 15, 2019 and interim periods within those annual periods. Early adoption is permitted for fiscal years beginning after December 15, 2018 and interim periods within those annual periods. The Company believes this guidance will not have a material impact on CONSOL Energy's financial statements.
In May 2014, the FASB issued Update 2014-09, - Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605 - Revenue Recognition and most industry-specific guidance throughout the Industry Topics of the Codification.Customers. The objective of the amendments in this Update is to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and International Financial Reporting Standards (IFRS). The core principle of the guidance is thatstandard requires an entity shouldto recognize revenue to depictin a manner that depicts the transfer of promised goods or services to customers inat an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or servicesservices.  In August 2015, the FASB issued ASU No. 2015-14 Revenue from Contracts with Customers - Deferral of the Effective Date which approved a one year deferral of ASU No. 2014-09 for annual reporting periods beginning after December 15, 2017. During the fourth quarter of 2017, the Company substantially completed its detailed review of the impact of the standard on each of its contracts. The Company adopted the ASUs using the modified retrospective method of adoption on January 1, 2018 and should disclose sufficient information, both qualitativedid not require an adjustment to the opening balance of equity. The Company does not expect the standard to have a significant impact on its results of operations, liquidity or financial position in 2018. The Company implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and quantitative,generate the disclosures required under the new standard. Additional disclosures will be required to enable users of financial statements to understanddescribe the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The following updates to Topic 606 were made during 2016:

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 naturecustomers including disaggregation 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 Obligationsrevenue and Licensing, which seeks to address implementation issues in the areas of identifyingremaining performance obligations, and licensing.
In May 2016,beginning with our Form 10-Q for 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.three months ended March 31, 2018.

The new standards are effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. Management continues to evaluate the impacts that these standards will have on CONSOL Energy's financial statements, specifically as it relates to contracts that contain positive electric power price related adjustments. CONSOL Energy anticipates using the modified retrospective approach at adoption as it relates to ASU 2014-09.

In March 2016, the FASB issued Update 2016-09 - Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Specifically, this Update states that: all excess tax benefits and tax deficiencies should be recognized as income tax expense or benefit in the income statement; excess tax benefits should be classified along with other income tax cash flows as an operating activity; an entity can make an accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur; the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity. For public entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted. The adoption of this new guidance is not expected to have a material impact on CONSOL Energy's financial statements.
In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842), which increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Update 2016-02 does retain a distinction between finance leases and operating leases, which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance.


97


Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease to not significantly change from previous GAAP. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities, but to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the right-to-use asset and lease liability will be initially measured at the present value of the lease payments in the statement of financial position.The accounting applied by a lessor is largely unchanged from that applied under previous GAAP. For public business entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The CompanyCNX is currently evaluatingreviewing all existing leases and agreements that are covered by this standard and will continue to evaluate the impact this guidance may have on CONSOL Energy'sthe financial statements.statements and related disclosures.


70


ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In addition to the risks inherent in operations, CONSOL EnergyCNX is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CONSOL Energy'sCNX's exposure to the risks of changing commodity prices, interest rates and foreign exchange rates.

CONSOL EnergyCNX is exposed to market price risk in the normal course of selling natural gas and to a lesser extent in the sale of coal. CONSOL Energygas. CNX uses fixed-price contracts, options and derivative commodity instruments to minimize exposure to market price volatility in the sale of natural gas and NGLs. CONSOL Energy sells coal under both short-term and long-term contracts with fixed price and/or indexed price contracts that reflect market value. Under our risk management policy, it is not our intent to engage in derivative activities for speculative purposes.

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

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

For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.
At December 31, 2017, our open derivative instruments were in a net asset position with a fair value of $60 million, and at December 31, 2016 our open derivative instruments were in a net liability position with a fair value of $188 million. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at December 31, 2017 and 2016. A hypothetical 10 percent increase in future natural gas prices would have decreased the fair value by $323 million and $255 million at December 31, 2017 and 2016, respectively. A hypothetical 10 percent decrease in future earnings related to derivativesnatural gas prices would have increased the fair value by $253 million.$321 million and $251 million at December 31, 2017 and 2016, respectively.
CONSOL Energy'sThe Company's interest expense is sensitive to changes in the general level of interest rates in the United States. At December 31, 2017 and 2016, CONSOL EnergyCNX had $2,573$2,214 million and $2,456 million, respectively, aggregate principal amount of debt outstanding under fixed-rate instruments, including unamortized debt issuance costs of $18 million and $201$23 million, ofrespectively, and no debt outstanding under variable-rate instruments. CONSOL Energy'sThe Company's primary exposure to market risk for changes in interest rates relates to ourthe revolving credit facility, under which there were no borrowings at December 31, 2017 or 2016, and CNXC's revolving credit facility, under which there were $201 million of borrowings at December 31, 2016. Aso a hypothetical 100 basis-point increase in the average rate for CONSOL Energy's and CNXC'sthe Company's revolving credit facilitiesfacility would decreasenot impact pre-tax future earnings related to interest expense by $2 million.earnings.
Almost allAll of CONSOL Energy’sthe Company's transactions are denominated in U.S. dollars, and, as a result, it does not have material exposure to currency exchange-rate risks.











98










71



Natural Gas Hedging Volumes

As of January 17, 2017 our15, 2018, the Company's hedged gas volumes which includes a combination of NYMEX financial hedges and index (NYMEX and basis) hedges and contracts, for the periods indicated are as follows:
For the Three Months Ended  For the Three Months Ended  
March 31, June 30, September 30, December 31, Total YearMarch 31, June 30, September 30, December 31, Total Year
2017 Fixed Price Volumes         
Hedged Bcf73.3
 76.0
 81.0
 81.0
 311.3
Weighted Average Hedge Price per Mcf$2.67
 $2.62
 $2.59
 $2.61
 $2.61
2018 Fixed Price Volumes                  
Hedged Bcf54.4
 55.0
 55.6
 55.6
 220.6
98.4
 95.8
 96.8
 97.6
 388.6
Weighted Average Hedge Price per Mcf$2.75
 $2.76
 $2.76
 $2.75
 $2.75
$2.79
 $2.77
 $2.77
 $2.77
 $2.77
2019 Fixed Price Volumes                  
Hedged Bcf39.9
 40.3
 40.7
 40.8
 161.7
67.3
 68.1
 68.8
 68.8
 273.0
Weighted Average Hedge Price per Mcf$2.75
 $2.75
 $2.75
 $2.75
 $2.76
$2.74
 $2.74
 $2.74
 $2.74
 $2.74
2020 Fixed Price Volumes                  
Hedged Bcf21.1
 21.1
 21.4
 21.4
 85.0
49.9
 49.3
 49.9
 49.9
 198.3*
Weighted Average Hedge Price per Mcf$2.91
 $2.91
 $2.91
 $2.92
 $2.91
$2.85
 $2.77
 $2.77
 $2.75
 $2.78
2021 Fixed Price Volumes                  
Hedged Bcf1.7
 1.7
 1.7
 1.7
 6.8
41.0
 41.5
 42.0
 42.0
 166.5
Weighted Average Hedge Price per Mcf$3.08
 $3.08
 $3.08
 $3.08
 $3.08
$2.62
 $2.62
 $2.62
 $2.62
 $2.62
2022 Fixed Price Volumes         
Hedged Bcf37.8
 38.2
 38.7
 38.7
 153.4
Weighted Average Hedge Price per Mcf$2.83
 $2.83
 $2.83
 $2.83
 $2.83
*Quarterly volumes do not add to annual volumes in as much as a discrete condition in individual quarters, where basis hedge volumes exceed NYMEX hedge volumes, does not exist for the year taken as a whole.


9972



ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

  Page
Report of Independent Registered Public Accounting Firm
10174
Consolidated Statements of Income for the Years Ended December 31, 2017, 2016 2015 and 20142015
10275
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016,7, 2016 and 2015 and 2014
10376
Consolidated Balance Sheets at December 31, 20167 and 20152016
10477
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2017, 2016 2015 and 20142015
10679
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016, 2015 2014
10780
Notes to the Audited Consolidated Financial Statements
10881



10073


Report of Independent Registered Public Accounting Firm

The
To the Stockholders and the Board of Directors and Stockholders of CONSOL Energy Inc.CNX Resources Corporation and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CONSOL Energy Inc.CNX Resources Corporation and Subsidiaries (the Company) as of December 31, 20162017 and 2015,2016, and the related consolidated statements of income, comprehensive income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included2017, and the related notes and financial statement schedule listed in the indexIndex at Item 15(a)15 (a) (collectively referred to as the “financial statements”). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CONSOL Energy Inc. and Subsidiariesthe Company at December 31, 20162017 and 2015,2016, and the consolidated results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 2016,2017, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), CONSOL Energy Inc. and Subsidiaries'the Company's internal control over financial reporting as of December 31, 2016,2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 8, 20177, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2008.

Pittsburgh, Pennsylvania
February 8, 20177, 2018










10174


CONSOL ENERGY INC.CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per share data)For the Years Ended December 31,
 2016 2015 2014
Revenues and Other Income:     
Natural Gas, NGLs and Oil Sales$793,248
 $726,921
 $1,004,924
(Loss) Gain on Commodity Derivative Instruments(141,021) 392,942
 23,193
Coal Sales1,065,582
 1,289,036
 1,616,874
Other Outside Sales32,038
 30,967
 276,242
Purchased Gas Sales43,256
 14,450
 8,999
Freight-Outside Coal46,468
 20,499
 23,133
Miscellaneous Other Income (Note 4)167,306
 144,351
 207,460
Gain on Sale of Assets19,498
 74,173
 43,198
Total Revenue and Other Income2,026,375
 2,693,339
 3,204,023
Costs and Expenses:     
Exploration and Production Costs     
Lease Operating Expense96,434
 121,847
 139,242
Transportation, Gathering and Compression (Note 25)374,350
 343,403
 239,579
Production, Ad Valorem, and Other Fees31,049
 30,438
 39,418
Depreciation, Depletion and Amortization417,853
 370,374
 323,600
Exploration and Production Related Other Costs14,519
 10,120
 23,355
Purchased Gas Costs42,717
 10,721
 7,251
Other Corporate Expenses87,913
 65,939
 46,838
Impairment of Exploration and Production Properties—
 828,905
 —
Selling, General and Administrative Costs102,503
 102,229
 128,731
Total Exploration and Production Costs1,167,338
 1,883,976
 948,014
PA Mining Operations Costs     
Operating and Other Costs733,300
 666,302
 982,749
Depreciation, Depletion and Amortization168,195
 176,864
 173,316
Freight Expense46,468
 20,499
 23,133
Selling, General and Administrative Costs37,512
 40,843
 68,597
Total PA Mining Operations Costs985,475
 904,508
 1,247,795
Other Costs     
Miscellaneous Operating Expense182,869
 78,743
 460,429
Selling, General and Administrative Costs12,717
 14,918
 13,307
Depreciation, Depletion and Amortization12,455
 19,882
 35,727
Loss on Debt Extinguishment—
 67,751
 95,267
Interest Expense191,476
 199,266
 223,333
Total Other Costs399,517
 380,560
 828,063
Total Costs and Expenses2,552,330
 3,169,044
 3,023,872
(Loss) Earnings from Continuing Operations Before Income Tax(525,955) (475,705) 180,151
Income Tax Expense (Benefit) (Note 6)10,010
 (125,439) 15,204
(Loss) Income from Continuing Operations(535,965) (350,266) 164,947
Loss from Discontinued Operations, net(303,183) (14,209) (1,857)
Net (Loss) Income(839,148) (364,475) 163,090
Less: Net Income Attributable to Noncontrolling Interests8,954
 10,410
 —
Net (Loss) Income Attributable to CONSOL Energy Shareholders$(848,102) $(374,885) $163,090
(Dollars in thousands, except per share data)For the Years Ended December 31,
 2017 2016 2015
Revenue and Other Operating Income:     
Natural Gas, NGLs and Oil Sales$1,125,224
 $793,248
 $726,921
Gain (Loss) on Commodity Derivative Instruments206,930
 (141,021) 392,942
Purchased Gas Sales53,795
 43,256
 14,450
Other Operating Income69,182
 64,485
 64,424
Total Revenue and Other Operating Income1,455,131
 759,968
 1,198,737
Costs and Expenses:     
Operating Expense     
Lease Operating Expense88,932
 96,434
 121,847
Transportation, Gathering and Compression382,865
 374,350
 343,403
Production, Ad Valorem, and Other Fees29,267
 31,049
 30,438
Depreciation, Depletion and Amortization412,036
 419,939
 371,783
Exploration and Production Related Other Costs48,074
 14,522
 10,119
Purchased Gas Costs52,597
 42,717
 10,721
Impairment of Exploration and Production Properties137,865
 —
 828,905
Selling, General and Administrative Costs93,211
 104,843
 102,270
Other Operating Expense112,369
 88,754
 65,858
Total Operating Expense1,357,216
 1,172,608
 1,885,344
Other (Income) Expense     
Other Expense3,825
 4,783
 38,226
Gain on Sale of Assets(188,063) (14,270) (61,148)
Loss on Debt Extinguishment2,129
 —
 67,751
Interest Expense161,443
 182,195
 199,121
Total Other (Income) Expense(20,666) 172,708
 243,950
Total Costs and Expenses1,336,550
 1,345,316
 2,129,294
Income (Loss) from Continuing Operations Before Income Tax118,581
 (585,348) (930,557)
Income Tax Benefit(176,458) (34,403) (280,359)
Income (Loss) from Continuing Operations295,039
 (550,945) (650,198)
Income (Loss) from Discontinued Operations, net85,708
 (297,157) 275,313
Net Income (Loss)$380,747
 $(848,102) $(374,885)




















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


75



CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(CONTINUED)
 For the Years Ended December 31,
(Dollars in thousands, except per share data)2017 2016 2015
Earnings (Loss) Per Share     
Basic     
Income (Loss) from Continuing Operations$1.29
 $(2.40) $(2.84)
Income (Loss) from Discontinued Operations0.37
 (1.30) 1.20
Total Basic Earnings (Loss) Per Share$1.66
 $(3.70) $(1.64)
Dilutive     
Income (Loss) from Continuing Operations$1.28
 $(2.40) $(2.84)
Income (Loss) from Discontinued Operations0.37
 (1.30) 1.20
Total Dilutive Earnings (Loss) Per Share$1.65
 $(3.70) $(1.64)
      
Dividends Declared Per Share$—
 $0.01
 $0.145


CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
      
 For the Years Ended December 31,
 2017 2016 2015
Net Income (Loss)$380,747
 $(848,102) $(374,885)
Other Comprehensive Income (Loss):     
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($7,365), $16,281, 53,252)12,228
 (33,226) (86,447)
Reclassification of Cash Flow Hedges from Other Comprehensive Income to Earnings (Net of tax: $-, $25,011, $45,054)—
 (43,470) (78,051)
      
Other Comprehensive Income (Loss)12,228
 (76,696) (164,498)
      
Comprehensive Income (Loss)$392,975
 $(924,798) $(539,383)











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



102


CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(CONTINUED)
 For the Years Ended December 31,
(Dollars in thousands, except per share data)2016 2015 2014
 (Loss) Earnings Per Share     
Basic     
(Loss) Income from Continuing Operations$(2.38) $(1.57) $0.72
Loss from Discontinued Operations(1.32) (0.07) (0.01)
Total Basic (Loss) Earnings Per Share$(3.70) $(1.64) $0.71
Dilutive     
(Loss) Income from Continuing Operations$(2.38) $(1.57) $0.71
Loss from Discontinued Operations(1.32) (0.07) (0.01)
Total Dilutive (Loss) Earnings Per Share$(3.70) $(1.64) $0.70
      
Dividends Declared Per Share$0.01
 $0.145
 $0.25


CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
      
 For the Years Ended December 31,
 2016 2015 2014
Net (Loss) Income$(839,148) $(364,475) $163,090
Other Comprehensive (Loss) Income:     
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $16,281, $53,252, ($56,304))(33,226) (86,447) 94,989
Net Increase in the Value of Cash Flow Hedge (Net of tax: $-, $-, ($55,767))—
 —
 97,316
Reclassification of Cash Flow Hedges from Other Comprehensive Income to Earnings (Net of tax: $25,011, $45,054, $10,465)(43,470) (78,051) (18,288)
      
Other Comprehensive (Loss) Income(76,696) (164,498) 174,017
      
Comprehensive (Loss) Income(915,844) (528,973) 337,107
      
Less: Comprehensive Income Attributable to Noncontrolling Interests9,216
 10,410
 —
      
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders$(925,060) $(539,383) $337,107

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



10376



CONSOL ENERGY INC.CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

      
December 31,
2016		 December 31,
2015		December 31,
2017		 December 31,
2016
ASSETS      
Current Assets:      
Cash and Cash Equivalents$60,475
 $72,574
$509,167
 $46,299
Accounts and Notes Receivable:      
Trade220,222
 151,383
156,817
 124,514
Other Receivables69,901
 121,735
48,908
 51,145
Inventories (Note 8)65,461
 66,792
Supplies Inventories10,742
 15,301
Recoverable Income Taxes116,851
 13,887
31,523
 114,481
Prepaid Expenses93,146
 297,287
95,347
 75,576
Current Assets of Discontinued Operations (Note 2)83
 81,105
—
 198,823
Total Current Assets626,139
 804,763
852,504
 626,139
Property, Plant and Equipment (Note 9):   
Property, Plant and Equipment (Note 7):   
Property, Plant and Equipment13,771,388
 13,794,907
9,316,495
 9,183,959
Less—Accumulated Depreciation, Depletion and Amortization5,630,949
 5,062,201
3,526,742
 3,214,984
Property, Plant and Equipment of Discontinued Operations, Net (Note 2)—
 936,671
—
 2,171,464
Total Property, Plant and Equipment—Net8,140,439
 9,669,377
5,789,753
 8,140,439
Other Assets:      
Deferred Income Taxes (Note 6)4,290
 —
Investment in Affiliates190,964
 237,330
197,921
 190,964
Other222,149
 214,388
91,735
 95,515
Other Assets of Discontinued Operations (Note 2)—
 4,044
—
 126,634
Total Other Assets417,403
 455,762
289,656
 413,113
TOTAL ASSETS$9,183,981
 $10,929,902
$6,931,913
 $9,179,691






















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


10477


CONSOL ENERGY INC.CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except per share data)
December 31,
2016		 December 31,
2015		December 31,
2017		 December 31,
2016
LIABILITIES AND EQUITY      
Current Liabilities:      
Accounts Payable$241,616
 $250,609
$211,161
 $157,102
Current Portion of Long-Term Debt (Note 12 and Note 13)12,000
 9,409
Short-Term Notes Payable (Note 10)—
 952,000
Other Accrued Liabilities (Note 11)680,348
 421,827
Current Portion of Long-Term Debt (Note 10 and Note 11)7,111
 7,924
Other Accrued Liabilities (Note 9)223,407
 389,641
Current Liabilities of Discontinued Operations (Note 2)6,050
 51,514
—
 385,347
Total Current Liabilities940,014
 1,685,359
441,679
 940,014
Long-Term Debt:      
Long-Term Debt (Note 12)2,722,995
 2,703,899
Capital Lease Obligations (Note 13)39,074
 34,884
Long-Term Debt (Note 10)2,187,026
 2,421,168
Capital Lease Obligations (Note 11)20,347
 27,262
Long-Term Debt of Discontinued Operations (Note 2)—
 5,001
—
 313,639
Total Long-Term Debt2,762,069
 2,743,784
2,207,373
 2,762,069
Deferred Credits and Other Liabilities:      
Deferred Income Taxes (Note 6)—
 74,629
Postretirement Benefits Other Than Pensions (Note 14)659,474
 630,892
Pneumoconiosis Benefits (Note 15)108,073
 111,903
Mine Closing (Note 7)218,631
 227,339
Gas Well Closing (Note 7)223,352
 163,842
Workers’ Compensation (Note 15)67,277
 69,812
Salary Retirement (Note 14)112,543
 91,596
Reclamation (Note 7)—
 25
Deferred Income Taxes (Note 5)44,373
 105,096
Asset Retirement Obligations (Note 6)198,768
 195,704
Salary Retirement (Note 12)34,748
 32,546
Other151,660
 166,957
105,073
 138,059
Deferred Credits and Other Liabilities of Discontinued Operations (Note 2)—
 107,988
—
 1,065,315
Total Deferred Credits and Other Liabilities1,541,010
 1,644,983
382,962
 1,536,720
TOTAL LIABILITIES5,243,093
 6,074,126
3,032,014
 5,238,803
Stockholders’ Equity:      
Common Stock, $0.01 Par Value; 500,000,000 Shares Authorized, 229,443,008 Issued and Outstanding at December 31, 2016; 229,054,236 Issued and Outstanding at December 31, 20152,298
 2,294
Common Stock, $0.01 Par Value; 500,000,000 Shares Authorized, 223,743,322 Issued and Outstanding at December 31, 2017; 229,443,008 Issued and Outstanding at December 31, 20162,241
 2,298
Capital in Excess of Par Value2,460,864
 2,435,497
2,450,323
 2,460,864
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding—
 —
—
 —
Retained Earnings1,727,789
 2,579,834
1,455,811
 1,727,789
Accumulated Other Comprehensive Loss(392,556) (315,598)(8,476) (392,556)
Common Stock in Treasury, at Cost—No Shares at December 31, 2016 and 2015—
 —
Total CONSOL Energy Inc. Stockholders’ Equity3,798,395
 4,702,027
Total CNX Resources Corporation Stockholders’ Equity3,899,899
 3,798,395
Noncontrolling Interest142,493
 153,749
—
 142,493
TOTAL EQUITY3,940,888
 4,855,776
3,899,899
 3,940,888
TOTAL LIABILITIES AND EQUITY$9,183,981
 $10,929,902
$6,931,913
 $9,179,691












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


10578


CONSOL ENERGY INC.CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Dollars in thousands, except per share data)
 
Common
Stock
 
Capital in
Excess
of Par
Value
 
Retained
Earnings
(Deficit)
 
Accumulated
Other
Comprehensive
Income
(Loss)
 
Common
Stock in
Treasury
 
Total
CONSOL
Energy Inc.
Stockholders’
Equity
 
Non-
Controlling
Interest
 
Total
Equity
Common
Stock
 
Capital in
Excess
of Par
Value
 
Retained
Earnings
(Deficit)
 
Accumulated
Other
Comprehensive
Income
(Loss)
 
Total
CNX Resources
Stockholders’
Equity
 
Non-
Controlling
Interest
 
Total
Equity
December 31, 2013$2,294
 $2,364,592
 $2,964,520
 $(325,117) $—
 $5,006,289
 $—
 $5,006,289
Net Income—
 —
 163,090
 —
 —
 163,090
 —
 163,090
Gas Cash Flow Hedge (Net of ($45,302) Tax)—
 —
 —
 79,028
 —
 79,028
 —
 79,028
Actuarially Determined Long-Term Liability Adjustments (Net of ($56,304) Tax)—
 —
 —
 94,989
 —
 94,989
 —
 94,989
Comprehensive Income—
 —
 163,090
 174,017
 —
 337,107
 —
 337,107
Issuance of Treasury Stock—
 —
 (15,954) —
 —
 (15,954) —
 (15,954)
Issuance of Common Stock12
 15,004
 —
 —
 —
 15,016
 —
 15,016
Tax Benefit from Stock-Based Compensation—
 2,629
 —
 —
 —
 2,629
 —
 2,629
Amortization of Stock-Based Compensation Awards—
 41,877
 —
 —
 —
 41,877
 —
 41,877
Dividends ($0.25 per share)—
 —
 (57,506) —
 —
 (57,506) —
 (57,506)
December 31, 20142,306
 2,424,102
 3,054,150
 (151,100) —
 5,329,458
 —
 5,329,458
2,306
 2,424,102
 3,054,150
 (151,100) 5,329,458
 —
 5,329,458
Net (Loss) Income—
 —
 (374,885) —
 —
 (374,885) 10,410
 (364,475)—
 —
 (374,885) —
 (374,885) 10,410
 (364,475)
Gas Cash Flow Hedge (Net of $45,054 Tax)—
 —
 —
 (78,051) —
 (78,051) —
 (78,051)—
 —
 —
 (78,051) (78,051) —
 (78,051)
Actuarially Determined Long-Term Liability Adjustments (Net of $53,252 Tax)—
 —
 —
 (86,447) —
 (86,447) —
 (86,447)—
 —
 —
 (86,447) (86,447) —
 (86,447)
Comprehensive (Loss) Income—
 —
 (374,885) (164,498) —
 (539,383) 10,410
 (528,973)—
 —
 (374,885) (164,498) (539,383) 10,410
 (528,973)
Treasury Stock Activity—
 —
 (12,181) —
 —
 (12,181) —
 (12,181)
Shares Withheld for Taxes—
 —
 (12,181) —
 (12,181) —
 (12,181)
Issuance of Common Stock10
 8,278
 —
 —
 —
 8,288
 —
 8,288
10
 8,278
 —
 —
 8,288
 —
 8,288
Retirement of Common Stock (2,213,100 shares)(22) (17,683) (53,969) —
 —
 (71,674) —
 (71,674)(22) (17,683) (53,969) —
 (71,674) —
 (71,674)
Tax Cost from Stock-Based Compensation—
 (3,706) —
 —
 —
 (3,706) —
 (3,706)—
 (3,706) —
 —
 (3,706) —
 (3,706)
Amortization of Stock-Based Compensation Awards—
 24,506
 —
 —
 —
 24,506
 —
 24,506
—
 24,506
 —
 —
 24,506
 —
 24,506
Distributions to Noncontrolling Interest—
 —
 —
 —
 —
 —
 (5,060) (5,060)—
 —
 —
 —
 —
 (5,060) (5,060)
Proceeds from Sale of MLP Interest—
 —
 —
 —
 —
 —
 148,399
 148,399
—
 —
 —
 —
 —
 148,399
 148,399
Dividends ($0.145 per share)—
 —
 (33,281) —
 —
 (33,281) —
 (33,281)—
 —
 (33,281) —
 (33,281) —
 (33,281)
December 31, 20152,294
 2,435,497
 2,579,834
 (315,598) —
 4,702,027
 153,749
 4,855,776
2,294
 2,435,497
 2,579,834
 (315,598) 4,702,027
 153,749
 4,855,776
Net (Loss) Income—
 —
 (848,102) —
 —
 (848,102) 8,954
 (839,148)—
 —
 (848,102) —
 (848,102) 8,954
 (839,148)
Gas Cash Flow Hedge (Net of $25,011 Tax)—
 —
 —
 (43,470) —
 (43,470) —
 (43,470)—
 —
 —
 (43,470) (43,470) —
 (43,470)
Actuarially Determined Long-Term Liability Adjustments (Net of $16,281 Tax)—
 —
 —
 (33,488) —
 (33,488) 262
 (33,226)—
 —
 —
 (33,488) (33,488) 262
 (33,226)
Comprehensive (Loss) Income—
 —
 (848,102) (76,958) —
 (925,060) 9,216
 (915,844)—
 —
 (848,102) (76,958) (925,060) 9,216
 (915,844)
Issuance of Common Stock4
 —
 —
 —
 —
 4
 —
 4
4
 —
 —
 —
 4
 —
 4
Treasury Stock Activity—
 —
 (1,649) —
 —
 (1,649) —
 (1,649)
Shares Withheld for Taxes—
 —
 (1,649) —
 (1,649) —
 (1,649)
Tax Cost From Stock-Based Compensation—
 (4,931) —
 —
 —
 (4,931) —
 (4,931)—
 (4,931) —
 —
 (4,931) —
 (4,931)
Amortization of Stock-Based Compensation Awards—
 30,298
 —
 —
 —
 30,298
 1,185
 31,483
—
 30,298
 —
 —
 30,298
 1,185
 31,483
Distributions to Noncontrolling Interest—
 —
 —
 —
 —
 —
 (21,657) (21,657)—
 —
 —
 —
 —
 (21,657) (21,657)
Dividends ($0.01 per share)—
 —
 (2,294) —
 —
 (2,294) —
 (2,294)—
 —
 (2,294) —
 (2,294) —
 (2,294)
December 31, 2016$2,298
 $2,460,864
 $1,727,789
 $(392,556) $—
 $3,798,395
 $142,493
 $3,940,888
$2,298
 $2,460,864
 $1,727,789
 $(392,556) $3,798,395
 $142,493
 $3,940,888
Net Income—
 —
 380,747
 —
 380,747
 —
 380,747
Actuarially Determined Long-Term Liability Adjustments (Net of ($7,365) Tax)—
 —
 —
 12,228
 12,228
 —
 12,228
Comprehensive Income—
 —
 380,747
 12,228
 392,975
 —
 392,975
Issuance of Common Stock7
 1,002
 —
 —
 1,009
 —
 1,009
Purchase and Retirement of Common Stock (6,410,900 shares)(64) (51,223) (51,922) —
 (103,209) —
 (103,209)
Distribution of CONSOL Energy, Inc—
 22,697
 (594,122) 371,852
 (199,573) (142,493) (342,066)
Shares Withheld for Taxes—
 —
 (6,681) —
 (6,681) —
 (6,681)
Amortization of Stock-Based Compensation Awards—
 16,983
 —
 —
 16,983
 —
 16,983
December 31, 2017$2,241
 $2,450,323
 $1,455,811
 $(8,476) $3,899,899
 $—
 $3,899,899


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


10679


CONSOL ENERGY INC.CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)For the Years Ended December 31,For the Years Ended December 31,
2016 2015 20142017 2016 2015
Cash Flows from Operating Activities:          
Net (Loss) Income$(839,148) $(364,475) $163,090
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided By Continuing Operating Activities:     
Net Loss from Discontinued Operations303,183
 14,209
 1,857
Net Income (Loss)$380,747
 $(848,102) $(374,885)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided By Continuing Operating Activities:     
Net (Income) Loss from Discontinued Operations(85,708) 297,157
 (275,313)
Depreciation, Depletion and Amortization598,503
 567,120
 532,643
412,036
 419,939
 371,783
Impairment of Exploration and Production Properties—
 828,905
 —
137,865
 —
 828,905
Non-Cash Other Post-Employment Benefits—
 (261,750) (45,749)
Stock-Based Compensation31,483
 24,513
 41,877
16,983
 19,316
 14,314
Gain on Sale of Assets(19,498) (74,173) (43,198)(188,063) (14,270) (61,148)
Loss on Debt Extinguishment—
 67,751
 95,267
2,129
 —
 67,751
Loss (Gain) on Commodity Derivative Instruments141,021
 (392,942) (23,193)
Net Cash Received in Settlement of Commodity Derivative Instruments245,212
 196,348
 19,025
(Gain) Loss on Commodity Derivative Instruments(206,930) 141,021
 (392,942)
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments(41,174) 245,212
 196,348
Deferred Income Taxes120,305
 (140,472) (7,319)(142,829) 75,892
 (275,541)
Return on Equity Investment22,268
 35,466
 102,174
—
 22,268
 35,466
Equity in Earnings of Affiliates(53,078) (54,897) (49,791)(49,830) (53,078) (54,897)
Changes in Operating Assets:          
Accounts and Notes Receivable(48,014) 160,370
 (89,928)(32,792) (46,434) 101,107
Inventories1,330
 5,573
 49,443
Supplies Inventories4,254
 (1,486) 933
Recoverable Income Tax76,196
 (91,313) 69,404
Prepaid Expenses84,026
 128,405
 4,788
631
 76,668
 128,402
Changes in Other Assets(98,572) 3,311
 (16,242)22,018
 (2,473) 63,656
Changes in Operating Liabilities:          
Accounts Payable(27,371) (145,875) 3,974
45,669
 (17,227) (131,825)
Accrued Interest(1,040) 26,649
 (9,868)(2,955) (1,144) 26,486
Other Operating Liabilities(20,356) (147,110) 227,467
37,712
 (48,315) (161,181)
Changes in Other Liabilities(9,724) (9,916) (161,024)(7,778) 78,140
 46,173
Other28,820
 32,667
 45,093
54,887
 15,461
 12,609
Net Cash Provided by Continuing Operating Activities
459,350
 499,677
 840,386
433,068
 267,232
 235,605
Net Cash Provided by Discontinued Operating Activities9,935
 6,172
 96,390
215,619
 197,026
 275,991
Net Cash Provided by Operating Activities469,285
 505,849
 936,776
648,687
 464,258
 511,596
Cash Flows from Investing Activities:          
Capital Expenditures(226,820) (982,934) (1,459,452)(632,846) (172,739) (840,349)
Proceeds from Noble Exchange Settlement213,295
 —
 —
—
 213,295
 —
Proceeds from Sales of Assets59,902
 110,571
 356,836
414,185
 46,989
 86,737
Net Investments in Equity Affiliates73,743
 (84,221) 95,207
Net Cash Provided by (Used in) Continuing Investing Activities
120,120
 (956,584) (1,007,409)
Net Cash Provided by (Used in) Discontinued Investing Activities367,251
 (39,633) (33,973)
Net Cash Provided by (Used in) Investing Activities487,371
 (996,217) (1,041,382)
Net Distributions from (Investments in) Equity Affiliates42,873
 73,743
 (72,288)
Net Cash (Used in) Provided by Continuing Investing Activities
(175,788) 161,288
 (825,900)
Net Cash (Used in) Provided by Discontinued Investing Activities(46,133) 326,083
 (170,317)
Net Cash (Used in) Provided by Investing Activities(221,921) 487,371
 (996,217)
Cash Flows from Financing Activities:          
(Payments on) Proceeds from Short-Term Borrowings(952,000) 952,000
 (11,736)—
 (952,000) 952,000
Payments on Miscellaneous Borrowings(8,312) (4,282) (10,286)(8,037) (7,802) (3,645)
Payments on Long-Term Notes, including Redemption Premium—
 (1,263,719) (1,819,005)(239,716) —
 (1,263,719)
Net Proceeds from Revolver - MLP16,000
 185,000
 —
Distributions to Noncontrolling Interest(21,657) (5,060) —
Proceeds from Sale of MLP Interest—
 148,359
 —
Proceeds from Spin-Off of CONSOL Energy Inc.425,000
 —
 —
Proceeds from Issuance of Long-Term Notes—
 492,760
 1,859,920
—
 —
 492,760
Tax Benefit from Stock-Based Compensation—
 208
 2,629
—
 —
 208
Dividends Paid(2,294) (33,281) (57,506)—
 (2,294) (33,281)
Proceeds from Issuance of Common Stock4
 8,288
 15,016
1,009
 4
 8,288
Purchases of Treasury Stock—
 (71,674) —
Shares Withheld for Taxes(6,681) (1,649) (12,181)
Purchases of Common Stock(103,209) —
 (71,674)
Debt Issuance and Financing Fees(482) (22,586) (24,861)(361) —
 (6,250)
Net Cash (Used in) Provided by Continuing Financing Activities
(968,741) 386,013
 (45,829)
Net Cash Used in Discontinued Financing Activities(14) (56) —
Net Cash (Used in) Provided by Financing Activities(968,755) 385,957
 (45,829)
Net Decrease in Cash and Cash Equivalents(12,099) (104,411) (150,435)
Net Cash Provided by (Used in) Continuing Financing Activities
68,005
 (963,741) 62,506
Net Cash (Used in) Provided by Discontinued Financing Activities(31,903) (6,663) 311,270
Net Cash Provided by (Used in) Financing Activities36,102
 (970,404) 373,776
Net Increase (Decrease) in Cash and Cash Equivalents462,868
 (18,775) (110,845)
Cash and Cash Equivalents at Beginning of Period72,574
 176,985
 327,420
46,299
 65,074
 175,919
Cash and Cash Equivalents at End of Period$60,475
 $72,574
 $176,985
$509,167
 $46,299
 $65,074
The accompanying notes are an integral part of these financial statements.


10780


CONSOL ENERGY INC.CNX RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)

NOTE 1—SIGNIFICANT ACCOUNTING POLICIES:

A summary of the significant accounting policies of CONSOL Energy Inc.CNX Resources Corporation and subsidiaries ("CONSOL Energy"CNX " or "the Company") is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements.
Basis of Consolidation:
The Consolidated Financial Statements include the accounts of CONSOL Energy Inc,CNX Resources Corporation, and its wholly owned and majority-owned and/or controlled subsidiaries, including certain variable interest entities that the Company is required to consolidate pursuant to the ConsolidatedConsolidation topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification. The portion of these entities that is not owned by the Company is presented as non-controlling interest. Investments in business entities in which CONSOL EnergyCNX does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation. Investments in oil and natural gas producing entities are accounted for under the proportionate consolidation method.
Discontinued Operations:
Businesses divested are classified in the Consolidated Financial Statements as either discontinued operations or held for sale when the provision of Accounting Standards Codification (ASC) Topic 205 or ASC Topic 360 are met. For businesses classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities of discontinued operations on the Consolidated Balance Sheets and to discontinued operations on the Consolidated Statements of Income and Cash Flows for all periods presented. The gains or losses associated with these divested businesses are recorded in discontinued operations on the Consolidated Statements of Income. The disclosures outside of Note 2- Discontinued Operations, for all periods presented, in the accompanying notes generally do not include the assets, liabilities, or operating results of businesses classified as discontinued operations.
Use of Estimates:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as various disclosures. Actual results could differ from those estimates. The most significant estimates included in the preparation of the consolidated financial statements are related to other postretirement benefits, coal workers' pneumoconiosis, workers' compensation, salary retirement benefits, stock-based compensation, asset retirement obligations, deferred income tax assets and liabilities, contingencies and the values of coal and natural gas, NGLs, condensate and oil (collectively "natural gas") reserves.
Cash and Cash Equivalents:
Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.
Trade Accounts Receivable:
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CONSOL EnergyCNX reserves for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. CONSOL EnergyCNX regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Reserves for uncollectable amounts were not material in the periods presented. In addition, there were no material financing receivables with a contractual maturity greater than one year at December 31, 20162017 or 2015.2016.



10881


Inventories:
Inventories are stated at the lower of cost or net realizable value. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead, depreciation, depletion, amortization, and other related costs. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Company's E&P and coal operations.
Property, Plant and Equipment:
CONSOL EnergyCNX uses the successful efforts method of accounting for natural gas producing activities. Costs of property acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are also amortized on a units-of-production method. Units-of-production amortization rates are revised at least once per year, or more frequently if events and circumstances indicate an adjustment is necessary. Such revisions are accounted for prospectively as changes in accounting estimates.

Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Costs of additional mine facilities required to maintain production after a mine reaches the production stage, generally referred to as “receding face costs,” are expensed as incurred; however, the costs of additional airshafts and new portals are capitalized. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred.

Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore or minerals before beginning the development stage of the mine.

Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which are costs incurred to make the mineral physically accessible, include costs to prepare property for shafts, driving main entries for ventilation, haulage, personnel, construction of airshafts, roof protection and other facilities.

Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. The Company employs this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once per year. Any material effect from changes in estimates is disclosed in the period the change occurs. Amortization of development cost begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine's production capacity and is not considered to shift the mine into the production phase.

Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary; however, the lease terms are generally extended automatically through the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction and are legally considered real property interests. Depletion of leased coal interests is computed using the units-of-productions method over proven and probable coal reserves. The Company also makes advance payments (advanced mining royalties) to lessors under certain lease agreements that are recoupable against future production, and it makes payments that are generally based upon a specified rate per ton or a percentage of gross realization from the sale of the coal. The Company evaluates its properties periodically for impairment issues or whenever events or circumstances indicate that the carrying amount may not be recoverable.

Gas advance royalties are similarroyalties that are paid in natureadvance for the right to use an owners land for the exploration and production of oil, NGLs and natural gas. These advance mining royalties and are evaluated periodically, or at a minimum once per year, for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Any revisions are accounted for prospectively as changes in accounting estimates.





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Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms, generally as follows:
  Years
Buildings and improvements 10 to 45
Machinery and equipment 3 to 25
Gathering and transmission30 to 40
Leasehold improvements Life of Lease

Costs to obtain coal lands are capitalized based on the cost at acquisition and are amortized using the units-of-production method over all estimated proven and probable coal reserve tons assigned and accessible to the mine. Proven and probable coal reserves are calculated on a clean coal ton equivalent, which excludes non-recoverable coal reserves and anticipated preparation plant processing refuse. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is produced. At an underground coal mine, a ton is considered produced once it reaches the surface area of the mine. Any material effect from changes in estimates is disclosed in the period the change occurs.

Costs for purchased and internally developed software are expensed until it has been determined that the software will result in probable future economic benefits and management has committed to funding the project. Thereafter, all direct costs of materials and services incurred in developing or obtaining software, including certain payroll and benefit costs of employees associated with the project, are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed seven years.

Capitalization of Interest:

Interest costs associated with the development of significant properties and projects are capitalized until the project is substantially complete and ready for its intended use. A weighted average cost of borrowing rate is used. For the years ended December 31, 2016, 2015, and 2014, capitalized interest totaled $1,467, $2,509 and $13,573, respectively.

Impairment of Long-lived Assets:

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the assets' carrying value.

In February 2017, the Company approved a plan to sell its subsidiaries Knox Energy LLC and Coalfield Pipeline Company (collectively, “Knox”). Knox met all of the criteria to be classified as held for sale in February 2017. As part of the required evaluation under the held for sale guidance, during the first quarter, Knox’s book value was evaluated and it was determined that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold. The resulting impairment of $137,865 was included in Impairment of Exploration and Production Properties within the the Consolidated Statements of Income during the year ended December 31, 2017. The sale of Knox closed in the second quarter of 2017 (See Note 3 - Acquisitions and Dispositions for more information). The disposal of Knox did not represent a strategic shift that would have had a major effect on the Company’s operations and financial results and was, therefore, not classified as a discontinued operation in accordance with Topic 205, Presentation of Financial Statements, and Topic 360, Property, Plant and Equipment.





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Impairment of Proved PropertiesProperties:

CONSOL EnergyCNX performs a quantitative annual impairment test, during the fourth quarter of each year,whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. During interim periods, management updates these annual tests whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. Impairment tests require that the Company first compare future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using a market-specific weighted average cost of capital. 

During the year ended December 31, 2015, certain of the Company’s proved properties, primarily shallow oil and gas assets, failed the undiscounted cash flow portion of the test. After performing the discounted cash flow portion of the test, CONSOL EnergyCNX recorded an impairment of $824,742, included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. Valuation of the impaired assets is a Level 3 measurement as it incorporates significant unobservable inputs, such as future production levels and operating costs, within the discounted cash flow analysis. The impairment related to approximately 95% of the Company’s shallow oil and gas assets in West Virginia and Pennsylvania.

There were no other additional impairments related to proved properties in the year ended December 31, 2015. There were no such impairments for the years ended December 31, 2017, 2016 or 2014.





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2015.
Impairment of Unproved PropertiesProperties:

CONSOL EnergyCNX evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis. Indicators of potential impairment include potential shifts in business strategy, overall economic factors and historical experience. If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period the determination is made. For the year ended December 31, 2015, unproved property impairments relating to the determination that the properties will not yield proved reserves were $4,163 and are included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. Valuation of the impaired assets is a Level 3 measurement as it incorporates significant unobservable inputs, such as future production levels and operating costs, within the discounted cash flow analysis. This impairment primarily related to the court ruling in June 2015 in the state of New York that officially bans hydraulic fracturing.

There were no other additional impairments related to unproved properties in the year ended December 31, 2015. There were no such impairments for the years ended December 31, 2016 and 2014.

Exploration expense, which is associated primarily with lease expirations, was $14,519, $10,120$48,074, $14,522 and $23,355$10,119 for the years ended December 31, 2017, 2016 2015 and 2014,2015, respectively, and is included in Exploration and Production Related Other Costs in the Consolidated Statements of Income.

There were no other impairments related to unproved properties in the years ended December 31, 2017, 2016 or 2015.
Income Taxes:
Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in CONSOL Energy'sthe Company's financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of CONSOL Energy'sthe Company's assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized.
CONSOL EnergyCNX evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that do not meet the more likely than not to be sustained criteria, the Company determines, on a cumulative probability basis, the largest amount of benefit that is more likely than not to be realized upon ultimate settlement. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that the Company believes are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution of identified matters.
Postretirement Benefits Other Than Pensions:
Postretirement benefit obligations established by the Coal Industry Retiree Health Benefit Act of 1992 (the Coal Act) are treated as a multi-employer plan which requires expense to be recorded for the associated obligations as payments are made. Postretirement benefits other than pensions, except for those established pursuant to the Coal Act, are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the FASB Accounting Standards Codification, which requires employers to accrue the cost of such retirement benefits for the employees' active service periods. Such liabilities are determined on an actuarial basis and CONSOL Energy is primarily self-insured for these benefits. Differences between actual and expected results or changes in the value of obligations are recognized through Other Comprehensive Income.
Pneumoconiosis Benefits and Workers' Compensation:
CONSOL Energy is required by federal and state statutes to provide benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers' pneumoconiosis. CONSOL Energy is also required by various state statutes to provide workers' compensation benefits for employees who sustain employment-related physical injuries or some types of occupational disease. Workers' compensation benefits include compensation for their disability, medical costs, and on some occasions, the cost of rehabilitation. CONSOL Energy is primarily self-insured for these benefits. Provisions for estimated benefits are determined on an actuarial basis.




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Gas Well Closing and Mine Closing Costs:Asset Retirement Obligations:

CONSOL EnergyCNX accrues for dismantling and removing costs of gas-related facilities mine closing costs, perpetual water care costs, and related surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Accrued costs of dismantling and removing natural gas-related facilities, mine closing costs (including surface reclamation costs) and perpetual care costsEstimates are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Amortization of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Deprecation, Depletion and Amortization on the Consolidated Statements of Income. Asset retirement obligations primarily relate to the closure of natural gas wells and coal mines, which includes treatment of water and the reclamation of land upon exhaustion of coal and natural gas reserves.
Subsidence:
Subsidence occurs when there is sinking or shifting of the ground surface due to the removal of underlying coal. Areas affected may include, although are not limited to, streams, property, roads, pipelines and other land and surface structures. Total estimated subsidence claims are recognized in the period when the related coal has been extracted and are included in Operating and Other Costs on the Consolidated Statements of Income and Other Accrued Liabilities on the Consolidated Balance Sheets. On occasion, CONSOL Energy prepays the estimated damages prior to undermining the property, in return for a release of liability. Prepayments are included as assets and either recognized as Prepaid Expenses or in Other Assets on the Consolidated Balance Sheets if the payment is made less than or greater than one year, respectively, prior to undermining the property.
Retirement Plans:Plan:
CONSOL EnergyCNX has a non-contributory defined benefit retirement plans. Effective December 31, 2015, CONSOL's qualified defined benefit retirement plans have been frozen.plan. The benefits for these plansthis plan are based primarily on years of service and employees' pay. These plans areThis plan is accounted for using the guidance outlined in the Compensation - Retirement Benefits Topic of the FASB Accounting Standards Codification. The cost of these retiree benefits are recognized over the employees' service periods. CONSOL EnergyCNX uses actuarial methods and assumptions in the valuation of defined benefit obligations and the determination of expense. Differences between actual and expected results or changes in the value of obligations and plan assets are recognized through Other Comprehensive Income.
Investment Plan:
CNX has an investment plan that is available to most employees. Throughout the years ended December 31, 2017 and 2016, the Company's matching contribution was 6% of eligible compensation contributed by eligible employees. In 2015, the Company contributed an additional 3% of eligible compensation into the 401(k) plan accounts for employees hired or rehired on or after October 1, 2014 or who were under age 40 or had less than 10 years of service with the Company as of September 30, 2014. This additional contribution was eliminated on January 1, 2016. The Company may also make discretionary contributions to the Plan ranging from 1% to 6% (1% to 4% prior to January 1, 2016) of eligible compensation for eligible employees (as defined by the Plan). Discretionary contributions made by the Company were $2,761 for the year ended December 31, 2016. There were no such discretionary contributions made by the Company for the years ended December 31, 2017 and 2015. Total payments and costs were $2,866, $5,858 and $6,329 for the years ended December 31, 2017, 2016 and 2015, respectively, including the discretionary contribution mentioned above.
Revenue Recognition:
Revenues are recognized when title passes to the customers. For natural gas, NGL and oil sales, this occurs at the contractual point of delivery. For domestic coal sales, this generally occurs when coal is loaded at the mine, the preparation facility, or offsite storage locations. For export coal sales, this generally occurs when coal is loaded onto marine vessels at terminal locations. For terminal, land and research and development, revenue is recognized generally as the service is provided to the customer.
CONSOL Energy has operational natural gas-balancing agreements. These imbalance agreements are managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken by the purchaser.
CONSOL EnergyCNX sells natural gas to accommodate the delivery points of its customers. In general, this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty. These transactions qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are, therefore, recorded net within the Consolidated Statements of Income in the Purchased Gas Sales line.
CONSOL EnergyCNX purchases natural gas produced by third-parties at market prices less a fee. The gas purchased from third-parties is then resold to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as Purchased Gas Sales and Purchase Gas Costs, respectively, in the Consolidated Statements of Income. Purchased gas sales are recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CONSOL EnergyCNX from the third-party.





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Freight Revenue and Expense:

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

Contingencies:

From time to time, CONSOL Energy,CNX, or its subsidiaries, isare subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and management's intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third-parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.


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Stock-Based Compensation:
Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. CONSOL EnergyCNX recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award's vesting term. See Note 17–13–Stock-Based Compensation for more information.
Earnings per Share:
Basic earnings per share are computed by dividing net income attributable to CONSOL Energy ShareholdersCNX shareholders by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similarly to basic earnings per share, except that the weighted average shares outstanding are increased to include additional shares from stock options, performance stock options, restricted stock units and performance share units, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options and performance share options were exercised, that outstanding restricted stock units and performance share units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. CONSOL Energy includes the impact of pro forma deferred tax assets in determining potential windfalls and shortfalls for purposes of calculating assumed proceeds under the treasury stock method.
The table below sets forth the share-based awards that have been excluded from the computation of the diluted earnings per share because their effect would be anti-dilutive:
 For the Years Ended
 December 31,
 2016 2015 2014
Anti-Dilutive Options6,208,813
 3,621,002
 358,731
Anti-Dilutive Restricted Stock Units663,003
 1,375,659
 —
Anti-Dilutive Performance Share Units2,400,326
 113,531
 —
Anti-Dilutive Performance Share Options802,804
 802,804
 —
 10,074,946
 5,912,996
 358,731








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 For the Years Ended
 December 31,
 2017 2016 2015
Anti-Dilutive Options2,773,423
 6,208,813
 3,621,002
Anti-Dilutive Restricted Stock Units18,598
 663,003
 1,375,659
Anti-Dilutive Performance Share Units—
 2,400,326
 113,531
Anti-Dilutive Performance Share Options927,268
 802,804
 802,804
 3,719,289
 10,074,946
 5,912,996
The computations for basic and dilutive earnings per share are as follows:
For the Years EndedFor the Years Ended
December 31,December 31,
2016 2015 20142017 2016 2015
Numerator:          
(Loss) Income from Continuing Operations$(535,965) $(350,266) $164,947
Less: Net Income Attributable to Noncontrolling Interest8,954
 10,410
 —
Net (Loss) Income from Continuing Operations attributable to CONSOL Energy Shareholders$(544,919) $(360,676) $164,947
Income (Loss) from Continuing Operations$295,039
 $(550,945) $(650,198)
Income (Loss) from Discontinued Operations85,708
 (297,157) 275,313
Net Income (Loss)$380,747
 $(848,102) $(374,885)
          
Loss from Discontinued Operations$(303,183) $(14,209) $(1,857)
     
Net (Loss) Income Attributable to CONSOL Energy Shareholders$(848,102) $(374,885) $163,090
Denominator:          
Weighted-average shares of common stock outstanding229,387,403
 229,186,125
 229,994,407
228,835,112
 229,387,403
 229,186,125
Effect of dilutive shares—
 —
 1,585,871
2,116,700
 —
 —
Weighted-average diluted shares of common stock outstanding229,387,403
 229,186,125
 231,580,278
230,951,812
 229,387,403
 229,186,125
(Loss) Earnings Per Share:     
Earnings (Loss) Per Share:     
Basic (Continuing Operations)$(2.38) $(1.57) $0.72
$1.29
 $(2.40) $(2.84)
Basic (Discontinued Operations)(1.32) (0.07) (0.01)0.37
 (1.30) 1.20
Total Basic$(3.70) $(1.64) $0.71
$1.66
 $(3.70) $(1.64)
          
Dilutive (Continuing Operations)$(2.38) $(1.57) $0.71
$1.28
 $(2.40) $(2.84)
Dilutive (Discontinued Operations)(1.32) (0.07) (0.01)0.37
 (1.30) 1.20
Total Dilutive$(3.70) $(1.64) $0.70
$1.65
 $(3.70) $(1.64)




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Shares of common stock outstanding were as follows:
2016 2015 20142017 2016 2015
Balance, Beginning of Year229,054,236
 230,265,463
 229,145,736
229,443,008
��229,054,236
 230,265,463
Issuance Related to Stock-Based Compensation (1)388,772
 1,001,873
 1,119,727
711,214
 388,772
 1,001,873
Retirement of Common Stock (2)—
 (2,213,100) —
(6,410,900) —
 (2,213,100)
Balance, End of Year229,443,008
 229,054,236
 230,265,463
223,743,322
 229,443,008
 229,054,236

(1) See Note 17–13 - Stock-Based Compensation for additional information.
(2) See Note 5–4 - Stock Repurchase for additional information.

Other Comprehensive Loss:

Changes in Accumulated Other Comprehensive Loss by component, net of tax, were as follows:
 Gains on Cash Flow Hedges Postretirement Benefits Total
Balance at December 31, 2015$43,470  $(359,068) $(315,598)
Other Comprehensive Loss before Reclassifications—  (61,730) (61,730)
Amounts Reclassified from Accumulated Other Comprehensive Loss(43,470) 28,504  (14,966)
Current Period Other Comprehensive Loss(43,470) (33,226) (76,696)
Less: Other Comprehensive Income Attributable to Non-Controlling Interest—  262  262 
Balance at December 31, 2016$—  $(392,556) $(392,556)



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Balance at December 31, 2016$(392,556)
Other Comprehensive Loss before Reclassifications(541)
Amounts Reclassified from Accumulated Other Comprehensive Loss12,769 
Distribution of CONSOL Energy, Inc.371,852 
Balance at December 31, 2017$(8,476)

The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:
For the Years Ended December 31,For the Years Ended December 31,
2016 2015 20142017 2016 2015
Derivative Instruments (Note 21)     
Derivative Instruments (Note 17)     
Natural Gas Price Swaps and Options$(68,481) $(123,105) $(28,753)$—  $(68,481) $(123,105)
Tax Expense25,011  45,054  10,465 —  25,011  45,054 
Net of Tax$(43,470) $(78,051) $(18,288)$—  $(43,470) $(78,051)
Actuarially Determined Long-Term Liability Adjustments* (Note 14 and Note 15)     
Actuarially Determined Long-Term Liability Adjustments* (Note 12)     
Amortization of Prior Service Costs$(590) $(336,993) $(22,381)$(2,775) $(590) $(336,993)
Recognized Net Actuarial Loss23,857  119,222  46,155 23,043  23,857  119,222 
Curtailment Loss (Gain)—  5  (36,182)
Curtailment Loss—  —  5 
Settlement Loss22,196  19,053  29,095 —  22,196  19,053 
Total45,463  (198,713) 16,687 20,268  45,463  (198,713)
Tax (Benefit) Expense(16,959) 74,687  (6,139)(7,499) (16,959) 74,687 
Net of Tax$28,504  $(124,026) $10,548 $12,769  $28,504  $(124,026)
 
*Excludes amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the years ended December 31, 2016 December 31, 2015 and December 31, 2014.2015. The table above only shows the reclassifications out of Accumulated Other Comprehensive Loss that relate to continuing operations.

Accounting for Derivative Instruments:

CONSOL EnergyCNX enters into financial derivative instruments to manage its exposure to commodity price volatility. The derivatives are accounted for as an asset or a liability in the accompanying Consolidated Balance Sheets at their fair value using “Level Two”Level 2 inputs, which is further defined in Note 2016 - Fair Value of Financial Instruments. Changes in the fair values of derivatives are recorded in earnings unless special hedge accounting criteria are met. For derivatives designated as cash flow hedges, the effective portions of changes in the fair values of the derivatives are reported in Other Comprehensive Income or Loss (OCI) on the Consolidated Balance Sheets, net of tax, and reclassified into Gain (Loss) on Commodity Derivative Instruments on the Consolidated Statements of Income in the same period or periods in which the forecasted transactions affect earnings. Any ineffective portion of a hedge is recognized in earnings in the current period.     
CONSOL EnergyCNX de-designated all of its cash flow hedges on December 31, 2014 and accounts for all existing and future natural gas and NGL commodity hedges on a mark-to-market basis, and records changes in fair value in current period earnings. In connection with this de-designation, CONSOL EnergyCNX froze the balances recorded in Accumulated Other Comprehensive Income at December 31, 2014


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and reclassified balances to earnings as the underlying physical transactions occurred. As of December 31, 2016, all gains that had been previously deferred in OCI have beenwere recognized in earnings.
All of CONSOL Energy’sthe Company's derivative instruments are subject to master netting arrangements with its counterparties, none of which currently require CONSOL EnergyCNX to post collateral for any of its hedges. However, as stated in the counterparty master agreements, if CONSOL Energy'sthe Company's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CONSOL EnergyCNX would be required to post collateral for hedges that are in a liability position in excess of defined thresholds. Each of CONSOL Energy'sthe Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CONSOL EnergyCNX and the applicable counterparty would net settle all open hedge positions.
CONSOL EnergyCNX is exposed to credit risk in the event of non-performance by counterparties, whose creditworthiness is subject to continuing review. Historically, CONSOL EnergyCNX has not experienced any issues of non-performance by derivative counterparties.
Recent Accounting Pronouncements:

In JanuaryMay 2017, the FASB issued Update 2017-012017-09 - Business CombinationsCompensation - Stock Compensation (Topic 805). This update clarifies718): Scope of Modification Accounting, which reduces diversity in practice and cost and complexity when applying the definitionguidance in this Topic to a change to the terms or conditions of a business withshare-based payment award. The amendments in this Update provide guidance about which changes to the objectiveterms or conditions of adding guidancea share-based payment award require an entity to assist entities with evaluating whether transactionsapply modification accounting in Topic 718. The amendments in the Update are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and should be accounted forapplied prospectively to an award modification on or after the adoption date. Early adoption is permitted. The adoption of this guidance is not expected to have a material impact on the Company's financial statements.
In March 2017, the FASB issued Update 2017-07 - Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which improves the presentation of net periodic pension cost and net periodic postretirement benefit cost. The amendments in the Update require that an employer report the service cost component in the same line item as acquisitions (or disposals)other compensation costs arising from services rendered by the pertinent employees during the period. The other components of assets or businesses.net benefit cost are required to be presented separately from the service cost component and outside a subtotal of income from operations, if one is presented. Because CNX does not present an income from operations subtotal, that requirement is not applicable. Additionally, the Company's service cost component is deemed immaterial, and therefore, the other components of net benefit cost will not be presented separately. For public business entities, the amendments in thisthe Update are effective for


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fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted as of the beginning of a fiscal year for which financial statements have not been issued. The adoption of this new guidance is not expected to have a materialan impact on CONSOL Energy's financial statements.
In December 2016, the FASB issued Update 2016-19 - Technical Corrections and Improvements, which covers a wide range of Topics in the Accounting Standards Codification (ASC). The amendments in this Update represent changes to clarify, correct errors, or make minor improvements to the ASC, making it easier to understand and apply by eliminating inconsistencies and providing clarifications. The amendments generally fall into one of the following categories: amendments related to differences between original guidance and the ASC, guidance clarification and reference corrections, simplification, or minor improvements. Most of the amendments in this Update do not require transition guidance and are effective upon issuance of this Update.
In October 2016, the FASB issued Update 2016-17 - Consolidation (Topic 810): Interests Held through Related Parties that are Under Common Control, which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The Update requires the reporting entity, in determining whether it satisfies the second characteristic of a primary beneficiary, to include its indirect economic interests in a VIE held through related parties that are under common control on a proportionate basis as opposed to in their entirety. The amendments in this Update will be applied retrospectively and are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The adoption of this new guidance is not expected to have a material impact on CONSOL Energy'sCompany's financial statements.
In August 2016, the FASB issued Update 2016-15 - Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The amendments relate to debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, and beneficial interests in securitization transactions. The Update also states that, in the absence of specific guidance for cash receipts and payments that have aspects of more than one class of cash flows, an entity should classify each separately identifiable source or use within the cash receipts and payments on the basis of their nature in financing, investing, or operating activities. In situations in which cash receipts or payments cannot be separated by source or use, the appropriate classification should depend on the activity that is likely to be the predominant source or use of cash flows for the item. The amendments in the Update will be applied using a retrospective transition method to each period presented and, for public entities, are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Earlyyears.The adoption is permitted, including adoption in an interim period. The Company is currently evaluating the impactof this guidance mayis not expected to have an impact on CONSOL Energy'sthe Company's financial statements.
In June 2016, the FASB issued Update 2016-13 - Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this, the amendments in this Update replace the incurred loss impairment methodology in current Generally Accepted Accounting Principals (GAAP) with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. The amendments in this Update will be applied using a modified-retrospective approach and, for public entities, are effective for fiscal years beginning after December 15, 2019 and interim periods within those annual periods. Early adoption is permitted for fiscal years beginning after December 15, 2018 and interim periods within those annual periods. The Company believes this guidance will not have a material impact on CONSOL Energy's financial statements.
In May 2014, the FASB issued Update 2014-09, - Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605 - Revenue Recognition and most industry-specific guidance throughout the Industry Topics of the Codification.Customers. The objective of the amendments in this Update is to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and International Financial Reporting Standards (IFRS). The core principle of the guidance is thatstandard requires an entity shouldto recognize revenue to depictin a manner that depicts the transfer of promised goods or services to customers inat an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or servicesservices.  In August 2015, the FASB issued ASU No. 2015-14 Revenue from Contracts with Customers - Deferral of the Effective Date which approved a one year deferral of ASU No. 2014-09 for annual reporting periods beginning after December 15, 2017. During the fourth quarter of 2017, the Company substantially completed its detailed review of the impact of the standard on each of its contracts. The Company adopted the ASUs using the modified retrospective method of adoption on January 1, 2018 and should disclose sufficient information, both qualitativedid not require an adjustment to the opening balance of equity. The Company does not expect the standard to have a significant impact on its results of operations, liquidity or


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financial position in 2018. The Company implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and quantitative,generate the disclosures required under the new standard. Additional disclosures will be required to enable users of financial statements to understanddescribe the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The following updates to Topic 606 were made during 2016:


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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 naturecustomers including disaggregation 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 Obligationsrevenue and Licensing, which seeks to address implementation issues in the areas of identifyingremaining performance obligations, and licensing.
In May 2016,beginning with our Form 10-Q for 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.

The new standards are effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. Management continues to evaluate the impacts that these standards will have on CONSOL Energy's financial statements, specifically as it relates to contracts that contain positive electric power price related adjustments. CONSOL Energy anticipates using the modified retrospective approach at adoption as it relates to ASU 2014-09.

Inthree months ended March 2016, the FASB issued Update 2016-09 - Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Specifically, this Update states that: all excess tax benefits and tax deficiencies should be recognized as income tax expense or benefit in the income statement; excess tax benefits should be classified along with other income tax cash flows as an operating activity; an entity can make an accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur; the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity. For public entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted. The adoption of this new guidance is not expected to have a material impact on CONSOL Energy's financial statements.31, 2018.

In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842), which increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Update 2016-02 does retain a distinction between finance leases and operating leases, which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease to not significantly change from previous GAAP. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities, but to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the right-to-use asset and lease liability will be initially measured at the present value of the lease payments in the statement of financial position.The accounting applied by a lessor is largely unchanged from that applied under previous GAAP. For public business entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The CompanyCNX is currently reviewing all existing leases and agreements that are covered by this standard and is evaluating the impact this guidance may have on CONSOL Energy'sthe financial statements.statements and related disclosures.
Reclassifications:
DuringCertain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2016, CONSOL Energy made reclassifications within its financial statements to better align the Company's financial reporting with its peer group. These reclassifications impacted the Lease Operating Expense, Transportation, Gathering and Compression, Direct Administrative and Selling, Production Royalty Interests and Purchased Gas Sales, Production Royalty Interests and Purchased Gas Costs, Operating and Other Costs and Selling, General and Administrative Costs line items on the Company's Consolidated Statements of Income. These changes are reflected in CONSOL Energy's current and historic Consolidated Statements of Income,2017, with no effect on previously reported net income (loss).






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or stockholder's equity.

Subsequent Events:

The Company has evaluated all subsequent events through the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.identified other than those disclosed in Note 21 - Subsequent Event.

NOTE 2—DISCONTINUED OPERATIONS:
On November 28, 2017, CNX announced that it had completed the tax-free spin-off of its coal business resulting in two independent, publicly traded companies, a coal company, CONSOL Energy, formerly known as CONSOL Mining Corporation and CNX, a natural gas exploration and production company. Following the Separation, CONSOL Energy and its subsidiaries 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. As of the close of business on November 15, 2017, CNX's shareholders received one share of CONSOL Energy common stock for every eight shares of CNX’s common stock held as of the Record Date. The coal company has been reclassified to discontinued operations for all periods presented.

In August 2016, CONSOL EnergyCNX completed the sale of itsthe Miller Creek Mining Complex and Fola Mining Complex subsidiaries.Complexes. In the transaction, the buyer acquired the Miller Creek and Fola assets and assumed the Miller Creek and Fola mine closing and reclamation liabilities; inliabilities. In order to equalize the value exchange, CONSOL EnergyCNX paid $28,271 of cash at closing, which included property taxes associated with the properties sold and other closing costs (a portion of which will be held in escrow for purposes of obtaining the surety bonds required for the the permits to transfer). These amounts wereThis amount was included in Net Cash Provided by Discontinued Investing Activities on the Consolidated Statements of Cash Flow. In addition, CONSOL EnergyFlows for the year ended December 31, 2016. CNX will also pay a total of $17,200$13,700 in remaining installments over the next four years.three years, ending in January 2020. The net loss on the sale of $53,130, excluding the related impairment charge discussed below, was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income. Prior to the closing, the Miller Creek and Fola Mining Complexes were classified as held for sale in discontinued operations and in accordance with the accounting guidance for Property, Plant and Equipment, assets held for sale are required to be measured at the lower of the carrying value or fair value less costs to sell. Upon meeting the assets held for sale criteria, the Company determined the carrying value of the Miller Creek and Fola Mining Complexes exceeded the fair value less costs to sell. As a result, an impairment charge of $355,681 was recorded during the year ended December 31, 2016. This impairment iswas included in the Loss from Discontinued Operations, net on the Consolidated Statements of Income.

In March 2016, CONSOL EnergyCNX 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


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Complex located in Amonate, Virginia; Russell County, Virginia coal reserves and Pangburn Shaner Fallowfield coal reserves located in Southwestern, Pennsylvania to Coronado IV LLC ("Coronado"). Various CONSOL EnergyCNX assets were excluded from the sale including coalbed methane, natural gas and minerals other than coal, current assets of BMC, certain coal seams and certain surface rights and the Amonate Preparation Plant.properties. Coronado assumed only specified liabilities and various CONSOL EnergyCNX liabilities were excluded and not assumed. The excluded liabilities included BMC’s indebtedness, trade payables and liabilities arising prior to closing, as well as the liabilities of the subsidiaries other than BMC which arewere parties to the sale. In addition, the buyer agreed to pay CONSOL EnergyCNX for Buchanan Mine coal sold outside the U.S. and Canada during the five years following closing a royalty of 20% of any excess of the gross sales price per ton over the following amounts: (1) year one, $75.00 per ton; (2) year two, $78.75 per ton; (3) year three, $82.69 per ton; (4) year four, $86.82 per ton; (5) year five, $91.16 per ton. At closing,Total royalty income recognized under this agreement was $10,073 and $9,575 for the parties entered into several agreements including, among others, agreements relatingyears ended December 31, 2017 and 2016, respectively. In connection with the separation and distribution agreement with CONSOL Energy (See Note 20 - Related Party) the royalty related to Buchanan Mine was retained by CNX and any related income is included in Other Expense on the coordination and conductConsolidated Statements of gas operations at the mines, an option to purchase the Amonate Preparation Plant and transition services.Income. Cash proceeds of $402,799 were received at closing and are included in Net Cash Provided by Discontinued Investing Activities on the Consolidated Statements of Cash Flow.Flows for the year ended December 31, 2016. The net loss on the sale was $38,364 and was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income.Income for the year ended December 31, 2016.

For all periods presented in the accompanying Consolidated Statements of Income, BMC along with the various other assets and the Miller Creek and Fola Mining Complexes are classified as discontinued operations.

The following table details selected financial information for the divested business included within discontinued operations:
For the Years Ended December 31,For the Years Ended December 31,
2016 2015 20142017 2016 2015
Coal Sales$102,904
 $367,234
 $426,263
$1,127,907
 $1,199,950
 $1,687,237
Freight-Outside Coal1,322
 5,098
 5,015
66,297
 47,790
 25,597
Miscellaneous Other Income740
 51
 2,635
73,645
 74,382
 67,969
(Loss) Gain on Sale of Assets(91,785) 336
 (6,640)
Gain on Sale of Assets—
 269,124
 13,362
Total Revenue and Other Income$13,181
 $372,719
 $427,273
$1,267,849
 $1,591,246
 $1,794,165
Total Costs134,248
 395,913
 431,344
1,147,254
 1,652,921
 1,362,508
Loss From Operations Before Income Taxes$(121,067) $(23,194) $(4,071)
Income (Loss) From Operations Before Income Taxes$120,595
 $(61,675) $431,657
Impairment on Assets Held for Sale355,681
 —
 —
—
 355,681
 —
Income Tax Benefit(173,565) (8,985) (2,214)
Loss From Discontinued Operations, net$(303,183) $(14,209) $(1,857)
Income Tax Expense (Benefit)23,984
 (129,153) 145,934
Less: Net Income Attributable to Noncontrolling interest10,903
 8,954
 10,410
Income (Loss) From Discontinued Operations, net$85,708
 $(297,157) $275,313

























11889




The major classes of assets and liabilities of discontinued operations:
December 31,
2016		 December 31,
2015		December 31,
2016
Assets:    
Cash and Cash Equivalents$14,176
Accounts Receivable - Trade$83
 $49,125
95,790
Other Receivables18,756
Inventories—
 30,646
50,160
Prepaid Expense—
 970
17,571
Other Current Assets—
 364
2,370
Total Current Assets$83
 $81,105
$198,823
Property, Plant and Equipment, Net—
 936,671
2,171,464
Other Assets—
 4,044
126,634
Total Assets of Discontinued Operations$83
 $1,021,820
$2,496,921
Liabilities:    
Accounts Payable$36
 $20,786
$84,550
Other Current Liabilities6,014
 30,728
300,797
Total Current Liabilities$6,050
 $51,514
$385,347
Long Term Debt—
 5,001
313,639
Postretirement Benefits Other Than Pensions659,474
Pneumoconiosis Benefits—
 1,129
108,073
Mine Closing—
 71,941
218,631
Reclamation—
 34,126
Gas Well Closing27,648
Workers' Compensation65,932
Salary Retirement79,997
Other liabilities—
 792
(94,440)
Total Liabilities of Discontinued Operations$6,050
 $164,503
$1,764,301

NOTE 3—ACQUISITIONS AND DISPOSITIONS:
In September 2017, CNX closed on the sale of approximately 22,000 acres of surface land in Colorado. CNX received net cash proceeds of $23,703 which is included in the cash flows from investing activities. The net gain on the sale was $18,758 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.    

In a two part closing in July and September 2017, CNX executed the sale of approximately 7,500 net undeveloped acres of the Marcellus Shale in Allegheny and Westmoreland counties, Pennsylvania. CNX received total cash proceeds of $36,649 which is included in the cash flows from investing activities. The net gain on the sale of these assets was $15,251 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.

In June 2017, CNX closed on the sale of approximately 11,100 net undeveloped acres of the Marcellus and Utica Shale in Allegheny, Washington, and Westmoreland counties, Pennsylvania. CNX received total cash proceeds of $83,500 which is included in cash flows from investing activities. The net gain on the sale of these assets was $58,541 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.     

In June 2017, the Company finalized the sale of 12 producing wells, 15 drilled but uncompleted wells (DUCs), and approximately 11,000 net developed and undeveloped Marcellus and Utica acres in Doddridge and Wetzel counties in West Virginia that were previously classified as held for sale. CNX received total cash proceeds of $125,507 which is included in cash flows from investing activities, as well as undeveloped acreage. The net loss on the sale was $9,430 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.
In May 2017, CNX finalized the sale of approximately 6,300 net undeveloped acres of the Utica-Point Pleasant Shale in Jefferson, Belmont and Guernsey counties, Ohio that were previously classified as held for sale. CNX received total cash proceeds of $76,585 which is included in cash flows from investing activities. The net gain on the sale of these assets was $72,346 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.


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In April 2017, CNX finalized the sale of its Knox Energy LLC and Coalfield Pipeline Company subsidiaries that were previously classified as held for sale. At closing, CNX received net cash proceeds of $19,055 which is included in cash flows from investing activities. The net gain on the sale of these assets was $606 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income. In February 2017, Knox met all of the criteria to be classified as held for sale. As part of the required evaluation under the held for sale guidance, during the first quarter, Knox’s book value was evaluated and it was determined that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold. The resulting impairment of $137,865 was included in Impairment of Exploration and Production Properties within the the Consolidated Statements of Income during the year ended December 31, 2017.

In September 2015, CONSOL EnergyCNX sold its 49% interest in Western Allegheny Energy (WAE), a joint venture with Rosebud Mining Company engaged in coal mining activities in Pennsylvania. At closing, CONSOL Energythe Company received $76,297 in cash and a $2,136 reduction in certain liabilities. During the third quarter of 2015, CONSOL EnergyCNX also received a cash distribution of $10,780 from WAE. The net gain on the sale was $48,468 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.

In December 2014, CNX Gas Company LLC (CNX Gas Company), wholly-owned subsidiary of CONSOL Energy, finalized an agreement with Columbia Energy Ventures (CEVCO) to sublease from CEVCO approximately 20,000 acres of Utica Shale and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West Virginia. Up-front bonus consideration of up to $96,106 was to be paid by CONSOL Energy over a five year period, as drilling occurs, in addition to royalties. CONSOL Energy made payments of $9,000 to CEVCO in the year ended December 31, 2016, while $50,969 of payments were made in the year ended December 31, 2015. At December 31, 2016, the amounts recorded in Other Current Liabilities and Other Long-Term Liabilities both on a discounted basis were $3,947 and $26,461, respectively. At December 31, 2015, the amounts recorded in Other Current Liabilities and Other Long-Term Liabilities on a discounted basis were $8,349 and $29,333, respectively.

In December 2014, CONSOL Energy completed the sale of its industrial supplies subsidiary to an unrelated third party for expected net proceeds of approximately $51,000, of which $44,035 was received and included in cash flows from investing activities during the year ended December 31, 2014. In connection with the sale, CONSOL Energy signed a supply agreement under which, among other things, it will continue to purchase certain goods exclusively from the new entity for a period of at least three years. CONSOL Energy recorded a net loss on the sale of $30,845, which was included in Gain on Sale of Assets in the Consolidated Statements of Income. In December 2015, there was $6,258 of expense related to the settlement of working capital adjustments and other matters in conjunction with the sale, which was included in Other Costs - Miscellaneous Operating Costs in the Consolidated Statements of Income.



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NOTE 4—MISCELLANEOUS OTHER INCOME:
  For the Years Ended December 31,
  2016 2015 2014
Equity in Earnings of Affiliates - CONE $48,260
 $43,799
 $29,807
Rental Income 36,059
 37,984
 45,059
Right of Way Issuance 27,343
 13,289
 7,333
Royalty Income - Non-Operated Coal 20,083
 15,402
 19,653
Gathering Revenue 10,834
 9,530
 23,520
Coal Contract Buyout 6,288
 —
 30,000
Purchased Coal Sales 5,757
 1,596
 9,029
Equity in Earnings of Affiliates - Other 4,818
 11,098
 19,984
Interest Income 1,507
 2,299
 2,303
Other 6,357
 9,354
 20,772
     Miscellaneous Other Income $167,306

$144,351

$207,460

NOTE 5—4— STOCK REPURCHASE:

In December 2014, CONSOL Energy’sSeptember 2017, CNX's Board of Directors approved a one-year stock repurchase program under which CONSOL Energy could have purchasedof up to $250,000$200,000 that terminated on November 1, 2017. On October 30, 2017, the Board approved an increase to the aggregate amount of the repurchase plan to $450,000. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The timing of any repurchases will be based on a number of factors, including available liquidity, the Company's stock price, the Company's financial outlook, and alternative investment options. The share repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its common stock over a two year period. Under the termsauthorization of the program CONSOL Energy was permitted to make repurchases in the open market, in privately negotiated transactions, accelerated repurchase programs or in structured share repurchase programs. Any repurchases of common stock were to be funded from available cash on hand or short-term borrowings. The program did not obligate CONSOL Energy to acquire any particular amount of common stock, and could have been modified or suspended at any time attime. The Board of Directors will continue to evaluate the Company’s discretion. Thesize of the stock repurchase program was conducted in compliance with applicable legal requirementsbased on CNX's free cash flow position, leverage ratio, and within the limits imposed by any credit agreement, receivables purchase agreement or indenture and was subject to market conditions and other factors. No shares were repurchased under this program during the year ended December 31, 2016.capital plans. During the year ended December 31, 2015, 2,213,1002017, 6,410,900 shares were repurchased and retired at an average price of $32.37$16.08 per share.share for a total cost of $103,209.



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NOTE 6—5—INCOME TAXES:

Income tax expense (benefit)benefit provided on earnings from continuing operations consisted of:
For The Years Ended December 31,For The Years Ended December 31,
2016 2015 20142017 2016 2015
Current:          
U.S. Federal$(103,562) $19,726
 $18,388
$(31,791) $(101,596) $839
U.S. State(8,699) (5,657) 2,724
(1,838) (8,699) (5,657)
Non-U.S.1,966
 964
 1,411
(110,295) 15,033
 22,523
(33,629) (110,295) (4,818)
Deferred:          
U.S. Federal124,766
 (181,859) (12,581)(166,112) 80,207
 (308,797)
U.S. State(4,461) 41,387
 5,262
23,283
 (4,315) 33,256
120,305
 (140,472) (7,319)(142,829) 75,892
 (275,541)
          
Total Income Tax Expense (Benefit)$10,010
 $(125,439) $15,204
Total Income Tax Benefit$(176,458) $(34,403) $(280,359)













The components of the net deferred taxes are as follows:
 December 31,
 2016 2015
Deferred Tax Assets:   
Postretirement benefits other than pensions$260,959
 $257,604
Alternative minimum tax219,872
 143,122
Net operating loss - Federal144,450
 165,951
Net operating loss - State74,310
 76,171
Gas derivatives72,105
 —
Gas well closing68,585
 79,246
Pneumoconiosis benefits43,997
 44,830
Salary retirement42,393
 30,177
Mine closing39,860
 63,399
Foreign tax credit39,850
 39,850
Workers' compensation30,758
 31,544
Mine subsidence29,532
 44,317
Capital lease2,925
 4,404
Equity Partnerships—
 45,746
Reclamation—
 14,122
Other66,724
 65,427
Total Deferred Tax Assets1,136,320
 1,105,910
Valuation Allowance(282,778) (78,306)
Net Deferred Tax Assets853,542
 1,027,604
    
Deferred Tax Liabilities:   
Property, plant and equipment(782,710) (946,778)
Equity Partnerships(40,200) —
Advance mining royalties(22,326) (44,921)
Gas derivatives—
 (105,864)
Other(4,016) (4,670)
Total Deferred Tax Liabilities(849,252) (1,102,233)
    
Net Deferred Tax Asset (Liability)$4,290
 $(74,629)



12191


 December 31,
 2017 2016
Deferred Tax Assets:   
Alternative minimum tax188,080
 219,872
Net operating loss - State107,756
 74,310
Net operating loss - Federal99,524
 144,450
Foreign tax credit44,402
 39,850
Gas well closing16,648
 20,512
Salary retirement9,404
 16,928
Capital lease2,020
 3,210
Gas derivatives—
 72,105
Other33,697
 48,961
Total Deferred Tax Assets501,531
 640,198
Valuation Allowance(136,576) (282,778)
Net Deferred Tax Assets364,955
 357,420
    
Deferred Tax Liabilities:   
Property, plant and equipment(385,366) (450,695)
Gas derivatives(15,248) —
Advance gas royalties(3,648) (5,824)
Equity Partnerships(1,251) (2,237)
Other(3,815) (3,760)
Total Deferred Tax Liabilities(409,328) (462,516)
    
Net Deferred Tax Liability$(44,373) $(105,096)

Deferred taxes are recorded for certain tax benefits, including net operating losses and tax credit carry-forwards, provided that management assesses the utilization of those assets to be more likely than not. A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. For the years ended December 31, 20162017 and 2015,2016, positive evidence considered included financial earnings generated over the past three years for certain subsidiaries, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence included financial and tax losses generated in prior periods, the inability to achieve forecasted results for those periods and the expectation thatimpact of expected future financial results from normal operations would not be sufficient to support fullon the utilization of certain tax credits within the foreseeable future. CONSOL Energycredits. CNX continues to report, on an after federal tax basis, a deferred tax asset related to state operating losses of $74,310$107,756 with a related valuation allowance of $60,488$61,560 at December 31, 2016.2017. The deferred tax asset related to state operating losses, on an after tax adjusted basis, was $76,171$74,310 with a related valuation allowance of $42,983$60,488 at December 31, 2015.2016. A review of positive and negative evidence regarding these state tax benefits concluded that the valuation allowances for various CONSOL EnergyCNX subsidiaries was warranted. TheThese net operating losses expire at various times between 20172018 and 2036.2037. A valuation allowance on foreign tax credits of $44,402 and $39,850 and $25,903 has also been recorded at December 31, 20162017 and 2015,2016, respectively. The foreign tax credits expire at various times between 2021 and 2023. A valuation allowance on deferred equity compensation for covered individuals as provided by Section 162(m) of $5,957 was recorded for 2017. No such valuation allowance was recorded for 2016. A valuation allowance on charitable contribution carry-forwards of $3,156 and $5,051 has been recorded for 2016.2017 and 2016, respectively. The Company's charitable contributions carry-forwards expire at various times between 2018 and 2021. No such valuation allowance was recorded2022.

As of December 31, 2017, the Company has a deferred tax asset related to federal net operating losses of $99,524, which expire at various times between 2034 and 2037. In connection with the restructuring and separation of the Company's coal business in November 2017, certain net operating loss carry-forwards were required to be written off under the Tax Cuts and Jobs Act (the "Act") passed on December 22, 2017. As a result, the Company has written off the deferred tax assets associated with these net operating losses, a reduction of $24,942 to the total deferred tax asset for 2015.net operating losses.

The deferred tax assets attributable to the state tax effect of future deductible temporary differences for certain CONSOL EnergyCNX subsidiaries with histories of financial and tax losses were also reviewed for positive and negative evidence regarding the realization of the associated deferred tax assets. A valuation allowance of $10,591$9,088 and $9,420$10,591 on an after federal tax adjusted basis has also been recorded for 20162017 and 2015,2016, respectively.

During 2016,

92


As of December 31, 2017, the Company has a deferred tax asset relating to federal alternative minimum tax credits increased $76,750,of $188,080, a decrease of $31,792 from the prior year that resulted from the monetization of alternative minimum tax credits on the Company's 2016 Federal income tax return as well as estimated monetization anticipated for 2017. During 2017, the valuation allowance relating to $219,872federal alternative minimum tax credits decreased by $154,384 to $12,413 at December 31, 2016 from $143,1222017. Under the Act, passed on December 22, 2017, the corporate alternative minimum tax was repealed. The Act also provided that existing alternative minimum tax credits are refundable beginning in 2018. As a result, it is now more likely than not that the benefit of CNX's alternative minimum tax credits will be realized. Accordingly, the previously recorded valuation allowance has been released. It should be noted that the Company does have a valuation allowance of $12,413 at December 31, 2015. This increase was primarily attributable to restoring previously2017 reflecting the anticipated government sequestration of a portion of monetized alternative minimum tax credits. This restoration was created by an agreement reached withamount represents 6.6% of the IRS to accelerate certain tax depreciation deductions in exchange for forgoing previously claimedCompany's total alternative minimum tax credit monetization. At December 31, 2016, a valuation allowance of $166,798 was recorded against these alternative minimum tax credits, based on management's view that negative evidence with respect to their realizability outweighed positive evidence. There was no such valuation allowance at December 31, 2015. These credits do not expire and will be able to be fully utilized when sufficient operating income is generated by the Company.credits.

Management will continue to assess the potential for realized deferred tax assets based upon income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods, as appropriate, that could materially impact net income.
    
The following is a reconciliation, stated as a percentage of pretax income, of the United States statutory federal income tax rate to CONSOL Energy'sCNX's effective tax rate:
For the Years Ended December 31,For the Years Ended December 31,
2016 2015 20142017 2016 2015
Amount Percent Amount Percent Amount PercentAmount Percent Amount Percent Amount Percent
Statutory U.S. federal income tax rate$(187,218) 35.0 % $(166,497) 35.0 % $63,053
 35.0 %$41,503
 35.0 % $(204,872) 35.0 % $(325,695) 35.0 %
Excess tax depletion(18,960) 3.5
 (29,526) 6.2
 (42,302) (23.5)
Effect of domestic production activities—
 —
 —
 —
 (1,235) (0.7)
Federal tax accrual to tax return reconciliation(6,789) 1.3
 13,576
 (2.9) (8,331) (4.6)
Uncertain tax positions27,359
 23.1
 1,351
 (0.2) —
 —
Effect of spin on Federal NOL's24,942
 21.0
 —
 —
 —
 —
Accrual to tax return reconciliation(1,147) (1.0) (4,564) 0.8
 (6,312) 0.7
IRS and state tax examination settlements36,619
 (6.8) (36) —
 (5,248) (2.9)—
 —
 (13,463) 2.3
 (36) —
Net effect of state income taxes(25,629) 4.8
 (10,109) 2.1
 5,235
 2.9
15,538
 13.1
 (20,954) 3.6
 (15,400) 1.7
Effect of change in state valuation allowance(430) (0.4) 18,999
 (3.2) 39,492
 (4.2)
Effect of change in federal valuation allowance187,759
 (35.1) 25,903
 (5.4) —
 —
(145,772) (122.9) 184,227
 (31.5) 25,903
 (2.8)
Effect of change in state valuation allowance20,047
 (3.7) 39,492
 (8.3) (1,436) (0.8)
Effect of foreign tax1,966
 (0.4) 964
 (0.2) 1,411
 0.8
Other deferred adjustments7,616
 6.4
 —
 —
 —
 —
Effect of federal rate reduction(131,784) (111.1) —
 —
 —
 —
Effect of federal tax credits(19,081) (16.1) —
 —
 —
 —
Other2,215
 (0.5) 794
 (0.2) 4,057
 2.1
4,798
 4.0
 4,873
 (0.8) 1,689
 (0.2)
Income Tax Expense (Benefit) / Effective Rate$10,010
 (1.9)% $(125,439) 26.3 % $15,204
 8.3 %
Income Tax Benefit / Effective Rate$(176,458) (148.9)% $(34,403) 6.0 % $(280,359) 30.2 %

As part of CONSOL Energy's IRS examinationOn December 22, 2017, the United States enacted the Tax Cuts and Jobs Act which made significant changes that affect CNX. CNX believes that those changes will positively impact its future after-tax earnings, primarily due to the lower U.S. Federal tax rate and the repeal of the corporate alternative minimum tax. Beginning January 1, 2018, CNX will be taxed at a 21% federal corporate tax rate. The Company has reflected the impact of this rate on its deferred tax assets and liabilities at December 31, 2017, as it is required to reflect the change in the period in which the law is enacted. The impact of this change was a net benefit of $115,291 in the income tax provision for the period ended December 31, 2017.

The Act also repealed the corporate alternative minimum tax for tax years 2010-2013, bonus depreciation was claimed resultingbeginning after January 1, 2018 and provided that prior alternative minimum tax credits would be refundable. As discussed above, CNX has credits that are expected to be refunded between 2018 and 2021 as a result of the Act and monetization opportunities under current law in 2017. The Company's effective tax rate reflects the release of previously recorded valuation allowances against alternative minimum tax credit carry-forwards of $154,385, including other immaterial changes to valuation, as those credits will now be able to be monetized, net of anticipated sequestration, under the Act.

The Act is a comprehensive tax reform bill containing a number of other provisions that either currently or in the future could impact CNX. The effect of certain limitations effective for the tax year 2018 and forward, specifically related to the deductibility of executive compensation, have been evaluated.

The net cash refundbenefits for the Act as recorded as provisional amounts as of $92,000. The bonus depreciation deduction adversely impacts earnings by reducingDecember 31, 2017, represent the Company's percentage depletion adjustment on its mining operations and reducingbest estimate using information available to the Section 199 manufacturing deduction in the years 2008-2012. ThisCompany as of February 7, 2018. The Company anticipates U.S. regulatory agencies


12293


resultedwill issue further regulations over the next year which may alter this estimate. The Company is still evaluating, among other things, the application of limitations for executive compensation related to contracts existing prior to November 2, 2017, and provisions in a net non-cash chargethe Act addressing the deductibility of interest expense after January 1, 2018. The Company will refine its estimates to earningsincorporate new or better information as it comes available through the filing date of $36,619.its 2017 U.S. income tax returns in the fourth quarter of 2018.

A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:
For the Years EndedFor the Years Ended
December 31,December 31,
2016 20152017 2016
Balance at beginning of period$12,702
 $4,265
$9,103
 $12,702
Increase in unrecognized tax benefits resulting from tax positions taken during current period666
 —
21,902
 666
Increase in unrecognized tax benefits resulting from tax positions taken during prior periods—
 8,437
7,474
 —
Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations(666) —
Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities(4,265) —
—
 (4,265)
Balance at end of period$9,103
 $12,702
$37,813
 $9,103

If these unrecognized tax benefits were recognized, $666$29,376 and $4,265$666 would affect CONSOL Energy'sCNX's effective income tax rate for 20162017 and 2015,2016, respectively.

CONSOL EnergyCNX and its subsidiaries file income tax returns in the United States and returns within various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to United States federal, state, local or non-U.S. income tax examinations by tax authorities for the years before 2010.2016.

CONSOL EnergyIn 2017, CNX recognized an increase in unrecognized tax benefits of $28,710 for tax benefits resulting from a tax position taken on our federal tax return for the Marginal Well Credit and Consideration of Interest on Depletion in 2016 and plan to take on our 2017 return.

CNX recognizes interest accrued related to unrecognized tax benefits in its interest expense. As of December 31, 20162017 and 2015,2016, the Company had an accrued liability of $305$644 and $53,$306, respectively, for interest related to uncertain tax positions. Interest expense of $252$337 and $53$253 was recorded in the Company's Consolidated Statements of Income for the years ended December 31, 20162017 and 2015,2016, respectively. During the years ended December 31, 2017 and 2016, and 2015, CONSOL EnergyCNX paid no interest related to income tax deficiencies.

CONSOL EnergyCNX recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of December 31, 2017 and 2016, and 2015, CONSOL EnergyCNX had no accrued liabilities for tax penalties.

NOTE 7—GAS WELL CLOSING and MINE CLOSING:
CONSOL Energy accrues for dismantling and removing costs of natural gas related facilities, mine closing costs, perpetual water care costs, and surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes capitalized asset retirement costs by increasing the carrying amount of related long-lived assets. The obligation for asset retirements is included in Gas Well Closing, Mine Closing and Other Accrued Liabilities on the Consolidated Balance Sheets.6—ASSET RETIREMENT OBLIGATIONS:
The reconciliation of changes in the asset retirement obligations at December 31, 20162017 and 20152016 is as follows:
  As of December 31,
  2016 2015
Balance at beginning of period $429,967
 $454,832
Accretion expense 23,924
 32,438
Payments (15,882) (18,033)
Revisions in estimated cash flows 36,320
 (33,984)
Other (785) (5,286)
Balance at end of period $473,544
 $429,967
For the year ended December 31, 2015, Other includes ($2,133) related to the disposition of two Perpetual Care sites as part of the WAE sale (see Note 3 - Acquisitions and Dispositions for more information) and ($2,355) related to the disposition of a non-producing mine.    

  As of December 31,
  2017 2016
Balance at beginning of period $201,006
 $145,778
Accretion expense 5,760
 3,755
Payments (6,875) (4,241)
Revisions in estimated cash flows 5,356
 56,398
Other (1,177) (684)
Balance at end of period $204,070
 $201,006


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NOTE 8—INVENTORIES:
 December 31,
 2016 2015
Coal$7,800
 $4,660
Supplies57,661
 62,132
Total Inventories$65,461
 $66,792
NOTE 9—7—PROPERTY, PLANT AND EQUIPMENT:
 December 31,
E&P Property, Plant and Equipment2016 2015
Intangible drilling cost$3,583,565
 $3,452,989
Proved gas properties2,016,916
 1,922,602
Unproved gas properties1,116,282
 1,421,083
Gas gathering equipment1,138,299
 1,147,173
Gas wells and related equipment791,996
 785,744
Other gas assets190,406
 125,691
Gas advance royalties13,762
 19,745
Total E&P Property, Plant and Equipment$8,851,226
 $8,875,027
Less: Accumulated Depreciation, Depletion and Amortization3,106,296
 2,695,674
Total E&P Property, Plant and Equipment - Net$5,744,930
 $6,179,353
    
PA Mining Operations Property, Plant and Equipment   
Coal and other plant and equipment$2,307,668
 $2,284,103
Coal properties and surface lands458,398
 456,044
Airshafts371,752
 351,870
Mine development326,152
 326,225
Coal advance mining royalties16,224
 16,263
Leased coal lands26,566
 26,402
Total PA Mining Operations Property, Plant and Equipment$3,506,760
 $3,460,907
Less: Accumulated Depreciation, Depletion and Amortization1,768,712
 1,603,642
Total PA Mining Operations Property, Plant and Equipment - Net$1,738,048
 $1,857,265
    
Other Property, Plant and Equipment   
Coal and other plant and equipment$532,919
 $569,333
Coal properties and surface lands481,126
 484,348
Airshafts10,003
 10,002
Mine development17,988
 18,073
Coal advance mining royalties310,530
 312,452
Leased coal lands60,836
 64,765
Total Other Property, Plant and Equipment$1,413,402
 $1,458,973
Less: Accumulated Depreciation, Depletion and Amortization755,941
 762,885
Total Other Property, Plant and Equipment - Net$657,461
 $696,088
    
Total Company Property, Plant and Equipment$13,771,388
 $13,794,907
Less - Total Company Accumulated Depreciation, Depletion and Amortization5,630,949
 5,062,201
Total Company Property, Plant and Equipment - Net$8,140,439
 $8,732,706


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 December 31,
Property, Plant and Equipment2017 2016
Intangible drilling cost$3,849,689
 $3,583,599
Proved gas properties1,999,891
 2,016,916
Gas gathering equipment1,182,234
 1,138,299
Unproved gas properties919,733
 1,116,282
Gas wells and related equipment834,120
 800,617
Surface land and other equipment309,602
 323,908
Other gas assets221,226
 204,338
Total Property, Plant and Equipment$9,316,495
 $9,183,959
Less: Accumulated Depreciation, Depletion and Amortization3,526,742
 3,214,984
Total Property, Plant and Equipment - Net$5,789,753
 $5,968,975
The following assets arewould be amortized using the units-of-production method. Amounts reflect properties where mining or drilling operations have not yet commenced and therefore, are not being amortized for the years ended December 31, 20162017 and 2015,2016, respectively.
 December 31,
 2016 2015
Unproved gas properties$1,116,282
 $1,421,083
Coal properties195,354
 258,099
Leased coal lands36,788
 44,805
Airshafts19,693
 24,674
Coal advance mining royalties16,270
 21,544
Gas advance royalties13,762
 19,745
Mine development7,771
 7,930
     Total$1,405,920
 $1,797,880
 December 31,
 2017 2016
Unproved gas properties$919,733
 $1,116,282
Gas Advance Royalties13,220
 13,762
     Total$932,953
 $1,130,044

As of December 31, 20162017 and 2015,2016, plant and equipment includes gross assets under capital lease of $77,438$73,688 and $79,551,$73,892, respectively. Included in Gas gathering equipment under the E&P division is a capital lease for the Jewell Ridge Pipeline of $66,919 at December 31, 20162017 and 2015. The E&P division2016. CNX also maintains a capital lease for vehicles of $6,015$6,769 and $7,474$6,973 at December 31, 20162017 and 2015,2016, respectively, which is included in Other gas assets. At December 31, 2016 and 2015, the PA Mining segment maintains capital leases for vehicles of $2,525 and $1,923, respectively, which are included in Coal and other plant and equipment. At December 31, 2016 and 2015, the Other segment maintains capital leases for vehicles and computer equipment of $1,979 and $3,235, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was $51,213$54,431 and $46,503$48,814 at December 31, 20162017 and 2015,2016, respectively. Amortization expense for capital leases is included in Depreciation, Depletion and Amortization in the Consolidated Statements of Income. See Note 13–11–Leases for further discussion of capital leases.

Industry Participation Agreements

CONSOL EnergyCNX had two significant industry participation agreements (referred to as "joint ventures" or "JVs") that provided drilling and completion carries for the Company's retained interests.

CNX Gas Company is party to a joint development agreement with Hess Ohio Developments, LLC (Hess) with respect to approximately 155125 thousand net Utica Shale acres in Ohio in which each party has a 50% undivided interest. Under the agreement, as amended, Hess was obligated to pay a total of approximately $335,000 in the form of a 50% drilling carry of certain CONSOL EnergyCNX working interest obligations as the acreage is developed. As of December 31, 2016, Hess' entire carry obligation has been met.

CNX Gas Company was party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 700 thousand net Marcellus Shale oil and gas acres in West Virginia and Pennsylvania, in which each party owned a 50% undivided interest. OnIn October 29, 2016, CNX Gas entered into an Exchange Agreement with Noble Energy, which terminated the joint development agreement related to the jointly owned gas assets held in connection with the joint venture with Noble and divided such jointly owned gas assets among CNX Gas and Noble Energy. The transactions contemplated by the Exchange Agreement waswere closed on December 1, 2016 with an effective date of October 1, 2016. As part of the exchange: each party will ownnow owns and operateoperates a 100% interest in its properties and wells in two separate operating areas; each party will havehas independent control and flexibility with respect to the scope and timing of future development over its operating area; and all acreage operated by CONSOL EnergyCNX and Noble Energy, Inc. in their respective operating areas will remain fully dedicated to CONECNX Midstream Partners LP. Cash proceeds of approximately $213,295 were received at closing and are included in cash flows from investing activities in the Consolidated Statements of Cash Flows.LP (see Note 20 - Related Party). The exchange was accounted for as a mineral conveyance, thus no gain or loss was recorded in connection with the transaction. In June 2017, Noble Energy announced that it has closed on a transaction divesting its upstream assets in northern West Virginia and southern Pennsylvania to HG Energy II Appalachia, LLC, a portfolio company of Quantum Energy Partners.


95


NOTE 10—8—SHORT-TERM NOTES PAYABLE:

CONSOL Energy's currentCNX's senior secured credit agreement expires on June 18, 2019. The creditIn November 2017, the facility allowswas amended to allow for upthe spin-off of the Company's coal business (See Note 2 - Discontinued Operations). At that time, the lenders' commitments to the facility were reduced from $2,000,000 of borrowings, which includesto $1,500,000, and the borrowing base remained unchanged at $2,000,000, including a $750,000$650,000 letters of credit aggregate sub-limit. CONSOL EnergyCNX can also request an additional $500,000 increase in the aggregate borrowing limit amount.



125


The current facility is secured by substantially all of the assets of CONSOL EnergyCNX Resources Corporation and certain of its subsidiaries. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is limited to a borrowing base, which is determined by the lenders syndication agent and approved by the required number of lenders in good faith by calculating a value of CONSOL Energy'sCNX's proved natural gas reserves.

The current facility contains a number of affirmative and negative covenants that limit the Company's ability to dispose of assets, make investments, purchase or redeem CONSOL EnergyCNX common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. InThe April 2016 the facility was amended to requireamendment requires that the Company must: (i) prepay outstanding loans under the revolving credit facility to the extent that cash on hand exceeds $150,000 for two consecutive business days; (ii) mortgage 85% of its proved reserves and 80% of its proved developed producing reserves, in each case, which are included in the borrowing base; (iii) maintain applicable deposit, securities and commodities accounts with the lenders or affiliates thereof; and (iv) enter into control agreements with respect to such applicable accounts. In addition, the Company pledged the equity interest it holds in CONECNX Gathering, LLC and CONECNX Midstream Partners, LP as collateral to secure loans under the credit agreement. Further, the credit facility allows unlimited investments in joint ventures for the development and operation of natural gas gathering systems.

The facility also requires that CONSOL EnergyCNX maintains a minimum interest coverage ratio of no less than 2.50 to 1.00, which is calculated as the ratio of Adjusted EBITDA to cash interest expense of CONSOL EnergyCNX and certain of its subsidiaries, measured quarterly. CONSOL EnergyCNX must also maintain a minimum current ratio of no less than 1.00 to 1.00, which is calculated as the ratio of current assets, plus revolver availability, to current liabilities, excluding borrowings under the revolver, measured quarterly. At December 31, 2016,2017, the interest coverage ratio was 3.494.01 to 1.00 and the current ratio was 2.594.78 to 1.00. Further, the credit facility allows unlimited investments in joint ventures for the development and operation of natural gas gathering systems and permits CONSOL Energy to separate its E&P and coal businesses if the leverage ratio (which is, essentially, the ratio of debt to EBITDA) of the E&P business immediately after the separation would not be greater than 2.75 to 1.00. The calculation of all of the ratios exclude CNX Coal Resources LP (CNXC).

At December 31, 2017, the $1,500,000 facility had no borrowings outstanding and $239,072 of letters of credit outstanding, leaving $1,260,928 of unused capacity. At December 31, 2016, the $2,000,000 facility had no borrowings outstanding and $325,676 of letters of credit outstanding, leaving $1,674,324 of unused capacity. At December 31, 2015, the $2,000,000 facility had $952,000 of borrowings outstanding and $258,177 of letters of credit outstanding, leaving $789,823 of unused capacity.

NOTE 11—9—OTHER ACCRUED LIABILITIES:
 December 31, December 31,
 2016 2015 2017 2016
Royalties $60,008
 $42,425
Gas derivatives $231,573
 $12,206
 41,291
 231,573
Subsidence liability 104,437
 86,860
Royalties 44,657
 38,707
Accrued interest 37,366
 38,406
 32,172
 35,127
Transportation charges 13,004
 9,856
Short-term incentive compensation 12,062
 13,424
Deferred revenue 11,559
 7,691
Accrued other taxes 9,779
 9,261
Accrued payroll & benefits 24,649
 24,952
 6,615
 7,322
Accrued other taxes 20,679
 10,927
Short-term incentive compensation 19,497
 6,802
Deferred Revenue 18,211
 11,557
Equipment leases 15,286
 15,286
Other 59,025
 60,052
 30,083
 26,155
Current portion of long-term liabilities: 
 
 
 
Postretirement benefits other than pensions 42,001
 46,105
Gas well closing 17,285
 15,648
Mine closing 14,276
 22,599
Workers' compensation 13,874
 14,803
Pneumoconiosis benefits 10,763
 9,382
Long-term disability 3,865
 4,248
Asset retirement obligations 5,302
 5,302
Salary retirement 2,904
 2,772
 1,532
 1,505
Reclamation —
 515
Total Other Accrued Liabilities $680,348
 $421,827
 $223,407

$389,641



12696


NOTE 12—10—LONG-TERM DEBT:
December 31,December 31,
2016 20152017 2016
Debt:      
Senior Notes due April 2022 at 5.875% (Principal of $1,850,000 plus Unamortized Premium of $4,731 and $5,617, respectively)$1,854,731
 $1,855,617
Senior Notes due April 2023 at 8.00% (Principal of $500,000 less Unamortized Discount of $5,656 and $6,561, respectively)494,344
 493,439
Revolving Credit Facility - CNX Coal Resources LP201,000
 185,000
MEDCO Revenue Bonds in Series due September 2025 at 5.75%102,865
 102,865
Senior Notes due April 2022 at 5.875% (Principal of $1,705,682 and $1,850,000 plus Unamortized Premium of $3,544 and $4,731, respectively)$1,709,226
 $1,854,731
Senior Notes due April 2023 at 8.00% (Principal of $500,000 less Unamortized Discount of $4,751 and $5,656, respectively)495,249
 494,344
Senior Notes due April 2020 at 8.25%, Issued at Par Value74,470
 74,470
—
 74,470
Senior Notes due March 2021 at 6.375%, Issued at Par Value20,611
 20,611
—
 20,611
Advance Royalty Commitments (7.73% and 16.35% Weighted Average Interest Rate, respectively)2,678
 3,964
Other Long-Term Note Maturing in 2018 (Principal of $1,789 and $3,096 less Unamortized Discount of $117 and $327, respectively)1,672
 2,769
Other Note Maturing in 2018 (Principal of $358 and $1,789 less Unamortized Discount of $8 and $117, respectively)350
 1,672
Less: Unamortized Debt Issuance Costs27,699
 33,017
17,536
 23,356
2,724,672
 2,705,718
2,187,289
 2,422,472
Less: Amounts Due in One Year*1,677
 1,819
263
 1,304
Long-Term Debt$2,722,995
 $2,703,899
$2,187,026
 $2,421,168

*Excludes current portion of Capital Lease Obligations of $10,323$6,848 and $7,590$6,620 at December 31, 20162017 and 2015,2016, respectively.

Annual undiscounted maturities on long-term debt during the next five years and thereafter are as follows:
Year ended December 31,AmountAmount
2017$1,804
2018672
$358
2019292
—
2020275,740
—
202120,861
—
20221,705,682
Thereafter2,454,043
500,000
Total Long-Term Debt Maturities$2,753,412
$2,206,040

In March 2015, CONSOL Energy closedDuring the year ended December 31, 2017, CNX called the remaining $74,470 balance on the private placement of $500,000 of 8.00% senior notes due in 2023 (the "Notes") less $7,240 of unamortized bond discount. The Notes are guaranteed by substantially all of CONSOL Energy's wholly-owned domestic restricted subsidiaries. CONSOL Energy used the net proceeds of the sale of the Notes, together with borrowings under its revolving credit facility, to purchase $937,822 of its outstanding 8.25% senior notes due in April 2020 and $229,176 ofthe remaining $20,611 balance on its outstanding 6.375% senior notes due in March 2021. The call price was $101.375 for the 8.25% senior notes due in April 2020 and $102.125 for the 6.375% senior notes due in March 2021. Additionally, CNX purchased $144,318 of its outstanding 5.875% senior notes due in April 2022 . As part of this transaction, $67,734these transactions, a loss of $2,129 was included in Loss on Debt Extinguishment on the Consolidated Statements of Income.Income for the year ended December 31, 2017.

In AprilDuring the year ended December 31, 2015, CONSOL EnergyCNX purchased $2,508$940,330 of its outstanding 8.25% senior notes due in April 2020 and $213$229,389 of its outstanding 6.375% senior notes due in March 2021. As part of this transaction, $17these transactions, a loss of $67,751 was included in Loss on Debt Extinguishment on the Consolidated Statements of Income.

In July 2015, CNXC entered into a Credit AgreementIncome for a $400,000 revolving credit facility. As ofthe year ended December 31, 2016 and 2015, CNXC had $201,000 and $185,000 of borrowings outstanding on the facility, respectively. CONSOL Energy is not a guarantor of CNXC's revolving credit facility. See Note 25 - Related Party Transactions for more information.


2015.



12797


NOTE 13—11—LEASES:
CONSOL EnergyCNX uses various leased facilities and equipment in its operations. Future minimum lease payments under capital and operating leases, together with the present value of the net minimum capital lease payments, at December 31, 20162017 are as follows:
 Capital Operating Capital Operating
 Leases Leases Leases Leases
Year Ended December 31,        
2017 $13,237
 $103,325
2018 12,442
 64,520
 $8,562
 $7,497
2019 11,977
 37,272
 8,362
 6,334
2020 11,007
 27,722
 7,539
 5,565
2021 8,959
 26,816
 6,706
 5,438
2022 —
 5,378
Thereafter —
 80,692
 —
 41,433
Total minimum lease payments $57,622
 $340,347
 $31,169
 $71,645
Less amount representing interest (2.00% – 7.36%) 8,225
  
Less amount representing interest (3.00% – 7.36%) 3,974
  
Present value of minimum lease payments 49,397
   27,195
  
Less amount due in one year 10,323
   6,848
  
Total Long-Term Capital Lease Obligation $39,074
  
Total long-term capital lease obligation $20,347
  

Rental expense under operating leases was $108,698, $109,789,$16,797, $20,772, and $111,257$26,360 for the years ended December 31, 2017, 2016 2015 and 2014,2015, respectively.

At December 31, 2016, certain of the above capital leases for mining equipment are subleased to a third-party. The following represents the minimum payments including interest for those capital subleases:
20172018201920202021ThereafterTotal
$3,699
 $3,699
 $3,699
 $3,699
 $2,157
 $—
 $16,953

At December 31, 2016, certain of the above operating leases for mining equipment are subleased to third-parties. The following represents the minimum rental payments for those operating subleases:
20172018201920202021ThereafterTotal
$40,299
 $13,819
 $6,909
 $—
 $—
 $—
 $61,027

CONSOL Energy leases certain owned mining equipment to a third-party under operating leases. The owned equipment included in gross property, plant and equipment was $26,005, with $15,603 accumulated depreciation at December 31, 2016. 

At December 31, 2016, scheduled minimum rental payments for operating leases related to this equipment were as follows: 
2017 2018 2019 2020 2021 Thereafter Total
$4,496
 $2,992
 $1,701
 $627
 $—
 $—
 $9,816



128

NOTE 12—PENSION:

NOTE 14—PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:
Pension:

CONSOL EnergyCNX has a non-contributory defined benefit retirement plans. Effective December 31, 2015, CONSOL Energy's qualified defined benefit retirement plan was frozen. The benefits for these plans are based primarily on years of service and employees' pay. CONSOL Energy's qualified pension plan allows for lump-sum distributions of benefits earned up until December 31, 2005, at the employees' election.

On September 30, 2014, the qualified pension plan was remeasured to reflect an announced plan amendment that reduced future accruals of pension benefits as of January 1, 2015. The plan amendment called for a hard freeze of the qualified defined benefit pension plan on January 1, 2015 for employees who were under age 40 or had less than 10 years of service as of September 30, 2014. Employees who were age 40 or over and had at least 10 years of service continued in the defined benefit pension plan unchanged. The modifications to the pension plan resulted in a $21,624 reduction in the pension liability.

On August 31, 2015, the qualified pension plan was remeasured to reflect an announced plan amendment that reduced accruals of pension benefits as of January 1, 2016. The plan amendment called for a hard freeze of the qualified defined benefit pension plan on January 1, 2016 for all remaining participants in the plan. The modifications to the pension plan resulted in a $26,352 reduction in the pension liability. The amendment resulted in a remeasurement of the qualified pension plan at August 31, 2015, which increased the pension liability by $17,793.

In the third quarter of 2015, CONSOL Energy remeasured its pension plan as a result of the previously discussed plan amendment. In conjunction with this remeasurement, the method used to estimate the service and interest components of net periodic benefit cost for pension was changed. This change was also made to other postretirement benefits in the fourth quarter during the annual remeasurement of that plan. This change, compared to the previous method, resulted in a decrease in the service and interest components for pension cost in the third quarter. Historically, CONSOL Energy estimated these service and interest cost components utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. CONSOL Energy has elected to utilize a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. This change was made to provide a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows to the corresponding spot yield curve rates. This change is immaterial to CONSOL's financial statements. CONSOL Energy has accounted for this change as a change in accounting estimate that is inseparable from a change in accounting principle and, accordingly, accounted for it prospectively.

According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lump sum distributions made during a plan year, which for CONSOL EnergyCNX is January 1 to December 31, exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the yearsyear ended December 31, 2016, 2015, and 2014.2015. Accordingly, CONSOL EnergyCNX recognized settlement expense of $22,196, $19,053, and $29,095$3,132 for the yearsyear ended December 31, 2016, 2015 and 2014 respectively, in Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. The settlement charges resulted in remeasurements ofLump sum payments did not exceed this threshold during the pension plan during 2016, 2015 and 2014.years ended December 31, 2017 or 2016.

Other Postretirement Benefit Plans:

Certain subsidiaries of CONSOL Energy provide medical and prescription drug benefits to retired employees covered by the Coal Industry Retiree Health Benefit Act of 1992 (the Coal Act). Represented hourly employees are eligible to participate based upon the terms of the National Bituminous Coal Wage Agreement of 2011.

On September 30, 2014, the Salaried OPEB plan and Production and Maintenance (P&M) OPEB plans were remeasured to reflect an announced plan amendment that reduced retiree medical and life insurance benefits as of September 30, 2014. Effective September 30, 2014, no retiree medical, prescription drug or life benefits were to be provided to active employees. Salaried and P&M retirees as of September 30, 2014 were to continue in the OPEB plans for a maximum period up to December 31, 2019 and coverage thereafter was eliminated (see below for information on an additional amendment made to these plans in 2015). The Company elected to make cash transition payments totaling approximately $46,282 to the active employees whose retiree medical, prescription drug and life insurance benefits were eliminated by the changes to the OPEB plans. These cash payments are not considered to be post-retirement benefits, and as such, they are not reflected in the actuarial calculations related to the OPEB plans. The amendment to the OPEB plans resulted in a $315,439 reduction in the OPEB liability and a curtailment gain of $35,633.





















12998


On May 31, 2015, the Salaried OPEB and P&M OPEB plans were remeasured to reflect another plan amendment which eliminated Salaried and P&M OPEB benefits at December 31, 2015. The amendment to the OPEB plans resulted in a $43,598 reduction in the OPEB liability. The amendment also resulted in a remeasurement of the OPEB plan at May 31, 2015, which decreased the liability by $1,070. CONSOL Energy recognized income of $235,541 related to amortization of prior service credit, coupled with recognition of actuarial losses in PA Mining Operations Costs - Operating and Other Costs and Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income for the year ended December 31, 2015 as a result of the changes made to the Salaried and P&M OPEB plans.
The Company will incur savings from cost containment changes related to pharmacy benefits, which were implemented on January 1, 2017, and increased member responsibility when using out-of-network providers and facilities, which will be implemented on March 27, 2017. These plan amendments resulted in a $28,164 reduction in the OPEB liability during the year ended December 31, 2016.
The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2016 and 2015the pension benefits is as follows:
  Pension Benefits Other Postretirement Benefits
  at December 31, at December 31,
  2016 2015 2016 2015
Change in benefit obligation:        
Benefit obligation at beginning of period $763,407
 $870,471
 $671,755
 $760,959
Service cost 1,927
 8,653
 —
 —
Interest cost 25,491
 32,095
 24,241
 27,238
Actuarial loss (gain) 46,962
 (39,563) 77,640
 (9,224)
Plan amendments —
 —
 (28,164) (43,598)
Plan transfer* —
 —
 —
 (5,242)
Plan curtailments —
 (26,352) —
 —
Plan settlements (54,197) (51,497) —
 —
Participant contributions —
 —
 —
 1,649
Benefits and other payments (35,709) (30,400) (45,387) (60,027)
Benefit obligation at end of period $747,881
 $763,407
 $700,085
 $671,755
         
Change in plan assets:        
Fair value of plan assets at beginning of period $669,039
 $751,176
 $—
 $—
Actual return (loss) on plan assets 50,575
 (9,293) —
 —
Company contributions 2,726
 9,053
 45,387
 58,378
Participant contributions —
 —
 —
 1,649
Benefits and other payments (35,709) (30,400) (45,387) (60,027)
Plan settlements (54,197) (51,497) —
 —
Fair value of plan assets at end of period $632,434
 $669,039
 $—
 $—
         
Funded status:        
Current liabilities $(2,904) $(2,772) $(40,611) $(40,863)
Noncurrent liabilities (112,543) (91,596) (659,474) (630,892)
Net obligation recognized $(115,447) $(94,368) $(700,085) $(671,755)
         
Amounts recognized in accumulated other comprehensive income consist of:        
Net actuarial loss $299,865
 $288,695
 $426,392
 $367,920
Prior service credit (1,611) (2,201) (28,164) —
Net amount recognized (before tax effect) $298,254
 $286,494
 $398,228
 $367,920

*The plan transfer relates to the IBNR (incurred but not reported) costs associated with the terminated Salaried and P&M OPEB plans. These costs are now included in Other Accrued Liabilities in the Consolidated Balance Sheets.




130

  December 31,
  2017 2016
Change in benefit obligation:    
Benefit obligation at beginning of period $34,051
 $33,196
Service cost 375
 367
Interest cost 1,201
 1,250
Actuarial loss 2,127
 651
Benefits and other payments (1,474) (1,413)
Benefit obligation at end of period $36,280
 $34,051
     
Change in plan assets:    
Fair value of plan assets at beginning of period $—
 $—
Company contributions 1,474
 1,413
Benefits and other payments (1,474) (1,413)
Fair value of plan assets at end of period $—
 $—
     
Funded status:    
Current liabilities $(1,532) $(1,505)
Noncurrent liabilities (34,748) (32,546)
Net obligation recognized $(36,280) $(34,051)
     
Amounts recognized in accumulated other comprehensive loss consist of:    
Net actuarial loss $14,374
 $13,772
Prior service credit (626) (988)
Net amount recognized (before tax effect) $13,748
 $12,784

The components of the net periodic benefit costscost are as follows:
Pension Benefits Other Postretirement Benefits
For the Years Ended December 31, For the Years Ended December 31,For the Years Ended December 31,
2016 2015 2014 2016 2015 20142017 2016 2015
Components of net periodic benefit cost:                
Service cost$1,927
 $8,653
 $17,187
 $—
 $—
 $7,089
$375
 $367
 $475
Interest cost25,491
 32,095
 35,363
 24,241
 27,238
 44,177
1,201
 1,250
 1,526
Expected return on plan assets(46,674) (51,528) (51,400) —
 —
 —
Amortization of prior service credits(590) (666) (1,217) —
 (336,327) (21,163)(362) (362) (362)
Recognized net actuarial loss9,694
 21,519
 23,927
 19,168
 102,875
 28,682
1,525
 1,505
 2,252
Curtailment loss (gain)—
 5
 (549) —
 —
 (35,633)
Settlement loss (gain)22,196
 19,053
 29,095
 —
 (8,932) —
Net periodic benefit cost (credit)$12,044
 $29,131
 $52,406
 $43,409
 $(215,146) $23,152
Settlement loss—
 —
 3,132
Net periodic benefit cost$2,739
 $2,760
 $7,023

Amounts included in accumulated other comprehensive loss which are expected to be recognized in 20172018 net periodic benefit costs:cost:
   Other
 Pension Postretirement Pension
 Benefits Benefits Benefits
Prior service credit recognition $(590) $(2,405) $(362)
Actuarial loss recognition $9,403
 $23,112
 $1,492

CONSOL EnergyCNX utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the Pension Plan.pension plan. Cumulative gains and losses that are in excess of 10% of the greater of either the projected benefit obligation (PBO) or the market-related value of plan assets are amortized over the expected remaining future lifetime of all plan participants for the Pensionpension plan.

CONSOL Energy also utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the OPEB Plan. Cumulative gains and losses that are in excess of 10% of the greater of either the accumulated postretirement benefit obligation (APBO) or the market-related value of plan assets are amortized over the average future remaining lifetime of the current inactive population for the OPEB plan.


99


The following table provides information related to the pension plansplan with an accumulated benefit obligation in excess of plan assets:
  As of December 31,
  2016 2015
Projected benefit obligation $747,881
 $763,407
Accumulated benefit obligation $745,793
 $761,124
Fair value of plan assets $632,434
 $669,039













131

  As of December 31,
  2017 2016
Projected benefit obligation $36,280
 $34,051
Accumulated benefit obligation $35,264
 $32,838
Fair value of plan assets $—
 $—

Assumptions:

The weighted-average assumptions used to determine benefit obligations are as follows:
 Pension Benefits Other Postretirement Benefits
 For the Year Ended For the Year Ended For the Year Ended
 December 31, December 31, As of December 31,
 2016 2015 2016 2015 2017 2016
Discount rate 4.31% 4.50% 4.22% 4.50% 3.70% 4.26%
Rate of compensation increase 3.90% 3.80% —
 —
 4.05% 3.90%

The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company plans.

The weighted-average assumptions used to determine net periodic benefit costscost are as follows:
  Pension Benefits at Other Postretirement Benefits at
  December 31, December 31,
  2016 2015 2014 2016 2015 2014
Discount rate 4.52% 4.07% 4.87% 4.50% 4.03% 4.88%
Expected long-term return on plan assets 7.25% 7.75% 7.75% —
 —
 —
Rate of compensation increase 3.80% 3.80% 4.21% —
 —
 —

The long-term rate of return is the sum of the portion of total assets in each asset class held multiplied by the expected return for that class, adjusted for expected expenses to be paid from the assets. The expected return for each class is determined using the plan asset allocation at the measurement date and a distribution of compound average returns over a twenty year time horizon. The model uses asset class returns, variances and correlation assumptions to produce the expected return for each portfolio. The return assumptions used forward-looking gross returns influenced by the current Treasury yield curve. These returns recognize current bond yields, corporate bond spreads and equity risk premiums based on current market conditions.
The assumed health care cost trend rates are as follows:
  At December 31,
  2016 2015 2014
Health care cost trend rate for next year 6.31% 6.49% 6.03%
Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.50% 4.50% 4.50%
Year that the rate reaches ultimate trend rate 2038
 2038
 2026

Assumed health care cost trend rates have a significant effect on the amounts reported for the medical plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:
  1 Percentage 1 Percentage
  Point Increase Point Decrease
Effect on total of service and interest cost components $3,659
 $(3,053)
Effect on accumulated postretirement benefit obligation $84,381
 $(71,751)








132


Plan Assets:

The Company’s overall investment strategy is to meet current and future benefit payment needs through diversification across asset classes, fund strategies and fund managers to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation. Consistent with the objectives of the Trust and in consideration of the Trust’s current funded status and the current level of market interest rates, the Retirement Board has approved an asset allocation strategy that will change over time in response to future improvements in the Trust’s funded status and/or changes in market interest rates. Such changes in asset allocation strategy are intended to allocate additional assets to the fixed income asset class should the Trust’s funded status improve. In this framework, the current target allocation for plan assets are 26% U.S. equity securities, 16.5% non-U.S. equity securities, 7.5% global equity securities and 50% fixed income. Both the equity and fixed income portfolios are comprised of both active and passive investment strategies. The Trust is primarily invested in Mercer Common Collective Trusts. Equity securities consist of investments in large and mid/small cap companies with non-U.S. equities being derived from both developed and emerging markets. Fixed income securities consist of U.S. as well as international instruments, including emerging markets. The core domestic fixed income portfolios invest in government, corporate, asset-backed securities and mortgage-backed obligations. The average quality of the fixed income portfolio must be rated at least “investment grade” by nationally recognized rating agencies. Within the fixed income asset class, investments are invested primarily across various strategies such that its overall profile strongly correlates with the interest rate sensitivity of the Trust’s liabilities in order to reduce the volatility resulting from the risk of changes in interest rates and the impact of such changes on the Trust’s overall financial status. Derivatives, interest rate swaps, options and futures are permitted investments for the purpose of reducing risk and to extend the duration of the overall fixed income portfolio; however, they may not be used for speculative purposes. All or a portion of the assets may be invested in mutual funds or other commingled vehicles so long as the pooled investment funds have an adequate asset base relative to their asset class; are invested in a diversified manner; and have management and/or oversight by an Investment Advisor registered with the SEC. The Retirement Board, as appointed by the CONSOL Energy Board of Directors, reviews the investment program on an ongoing basis including asset performance, current trends and developments in capital markets, changes in Trust liabilities and ongoing appropriateness of the overall investment policy.

In May 2015, the FASB issued an Accounting Standards Update that removes the requirement to categorize within the fair value hierarchy investments for which fair values are estimated using the net asset value practical expedient provided by Accounting Standards Codification 820, Fair Value Measurement. This new guidance is effective for public entities for fiscal years beginning after December 15, 2015. In accordance with this Update, certain investments in 2016 and 2015 that are measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified as Level 1, 2 or 3 in the below fair value hierarchy but are included in the total.
The fair values of plan assets at December 31, 2016 and 2015 by asset category are as follows:
  Fair Value Measurements at December 31, 2016 Fair Value Measurements at December 31, 2015
    Quoted       Quoted    
    Prices in       Prices in    
    Active       Active    
    Markets for Significant Significant   Markets for Significant Significant
    Identical Observable Unobservable   Identical Observable Unobservable
    Assets Inputs Inputs   Assets Inputs Inputs
  Total (Level 1) (Level 2) (Level 3) Total (Level 1) (Level 2) (Level 3)
Asset Category                
Cash/Accrued Income $639
 $639
 $—
 $—
 $631
 $631
 $—
 $—
US Equities (a) 11
 11
 —
 —
 10
 10
 —
 —
Mercer Common Collective Trusts (b) 631,784
 —
 —
 —
 668,398
 —
 —
 —
Total $632,434
 $650
 $—
 $—
 $669,039
 $641
 $—
 $—
__________

(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.

There are no investments in CONSOL Energy stock held by these plans at December 31, 2016 or 2015.
There are no assets in the other postretirement benefit plans at December 31, 2016 or 2015.


133

 For the Years ended December 31,
 2017 2016 2015
Discount rate4.26% 4.55% 4.07%
Rate of compensation increase3.90% 3.80% 3.80%

Cash Flows:

If necessary, CONSOL Energy intends to contribute to the pension trust using prudent funding methods. However, the Company does not expect to contribute to the pension plan trust in 2017. Pension benefit payments are primarily funded from the trust. CONSOL EnergyCNX expects to pay benefits of $2,904$1,532 from the non-qualified pension plan in 2017. CONSOL Energy does not expect to contribute to the other postemployment plan in 2017 and intends to pay benefit claims as they are due.2018.
The following benefit payments, reflectingwhich reflect expected future service, are expected to be paid:
    Other
  Pension Postretirement
  Benefits Benefits
2017 $47,374
 $40,611
2018 $47,100
 $43,829
2019 $46,211
 $43,932
2020 $45,773
 $44,136
2021 $44,206
 $44,233
Year 2022-2026 $223,745
 $215,248
NOTE 15—COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION:
Under the Federal Coal Mine Health and Safety Act of 1969, as amended, CONSOL Energy is responsible for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers' pneumoconiosis disease. CONSOL Energy is also responsible under various state statutes for pneumoconiosis benefits. CONSOL Energy primarily provides for these claims through a self-insurance program. The calculation of the actuarial present value of the estimated pneumoconiosis obligation is based on an annual actuarial study by independent actuaries and uses assumptions regarding disability incidence, medical costs, indemnity levels, mortality, death benefits, dependents and interest rates which are derived from actual company experience and outside sources. Recent legislative changes have not been favorable for CWP. Although these changes have not had a significant impact on the liability, CONSOL has noticed an increase in claims. Actuarial gains or losses can result from differences in incident rates and severity of claims filed as compared to original assumptions.
CONSOL Energy must also compensate individuals who sustain employment-related physical injuries or some types of occupational diseases and, on some occasions, for costs of their rehabilitation. Workers' compensation laws will also compensate survivors of workers who suffer employment-related deaths. Workers' compensation laws are administered by state agencies, and each state has its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy primarily provides for these claims through a self-insurance program. CONSOL Energy recognizes an actuarial present value of the estimated workers' compensation obligation calculated by independent actuaries. The calculation is based on claims filed and an estimate of claims incurred but not yet reported as well as various assumptions, including discount rate, future healthcare trend rate, benefit duration and recurrence of injuries. Actuarial gains or losses associated with workers' compensation have resulted from discount rate changes and differences in claims experience and incident rates as compared to prior assumptions.
  Pension
Year ended December 31, Benefits
2018 $1,532
2019 $1,596
2020 $1,679
2021 $1,757
2022 $1,842
Year 2023-2027 $10,456


134


  CWP Workers' Compensation
  at December 31, at December 31,
  2016 2015 2016 2015
Change in benefit obligation:        
Benefit obligation at beginning of period $122,503
 $126,098
 $83,165
 $89,741
State administrative fees and insurance bond premiums —
 —
 3,265
 3,581
Service cost 4,327
 6,491
 7,618
 9,389
Interest cost 4,283
 5,116
 2,550
 3,195
Actuarial loss (gain) 439
 (5,089) 123
 (4,089)
Benefits paid (11,409) (10,113) (17,028) (18,999)
Curtailment gain (1,307) —
 —
 —
Settlements —
 —
 —
 347
Benefit obligation at end of period $118,836
 $122,503
 $79,693
 $83,165
         
Current assets $—
 $—
 $1,458
 $1,450
Current liabilities (10,763) (9,471) (13,874) (14,803)
Noncurrent liabilities (108,073) (113,032) (67,277) (69,812)
Net obligation recognized $(118,836) $(122,503) $(79,693) $(83,165)
         
Amounts recognized in accumulated other comprehensive income consist of:        
Net actuarial gain $(62,714) $(68,101) $(12,914) $(13,440)
Net amount recognized (before tax effect) $(62,714) $(68,101) $(12,914) $(13,440)

The components of the net periodic cost are as follows:
 CWP Workers’ Compensation
 For the Years Ended For the Years Ended
 December 31, December 31,
 2016 2015 2014 2016 2015 2014
Service cost$4,327
 $6,491
 $5,674
 $7,618
 $9,389
 $9,781
Interest cost4,283
 5,116
 5,537
 2,550
 3,195
 3,577
Recognized net actuarial gain(4,948) (5,576) (6,196) (403) (31) (382)
State administrative fees and insurance bond premiums—
 —
 —
 3,265
 3,581
 3,352
Curtailment gain(1,307) —
 —
 —
 —
 —
Settlement gain—
 —
 —
 —
 —
 —
Net periodic cost$2,355
 $6,031
 $5,015
 $13,030
 $16,134
 $16,328
(Income) expense attributable to discontinued operations included in the CWP net periodic cost was $(1,290), $297 and $87 for the years ended December 31, 2016, 2015 and 2014, respectively.
On March 31, 2016, CONSOL Energy completed the sale of its membership interests in BMC (see Note 2 - Discontinued Operations). As a result of the sale, certain obligations of the CWP plan were transferred to the buyer. This transfer triggered a curtailment gain of $1,307. The curtailment resulted in a plan remeasurement increasing plan liabilities by $7,713 at March 31, 2016.






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The following are amounts included in accumulated other comprehensive income that are expected to be recognized in 2017 net periodic benefit costs:
    Workers'
  CWP Compensation
  Benefits Benefits
Actuarial gain recognition $(7,631) $(610)

CONSOL Energy utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the Workers’ Compensation and CWP plans. Cumulative gains and losses that are in excess of 10% of the greater of either the estimated liability or the market-related value of plan assets are amortized over the expected average remaining future service of the current active membership of the Workers’ Compensation and CWP plans.
Assumptions:
The weighted-average discount rates used to determine benefit obligations and net periodic cost (benefit) are as follows:
  CWP Workers' Compensation
  For the Years Ended For the Years Ended
  December 31, December 31,
  2016
 2015
 2014
 2016
 2015
 2014
Benefit obligations 4.40% 4.60% 4.21% 4.05% 4.26% 3.84%
Net periodic cost 4.60% 4.21% 4.75% 4.26% 3.84% 4.57%
Discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company's plans.

Cash Flows:
CONSOL Energy does not intend to make contributions to the CWP or Workers' Compensation plans in 2017, but it intends to pay benefit claims as they become due.
The following benefit payments, which reflect expected future claims as appropriate, are expected to be paid:
    Workers' Compensation
  CWP Total Actuarial Other
  Benefits Benefits Benefits Benefits
2017 $10,763
 $15,897
 $12,416
 $3,481
2018 $8,417
 $15,193
 $11,625
 $3,568
2019 $7,606
 $15,061
 $11,404
 $3,657
2020 $7,137
 $15,044
 $11,295
 $3,749
2021 $6,963
 $15,056
 $11,214
 $3,842
Year 2022-2026 $35,714
 $76,577
 $55,876
 $20,701



136100


NOTE 16—OTHER EMPLOYEE BENEFIT PLANS:
UMWA Benefit Trusts:
The Coal Act created two multi-employer benefit plans: (1) the United Mine Workers of America Combined Benefit Fund (the Combined Fund) into which the former UMWA Benefit Trusts were merged, and (2) the United Mine Workers of America 1992 Benefit Plan (1992 Benefit Plan). CONSOL Energy accounts for required contributions to these multi-employer trusts as expense when incurred.
The Combined Fund provides medical and death benefits for all beneficiaries of the former UMWA Benefit Trusts who were actually receiving benefits as of July 20, 1992. The 1992 Benefit Plan provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and for those who retired between July 20, 1992 and September 30, 1994. The Coal Act provides for the assignment of beneficiaries to former employers and the allocation of unassigned beneficiaries (referred to as orphans) to companies using a formula set forth in the Coal Act. The Coal Act requires that responsibility for funding the benefits to be paid to beneficiaries be assigned to their former signatory employers or related companies. This cost is recognized when contributions are assessed. CONSOL Energy's total contributions under the Coal Act were $8,455, $9,239 and $10,121 for the years ended December 31, 2016, 2015 and 2014, respectively. Based on available information at December 31, 2016, CONSOL Energy's obligation for the Combined Fund and 1992 Benefit Plans is estimated to be approximately $93,795.

Pursuant to the provisions of the Tax Relief and Healthcare Act of 2006 (the 2006 Act) and the 1992 Benefit Plan, CONSOL Energy is required to provide security in an amount based on the annual cost of providing health care benefits for all individuals receiving benefits from the 1992 Benefit Plan who are attributable to CONSOL Energy, plus all individuals receiving benefits from an individual employer plan maintained by CONSOL Energy who are entitled to receive such benefits. In accordance with the terms of the 2006 Act and the 1992 Benefit Plan, CONSOL Energy must secure its obligations by posting letters of credit, which were $19,170, $21,473 and $21,394 at December 31, 2016, 2015 and 2014, respectively. The 2016, 2015 and 2014 security amounts were based on the annual cost of providing health care benefits and included a reduction in the number of eligible employees.
Investment Plan:
CONSOL Energy has an investment plan available to most non-represented employees. Throughout the year ended December 31, 2016, the Company's matching contribution was 6% of eligible compensation contributed by eligible employees. In conjunction with the qualified pension plan changes in 2015, the Company contributed an additional 3% of eligible compensation into the 401(k) plan accounts for employees hired or rehired on or after October 1, 2014 or who were under age 40 or had less than 10 years of service with the Company as of September 30, 2014. This additional contribution was eliminated on January 1, 2016. The Company may also make discretionary contributions to the Plan ranging from 1% to 6% (1% to 4% prior to January 1, 2016) of eligible compensation for eligible employees (as defined by the Plan). Discretionary contributions made by the Company were $12,260 for the year ended December 31, 2016. There were no such discretionary contributions made by the Company for the years ended December 31, 2015 and 2014. Total payments and costs were $20,784, $20,058 and $18,341 for the years ended December 31, 2016, 2015 and 2014, respectively.
Long-Term Disability:
CONSOL Energy has a Long-Term Disability Plan available to all eligible full-time salaried employees. The benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled.
  For the Years Ended
  December 31,
  2016 2015 2014
Benefit cost $2,128
 $2,619
 $2,213
Discount rate assumption used to determine net periodic benefit costs 3.71% 3.18% 3.53%
Liabilities incurred under the Long-Term Disability Plan are included in Other Accrued Liabilities and Deferred Credits and Other Liabilities–Other in the Consolidated Balance Sheets and amounted to a combined total of $19,144 and $19,789 at December 31, 2016 and 2015, respectively.


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NOTE 17—13—STOCK-BASED COMPENSATION:
CONSOL EnergyCNX adopted the CONSOL Energy Inc. Equity Incentive Plan (the Equity Incentive Plan) on April 7, 1999. The Equity Incentive Plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments to the Equity Incentive Plan have been adopted and approved by the Board of Directors and the Company's Shareholders since the commencement of the plan.Equity Incentive Plan. Most recently, in May 2016, the Board of Directors and the Company's Shareholders adopted and approved a 10,550,000 increase to the total number of shares available for issuance, which brought the total number of shares of common stock that can be covered by grants, after adjustment, in accordance with the terms of the Equity Incentive Plan, for the separation of the coal business from the gas business on November 28, 2017, to 42,350,000.48,915,944. At December 31, 2016, 8,733,1692017, 7,411,143 shares of common stock remainremained available for all awards.grant under the plan. The Equity Incentive Plan provides that the aggregate number of shares available for issuance will be reduced by one share for each share issued in settlement ofrelating to stock options and by 1.62 for each share issued in settlement ofrelating to Performance Share Units (PSUs) or Restricted Stock Units (RSUs). No award of stock options may be exercised under the Equity Incentive Plan after the tenth anniversary of the effectivegrant date of the award.

For only those shares expected to vest, CONSOL EnergyCNX recognizes stock-based compensation costs on a straight-line basis over the requisite service period of the award, which is generally the vesting term. Awards granted in 2014 vest immediately if granted to retiree-eligible employees who are aged 62Options and older. Awards granted in 2014 vest at the end of one year when granted to employees aged 55 to 62 and who have also completed ten years of service. Awards granted in 2014RSUs vest over a three-year term at 33% per year for all other employees. Awardsterm. PSUs granted in 2015 vest over a three-year term at 33% per year. Options and RSUswhile PSUs granted in 2016 vest over a three-year term at 33% per year. Performance share units granted in 2016and 2017 vest over a five-year term at 20% per year subject to performance conditions. If an employee leaves the Company, all unvested shares are forfeited. The vesting of all awards will accelerate in the event of death and disability and may accelerate upon a change in control of CONSOL Energy. See each specific award section for special vesting terms related to non-employee directors and other specific awards.CNX. The total stock-based compensation expense recognized during the years ended December 31, 2017, 2016 and 2015 was $16,983, $19,316 and 2014 was $31,483, $24,513 and $41,877,$14,314, respectively. The related deferred tax benefit totaled $11,255, $9,229$6,114, $7,272 and $15,243,$5,210, for the years ended December 31, 2017, 2016 and 2015, and 2014, respectively.

As of December 31, 2016, CONSOL Energy2017, CNX has $40,234$28,712 of unrecognized compensation cost related to all nonvested stock-based compensation awards, which is expected to be recognized over a weighted-average period of 2.732.75 years. When stock options are exercised and restricted and performance stock unit awards become vested, the issuances are made from CONSOL Energy'sCNX's common stock shares.

Pursuant to the terms of the CNX Equity Plan and the outstanding awards, in the event of certain changes in the outstanding common stock of CNX or its capital structure, including by reason of a spin-off, the administrator of the CNX Equity Plan is required to appropriately adjust the number, exercise price, kind of shares, performance goals or other terms and conditions of Awards granted thereunder. In connection with the Separation, the Board of Directors of CNX has determined that it is appropriate that the outstanding awards be equitably adjusted pursuant to the terms of the CNX Equity Plan and/or converted into awards issued under the CONSOL Energy Inc. (CEIX) Equity Incentive Plan, such that the intrinsic value of the outstanding awards immediately following the separation remains the same as the intrinsic value of such awards immediately prior to the separation. It was agreed upon that a simple average of the volume weighted average price (VWAP) per share for each of the three trading days prior to the distribution of CONSOL Energy, Inc will be divided by the simple average of the VWAP for each of the 3 trading days subsequent to the distribution date of CNX or CEIX will be used to ensure intrinsic value was preserved for conversion of CONSOL Energy units to CNX or CEIX units. Each type of award is summarized below:

•CONSOL Energy's stock options held by both CNX and CEIX employees and former employees were adjusted to provide holders 1.15504 options to purchase CNX common stock for every option of CONSOL Energy stock held.
•CONSOL Energy's restricted stock and performance share units awarded to CNX employees under the Performance Share Program were adjusted to provide holders 1.15504 restricted shares or performance share units of CNX stock for every one restricted share or performance share unit of CONSOL Energy stock.
•CONSOL Energy's restricted stock and performance share units awarded to CEIX employees were adjusted to provide holders .71890 restricted shares or performance share units of CEIX stock for every one restricted share or performance share unit of CONSOL Energy stock.

The separation resulted in a modification of the equity plans but did not have a material impact on the financial statements as of December 31, 2017.

In March 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update on stock compensation that was intended to simplify and improve the accounting and statement of cash flow presentation for income taxes at settlement, forfeitures, and net settlements for withholding tax. The guidance is effective for public entities for fiscal years beginning after December 15, 2016. In accordance with this Update, $4,867 of additional income tax expense was recognized in the Consolidated Statements of Income for the year ended December 31, 2017. Also in accordance with this Update, the value of shares withheld for employee tax withholding purposes of $6,681 and $1,649 for the years ended December 31, 2017 and 2016 were reclassified between Net Cash Provided by Operating Activities and Net Cash Used in Financing Activities of the Consolidated


101


Statements of Cash Flows. As permitted by this Update, the Company has elected to account for forfeitures of stock compensation as they occur. The cumulative effect of the policy election to recognize forfeitures as they occur was nominal.
Stock Options:
CONSOL EnergyCNX examined its historical pattern of option exercises in an effort to determine if there were any discernable activity patterns based on certain employee populations. From this analysis, CONSOL EnergyCNX identified two distinct employee populations and used the Black-Scholes option pricing model to value the options for each of the employee populations. The expected term computation presented in the table below is based upon a weighted average of the historical exercise patterns and post-vesting termination behavior of the two populations. The risk-free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S. Treasury obligations for the expected term of the award. The expected forfeiture rate is based upon historical forfeiture activity. A combination of historical and implied volatility is used to determine expected volatility and future stock price trends. The total fair value of options granted during the yearyears ended December 31, 2017 and 2016 was $353 and $19,305, respectively, based on the following assumptions and weighted average fair values:
 December 31, December 31,
 2016 20172016
Weighted average fair value of grants $5.73
 $6.19
$5.73
Risk-free interest rate 1.13% 1.66%1.13%
Expected dividend yield 0.27% —%0.27%
Expected forfeiture rate 2.00% —%2.00%
Expected volatility 61.09% 50.85%61.09%
Expected term in years 4.90
 3.71
4.90
CONSOL EnergyCNX did not grant stock option awards during the yearsyear ended December 31, 2015 or 2014.




138


2015.
A summary of the status of stock options granted is presented below:
   Weighted     Weighted  
   Average     Average  
   Weighted Remaining Aggregate   Weighted Remaining Aggregate
   Average Contractual Intrinsic   Average Contractual Intrinsic
   Exercise Term (in Value (in   Exercise Term (in Value (in
 Shares Price years) thousands) Shares Price years) thousands)
Balance at December 31, 2015 3,621,002
 $43.15    
Balance at December 31, 2016 6,208,813
 $43.12    
Granted 3,369,197
 $4.22     56,947
 $15.69    
Exercised —
 —     (126,221) $7.94    
Forfeited (781,386) $36.32    
Balance at December 31, 2016 6,208,813
 $22.88 6.02
 $—
Forfeited/Expired (778,413) $30.77    
Awards granted in conversion, as a result of the separation 831,189
 $21.50    
Balance at December 31, 2017 6,192,315
 $21.51 5.60
 $—
Vested 2,990,263
 $43.12 2.57
 $—
 4,332,383
 $27.81 4.42
 $—
Exercisable at December 31, 2016 2,990,263
 $43.12 2.57
 $—
Exercisable at December 31, 2017 4,187,408
 $28.38 4.33
 $—
At December 31, 2016,2017, there are 5,888,0755,756,074 employee stock options outstanding under the Equity Incentive Plan. Non-employee director stock options vest one year after the grant date. There are 320,738 fully vested436,241 stock options outstanding under these grants.

The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CONSOL Energy'sCNX's closing stock price on the last trading day of the year ended December 31, 20162017 and the option's exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2016.2017. This amount varies based on the fair market value of CONSOL Energy's stock. No options were exercised during the year ended December 31, 2016. TheCNX's stock.The total intrinsic value of options exercised for the years ended December 31, 2017, 2016 and 2015 was $1,067, $0 and 2014 was $2,744 and $14,545,$2,744, respectively.

Cash received from option exercises for the years ended December 31, 2017, 2016 and 2015 was $1,002, $0, and 2014 was $8,281 and $15,011,$8,281, respectively. The tax impact from option exercises totaled $208$205, $0, and $2,629$208 for the years ended December 31, 2017, 2016 and 2015, and 2014, respectively. This excess tax benefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.


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Restricted Stock Units:

Under the Equity Incentive Plan, CONSOL EnergyCNX grants certain employees and non-employee directors restricted stock unitRSU awards, which entitle the holder to receive shares of common stock as the award vests. Non-employee director restricted stock unitsRSUs vest at the end of one year. In 2014, restricted stock units were granted that will vest over a five year period unless certain market conditions are met, in which the award will accelerate. Compensation expense is recognized over the vesting period of the units, described above. The total fair value of restricted stock unitsRSUs granted during the years ended December 31, 2017, 2016 and 2015 was $14,328, $493 and 2014 was $493, $26,550 and $31,360,$26,550, respectively. The total fair value of restricted stock units vested during the years ended December 31, 2017, 2016 and 2015 was $12,805, $19,095 and 2014 was $19,095, $20,793 and $15,686,$20,793, respectively. The following table represents the nonvested restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant:
 Number of Weighted Average Number of Weighted Average
 Shares Grant Date Fair Value Shares Grant Date Fair Value
Nonvested at December 31, 2015 1,303,573
 $32.60
Nonvested at December 31, 2016 663,003
 $31.97
Granted 27,379
 $17.99 863,483
 $16.59
Vested (579,246) $32.97 (408,117) $31.38
Forfeited (88,703) $30.42 (54,823) $20.67
Nonvested at December 31, 2016 663,003
 $31.97
RSUs surrendered as a result of the separation (253,959) $21.14
RSUs granted in conversion, as a result of the separation 127,875
 $16.02
Nonvested at December 31, 2017 937,462
 $16.01
Performance Share Units:
Under the Equity Incentive Plan, CONSOL EnergyCNX grants certain employees performance share unit awards, which entitle the holder to shares of common stock subject to the achievement of certain market and performance goals. Compensation expense is recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. For the PSUs issued in 2014 and 2015, achievement of the market goals is not probable, but achievement of the performance goals is probable.


139


Achievement of the market goals is probable for the first tranche of the PSUs issued in 2016. The total fair value of performance share units granted during the years ended December 31, 2017, 2016 and 2015 was $9,789, $24,283 and 2014 was $24,283, $18,771 and $11,853,$18,771, respectively. No performance share units vested during the year ended December 31, 2016. The total fair value of performance share units vested during the years ended December 31, 2017, 2016 and 2015 was $17,646, $0 and 2014 was $20,083, and $18,759, respectively. The following table represents the nonvested performance share units and their corresponding fair value (based upon the closing share price) on the date of grant:
 Number of Weighted Average Number of Weighted Average
 Shares Grant Date Fair Value Shares Grant Date Fair Value
Nonvested at December 31, 2015 491,493
 $27.83
Nonvested at December 31, 2016 1,424,551
 $26.41
Granted 950,404
 $25.55 447,691
 $21.87
PSUs issued as a result of 200% payout 187,062
 $25.80
Vested —
 — (560,960) $31.46
Forfeited (17,346) $19.62 (16,124) $20.65
Nonvested at December 31, 2016 1,424,551
 $26.41
PSUs surrendered as a result of the separation (379,893) $24.04
PSUs granted in conversion, as a result of the separation 170,715
 $25.53
Nonvested at December 31, 2017 1,273,042
 $25.53
Performance Options:
Under the Equity Incentive Plan in 2010, CONSOL EnergyCNX granted certain employees performance options, which entitled the holder to shares of common stock subject to the achievement of certain performance goals. Compensation expense was recognized over the vesting period of the options, described above.options. The Black-Scholes option valuation model was used to value each tranche separately. No performance options were granted in 2016, 2015, or 2014. No performance options vested in2017, 2016, or 2015. The total fair value of performance options vested during the year ended December 31, 2014 was $4,949. A summary of the status of performance options granted is presented below:
      Weighted  
      Average  
    Weighted Remaining Aggregate
    Average Contractual Intrinsic
    Exercise Term (in Value (in
  Shares Price years) thousands)
Balance at December 31, 2015 802,804
 $45.05    
Granted —
 —    
Exercised —
 —    
Forfeited —
 —    
Balance at December 31, 2016 802,804
 $45.05 3.42
 $—
Vested 802,804
 $45.05 3.42
 $—
Exercisable at December 31, 2016 802,804
 $45.05 3.42
 $—
CONSOL Stock Units:

Under the Equity Incentive Plan in 2013, CONSOL Energy granted certain employees CONSOL Stock Unit Awards, which entitled the holder to shares of common stock subject to the achievement of certain market and performance goals. Compensation expense was recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. CONSOL Energy used the Monte Carlo methodology to estimate the fair value of the CONSOL Stock Units. The achievement of the market and performance goals was not attained and therefore, all shares were forfeited in 2016. No CONSOL Stock Units were granted in 2016. The total fair value of CONSOL Stock Units granted during the years ended December 31, 2015 and 2014 was $110 and $189 respectively. The following table represents the nonvested CONSOL Stock Unit awards and their corresponding fair value at the grant date:
  Number of Weighted Average
  Shares Grant Date Fair Value
Nonvested at December 31, 2015 803,998
 $33.68
Granted —
 —
Forfeited (803,998) $33.68
Nonvested at December 31, 2016 —
 —



140103


      Weighted  
      Average  
    Weighted Remaining Aggregate
    Average Contractual Intrinsic
    Exercise Term (in Value (in
  Shares Price years) thousands)
Balance at December 31, 2016 802,804
 $45.05    
Granted —
 —    
Exercised —
 —    
Forfeited/Expired —
 —    
Options granted in conversion, as a result of the separation 124,464
0.04
$39.00    
Balance at December 31, 2017 927,268
 $39.00 2.42
 $—
Vested 927,268
 $39.00 2.42
 $—
Exercisable at December 31, 2017 927,268
 $39.00 2.42
 $—

NOTE 18—14—SUPPLEMENTAL CASH FLOW INFORMATION:
The following are non-cash transactions that impact the investing and financing activities of CONSOL Energy.CNX. For non-cash transactions that relate to the separation, as well as, acquisitions and dispositions, see Note 2 - Discontinued Operations and Note - 3 Acquisitions and Dispositions.
CONSOL EnergyCNX obtains capital lease arrangements for company-used vehicles. For the years ended December 31, 2017, 2016 amounts were nominal and for the year ended December 31, 2015, and 2014, CONSOL EnergyCNX entered into non-cash capital lease arrangements of $55, $4,973 and $1,540, respectively.$4,241.

As of December 31, 2017, 2016 and 2015, and 2014, CONSOL EnergyCNX purchased goods and services related to capital projects in the amount of $6,706, $24,347$2,379, $5,501 and $68,800,$25,827, respectively, which are included in accounts payable.

The following table shows cash paid (received) during the year for:
 For the Years Ended December 31, For the Years Ended December 31,
 2016 2015 2014 2017 2016 2015
Interest (net of amounts capitalized) $186,924
 $207,094
 $233,631
 $152,047
 $186,924
 $207,094
Income taxes $(18,032) $(59,584) $(81,962) $(121,773) $(18,032) $(59,584)
NOTE 19—15—CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS:
CONSOL EnergyCNX markets natural gas primarily to gas wholesalers and thermal coal principally to electric utilities in the United States.
Concentration of credit risk is summarized below:
  December 31,
  2016 2015
Gas wholesalers $124,509
 $72,664
Thermal coal utilities 62,525
 58,281
Coal brokers and distributors 28,955
 14,435
Other 4,233
 6,003
Total Accounts Receivable Trade $220,222
 $151,383
No sales to any E&P or coal customer exceeded 10% of the Company's revenues during the year ended December 31, 2016.
  December 31,
  2017 2016
Gas Wholesalers $126,387
 $95,826
NGL, Condensate & Processing Facilities

 29,841
 27,468
Other 589
 1,220
Total Accounts Receivable Trade $156,817
 $124,514
During the year ended December 31, 2015, coal2017 sales to DukeDirect Energy Business Marketing LLC were $242,020,$153,565 and sales to NJR Energy Services Company were $147,595, each of which comprises over 10% of sales.
During the year ended December 31, 2016, sales to NJR Energy Services Company were $106,280, which comprised over 10% of the Company's revenues.
During the year ended December 31, 2014, E&P2015, sales to NJR Energy Services Company were $295,779,$131,299, which comprised over 10% of the Company's revenues.



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NOTE 20—16—FAIR VALUE OF FINANCIAL INSTRUMENTS:
CONSOL EnergyCNX determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including NYMEX forward curves, LIBOR-based discount rates and basis forward curves), while unobservable inputs reflect the Company's own assumptions of what market participants would use.
The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below:
Level One - Quoted prices for identical instruments in active markets.
Level Two - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs, including NYMEX forward curves, LIBOR-based discount rates and basis forward curves.


141


Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity. The significant unobservable inputs used in the fair value measurement of the Company's third party guarantees are the credit risk of the third party and the third party surety bond markets. A significant increase or decrease in these values, in isolation, would have a directionally similar effect resulting in higher or lower fair value measurement of the Company's Level 3 guarantees.
In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.
The financial instrumentsinstrument measured at fair value on a recurring basis areis summarized below:
Fair Value Measurements at
December 31, 2016		 Fair Value Measurements at
December 31, 2015		Fair Value Measurements at
December 31, 2017		 Fair Value Measurements at
December 31, 2016
DescriptionLevel 1 Level 2 Level 3 Level 1 Level 2 Level 3Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Gas Derivatives$—
 $(188,156) $—
 $—
 $266,558
 $—
$—
 $59,949
 $—
 $—
 $(188,156) $—
Murray Energy Guarantees$—
 $—
 $(1,362) $—
 $—
 $(1,228)
Put Option$—
 $(3,500) $—
 $—
 $—
 $—
The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:

Cash and cash equivalents: The carrying amount reported in the balance sheetsConsolidated Balance Sheets for cash and cash equivalents approximates its fair value due to the short-term maturity of these instruments.

Short-term notes payable: The carrying amount reported in the Consolidated Balance Sheets for short-term notes payable approximates its fair value due to the short-term maturity of these instruments.

Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses. The discounted cash flow analyses are based on current market rates for instruments with similar cash flows.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
December 31, 2016 December 31, 2015December 31, 2017 December 31, 2016
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Cash and Cash Equivalents$60,475
 $60,475
 $72,574
 $72,574
$509,167
 $509,167
 $46,299
 $46,299
Short-Term Notes Payable$—
 $—
 $952,000
 $952,000
Long-Term Debt$2,752,371
 $2,717,582
 $2,738,735
 $1,808,936
$2,204,825
 $2,281,282
 $2,445,828
 $2,422,247
Cash and cash equivalents represent highly-liquid instruments and constitute Level 1 fair value measurements. Certain of the Company’s debt is actively traded on a public market and, as a result, constitute Level 1 fair value measurements. The portion of the Company’s debt obligations that areis not actively traded areis valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.



105


NOTE 21—17—DERIVATIVE INSTRUMENTS:

CONSOL EnergyCNX enters into financial derivative instruments to manage its exposure to commodity price volatility. CONSOL Energy de-designated all of its cash flow hedges on December 31, 2014 and accounts for all existing and futureThese natural gas and NGL commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings. In connection with this de-designation, CONSOL Energy froze the balances recorded in Accumulated Other Comprehensive Income at December 31, 2014 and reclassified balances to earnings as the underlying physical transactions occurred. As of December 31, 2016, all gains deferred in OCI have been recognized in earnings.

CONSOL EnergyCNX is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.

None of the Company's counterparty master agreements currently require CONSOL EnergyCNX to post collateral for any of its positions. However, as stated in the counterparty master agreements, if CONSOL Energy'sthe Company's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CONSOL EnergyCNX would have to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's


142


derivative instruments are subject to master netting arrangements with ourits counterparties. CONSOL EnergyCNX recognizes all financial derivative instruments as either assets or liabilities at fair value on the Consolidated Balance Sheets on a gross basis.

Each of CONSOL Energy'sthe Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CONSOL EnergyCNX and the applicable counterparty would net settle all open hedge positions.

The total notional amounts of production of CONSOL Energy'sthe Company's derivative instruments at December 31, 20162017 and December 31, 20152016 were as follows:
December 31, Forecasted toDecember 31, Forecasted to
2016 2015 Settle Through2017 2016 Settle Through
Natural Gas Commodity Swaps (Bcf)744.7
 456.1
 20211,067.2
 744.7
 2022
Natural Gas Basis Swaps (Bcf)482.0
 124.4
 2020688.1
 482.0
 2022
Propane Commodity Swaps (Mbbls)126.0
 —
 2017—
 126.0
 —

The gross fair value of CONSOL Energy'sthe Company's derivative instruments at December 31, 20162017 and December 31, 20152016 were as follows:
Asset Derivative Instruments Liability Derivative Instruments
 December 31,  December 31,
 2016 2015  2016 2015
Commodity Swaps:       
Prepaid Expense$16
 $234,409
 Other Accrued Liabilities$209,980
 $—
Other Assets29,596
 44,539
 Other Liabilities67,139
 5,137
Total Asset$29,612
 $278,948
 Total Liability$277,119
 $5,137
         
Basis Only Swaps:        
Prepaid Expense$56,916
 $5,429
 Other Accrued Liabilities$21,593
 $12,206
Other Assets35,603
 1,093
 Other Liabilities11,575
 1,569
Total Asset$92,519
 $6,522
 Total Liability$33,168
 $13,775













Asset Derivative Instruments Liability Derivative Instruments
 December 31,  December 31,
 2017 2016  2017 2016
Commodity Swaps:       
Prepaid Expense$62,369
 $16
 Other Accrued Liabilities$5,985
 $209,980
Other Assets59,281
 29,596
 Other Liabilities42,419
 67,139
Total Asset$121,650
 $29,612
 Total Liability$48,404
 $277,119
         
Basis Only Swaps:        
Prepaid Expense$14,965
 $56,916
 Other Accrued Liabilities$35,306
 $21,593
Other Assets24,223
 35,603
 Other Liabilities17,179
 11,575
Total Asset$39,188
 $92,519
 Total Liability$52,485
 $33,168














143106




The effect of derivative instruments on CONSOL Energy'sthe Company's Consolidated Statements of Income was as follows:
 Year Ended December 31,
 2016 2015 2014
Cash Received (Paid) in Settlement of Commodity Derivative Instruments:     
  Commodity Swaps:     
    Natural Gas$225,797
 $193,976
 $19,025
    Propane(650) —
 —
  Natural Gas Basis Swaps20,065
 2,372
 —
Total Cash Received in Settlement of Commodity Derivative Instruments245,212
 196,348
 19,025
      
Unrealized (Loss) Gain on Commodity Derivative Instruments:     
  Commodity Swaps:     
    Natural Gas(520,170) 81,142
 —
    Propane(1,148) —
 —
  Natural Gas Basis Swaps66,604
 (7,653) —
  Reclassified from Accumulated OCI68,481
 123,105
 —
  Gain Recognized for Ineffectiveness*—
 —
 4,168
Total Unrealized (Loss) Gain on Commodity Derivative Instruments(386,233) 196,594
 4,168
      
(Loss) Gain on Commodity Derivative Instruments:     
  Commodity Swaps:     
    Natural Gas$(294,373) $275,118
 $19,025
    Propane(1,798) —
 —
  Natural Gas Basis Swaps86,669
 (5,281) —
  Reclassified from Accumulated OCI68,481
 123,105
 —
  Gain Recognized for Ineffectiveness*—
 —
 4,168
Total (Loss) Gain on Commodity Derivative Instruments$(141,021) $392,942
 $23,193
* No amounts were excluded from effectiveness testing of cash flow hedges.
 For the Years Ended December 31,
 2017 2016 2015
Cash (Paid) Received in Settlement of Commodity Derivative Instruments:     
  Commodity Swaps:     
    Natural Gas$(34,928) $225,797
 $193,976
    Propane(1,216) (650) —
  Natural Gas Basis Swaps(5,030) 20,065
 2,372
Total Cash (Paid) Received in Settlement of Commodity Derivative Instruments(41,174) 245,212
 196,348
      
Unrealized Gain (Loss) on Commodity Derivative Instruments:     
  Commodity Swaps:     
    Natural Gas319,605
 (520,170) 81,142
    Propane1,147
 (1,148) —
  Natural Gas Basis Swaps(72,648) 66,604
 (7,653)
  Reclassified from Accumulated OCI—
 68,481
 123,105
Total Unrealized Gain (Loss) on Commodity Derivative Instruments248,104
 (386,233) 196,594
      
Gain (Loss) on Commodity Derivative Instruments:     
  Commodity Swaps:     
    Natural Gas$284,677
 $(294,373) $275,118
    Propane(69) (1,798) —
  Natural Gas Basis Swaps(77,678) 86,669
 (5,281)
  Reclassified from Accumulated OCI—
 68,481
 123,105
Total Gain (Loss) on Commodity Derivative Instruments$206,930
 $(141,021) $392,942
    
Changes in Accumulated OCI, net of tax, attributable to cash flow hedges that were de-designated December 31, 2014 were as follows:
 Year Ended December 31, For the Years Ended December 31,
2016 2015 2014 2016 2015
Beginning Balance – Accumulated OCIBeginning Balance – Accumulated OCI$43,470
 $121,521
 $42,493
Beginning Balance – Accumulated OCI$43,470
 $121,521
Gain Recognized in Accumulated OCI—
 —
 97,316
Gain Reclassified from Accumulated OCI (Net of tax: $25,011, $45,054, $10,465)(43,470) (78,051) (18,288)
Gain Reclassified from Accumulated OCI (Net of tax: $25,011, $45,054)Gain Reclassified from Accumulated OCI (Net of tax: $25,011, $45,054)(43,470) (78,051)
Ending Balance – Accumulated OCIEnding Balance – Accumulated OCI$—
 $43,470
 $121,521
Ending Balance – Accumulated OCI$—
 $43,470

The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. These physical commodity contracts qualify for the normal purchases and sales exception and are not subject to derivative instrument accounting.


107


NOTE 22—18—COMMITMENTS AND CONTINGENT LIABILITIES:

CONSOL EnergyCNX and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. CONSOL EnergyCNX accrues the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CONSOL Energy.CNX. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CONSOL Energy;CNX; however, such amounts cannot be reasonably estimated. The amount claimed against CONSOL EnergyCNX is disclosed below when an amount is expressly stated in the lawsuit or claim, which is not often the case. The maximum aggregate amount claimed in those lawsuits and claims, regardless of probability, where a claim is expressly stated or can be estimated, exceeds the aggregate amounts accrued for all lawsuits and claims by approximately $937,421.

The following lawsuits and claims include those for which a loss is probable and an accrual has been recognized.


144


recognized:

Hale Litigation: This class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia. The putative class consists of force-pooled unleased gas owners whose ownership of the coalbed methane (CBM) gas was declared to be in conflict with rights of others. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on allegations CNX Gas Company failed to either pay royalties due to conflicting claimants or deemed lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, which CNX opposed. On March 29, 2017, the Court issued an Order certifying four issues for class treatment: (1) allegedly excessive deductions; (2) royalties based on purported improperly low prices; (3) deduction of severance taxes; and (4) Plaintiffs' request for an accounting. On April 13, 2017, CNX filed a Petition for Allowance of Appeal with the Fourth Circuit, and on June 23, 2015,May 22, 2017 the Petition was denied. CNX Gas Company filed its Oppositionand plaintiffs’ counsel have reached an agreement in principal to same. The Court held a hearing onsettle the Motion on September 18, 2015 and has not yet ruled. CONSOL Energy continuescertified class claims, subject to believe this action cannot properly proceed as a class action in any form, believes the case has meritorious defenses, and intends to defend it vigorously.court approval. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL EnergyCNX and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

Addison Litigation: This class action lawsuit was filed on April 28, 2010 in the U.S. District Court in Abingdon, Virginia. The putative class consists of gas lessors whose gas ownership is in conflict. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on the allegations that CNX Gas Company failed to either pay royalties due to these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, which CNX opposed. On March 29, 2017, the Court issued an Order denying class certification in this matter. CNX and on June 23, 2015, CNX Gas Company filed its Oppositionplaintiff’s counsel have reached an agreement in principal to same. The Court held a hearing on the Motion on September 18, 2015 and has not yet ruled. CONSOL Energy continues to believesettle this action cannot properly proceed as a class action in any form, believes the case has meritorious defenses, and intends to defend it vigorously.lawsuit. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL EnergyCNX and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

The following royalty, land rights and other lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly, an accrual may not have been recognized. These claims are influenced by many factors which prevent the estimation of a range of potential loss. These factors include, but are not limited to, generalized allegations of unspecified damages (such as improper deductions), discovery having not commenced or not having been completed, unavailability of expert reports on damages and non-monetary issues being tried. For example, in instances where a gas lease termination is sought, damages would depend on speculation as to if and when the gas production would otherwise have occurred, how many wells would have been drilled on the lease premises, what their production would be, what the cost of production would be, and what the price of gas would be during the production period. An estimate is calculated, if applicable, when sufficient information becomes available.

Fitzwater Litigation: Two nonunion retired coal miners have sued CONSOL Energy Inc., Fola Coal Company and Consolidation Coal Company in West Virginia Federal Court alleging ERISA violations in the termination of retiree health care benefits. The Plaintiffs contend they relied to their detriment on oral statements and promises of "lifetime health benefits" allegedly made by various members of management during Plaintiffs' employment and that they were allegedly denied access to Summary Plan Documents that clearly reserved to the Company the right to modify or terminate the CONSOL Energy Inc. Retiree Health and Welfare Plan. Plaintiffs request that retiree health benefits be reinstated and seek to represent a class of all nonunion retirees of CONSOL Energy and its subsidiaries. The Company believes it has meritorious defense and intends to vigorously defend this suit.

Virginia Mine Void Litigation: The Company is currently defending three lawsuits naming Consolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, and/or CONSOL Energy. The lawsuits were filed in the U.S. District Court for the Western District of Virginia. On October 26, 2015, the trial court granted summary judgment in favor of the defendants in two of the actions upon its finding that plaintiffs' claims are barred by the applicable statutes of limitation. Plaintiffs have appealed both cases to the U.S. Court of Appeals for the Fourth Circuit. Oral argument was held on December 8, 2016. The third case remains pending in the trial court. On January 26, 2016, six mine void lawsuits that have twice before been filed and voluntarily dismissed, were refiled for a third time in state court but have not been served. The Complaints seek damages and injunctive relief in connection with the transfer of water from mining activities at Buchanan Mine into void spaces in inactive ICCC mines adjacent to the Buchanan operations, voids ostensibly underlying plaintiffs’ properties. While some of the plaintiffs have an ownership interest in the coal, others have some interest in one or more of the fee, surface, oil/gas or other mineral estates. The suits allege the water storage precludes access to and has damaged coal, impeded coalbed methane gas production and was


145


made without compensation to the property owners. Plaintiffs seek recovery in tort, contract and trespass assumpsit (quasi-contract). The suits each seek damages between $50,000 and in excess of $100,000 plus punitive damages. The Company intends to vigorously defend these suits.
 
At December 31, 2016, CONSOL Energy2017, CNX has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties as described by major category in the following table. These amounts represent the maximum potential of total future payments that the Company could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guaranteesunconditional purchase obligations and letters of credit are recorded as liabilities in the financial statements. CONSOL EnergyCNX management believes that these guaranteescommitments will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.


108


Amount of Commitment Expiration Per PeriodAmount of Commitment Expiration Per Period
Total
Amounts
Committed
 
Less Than
1  Year
 1-3 Years 3-5 Years 
Beyond
5  Years
Total
Amounts
Committed
 
Less Than
1  Year
 1-3 Years 3-5 Years 
Beyond
5  Years
Letters of Credit:                  
Employee-Related$82,273
 $67,871
 $14,402
 $—
 $—
Environmental998
 600
 398
 —
 —
Firm Transportation$239,052
 $231,992
 $7,060
 $—
 $—
Other242,405
 228,313
 14,092
 —
 —
20
 20
 —
 —
 —
Total Letters of Credit325,676
 296,784
 28,892
 —
 —
239,072
 232,012
 7,060
 —
 —
Surety Bonds:                  
Employee-Related112,810
 111,510
 1,300
 —
 —
1,850
 1,850
 —
 —
 —
Environmental514,851
 483,604
 31,247
 —
 —
5,438
 4,178
 1,260
 —
 —
Other22,417
 21,591
 824
 2
 —
12,485
 10,823
 1,662
 —
 —
Total Surety Bonds650,078
 616,705
 33,371
 2
 —
19,773
 16,851
 2,922
 —
 —
Guarantees:                  
Other74,203
 41,285
 17,767
 13,401
 1,750
CONSOL Energy192,490
 59,809
 69,059
 41,047
 22,575
Total Guarantees74,203
 41,285
 17,767
 13,401
 1,750
192,490
 59,809
 69,059
 41,047
 22,575
Total Commitments$1,049,957
 $954,774
 $80,030
 $13,403
 $1,750
$451,335
 $308,672
 $79,041
 $41,047
 $22,575

Included in the above table are commitments and guarantees entered into in conjunction with the sale of Consolidation Coal Company and certain of its subsidiaries, which contain all five of its longwall coal mines in West Virginia, and its river operations to a subsidiary of Murray Energy Corporation (Murray Energy). As partspin-off of the sales agreement, CONSOL Energy has guaranteed certain equipment lease obligations andCompany's coal sales agreements that were assumed by Murray Energy. In the event that Murray Energy would default on the obligations defined in the agreements, CONSOL Energy would be required to perform under the guarantees. If CONSOL Energy would be required to perform, the stock purchase agreement provides various recourse actions. At December 31, 2016 and December 31, 2015, the fair value of these guarantees was $1,362 and $1,228, respectively, and are included in Other Accrued Liabilities on the Consolidated Balance Sheets. The fair value of certain of the guarantees was determined using CONSOL Energy’s risk-adjusted interest rate. Significant increases or decreases in the risk-adjusted interest rates may result in a significantly higher or lower fair value measurement. Coal sales agreement guarantees were valued based on an evaluation of coal market pricing compared to contracted sales price and includes an adjustment for nonperformance risk. No other amounts related to financial guarantees and letters of credit are recorded as liabilities in the financial statements. Significant judgment is required in determining the fair value of these guarantees. The guarantees of the leases and sales agreements are classified within Level 3 of the fair value hierarchy.

As part of the sale of Buchanan Minebusiness (See Note 2 - Discontinued Operations),. Although CONSOL Energy has guaranteed certain equipment lease obligationsagreed to indemnify us to the extent that were assumed by Coronado. In the eventwe are called upon to pay any of these liabilities, there is no assurance that Coronado would default on the obligations defined in the agreements, CONSOL Energy would be requiredwill satisfy its obligations to perform under the guarantees. indemnify us in these situations.

CONSOL Energy regularly evaluates the likelihood of default for all guarantees based on an expected loss analysis and records the fair value, if any, of its guarantees as an obligation in the consolidated financial statements. 
CONSOL Energy and CNX Gas Company enterenters into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase


146


obligations are not recorded on the Consolidated Balance Sheets. As of December 31, 2016,2017, the purchase obligations for each of the next five years and beyond were as follows:
 
Obligations DueAmountAmount
Less than 1 year$209,797
$181,303
1 - 3 years285,224
264,773
3 - 5 years243,534
237,625
More than 5 years622,509
513,744
Total Purchase Obligations$1,361,064
$1,197,445



109


NOTE 23—19—SEGMENT INFORMATION:

CONSOL Energy consists of two principal business divisions: Exploration and Production (E&P) and Pennsylvania (PA) Mining Operations. The principal activity of the E&P division,CNX, which includes four reportable segments, is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The E&P division'sCompany's reportable segments are Marcellus Shale, Utica Shale, Coalbed Methane, and Other Gas. The Other Gas segment is primarily related to shallow oil and gas production and the Chattanooga Shale in Tennessee, neither of which areis not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, impairment of exploration and production properties, as well as various other corporateoperating activities not allocated to each individual segment.
The Company's unallocated expenses include selling, general and administrative activities, as well as various other activities assigned to the E&P division but not allocated to each individual segment. The principal activitiesexpense, gain on sale of the PA Mining Operations division are mining, preparationassets, loss on debt extinguishment, interest expense and marketing of thermal coal, sold primarily to power generators. It also includes selling, general and administrative activities, as well as various other activities assigned to the PA Mining Operations division.
CONSOL Energy’s Other division includes expenses from various corporate and diversified business activities that are not allocated to the E&P or PA Mining Operations divisions. The diversified business activities include coal terminal operations, closed and idle mine activities, water operations, selling, general and administrative activities, as well as various other non-operated activities, none of which are individually significant to the Company. In previous periods, this division included activity from the sales of industrial supplies (this subsidiary was sold in December 2014).income taxes.
Prior to the salespin-off of the Buchanan Mine on March 31, 2016 and the Fola and Miller Creek Complexes on August 1, 2016 (seecoal company in November 2017 (See Note 2 - Discontinued Operations), CONSOL EnergyCNX had a Coal division. The Coal division had three reportable segments; PA Operations, Virginia (VA) Operations and Other Coal. The VA Operations segment included the Buchanan Mine and the Other Coal segment was primarily comprised of the assets and operations of the FolaMiller Creek and Miller CreekFola Complexes, as well as coal terminal operations, closed and idle mine activities, selling, general and administrative activities and various other non-operated activities. PA Operations now constitutes its own division and reportable segment and the remaining activity in the Other Coal segment became part of CONSOL Energy's diversified business activities in the Other division. Prior periods have been reclassified to align with current period presentation.
In the preparation of the following information, intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at the divisionTotal Operating level for E&P and are not allocated between each individual E&P segment. These assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy,CNX, whereby each individual asset may service more than one segment within the division.segment. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.
Industry segment results for the year ended December 31, 2017 are:
 
Marcellus
Shale
 Utica Shale 
Coalbed
Methane
 
Other
Gas
 Total Operating Unallocated Consolidated 
Natural Gas, NGLs and Oil Sales$646,188
 $217,020
 $208,677
 $53,339
 $1,125,224
 $—
 $1,125,224
(A)
(Loss) Gain on Commodity Derivative Instruments(30,336) 1,367
 (9,589) 245,488
 206,930
 —
 206,930
 
Purchased Gas Sales—
 —
 —
 53,795
 53,795
 —
 53,795
  
Other Operating Income—
 —
 —
 69,182
 69,182
 —
 69,182
(B)
Total Revenue and Other Operating Income$615,852
 $218,387
 $199,088
 $421,804
 $1,455,131
 $—
 $1,455,131
  
Earnings (Loss) From Continuing Operations Before Income Tax$91,436
 $64,741
 $20,346
 $14,603
 $191,126
 $(72,545) $118,581
 
Segment Assets        $6,122,746
 $809,167
 $6,931,913
(C)
Depreciation, Depletion and Amortization        $412,036
 $—
 $412,036
  
Capital Expenditures        $632,846
 $—
 $632,846
  
(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.










147110




Industry segment results for the year ended December 31, 2016 are:

 
Marcellus
Shale
 Utica Shale 
Coalbed
Methane
 
Other
Gas
 
Total
E&P
 PA Mining Operations Other 
Adjustments
and
Eliminations
 Consolidated 
Sales—Outside$414,484
 $163,112
 $174,323
 $41,329
 $793,248
 $1,065,582
 $—
 $—
 $1,858,830
 
Gain (Loss) on Commodity Derivative Instruments147,282
 29,285
 52,396
 (369,984) (141,021) —
 —
 —
 (141,021) 
Other Outside Sales—
 —
 —
 —
 —
 —
 32,038
 —
 32,038
 
Sales—Purchased Gas—
 —
 —
 43,256
 43,256
 —
 —
 —
 43,256
  
Freight—Outside—
 —
 —
 —
 —
 46,468
 —
 —
 46,468
  
Intersegment Transfers—
 —
 424
 —
 424
 —
 —
 (424) —
  
Total Sales and Freight$561,766
 $192,397
 $227,143
 $(285,399) $695,907
 $1,112,050
 $32,038
 $(424) $1,839,571
  
Earnings (Loss) From Continuing Operations
Before Income Tax		$72,141
 $28,390
 $37,999
 $(517,370) $(378,840) $130,708
 $(277,399) $(424) $(525,955)(A)
Segment Assets        $6,235,568
 $1,982,206
 $966,124
 $83
 $9,183,981
(B)
Depreciation, Depletion and Amortization        $417,853
 $168,195
 $12,455
 $—
 $598,503
  
Capital Expenditures        $165,101
 $50,809
 $10,910
 $—
 $226,820
  

 
Marcellus
Shale
 Utica Shale 
Coalbed
Methane
 
Other
Gas
 
Total
Operating
 Unallocated Consolidated 
Natural Gas, NGLs and Oil Sales$414,484
 $163,112
 $174,323
 $41,329
 $793,248
 $—
 $793,248
(D)
Gain (Loss) on Commodity Derivative Instruments147,282
 29,285
 52,396
 (369,984) (141,021) —
 (141,021) 
Purchased Gas Sales—
 —
 —
 43,256
 43,256
 —
 43,256
  
Other Operating Income—
 —
 —
 64,485
 64,485
 —
 64,485
(E)
Intersegment Transfers—
 —
 424
 (424) —
 —
 —
  
Total Revenue and Other Operating Income$561,766
 $192,397
 $227,143
 $(221,338) $759,968
 $—
 $759,968
  
Earnings (Loss) From Continuing Operations Before Income Tax$72,141
 $28,390
 $37,999
 $(446,327) $(307,797) $(277,551) $(585,348) 
Segment Assets        $6,238,156
 $2,941,535
 $9,179,691
(F)
Depreciation, Depletion and Amortization        $419,939
 $—
 $419,939
  
Capital Expenditures        $172,739
 $—
 $172,739
 
(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.





148




Industry segment results for the year ended December 31, 2015 are:

 
Marcellus
Shale
 Utica Shale 
Coalbed
Methane
 
Other
Gas
 
Total
E&P
 PA Mining Operations Other 
Adjustments
and
Eliminations
 Consolidated 
Sales—Outside$379,453
 $92,223
 $200,645
 $54,600
 $726,921
 $1,289,036
 $—
 $—
 $2,015,957
(C)
Gain on Commodity Derivative Instruments100,785
 6,430
 67,281
 218,446
 392,942
 —
 —
 —
 392,942
 
Other Outside Sales—
 —
 —
 —
 —
 —
 30,967
 —
 30,967
 
Sales—Purchased Gas—
 —
 —
 14,450
 14,450
 —
 —
 —
 14,450
  
Freight—Outside—
 —
 —
 —
 —
 20,499
 —
 —
 20,499
  
Intersegment Transfers—
 —
 1,538
 —
 1,538
 —
 —
 (1,538) —
  
Total Sales and Freight$480,238
 $98,653
 $269,464
 $287,496
 $1,135,851
 $1,309,535
 $30,967
 $(1,538) $2,474,815
  
Earnings (Loss) From Continuing Operations
Before Income Tax		$56,116
 $(19,428) $59,662
 $(775,207) $(678,857) $404,994
 $(200,304) $(1,538) $(475,705)(D)
Segment Assets        $6,892,284
 $2,076,301
 $939,497
 $1,021,820
 $10,929,902
(E)
Depreciation, Depletion and Amortization        $370,374
 $176,864
 $19,882
 $—
 $567,120
  
Capital Expenditures        $832,446
 $136,291
 $14,197
 $—
 $982,934
 

(C)(D)Included in the PA Mining Operations segmentTotal Operating are sales of $242,020$106,280 to DukeNJR Energy Services Company, which comprises over 10% of sales.
(D)(E)
Includes equity in earnings of unconsolidated affiliates of $46,614 and $8,283 for Total E&P and Other, respectively.
$53,078.
(E)(F)
Includes investments in unconsolidated equity affiliates of $234,803 and $2,527 for Total E&P and Other, respectively.
$190,964.























149



Industry segment results for the year ended December 31, 20142015 are:
 
Marcellus
Shale
 Utica Shale 
Coalbed
Methane
 
Other
Gas
 
Total
E&P
 PA Mining Operations Other 
Adjustments
and
Eliminations
 Consolidated 
Sales—Outside$457,679
 $86,948
 $340,739
 $119,558
 $1,004,924
 $1,616,874
 $—
 $—
 $2,621,798
(F)
Gain on Commodity Derivative Instruments14,764
 1,247
 4,103
 3,079
 23,193
 —
 —
 —
 23,193
 
Other Outside Sales—
 —
 —
 —
 —
 —
 276,242
 —
 276,242
 
Sales—Purchased Gas—
 —
 —
 8,999
 8,999
 —
 —
 —
 8,999
  
Freight—Outside—
 —
 —
 —
 —
 23,133
 —
 —
 23,133
  
Intersegment Transfers—
 —
 2,458
 —
 2,458
 —
 78,229
 (80,687) —
  
Total Sales and Freight$472,443
 $88,195
 $347,300
 $131,636
 $1,039,574
 $1,640,007
 $354,471
 $(80,687) $2,953,365
  
Earnings (Loss) From Continuing Operations
Before Income Tax		$171,902
 $43,645
 $108,107
 $(133,940) $189,714
 $430,968
 $(438,073) $(2,458) $180,151
(G)
Segment Assets        $7,364,185
 $2,094,041
 $1,186,874
 $1,009,546
 $11,654,646
(H)
Depreciation, Depletion and Amortization        $323,600
 $173,316
 $35,727
 $—
 $532,643
  
Capital Expenditures        $1,103,656
 $341,229
 $14,567
 $—
 $1,459,452
 
 
Marcellus
Shale
 Utica Shale 
Coalbed
Methane
 
Other
Gas
 
Total
Operating
 Unallocated Consolidated 
Natural Gas, NGLs and Oil Sales$379,453
 $92,223
 $200,645
 $54,600
 $726,921
 $—
 $726,921
(G)
Gain on Commodity Derivative Instruments100,785
 6,430
 67,281
 218,446
 392,942
 —
 392,942
 
Purchased Gas Sales—
 —
 —
 14,450
 14,450
 —
 14,450
  
Other Operating Income—
 —
 —
 64,424
 64,424
 —
 64,424
(H)
Intersegment Transfers��
 —
 1,538
 (1,538) —
 —
 —
  
Total Revenue and Other Operating Income$480,238
 $98,653
 $269,464
 $350,382
 $1,198,737
 $—
 $1,198,737
  
Earnings (Loss) From Continuing Operations Before Income Tax$56,116
 $(19,428) $59,662
 $(680,687) $(584,337) $(346,220) $(930,557) 
Segment Assets        $6,894,810
 $4,035,092
 $10,929,902
(I)
Depreciation, Depletion and Amortization        $371,783
 $—
 $371,783
  
Capital Expenditures        $840,349
 $—
 $840,349
 
(F) Included in the Total E&P segment are sales of $295,779 to NJR Energy Services Company, which comprises over 10% of sales.
(G)    Includes equity in earnings of unconsolidated affiliates of $32,217 and $17,574 for Total E&P and Other, respectively.
(H) Includes investments in unconsolidated equity affiliates of $121,721 and $31,237 for Total E&P and Other, respectively.

(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.



150111


Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Operating Income:
  For the Years Ended December 31,
  2016 2015 2014
Total Segment Sales and Freight from External Customers $1,980,592
 $2,081,873
 $2,930,172
(Loss) Gain on Commodity Derivative Instruments (141,021) 392,942
 23,193
Other Income not Allocated to Segments (Note 4) 167,306
 144,351
 207,460
Gain on Sale of Assets 19,498
 74,173
 43,198
Total Consolidated Revenue and Other Income $2,026,375
 $2,693,339
 $3,204,023
  For the Years Ended December 31,
  2017 2016 2015
Total Segment Sales from External Customers $1,179,019
 $836,504
 $741,371
Gain (Loss) on Commodity Derivative Instruments 206,930
 (141,021) 392,942
Other Income 69,182
 64,485
 64,424
Total Consolidated Revenue and Other Operating Income $1,455,131
 $759,968
 $1,198,737

Earnings (Loss) Earnings From Continuing Operations Before Income Tax:
  For the Years Ended December 31,
  2016 2015 2014
Segment (Loss) Income Before Income Taxes for reportable business segments $(248,132) $(273,863) $620,682
Segment (Loss) Income Before Income Taxes for all other business segments (85,923) 66,713
 (119,473)
Interest expense (191,476) (199,266) (223,333)
Eliminations (424) (1,538) (2,458)
Loss on debt extinguishment —
 (67,751) (95,267)
(Loss) Earnings From Continuing Operations Before Income Tax $(525,955) $(475,705) $180,151
  For the Years Ended December 31,
  2017 2016 2015
Segment Income (Loss) Before Income Taxes for Reportable Business Segments $191,126
 $(307,797) $(584,337)
Segment Loss Before Income Taxes for All Other Business Segments (97,036) (109,626) (140,496)
Gain on Sale of Assets 188,063
 14,270
 61,148
Interest Expense (161,443) (182,195) (199,121)
Loss on Debt Extinguishment (2,129) —
 (67,751)
Earnings (Loss) From Continuing Operations Before Income Tax $118,581
 $(585,348) $(930,557)

Total Assets:
  December 31,
 2016 2015
Segment assets for total reportable business segments $8,217,774
 $8,968,585
Segment assets for all other business segments 797,830
 859,675
Items excluded from segment assets:    
Cash and other investments 47,153
 65,935
Recoverable income taxes 116,851
 13,887
Deferred tax assets 4,290
 —
Discontinued Operations 83
 1,021,820
Total Consolidated Assets $9,183,981
 $10,929,902

















  December 31,
 2017 2016
Segment Assets for Total Reportable Business Segments $6,122,746
 $6,238,156
Segment Assets for All Other Business Segments 268,569
 283,917
Items Excluded from Segment Assets:    
Cash and Other Investments 509,075
 46,216
Recoverable Income Taxes 31,523
 114,481
Discontinued Operations —
 2,496,921
Total Consolidated Assets $6,931,913
 $9,179,691



151112


Enterprise-Wide Disclosures:

CONSOL Energy's Revenues by geographical location (I):
  For the Years Ended December 31,
  2016 2015 2014
United States $1,799,336
 $1,822,452
 $2,713,833
Asia 109,312
 106,954
 66,912
Europe 40,704
 112,844
 121,909
South America 25,406
 28,060
 19,013
Canada 5,834
 11,563
 8,505
Total Revenues and Freight from External Customers (J) $1,980,592
 $2,081,873
 $2,930,172
_________________________
(I) CONSOL Energy attributes revenue to individual countries based on the location of the customer.
(J) CONSOL Energy has contractual relationships with certain U.S. based customers who distribute coal to international markets. The table above reflects the ultimate destination of CONSOL Energy coal.

CONSOL Energy's Property, Plant and Equipment by geographical location:
  December 31,
  2016 2015
United States $8,129,415
 $8,721,682
Canada 11,024
 11,024
Discontinued Operations —
 936,671
Total Property, Plant and Equipment, net $8,140,439
 $9,669,377

NOTE 24—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:
The payment obligations under the $74,470, 8.250% per annum senior notes due April 1, 2020, the $20,611, 6.375% per annum senior notes due March 1, 2021, the $1,854,731, 5.875% per annum senior notes due April 15, 2022, and the $494,344, 8.000% per annum senior notes due April 1, 2023 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally, guaranteed by certain subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantor subsidiary, CNX Coal Resources LP (CNXC), a non-guarantor subsidiary, and the remaining guarantor and non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.
On September 30, 2016, CNXC acquired an additional 5% undivided interest in the Pennsylvania Mining Complex from CONSOL Energy, increasing their total undivided interest to 25%. To account for the acquisition, CNXC recast its consolidated financial statements to retrospectively reflect the additional 5% interest as if the business was owned for all periods presented. This resulted in corresponding retrospective adjustments between the Other Subsidiary Guarantors and the CNXC Non-Guarantor columns below. 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.



152


Income Statement for the Year Ended December 31, 2016:
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 CNXC Non-Guarantor 
Other
Subsidiary
Non-
Guarantors
 Elimination Consolidated
Revenues and Other Income:             
Natural Gas, NGLs and Oil Sales$—
 $793,672
 $—
 $—
 $—
 $(424) $793,248
Loss on Commodity Derivative Instruments—
 (141,021) —
 —
 —
 —
 (141,021)
Coal Sales—
 —
 799,187
 266,395
 —
 —
 1,065,582
Other Outside Sales—
 —
 32,038
 —
 —
 —
 32,038
Purchased Gas Sales—
 43,256
 —
 —
 —
 —
 43,256
Freight-Outside Coal—
 —
 34,865
 11,603
 —
 —
 46,468
Miscellaneous Other Income(712,927) 80,444
 83,735
 3,128
 —
 712,926
 167,306
Gain (Loss) on Sale of Assets—
 14,870
 4,637
 (9) —
 —
 19,498
Total Revenue and Other Income(712,927) 791,221
 954,462
 281,117
 —
 712,502
 2,026,375
Costs and Expenses:             
Exploration and Production Costs             
Lease Operating Expense—
 96,434
 —
 —
 —
 —
 96,434
Transportation, Gathering and Compression—
 374,350
 —
 —
 —
 —
 374,350
Production, Ad Valorem, and Other Fees—
 31,049
 —
 —
 —
 —
 31,049
Depreciation, Depletion and Amortization—
 417,853
 —
 —
 —
 —
 417,853
Exploration and Production Related Other Costs—
 14,519
 —
 —
 —
 —
 14,519
Purchased Gas Costs—
 42,717
 —
 —
 —
 —
 42,717
Other Corporate Expenses—
 87,913
 —
 —
 —
 —
 87,913
Selling, General and Administrative Costs—
 102,503
 —
 —
 —
 —
 102,503
Total Exploration and Production Costs—
 1,167,338
 —
 —
 —
 —
 1,167,338
PA Mining Operations Costs             
Operating and Other Costs—
 —
 550,299
 183,001
 —
 —
 733,300
Depreciation, Depletion and Amortization—
 —
 126,201
 41,994
 —
 —
 168,195
Freight Expense—
 —
 34,865
 11,603
 —
 —
 46,468
Selling, General and Administrative Costs—
 —
 27,563
 9,949
 —
 —
 37,512
Total PA Mining Operations Costs—
 —
 738,928
 246,547
 —
 —
 985,475
Other Costs             
Miscellaneous Operating Expense43,533
 —
 139,289
 —
 47
 —
 182,869
Selling, General and Administrative Costs—
 —
 12,717
 —
 —
 —
 12,717
Depreciation, Depletion and Amortization568
 —
 11,887
 —
 —
 —
 12,455
Interest Expense173,327
 2,723
 6,707
 8,719
 —
 —
 191,476
Total Other Costs217,428
 2,723
 170,600
 8,719
 47
 —
 399,517
Total Costs And Expenses217,428
 1,170,061
 909,528
 255,266
 47
 —
 2,552,330
(Loss) Earnings from Continuing Operations Before Income Tax(930,355) (378,840) 44,934
 25,851
 (47) 712,502
 (525,955)
Income Tax (Benefit) Expense(82,253) (150,551) 242,832
 —
 (18) —
 10,010
(Loss) Income From Continuing Operations(848,102) (228,289) (197,898) 25,851
 (29) 712,502
 (535,965)
Loss From Discontinued Operations, net—
 —
 —
 —
 (303,183) —
 (303,183)
Net (Loss) Income(848,102) (228,289) (197,898) 25,851
 (303,212) 712,502
 (839,148)
Less: Net Income Attributable to Noncontrolling Interest—
 —
 —
 —
 —
 8,954
 8,954
Net (Loss) Income Attributable to CONSOL Energy Shareholders$(848,102) $(228,289) $(197,898) $25,851
 $(303,212) $703,548
 $(848,102)



153


Balance Sheet at December 31, 2016:
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 CNXC
Non-Guarantor		 Other Subsidiary
Non-Guarantors		 Elimination Consolidated
Assets:             
Current Assets:             
Cash and Cash Equivalents$49,722
 $83
 $—
 $9,785
 $885
 $—
 $60,475
Accounts and Notes Receivable:             
Trade—
 124,509
 72,295
 23,418
 —
 —
 220,222
Other Receivables20,097
 34,773
 14,516
 515
 —
 —
 69,901
Inventories—
 15,301
 38,669
 11,491
 —
 —
 65,461
Recoverable Income Taxes175,877
 (59,026) —
 —
 —
 —
 116,851
Prepaid Expenses12,828
 60,500
 16,306
 3,512
 —
 —
 93,146
Current Assets of Discontinued Operations—
 —
 —
 —
 83
 —
 83
Total Current Assets258,524
 176,140
 141,786
 48,721
 968
 —
 626,139
Property, Plant and Equipment:             
Property, Plant and Equipment114,611
 8,851,226
 3,928,861
 876,690
 —
 —
 13,771,388
Less-Accumulated Depreciation, Depletion and Amortization84,788
 3,106,296
 1,997,687
 442,178
 —
 —
 5,630,949
Total Property, Plant and Equipment-Net29,823
 5,744,930
 1,931,174
 434,512
 —
 —
 8,140,439
Other Assets:             
Deferred Income Taxes25,904
 (21,614) —
 —
 —
 —
 4,290
Investment in Affiliates7,974,260
 188,376
 27,269
 —
 —
 (7,998,941) 190,964
Other19,960
 67,096
 114,030
 21,063
 —
 —
 222,149
Total Other Assets8,020,124
 233,858
 141,299
 21,063
 —
 (7,998,941) 417,403
Total Assets$8,308,471
 $6,154,928
 $2,214,259
 $504,296
 $968
 $(7,998,941) $9,183,981
Liabilities and Equity:             
Current Liabilities:             
Accounts Payable$48,666
 $127,309
 $36,039
 $18,797
 $—
 $10,805
 $241,616
Accounts Payable (Recoverable)-Related Parties1,832,908
 1,034,138
 (2,648,416) 1,666
 (209,491) (10,805) —
Current Portion of Long-Term Debt1,533
 6,369
 4,010
 88
 —
 —
 12,000
Other Accrued Liabilities75,039
 337,374
 223,705
 44,230
 —
 —
 680,348
Current Liabilities of Discontinued Operations—
 —
 —
 —
 6,050
 —
 6,050
Total Current Liabilities1,958,146
 1,505,190
 (2,384,662) 64,781
 (203,441) —
 940,014
Long-Term Debt:2,421,511
 26,884
 115,685
 197,989
 —
 —
 2,762,069
Deferred Credits and Other Liabilities:             
Postretirement Benefits Other Than Pensions—
 —
 659,474
 —
 —
 —
 659,474
Pneumoconiosis Benefits—
 —
 106,016
 2,057
 —
 —
 108,073
Mine Closing—
 —
 209,384
 9,247
 —
 —
 218,631
Gas Well Closing—
 195,704
 27,549
 99
 —
 —
 223,352
Workers’ Compensation—
 —
 64,187
 3,090
 —
 —
 67,277
Salary Retirement112,543
 —
 —
 —
 —
 —
 112,543
Other17,876
 117,658
 15,663
 463
 —
 —
 151,660
Total Deferred Credits and Other Liabilities130,419
 313,362
 1,082,273
 14,956
 —
 —
 1,541,010
Total CONSOL Energy Inc. Stockholders’ Equity3,798,395
 4,309,492
 3,400,963
 226,570
 204,409
 (8,141,434) 3,798,395
Noncontrolling Interest—
 —
 —
 —
 —
 142,493
 142,493
Total Liabilities and Equity$8,308,471
 $6,154,928
 $2,214,259
 $504,296
 $968
 $(7,998,941) $9,183,981




154


Condensed Statement of Cash Flows for the Year Ended December 31, 2016:
 Parent Issuer 
CNX Gas
Guarantor
 Other Subsidiary Guarantors CNXC Non-Guarantor 
Other
Subsidiary Non-Guarantors

 Elimination Consolidated
Net Cash Provided by (Used in) Continuing Operating Activities$943,652
 $(165,861) $58,648
 $73,098
 $(377,257) $(72,930) $459,350
Net Cash Provided by Discontinued Operating Activities—
 —
 —
 —
 9,935
 —
 9,935
Net Cash Provided by (Used in) Operating Activities$943,652
 $(165,861) $58,648
 $73,098
 $(367,322) $(72,930) $469,285
Cash Flows from Investing Activities:             
Capital Expenditures$(2,990) $(165,101) $(46,025) $(12,704) $—
 $—
 $(226,820)
CNXC Acquisition of 5% Pennsylvania Mining Complex—
 —
 21,500
 (21,500) —
 —
 —
Proceeds from Noble Exchange Settlement—
 213,295
 —
 —
 —
 —
 213,295
Proceeds From Sales of Assets—
 44,710
 15,169
 23
 —
 —
 59,902
Net Investments in Equity Affiliates—
 79,103
 (5,360) —
 —
 —
 73,743
Net Cash (Used in) Provided by Continuing Investing Activities(2,990) 172,007
 (14,716) (34,181) —
 —
 120,120
Net Cash Provided by Discontinued Investing Activities—
 —
 —
 —
 367,251
 —
 367,251
Net Cash (Used in) Provided by Investing Activities$(2,990) $172,007
 $(14,716) $(34,181) $367,251
 $—
 $487,371
Cash Flows from Financing Activities:             
Payments on Short-Term Borrowings$(952,000) $—
 $—
 $—
 $—
 $—
 $(952,000)
Payments on Miscellaneous Borrowings(1,645) (6,138) (450) (79) —
 —
 (8,312)
Proceeds from Revolver - MLP—
 —
 —
 16,000
 —
 —
 16,000
Distributions of Noncontrolling Interest—
 —
 —
 (42,634) —
 20,977
 (21,657)
Net Change in Parent Advancements—
 —
 —
 (8,953) —
 8,953
 —
Dividends Paid(2,294) —
 —
 —
 —
 —
 (2,294)
Proceeds from Issuance of Common Stock4
 —
 —
 —
 —
 —
 4
Debt Issuance and Financing Fees—
 —
 (482) —
 —
 —
 (482)
Net Cash (Used in) Provided by Continuing Financing Activities(955,935) (6,138) (932) (35,666) —
 29,930
 (968,741)
Net Cash Used in Discontinued Financing Activities—
 —
 —
 —
 (14) —
 (14)
Net Cash (Used in) Provided by Financing Activities$(955,935) $(6,138) $(932) $(35,666) $(14) $29,930
 $(968,755)


155


Statement of Comprehensive Income for the Year Ended December 31, 2016:
 Parent Issuer 
CNX Gas
Guarantor
 Other Subsidiary Guarantors CNXC Non-
Guarantor		 
Other Subsidiary Non-
Guarantors
 Elimination Consolidated
Net (Loss) Income$(848,102) $(228,289) $(197,898) $25,851
 $(303,212) $712,502
 $(839,148)
Other Comprehensive (Loss) Income:             
  Actuarially Determined Long-Term Liability Adjustments(33,226) —
 (34,044) 818
 —
 33,226
 (33,226)
  Reclassification of Cash Flow Hedge from OCI to Earnings(43,470) (43,470) —
 —
 —
 43,470
 (43,470)
Other Comprehensive (Loss) Income:(76,696) (43,470) (34,044) 818
 —
 76,696
 (76,696)
Comprehensive (Loss) Income(924,798) (271,759) (231,942) 26,669
 (303,212) 789,198
 (915,844)
  Less: Comprehensive Income Attributable to Noncontrolling Interest—
 —
 —
 —
 —
 9,216
 9,216
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders$(924,798) $(271,759) $(231,942) $26,669
 $(303,212) $779,982
 $(925,060)











































156


Income Statement for the Year Ended December 31, 2015:
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 CNXC Non-Guarantor 
Other
Subsidiary
Non-
Guarantors
 Elimination Consolidated
Revenues and Other Income:             
Natural Gas, NGLs and Oil Sales$—
 $728,458
 $—
 $—
 $—
 $(1,537) $726,921
Gain on Commodity Derivative Instruments—
 392,942
 —
 —
 —
 —
 392,942
Coal Sales—
 —
 966,775
 322,261
 —
 —
 1,289,036
Other Outside Sales—
 —
 30,967
 —
 —
 —
 30,967
Purchased Gas Sales—
 14,450
 —
 —
 —
 —
 14,450
Freight-Outside Coal—
 —
 16,690
 3,809
 —
 —
 20,499
Miscellaneous Other Income(172,450) 62,340
 82,690
 880
 4,105
 166,786
 144,351
Gain on Sale of Assets—
 12,540
 61,572
 61
 —
 —
 74,173
Total Revenue and Other Income(172,450) 1,210,730
 1,158,694
 327,011
 4,105
 165,249
 2,693,339
Costs and Expenses:             
Exploration and Production Costs             
Lease Operating Expense—
 121,847
 —
 —
 —
 —
 121,847
Transportation, Gathering and Compression—
 343,403
 —
 —
 —
 —
 343,403
Production, Ad Valorem, and Other Fees—
 30,438
 —
 —
 —
 —
 30,438
Depreciation, Depletion and Amortization—
 370,374
 —
 —
 —
 —
 370,374
Exploration and Production Related Other Costs—
 10,120
 —
 —
 9
 (9) 10,120
Purchased Gas Costs—
 10,721
 —
 —
 —
 —
 10,721
Other Corporate Expenses—
 65,939
 —
 —
 —
 —
 65,939
Impairment of Exploration and Production Properties—
 828,905
 —
 —
 —
 —
 828,905
Selling, General and Administrative Costs—
 102,229
 —
 —
 —
 —
 102,229
Total Exploration and Production Costs—
 1,883,976
 —
 —
 9
 (9) 1,883,976
PA Mining Operations Costs             
Operating and Other Costs—
 —
 472,341
 193,961
 —
 —
 666,302
Depreciation, Depletion and Amortization—
 —
 132,728
 44,136
 —
 —
 176,864
Freight Expense—
 —
 16,690
 3,809
 —
 —
 20,499
Selling, General and Administrative Costs—
 —
 29,912
 10,931
 —
 —
 40,843
Total PA Mining Operations Costs—
 —
 651,671
 252,837
 —
 —
 904,508
Other Costs             
Miscellaneous Operating Expense69,059
 —
 9,176
 —
 508
 —
 78,743
Selling, General and Administrative Costs—
 —
 14,918
 —
 —
 —
 14,918
Depreciation, Depletion and Amortization604
 —
 19,278
 —
 —
 —
 19,882
Loss on Debt Extinguishment67,751
 —
 —
 —
 —
 —
 67,751
Interest Expense186,291
 5,613
 6,453
 9,636
 76
 (8,803) 199,266
Total Other Costs323,705
 5,613
 49,825
 9,636
 584
 (8,803) 380,560
Total Costs And Expenses323,705
 1,889,589
 701,496
 262,473
 593
 (8,812) 3,169,044
(Loss) Earnings from Continuing Operations Before Income Tax(496,155) (678,859) 457,198
 64,538
 3,512
 174,061
 (475,705)
Income Tax (Benefit) Expense(121,270) (257,056) 251,558
 —
 1,329
 —
 (125,439)
(Loss) Income From Continuing Operations(374,885) (421,803) 205,640
 64,538
 2,183
 174,061
 (350,266)
Loss From Discontinued Operations, net—
 —
 —
 —
 (14,209) —
 (14,209)
Net (Loss) Income(374,885) (421,803) 205,640
 64,538
 (12,026) 174,061
 (364,475)
Less: Net Income Attributable to Noncontrolling Interest—
 —
 —
 —
 —
 10,410
 10,410
Net (Loss) Income Attributable to CONSOL Energy Shareholders$(374,885) $(421,803) $205,640
 $64,538
 $(12,026) $163,651
 $(374,885)


157


Balance Sheet at December 31, 2015:
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 CNXC
Non-Guarantor		 Other Subsidiary
Non-Guarantors		 Elimination Consolidated
Assets:             
Current Assets:             
Cash and Cash Equivalents$64,995
 $75
 $—
 $6,534
 $970
 $—
 $72,574
Accounts and Notes Receivable:             
Trade—
 72,664
 59,321
 19,398
 —
 —
 151,383
Other Receivables18,933
 99,001
 3,330
 471
 —
 —
 121,735
Inventories—
 13,815
 40,739
 12,238
 —
 —
 66,792
Recoverable Income Taxes72,913
 (59,026) —
 —
 —
 —
 13,887
Prepaid Expenses27,245
 244,680
 20,273
 5,089
 —
 —
 297,287
Current Assets of Discontinued Operations—
 —
 —
 —
 81,105
 —
 81,105
Total Current Assets184,086
 371,209
 123,663
 43,730
 82,075
 —
 804,763
Property, Plant and Equipment:             
Property, Plant and Equipment156,348
 8,875,027
 3,898,005
 865,527
 —
 —
 13,794,907
Less-Accumulated Depreciation, Depletion and Amortization111,367
 2,695,674
 1,854,249
 400,911
 —
 —
 5,062,201
Property, Plant and Equipment of Discontinued Operations—
 —
 —
 —
 936,671
 —
 936,671
Total Property, Plant and Equipment-Net44,981
 6,179,353
 2,043,756
 464,616
 936,671
 —
 9,669,377
Other Assets:             
Investment in Affiliates10,563,985
 234,803
 6,293
 —
 —
 (10,567,751) 237,330
Other53,529
 47,892
 95,369
 17,598
 —
 —
 214,388
Other Assets of Discontinued Operations—
 —
 —
 —
 4,044
 —
 4,044
Total Other Assets10,617,514
 282,695
 101,662
 17,598
 4,044
 (10,567,751) 455,762
Total Assets$10,846,581
 $6,833,257
 $2,269,081
 $525,944
 $1,022,790
 $(10,567,751) $10,929,902
Liabilities and Equity:             
Current Liabilities:             
Accounts Payable$32,245
 $149,930
 $37,212
 $17,405
 $—
 $13,817
 $250,609
Accounts Payable (Recoverable)-Related Parties2,650,732
 1,521,442
 (3,953,215) 4,310
 (209,452) (13,817) —
Current Portion of Long-Term Debt1,509
 6,798
 1,041
 61
 —
 —
 9,409
Short-Term Notes Payable952,000
 —
 —
 —
 —
 —
 952,000
Other Accrued Liabilities63,668
 102,753
 218,186
 37,220
 —
 —
 421,827
Current Liabilities of Discontinued Operations—
 —
 —
 —
 51,514
 —
 51,514
Total Current Liabilities3,700,154
 1,780,923
 (3,696,776) 58,996
 (157,938) —
 1,685,359
Long-Term Debt:             
Long-Term Debt2,418,961
 33,141
 105,611
 181,070
 —
 —
 2,738,783
Long-Term Debt of Discontinued Operations—
 —
 —
 —
 5,001
 —
 5,001
Total Long-Term Debt2,418,961
 33,141
 105,611
 181,070
 5,001
 —
 2,743,784
Deferred Credits and Other Liabilities:             
Deferred Income Taxes(122,547) 197,176
 —
 —
 —
 —
 74,629
Postretirement Benefits Other Than Pensions—
 —
 630,892
 —
 —
 —
 630,892
Pneumoconiosis Benefits—
 —
 109,969
 1,934
 —
 —
 111,903
Mine Closing—
 —
 218,936
 8,403
 —
 —
 227,339
Gas Well Closing—
 135,174
 28,572
 96
 —
 —
 163,842
Workers’ Compensation—
 —
 66,883
 2,929
 —
 —
 69,812
Salary Retirement91,596
 —
 —
 —
 —
 —
 91,596
Reclamation—
 —
 25
 —
 —
 —
 25
Other56,390
 105,588
 4,266
 713
 —
 —
 166,957
Deferred Credits and Other Liabilities of Discontinued Operations—
 —
 —
 —
 107,988
 —
 107,988
Total Deferred Credits and Other Liabilities25,439
 437,938
 1,059,543
 14,075
 107,988
 —
 1,644,983
Total CONSOL Energy Inc. Stockholders’ Equity4,702,027
 4,581,255
 4,800,703
 271,803
 1,067,739
 (10,721,500) 4,702,027
Noncontrolling Interest—
 —
 —
 —
 —
 153,749
 153,749
Total Liabilities and Equity$10,846,581
 $6,833,257
 $2,269,081
 $525,944
 $1,022,790
 $(10,567,751) $10,929,902


158


Condensed Statement of Cash Flows for the Year Ended December 31, 2015:
 Parent Issuer 
CNX Gas
Guarantor
 Other Subsidiary Guarantors CNXC Non-Guarantor 
Other
Subsidiary Non-Guarantors
 Elimination Consolidated
Net Cash (Used in) Provided by Continuing Operating Activities$(153,930) $624,788
 $21,906
 $76,908
 $33,422
 $(103,417) $499,677
Net Cash Provided by Discontinued Operating Activities—
 —
 —
 —
 6,172
 —
 6,172
Net Cash (Used in) Provided by Operating Activities$(153,930) $624,788
 $21,906
 $76,908
 $39,594
 $(103,417) $505,849
Cash Flows from Investing Activities:             
Capital Expenditures$(9,752) $(832,446) $(106,663) $(34,073) $—
 $—
 $(982,934)
Proceeds From Sales of Assets142
 10,298
 100,060
 71
 —
 —
 110,571
Net Investments in Equity Affiliates—
 (79,756) (4,465) —
 —
 —
 (84,221)
Net Cash Used in Continuing Investing Activities(9,610) (901,904) (11,068) (34,002) —
 —
 (956,584)
Net Cash Used in Discontinued Investing Activities—
 —
 —
 —
 (39,633) —
 (39,633)
Net Cash Used in Investing Activities$(9,610) $(901,904) $(11,068) $(34,002) $(39,633) $—
 $(996,217)
Cash Flows from Financing Activities:             
Proceeds from (Payments on) Short-Term Borrowings$952,000
 $252,900
 $—
 $—
 $—
 $(252,900) $952,000
(Payments on) Proceeds from Miscellaneous Borrowings(1,281) (6,391) 3,443
 (53) —
 —
 (4,282)
Payments on Long-Term Notes, including Redemption Premium

(1,263,719) —
 —
 (10,951) —
 10,951
 (1,263,719)
Proceeds from Revolver - MLP—
 —
 —
 185,000
 —
 —
 185,000
Distributions to Noncontrolling Interest—
 —
 —
 (11,353) —
 6,293
 (5,060)
Proceeds from Sale of MLP Interest—
 —
 —
 148,359
 —
 —
 148,359
Proceeds from Issuance of Long-Term Notes492,760
 —
 —
 16,990
 —
 (16,990) 492,760
Net Distributions from Offering to Parent—
 —
 —
 (342,711) —
 342,711
 —
Net Change in Parent Advancements—
 —
 —
 (17,328) —
 17,328
 —
Tax Benefit from Stock-Based Compensation208
 —
 —
 —
 —
 —
 208
Dividends Paid(33,281) —
 —
 —
 —
 —
 (33,281)
Proceeds from Issuance of Common Stock8,288
 —
 —
 —
 —
 —
 8,288
Purchases of Treasury Stock(71,674) —
 —
 —
 —
 —
 (71,674)
Debt Issuance and Financing Fees—
 —
 (14,281) (4,329) —
 (3,976) (22,586)
Net Cash Provided by (Used in) Continuing Financing Activities83,301
 246,509
 (10,838) (36,376) —
 103,417
 386,013
Net Cash Used in Discontinued Financing Activities—
 —
 —
 —
 (56) —
 (56)
Net Cash Provided by (Used in) Financing Activities$83,301
 $246,509
 $(10,838) $(36,376) $(56) $103,417
 $385,957



159


Statement of Comprehensive Income for the Year Ended December 31, 2015:
 Parent Issuer 
CNX Gas
Guarantor
 Other Subsidiary Guarantors CNXC Non-
Guarantor		 
Other Subsidiary Non-
Guarantors
 Elimination Consolidated
Net (Loss) Income$(374,885) $(421,803) $205,640
 $64,538
 $(12,026) $174,061
 $(364,475)
Other Comprehensive (Loss) Income:             
  Actuarially Determined Long-Term Liability Adjustments(86,447) —
 (84,607) (1,840) —
 86,447
 (86,447)
  Reclassification of Cash Flow Hedge from OCI to Earnings(78,051) (78,051) —
 —
 —
 78,051
 (78,051)
Other Comprehensive (Loss) Income:(164,498) (78,051) (84,607) (1,840) —
 164,498
 (164,498)
Comprehensive (Loss) Income(539,383) (499,854) 121,033
 62,698
 (12,026) 338,559
 (528,973)
  Less: Comprehensive Income Attributable to Noncontrolling Interest—
 —
 —
 —
 —
 10,410
 10,410
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders$(539,383) $(499,854) $121,033
 $62,698
 $(12,026) $328,149
 $(539,383)



160


Income Statement for the Year Ended December 31, 2014:
 
Parent
Issuer
 
CNX Gas
Guarantor
 
Other
Subsidiary
Guarantors
 CNXC Non-Guarantor 
Other
Subsidiary
Non-
Guarantors
 Elimination Consolidated
Revenues and Other Income:             
Natural Gas, NGLs and Oil Sales$—
 $1,007,381
 $—
 $—
 $—
 $(2,457) $1,004,924
Gain on Commodity Derivative Instruments—
 23,193
 —
 —
 —
 —
 23,193
Coal Sales—
 —
 1,212,627
 404,247
 —
 —
 1,616,874
Other Outside Sales—
 —
 41,255
 —
 234,987
 —
 276,242
Purchased Gas Sales—
 8,999
 —
 —
 —
 —
 8,999
Freight-Outside Coal—
 —
 18,941
 4,192
 —
 —
 23,133
Miscellaneous Other Income420,030
 60,634
 138,201
 9,475
 10,305
 (431,185) 207,460
Gain (Loss) on Sale of Assets—
 45,917
 (2,926) 185
 22
 —
 43,198
Total Revenue and Other Income420,030
 1,146,124
 1,408,098
 418,099
 245,314
 (433,642) 3,204,023
Costs and Expenses:             
Exploration and Production Costs             
Lease Operating Expense—
 139,242
 —
 —
 —
 —
 139,242
Transportation, Gathering and Compression—
 239,591
 —
 —
 —
 (12) 239,579
Production, Ad Valorem, and Other Fees—
 39,418
 —
 —
 —
 —
 39,418
Depreciation, Depletion and Amortization—
 323,600
 —
 —
 —
 —
 323,600
Exploration and Production Related Other Costs—
 22,718
 637
 —
 119
 (119) 23,355
Purchased Gas Costs—
 7,251
 —
 —
 —
 —
 7,251
Other Corporate Expenses—
 46,838
 —
 —
 —
 —
 46,838
Selling, General and Administrative Costs—
 128,731
 —
 —
 —
 —
 128,731
Total Exploration and Production Costs—
 947,389
 637
 —
 119
 (131) 948,014
PA Mining Operations Costs             
Operating and Other Costs—
 —
 742,886
 239,863
 —
 —
 982,749
Depreciation, Depletion and Amortization—
 —
 129,979
 43,337
 —
 —
 173,316
Freight Expense—
 —
 12,575
 4,192
 6,366
 —
 23,133
Selling, General and Administrative Costs—
 —
 57,814
 17,149
 (6,366) —
 68,597
Total PA Mining Operations Costs—
 —
 943,254
 304,541
 —
 —
 1,247,795
Other Costs             
Miscellaneous Operating Expense99,273
 —
 129,257
 —
 231,899
 —
 460,429
Selling, General and Administrative Costs788
 —
 12,519
 —
 —
 —
 13,307
Depreciation, Depletion and Amortization640
 —
 33,273
 —
 1,814
 —
 35,727
Loss on Debt Extinguishment95,267
 —
 —
 —
 —
 —
 95,267
Interest Expense213,384
 9,021
 9,608
 8,683
 245
 (17,608) 223,333
Total Other Costs409,352
 9,021
 184,657
 8,683
 233,958
 (17,608) 828,063
Total Costs And Expenses409,352
 956,410
 1,128,548
 313,224
 234,077
 (17,739) 3,023,872
Earnings (Loss) from Continuing Operations Before Income Tax10,678
 189,714
 279,550
 104,875
 11,237
 (415,903) 180,151
Income Tax (Benefit) Expense(152,412) 66,441
 96,926
 —
 4,249
 —
 15,204
Income (Loss) From Continuing Operations163,090
 123,273
 182,624
 104,875
 6,988
 (415,903) 164,947
Loss From Discontinued Operations, net—
 —
 —
 —
 (1,857) —
 (1,857)
Net Income (Loss) Attributable to CONSOL Energy Shareholders$163,090
 $123,273
 $182,624
 $104,875
 $5,131
 $(415,903) $163,090



161




Condensed Statement of Cash Flows for the Year Ended December 31, 2014:
 Parent Issuer 
CNX Gas
Guarantor
 Other Subsidiary Guarantors CNXC Non-Guarantor 
Other
Subsidiary Non-Guarantors

 Elimination Consolidated
Net Cash (Used in) Provided by Continuing Operating Activities$(178,921) $567,851
 $(4,086) $142,636
 $(59,441) $372,347
 $840,386
Net Cash Provided by Discontinued Operating Activities—
 —
 —
 —
 96,390
 —
 96,390
Net Cash (Used in) Provided by Operating Activities$(178,921) $567,851
 $(4,086) $142,636
 $36,949
 $372,347
 $936,776
Cash Flows from Investing Activities:             
Capital Expenditures$(4,420) $(1,103,656) $(266,300) $(85,076) $—
 $—
 $(1,459,452)
Proceeds From Sales of Assets44,049
 92,507
 201,221
 19,046
 13
 —
 356,836
Net Investments in Equity Affiliates—
 85,248
 9,959
 —
 —
 —
 95,207
Net Cash Provided by (Used in) Continuing Investing Activities39,629
 (925,901) (55,120) (66,030) 13
 —
 (1,007,409)
Net Cash Used in Discontinued Investing Activities—
 —
 —
 —
 (33,973) —
 (33,973)
Net Cash Provided by (Used in) Investing Activities$39,629
 $(925,901) $(55,120) $(66,030) $(33,960) $—
 $(1,041,382)
Cash Flows from Financing Activities:             
Payments on Short-Term Borrowings$(11,736) $—
 $—
 $—
 $—
 $—
 $(11,736)
(Payments on) Proceeds from Miscellaneous Borrowings(399) 387,663
 (7,233) (24) (2,630) (387,663) (10,286)
Payments on Long-Term Notes, including Redemption Premium(1,819,005) —
 —
 (2,311) —
 2,311
 (1,819,005)
Proceeds from Issuance of Long-Term Notes1,859,920
 —
 —
 14,214
 —
 (14,214) 1,859,920
Net Change in Parent Advancements—
 —
 —
 (88,485) —
 88,485
 —
Tax Benefit from Stock-Based Compensation2,629
 —
 —
 —
 —
 —
 2,629
Dividends Paid(57,506) —
 —
 —
 —
 —
 (57,506)
Proceeds from Issuance of Common Stock15,016
 —
 —
 —
 —
 —
 15,016
Debt Issuance and Financing Fees(24,861) —
 —
 —
 —
 —
 (24,861)
Other Financing Activities—
 (5,169) 5,169
 —
 —
 —
 —
Net Cash (Used in) Provided by Financing Activities$(35,942) $382,494
 $(2,064) $(76,606) $(2,630) $(311,081) $(45,829)




162


Statement of Comprehensive Income for the Year Ended December 31, 2014:
 Parent Issuer 
CNX Gas
Guarantor
 Other Subsidiary Guarantors CNXC Non-
Guarantor		 
Other Subsidiary Non-
Guarantors
 Elimination Consolidated
Net Income (Loss)$163,090
 $123,273
 $182,624
 $104,875
 $5,131
 $(415,903) $163,090
Other Comprehensive Income (Loss):             
  Actuarially Determined Long-Term Liability Adjustments94,989
 —
 53,190
 41,799
 —
 (94,989) 94,989
  Net Increase (Decrease) in the Value of Cash Flow Hedge97,316
 97,316
 —
 —
 —
 (97,316) 97,316
  Reclassification of Cash Flow Hedge from OCI to Earnings(18,288) (18,288) —
 —
 —
 18,288
 (18,288)
Other Comprehensive Income (Loss):174,017
 79,028
 53,190
 41,799
 —
 (174,017) 174,017
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders$337,107
 $202,301
 $235,814
 $146,674
 $5,131
 $(589,920) $337,107

NOTE 2520—RELATED PARTY TRANSACTIONS
CONECNX Gathering LLC and CONECNX Midstream Partners LP

In September 2011, CNX Gas Company,Midstream Partners LP ("CNXM" or the "Partnership"), formerly known as CONE Midstream Partners LP (see Note 21 - Subsequent Event), is a wholly owned subsidiary of CONSOL Energy,master limited partnership formed in May 2014 by CNX Resources Corporation and Noble Energy, Inc. (Noble Energy), an unrelated third party, formed CONE Gathering LLC (CONE) to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CONSOL Energy accounts for CNX Gas Company's 50% ownership interest in CONE under the equity method of accounting.

In May 2014, CONSOL Energy and Noble Energy (collectively, “the Sponsors”) formed CONE Midstream Partners LP (the Partnership), a master limited partnership,primarily to own, operate, develop and acquire natural gas gathering and other midstream energy assets to service each company’stheir production in the Marcellus Shale in Pennsylvania and West Virginia. The Partnership's assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. The Partnership's general partner is CNX Midstream GP LLC, formerly known as CONE Midstream GP LLC, a wholly owned subsidiary of CONE.CNX Gathering LLC (“CNX Gathering”), formerly known as CONE Gathering LLC. CNX Gathering, a Delaware limited liability company, is a joint venture formed by CNX and Noble Energy in September 2011.

In September 2014,At December 31, 2017, CNX accounted for its ownership interests in each of the Partnership closed its initial public offering of 20,125,000 common units representing limited partnership interests, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters. Following the IPO, CONE had a 2% general partner interest in the Partnership, while each sponsor had a 32.1% limited partner interest.and CNX Gas Company accounts for its portion of the earnings in the PartnershipGathering under the equity method of accounting. CNX Gathering is a variable interest entity for which the Company has the ability to exert significant influence, but not control, over the operating and financing policies of. The Partnership is a variable interest entity for which CNX Gathering, through it's ownership and control of the Partnership's general partner, has the power to direct the activities that most significantly impact the Partnership's economic performance. In addition, through its general partner interest and incentive distribution rights in the Partnership, CNX Gathering has the obligation to absorb the Partnership's losses and the right to receive benefits from the Partnership in accordance with those interests. Therefore, CNX Gathering has a controlling financial interest in the Partnership, is the primary beneficiary of the Partnership and consolidates it accordingly. Rule 3-09 of Regulation S-X provides that if a 50%-or-less-owned person accounted for by the equity method meets the first or third condition of the significant subsidiary tests set forth in Rule 1-02(w) of Regulation S-X, substituting 20% for 10%, separate financial statements for that 50%-or-less-owned person shall be filed. The significance tests are calculated as of the end of each of the Partnership's fiscal years with respect to each fiscal year. Pursuant to Rule 3-09 CNX Gathering LLC has met the significant subsidiary test as of December 31, 2017 and 2016, and for the three years ended December 31, 2017, and therefore the required financial statements are included as an exhibit to this Annual Report on Form 10-K.

In November 2016, the Partnership acquired from CONECNX Gathering an additional 25% ownership interest in CONECNX Midstream DevCo I LP, formerly known as CONE Midstream Devco 1 LP, commonly referred to as the “Anchor"Anchor Systems.”" The transaction included a total purchase consideration of $248,000, comprised of $140,000 in cash and issuance of approximately 5,200,0002,600,000 common limited partnership units to the Sponsors.each of CNX and Noble Energy. Following the acquisition, CONECNX Gathering continues to have a 2% general partner interest in the Partnership, while each Sponsor’s limited partner interest increased to 33.5%. At December 31, 2016,2017, CNX Gas Company and Noble Energy each continuecontinues to own a 50% membership interest in the assets of CONE that were not contributed to the Partnership.CNX Gathering, which owns a 95% noncontrolling interest in CNX Midstream Devco II LP and CNX Midstream Devco III LP.


















163

In November 2017 the subordination period with respect to the Partnership’s subordinated units expired, and all of the 29,163,121 outstanding subordinated units, of which CNX owned half, automatically converted into common units on a one-for-one basis.

The following is a summary of the Company's Investment in Affiliates balances included within the Consolidated Balance Sheets associated with CONECNX Gathering and the Partnership, respectively:
CONE The Partnership TotalCNX Gathering LLC CNX Midstream Partners LP Total
Balance at December 31, 2014$94,467
 $4,883
 $99,350
Equity in Earnings20,916
 22,883
 43,799
Additional Contributions87,187
 —
 87,187
Distribution of Earnings—
 (16,719) (16,719)
Balance at December 31, 2015202,570
 11,047
 213,617
$202,570
 $11,047
 $213,617
Equity in Earnings17,112
 31,148
 48,260
17,112
 31,148
 48,260
Additional Contributions4,621
 —
 4,621
4,621
 —
 4,621
Distribution of Earnings(8,224) (19,066) (27,290)(8,224) (19,066) (27,290)
Funds received on dropdown transaction(70,000) —
 (70,000)
Basis differential4,996
 (4,996) —
Funds Received on Dropdown Transaction(70,000) —
 (70,000)
Basis Differential4,996
 (4,996) —
Balance at December 31, 2016$151,075
 $18,133
 $169,208
$151,075
 $18,133
 $169,208
Equity in Earnings9,823
 38,523
 48,346
Distribution of Earnings(17,254) (24,929) (42,183)
Asset Transfer(2,527) 2,527
 —
Balance at December 31, 2017$141,117
 $34,254
 $175,371


113



The following transactions were included within Miscellaneous Other Income and Transportation, Gathering and Compression within the Consolidated Statements of Income:
 For the Years Ended December 31,
 2016 2015 2014
Miscellaneous Other Income:     
     Equity in Earnings of Affiliates - CONE$17,112
 $20,916
 $25,521
     Equity in Earnings of Affiliates - the Partnership$31,148
 $22,883
 $4,286
      
Transportation, Gathering and Compression:     
     Gathering Services - CONE$706
 $1,077
 $219
     Gathering Services - the Partnership$123,020
 $104,291
 $65,365
 For the Years Ended December 31,
 2017 2016 2015
Other Income:     
     Equity in Earnings of Affiliates - CNX Gathering$9,823
 $17,112
 $20,916
     Equity in Earnings of Affiliates - CNX Midstream Partners LP$38,523
 $31,148
 $22,883
      
Transportation, Gathering and Compression:     
     Gathering Services - CNX Gathering$914
 $706
 $1,077
     Gathering Services - CNX Midstream Partners LP$136,068
 $122,256
 $104,291

At December 31, 2017 and 2016, and December 31, 2015, CONSOL EnergyCNX had a net payable of $5,815$9,982 and $12,216,$5,815, respectively, due to both the PartnershipCNX Midstream Partners and CONECNX Gathering primarily for accrued but unpaid gathering services. Additionally, during the year ended December 31, 2015, CONSOL Energy purchased $2,239 of supply inventory from the Partnership. CONSOL Energy did not have any supply inventory purchases from the Partnership during the year ended December 31, 2016.

CNX Coal Resources LP

In July 2015, CNX Coal Resources LP (CNXC) closed its initial public offering of 5,000,000 common units representing limited partnership interests at a price to the public of $15.00 per unit. Additionally, Greenlight Capital entered into a common unit purchase agreement with CNXC pursuant to which Greenlight Capital agreed to purchase, and CNXC agreed to sell, 5,000,000 common units at a price per unit equal to $15.00, which equates to $75,000 in net proceeds. CNXC's general partner is CNX Coal Resources GP, a wholly owned subsidiary of CONSOL Energy. The underwriters of the IPO filing exercised an over-allotment option of 561,067 common units to the public at $15.00 per unit.Energy Inc.

In connection with the Initial Public Offering (IPO), CNXCspin-off of its coal business, as discussed in Note 2 - Discontinued Operations, CNX and CONSOL Energy entered into a $400,000 senior secured revolving credit facility with certain lenders and PNC Bank, National Association (PNC), as administrative agent. Obligations underseveral agreements that govern the revolving credit facility are guaranteed by CNXC's subsidiaries (the guarantor subsidiaries) and are secured by substantially allrelationship of CNXC's and CNXC's subsidiaries' assets pursuant to a security agreement and various mortgages. Under the new revolving credit facility, CNXC made an initial draw of $200,000, and after origination fees of $3,000,parties following the net proceeds were $197,000.Distribution, including the following:

The total net proceeds related to these transactions that were distributed•Separation and Distribution Agreement;
•Transition Services Agreement;
•Tax Matters Agreement;
•Employee Matters Agreement;
•Intellectual Property Matters Agreement;
•CNX Resources Corporation to CONSOL Energy were $342,711.Inc. Trademark License Agreement;

In September 2016, CNXC and its wholly owned subsidiary, CNX Thermal Holdings LLC (CNX Thermal), entered into a Contribution Agreement with •CONSOL Energy CONSOL Pennsylvania Coal Company LLCInc. to CNX Resources Corporation Trademark License Agreement; and Conrhein Coal Company (the Contributing Parties) under which CNX Thermal acquired an additional 5% undivided interest in and
•First Amendment to the Pennsylvania Mine


164


Complex, in exchange for (i) cash consideration in the amount of $21,500 and (ii) CNXC's issuance of 3,956,496 Class A Preferred Units representing limited partner interests in CNXC at an issue price of $17.01 per Class A preferred Unit (the "Class A Preferred Unit Issue Price"), or an aggregate $67,300 in equity consideration. The Class A Preferred Unit Issue Price was calculated as the volume-weighted average trading price of CNXC's common units (the "Common Units") over the trailing 15-day trading period ending on September 29, 2016 (or $14.79 per unit), plus a 15% premium.

In connection with the PA Mining acquisition, in September 2016, the General Partner and CNXC entered into the First Amended and Restated Omnibus Agreement (the "Amended (“Omnibus Agreement"Amendment”).

There were also one-time transaction costs related to the spin-off of approximately $40,545 for the year ended December 31, 2017, that will be split equally by the two companies per the Separation and Distribution agreement. These costs consisted of consulting and professional fees associated with preparing for and executing the spin-off, as well as other items that were included within total costs of discontinued operations.

As of December 31, 2017, CNX had a receivable from CONSOL Energy and certain of its subsidiaries. Under$12,540 recorded in Total Current Assets on the Amended Omnibus Agreement, CONSOL Energy indemnified CNXC for certain liabilities. The Amended Omnibus AgreementConsolidated Balance Sheets. CNX also amended CNXC'shad recorded obligations to CONSOL Energy with respectof $15,415, of which $4,500 was recorded in Total Current Liabilities and $10,915 was included in Total Deferred Credits and Other Liabilities on the Consolidated Balance Sheets at December 31, 2017. These items relate to the paymentreimbursement of an annual administrative support feethe one-time transaction costs as well as other reimbursements per the terms of the separation and reimbursement for the provisions of certain management and operating services provided, in each case to reflect structural changes in how those services are provided to CNXC by CONSOL Energy.distribution agreement.

Charges for services fromAll significant intercompany transactions between CNX and CONSOL Energy includehave been included in the following:
 For the Years Ended December 31,
 2016 2015 2014
Operating and Other Costs$4,251
 $6,793
 $6,707
Selling, General and Administrative Expenses3,826
 8,926
 11,384
Total Services from CONSOL Energy$8,077
 $15,719
 $18,091

At December 31, 2016Consolidated Financial Statements and December 31, 2015, CNXC had aare considered to have been effectively settled for cash at the time the transaction was recorded. The total net payable toeffect of these transactions between CNX and CONSOL Energy is reflected in the amountConsolidated Statements of $1,666Cash Flows as a financing activity. In the Consolidated Statements of Stockholders' Equity, the distribution of CONSOL Energy Inc. is the net of the variety of intercompany transactions including, but not limited too, collection of trade receivables, payment of trade payables and $4,310, respectively. This payable includes reimbursementsaccrued liabilities, settlement of charges for business expenses, executive fees, stock-based compensationallocated selling, general and other items under the omnibus agreement.administrative costs and payment of taxes by CNX on CONSOL Energy's behalf.



165114


NOTE 21—SUBSEQUENT EVENTS
On January 3rd, 2018 CNX Resources Corporation closed on an agreement to purchase Noble Energy, Inc.'s 50% membership interest in CONE Gathering LLC for $305,000 in cash and the mutual release of all outstanding claims. [CNX Gathering holds all of the interests in CONE Midstream GP, LLC, which in turn holds the general partnership interest in CNXM] and all of the incentive distribution rights in CNXM. As a result of this transaction, CNX owns 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership.  In conjunction with the closing, CNXM changed its name from CONE Midstream Partners, LP. Beginning in the first quarter of 2018, CNX Gathering will be fully consolidated into the Company's financial statements.

Throughout the month of January 2018, CNX repurchased and canceled $384,707 aggregate principal amount of the Company's 5.875% senior notes due in April 2022. The weighted average repurchase price was 103.78%.

On February 7, 2018, CNX entered into a Purchase and Sale Agreement (the “Purchase Agreement”), with CNXM, CNX Gathering, CNX Midstream DevCo I LP, a Delaware limited partnership (“DevCo I LP”), CNX Midstream DevCo III LP, a Delaware limited partnership (“DevCo III LP”), and, for certain purposes, CNX Midstream DevCo I GP LLC, a Delaware limited liability company, CNX Midstream DevCo III GP LLC, a Delaware limited liability company, and CNX Midstream Operating Company LLC, a Delaware limited liability company.

CNX Gathering owns a 95% noncontrolling interest in DevCo III LP, which owns the gathering system and related assets commonly referred to as the Shirley-Penns System (the “Shirley-Penns System”), while CNXM owns the remaining 5% controlling interest in DevCo III LP. Pursuant to the terms of the Purchase Agreement, DevCo III LP will transfer its interest in the Shirley-Penns System on a pro rata basis to CNX Gathering and CNXM in accordance with each transferee’s respective ownership interest in DevCo III LP, and following such transfer, CNX Gathering will sell its aggregate interest in the Shirley-Penns System to DevCo I LP in exchange for cash consideration in the amount of $265,000 million (the “Acquisition”). CNXM expects to fund the Acquisition with cash on hand and through debt financing, subject to market conditions. The Acquisition is expected to close in the first quarter of 2018, subject to customary closing conditions (the “Closing”). Following the Closing, CNXM will own (through one or more intermediate entities) a 100% controlling interest in the Shirley-Penns System.

In addition, in connection with the Closing, CNXM expects to amend its gathering agreement with CNX Gas Company, to require CNX Gas to make a minimum volume commitment for the Shirley-Penns System for the period from January 1, 2018 through December 31, 2031 and to establish certain gathering fees, deficiency payments and excess delivery credits related thereto.

The foregoing description of the Purchase Agreement is not complete and is qualified in its entirety by reference to the full text of the Purchase Agreement, which is filed as Exhibit 10.75 to this Annual Report on Form 10-K and incorporated herein by reference.

Supplemental Gas Data (unaudited):

The following information was prepared in accordance with the FASB's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).”

Capitalized Costs:
 As of December 31, As of December 31,
 2016 2015 2017 2016
Intangible drilling costs 3,849,689
 3,583,599
Proved gas properties $2,016,916
 $1,922,602
 1,999,891
 2,016,916
Gas gathering assets 1,182,234
 1,138,299
Unproved gas properties 1,116,282
 1,421,083
 919,733
 1,116,282
Intangible drilling costs 3,583,565
 3,452,989
Gas wells and related equipment 791,996
 785,744
 834,120
 800,617
Gas gathering assets 1,138,299
 1,147,173
Gas well plugging 176,961
 115,121
 181,038
 176,961
Total Property, Plant and Equipment 8,824,019
 8,844,712
 $8,966,705
 $8,832,674
Accumulated Depreciation, Depletion and Amortization (3,099,622) (2,691,005) (3,408,606) (3,099,751)
Net Capitalized Costs $5,724,397
 $6,153,707
 $5,558,099
 $5,732,923



115


Costs incurred for property acquisition, exploration and development (*):
 For the Years Ended December 31, For the Years Ended December 31,
 2016 2015 2014 2017 2016 2015
Property acquisitions            
Proved properties $—
 $—
 $—
 $15,850
 $—
 $—
Unproved properties 1,537
 76,676
 119,597
 32,038
 1,537
 76,676
Development 138,813
 666,315
 952,733
 544,809
 138,813
 666,315
Exploration 32,259
 95,371
 45,006
 48,020
 32,259
 95,371
Total $172,609
 $838,362
 $1,117,336
 $640,717
 $172,609
 $838,362
__________
(*)Includes costs incurred whether capitalized or expensed.

























166


Results of Operations for Producing Activities:
 For the Years Ended December 31, For the Years Ended December 31,
 2016 2015 2014 2017 2016 2015
Natural Gas, NGLs and Oil Sales $793,673
 $728,458
 $1,007,381
 $1,125,224
 $793,248
 $726,921
(Loss) Gain on Commodity Derivative Instruments (141,021) 392,942
 23,193
Gain (Loss) on Commodity Derivative Instruments 206,930
 (141,021) 392,942
Purchased Gas Sales 43,256
 14,450
 8,999
 53,795
 43,256
 14,450
Total Revenue 695,908
 1,135,850
 1,039,573
 1,385,949
 695,483
 1,134,313
Lease Operating Expense 96,434
 121,847
 139,242
 88,932
 96,434
 121,847
Production, Ad Valorem, and Other Fees 31,049
 30,438
 39,418
 29,267
 31,049
 30,438
Transportation, Gathering and Compression 374,350
 343,403
 239,591
 382,865
 374,350
 343,403
Purchased Gas Costs 42,717
 10,721
 7,251
 52,597
 42,717
 10,721
Impairment of Exploration and Production Properties —
 828,905
 —
 137,865
 —
 828,905
Other Costs 14,519
 10,120
 22,718
Exploration Costs 48,074
 14,522
 10,119
DD&A 417,853
 370,374
 323,600
 412,036
 419,939
 371,783
Total Costs 976,922
 1,715,808
 771,820
 1,151,636
 979,011
 1,717,216
Pre-tax Operating Income / (Loss) (281,014) (579,958) 267,753
 234,313
 (283,528) (582,903)
Income Taxes / (Benefit) (69,308) (250,220) 45,162
Income Tax Benefit (348,676) (69,929) (251,490)
Results of Operations for Producing Activities excluding Corporate and Interest Costs $(211,706) $(329,738) $222,591
 $582,989
 $(213,599) $(331,413)
The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:


116


 For the Years Ended December 31, For the Years Ended December 31,
 2016 2015 2014 2017 2016 2015
Production (MMcfe) 394,387
 328,657
 235,714
 407,166
 394,387
 328,657
Total average sales price before effects of financial settlements (per Mcfe) $2.01
 $2.22
 $4.27
 $2.76
 $2.01
 $2.22
Average effects of financial settlements (per Mcfe) $0.62
 $0.60
 $0.10
 $(0.10) $0.62
 $0.59
Total average sales price including effects of financial settlements (per Mcfe) $2.63
 $2.82
 $4.37
 $2.66
 $2.63
 $2.81
Average lifting costs, excluding ad valorem and severance taxes (per Mcfe) $0.24
 $0.37
 $0.59
 $0.22
 $0.24
 $0.37
During the years ended December 31, 2017, 2016 and 2015, the Company drilled 90.0, 36.0, and 2014, we drilled 36.0, 132.8 and 180.3 net development wells, respectively. There were no net dry development wells in 2017, 2016, 2015, or 2014.2015.
During the year ended December 31, 2016, there were no2017, the Company drilled 4.0 net exploratory wells. During the years ended December 31, 20152016 and 2014,2015, we drilled 2.50.0 and 8.52.5 net exploratory wells, respectively. There were no net dry exploratory wells in 2017, 2016, 2015, or 2014.2015.
At December 31, 2016,2017, there were 15.03.9 net development wells and no1.8 exploratory wells that have been partially drilled but not turned in-line. Additionally there are 65.5 net developmental wells that are drilled but uncompleted and 3.0uncompleted. Additionally there are 13.0 net developmental wells and no net exploratory well that have been completed and are awaiting final tie-in to production.
We areCNX is committed to provide 431.4712.3 Bcf of gas under existing sales contracts or agreements over the course of the next four years. We expectThe Company expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.







167


Most of ourthe Company's development wells and proved acreage are located in Virginia, West Virginia, Ohio and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2016,2017, the number of producing wells, developed acreage and undeveloped acreage:
 Gross Net(1) Gross Net(1)
Producing Gas Wells (including gob wells) 17,314
 12,846
 17,013
 12,853
Producing Oil Wells 189
 30
 171
 12
Acreage Position:        
Proved Developed Acreage 549,816
 541,282
 551,900
 543,937
Proved Undeveloped Acreage 34,467
 30,038
 41,066
 40,703
Unproved Acreage 4,804,804
 3,745,533
 4,434,714
 3,817,015
Total Acreage 5,389,087
 4,316,853
 5,027,680
 4,401,655
____________
(1)Net acres include acreage attributable to ourthe Company's working interests of the properties. Additional adjustments (either increases or decreases) may be required as wethe Company further developdevelops title to and further confirm ourconfirms its rights with respect to ourits various properties in anticipation of development. We believeThe Company believes that ourits assumptions and methodology in this regard are reasonable.

Proved Oil and Gas Reserves Quantities:

Annually, the preparation of natural gas reserves estimates are completed in accordance with CONSOL Energy'sCNX prescribed internal control procedures, which include verification of input data into a gas reserves forecasting and economic evaluation software, as well as


117


multi-functional management review. The input data verification includes reviews of the price and cost assumptions used in the economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer with over 10 years of experience in the oil and gas industry. Our 2016The Company's 2017 gas reserves results, which are reported in the Supplemental Gas Data year ended December 31, 20162017 Form 10-K, were audited by Netherland, Sewell & Associates, Inc. The technical person primarily responsible for overseeing the audit of ourthe Company's reserves is a registered professional engineer in the state of Texas with over 15 years of experience in the oil and gas industry. The gas reserves estimates are as follows:


168


     Condensate Consolidated     Condensate Consolidated
 Natural Gas NGLs & Crude Oil Operations Natural Gas NGLs & Crude Oil Operations
 (MMcf) (Mbbls) (Mbbls) (MMcfe) (MMcf) (Mbbls) (Mbbls) (MMcfe)
Balance December 31, 2013 (a) 5,585,107
 21,546
 2,806
 5,731,214
Balance December 31, 2014 (a) 6,317,600
 77,790
 7,213
 6,827,616
Revisions (b) (46,560) 40,363
 3,756
 218,168
 1,055,225
 45,711
 6,569
 1,368,909
Price Changes 15,512
 —
 —
 15,512
 (2,866,123) (45,675) (3,208) (3,159,421)
Extensions and Discoveries (c) 979,801
 18,459
 1,314
 1,098,436
 840,800
 13,916
 1,707
 934,542
Production (216,260) (2,578) (664) (235,714) (287,287) (5,530) (1,365) (328,657)
Balance December 31, 2014 (a) 6,317,600
 77,790
 7,212
 6,827,616
Balance December 31, 2015 (a) 5,060,215
 86,212
 10,916
 5,642,989
Revisions (d) 1,052,978
 45,993
 6,662
 1,368,909
 11,559
 (19,078) 510
 (99,849)
Price Changes (2,866,123) (45,675) (3,208) (3,159,421) (179,914) (1,647) (34) (190,009)
Extensions and Discoveries (e) 840,800
 13,916
 1,707
 934,542
 643,688
 10,960
 1,783
 720,146
Production (285,041) (5,812) (1,458) (328,657) (348,753) (6,710) (896) (394,387)
Balance December 31, 2015 (a) 5,060,214
 86,212
 10,915
 5,642,989
Revisions (f) 21,280
 (20,669) 481
 (99,849)
Purchases of Reserves In-Place (f) 1,352,759
 13,177
 1,970
 1,443,642
Sales of Reserves In-Place (f) (711,155) (22,382) (4,240) (870,884)
Balance December 31, 2016 (a) 5,828,399
 60,532
 10,009
 6,251,648
Revisions (g) (202,735) 1,162
 (5,834) (232,321)
Price Changes (179,914) (1,647) (35) (190,009) 173,738
 1,188
 (159) 181,470
Extensions and Discoveries (g) 643,688
 10,960
 1,783
 720,146
Extensions and Discoveries (e) 1,769,029
 17,887
 1,800
 1,887,153
Production (358,474) (5,119) (867) (394,387) (364,893) (6,456) (589) (407,166)
Purchases of Reserves In-Place (h) 1,352,759
 13,177
 1,970
 1,443,642
Sales of Reserves In-Place (h) (711,155) (22,382) (4,240) (870,884)
Balance December 31, 2016 (a) 5,828,398
 60,532
 10,007
 6,251,648
Sales of Reserves In-Place (81,780) (2,622) (277) (99,172)
Balance December 31, 2017 (a) 7,121,758
 71,691
 4,950
 7,581,612
                
Proved developed reserves (i):        
December 31, 2014 2,979,906
 32,405
 4,061
 3,198,706
Proved developed resources:        
December 31, 2015 3,310,894
 59,196
 5,180
 3,697,152
 3,310,894
 59,196
 5,180
 3,697,152
December 31, 2016 3,478,464
 30,666
 3,474
 3,683,302
 3,478,464
 30,666
 3,474
 3,683,302
December 31, 2017 4,051,526
 56,022
 3,567
 4,409,065
                
Proved undeveloped reserves:        
December 31, 2014 3,337,694
 45,385
 3,151
 3,628,910
Proved undeveloped resources:        
December 31, 2015 1,749,320
 27,016
 5,736
 1,945,837
 1,749,320
 27,016
 5,736
 1,945,837
December 31, 2016 2,349,934
 29,866
 6,536
 2,568,346
 2,349,934
 29,866
 6,536
 2,568,346
December 31, 2017 3,070,232
 15,669
 1,383
 3,172,547
__________
(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 EnergyCNX 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 primarilyThe upward revisions in 2015 of 1,369 Bcfe were due to efficiencies611 Bcfe increase in operationsboth 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 optimizationperformance. 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 had the total effectselecting our highest rate of positive revisions. Additionally, the 2014 revisions include a reclassification of ethane volumes from natural gas to NGLs.
return properties for future development.


118


(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 ourthe 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)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 ourthe Company's fourth quarter realignment of the Marcellus Shale properties as part of dissolving our joint venture with Noble Energy.


169


(i)(g)IncludedThe downward revisions for 2017 is due to corporate planning changes by our JV partner in our proved developed reserves at December 31, 2016 are producing wells with negative undiscounted cash flows that represent 199.3Ohio Utica which resulted in all PUD's being removed, causing a 458 Bcfe of natural gasdownward revision, offset, in part by improved well performance due to the enhanced RCS completions 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.improved operating costs.
  For the Year
  Ended
  December 31,
  20162017
Proved Undeveloped Reserves (MMcfe)  
Beginning proved undeveloped reserves 1,945,8372,568,346
Undeveloped reserves transferred to developed(a) (211,876735,076)
Disposition of reserves in placePrice Revisions5,066
Revisions Due to Plan Changes (b) (199,401472,118)
Acquisition of reserves in place547,680
PriceRevisions Due to Changes(188,066)
Plan and other revisions Due to Well Performance (b) 4,906107,421
Extension and discoveries (c) 669,2661,698,908
Ending proved undeveloped reserves(d)(e) 2,568,3463,172,547
_________
(a)During 2016,2017, various exploration and development drilling and evaluations were completed. Approximately, $58,694$247,459 of capital was spent in the year ended December 31, 20162017 related to undeveloped reserves that were transferred to developed.
(b) Plan and otherThe downward revisions arefor 2017 is due to high grading of locations. Thesecorporate planning changes along with upward revisions attributable to efficienciesby our JV partner in operations and well performance had the total affect of a positive revision.Ohio Utica which resulted in PUD's being removed.
(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, 20162017 are approximately 215,861301,063 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 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.
CNX.
At December 31, 20162017 there were no wells pending the determination of proved reserves.
The following table represents the capitalized exploratory well cost activity as indicated:
 December 31, December 31,
 2016 2015 2014 2017 2016 2015
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves $40,917
 $17,179
 $27,453
 $40,149
 $40,917
 $17,179
Costs expensed due to determination of dry hole or abandonment of project $—
 $—
 $2,041
��$—
 $—
 $—
CONSOL Energy'sCNX proved natural gas reserves are located in the United States.


170119

Standardized Measure of Discounted Future Net Cash Flows:
The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.
The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CONSOL Energy.CNX. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CONSOL Energy'sCNX investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and cost assumptions.
The standardized measure is intended to provide a better means for comparing the value of CONSOL Energy'sCNX proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.
 December 31, December 31,
 2016 2015 2014 2017 2016 2015
Future Cash Flows (a)            
Revenues $11,303,409
 $11,837,732
 $28,502,852
 $19,261,578
 $11,303,409
 $11,837,732
Production costs (5,850,941) (6,584,947) (10,100,868) (7,234,303) (5,850,941) (6,584,947)
Development costs (1,550,294) (1,220,010) (3,368,621) (1,710,585) (1,550,294) (1,220,010)
Income tax expense (1,482,826) (1,532,454) (5,711,989) (2,475,981) (1,482,826) (1,532,454)
Future Net Cash Flows 2,419,348
 2,500,321
 9,321,374
 7,840,709
 2,419,348
 2,500,321
Discounted to present value at a 10% annual rate (1,464,231) (1,481,017) (6,337,216) (4,709,311) (1,464,231) (1,481,017)
Total standardized measure of discounted net cash flows $955,117
 $1,019,304
 $2,984,158
 $3,131,398
 $955,117
 $1,019,304

(a)For 2016,2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016,2017, adjusted for energy content and a regional price differential. For 2016,2017, this adjusted natural gas price was $1.73$2.44 per mcf, the adjusted oil price was $25.04$38.65 per barrel and the adjusted NGL price was $15.77$23.61 per barrel.

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.

For 2015, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2015, adjusted for energy content and a regional price differential. For 2015, this adjusted natural gas price was $2.02 per mcf, the adjusted oil price was $25.29 per barrel and the adjusted NGL price was $15.59 per barrel.

For 2014, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2014, adjusted for energy content and a regional price differential. For 2014, this adjusted natural gas price was $3.85 per mcf, the adjusted oil price was $77.30 per barrel and the adjusted NGL price was $46.54 per barrel.











171120

The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
 December 31, December 31,
 2016 2015 2014 2017 2016 2015
Balance at beginning of period $1,019,304
 $2,984,158
 $1,680,811
 $955,117
 $1,019,304
 $2,984,158
Net changes in sales prices and production costs (172,812) (4,151,684) 517,731
 1,983,475
 (172,812) (4,151,684)
Sales net of production costs (150,819) (589,533) (559,563) (831,131) (150,819) (589,533)
Net change due to revisions in quantity estimates (35,502) 408,006
 151,233
 (145,496) (35,502) 408,006
Net change due to extensions, discoveries and improved recovery (54,628) 157,016
 418,775
 588,574
 (54,628) 157,016
Development costs incurred during the period 138,813
 666,315
 952,733
 544,809
 138,813
 666,315
Difference in previously estimated development costs compared to actual costs incurred during the period (39,821) 8,911
 (102,949) (129,427) (39,821) 8,911
Purchase of Reserves In-Place 238,819
 —
 —
 —
 238,819
 —
Sales of Reserves In-Place (137,998) —
 —
 (55,277) (137,998) —
Changes in estimated future development costs (158,000) 374,982
 595,221
 (233,017) (158,000) 374,982
Net change in future income taxes 36,513
 1,259,744
 (798,470) (404,582) 36,513
 1,259,744
Accretion of discount and other 271,248
 (98,611) 128,636
Timing and Other 712,764
 125,529
 (354,778)
Accretion 145,589
 145,719
 256,167
Total discounted cash flow at end of period $955,117
 $1,019,304
 $2,984,158
 $3,131,398
 $955,117
 $1,019,304

Supplemental Coal Data (unaudited)
  Millions of Tons
  For the Year Ended December 31,
  2016 2015 2014 2013 2012
Proven and probable coal reserves at beginning of period 3,047
 3,238
 3,032
 4,229
 4,314
Purchased reserves —
 24
 —
 1
 —
Reserves sold in place (601) (43) (233) (1,199) (155)
Production (26) (29) (32) (55) (55)
Revisions and other changes (59) (143) 471
 56
 125
Consolidated proven and probable coal reserves at end of period* (1) 2,361
 3,047
 3,238
 3,032
 4,229
           
Proportionate share of proven and probable coal reserves of unconsolidated equity affiliates (excluded from the table above)* —
 —
 55
 57
 41
______________
* Proven and probable coal reserves are the equivalent of “demonstrated reserves” under the coal resource classification system of the U.S. Geological Survey. Generally, these reserves would be commercially mineable at year-end prices and cost levels, using current technology and mining practices.
(1) 143.3 Million tons for the Mason Dixon Project are controlled by CCC, a former subsidiary of CONSOL Energy that was sold in December 2013. As of filing, these tons are still controlled by CCC 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.
CONSOL Energy's coal reserves are located in nearly every major coal-producing region in North America. Our estimate of proven and probable coal reserves has been determined by CONSOL Energy. At December 31, 2016, 141 million tons were assigned to mines either in production or temporarily idled. The proven and probable coal reserves at December 31, 2016 include 2,274 million tons of thermal coal reserves, of which approximately 2 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million British thermal unit (Btu), 8 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu, and 90 percent has a sulfur content equivalent to greater than 2.5 pounds sulfur dioxide per million Btu. The reserves also include 87 million tons of metallurgical coal in consolidated reserves, of which approximately 24 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu and 76 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu.



172


Supplemental Quarterly Information (unaudited):
(Dollars in thousands, except per share data)
 Three Months Ended Three Months Ended
 March 31, June 30, September 30, December 31, March 31, June 30, September 30, December 31,
 2016 2016 2016 2016 2017 2017 2017 2017
Sales (A) $478,864
 $235,251
 $688,590
 $390,398
 $304,278
 $354,409
 $267,009
 $460,253
Freight Revenue $13,110
 $11,447
 $9,392
 $12,519
Costs and Expenses (B) $329,071
 $369,392
 $361,551
 $415,224
 $162,148
 $166,330
 $171,606
 $214,020
Freight Expense $13,110
 $11,447
 $9,392
 $12,519
(Loss) Income from Continuing Operations $(43,291) $(234,044) $62,568
 $(321,198)
(Loss) Income from Discontinued Operations $(53,167) $(234,605) $(34,975) $19,564
Net (Loss) Income Attributable to CONSOL Energy Shareholders $(97,572) $(469,828) $25,345
 $(306,047)
(Loss) Income from Continuing Operations (C) $(75,234) $122,384
 $(34,254) $282,143
Income (Loss) from Discontinued Operations $36,268
 $47,126
 $7,813
 $(5,499)
Net (Loss) Income $(38,966) $169,510
 $(26,441) $276,644
Earnings Per Share                
Basic:                
(Loss) Income from Continuing Operations $(0.19) $(1.03) $0.26
 $(1.42) $(0.33) $0.53
 $(0.15) $1.24
(Loss) Income from Discontinued Operations $(0.24) $(1.02) $(0.15) $0.09
Income (Loss) from Discontinued Operations $0.16
 $0.21
 $0.04
 $(0.04)
Net (Loss) Income $(0.43) $(2.05) $0.11
 $(1.33) $(0.17) $0.74
 $(0.11) $1.20
Dilutive:                
(Loss) Income from Continuing Operations $(0.19) $(1.03) $0.26
 $(1.42) $(0.33) $0.53
 $(0.15) $1.23
(Loss) Income from Discontinued Operations $(0.24) $(1.02) $(0.15) $0.09
Income (Loss) from Discontinued Operations $0.16
 $0.20
 $0.04
 $(0.03)
Net (Loss) Income $(0.43) $(2.05) $0.11
 $(1.33) $(0.17) $0.73
 $(0.11) $1.20



121


  Three Months Ended
  March 31, June 30, September 30, December 31,
  2015 2015 2015 2015
Sales (A) $715,740
 $503,825
 $631,979
 $602,772
Freight Revenue $5,018
 $2,750
 $2,436
 $10,295
Costs and Expenses (B) $399,281
 $351,200
 $267,826
 $243,267
Freight Expense $5,018
 $2,750
 $2,436
 $10,295
Income (Loss) from Continuing Operations (C) $52,964
 $(577,884) $129,312
 $45,342
Income (Loss) from Discontinued Operations $26,067
 $(25,417) $(3,842) $(11,017)
Net Income (Loss) Attributable to CONSOL Energy Shareholders $79,031
 $(603,301) $118,980
 $30,405
Earnings Per Share        
Basic:        
Income (Loss) from Continuing Operations $0.23
 $(2.52) $0.54
 $0.18
Income (Loss) from Discontinued Operations $0.11
 $(0.12) $(0.02) $(0.05)
Net Income (Loss) $0.34
 $(2.64) $0.52
 $0.13
Dilutive:        
Income (Loss) from Continuing Operations $0.23
 $(2.52) $0.54
 $0.18
Income (Loss) from Discontinued Operations $0.11
 $(0.12) $(0.02) $(0.05)
Net Income (Loss) $0.34
 $(2.64) $0.52
 $0.13
  Three Months Ended
  March 31, June 30, September 30, December 31,
  2016 2016 2016 2016
Sales (A) $244,935
 $(23,518) $416,192
 $57,874
Costs and Expenses (B) $162,910
 $153,971
 $160,811
 $170,134
(Loss) Income from Continuing Operations $(50,219) $(256,535) $56,264
 $(300,455)
Loss from Discontinued Operations $(47,353) $(213,293) $(30,919) $(5,592)
Net (Loss) Income $(97,572) $(469,828) $25,345
 $(306,047)
Earnings Per Share        
Basic:        
(Loss) Income from Continuing Operations $(0.22) $(1.12) $0.25
 $(1.31)
Loss from Discontinued Operations $(0.21) $(0.93) $(0.14) $(0.02)
Net (Loss) Income $(0.43) $(2.05) $0.11
 $(1.33)
Dilutive:        
(Loss) Income from Continuing Operations $(0.22) $(1.12) $0.24
 $(1.30)
Loss from Discontinued Operations $(0.21) $(0.93) $(0.13) $(0.03)
Net (Loss) Income $(0.43) $(2.05) $0.11
 $(1.33)

(A) Includes natural gas, NGLs, and oil sales; gain (loss) on commodity derivative instruments; coal sales; other outside sales; and purchased gas sales.
(B) Includes exploration and production costs coal costs and miscellaneousother operating expense, excludingexpense; excludes DD&A, other corporate expenses, selling, general and administrative, loss on debt extinguishment, interest expense and freightother expense.


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(C) Includes an impairment of $828,905$137,865 that was recorded during the three months ended June 30, 2015March 31, 2017 related to CONSOL Energy'sCNX's exploration and production properties. The impairment primarily related to the write down of the Company's shallow oil and gas asset values including impairments to unproved property. See Note 1 - Significant Accounting Policies in Item 8 of this Form 10-K for additional information.



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ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
ITEM 9A.CONTROLS AND PROCEDURES
Disclosure controls and procedures. CONSOL Energy,CNX, under the supervision and with the participation of its management, including CONSOL Energy’sCNX’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, CONSOL Energy’sCNX’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 20162017 to ensure that information required to be disclosed by CONSOL EnergyCNX in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CONSOL EnergyCNX in such reports is accumulated and communicated to CONSOL Energy’sCNX’s management, including CONSOL Energy’sCNX’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Management's Annual Report on Internal Control Over Financial Reporting. CONSOL Energy'sCNX's management is responsible for establishing and maintaining adequate internal control over financial reporting. CONSOL Energy'sCNX's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
CONSOL Energy'sCNX's internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of CONSOL Energy;CNX; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of CONSOL Energy'sCNX's assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of CONSOL Energy'sCNX's internal control over financial reporting as of December 31, 2016.2017. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (COSO) in Internal Control-Integrated Framework. Based on ourmanagements assessment and those criteria, management has concluded that CONSOL EnergyCNX maintained effective internal control over financial reporting as of December 31, 2016.2017.
The effectiveness of CONSOL Energy'sCNX's internal control over financial reporting as of December 31, 20162017 has been audited by Ernst and& Young, LLP, an independent registered public accounting firm, as stated in their report set forth in the Report of Independent Registered Public Accounting Firm in Part II, Item 9A of this annual reportAnnual Report on Form 10-K.

Changes in internal controls over financial reporting. There were no changes in the Company's internal controls over financial reporting that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.



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Report of Independent Registered Public Accounting Firm
The

To the Stockholders and the Board of Directors and Stockholders of CONSOL Energy Inc.CNX Resources Corporation and Subsidiaries

Opinion on Internal Control over Financial Reporting

We have audited CONSOL Energy Inc.CNX Resources Corporation and Subsidiaries'Subsidiaries’ internal control over financial reporting as of December 31, 2016,2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). CONSOL Energy Inc.In our opinion, CNX Resources Corporation and Subsidiaries'Subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of CNX Resources Corporation and Subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of income, comprehensive income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2017 of the Company and our report dated February 7, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management'sManagement’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A.Reporting. Our responsibility is to express an opinion on the Company'sCompany’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company'scompany’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company'scompany’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company'scompany’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, CONSOL Energy Inc. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based onthe COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2016 of CONSOL Energy Inc. and Subsidiaries and our report dated February 8, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 8, 2017




7, 2018



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ITEM 9B.OTHER INFORMATION

NONE

PART III

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item is incorporated herein by reference from the information under the captions “PROPOSAL NO. 1-ELECTION OF DIRECTORS-Biographies of Nominees,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION and “SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the Proxy Statement for the annual meeting of shareholders to be held on May 9, 20172018 (the “Proxy Statement”).

Executive Officers of CONSOL EnergyCNX

The following is a list, as of February 1, 2017,2018, of CONSOL EnergyCNX executive officers, their ages and their positions and offices held with CONSOL Energy.CNX.
Name Age Position
Nicholas J. DeIuliis 4849 President and Chief Executive Officer
Stephen W. Johnson 5859 Executive Vice President - Chief Administrative Officer
David M. KhaniDonald W. Rush 5335 Executive Vice President and Chief Financial Officer
Timothy C. Dugan 5556 Executive Vice President and Chief Operating Officer - Exploration and Production
James A. Brock60Executive Vice President and Chief Operating Officer - Coal

Nicholas J. DeIuliis has beenis a Director and the President and Chief Executive Officer of CNX Resources Corporation. Prior to the separation of CONSOL Energy Inc. into two separate companies, Mr. DeIuliis had more than 25 years of experience with the Company and in that time has held the positions of Chief Executive Officer since May 7, 2015, President since February 23, 2011, and on May 7, 2014 he was named CONSOL's Chief Executive Officer. Mr. DeIuliis previously served in various positions at CNX Gas Corporation, including President, Chief Executive Officer and Chief Operating Officer. He is currently Chairman ofas the Board at CNX Gas Corporation. He was Executive Vice President and Chief Operating Officer, of CONSOL Energy from January 16, 2009 until February 23, 2011. Prior to that time, he held the following positions at CONSOL Energy: Senior Vice President - Strategic Planning, (November 1, 2004 to August 2005); Vice President Strategic Planning (April 1, 2002 to November 1, 2004); Director-Corporate Strategy (October 1, 2001 to April 1, 2002); Manager-Strategic Planning (January 1, 2001 to October 2001); and Supervisor-Process Engineering (April 1, 1999 toearlier in his career various engineering positions. On January 1, 2001)3, 2018, Mr. DeIuliis was appointed Chairman of the Board and Chief Executive Officer of the general partner of CNX Midstream Partners LP (formerly known as CONE Midstream Partners, LP). He was appointed a directerDirector, President and electedChief Executive Officer of CNX Gas Corporation from its creation in 2005 through 2009. Mr. DeIuliis was a Director and Chairman of the Board of the general partner of CONSOL Coal Resources LP (formerly known as CNX Coal Resources LP effectiveLP) from March 16, 2015.2015 until November 28, 2017. Mr. DeIuliis is a member of the Board of Directors of the University of Pittsburgh Cancer Institute, the Center for Responsible Shale Development and the Allegheny Conference on Community Development. Mr. DeIuliis is a registered engineer in the Commonwealth of Pennsylvania and a member of the Pennsylvania bar.

Stephen W. Johnson has beenserved as the Executive Vice President and Chief Administrative Officer of CONSOL Energy and CNX GasResources Corporation since April 13, 2015. From December 31, 2012 until April 13, 2015, heMr. Johnson held the same position at the formerly named CONSOL Energy Inc. prior to its separation into two separate companies. Before being appointed to his current position, Mr. Johnson served as Executive Vice President - Diversified Business Units and Chief Legal and Corporate Affairs Officer, of CONSOL Energy and CNX Gas Corporation. Prior to that time, Mr. Johnson served as Senior Vice President and General Counsel of both CONSOL Energy and CNX Gas Corporation from February 5, 2009 through December 31, 2012.  Prior to February 5, 2009, he served in the following positions with CNX Gas Corporation: General Counsel (September 1, 2005 to December 2, 2005); Senior Vice President and General Counsel (December 2, 2005 to June 21, 2007); and Executive Vice President, General Counsel and Secretary (June 21, 2007 to February 5, 2009). EffectiveCorporation. On May 30, 2014, Mr. Johnson became a director of the general partnership of CONE Midstream Partners LP. He was appointed a directorDirector of the general partner of CNX Midstream Partners LP (formerly known as CONE Midstream Partners LP). Mr. Johnson was a Director of the general partner of CONSOL Coal Resources LP effective(formerly known as CNX Coal Resources LP) from March 16, 2015.2015 until November 28, 2017. Mr. Johnson has spent numerous years in the natural resources industry, including 12 years with CNX Resources Corporation, CONSOL Energy Inc. and CNX Gas Corporation and a number of years prior to that representing natural resources companies in private legal practice. Mr. Johnson is the Chairman of the Board of Concordia Lutheran Ministries, a nonprofit continuing care retirement community, and the former Chairman of NEED, a nonprofit minority college access program.

David M. KhaniDonald W. Rush joined CONSOL Energy on September 1, 2011has served as its Vice President - Finance, and was promoted tothe Executive Vice President and Chief Financial Officer effective March 1, 2013. Prior to joiningof CNX Resources Corporation since July 11, 2017. Mr. Rush held the same position at the formerly named CONSOL Energy Mr. Khani wasInc. prior to its separation into two separate companies.  He previously served as Vice President of Energy Marketing where he oversaw the Company's commercial functions, including mergers and acquisitions, gas marketing and transportation, in addition to holding other strategy and planning, business development and engineering positions during his 12 years with FBR Capital Markets & Co. ("FBR"), an investment bankingthe Company. He successfully guided the Company through every significant transaction during its transition into a pure play natural gas exploration and advisory firm and heldproduction company, including the following positions: Directorsale of Research from February 2007 through October 2010, and then Co-Director of Research from November 2010 through August 2011. Effective May 30, 2014, Mr. Khani became a directorthe Company's five West Virginia coal mines in 2013 and the separation of the Company’s Marcellus Shale joint venture with Noble Energy Inc. in 2016. On January 3, 2018, Mr. Rush was appointed as a Director named Chief Financial Officer of the general partnership of CONE Midstream Partners LP. He was appointed a director of the


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general partner of CNX Coal Resources,Midstream Partners LP effective March 16, 2015.(formerly known as CONE Midstream Partners, LP). Mr. Rush holds a B.S in civil engineering from the University of Pittsburgh and an M.B.A from Carnegie Mellon University’s Tepper School of Business.

Timothy C. Dugan has beenserved as an Executive Vice President since September 20, 2016, and Chief Operating Officer- Exploration & ProductionOfficer of CONSOL EnergyCNX Resources Corporation since January 28, 2014. On September 20, 2016Mr. Dugan held the same position at the formerly named CONSOL Energy Inc. prior to its separation into two separate companies. Before being appointed to his current position, he was given the additional title of Executive Vice President. He was President and Chief Operating OfficeOfficer of CNX Gas Corporation from May 22, 2014 to December 1, 2014 when he became President and Chief Executive Officer. In January 2018, Mr. Dugan was appointed Director and named Chief Operating Officer of the general partner of CNX Midstream Partners LP (formerly known as CONE Midstream Partners, LP) on January 3, 2018, and January 12, 2018, respectively. Prior to joining CONSOL Energy,CNX, Mr. Dugan was Vice President - Appalachia South Business Unit at Chesapeake Energy Corporation. 


176


Corporation, a [include simple business description for Chesapeake]. During his seven years with Chesapeake Energy, he held theseveral titles, of Senior Asset Manager, Operations Superintendent,including Senior Asset Manager and District Manager. From 2001 to 2007, Mr. Dugan was employedbegan his petroleum and natural gas engineering career in 1984 with EQTCabot Oil & Gas Corporation whereas a General Foreman and Field Consultant, and he held the titles of Regional Reservoir Engineer and Director of Operations - Engineering.

James A. Brock has been Chief Operating Officer - Coal of CONSOL Energy since December 10, 2010. On September 20, 2016 he was given the additional title of Executive Vice President. Prior to this appointment, he served as Senior Vice President - Northern Appalachia - West Virginia Operations of CONSOL Energy beginning December 3, 2007.  From September 7, 2006 until December 3, 2007 he served as Vice President-Operations.  Mr. Brock began his careerother industry related positions with CONSOL Energy in 1979 at the Matthews Mine and since then has servedprogressing responsibility at various locations in many positions including Section Foreman, Mine Longwall Coordinator, General Mine Foreman,oil and Superintendent.gas companies. Mr. Brock was appointed the Chief Executive Officer andDugan is a directormember of the general partnerSociety of CNX Coal Resources, LP effective March 16, 2015.Petroleum Engineers.

CONSOL EnergyCNX has a written Code of Business Conduct that applies to CONSOL Energy'sCNX's Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer) and others. The Code of Business Conduct is available on CONSOL Energy'sCNX's website at www.consolenergy.com.www.cnx.com. Any amendments to, or waivers from, a provision of our code of employee business conduct and ethics that applies to our principal executive officer, our principal financial and accounting officer and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting such information on our website at www.consolenergy.com.www.cnx.com.

By certification dated June 8, 2016, CONSOL Energy's6, 2017, CNX's Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was not aware of any violation by the Company of the NYSE corporate governance listing standards. In addition, the required Sarbanes-Oxley Act, Section 302 certifications regarding the quality of our public disclosures were filed by CONSOL Energy as exhibits to this Form 10-K.


ITEM 11.EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from the information under the captions “BOARD OF DIRECTORS AND COMPENSATION INFORMATION and “EXECUTIVE COMPENSATION INFORMATION” (excluding the Compensation Committee Report) in the Proxy Statement.

ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item is incorporated by reference from the information under the captions “BENEFICIAL OWNERSHIP OF SECURITIES” and “SECURITIES AUTHORIZED FOR ISSUANCE UNDER CONSOL ENERGYCNX EQUITY COMPENSATION PLAN” in the Proxy Statement.


ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information requested by this Item is incorporated by reference from the information under the caption “PROPOSAL NO. 1-ELECTION OF DIRECTORS - Related Party Policy and Procedures and PROPOSAL NO. 1 - ELECTION OF DIRECTORS - Determination of Director Independence in the Proxy Statement.


ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated by reference from the information under the caption “ACCOUNTANTS AND AUDIT COMMITTEE-INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in the Proxy Statement.


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PART IV

ITEM 15.EXHIBIT INDEX
In reviewing any agreements incorporated by reference in this Form 10-K or filed with this 10-K, please remember that such agreements are included to provide information regarding their terms. They are not intended to be a source of financial, business or operational information about CONSOL EnergyCNX or any of its subsidiaries or affiliates. The representations, warranties and covenants contained in these agreements are made solely for purposes of the agreements and are made as of specific dates; are solely for the benefit of the parties; may be subject to qualifications and limitations agreed upon by the parties in connection with negotiating the terms of the agreements, including being made for the purpose of allocating contractual risk between the parties instead of establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors or security holders. Investors and security holders should not rely on the representations, warranties and covenants or any description thereof as characterizations of the actual state of facts or condition of CONSOL EnergyCNX or any of its subsidiaries or affiliates or, in connection with acquisition agreements, of the assets to be acquired. Moreover, information concerning the subject matter of the representations, warranties and covenants may change after the date of the agreements. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.
(A)(1) Financial Statements Contained in Item 8 hereof.
(A)(2) Financial Statement Schedule-Schedule II Valuation and qualifying accounts.
2.1
 Asset Acquisition Agreement dated August 17, 2011 between CNX Gas Company LLC and Noble Energy, Inc., incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on August 18, 2011.
2.2
 Joint Development Agreement by and among CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011, incorporated by reference to Exhibit 2.2 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2011, filed on October 31, 2011.
2.3
 Stock Purchase Agreement, dated October 25, 2013, among CONSOL Energy Inc., Consolidation Coal Company, Ohio Valley Resources, Inc., and, as to certain provisions of the Purchase Agreement, Murray Energy Corporation, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on December 11, 2013.
2.4
 Membership Interest and Asset Purchase Agreement dated February 26, 2016 among CONSOL Energy Inc., CONSOL Mining Holding Company LLC, CONSOL Buchanan Mining Company LLC, CONSOL Amonate Mining Company LLC CONSOL Mining Company LLC, CNX Land LLC, CNX Marine Terminals Inc., CNX RCPC LLC, CONSOL Pennsylvania Coal Company LLC and CONSOL Amonate Facility LLC and Coronado IV LLC which is incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on February 29, 2016.
2.5
 Exchange Agreement dated October 29, 2016, by and between CNX Gas Company LLC and Noble Energy, Inc. including Appendix I (Definitions) thereto, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on October 31, 2016.
2.6 First Amendment to Exchange Agreement dated as of December 1, 2016, by and between CNX Gas Company LLC and Noble Energy, Inc. Exhibits and Schedules identified in the First Amendment to Exchange Agreement are not being filed but will be furnished supplementally to the Securities and Exchange Commission upon request.
2.7
Separation and Distribution Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
2.8
Tax Matters Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
2.9
Employee Matters Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
2.10
Intellectual Property Matters Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 2.4 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
3.1
 Restated Certificate of Incorporation of CONSOL Energy Inc., incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on May 8, 2006.
3.2
 CONSOL Energy Inc. Bylaws (Amended andCertificate of Amendment to the Restated on September 20, 2016),Certificate of Incorporation of the Company, incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on September 26, 2016.December 4, 2017.
3.3
Amended and Restated Bylaws of the Company, incorporated by reference to Exhibit 3.2 to Form 8-K (file no. 001-14901) filed on December 4, 2017.


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4.1
 Supplemental Indenture, dated as of April 30, 2010, among Dominion Exploration & Production, Inc., Dominion Reserves, Inc., Dominion Coalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian Development Properties, LLC, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.6 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.
4.2
 Supplemental Indenture No. 2, dated as of June 16, 2010, among Cardinal States Gathering Company, CNX Gas Company LLC, CNX Gas Corporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.7 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.
4.3
 Supplemental Indenture No. 3, dated as of August 24, 2011, to Indenture dated as of April 1, 2010 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on August 29, 2011.


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4.4
 Supplemental Indenture No. 4, dated as of September 10, 2013, to Indenture dated as of April 1, 2010, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 of Form 10-Q (file no. 001-14901) filed on November 1, 2013.
4.5
 Supplemental Indenture No. 5, dated as of March 23, 2015, to the Indenture dated as of April 1, 2010 by and among CONSOL Energy Inc., the Subsidiary Guarantors listed on the signature pages thereof and Wells Fargo Bank, National Association, a national banking association, as successor trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.4 of Form 10-Q (file no. 001-14901) filed on May 5, 2015.
4.6
 Indenture, dated as of March 9, 2011, among CONSOL Energy Inc., the Subsidiaries named therein and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 6.375% Senior Notes due 2021, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on March 11, 2011.
4.7
 Supplemental Indenture No. 1, dated as of August 24, 2011, to Indenture dated as of March 9, 2011 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 6.375% Senior Notes due 2021, incorporated by reference to Exhibit 4.3 to Form 8-K (file no. 001-14901) filed on August 29, 2011.
4.8
 Supplemental Indenture No. 2, dated as of September 10, 2013, to Indenture dated as of March 9, 2011, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 6.375 % Senior Notes due 2021, incorporated by reference to Exhibit 4.3 of Form 10-Q (file no. 001-14901) filed on November 1, 2013.
4.9
 Supplemental Indenture No. 3, dated as of March 23, 2015, to the Indenture dated as of March 9, 2011 by and among CONSOL Energy Inc., the Subsidiary Guarantors listed on the signature pages thereof and Wells Fargo Bank, National Association, a national banking association, as successor trustee, with respect to the 6.375% Senior Notes due 2021, incorporated by reference to Exhibit 4.3 of Form 10-Q (file no. 001-14901) filed on May 5, 2015.
4.10
 Indenture, dated as of April 16, 2014, among CONSOL Energy Inc., the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, a national banking association, as trustee, with respect to the 5.875% Senior Notes due 2022, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
4.11
 Indenture, dated as of March 30, 2015, among CONSOL Energy Inc., the subsidiary guarantors party thereto and Well Fargo, National Association, as Trustee, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on March 30, 2015.
4.12
 Registration Rights Agreement, dated as of April 16, 2014, by and among CONSOL Energy Inc., the guarantors signatory thereto and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
4.13
 Registration Rights Agreement, dated as of August 12, 2014, by and among CONSOL Energy Inc., the guarantors signatory thereto and Goldman, Sachs & Co., as the initial purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on August 12, 2014.
4.14
 Registration Rights Agreement, dated as of March 30, 2015, among CONSOL Energy Inc., the subsidiary guarantors party thereto and Goldman, Sachs & Co. as the initial purchaser named therein, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on March 30, 2015.
4.15
 Agreement of Resignation, Appointment and Acceptance, dated July 22, 2013, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. signatory thereto, Wells Fargo Bank, National Association, as Successor Trustee to The Bank of Nova Scotia Trust Company of New York, and The Bank of Nova Scotia Trust Company of New York, as Resigning Trustee (related to the Indenture dated as of April 1, 2010 with respect to the 8.00% Senior Notes due 2017, the Indenture dated as of April 1, 2010 with respect to the 8.25% Senior Notes due 2020, and the Indenture dated as of March 9, 2011 with respect to the 6.375% Senior Notes due 2021), incorporated by reference to Exhibit 4.4 of Form 10-Q (file no. 001-14901) filed on November 1, 2013.


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10.1
 Purchase and Sale Agreement, dated as of April 30, 2003, by and among CONSOL Energy Inc., CONSOL Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company, CNX Gas Company LLC, CNX Marine Terminals Inc. and CNX Funding Corporation, incorporated by reference to Exhibit 10.30 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2003, filed on August 13, 2003.
10.2
First Amendment to Purchase and Sale Agreement dated as of April 30, 2007, entered into among CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals Inc., each an “Originator” and CNX Funding Corporation, incorporated by reference to Exhibit 10.31 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.


179


10.3Second Amendment to Purchase and Sale Agreement dated as of November 16, 2007, entered into among CONSOL Energy Inc. (“CONSOL Energy”), CONSOL Energy Sales Company, CONSOL of Kentucky Inc., Consol Pennsylvania Coal Company LLC, Consolidation Coal Company, Island Creek Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals Inc. (each an “Existing Originator”) and collectively the “Existing Originators”), Fola Coal Company, LLC., Little Eagle Coal Company, LLC., Mon River Towing, Inc., Terry Eagle Coal Company, LLC., Tri-River Fleeting Harbor Service, Inc., and Twin Rivers Towing Company (each, a “New Originator” and collectively the “New Originators”; the Existing Originators and the New Originators, each an “Originator” and collectively, the “Originators”), Windsor Coal Company (the “Released Originator”) and CNX Funding Corporation, incorporated by reference to Exhibit 10.32 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.4Third Amendment to the Purchase and Sale Agreement, dated as of March 12, 2010, among CNX Marine Terminals Inc., CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company LLC, Consolidated Coal Company, Eighty-Four Mining Company, Fola Coal Company, L.L.C., Island Creek Coal Company, Keystone Coal Mining Corporation, Little Eagle Coal Company, L.L.C., McElroy Coal Company, Mon River Towing, Inc., Terry Eagle Coal Company, L.L.C., Twin Rivers Towing Company and CNX Funding Corporation, incorporated by reference to Exhibit 10.6 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
10.5 Purchase and Sale Agreement dated July 19, 2016, among CONSOL of Kentucky Inc., Island Creek Coal Company, Laurel Run Mining Company, and CNX Land LLC and Southeastern Land, LLC, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on July 25, 2016.
10.6
10.3
 Purchase and Sale Agreement dated July 19, 2016, among AMVEST West Virginia Coal, L.L.C., Braxton-Clay Land & Mineral, Inc., Nicholas-Clay Land & Mineral, Inc., Peters Creek Mineral Services, Inc., Terry Eagle Limited Partnership, Terry Eagle Coal Company, L.L.C., Fola Coal Company, L.L.C., Little Eagle Coal Company, L.L.C., and Vaughan Railroad Company and Southeastern Land, LLC, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on July 25, 2016.
10.7
10.4
 Contribution Agreement dated as of November 15, 2016, by and among CONE Gathering LLC, CONE Midstream GP LLC, CONE Midstream Partners LP, CONE Midstream Operating Company LLC and certain other signatories thereto, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on November 16, 2016.
10.8Amended and Restated Receivable Purchase Agreement, dated as of April 30, 2007, by and among CNX Funding Corporation, CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company, CNX Marine Terminals Inc., Market Street Funding LLC, Liberty Street Funding LLC, PNC Bank, National Association, and the Bank of Nova Scotia, incorporated by reference to Exhibit 10.33 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.9First Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 9, 2007, entered into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.34 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.10Second Amendment to Amended and Restated Receivables Purchase Agreement, dated as of July 27, 2007, entered into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer (in such capacity, the “Servicer”), the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.35 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.11Third Amendment to Amended and Restated Receivables Purchase Agreement, dated as of November 16, 2007, entered into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various new sub-servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.36 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.12Fourth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 27, 2009, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.4 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
10.5


180


10.13Fifth Amendment to Amended and Restated Receivables Purchase Agreement and Waiver, dated as of March 12, 2010, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.5 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
10.14Sixth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 23, 2010, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages of the Amendment, the Conduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LC Participants listed on the signature pages of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.13 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February 10, 2011.
10.15Seventh Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 30, 2012, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages of the Amendment, the Conduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LC Participants listed on the signature pages of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.5 to Form 10-Q for the quarter ended March 31, 2012 (file no. 001-14901), filed on April 30, 2012.
10.16Eighth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of November 8, 2012, by and among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.17Ninth Amendment to Amended and Restated Receivables Purchase Agreement, dated September 23, 2013, by and among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, Market Street Funding LLC, as Assignor, and PNC Bank, National Association, as Administrator, as LC Bank and as Assignee, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2013, filed on November 1, 2013.
10.18Tenth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 28, 2014, by and among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.19Eleventh Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 23, 2014, by and among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no. 001-14901) filed on May 5, 2015.
10.20Twelfth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 27, 2015, by and among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.3 of Form 10-Q (file no. 001-14901) filed on May 5, 2015..
10.21Letter Agreement re: Receivables Purchase Agreement - Dilution Ratio, dated June 21, 2012, incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2012 (file no. 001-14901), filed on August 1, 2012.
10.22Letter Agreement Re: Receivables Purchase Agreement - Delinquency Ratio and Default Ratio, dated April 18, 2014, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) filed on May 5, 2015.
10.23Payoff and Termination Letter re: Amended and Restated Receivables Purchase Agreement, dated as of July 7, 2015, by and among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no. 001-14901) filed on July 31, 2015.


181


10.24 Amended and Restated Credit Agreement, dated as of April 12, 2011, by and among CONSOL Energy Inc., the Guarantors Party thereto, the Lenders Party thereto, PNC Bank, National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and Sovereign Bank, as the Co-Documentation Agents, and PNC Capital Markets LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Joint Lead Arrangers, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.25
10.6
 Amendment No. 1 to Credit Agreement, dated as of December 5, 2013, to the Amended and Restated Credit Agreement, dated as of April 12, 2011, by and among CONSOL Energy Inc., the lenders and agents party thereto and PNC Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on December 11, 2013.
10.26
10.7
 Amended and Restated Credit Agreement, dated as of June 18, 2014, by and among CONSOL Energy Inc., the lenders and agents party thereto and PNC Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K/A (file no. 001-14901) filed on June 25, 2014.
10.27
10.8
 Amendment No. 1, dated as of May 22, 2015, to the Amended and Restated Credit Agreement, dated as of June 18, 2014, by and among CONSOL Energy Inc., the subsidiary guarantors party thereto and certain lenders and PNC Bank, National Association as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 26, 2015.
10.28
10.9
 Amendment No. 2, dated as of April 20, 2016, to the Amended and Restated Credit Agreement, dated as of June 18, 2014, and the Amended and Restated Security Agreement, dated as of June 18, 2014, by and among CONSOL Energy Inc., the subsidiary guarantors party thereto, certain lenders and PNC Bank, National Association as administrative agent and as collateral agent, incorporated by reference to Exhibit 10.1 to the Form 8-K (file no. 001-14901) filed on April 26, 2016.
10.29
10.10
Amendment No. 3 and Borrowing Base Redetermination, dated as of October 25, 2017, to the Amended and Restated Credit Agreement, dated as of June 18, 2014, by and among CONSOL Energy Inc., the subsidiary guarantors party thereto, certain lenders and PNC Bank, National Association as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on October 31, 2017.
10.11
Amendment No. 4, dated as of November 27, 2017, to the Amended and Restated Credit Agreement, dated as of June 18, 2014, by and among CONSOL Energy Inc., the subsidiary guarantors party thereto, certain lenders and PNC Bank, National Association as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on December 1, 2017.
10.12
 Resignation, Consent and Appointment Agreement entered into as of September 12, 2016, by and among Bank of America, N.A., as the resigning Syndication Agent under that certain Amended and Restated Credit Agreement, dated as of June 18, 2014, JPMorgan Chase Bank, N.A., as the successor Syndication Agent, and CONSOL Energy Inc., a Delaware corporation, as the Borrower, incorporated by reference to Exhibit 10.3 to the Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2016, filed on November 1, 2016.
10.30
10.13
 Amended and Restated Collateral Trust Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc. and its Designated Subsidiaries, Wilmington Trust Company, as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on May 13, 2010.
10.31
10.14
 Amended and Restated Pledge Agreement, dated as of May 7, 2010, made and entered into by each of the pledgors listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on May 13, 2010.


129


10.32
10.15
 Amended and Restated Security Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc., each of the parties listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.4 to Form 8-K (file no. 001-14901) filed on May 13, 2010.
10.33
10.16
 Patent, Trademark and Copyright Security Agreement, dated as of June 27, 2007, by and among each of the pledgors listed on the signature pages thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 10.20 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February 10, 2011.
10.34
10.17
 First Amendment to Amended and Restated Patent, Trademark and Copyright Security Agreement, dated as of May 7, 2010, by and among each of the pledgors listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.5 to Form 8-K (file no. 001-14901) filed on May 13, 2010.
10.35
10.18
 Patent, Trademark and Copyright Assignment and Assumption, dated as of April 12, 2011, between Wilmington Trust Company as assignor and PNC Bank, National Association as assignee, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.36
10.19
 Guaranty and Suretyship Agreement, dated as of April 30, 2003, by CONSOL Energy Inc., as guarantor in favor of CNX Funding Corporation, incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2011, filed on May 3, 2011.
10.37
10.20
 Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of May 7, 2010, jointly and severally given by each of the undersigned thereto and each of the other persons which become Guarantors thereunder from time to time in favor of PNC Bank, National Association, in its capacity as the administrative agent for the Lenders, in connection with that certain Amended and Restated Credit Agreement, as defined therein, incorporated by reference to Exhibit 10.22 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February 10, 2011.


182


10.38
10.21
 CNX Gas Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, by CNX Gas Corporation and certain of its subsidiaries, incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.39
10.22
 Successor Agent Agreement, dated as of April 12, 2011, by and among among Wilmington Trust Company and David A. Varansky as existing agents, PNC Bank, National Association as Collateral Trustee and CONSOL Energy Inc. and certain of its subsidiaries, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.40
10.23
 Amended and Restated Credit Agreement, dated as of April 12, 2011, by and among CNX Gas Corporation, the Guarantors Party thereto, the Lenders Party thereto, PNC Bank, National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and Wells Fargo Bank, N.A., as the Co-Documentation Agents, and PNC Capital Markets LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Bookrunners and Joint Lead Arrangers, incorporated by reference to Exhibit 10.3 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.41
10.24
 Amendment No. 1 to Credit Agreement, dated as of December 14, 2011, by and among CNX Gas Corporation, the lenders and agents party thereto and PNC Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.29 to Form 10-K for the year ended December 31, 2012 (file no. 01-14901), filed on February 7, 2013.
10.42
10.25
 Amendment No. 2 to Credit Agreement, dated as of March 12, 2013, to the Amended and Restated Credit Agreement, dated as of April 12, 2011, as amended by Amendment No. 1, dated December 14, 2011, by and among CNX Gas Corporation, the lenders and agents party thereto and PNC Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.
10.43
10.26
 Collateral Trust Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation, its Designated Subsidiaries, Wilmington Trust Company, as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by reference to Exhibit 2.1 to the CNX Gas Corporation Form 8-K (file no. 001-32723) filed on May 13, 2010.
10.44
10.27
 Pledge Agreement, dated as of May 7, 2010, by each of the pledgors listed on the signature pages thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.2 to the CNX Gas Corporation Form 8-K (file no. 001-32723) filed on May 13, 2010.
10.45
10.28
 Security Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation and each of the undersigned parties thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.3 to the CNX Gas Corporation Form 8-K (file no. 001-32723) filed on May 13, 2010.
10.46
10.29
 CONSOL Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, by CONSOL Energy and certain of its subsidiaries, incorporated by reference to Exhibit 10.4 to Form 8-K (file no. 001-14901) filed on April 18, 2011.


130


10.47
10.30
 Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, among CNX Gas Company LLC and certain of its subsidiaries, incorporated by reference to Exhibit 10.5 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.48
10.31
 Successor Agent Agreement, dated as of April 12, 2011, by and among Wilmington Trust Company and David A. Vanaskey as existing agents, PNC Bank, National Association as Collateral Trustee and CNX Gas Corporation and certain of its subsidiaries, incorporated by reference to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
10.49
10.32
 Closing Agreement by and between CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011, incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2011, filed on October 31, 2011.
10.50
10.33
 Stipulation and Agreement of Compromise and Settlement, dated May 8, 2013, between and among (i) plaintiffs Harold L. Hurwitz and James R. Gummel, on their own behalf and on behalf of the Class (as defined therein) and (ii) defendants CNX Gas Corporation, CONSOL Energy Inc. and certain individual defendants, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2013, filed on August 5, 2013.
10.51
10.34
 Amendment No. 1, dated April 19, 2013, to the Asset Acquisition Agreement, dated August 17, 2011, between CNX Gas Company LLC and Noble Energy, Inc, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2013, filed on August 5, 2013.
10.52
10.35
 Purchase Agreement, dated as of April 10, 2014, among CONSOL Energy Inc., the subsidiary guarantors party thereto and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers named therein, incorporated by reference to Exhibit 1.1 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
10.53*
10.36
Transition Services Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on December 4, 2017
10.37
CNX Resources Corporation to CONSOL Energy Inc. Trademark License Agreement dated as of November 28, 2017, by and between the Company and CONSOL Energy Inc., incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on December 4, 2017
10.38
CONSOL Energy Inc. to CNX Resources Corporation Trademark License Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Energy Inc., incorporated by reference to Exhibit 10.3 to Form 8-K (file no. 001-14901) filed on December 4, 2017
10.39*
 Amended and Restated Employment Agreement, dated March 21, 2014, between CONSOL Energy Inc. and J. Brett Harvey incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 26, 2014.
10.54*
10.40*
 Letter Agreement, dated August 24, 2007, by and between CONSOL Energy Inc. and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on August 24, 2007.


183


10.55*
10.41*
 Change in Control Agreement by and between CONSOL Energy Inc. and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.7 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
10.56*Amended and Restated Change in Control Severance Agreement, dated as of April 10, 2014, between CONSOL Energy Inc. and David M. Khani, incorporated by reference to Exhibit 10.8 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.57*
10.42*
 Amended and Restated Change in Control Severance Agreement, dated as of October 9, 2015, between CONSOL Energy Inc., and David M. Khani, incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2015, filed on November 3, 2015.
10.58*Amended and Restated Change in Control Severance Agreement, dated as of April 10, 2014, between CONSOL Energy Inc. and James Grech, incorporated by reference to Exhibit 10.9 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.59*
10.43*
 Change in Control Agreement by and among CNX Gas Corporation, CONSOL Energy Inc. and Stephen W. Johnson, incorporated by reference to Exhibit 10.4 to Form 10-K for the year ended December 31, 2008 of CNX Gas Corporation (file no. 001-32723) filed on February 17, 2009.
10.60*Amended and Restated Change in Control Severance Agreement, dated as of August 24, 2015, between CONSOL Energy Inc., and James A. Brock, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2015, filed on November 3, 2015
10.61*
10.44*
 Amended and Restated Change in Control Severance Agreement, dated as of February 7, 2017, between CNX Coal Resources GP LLC, and James A. Brock.Brock, incorporated by reference Exhibit 10.61 to Form 10-K (file no. 001-14901) for year-end December 31, 2016 filed on February 8, 2017.
10.62*
10.45*
 Amended and Restated Change in Control Severance Agreement, dated as of August 24, 2015, between CONSOL Energy Inc., and Timothy Dugan, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2015, filed on November 3, 2015.
10.63*Agreement, dated as of April 28, 2016, between CONSOL Energy Inc. and James C. Grech, incorporated by reference to Exhibit 10.1 to the Form 8-K (file no. 001-14901) filed on May 4, 2016.
10.64*
10.46*
 Form of Indemnification Agreement for Directors and Executive Officers of CONSOL Energy Inc., incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.
10.65*
10.47*
 Form of Indemnification Agreement for Directors and Executive Officers of CNX Gas Corporation, incorporated by reference to Exhibit 10.7 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.
10.66*
10.48*
 CONSOL Energy Inc.CNX Resources Corporation Equity Incentive Plan, as amended and restated effective May 11, 2016, incorporated by reference to Exhibit 99.1 to the Form S-8 (file no. 333-211286)January 26, 2018, filed on May 4, 2016.herewith.
10.67*
10.49*
 Amended and Restated CONSOL Energy Inc.CNX Resources Corporation Executive Annual Incentive Plan, incorporated by reference to Appendix A to the Form DEF 14A (file no. 001-14901) filed on March 29, 2013.herewith.
10.68*
10.50*
 Form of Non-Qualified Stock Option Award Agreement For Employees, incorporated by reference to Exhibit 10.26 to the Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.


131


10.69*
10.51*
 Form of Non-Qualified Stock Option Award Agreement for Employees (February 17, 2009 and through 2012), incorporated by reference to Exhibit 10.28 to Form S-4 (file no. 333-157894) filed on June 26, 2009.
10.70*
10.52*
 Form of Non-Qualified Performance Stock Option Agreement for Employees, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on June 21, 2010.
10.71*
10.53*
 Form of Non-Qualified Stock Option Award for Employees (January 27, 2016), incorporated by reference to Exhibit 10.72 to Form 10-K (file no. 001-14901) for the year ended December 31, 2015, filed on February 5, 2016.
10.72*
10.54*
 Form of Employee Nonqualified Stock Option Agreement (May 26, 2016), incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2016, filed on July 29, 2016.
10.73*
10.55*
 Form of Restricted Stock Unit Award for Employees (February 17, 2009 through 2014), incorporated by reference to Exhibit 10.31 to Amendment No. 1 to Form S-4 (file no. 333-157894) filed on June 26, 2009.
10.74*
10.56*
 Form of 5-Year Restricted Stock Unit Award Agreement for Employees, incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.75*
10.57*
 Form of Restricted Stock Unit Award Agreement for Directors, incorporated by reference to Exhibit 10.30 to the Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.
10.76*
10.58*
 Form of Restricted Stock Unit Award Agreement for Employees (for 2015 awards), incorporated by reference to Exhibit 10.67 to Form 10-K for the year ended December 31, 2014 (file no. 001-14901), filed on February 6, 2015.
10.77*
10.59*
 Form of Restricted Stock Unit Award Agreement for Employees (With Deferral Election) (for 2017 awards).
10.78*
10.60*
 Form of Performance Share Unit Award Agreement (for 2014 awards), incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.79*
10.61*
 Form of Performance Share Unit Award Agreement (for 2015 awards), incorporated by reference to Exhibit 10.69 to Form 10-K for the year ended December 31, 2014 (file no. 001-14901), filed on February 6, 2015.


184


10.80*
10.62*
 Form of Performance Share Unit Award Agreement (for 2016 awards), incorporated by reference to Exhibit 10.79 to Form 10-K (file no. 001-14901) for the year ended December 31, 2015, filed on February 5, 2016.
10.81*
10.63*
 Form of Performance Share Unit Award Agreement (for 2017 awards).
10.82*
10.64*
 Summary of Non-Employee Director Compensation, incorporated by reference to Exhibit 10.69 to Form 10-K (file no. 001-14901) for the year ended December 31, 2013, filed on February 7, 2014.
10.83*
10.65*
 Directors Deferred Compensation Plan (1999 Plan), incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.84*
10.66*
 Directors' Deferred Fee Plan (2004 Plan) (Amended and Restated on December 4, 2007), incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.85*
10.67*
 Hypothetical Investment Election Form Relating to Directors' Deferred Fee Plan (2004 Plan), incorporated by reference to Exhibit 10.50 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
10.86*
10.68*
 Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.95 to the Form 8-K (file no. 001-14901) filed on May 8, 2006.
10.87*
10.69*
 Trust Agreement (Amended and Restated on March 20, 2008) (1999 Directors Deferred Compensation Plan), incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.88*
10.70*
 Trust Agreement (Amended and Restated on March 20, 2008) (Directors' Deferred Fee Plan (2004 Plan)), incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.89*
10.71*
 Amended and Restated Retirement Restoration Plan of CONSOL Energy Inc., incorporated reference to Exhibit 10.30 to Form 10-K for the year endedCNX Resources Corporation, as amended and restated effective December 31,2, 2008, (file no. 001-14901),as amended and restated effective November 28, 2017, filed on February 17, 2009.herewith.
10.90*
10.72*
 Amended and Restated Supplemental Retirement Plan of CONSOL Energy Inc.CNX Resources Corporation effective January 1, 2007, as amended and restated on September 8, 2009, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901)effective November 28, 2017, filed on September 11, 2009.herewith.
10.91*
10.73*
 Amendment to CONSOL Energy Inc. Supplemental Retirement Plan, dated as of October 17, 2011, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901), for the quarter ended September 30, 2011, filed on October 31, 2011.
10.92*CONSOL Energy Inc.CNX Resources Corporation Defined Contribution Restoration Plan, effective January 1, 2012, incorporated by reference to Exhibit 10.12 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014,as amended and restated effective November 28, 2017, filed on May 6, 2014.herewith.
10.93*
10.74*
 Executive Compensation Clawback Policy of CONSOL Energy Inc., dated as of January 28, 2014, incorporated by reference to Exhibit 10.11 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.75*
Purchase and Sale Agreement, dated as of February 7, 2018, by and among CNX Midstream Partners LP, CNX Midstream DevCo I LP, CNX Midstream DevCo III LP, CNX Gathering LLC, and, for certain purposes, CNX Midstream DevCo I GP LLC, CNX Midstream DevCo III GP LLC and CNX Midstream Operating Company LLC.
12
 Computation of Ratio of Earnings to Fixed Charges.
14.1Code of Employee Business Conduct and Ethics
21
 Subsidiaries of CONSOL Energy Inc.CNX Resources Corporation.
23.1
 Consent of Ernst & Young LLP
23.2
 Consent of Netherland Sewell & Associates, Inc.


132


31.1
 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2
 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1
 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2
 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
95
 Mine Safety Disclosure Exhibit
99
99.1
 Engineers' Audit Letter
99.2
 Financial Statements of CNX Gathering LLC
101 Interactive Data File (Form 10-K for the year ended December 31, 20162017 furnished in XBRL).

* Denotes the management contracts and compensatory arrangements in which any director or any named executive officer participates
Supplemental Information
No annual report or proxy material has been sent to shareholders of CONSOL EnergyCNX at the time of filing of this Form 10-K. An annual report will be sent to shareholders and to the commission subsequent to the filing of this Form 10-K.

In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.

ITEM 16. FORM 10-K SUMMARY
NONE

185

133


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, as of the 8th7th day of February, 2017.2018.
 CONSOL ENERGY INC.CNX RESOURCES CORPORATION
    
 By:  
/s/    NICHOLAS J. DEIULIIS    
   Nicholas J. DeIuliis
   Director, Chief Executive Officer and President
   (Duly Authorized Officer and Principal Executive Officer)
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 8th day of February, 2017, by the following persons on behalf of the registrant in the capacities indicated:
Signature Title
   
/s/    NICHOLAS J. DEIULIIS    
 Director, Chief Executive Officer and President
Nicholas J. DeIuliis (Duly Authorized Officer and Principal Executive Officer)
   
/s/    DAVIDONALD M. KW. RHANIUSH     
 Chief Financial Officer and Executive Vice President
David M. KhaniDonald W. Rush (Duly Authorized Officer and Principal Financial Officer)
   
/s/    C. KJRISTOPHERASON  HL. MAGEDORNUMFORD
 Controller and Vice President
C. Kristopher HagedornJason L. Mumford (Duly Authorized Officer and Principal Accounting Officer)
   
/s/   WILLIAM N. THORNDIKE JR.
 Director and Chairman of the Board
William N. Thorndike Jr.  
   
/s/    AJ. PLVINALMER R. CARPENTERLARKSON
 Director
Alvin R. CarpenterJ. Palmer Clarkson  
   
/s/    WILLIAM E. DAVIS       
 Director
William E. Davis  
   
/s/    MAUREEN E. LALLY-GREEN   
 Director
Maureen E. Lally-Green  
   
/s/    GREGORY A. LANHAM  
Director
Gregory A. Lanham
/s/    BERNARD LANIGAN JR. 
 Director
Bernard Lanigan Jr.  
/s/    JOHN T. MILLS
Director
John T. Mills
/s/    JOSEPH P.PLATT
Director
Joseph P. Platt
/s/    WILLIAM P. POWELL
Director
William P. Powell
/s/   EDWINS.ROBERSON
Director
Edwin S. Roberson


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SCHEDULE II

CONSOL ENERGY INC.CNX RESOURCES CORPORATION AND SUBSIDIARIES
Valuation and Qualifying Accounts
(Dollars in thousands)

   Additions Deductions     Additions Deductions  
 Balance at   Release of   Balance at Balance at   Release of   Balance at
 Beginning Charged to Valuation Charged to End Beginning Charged to Valuation Charged to End
 of Period Expense Allowance Expense of Period
Year Ended December 31, 2017          
State operating loss carry-forwards $60,488
 $—
 $1,072
 $—
 $61,560
Deferred deductible temporary differences 10,590
 —
 (1,502) —
 9,088
Charitable Contributions 5,052
 —
 (1,896) —
 3,156
162(m) Officers Compensation —
 —
 5,957
 —
 5,957
AMT Credit 166,798
 —
 (154,385) —
 12,413
Foreign Tax Credits 39,850
 4,552
 —
 —
 44,402
Total $282,778
 $4,552
 $(150,754) $—
 $136,576
 of Period Expense Allowance Expense of Period          
Year Ended December 31, 2016                    
State operating loss carry-forwards $42,983
 $17,505
 $—
 $—
 $60,488
 $42,983
 $17,505
 $—
 $—
 $60,488
Deferred deductible temporary differences 9,420
 1,170
 —
 —
 10,590
 9,420
 1,170
 —
 —
 10,590
Charitable Contributions —
 5,052
 —
 —
 5,052
 —
 5,052
 —
 —
 5,052
AMT Credit —
 166,798
 —
 —
 166,798
 —
 166,798
 —
 —
 166,798
Foreign Tax Credits 25,903
 13,947
 —
 —
 39,850
 25,903
 13,947
 —
 —
 39,850
Total $78,306
 $204,472
 $—
 $—
 $282,778
 $78,306
 $204,472
 $—
 $—
 $282,778
                    
Year Ended December 31, 2015                    
State operating loss carry-forwards $6,080
 $31,578
 $5,325
 $—
 $42,983
 $6,080
 $31,578
 $5,325
 $—
 $42,983
Deferred deductible temporary differences 16
 7,914
 1,490
 —
 9,420
 16
 7,914
 1,490
 —
 9,420
Foreign Tax Credits —
 25,903
 —
 —
 25,903
 —
 25,903
 —
 —
 25,903
Total $6,096
 $65,395
 $6,815
 $—
 $78,306
 $6,096
 $65,395
 $6,815
 $—
 $78,306
          
Year Ended December 31, 2014          
State operating loss carry-forwards $7,527
 $157
 $(1,323) $(281) $6,080
Deferred deductible temporary differences 5
 11
 —
 —
 16
Total $7,532
 $168
 $(1,323) $(281) $6,096



187135