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x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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51-0337383
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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Title of each class
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Name of exchange on which registered
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Common Stock ($.01 par value)
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New York Stock Exchange
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Preferred Share Purchase Rights
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New York Stock Exchange
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TABLE OF CONTENTS
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Page
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PART I
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ITEM 1.
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Business
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ITEM 1A.
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Risk Factors
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ITEM 1B.
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Unresolved Staff Comments
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ITEM 2.
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Properties
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ITEM 3.
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Legal Proceedings
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ITEM 4.
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Mine Safety and Health Administration Safety Data
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PART II
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ITEM 5.
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Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
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ITEM 6.
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Selected Financial Data
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ITEM 7.
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Management's Discussion and Analysis of Financial Condition and Results of Operations
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ITEM 7A.
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Quantitative and Qualitative Disclosures About Market Risk
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ITEM 8.
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Financial Statements and Supplementary Data
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ITEM 9.
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Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
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ITEM 9A.
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Controls and Procedures
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ITEM 9B.
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Other Information
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PART III
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ITEM 10.
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Directors and Executive Officers of the Registrant
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ITEM 11.
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Executive Compensation
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ITEM 12.
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Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
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ITEM 13.
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Certain Relationships and Related Transactions and Director Independence
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ITEM 14.
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Principal Accounting Fees and Services
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PART IV
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ITEM 15.
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Exhibits and Financial Statement Schedules
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ITEM 16.
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Form 10-K Summary
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SIGNATURES
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•
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prices for natural gas and natural gas liquids are volatile and can fluctuate widely based upon a number of factors beyond our control including oversupply relative to the demand for our products, weather and the price and availability of alternative fuels;
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•
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our dependence on gathering, processing and transportation facilities and other midstream facilities owned by CNX Midstream Partners LP (NYSE: CNXM) (CNXM) and others;
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•
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uncertainties in estimating our economically recoverable natural gas reserves, and inaccuracies in our estimates;
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•
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the high-risk nature of drilling and developing natural gas wells;
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•
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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;
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•
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challenges associated with strategic determinations, including the allocation of capital and other resources to strategic opportunities;
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•
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our development and exploration projects, as well as CNXM’s midstream system development, require substantial capital expenditures;
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•
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the impact of potential, as well as any adopted environmental regulations including any relating to greenhouse gas emissions on our operating costs as well as on the market for natural gas and for our securities;
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•
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environmental regulations can increase costs and introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities;
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•
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our operations are subject to operating risks that could increase our operating expenses and decrease our production levels which could adversely affect our results of operation and our 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;
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•
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decreases in the availability of, or increases in the price of, required personnel, services, equipment, parts and raw materials in sufficient quantities or at reasonable costs to support our operations;
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•
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if natural gas prices decrease or drilling efforts are unsuccessful, we may be required to record write-downs of our proved natural gas properties;
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•
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changes in assumptions impacting management’s estimates of future financial results as well as other assumptions such as movement in our stock price, weighted-average cost of capital, terminal growth rates and industry multiples, could cause goodwill and other intangible assets we hold to become impaired and result in material non-cash charges to earnings;
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•
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a loss of our competitive position because of the competitive nature of the natural gas industry, consolidation within the industry or overcapacity in the industry adversely affecting our ability to sell our products and midstream services, which could impair our profitability;
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•
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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;
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•
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hedging activities may prevent us from benefiting from price increases and may expose us to other risks;
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•
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existing and future government laws, regulations and other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations;
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•
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significant costs and liabilities may be incurred as a result of pipeline operations and related increase in the regulation of gas gathering pipelines;
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•
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our ability to find adequate water sources for our use in shale gas drilling and production operations, or our ability to dispose of, transport or recycle water used or removed in connection with our gas operations at a reasonable cost and within applicable environmental rules;
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•
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failure to find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves;
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•
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risks associated with our debt;
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•
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a decrease in our borrowing base, which could decrease for a variety of reasons including lower natural gas prices, declines in natural gas proved reserves, asset sales and lending requirements or regulations;
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•
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changes in federal or state income tax laws;
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•
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cyber-incidents could have a material adverse effect on our business, financial condition or results of operations;
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•
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construction of new gathering, compression, dehydration, treating or other midstream assets by CNXM may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks;
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•
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our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel;
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•
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terrorist activities could materially and adversely affect our business and results of operations;
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•
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we may operate a portion of our business with one or more joint venture partners or in circumstances where we are not the operator, which may restrict our operational and corporate flexibility and we may not realize the benefits we expect to realize from a joint venture;
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•
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acquisitions and divestitures we anticipate may not occur or produce anticipated benefits;
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•
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the outcomes of various legal proceedings, including those which are more fully described in our reports filed under the Exchange Act;
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•
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there is no guarantee that we will continue to repurchase shares of our common stock under our current or any future share repurchase program at levels undertaken previously or at all;
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•
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negative public perception regarding our industry could have an adverse effect on our operations;
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•
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CONSOL Energy may not be able to satisfy its indemnification obligations in the future and such indemnities may not be sufficient to hold us harmless from the full amount of liabilities for which CONSOL Energy will be allocated responsibility;
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•
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the separation of CONSOL Energy could result in substantial tax liability; and
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•
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other factors discussed in this 2018 Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file with the Securities and Exchange Commission.
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ITEM 1.
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Business
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•
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Total average production of 1,389,325 Mcfe per day;
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•
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92% Natural Gas, 8% Liquids; and
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•
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57% Marcellus, 30% Utica, 12% coalbed methane, and 1% other.
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•
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7.9 Tcfe of proved reserves;
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•
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94.4% natural gas;
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•
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57.0% proved developed;
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•
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98.6% operated; and
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•
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A reserve life ratio of 15.54 years (based on 2018 production).
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•
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Responsibility: Be a safe and compliant operator; be a trusted community partner and respected corporate citizen; act with pride and integrity;
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•
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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
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•
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Excellence: Be prudent capital allocators; be a lean, efficient, nimble organization; be a disciplined, reliable, performance-driven company.
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Marcellus
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Utica
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CBM
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Other Gas
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Segment
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Segment
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Segment
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Segment
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Total
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Estimated Net Proved Reserves (MMcfe)
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5,595,409
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1,067,617
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1,209,638
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8,671
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7,881,335
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Percent Developed
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54
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%
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49
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%
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77
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%
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100
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%
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57
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%
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Net Producing Wells (including oil and gob wells)
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355
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45
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4,152
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71
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4,623
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Net Acreage Position:
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Net Proved Developed Acres
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42,853
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12,090
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231,415
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3,244
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289,602
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Net Proved Undeveloped Acres
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26,324
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7,046
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—
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—
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33,370
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Net Unproved Acres(1)
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515,073
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252,473
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2,227,764
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965,118
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3,960,428
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Total Net Acres(2)
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584,250
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271,609
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2,459,179
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968,362
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4,283,400
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(1)
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Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
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(2)
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Acreage amounts are only included under the target strata CNX expects to produce with the exception of certain CBM acres governed by separate leases, although the reported acres may include rights to multiple gas seams (e.g. we have rights to the 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, and our acreage rights and have used our best judgment to reflect the acres in the strata we expect to primarily produce. As more information is obtained or circumstances change, the acreage classification may change.
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Gross
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Net(1)
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Producing Gas Wells (including gob wells)
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6,453
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4,623
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Producing Oil Wells
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149
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1
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Net Acreage Position:
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||
Proved Developed Acreage
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289,602
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289,602
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Proved Undeveloped Acreage
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33,370
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33,370
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Unproved Acreage
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4,940,180
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3,960,428
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Total Acreage
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5,263,152
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4,283,400
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(1)
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Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
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Gross Unproved Acres
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Net Unproved Acres
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Net Proved Undeveloped Acres
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Held by production/fee
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4,797,145
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3,896,613
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18,524
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Expiration within 2 years
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87,553
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37,115
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7,628
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Expiration beyond 2 years
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55,482
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26,700
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7,218
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Total Acreage
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4,940,180
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3,960,428
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33,370
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For the Year
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|||||||
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Ended December 31,
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|||||||
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2018
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2017
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2016
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|||||
Marcellus segment
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65.9
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|
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9.0
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—
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Utica segment
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12.0
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17.0
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|
13.0
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CBM segment
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6.0
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64.0
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23.0
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Other Gas segment
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—
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|
|
—
|
|
|
—
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|
Total Development Wells (Net)
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|
83.9
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|
|
90.0
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|
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36.0
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For the Year Ended December 31,
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|||||||||||||||||||||||||
|
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2018
|
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2017
|
|
2016
|
|||||||||||||||||||||
|
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Producing
|
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Dry
|
|
Still Eval.
|
|
Producing
|
|
Dry
|
|
Still Eval.
|
|
Producing
|
|
Dry
|
|
Still Eval.
|
|||||||||
Marcellus segment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Utica segment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
CBM segment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other Gas segment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Exploratory Wells (Net)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.0
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|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
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|
|
|
Net Reserves
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|||||||
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(Million cubic feet equivalent)
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|||||||
|
|
as of December 31,
|
|||||||
|
|
2018
|
|
2017
|
|
2016
|
|||
Proved developed reserves
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|
4,494,878
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|
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4,409,065
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3,683,302
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|
Proved undeveloped reserves
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3,386,457
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|
|
3,172,547
|
|
|
2,568,346
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|
Total proved developed and undeveloped reserves(1)
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|
7,881,335
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|
|
7,581,612
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|
|
6,251,648
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(1)
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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.
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|
|
Discounted Future
|
||||||||||
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|
Net Cash Flows
|
||||||||||
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(Dollars in millions)
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Future net cash flows
|
|
$
|
13,132
|
|
|
$
|
7,841
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|
|
$
|
2,419
|
|
Total PV-10 measure of pre-tax discounted future net cash flows (1)
|
|
$
|
6,172
|
|
|
$
|
4,140
|
|
|
$
|
1,559
|
|
Total standardized measure of after tax discounted future net cash flows
|
|
$
|
4,655
|
|
|
$
|
3,131
|
|
|
$
|
955
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|
(1)
|
We calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-Generally Accepted Accounting Principles (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of the financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.
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|
|
As of December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
|
(Dollars in millions)
|
||||||||||
Future cash inflows
|
|
$
|
26,610
|
|
|
$
|
19,262
|
|
|
$
|
11,303
|
|
Future production costs
|
|
(7,730
|
)
|
|
(7,234
|
)
|
|
(5,851
|
)
|
|||
Future development costs (including abandonments)
|
|
(1,600
|
)
|
|
(1,711
|
)
|
|
(1,550
|
)
|
|||
Future net cash flows (pre-tax)
|
|
17,280
|
|
|
10,317
|
|
|
3,902
|
|
|||
10% discount factor
|
|
(11,108
|
)
|
|
(6,177
|
)
|
|
(2,343
|
)
|
|||
PV-10 (Non-GAAP measure)
|
|
6,172
|
|
|
4,140
|
|
|
1,559
|
|
|||
Undiscounted income taxes
|
|
(4,147
|
)
|
|
(2,476
|
)
|
|
(1,483
|
)
|
|||
10% discount factor
|
|
2,630
|
|
|
1,467
|
|
|
879
|
|
|||
Discounted income taxes
|
|
(1,517
|
)
|
|
(1,009
|
)
|
|
(604
|
)
|
|||
Standardized GAAP measure
|
|
$
|
4,655
|
|
|
$
|
3,131
|
|
|
$
|
955
|
|
|
|
For the Year
|
|||||||
|
|
Ended December 31,
|
|||||||
|
|
2018
|
|
2017
|
|
2016
|
|||
Natural Gas
|
|
|
|
|
|
|
|||
Sales Volume (MMcf)
|
|
|
|
|
|
|
|||
Marcellus
|
|
255,127
|
|
|
209,687
|
|
|
186,812
|
|
Utica
|
|
148,117
|
|
|
70,708
|
|
|
71,277
|
|
CBM
|
|
60,268
|
|
|
65,373
|
|
|
68,971
|
|
Other
|
|
4,714
|
|
|
19,125
|
|
|
21,693
|
|
Total
|
|
468,226
|
|
|
364,893
|
|
|
348,753
|
|
|
|
|
|
|
|
|
|||
NGL
|
|
|
|
|
|
|
|||
Sales Volume (Mbbls)
|
|
|
|
|
|
|
|||
Marcellus
|
|
5,227
|
|
|
4,604
|
|
|
3,922
|
|
Utica
|
|
853
|
|
|
1,851
|
|
|
2,787
|
|
Other
|
|
1
|
|
|
1
|
|
|
1
|
|
Total
|
|
6,081
|
|
|
6,456
|
|
|
6,710
|
|
|
|
|
|
|
|
|
|||
Oil and Condensate
|
|
|
|
|
|
|
|||
Sales Volume (Mbbls)
|
|
|
|
|
|
|
|||
Marcellus
|
|
286
|
|
|
346
|
|
|
360
|
|
Utica
|
|
78
|
|
|
204
|
|
|
470
|
|
Other
|
|
35
|
|
|
39
|
|
|
65
|
|
Total
|
|
399
|
|
|
589
|
|
|
895
|
|
|
|
|
|
|
|
|
|||
Total Sales Volume (MMcfe)
|
|
|
|
|
|
|
|||
Marcellus
|
|
288,203
|
|
|
239,387
|
|
|
212,504
|
|
Utica
|
|
153,704
|
|
|
83,038
|
|
|
90,820
|
|
CBM
|
|
60,268
|
|
|
65,373
|
|
|
68,971
|
|
Other
|
|
4,929
|
|
|
19,368
|
|
|
22,092
|
|
Total
|
|
507,104
|
|
|
407,166
|
|
|
394,387
|
|
|
|
For the Year
|
||||||||||
|
|
Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Average Sales Price - Gas (Mcf)
|
|
$
|
2.97
|
|
|
$
|
2.59
|
|
|
$
|
1.92
|
|
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
|
|
$
|
(0.15
|
)
|
|
$
|
(0.11
|
)
|
|
$
|
0.70
|
|
Average Sales Price - NGLs (Mcfe)*
|
|
$
|
4.55
|
|
|
$
|
4.03
|
|
|
$
|
2.42
|
|
Average Sales Price - Oil (Mcfe)*
|
|
$
|
9.89
|
|
|
$
|
7.56
|
|
|
$
|
6.15
|
|
Average Sales Price - Condensate (Mcfe)*
|
|
$
|
8.43
|
|
|
$
|
6.59
|
|
|
$
|
4.58
|
|
|
|
|
|
|
|
|
||||||
Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments
|
|
$
|
2.97
|
|
|
$
|
2.66
|
|
|
$
|
2.63
|
|
Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments
|
|
$
|
3.11
|
|
|
$
|
2.76
|
|
|
$
|
2.01
|
|
Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe)
|
|
$
|
0.19
|
|
|
$
|
0.22
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
||||||
Average Sales Price - NGLs (Bbl)
|
|
$
|
27.30
|
|
|
$
|
24.18
|
|
|
$
|
14.52
|
|
Average Sales Price - Oil (Bbl)
|
|
$
|
59.34
|
|
|
$
|
45.36
|
|
|
$
|
36.90
|
|
Average Sales Price - Condensate (Bbl)
|
|
$
|
50.58
|
|
|
$
|
39.54
|
|
|
$
|
27.48
|
|
ITEM 1A.
|
Risk Factors
|
•
|
weather conditions in our markets that affect the demand for natural gas;
|
•
|
changes in the consumption pattern of industrial consumers, electricity generators and residential users of electricity and natural gas;
|
•
|
with respect to natural gas, the price and availability of alternative fuel sources used by electricity generators;
|
•
|
technological advances affecting energy consumption and conservation measures reducing demand;
|
•
|
the costs, availability and capacity of transportation infrastructure;
|
•
|
proximity and capacity of natural gas pipelines and other transportation facilities;
|
•
|
changes in levels of international demand and tariffs associated with international export; and
|
•
|
the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and delays.
|
•
|
geological conditions;
|
•
|
our acreage position, and our ability to acquire additional acreage, including third-party swaps to develop our position efficiently;
|
•
|
changes in governmental regulations and taxation;
|
•
|
the amount and timing of actual production;
|
•
|
future prices and our hedging position;
|
•
|
future operating costs;
|
•
|
operational risks and results; and
|
•
|
capital costs of drilling, completion and gathering assets.
|
•
|
the results of delineation efforts and the acquisition, review and analysis of seismic data;
|
•
|
the availability of sufficient capital resources to us and any other participants in a well for the drilling of the well;
|
•
|
whether we are able to acquire on a timely basis all of the leasehold interests required for the well, including through swap transactions with other operators;
|
•
|
whether we are able to obtain, on a timely basis or at all, the permits required to drill the wells;
|
•
|
whether production levels align with estimates;
|
•
|
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;
|
•
|
the formation as to which we drill, as the cost structure between wet gas which requires additional processing and dry gas varies; and
|
•
|
our financial resources and results.
|
•
|
personal injury or loss of life;
|
•
|
damage to and destruction of property, natural resources and equipment, including our properties and our natural gas production or transportation facilities;
|
•
|
pollution and other environmental damage to our properties or the properties of others;
|
•
|
potential legal liability and monetary losses;
|
•
|
damage to our reputation within the industry or with customers;
|
•
|
regulatory investigations and penalties;
|
•
|
suspension of our operations; and
|
•
|
repair and remediation costs.
|
•
|
demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas business;
|
•
|
the tightening of credit or lack of credit availability to our customers could adversely affect us, as our ability to receive payment for natural gas sold and delivered depends on the continued creditworthiness of our customers;
|
•
|
our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our natural gas reserves; and
|
•
|
a decline in our creditworthiness may require us to post letters of credit, cash collateral, or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.
|
•
|
our production is less than expected;
|
•
|
we are unable to find available counterparties in the future with which to enter into hedges and counterparties able to enter into basis hedge contracts;
|
•
|
the creditworthiness of our counterparties or their guarantors is substantially impaired; and
|
•
|
counterparties have credit limits that may constrain our ability to hedge additional volumes.
|
•
|
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.
|
•
|
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 natural gas reserves or other general corporate requirements;
|
•
|
limiting our flexibility in planning for, or reacting to, changes in our business and in the natural gas industry;
|
•
|
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.
|
•
|
a cyber-incident impacting one of our vendors or service providers could result in supply chain disruptions, loss or corruption of our information or other negative consequences, any of which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
|
•
|
a cyber-incident related to our facilities may result in equipment damage or failure;
|
•
|
a cyber-incident impacting midstream or downstream pipelines could prevent our product from being delivered, resulting in a loss of revenues;
|
•
|
a cyber-incident impacting a communications network or power grid could cause operational disruption resulting in loss of revenues;
|
•
|
a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and
|
•
|
business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our units.
|
ITEM 1B.
|
Unresolved Staff Comments
|
ITEM 2.
|
Properties
|
ITEM 3.
|
Legal Proceedings
|
ITEM 4.
|
Mine Safety and Health Administration Safety Data
|
ITEM 5.
|
Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
||||||
CNX Resources Corporation
|
|
100.0
|
|
|
107.4
|
|
|
25.7
|
|
|
59.3
|
|
|
55.0
|
|
|
42.9
|
|
Peer Group
|
|
100.0
|
|
|
88.3
|
|
|
38.8
|
|
|
53.1
|
|
|
42.3
|
|
|
27.6
|
|
S&P 500 Stock Index
|
|
100.0
|
|
|
144.4
|
|
|
143.4
|
|
|
157.0
|
|
|
187.4
|
|
|
175.8
|
|
ISSUER PURCHASES OF EQUITY SECURITIES
|
||||||||||
|
(a)
|
(b)
|
(c)
|
(d)
|
||||||
Period
|
Total Number of Shares Purchased (1)
|
Average Price Paid per Share
|
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)
|
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (000's omitted)
|
||||||
October 1, 2018-
October 31, 2018 |
3,552,158
|
|
$
|
14.06
|
|
3,552,158
|
|
$
|
300,643
|
|
November 1, 2018-
November 30, 2018 |
712,300
|
|
$
|
14.10
|
|
712,300
|
|
$
|
290,597
|
|
December 1, 2018-
December 31, 2018 |
2,230,834
|
|
$
|
12.06
|
|
2,230,834
|
|
$
|
263,684
|
|
Total
|
6,495,292
|
|
|
6,495,292
|
|
$
|
854,924,000
|
|
ITEM 6.
|
Selected Financial Data
|
(Dollars in thousands, except per share data)
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Revenue and Other Operating Income from Continuing Operations
|
|
$
|
1,730,434
|
|
|
$
|
1,455,131
|
|
|
$
|
759,968
|
|
|
$
|
1,198,737
|
|
|
$
|
1,080,351
|
|
Income (Loss) from Continuing Operations
|
|
$
|
883,111
|
|
|
$
|
295,039
|
|
|
$
|
(550,945
|
)
|
|
$
|
(650,198
|
)
|
|
$
|
(269,625
|
)
|
Net Income (Loss) Attributable to CNX Resources Shareholders
|
|
$
|
796,533
|
|
|
$
|
380,747
|
|
|
$
|
(848,102
|
)
|
|
$
|
(374,885
|
)
|
|
$
|
163,090
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (Loss) from Continuing Operations
|
|
$
|
3.75
|
|
|
$
|
1.29
|
|
|
$
|
(2.40
|
)
|
|
$
|
(2.84
|
)
|
|
$
|
(1.17
|
)
|
Income (Loss) from Discontinued Operations
|
|
—
|
|
|
0.37
|
|
|
(1.30
|
)
|
|
1.20
|
|
|
1.88
|
|
|||||
Net Income (Loss)
|
|
$
|
3.75
|
|
|
$
|
1.66
|
|
|
$
|
(3.70
|
)
|
|
$
|
(1.64
|
)
|
|
$
|
0.71
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (Loss) from Continuing Operations
|
|
$
|
3.71
|
|
|
$
|
1.28
|
|
|
$
|
(2.40
|
)
|
|
$
|
(2.84
|
)
|
|
$
|
(1.17
|
)
|
Income (Loss) from Discontinued Operations
|
|
—
|
|
|
0.37
|
|
|
(1.30
|
)
|
|
1.20
|
|
|
1.87
|
|
|||||
Net Income (Loss)
|
|
$
|
3.71
|
|
|
$
|
1.65
|
|
|
$
|
(3.70
|
)
|
|
$
|
(1.64
|
)
|
|
$
|
0.70
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Assets from Continuing Operations
|
|
$
|
8,592,170
|
|
|
$
|
6,931,913
|
|
|
$
|
6,682,770
|
|
|
$
|
7,302,119
|
|
|
$
|
7,968,069
|
|
Assets from Discontinued Operations
|
|
—
|
|
|
—
|
|
|
2,496,921
|
|
|
3,627,783
|
|
|
3,686,576
|
|
|||||
Total Assets
|
|
$
|
8,592,170
|
|
|
$
|
6,931,913
|
|
|
$
|
9,179,691
|
|
|
$
|
10,929,902
|
|
|
$
|
11,654,645
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-Term Debt from Continuing Operations (including current portion)
|
|
$
|
2,398,501
|
|
|
$
|
2,214,484
|
|
|
$
|
2,456,354
|
|
|
$
|
2,460,633
|
|
|
$
|
3,129,433
|
|
Long-Term Debt from Discontinued Operations (including current portion)
|
|
—
|
|
|
—
|
|
|
317,715
|
|
|
294,222
|
|
|
120,128
|
|
|||||
Total Long-Term Debt (including current portion)
|
|
$
|
2,398,501
|
|
|
$
|
2,214,484
|
|
|
$
|
2,774,069
|
|
|
$
|
2,754,855
|
|
|
$
|
3,249,561
|
|
Cash Dividends Declared Per Share of Common Stock
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.010
|
|
|
$
|
0.145
|
|
|
$
|
0.250
|
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Gas:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net sales volumes produced (in Bcfe)
|
|
507.1
|
|
|
407.2
|
|
|
394.4
|
|
|
328.7
|
|
|
235.7
|
|
|||||
Average sales price ($ per Mcfe) (A)
|
|
$
|
2.97
|
|
|
$
|
2.66
|
|
|
$
|
2.63
|
|
|
$
|
2.81
|
|
|
$
|
4.37
|
|
Average cost ($ per Mcfe)
|
|
$
|
1.98
|
|
|
$
|
2.23
|
|
|
$
|
2.32
|
|
|
$
|
2.62
|
|
|
$
|
3.13
|
|
Proved reserves (in Bcfe) (B)
|
|
7,881
|
|
|
7,582
|
|
|
6,252
|
|
|
5,643
|
|
|
6,828
|
|
(A)
|
Represents average net sales price including the effect of derivative transactions.
|
(B)
|
Represents proved developed and undeveloped gas reserves at period end.
|
ITEM 7.
|
Management's Discussion and Analysis of Financial Condition and Results of Operations
|
•
|
Record total gas production of 507.1 Bcfe in 2018, 24.5% higher than 2017
|
◦
|
Included in CNX's 2018 production is approximately 27 Bcfe of production related to assets that were sold in 2018.
|
•
|
Record Marcellus Shale production of 288.2 Bcfe in 2018, 20.4% higher than 2017.
|
•
|
Increased proved reserves to 7.9 Tcfe, 4% higher than 2017.
|
◦
|
Increase even after a reduction of approximately 825 Bcfe of reserves related to assets that were sold in 2018.
|
•
|
On January 3, 2018, the Company acquired the remaining 50% membership interest in CONE 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.
|
•
|
CNX sold substantially all of its shallow oil and gas assets and certain Coalbed Methane (CBM) assets in Pennsylvania and West Virginia during the second quarter of 2018.
|
•
|
During the third quarter of 2018, CNX closed on the sale of substantially all of its Ohio Utica Joint Venture Assets in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble Counties, which included approximately 26,000 net undeveloped acres.
|
•
|
Gas production costs continue to decline - for the year ended December 31, 2018, total gas production costs were $1.98 per Mcfe, which includes $0.90 per Mcfe of depreciation, depletion and amortization, a 11.2% decline from the prior year.
|
•
|
Repurchased $384 million of common stock on the open market.
|
•
|
Repurchased $411 million of 5.875% notes due in 2022.
|
•
|
Called the remaining $500 million balance of 8% senior notes due April 2023.
|
•
|
Our 2019 annual gas production is expected to be at a minimum base of approximately 495-515 Bcfe.
|
•
|
Our 2019 E&P capital investment is expected to be approximately $1,000-$1,080 million.
|
|
For the Years Ended December 31,
|
||||||||||
(Dollars in thousands)
|
2018
|
|
2017
|
|
Variance
|
||||||
Income from Continuing Operations
|
$
|
883,111
|
|
|
$
|
295,039
|
|
|
$
|
588,072
|
|
Income from Discontinued Operations, Net
|
—
|
|
|
85,708
|
|
|
(85,708
|
)
|
|||
Net Income
|
$
|
883,111
|
|
|
$
|
380,747
|
|
|
$
|
502,364
|
|
Less: Net Income Attributable to Noncontrolling Interest
|
86,578
|
|
|
—
|
|
|
86,578
|
|
|||
Net Income Attributable to CNX Resources Shareholders
|
$
|
796,533
|
|
|
$
|
380,747
|
|
|
$
|
415,786
|
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
Sales Volume (Bcfe)
|
507.1
|
|
|
407.2
|
|
|
99.9
|
|
|
24.5
|
%
|
|||
|
|
|
|
|
|
|
|
|||||||
Average Sales Price (per Mcfe)
|
$
|
2.97
|
|
|
$
|
2.66
|
|
|
$
|
0.31
|
|
|
11.7
|
%
|
Lease Operating Expense (per Mcfe)
|
0.19
|
|
|
0.22
|
|
|
(0.03
|
)
|
|
(13.6
|
)%
|
|||
Production, Ad Valorem, and Other Fees (per Mcfe)
|
0.06
|
|
|
0.07
|
|
|
(0.01
|
)
|
|
(14.3
|
)%
|
|||
Transportation, Gathering and Compression (per Mcfe)
|
0.84
|
|
|
0.94
|
|
|
(0.10
|
)
|
|
(10.6
|
)%
|
|||
Depreciation, Depletion and Amortization (DD&A) (per Mcfe)
|
0.89
|
|
|
1.00
|
|
|
(0.11
|
)
|
|
(11.0
|
)%
|
|||
Average Costs (per Mcfe)
|
$
|
1.98
|
|
|
$
|
2.23
|
|
|
$
|
(0.25
|
)
|
|
(11.2
|
)%
|
Average Margin (per Mcfe)
|
$
|
0.99
|
|
|
$
|
0.43
|
|
|
$
|
0.56
|
|
|
130.2
|
%
|
•
|
Lease operating expense decreased on a per unit basis due to the overall increase in sales volumes, primarily Utica, in the 2018. There were also significant decreases in routine well operating costs, repairs and maintenance expenses and employee costs, partially due to the sale of substantially all our shallow oil and gas properties in the first quarter. See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. In 2018, the company also deployed more in-house resources that maintained overall lease operating costs and increased operational efficiencies while significantly increasing production. The decreases were partially offset by increased water disposal costs, primarily in the first quarter of 2018, resulting from increased production volumes and gaps in the completions schedule for new wells.
|
•
|
Transportation, gathering, and compression expense decreased on a per-unit basis primarily due to the 24.5% increase in sales volumes, and the shift towards dry Utica Shale production which has lower gathering costs and no processing costs. In the third quarter of 2018, CNX closed on the sale of substantially all of its Ohio Utica Joint Venture Assets in the wet gas Utica Shale areas (see Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).
|
•
|
Depreciation, depletion, and amortization decreased on a per-unit basis primarily due to a reduction in Marcellus Shale and Utica Shale rates as a result of an increase in the Company's associated reserves and an overall change in production mix.
|
|
|
For the Years Ended December 31,
|
|||||||||||||
in thousands (unless noted)
|
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change |
|||||||
LIQUIDS
|
|
|
|
|
|
|
|
|
|||||||
NGLs:
|
|
|
|
|
|
|
|
|
|||||||
Sales Volume (MMcfe)
|
|
36,489
|
|
|
38,736
|
|
|
(2,247
|
)
|
|
(5.8
|
)%
|
|||
Sales Volume (Mbbls)
|
|
6,081
|
|
|
6,456
|
|
|
(375
|
)
|
|
(5.8
|
)%
|
|||
Gross Price ($/Bbl)
|
|
$
|
27.30
|
|
|
$
|
24.18
|
|
|
$
|
3.12
|
|
|
12.9
|
%
|
Gross Revenue
|
|
$
|
165,883
|
|
|
$
|
156,132
|
|
|
$
|
9,751
|
|
|
6.2
|
%
|
|
|
|
|
|
|
|
|
|
|||||||
Oil:
|
|
|
|
|
|
|
|
|
|||||||
Sales Volume (MMcfe)
|
|
307
|
|
|
421
|
|
|
(114
|
)
|
|
(27.1
|
)%
|
|||
Sales Volume (Mbbls)
|
|
51
|
|
|
70
|
|
|
(19
|
)
|
|
(27.1
|
)%
|
|||
Gross Price ($/Bbl)
|
|
$
|
59.34
|
|
|
$
|
45.36
|
|
|
$
|
13.98
|
|
|
30.8
|
%
|
Gross Revenue
|
|
$
|
3,036
|
|
|
$
|
3,179
|
|
|
$
|
(143
|
)
|
|
(4.5
|
)%
|
|
|
|
|
|
|
|
|
|
|||||||
Condensate:
|
|
|
|
|
|
|
|
|
|||||||
Sales Volume (MMcfe)
|
|
2,082
|
|
|
3,116
|
|
|
(1,034
|
)
|
|
(33.2
|
)%
|
|||
Sales Volume (Mbbls)
|
|
347
|
|
|
519
|
|
|
(172
|
)
|
|
(33.1
|
)%
|
|||
Gross Price ($/Bbl)
|
|
$
|
50.58
|
|
|
$
|
39.54
|
|
|
$
|
11.04
|
|
|
27.9
|
%
|
Gross Revenue
|
|
$
|
17,559
|
|
|
$
|
20,531
|
|
|
$
|
(2,972
|
)
|
|
(14.5
|
)%
|
|
|
|
|
|
|
|
|
|
|||||||
GAS
|
|
|
|
|
|
|
|
|
|||||||
Sales Volume (MMcf)
|
|
468,226
|
|
|
364,893
|
|
|
103,333
|
|
|
28.3
|
%
|
|||
Sales Price ($/Mcf)
|
|
$
|
2.97
|
|
|
$
|
2.59
|
|
|
$
|
0.38
|
|
|
14.7
|
%
|
Gross Revenue
|
|
$
|
1,391,459
|
|
|
$
|
945,382
|
|
|
$
|
446,077
|
|
|
47.2
|
%
|
|
|
|
|
|
|
|
|
|
|||||||
Hedging Impact ($/Mcf)
|
|
$
|
(0.15
|
)
|
|
$
|
(0.11
|
)
|
|
$
|
(0.04
|
)
|
|
(36.4
|
)%
|
Loss on Commodity Derivative Instruments - Cash Settlement
|
|
$
|
(69,720
|
)
|
|
$
|
(41,174
|
)
|
|
$
|
(28,546
|
)
|
|
(69.3
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
(in millions)
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
Other Income
|
|
|
|
|
|
|
|
|||||||
Right of Way Sales
|
$
|
14
|
|
|
$
|
2
|
|
|
$
|
12
|
|
|
600.0
|
%
|
Royalty Income
|
15
|
|
|
10
|
|
|
5
|
|
|
50.0
|
%
|
|||
Interest Income
|
—
|
|
|
9
|
|
|
(9
|
)
|
|
(100.0
|
)%
|
|||
Other
|
8
|
|
|
6
|
|
|
2
|
|
|
33.3
|
%
|
|||
Total Other Income
|
$
|
37
|
|
|
$
|
27
|
|
|
$
|
10
|
|
|
37.0
|
%
|
|
|
|
|
|
|
|
|
|||||||
Other Expense
|
|
|
|
|
|
|
|
|||||||
Bank Fees
|
$
|
11
|
|
|
$
|
13
|
|
|
$
|
(2
|
)
|
|
(15.4
|
)%
|
Professional Services
|
7
|
|
|
6
|
|
|
1
|
|
|
16.7
|
%
|
|||
Other Land Rental Expense
|
4
|
|
|
6
|
|
|
(2
|
)
|
|
(33.3
|
)%
|
|||
Other Corporate Expense
|
—
|
|
|
6
|
|
|
(6
|
)
|
|
(100.0
|
)%
|
|||
Total Other Expense
|
$
|
22
|
|
|
$
|
31
|
|
|
$
|
(9
|
)
|
|
(29.0
|
)%
|
|
|
|
|
|
|
|
|
|
||||||
Total Other (Income) Expense
|
$
|
(15
|
)
|
|
$
|
4
|
|
|
$
|
(19
|
)
|
|
(475.0
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
Total Company Earnings Before Income Tax
|
$
|
1,099
|
|
|
$
|
119
|
|
|
$
|
980
|
|
|
823.5
|
%
|
Income Tax Expense (Benefit)
|
$
|
216
|
|
|
$
|
(176
|
)
|
|
$
|
392
|
|
|
(222.7
|
)%
|
Effective Income Tax Rate
|
19.6
|
%
|
|
(148.9
|
)%
|
|
168.5
|
%
|
|
|
|
For the Year Ended
|
|
Difference to Year Ended
|
||||||||||||||||||||||||||||||||||||
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||||||||||||||||||
(in millions)
|
Marcellus
|
|
Utica
|
|
CBM
|
|
Other
Gas
|
|
Total
|
|
Marcellus
|
|
Utica
|
|
CBM
|
|
Other
Gas
|
|
Total
|
||||||||||||||||||||
Natural Gas, NGLs and Oil Revenue
|
$
|
903
|
|
|
$
|
446
|
|
|
$
|
213
|
|
|
$
|
16
|
|
|
$
|
1,578
|
|
|
$
|
257
|
|
|
$
|
229
|
|
|
$
|
4
|
|
|
$
|
(37
|
)
|
|
$
|
453
|
|
(Loss) Gain on Commodity Derivative Instruments
|
(40
|
)
|
|
(20
|
)
|
|
(9
|
)
|
|
39
|
|
|
(30
|
)
|
|
(10
|
)
|
|
(21
|
)
|
|
1
|
|
|
(207
|
)
|
|
(237
|
)
|
||||||||||
Purchased Gas Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
66
|
|
|
66
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
12
|
|
||||||||||
Other Operating Income
|
—
|
|
|
—
|
|
|
—
|
|
|
27
|
|
|
27
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(42
|
)
|
|
(42
|
)
|
||||||||||
Total Revenue and Other Operating Income
|
863
|
|
|
426
|
|
|
204
|
|
|
148
|
|
|
1,641
|
|
|
247
|
|
|
208
|
|
|
5
|
|
|
(274
|
)
|
|
186
|
|
||||||||||
Lease Operating Expense
|
41
|
|
|
30
|
|
|
22
|
|
|
2
|
|
|
95
|
|
|
9
|
|
|
11
|
|
|
(3
|
)
|
|
(11
|
)
|
|
6
|
|
||||||||||
Production, Ad Valorem, and Other Fees
|
18
|
|
|
7
|
|
|
7
|
|
|
1
|
|
|
33
|
|
|
3
|
|
|
2
|
|
|
—
|
|
|
(1
|
)
|
|
4
|
|
||||||||||
Transportation, Gathering and Compression
|
320
|
|
|
52
|
|
|
48
|
|
|
4
|
|
|
424
|
|
|
64
|
|
|
7
|
|
|
(16
|
)
|
|
(14
|
)
|
|
41
|
|
||||||||||
Depreciation, Depletion and Amortization
|
230
|
|
|
143
|
|
|
77
|
|
|
11
|
|
|
461
|
|
|
8
|
|
|
59
|
|
|
(6
|
)
|
|
(12
|
)
|
|
49
|
|
||||||||||
Impairment of Exploration and Production Properties
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(138
|
)
|
|
(138
|
)
|
||||||||||
Exploration and Production Related Other Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(36
|
)
|
|
(36
|
)
|
||||||||||
Purchased Gas Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
65
|
|
|
65
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
12
|
|
||||||||||
Other Operating Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
72
|
|
|
72
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(40
|
)
|
|
(40
|
)
|
||||||||||
Selling, General, and Administrative Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
112
|
|
|
112
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
19
|
|
||||||||||
Total Operating Costs and Expenses
|
609
|
|
|
232
|
|
|
154
|
|
|
279
|
|
|
1,274
|
|
|
84
|
|
|
79
|
|
|
(25
|
)
|
|
(221
|
)
|
|
(83
|
)
|
||||||||||
Interest Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
122
|
|
|
122
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39
|
)
|
|
(39
|
)
|
||||||||||
Total E&P Division Costs
|
609
|
|
|
232
|
|
|
154
|
|
|
401
|
|
|
1,396
|
|
|
84
|
|
|
79
|
|
|
(25
|
)
|
|
(260
|
)
|
|
(122
|
)
|
||||||||||
Earnings (Loss) from Continuing Operations Before Income Tax
|
$
|
254
|
|
|
$
|
194
|
|
|
$
|
50
|
|
|
$
|
(253
|
)
|
|
$
|
245
|
|
|
$
|
163
|
|
|
$
|
129
|
|
|
$
|
30
|
|
|
$
|
(14
|
)
|
|
$
|
308
|
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
Marcellus Gas Sales Volumes (Bcf)
|
255.1
|
|
|
209.7
|
|
|
45.4
|
|
|
21.6
|
%
|
|||
NGLs Sales Volumes (Bcfe)*
|
31.4
|
|
|
27.6
|
|
|
3.8
|
|
|
13.8
|
%
|
|||
Condensate Sales Volumes (Bcfe)*
|
1.7
|
|
|
2.1
|
|
|
(0.4
|
)
|
|
(19.0
|
)%
|
|||
Total Marcellus Sales Volumes (Bcfe)*
|
288.2
|
|
|
239.4
|
|
|
48.8
|
|
|
20.4
|
%
|
|||
|
|
|
|
|
|
|
|
|||||||
Average Sales Price - Gas (per Mcf)
|
$
|
2.93
|
|
|
$
|
2.50
|
|
|
$
|
0.43
|
|
|
17.2
|
%
|
Loss on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)
|
$
|
(0.16
|
)
|
|
$
|
(0.14
|
)
|
|
$
|
(0.02
|
)
|
|
(14.3
|
)%
|
Average Sales Price - NGLs (per Mcfe)*
|
$
|
4.55
|
|
|
$
|
3.96
|
|
|
$
|
0.59
|
|
|
14.9
|
%
|
Average Sales Price - Condensate (per Mcfe)*
|
$
|
8.32
|
|
|
$
|
6.44
|
|
|
$
|
1.88
|
|
|
29.2
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Average Marcellus Sales Price (per Mcfe)
|
$
|
2.99
|
|
|
$
|
2.57
|
|
|
$
|
0.42
|
|
|
16.3
|
%
|
Average Marcellus Lease Operating Expenses (per Mcfe)
|
0.14
|
|
|
0.13
|
|
|
0.01
|
|
|
7.7
|
%
|
|||
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)
|
0.07
|
|
|
0.07
|
|
|
—
|
|
|
—
|
%
|
|||
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe)
|
1.11
|
|
|
1.07
|
|
|
0.04
|
|
|
3.7
|
%
|
|||
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)
|
0.79
|
|
|
0.92
|
|
|
(0.13
|
)
|
|
(14.1
|
)%
|
|||
Total Average Marcellus Costs (per Mcfe)
|
$
|
2.11
|
|
|
$
|
2.19
|
|
|
$
|
(0.08
|
)
|
|
(3.7
|
)%
|
Average Margin for Marcellus (per Mcfe)
|
$
|
0.88
|
|
|
$
|
0.38
|
|
|
$
|
0.50
|
|
|
131.6
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
Utica Gas Sales Volumes (Bcf)
|
148.1
|
|
|
70.7
|
|
|
77.4
|
|
|
109.5
|
%
|
|||
NGLs Sales Volumes (Bcfe)*
|
5.1
|
|
|
11.1
|
|
|
(6.0
|
)
|
|
(54.1
|
)%
|
|||
Oil Sales Volumes (Bcfe)*
|
0.1
|
|
|
0.2
|
|
|
(0.1
|
)
|
|
(50.0
|
)%
|
|||
Condensate Sales Volumes (Bcfe)*
|
0.4
|
|
|
1.0
|
|
|
(0.6
|
)
|
|
(60.0
|
)%
|
|||
Total Utica Sales Volumes (Bcfe)*
|
153.7
|
|
|
83.0
|
|
|
70.7
|
|
|
85.2
|
%
|
|||
|
|
|
|
|
|
|
|
|||||||
Average Sales Price - Gas (per Mcf)
|
$
|
2.82
|
|
|
$
|
2.29
|
|
|
$
|
0.53
|
|
|
23.1
|
%
|
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)
|
$
|
(0.13
|
)
|
|
$
|
0.02
|
|
|
$
|
(0.15
|
)
|
|
(750.0
|
)%
|
Average Sales Price - NGLs (per Mcfe)*
|
$
|
4.54
|
|
|
$
|
4.20
|
|
|
$
|
0.34
|
|
|
8.1
|
%
|
Average Sales Price - Oil (per Mcfe)*
|
$
|
9.46
|
|
|
$
|
7.31
|
|
|
$
|
2.15
|
|
|
29.4
|
%
|
Average Sales Price - Condensate (per Mcfe)*
|
$
|
8.96
|
|
|
$
|
6.88
|
|
|
$
|
2.08
|
|
|
30.2
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Average Utica Sales Price (per Mcfe)
|
$
|
2.77
|
|
|
$
|
2.63
|
|
|
$
|
0.14
|
|
|
5.3
|
%
|
Average Utica Lease Operating Expenses (per Mcfe)
|
0.19
|
|
|
0.23
|
|
|
(0.04
|
)
|
|
(17.4
|
)%
|
|||
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)
|
0.05
|
|
|
0.06
|
|
|
(0.01
|
)
|
|
(16.7
|
)%
|
|||
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)
|
0.34
|
|
|
0.54
|
|
|
(0.20
|
)
|
|
(37.0
|
)%
|
|||
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)
|
0.93
|
|
|
1.02
|
|
|
(0.09
|
)
|
|
(8.8
|
)%
|
|||
Total Average Utica Costs (per Mcfe)
|
$
|
1.51
|
|
|
$
|
1.85
|
|
|
$
|
(0.34
|
)
|
|
(18.4
|
)%
|
Average Margin for Utica (per Mcfe)
|
$
|
1.26
|
|
|
$
|
0.78
|
|
|
$
|
0.48
|
|
|
61.5
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
CBM Gas Sales Volumes (Bcf)
|
60.3
|
|
|
65.4
|
|
|
(5.1
|
)
|
|
(7.8
|
)%
|
|||
|
|
|
|
|
|
|
|
|||||||
Average Sales Price - Gas (per Mcf)
|
$
|
3.53
|
|
|
$
|
3.19
|
|
|
$
|
0.34
|
|
|
10.7
|
%
|
Loss on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)
|
$
|
(0.15
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
—
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Average CBM Sales Price (per Mcf)
|
$
|
3.39
|
|
|
$
|
3.05
|
|
|
$
|
0.34
|
|
|
11.1
|
%
|
Average CBM Lease Operating Expenses (per Mcf)
|
0.37
|
|
|
0.39
|
|
|
(0.02
|
)
|
|
(5.1
|
)%
|
|||
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)
|
0.12
|
|
|
0.11
|
|
|
0.01
|
|
|
9.1
|
%
|
|||
Average CBM Transportation, Gathering and Compression Costs (per Mcf)
|
0.80
|
|
|
0.98
|
|
|
(0.18
|
)
|
|
(18.4
|
)%
|
|||
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)
|
1.28
|
|
|
1.26
|
|
|
0.02
|
|
|
1.6
|
%
|
|||
Total Average CBM Costs (per Mcf)
|
$
|
2.57
|
|
|
$
|
2.74
|
|
|
$
|
(0.17
|
)
|
|
(6.2
|
)%
|
Average Margin for CBM (per Mcf)
|
$
|
0.82
|
|
|
$
|
0.31
|
|
|
$
|
0.51
|
|
|
164.5
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change |
|||||||
Other Gas Sales Volumes (Bcf)
|
4.7
|
|
|
19.2
|
|
|
(14.5
|
)
|
|
(75.5
|
)%
|
|||
Oil Sales Volumes (Bcfe)*
|
0.2
|
|
|
0.2
|
|
|
—
|
|
|
—
|
%
|
|||
Total Other Sales Volumes (Bcfe)*
|
4.9
|
|
|
19.4
|
|
|
(14.5
|
)
|
|
(74.7
|
)%
|
|||
|
|
|
|
|
|
|
|
|||||||
Average Sales Price - Gas (per Mcf)
|
$
|
2.91
|
|
|
$
|
2.69
|
|
|
$
|
0.22
|
|
|
8.2
|
%
|
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)
|
$
|
(0.13
|
)
|
|
$
|
(0.14
|
)
|
|
$
|
0.01
|
|
|
7.1
|
%
|
Average Sales Price - Oil (per Mcfe)*
|
$
|
10.09
|
|
|
$
|
7.75
|
|
|
$
|
2.34
|
|
|
30.2
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Average Other Sales Price (per Mcfe)
|
$
|
3.09
|
|
|
$
|
2.62
|
|
|
$
|
0.47
|
|
|
17.9
|
%
|
Average Other Lease Operating Expenses (per Mcfe)
|
0.42
|
|
|
0.63
|
|
|
(0.21
|
)
|
|
(33.3
|
)%
|
|||
Average Other Production, Ad Valorem, and Other Fees (per Mcfe)
|
0.04
|
|
|
0.12
|
|
|
(0.08
|
)
|
|
(66.7
|
)%
|
|||
Average Other Transportation, Gathering and Compression Costs (per Mcfe)
|
0.87
|
|
|
0.90
|
|
|
(0.03
|
)
|
|
(3.3
|
)%
|
|||
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe)
|
1.49
|
|
|
1.05
|
|
|
0.44
|
|
|
41.9
|
%
|
|||
Total Average Other Costs (per Mcfe)
|
$
|
2.82
|
|
|
$
|
2.70
|
|
|
$
|
0.12
|
|
|
4.4
|
%
|
Average Margin for Other (per Mcfe)
|
$
|
0.27
|
|
|
$
|
(0.08
|
)
|
|
$
|
0.35
|
|
|
437.5
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Sales Volumes (in billion cubic feet)
|
20.5
|
|
|
22.0
|
|
|
(1.5
|
)
|
|
(6.8
|
)%
|
|||
Average Sales Price (per Mcf)
|
$
|
3.23
|
|
|
$
|
2.44
|
|
|
$
|
0.79
|
|
|
32.4
|
%
|
Average Cost (per Mcf)
|
$
|
3.17
|
|
|
$
|
2.39
|
|
|
$
|
0.78
|
|
|
32.6
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
(in millions)
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
Equity in Earnings of Affiliates
|
$
|
5
|
|
|
$
|
50
|
|
|
$
|
(45
|
)
|
|
(90.0
|
)%
|
Gathering Income
|
10
|
|
|
11
|
|
|
(1
|
)
|
|
(9.1
|
)%
|
|||
Water Income
|
11
|
|
|
5
|
|
|
6
|
|
|
120.0
|
%
|
|||
Other
|
1
|
|
|
3
|
|
|
(2
|
)
|
|
(66.7
|
)%
|
|||
Total Other Operating Income
|
$
|
27
|
|
|
$
|
69
|
|
|
$
|
(42
|
)
|
|
(60.9
|
)%
|
•
|
Equity in Earnings of Affiliates decreased $45 million primarily due to the consolidation of CNX Gathering and CNXM in the current year. See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
|
•
|
Water Income increased $6 million due to increased sales of freshwater to third-parties for hydraulic fracturing.
|
|
For the Years Ended December 31,
|
|||||||||||||
(in millions)
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
Lease Expiration Costs
|
$
|
5
|
|
|
$
|
40
|
|
|
$
|
(35
|
)
|
|
(87.5
|
)%
|
Land Rentals
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
%
|
|||
Other
|
3
|
|
|
4
|
|
|
(1
|
)
|
|
(25.0
|
)%
|
|||
Total Exploration and Production Related Other Costs
|
$
|
12
|
|
|
$
|
48
|
|
|
$
|
(36
|
)
|
|
(75.0
|
)%
|
•
|
Lease Expiration Costs relate to leases where the primary term expired or will expire within the next 12 months. The $35 million decrease in the year ended December 31, 2018, was primarily due to leases in both Monroe and Noble County, Ohio that were no longer in the Company's future drilling plans, so they were not renewed in the 2017 period.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2018
|
|
2017
|
|
Variance
|
|
Percent
Change
|
|||||||
Idle Rig Expense
|
$
|
5
|
|
|
$
|
41
|
|
|
$
|
(36
|
)
|
|
(87.8
|
)%
|
Unutilized Firm Transportation and Processing Fees
|
42
|
|
|
50
|
|
|
(8
|
)
|
|
(16.0
|
)%
|
|||
Severance Expense
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
%
|
|||
Insurance Expense
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
%
|
|||
Litigation Settlements
|
4
|
|
|
3
|
|
|
1
|
|
|
33.3
|
%
|
|||
Other
|
17
|
|
|
14
|
|
|
3
|
|
|
21.4
|
%
|
|||
Total Other Operating Expense
|
$
|
72
|
|
|
$
|
112
|
|
|
$
|
(40
|
)
|
|
(35.7
|
)%
|
•
|
Idle Rig Expense relates to the temporary idling of some of the Company's natural gas rigs. The total idle rig expense incurred by the Company decreased $36 million in the period-to-period comparison due to contracts that expired in the current period. Additionally, the total idle rig expense decreased 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 in the year ended December 31, 2017.
|
•
|
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 decrease in the period-to-period comparison was primarily due to the increase 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.
|
(in millions)
|
For the period January 3, 2018 through December 31, 2018
|
||
Midstream Revenue - Related Party
|
$
|
168
|
|
Midstream Revenue - Third Party
|
90
|
|
|
Total Revenue
|
$
|
258
|
|
|
|
||
Transportation, Gathering and Compression
|
$
|
47
|
|
Depreciation, Depletion and Amortization
|
32
|
|
|
Selling, General, and Administrative Costs
|
23
|
|
|
Total Operating Costs and Expenses
|
102
|
|
|
Gain on Asset Sales
|
(2
|
)
|
|
Interest Expense
|
24
|
|
|
Total Midstream Division Costs
|
124
|
|
|
Earnings from Continuing Operations Before Income Tax
|
$
|
134
|
|
|
TOTAL
|
|
Dry Gas (BBtu/d) (*)
|
740
|
|
Wet Gas (BBtu/d) (*)
|
661
|
|
Other (BBtu/d) (*)(**)
|
73
|
|
Total Gathered Volumes
|
1,474
|
|
|
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 Operations, net
|
85,708
|
|
|
(297,157
|
)
|
|
382,865
|
|
|||
Net Income (Loss)
|
$
|
380,747
|
|
|
$
|
(848,102
|
)
|
|
$
|
1,228,849
|
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2017
|
|
2016
|
|
Variance
|
|
Percent
Change
|
|||||||
Sales Volume (Bcfe)
|
407.2
|
|
|
394.4
|
|
|
12.8
|
|
|
3.2
|
%
|
|||
|
|
|
|
|
|
|
|
|||||||
Average Sales Price (per Mcfe)
|
$
|
2.66
|
|
|
$
|
2.63
|
|
|
$
|
0.03
|
|
|
1.1
|
%
|
Lease Operating Expense
|
0.22
|
|
|
0.24
|
|
|
(0.02
|
)
|
|
(8.3
|
)%
|
|||
Production, Ad Valorem, and Other Fees
|
0.07
|
|
|
0.08
|
|
|
(0.01
|
)
|
|
(12.5
|
)%
|
|||
Transportation, Gathering and Compression
|
0.94
|
|
|
0.95
|
|
|
(0.01
|
)
|
|
(1.1
|
)%
|
|||
Depreciation, Depletion and Amortization (DD&A)
|
1.00
|
|
|
1.05
|
|
|
(0.05
|
)
|
|
(4.8
|
)%
|
|||
Average Costs (per Mcfe)
|
$
|
2.23
|
|
|
$
|
2.32
|
|
|
$
|
(0.09
|
)
|
|
(3.9
|
)%
|
Average Margin
|
$
|
0.43
|
|
|
$
|
0.31
|
|
|
$
|
0.12
|
|
|
38.7
|
%
|
•
|
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 10 - 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 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.
|
|
|
For the Years Ended December 31,
|
|||||||||||||
in thousands (unless noted)
|
|
2017
|
|
2016
|
|
Variance
|
|
Percent
Change |
|||||||
LIQUIDS
|
|
|
|
|
|
|
|
|
|
|
|||||
NGLs:
|
|
|
|
|
|
|
|
|
|
|
|||||
Sales Volume (MMcfe)
|
|
38,736
|
|
|
40,260
|
|
|
(1,524
|
)
|
|
(3.8
|
)%
|
|||
Sales Volume (Mbbls)
|
|
6,456
|
|
|
6,710
|
|
|
(254
|
)
|
|
(3.8
|
)%
|
|||
Gross Price ($/Bbl)
|
|
$
|
24.18
|
|
|
$
|
14.52
|
|
|
$
|
9.66
|
|
|
66.5
|
%
|
Gross Revenue
|
|
$
|
156,132
|
|
|
$
|
97,580
|
|
|
$
|
58,552
|
|
|
60.0
|
%
|
|
|
|
|
|
|
|
|
|
|||||||
Oil:
|
|
|
|
|
|
|
|
|
|||||||
Sales Volume (MMcfe)
|
|
421
|
|
|
410
|
|
|
11
|
|
|
2.7
|
%
|
|||
Sales Volume (Mbbls)
|
|
70
|
|
|
68
|
|
|
2
|
|
|
2.9
|
%
|
|||
Gross Price ($/Bbl)
|
|
$
|
45.36
|
|
|
$
|
36.90
|
|
|
$
|
8.46
|
|
|
22.9
|
%
|
Gross Revenue
|
|
$
|
3,179
|
|
|
$
|
2,521
|
|
|
$
|
658
|
|
|
26.1
|
%
|
|
|
|
|
|
|
|
|
|
|||||||
Condensate:
|
|
|
|
|
|
|
|
|
|||||||
Sales Volume (MMcfe)
|
|
3,116
|
|
|
4,964
|
|
|
(1,848
|
)
|
|
(37.2
|
)%
|
|||
Sales Volume (Mbbls)
|
|
519
|
|
|
828
|
|
|
(309
|
)
|
|
(37.3
|
)%
|
|||
Gross Price ($/Bbl)
|
|
$
|
39.54
|
|
|
$
|
27.48
|
|
|
$
|
12.06
|
|
|
43.9
|
%
|
Gross Revenue
|
|
$
|
20,531
|
|
|
$
|
22,748
|
|
|
$
|
(2,217
|
)
|
|
(9.7
|
)%
|
|
|
|
|
|
|
|
|
|
|||||||
GAS
|
|
|
|
|
|
|
|
|
|||||||
Sales Volume (MMcf)
|
|
364,893
|
|
|
348,753
|
|
|
16,140
|
|
|
4.6
|
%
|
|||
Sales Price ($/Mcf)
|
|
$
|
2.59
|
|
|
$
|
1.92
|
|
|
$
|
0.67
|
|
|
34.9
|
%
|
Gross Revenue
|
|
$
|
945,382
|
|
|
$
|
670,823
|
|
|
$
|
274,559
|
|
|
40.9
|
%
|
|
|
|
|
|
|
|
|
|
|||||||
Hedging Impact ($/Mcf)
|
|
$
|
(0.11
|
)
|
|
$
|
0.70
|
|
|
$
|
(0.81
|
)
|
|
(115.7
|
)%
|
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement
|
|
$
|
(41,174
|
)
|
|
$
|
245,212
|
|
|
$
|
(286,386
|
)
|
|
(116.8
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
(in millions)
|
2017
|
|
2016
|
|
Variance
|
|
Percent
Change
|
|||||||
Other Income
|
|
|
|
|
|
|
|
|||||||
Right of Way Sales
|
$
|
2
|
|
|
$
|
15
|
|
|
$
|
(13
|
)
|
|
(86.7
|
)%
|
Royalty Income
|
10
|
|
|
10
|
|
|
—
|
|
|
—
|
%
|
|||
Interest Income
|
9
|
|
|
—
|
|
|
9
|
|
|
100.0
|
%
|
|||
Other
|
6
|
|
|
4
|
|
|
2
|
|
|
50.0
|
%
|
|||
Total Other Income
|
$
|
27
|
|
|
$
|
29
|
|
|
$
|
(2
|
)
|
|
(6.9
|
)%
|
|
|
|
|
|
|
|
|
|||||||
Other Expense
|
|
|
|
|
|
|
|
|||||||
Professional Services
|
$
|
6
|
|
|
$
|
7
|
|
|
$
|
(1
|
)
|
|
(14.3
|
)%
|
Bank Fees
|
13
|
|
|
13
|
|
|
—
|
|
|
—
|
%
|
|||
Other Land Rental Expense
|
6
|
|
|
5
|
|
|
1
|
|
|
20.0
|
%
|
|||
Other Corporate Expense
|
6
|
|
|
9
|
|
|
(3
|
)
|
|
(33.3
|
)%
|
|||
Total Other Expense
|
$
|
31
|
|
|
$
|
34
|
|
|
$
|
(3
|
)
|
|
(8.8
|
)%
|
|
|
|
|
|
|
|
|
|||||||
Total Other Expense
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
(1
|
)
|
|
(20.0
|
)%
|
|
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
|
)%
|
|
|
|
For the Year Ended
|
|
Difference to Year Ended
|
||||||||||||||||||||||||||||||||||||
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||||||||||||||||||
(in millions)
|
Marcellus
|
|
Utica
|
|
CBM
|
|
Other
Gas
|
|
Total
|
|
Marcellus
|
|
Utica
|
|
CBM
|
|
Other
Gas
|
|
Total
|
||||||||||||||||||||
Natural Gas, NGLs and Oil Revenue
|
$
|
646
|
|
|
$
|
217
|
|
|
$
|
209
|
|
|
$
|
53
|
|
|
$
|
1,125
|
|
|
$
|
231
|
|
|
$
|
54
|
|
|
$
|
34
|
|
|
$
|
13
|
|
|
$
|
332
|
|
(Loss) Gain on Commodity Derivative Instruments
|
(30
|
)
|
|
1
|
|
|
(10
|
)
|
|
246
|
|
|
207
|
|
|
(177
|
)
|
|
(28
|
)
|
|
(62
|
)
|
|
615
|
|
|
348
|
|
||||||||||
Purchased Gas Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
54
|
|
|
54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
11
|
|
||||||||||
Other Operating Income
|
—
|
|
|
—
|
|
|
—
|
|
|
69
|
|
|
69
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
||||||||||
Total Revenue and Other Operating Income
|
616
|
|
|
218
|
|
|
199
|
|
|
422
|
|
|
1,455
|
|
|
54
|
|
|
26
|
|
|
(28
|
)
|
|
643
|
|
|
695
|
|
||||||||||
Lease Operating Expense
|
32
|
|
|
19
|
|
|
25
|
|
|
13
|
|
|
89
|
|
|
(2
|
)
|
|
(3
|
)
|
|
—
|
|
|
(2
|
)
|
|
(7
|
)
|
||||||||||
Production, Ad Valorem, and Other Fees
|
15
|
|
|
5
|
|
|
7
|
|
|
2
|
|
|
29
|
|
|
(2
|
)
|
|
—
|
|
|
1
|
|
|
(1
|
)
|
|
(2
|
)
|
||||||||||
Transportation, Gathering and Compression
|
256
|
|
|
45
|
|
|
64
|
|
|
18
|
|
|
383
|
|
|
28
|
|
|
(6
|
)
|
|
(8
|
)
|
|
(5
|
)
|
|
9
|
|
||||||||||
Depreciation, Depletion and Amortization
|
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
|
—
|
|
|
—
|
|
|
—
|
|
|
48
|
|
|
48
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33
|
|
|
33
|
|
||||||||||
Purchased Gas Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
53
|
|
|
53
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
||||||||||
Other Operating Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
112
|
|
|
112
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|
23
|
|
||||||||||
Selling, General and Administrative Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
93
|
|
|
93
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
(11
|
)
|
||||||||||
Total Operating Costs and Expenses
|
525
|
|
|
153
|
|
|
179
|
|
|
500
|
|
|
1,357
|
|
|
35
|
|
|
(11
|
)
|
|
(10
|
)
|
|
171
|
|
|
185
|
|
||||||||||
Interest Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
161
|
|
|
161
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|
(21
|
)
|
||||||||||
Total E&P Division Costs
|
$
|
525
|
|
|
$
|
153
|
|
|
$
|
179
|
|
|
$
|
661
|
|
|
$
|
1,518
|
|
|
$
|
35
|
|
|
$
|
(11
|
)
|
|
$
|
(10
|
)
|
|
$
|
150
|
|
|
$
|
164
|
|
Earnings (Loss) from Continuing Operations Before Income Tax
|
$
|
91
|
|
|
$
|
65
|
|
|
$
|
20
|
|
|
$
|
(239
|
)
|
|
$
|
(63
|
)
|
|
$
|
19
|
|
|
$
|
37
|
|
|
$
|
(18
|
)
|
|
$
|
493
|
|
|
$
|
531
|
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2017
|
|
2016
|
|
Variance
|
|
Percent
Change
|
|||||||
Marcellus Gas Sales Volumes (Bcf)
|
209.7
|
|
|
186.8
|
|
|
22.9
|
|
|
12.3
|
%
|
|||
NGLs Sales Volumes (Bcfe)*
|
27.6
|
|
|
23.5
|
|
|
4.1
|
|
|
17.4
|
%
|
|||
Condensate Sales Volumes (Bcfe)*
|
2.1
|
|
|
2.2
|
|
|
(0.1
|
)
|
|
(4.5
|
)%
|
|||
Total Marcellus Sales Volumes (Bcfe)*
|
239.4
|
|
|
212.5
|
|
|
26.9
|
|
|
12.7
|
%
|
|||
|
|
|
|
|
|
|
|
|||||||
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)
|
$
|
2.57
|
|
|
$
|
2.64
|
|
|
$
|
(0.07
|
)
|
|
(2.7
|
)%
|
Average Marcellus Lease Operating Expenses (per Mcfe)
|
0.13
|
|
|
0.16
|
|
|
(0.03
|
)
|
|
(18.8
|
)%
|
|||
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)
|
0.07
|
|
|
0.08
|
|
|
(0.01
|
)
|
|
(12.5
|
)%
|
|||
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe)
|
1.07
|
|
|
1.07
|
|
|
—
|
|
|
—
|
%
|
|||
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)
|
0.92
|
|
|
0.99
|
|
|
(0.07
|
)
|
|
(7.1
|
)%
|
|||
Total Average Marcellus Costs (per Mcfe)
|
$
|
2.19
|
|
|
$
|
2.30
|
|
|
$
|
(0.11
|
)
|
|
(4.8
|
)%
|
Average Margin for Marcellus (per Mcfe)
|
$
|
0.38
|
|
|
$
|
0.34
|
|
|
$
|
0.04
|
|
|
11.8
|
%
|
|
For the Years Ended December 31,
|
||||||||||||
|
2017
|
|
2016
|
|
Variance
|
|
Percent
Change |
||||||
Utica Gas Sales Volumes (Bcf)
|
70.7
|
|
|
71.3
|
|
|
(0.6
|
)
|
|
(0.8
|
)%
|
||
NGLs Sales Volumes (Bcfe)*
|
11.1
|
|
|
16.7
|
|
|
(5.6
|
)
|
|
(33.5
|
)%
|
||
Oil Sales Volumes (Bcfe)*
|
0.2
|
|
|
—
|
|
|
0.2
|
|
|
100.0
|
%
|
||
Condensate Sales Volumes (Bcfe)*
|
1.0
|
|
|
2.8
|
|
|
(1.8
|
)
|
|
(64.3
|
)%
|
||
Total Utica Sales Volumes (Bcfe)*
|
83.0
|
|
|
90.8
|
|
|
(7.8
|
)
|
|
(8.6
|
)%
|
||
|
|
|
|
|
|
|
|
||||||
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)
|
$
|
2.63
|
|
|
$
|
2.12
|
|
|
0.51
|
|
|
24.1
|
%
|
Average Utica Lease Operating Expenses (per Mcfe)
|
0.23
|
|
|
0.25
|
|
|
(0.02
|
)
|
|
(8.0
|
)%
|
||
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)
|
0.06
|
|
|
0.05
|
|
|
0.01
|
|
|
20.0
|
%
|
||
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)
|
0.54
|
|
|
0.57
|
|
|
(0.03
|
)
|
|
(5.3
|
)%
|
||
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)
|
1.02
|
|
|
0.94
|
|
|
0.08
|
|
|
8.5
|
%
|
||
Total Average Utica Costs (per Mcfe)
|
$
|
1.85
|
|
|
$
|
1.81
|
|
|
0.04
|
|
|
2.2
|
%
|
Average Margin for Utica (per Mcfe)
|
$
|
0.78
|
|
|
$
|
0.31
|
|
|
0.47
|
|
|
151.6
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2017
|
|
2016
|
|
Variance
|
|
Percent
Change
|
|||||||
CBM Gas Sales Volumes (Bcf)
|
65.4
|
|
|
69.0
|
|
|
(3.6
|
)
|
|
(5.2
|
)%
|
|||
|
|
|
|
|
|
|
|
|||||||
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)
|
$
|
3.05
|
|
|
$
|
3.29
|
|
|
$
|
(0.24
|
)
|
|
(7.3
|
)%
|
Average CBM Lease Operating Expenses (per Mcf)
|
0.39
|
|
|
0.36
|
|
|
0.03
|
|
|
8.3
|
%
|
|||
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)
|
0.11
|
|
|
0.09
|
|
|
0.02
|
|
|
22.2
|
%
|
|||
Average CBM Transportation, Gathering and Compression Costs (per Mcf)
|
0.98
|
|
|
1.04
|
|
|
(0.06
|
)
|
|
(5.8
|
)%
|
|||
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)
|
1.26
|
|
|
1.25
|
|
|
0.01
|
|
|
0.8
|
%
|
|||
Total Average CBM Costs (per Mcf)
|
$
|
2.74
|
|
|
$
|
2.74
|
|
|
$
|
—
|
|
|
—
|
%
|
Average Margin for CBM (per Mcf)
|
$
|
0.31
|
|
|
$
|
0.55
|
|
|
$
|
(0.24
|
)
|
|
(43.6
|
)%
|
|
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
|
%
|
|
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
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
(in millions)
|
2017
|
|
2016
|
|
Variance
|
|
Percent
Change
|
|||||||
Water Income
|
$
|
5
|
|
|
$
|
1
|
|
|
$
|
4
|
|
|
400.0
|
%
|
Gathering Income
|
11
|
|
|
11
|
|
|
—
|
|
|
—
|
%
|
|||
Equity in Earnings of Affiliates
|
50
|
|
|
53
|
|
|
(3
|
)
|
|
(5.7
|
)%
|
|||
Other
|
3
|
|
|
—
|
|
|
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.
|
|
For the Years Ended December 31,
|
|||||||||||||
(in millions)
|
2017
|
|
2015
|
|
Variance
|
|
Percent
Change
|
|||||||
Lease Expiration Costs
|
$
|
40
|
|
|
$
|
7
|
|
|
$
|
33
|
|
|
471.4
|
%
|
Land Rentals
|
4
|
|
|
4
|
|
|
—
|
|
|
100.0
|
%
|
|||
Permitting Expense
|
1
|
|
|
2
|
|
|
(1
|
)
|
|
(50.0
|
)%
|
|||
Other
|
3
|
|
|
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 would expire within the next 12 months thereafter, because they were no longer in the Company's future drilling plan. Additionally, approximately $10 million of the $33 million increase was associated with leases which have ceased production.
|
|
For the Years Ended December 31,
|
|||||||||||||
(in millions)
|
2017
|
|
2016
|
|
Variance
|
|
Percent
Change
|
|||||||
Idle Rig Expense
|
$
|
41
|
|
|
$
|
33
|
|
|
$
|
8
|
|
|
24.2
|
%
|
Unutilized Firm Transportation and Processing Fees
|
50
|
|
|
37
|
|
|
13
|
|
|
35.1
|
%
|
|||
Litigation Settlements
|
3
|
|
|
1
|
|
|
2
|
|
|
200.0
|
%
|
|||
Severance Expense
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
%
|
|||
Insurance Expense
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
%
|
|||
Other
|
14
|
|
|
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.
|
•
|
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.
|
|
For the Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Cash provided by operating activities
|
$
|
886
|
|
|
$
|
649
|
|
|
$
|
237
|
|
Cash used in investing activities
|
$
|
(895
|
)
|
|
$
|
(222
|
)
|
|
$
|
(673
|
)
|
Cash (used in) provided by financing activities
|
$
|
(483
|
)
|
|
$
|
36
|
|
|
$
|
(519
|
)
|
•
|
Net income increased $502 million in the period-to-period comparison.
|
•
|
Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $624 million gain on previously held equity interest, a $488 million change in deferred income taxes, a $138 million decrease in impairment of exploration and production properties, a $130 million change in discontinued operations (See Note 5 - Discontinued Operations in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for more information), a $208 million net change in commodity derivative instruments, and a $52 million increase in the loss on debt extinguishment.
|
•
|
Capital expenditures increased $483 million in the period-to-period comparison primarily due to increased expenditures in both the Marcellus and Utica Shale plays resulting from increased drilling and completions activity. Also contributing to the increase is CNXM's capital expenditures which were not included in 2017 due to the consolidation that occurred in 2018. See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
|
•
|
In January 2018, CNX acquired Noble Energy's interest in CNX Gathering for a net payment of $299 million. See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
|
•
|
Proceeds from the sale of assets increased $98 million primarily due to the 2018 sale of substantially all of the Ohio Utica Joint Venture Assets in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble counties along with the 2018 sale of substantially all of CNX's shallow oil and gas assets and certain CBM assets in Pennsylvania and West Virginia. This was partially offset by the 2017 sales of approximately 32,900 net undeveloped acres in Ohio, Pennsylvania, and West Virginia.
|
•
|
In the year ended December 31,2018, there were $612 million of borrowings on the CNX credit facility.
|
•
|
In the year ended December 31, 2018, CNX paid $955 million to repurchase all of the remaining 8.00% senior notes due April 2023 and $411 million of the 5.75% senior notes due in April 2022. CNXM also received proceeds of $394 million from long-term borrowings. In the year ended December 31, 2017, CNX paid $240 million to repurchase $144 million of the 5.75% senior notes due in April 2022 and the remaining 8.25% senior notes due in April 2020 and the 6.375% senior notes due in March 2021. See Note 14 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
|
•
|
In the years ended December 31, 2018 and 2017, CNX repurchased $382 million and $103 million, respectively, of its common stock on the open market.
|
•
|
In the year ended December 31,2018, there were $66 million of net payments on the CNXM credit facility.
|
•
|
In the year ended December 31,2018, there were $55 million in distributions to CNXM noncontrolling interest holders.
|
•
|
In the year ended December 31, 2017, CNX received proceeds of $425 million related to the spin-off of its coal business. See Note 5 - 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, 2018, there were $21 million in debt issuance and financing fees. These fees were nominal in the twelve months ended December 31, 2017.
|
•
|
Financing activities of discontinued operations changed $32 million. See Note 5 - Discontinued Operations in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for more information.
|
|
Payments due by Year
|
||||||||||||||||||
|
Less Than
1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than
5 Years
|
|
Total
|
||||||||||
Purchase Order Firm Commitments
|
$
|
22,036
|
|
|
$
|
1,155
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
23,191
|
|
Gas Firm Transportation and Processing
|
198,352
|
|
|
406,924
|
|
|
358,820
|
|
|
1,034,145
|
|
|
1,998,241
|
|
|||||
Long-Term Debt
|
—
|
|
|
—
|
|
|
1,992,376
|
|
|
394,625
|
|
|
2,387,001
|
|
|||||
Interest on Long-Term Debt
|
133,124
|
|
|
266,248
|
|
|
129,454
|
|
|
65,000
|
|
|
593,826
|
|
|||||
Capital (Finance) Lease Obligations
|
6,997
|
|
|
13,299
|
|
|
—
|
|
|
—
|
|
|
20,296
|
|
|||||
Interest on Capital (Finance) Lease Obligations
|
1,252
|
|
|
989
|
|
|
—
|
|
|
—
|
|
|
2,241
|
|
|||||
Operating Lease Obligations
|
70,590
|
|
|
128,405
|
|
|
24,665
|
|
|
36,256
|
|
|
259,916
|
|
|||||
Long-Term Liabilities—Employee Related (a)
|
1,857
|
|
|
4,012
|
|
|
4,303
|
|
|
25,508
|
|
|
35,680
|
|
|||||
Other Long-Term Liabilities (b)
|
244,087
|
|
|
27,421
|
|
|
2,364
|
|
|
32,877
|
|
|
306,749
|
|
|||||
Total Contractual Obligations (c)
|
$
|
678,295
|
|
|
$
|
848,453
|
|
|
$
|
2,511,982
|
|
|
$
|
1,588,411
|
|
|
$
|
5,627,141
|
|
(a)
|
Employee related long-term liabilities include salaried retirement contributions and work-related injuries and illnesses.
|
(b)
|
Other long-term liabilities include royalties and other long-term liability costs.
|
(c)
|
The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
|
•
|
An aggregate principal amount of $1,294 million of 5.875% Senior Notes due in April 2022 plus $2 million of unamortized bond premium. Interest on the notes is payable April 15 and October 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM.
|
•
|
An aggregate principal amount of $612 million in outstanding borrowings under the CNX revolver.
|
•
|
An aggregate principal amount of $400 million of 6.50% Senior Notes due in March 2026 issued by CNXM, less $5 million of unamortized bond discount. Interest on the notes is payable March 15 and September 15 of each year. Payment on the principal and interest on the notes is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of these notes.
|
•
|
An aggregate principal amount of $84 million in outstanding borrowings under the CNXM revolver. CNX is not a guarantor of CNXM's revolving credit facility.
|
•
|
An aggregate principal amount of $20 million of capital leases with a weighted average interest rate of 7.18% per annum.
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
For the Three Months Ended
|
|
|
||||||||||||||||
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Total Year
|
||||||||||
2019 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Bcf
|
88.7
|
|
|
96.8
|
|
|
97.9
|
|
|
95.7
|
|
|
376.0*
|
|
|||||
Weighted Average Hedge Price per Mcf
|
$
|
2.79
|
|
|
$
|
2.67
|
|
|
$
|
2.67
|
|
|
$
|
2.72
|
|
|
$
|
2.71
|
|
2020 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Bcf
|
108.1
|
|
|
120.7
|
|
|
122.0
|
|
|
122.0
|
|
|
468.6*
|
|
|||||
Weighted Average Hedge Price per Mcf
|
$
|
2.58
|
|
|
$
|
2.54
|
|
|
$
|
2.54
|
|
|
$
|
2.54
|
|
|
$
|
2.55
|
|
2021 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Bcf
|
101.2
|
|
|
102.3
|
|
|
103.4
|
|
|
103.4
|
|
|
410.3
|
|
|||||
Weighted Average Hedge Price per Mcf
|
$
|
2.44
|
|
|
$
|
2.44
|
|
|
$
|
2.44
|
|
|
$
|
2.44
|
|
|
$
|
2.44
|
|
2022 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Bcf
|
68.2
|
|
|
69.0
|
|
|
69.7
|
|
|
69.7
|
|
|
276.6
|
|
|||||
Weighted Average Hedge Price per Mcf
|
$
|
2.48
|
|
|
$
|
2.48
|
|
|
$
|
2.48
|
|
|
$
|
2.48
|
|
|
$
|
2.48
|
|
2023 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Bcf
|
31.3
|
|
|
31.7
|
|
|
32.0
|
|
|
32.0
|
|
|
127.0
|
|
|||||
Weighted Average Hedge Price per Mcf
|
$
|
2.35
|
|
|
$
|
2.35
|
|
|
$
|
2.35
|
|
|
$
|
2.35
|
|
|
$
|
2.35
|
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
||
|
|
Page
|
Report of Independent Registered Public Accounting Firm
|
||
Consolidated Statements of Income for the Years Ended December 31, 2018, 2017 and 2016
|
||
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2018, 2017 and 2016
|
||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017, 2016
|
||
Notes to the Audited Consolidated Financial Statements
|
(Dollars in thousands, except per share data)
|
For the Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Revenue and Other Operating Income:
|
|
|
|
|
|
||||||
Natural Gas, NGLs and Oil Revenue
|
$
|
1,577,937
|
|
|
$
|
1,125,224
|
|
|
$
|
793,248
|
|
(Loss) Gain on Commodity Derivative Instruments
|
(30,212
|
)
|
|
206,930
|
|
|
(141,021
|
)
|
|||
Purchased Gas Revenue
|
65,986
|
|
|
53,795
|
|
|
43,256
|
|
|||
Midstream Revenue
|
89,781
|
|
|
—
|
|
|
—
|
|
|||
Other Operating Income
|
26,942
|
|
|
69,182
|
|
|
64,485
|
|
|||
Total Revenue and Other Operating Income
|
1,730,434
|
|
|
1,455,131
|
|
|
759,968
|
|
|||
Costs and Expenses:
|
|
|
|
|
|
||||||
Operating Expense
|
|
|
|
|
|
||||||
Lease Operating Expense
|
95,139
|
|
|
88,932
|
|
|
96,434
|
|
|||
Transportation, Gathering and Compression
|
302,933
|
|
|
382,865
|
|
|
374,350
|
|
|||
Production, Ad Valorem, and Other Fees
|
32,750
|
|
|
29,267
|
|
|
31,049
|
|
|||
Depreciation, Depletion and Amortization
|
493,423
|
|
|
412,036
|
|
|
419,939
|
|
|||
Exploration and Production Related Other Costs
|
12,033
|
|
|
48,074
|
|
|
14,522
|
|
|||
Purchased Gas Costs
|
64,817
|
|
|
52,597
|
|
|
42,717
|
|
|||
Impairment of Exploration and Production Properties
|
—
|
|
|
137,865
|
|
|
—
|
|
|||
Impairment of Other Intangible Assets
|
18,650
|
|
|
—
|
|
|
—
|
|
|||
Selling, General and Administrative Costs
|
134,806
|
|
|
93,211
|
|
|
104,843
|
|
|||
Other Operating Expense
|
72,412
|
|
|
112,369
|
|
|
88,754
|
|
|||
Total Operating Expense
|
1,226,963
|
|
|
1,357,216
|
|
|
1,172,608
|
|
|||
Other (Income) Expense
|
|
|
|
|
|
||||||
Other (Income) Expense
|
(14,571
|
)
|
|
3,825
|
|
|
4,783
|
|
|||
Gain on Sale of Assets
|
(157,015
|
)
|
|
(188,063
|
)
|
|
(14,270
|
)
|
|||
Gain on Previously Held Equity Interest
|
(623,663
|
)
|
|
—
|
|
|
—
|
|
|||
Loss on Debt Extinguishment
|
54,118
|
|
|
2,129
|
|
|
—
|
|
|||
Interest Expense
|
145,934
|
|
|
161,443
|
|
|
182,195
|
|
|||
Total Other (Income) Expense
|
(595,197
|
)
|
|
(20,666
|
)
|
|
172,708
|
|
|||
Total Costs and Expenses
|
631,766
|
|
|
1,336,550
|
|
|
1,345,316
|
|
|||
Earnings (Loss) from Continuing Operations Before Income Tax
|
1,098,668
|
|
|
118,581
|
|
|
(585,348
|
)
|
|||
Income Tax Expense (Benefit)
|
215,557
|
|
|
(176,458
|
)
|
|
(34,403
|
)
|
|||
Income (Loss) from Continuing Operations
|
883,111
|
|
|
295,039
|
|
|
(550,945
|
)
|
|||
Income (Loss) from Discontinued Operations, net
|
—
|
|
|
85,708
|
|
|
(297,157
|
)
|
|||
Net Income (Loss)
|
883,111
|
|
|
380,747
|
|
|
(848,102
|
)
|
|||
Less: Net Income Attributable to Noncontrolling Interests
|
86,578
|
|
|
—
|
|
|
—
|
|
|||
Net Income (Loss) Attributable to CNX Resources Shareholders
|
$
|
796,533
|
|
|
$
|
380,747
|
|
|
$
|
(848,102
|
)
|
|
For the Years Ended December 31,
|
||||||||||
(Dollars in thousands, except per share data)
|
2018
|
|
2017
|
|
2016
|
||||||
Earnings (Loss) Per Share
|
|
|
|
|
|
||||||
Basic
|
|
|
|
|
|
||||||
Income (Loss) from Continuing Operations
|
$
|
3.75
|
|
|
$
|
1.29
|
|
|
$
|
(2.40
|
)
|
Income (Loss) from Discontinued Operations
|
—
|
|
|
0.37
|
|
|
(1.30
|
)
|
|||
Total Basic Earnings (Loss) Per Share
|
$
|
3.75
|
|
|
$
|
1.66
|
|
|
$
|
(3.70
|
)
|
Diluted
|
|
|
|
|
|
||||||
Income (Loss) from Continuing Operations
|
$
|
3.71
|
|
|
$
|
1.28
|
|
|
$
|
(2.40
|
)
|
Income (Loss) from Discontinued Operations
|
—
|
|
|
0.37
|
|
|
(1.30
|
)
|
|||
Total Diluted Earnings (Loss) Per Share
|
$
|
3.71
|
|
|
$
|
1.65
|
|
|
$
|
(3.70
|
)
|
|
|
|
|
|
|
||||||
Dividends Declared Per Share
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.01
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Net Income (Loss)
|
$
|
883,111
|
|
|
$
|
380,747
|
|
|
$
|
(848,102
|
)
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
||||||
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($792), ($7,365), 16,281)
|
1,672
|
|
|
12,228
|
|
|
(33,226
|
)
|
|||
Reclassification of Cash Flow Hedges from Other Comprehensive Income to Earnings (Net of tax: $-, $-, $25,011)
|
—
|
|
|
—
|
|
|
(43,470
|
)
|
|||
|
|
|
|
|
|
||||||
Other Comprehensive Income (Loss)
|
1,672
|
|
|
12,228
|
|
|
(76,696
|
)
|
|||
|
|
|
|
|
|
||||||
Comprehensive Income (Loss)
|
$
|
884,783
|
|
|
$
|
392,975
|
|
|
$
|
(924,798
|
)
|
|
|
|
|
|
|
||||||
Less: Comprehensive Income Attributable to Noncontrolling Interests
|
86,578
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
||||||
Comprehensive Income (Loss) Attributable to CNX Resources Shareholders
|
$
|
798,205
|
|
|
$
|
392,975
|
|
|
$
|
(924,798
|
)
|
|
|
|
|
||||
|
December 31,
2018 |
|
December 31,
2017 |
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and Cash Equivalents
|
$
|
17,198
|
|
|
$
|
509,167
|
|
Accounts and Notes Receivable:
|
|
|
|
||||
Trade
|
252,424
|
|
|
156,817
|
|
||
Other Receivables
|
11,077
|
|
|
48,908
|
|
||
Supplies Inventories
|
9,715
|
|
|
10,742
|
|
||
Recoverable Income Taxes
|
149,481
|
|
|
31,523
|
|
||
Prepaid Expenses
|
61,791
|
|
|
95,347
|
|
||
Total Current Assets
|
501,686
|
|
|
852,504
|
|
||
Property, Plant and Equipment (Note 10):
|
|
|
|
||||
Property, Plant and Equipment
|
9,567,428
|
|
|
9,316,495
|
|
||
Less—Accumulated Depreciation, Depletion and Amortization
|
2,624,984
|
|
|
3,526,742
|
|
||
Total Property, Plant and Equipment—Net
|
6,942,444
|
|
|
5,789,753
|
|
||
Other Assets:
|
|
|
|
||||
Investment in Affiliates
|
18,663
|
|
|
197,921
|
|
||
Goodwill
|
796,359
|
|
|
—
|
|
||
Other Intangible Assets
|
103,200
|
|
|
—
|
|
||
Other
|
229,818
|
|
|
91,735
|
|
||
Total Other Assets
|
1,148,040
|
|
|
289,656
|
|
||
TOTAL ASSETS
|
$
|
8,592,170
|
|
|
$
|
6,931,913
|
|
|
December 31,
2018 |
|
December 31,
2017 |
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Accounts Payable
|
$
|
229,806
|
|
|
$
|
211,161
|
|
Current Portion of Long-Term Debt (Note 14 and Note 15)
|
6,997
|
|
|
7,111
|
|
||
Other Accrued Liabilities (Note 13)
|
286,172
|
|
|
223,407
|
|
||
Total Current Liabilities
|
522,975
|
|
|
441,679
|
|
||
Long-Term Debt:
|
|
|
|
||||
Long-Term Debt (Note 14)
|
2,378,205
|
|
|
2,187,026
|
|
||
Capital Lease Obligations (Note 15)
|
13,299
|
|
|
20,347
|
|
||
Total Long-Term Debt
|
2,391,504
|
|
|
2,207,373
|
|
||
Deferred Credits and Other Liabilities:
|
|
|
|
||||
Deferred Income Taxes (Note 8)
|
398,682
|
|
|
44,373
|
|
||
Asset Retirement Obligations (Note 9)
|
37,479
|
|
|
198,768
|
|
||
Other
|
159,787
|
|
|
139,821
|
|
||
Total Deferred Credits and Other Liabilities
|
595,948
|
|
|
382,962
|
|
||
TOTAL LIABILITIES
|
3,510,427
|
|
|
3,032,014
|
|
||
Stockholders’ Equity:
|
|
|
|
||||
Common Stock, $0.01 Par Value; 500,000,000 Shares Authorized, 198,663,342 Issued and Outstanding at December 31, 2018; 223,743,322 Issued and Outstanding at December 31, 2017
|
1,990
|
|
|
2,241
|
|
||
Capital in Excess of Par Value
|
2,264,063
|
|
|
2,450,323
|
|
||
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding
|
—
|
|
|
—
|
|
||
Retained Earnings
|
2,071,809
|
|
|
1,455,811
|
|
||
Accumulated Other Comprehensive Loss
|
(7,904
|
)
|
|
(8,476
|
)
|
||
Total CNX Resources Stockholders’ Equity
|
4,329,958
|
|
|
3,899,899
|
|
||
Noncontrolling Interest
|
751,785
|
|
|
—
|
|
||
TOTAL STOCKHOLDERS' EQUITY
|
5,081,743
|
|
|
3,899,899
|
|
||
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
8,592,170
|
|
|
$
|
6,931,913
|
|
|
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, 2015
|
$
|
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
|
)
|
|||||||
Gas Cash Flow Hedge (Net of $25,011 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(43,470
|
)
|
|
(43,470
|
)
|
|
—
|
|
|
(43,470
|
)
|
|||||||
Actuarially Determined Long-Term Liability Adjustments (Net of $16,281 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(33,488
|
)
|
|
(33,488
|
)
|
|
262
|
|
|
(33,226
|
)
|
|||||||
Comprehensive (Loss) Income
|
—
|
|
|
—
|
|
|
(848,102
|
)
|
|
(76,958
|
)
|
|
(925,060
|
)
|
|
9,216
|
|
|
(915,844
|
)
|
|||||||
Shares Withheld for Taxes
|
—
|
|
|
—
|
|
|
(1,649
|
)
|
|
—
|
|
|
(1,649
|
)
|
|
—
|
|
|
(1,649
|
)
|
|||||||
Issuance of Common Stock
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
|||||||
Tax Cost from Stock-Based Compensation
|
—
|
|
|
(4,931
|
)
|
|
—
|
|
|
—
|
|
|
(4,931
|
)
|
|
—
|
|
|
(4,931
|
)
|
|||||||
Amortization of Stock-Based Compensation Awards
|
—
|
|
|
30,298
|
|
|
—
|
|
|
—
|
|
|
30,298
|
|
|
1,185
|
|
|
31,483
|
|
|||||||
Distributions to Noncontrolling Interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21,657
|
)
|
|
(21,657
|
)
|
|||||||
Dividends ($0.145 per share)
|
—
|
|
|
—
|
|
|
(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
|
|
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 Stock
|
7
|
|
|
1,002
|
|
|
—
|
|
|
—
|
|
|
1,009
|
|
|
—
|
|
|
1,009
|
|
|||||||
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
|
|
Net Income
|
—
|
|
|
—
|
|
|
796,533
|
|
|
—
|
|
|
796,533
|
|
|
86,578
|
|
|
883,111
|
|
|||||||
Actuarially Determined Long-Term Liability Adjustments (Net of ($792) Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
1,672
|
|
|
1,672
|
|
|
—
|
|
|
1,672
|
|
|||||||
Comprehensive Income
|
—
|
|
|
—
|
|
|
796,533
|
|
|
1,672
|
|
|
798,205
|
|
|
86,578
|
|
|
884,783
|
|
|||||||
Issuance of Common Stock
|
8
|
|
|
1,705
|
|
|
—
|
|
|
—
|
|
|
1,713
|
|
|
—
|
|
|
1,713
|
|
|||||||
Purchase and Retirement of Common Stock (25,894,324 shares)
|
(259
|
)
|
|
(206,895
|
)
|
|
(176,598
|
)
|
|
—
|
|
|
(383,752
|
)
|
|
—
|
|
|
(383,752
|
)
|
|||||||
Shares Withheld for Taxes
|
—
|
|
|
—
|
|
|
(5,037
|
)
|
|
—
|
|
|
(5,037
|
)
|
|
(348
|
)
|
|
(5,385
|
)
|
|||||||
Acquisition of CNX Gathering, LLC
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
718,577
|
|
|
718,577
|
|
|||||||
Amortization of Stock-Based Compensation Awards
|
—
|
|
|
18,930
|
|
|
—
|
|
|
—
|
|
|
18,930
|
|
|
2,411
|
|
|
21,341
|
|
|||||||
Distributions to CNXM Noncontrolling Interest Holders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(55,433
|
)
|
|
(55,433
|
)
|
|||||||
ASU 2018-02 Reclassification
|
—
|
|
|
—
|
|
|
1,100
|
|
|
(1,100
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
December 31, 2018
|
$
|
1,990
|
|
|
$
|
2,264,063
|
|
|
$
|
2,071,809
|
|
|
$
|
(7,904
|
)
|
|
$
|
4,329,958
|
|
|
$
|
751,785
|
|
|
$
|
5,081,743
|
|
(Dollars in thousands)
|
For the Years Ended December 31,
|
||||||||||
Cash Flows from Operating Activities:
|
2018
|
|
2017
|
|
2016
|
||||||
Net Income (Loss)
|
$
|
883,111
|
|
|
$
|
380,747
|
|
|
$
|
(848,102
|
)
|
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Continuing Operating Activities:
|
|
|
|
|
|
||||||
Net (Income) Loss from Discontinued Operations
|
—
|
|
|
(85,708
|
)
|
|
297,157
|
|
|||
Depreciation, Depletion and Amortization
|
493,423
|
|
|
412,036
|
|
|
419,939
|
|
|||
Amortization of Deferred Financing Costs
|
8,361
|
|
|
10,630
|
|
|
9,059
|
|
|||
Impairment of Exploration and Production Properties
|
—
|
|
|
137,865
|
|
|
—
|
|
|||
Impairment of Other Intangible Assets
|
18,650
|
|
|
—
|
|
|
—
|
|
|||
Stock-Based Compensation
|
21,341
|
|
|
16,983
|
|
|
19,316
|
|
|||
Gain on Sale of Assets
|
(157,015
|
)
|
|
(188,063
|
)
|
|
(14,270
|
)
|
|||
Gain on Previously Held Equity Interest
|
(623,663
|
)
|
|
—
|
|
|
—
|
|
|||
Loss on Debt Extinguishment
|
54,118
|
|
|
2,129
|
|
|
—
|
|
|||
Loss (Gain) on Commodity Derivative Instruments
|
30,212
|
|
|
(206,930
|
)
|
|
141,021
|
|
|||
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments
|
(69,720
|
)
|
|
(41,174
|
)
|
|
245,212
|
|
|||
Deferred Income Taxes
|
345,560
|
|
|
(142,829
|
)
|
|
75,892
|
|
|||
Return on Equity Investment
|
—
|
|
|
—
|
|
|
22,268
|
|
|||
Equity in Earnings of Affiliates
|
(5,363
|
)
|
|
(49,830
|
)
|
|
(53,078
|
)
|
|||
Changes in Operating Assets:
|
|
|
|
|
|
||||||
Accounts and Notes Receivable
|
(57,734
|
)
|
|
(32,792
|
)
|
|
(46,434
|
)
|
|||
Supplies Inventories
|
1,027
|
|
|
4,254
|
|
|
(1,486
|
)
|
|||
Recoverable Income Tax
|
(118,498
|
)
|
|
76,196
|
|
|
(91,313
|
)
|
|||
Prepaid Expenses
|
(1,391
|
)
|
|
631
|
|
|
76,668
|
|
|||
Changes in Other Assets
|
4,904
|
|
|
22,018
|
|
|
(2,473
|
)
|
|||
Changes in Operating Liabilities:
|
|
|
|
|
|
||||||
Accounts Payable
|
12,760
|
|
|
45,669
|
|
|
(17,227
|
)
|
|||
Accrued Interest
|
(5,839
|
)
|
|
(2,955
|
)
|
|
(1,144
|
)
|
|||
Other Operating Liabilities
|
53,135
|
|
|
81,969
|
|
|
(41,913
|
)
|
|||
Changes in Other Liabilities
|
(1,556
|
)
|
|
(7,778
|
)
|
|
78,140
|
|
|||
Net Cash Provided by Continuing Operating Activities
|
885,823
|
|
|
433,068
|
|
|
267,232
|
|
|||
Net Cash Provided by Discontinued Operating Activities
|
—
|
|
|
215,619
|
|
|
197,026
|
|
|||
Net Cash Provided by Operating Activities
|
885,823
|
|
|
648,687
|
|
|
464,258
|
|
|||
Cash Flows from Investing Activities:
|
|
|
|
|
|
||||||
Capital Expenditures
|
(1,116,397
|
)
|
|
(632,846
|
)
|
|
(172,739
|
)
|
|||
CNX Gathering LLC Acquisition, Net of Cash Acquired
|
(299,272
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from Noble Exchange Settlement
|
—
|
|
|
—
|
|
|
213,295
|
|
|||
Proceeds from Asset Sales
|
511,767
|
|
|
414,185
|
|
|
46,989
|
|
|||
Net Distributions from Equity Affiliates
|
9,250
|
|
|
42,873
|
|
|
73,743
|
|
|||
Net Cash (Used in) Provided by Continuing Investing Activities
|
(894,652
|
)
|
|
(175,788
|
)
|
|
161,288
|
|
|||
Net Cash (Used in) Provided by Discontinued Investing Activities
|
—
|
|
|
(46,133
|
)
|
|
326,083
|
|
|||
Net Cash (Used in) Provided by Investing Activities
|
(894,652
|
)
|
|
(221,921
|
)
|
|
487,371
|
|
|||
Cash Flows from Financing Activities:
|
|
|
|
|
|
||||||
Proceeds from (Payments on) CNX Revolving Credit Facility
|
612,000
|
|
|
—
|
|
|
(952,000
|
)
|
|||
Payments on Miscellaneous Borrowings
|
(7,165
|
)
|
|
(8,037
|
)
|
|
(7,802
|
)
|
|||
Payments on Long-Term Notes
|
(955,019
|
)
|
|
(239,716
|
)
|
|
—
|
|
|||
Proceeds from Issuance of CNXM Senior Notes
|
394,000
|
|
|
—
|
|
|
—
|
|
|||
Net Payments on CNXM Revolving Credit Facility
|
(65,500
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions to CNXM Noncontrolling Interest Holders
|
(55,433
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from Spin-Off of CONSOL Energy Inc.
|
—
|
|
|
425,000
|
|
|
—
|
|
|||
Dividends Paid
|
—
|
|
|
—
|
|
|
(2,294
|
)
|
|||
Proceeds from Issuance of Common Stock
|
1,713
|
|
|
1,009
|
|
|
4
|
|
|||
Shares Withheld for Taxes
|
(5,385
|
)
|
|
(6,681
|
)
|
|
(1,649
|
)
|
|||
Purchases of Common Stock
|
(381,752
|
)
|
|
(103,209
|
)
|
|
—
|
|
|||
Debt Issuance and Financing Fees
|
(20,599
|
)
|
|
(361
|
)
|
|
—
|
|
|||
Net Cash (Used in) Provided by Continuing Financing Activities
|
(483,140
|
)
|
|
68,005
|
|
|
(963,741
|
)
|
|||
Net Cash Used in Discontinued Financing Activities
|
—
|
|
|
(31,903
|
)
|
|
(6,663
|
)
|
|||
Net Cash (Used in) Provided by Financing Activities
|
(483,140
|
)
|
|
36,102
|
|
|
(970,404
|
)
|
|||
Net (Decrease) Increase in Cash and Cash Equivalents
|
(491,969
|
)
|
|
462,868
|
|
|
(18,775
|
)
|
|||
Cash and Cash Equivalents at Beginning of Period
|
509,167
|
|
|
46,299
|
|
|
65,074
|
|
|||
Cash and Cash Equivalents at End of Period
|
$
|
17,198
|
|
|
$
|
509,167
|
|
|
$
|
46,299
|
|
|
|
Years
|
Buildings and improvements
|
|
10 to 45
|
Machinery and equipment
|
|
3 to 25
|
Gathering and transmission
|
|
30 to 40
|
Leasehold improvements
|
|
Life of Lease
|
|
For the Years Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Anti-Dilutive Options
|
2,285,775
|
|
|
2,773,423
|
|
|
6,208,813
|
|
Anti-Dilutive Restricted Stock Units
|
—
|
|
|
18,598
|
|
|
663,003
|
|
Anti-Dilutive Performance Share Units
|
145,217
|
|
|
—
|
|
|
2,400,326
|
|
Anti-Dilutive Performance Share Options
|
927,268
|
|
|
927,268
|
|
|
802,804
|
|
|
3,358,260
|
|
|
3,719,289
|
|
|
10,074,946
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Income (Loss) from Continuing Operations
|
$
|
883,111
|
|
|
$
|
295,039
|
|
|
$
|
(550,945
|
)
|
Less: Net Income Attributable to Non-Controlling Interest
|
86,578
|
|
|
—
|
|
|
—
|
|
|||
Net Income from Continuing Operations Attributable to CNX Resources Shareholders
|
$
|
796,533
|
|
|
$
|
295,039
|
|
|
$
|
(550,945
|
)
|
Income (Loss) from Discontinued Operations
|
—
|
|
|
85,708
|
|
|
(297,157
|
)
|
|||
Net Income (Loss) Attributable to CNX Resources Shareholders
|
$
|
796,533
|
|
|
$
|
380,747
|
|
|
$
|
(848,102
|
)
|
|
|
|
|
|
|
||||||
Weighted-average shares of common stock outstanding
|
212,348,581
|
|
|
228,835,112
|
|
|
229,387,403
|
|
|||
Effect of diluted shares
|
2,280,384
|
|
|
2,116,700
|
|
|
—
|
|
|||
Weighted-average diluted shares of common stock outstanding
|
214,628,965
|
|
|
230,951,812
|
|
|
229,387,403
|
|
|||
|
|
|
|
|
|
||||||
Earnings (Loss) Per Share:
|
|
|
|
|
|
||||||
Basic (Continuing Operations)
|
$
|
3.75
|
|
|
$
|
1.29
|
|
|
$
|
(2.40
|
)
|
Basic (Discontinued Operations)
|
—
|
|
|
0.37
|
|
|
(1.30
|
)
|
|||
Total Basic
|
$
|
3.75
|
|
|
$
|
1.66
|
|
|
$
|
(3.70
|
)
|
|
|
|
|
|
|
||||||
Diluted (Continuing Operations)
|
$
|
3.71
|
|
|
$
|
1.28
|
|
|
$
|
(2.40
|
)
|
Diluted (Discontinued Operations)
|
—
|
|
|
0.37
|
|
|
(1.30
|
)
|
|||
Total Diluted
|
$
|
3.71
|
|
|
$
|
1.65
|
|
|
$
|
(3.70
|
)
|
|
For the Years Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Balance, Beginning of Year
|
223,743,322
|
|
|
229,443,008
|
|
|
229,054,236
|
|
Issuance Related to Stock-Based Compensation (1)
|
814,344
|
|
|
711,214
|
|
|
388,772
|
|
Retirement of Common Stock (2)
|
(25,894,324
|
)
|
|
(6,410,900
|
)
|
|
—
|
|
Balance, End of Year
|
198,663,342
|
|
|
223,743,322
|
|
|
229,443,008
|
|
|
Amount
|
||
Balance at December 31, 2017
|
$
|
(8,476
|
)
|
Other Comprehensive Income before Reclassifications
|
1,736
|
|
|
Amounts Reclassified from Accumulated Other Comprehensive Loss, net of tax
|
(64
|
)
|
|
Current Period Other Comprehensive Income
|
1,672
|
|
|
ASU 2018-02 Reclassification
|
(1,100
|
)
|
|
Balance at December 31, 2018
|
$
|
(7,904
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Derivative Instruments (Note 21)
|
|
|
|
|
|
||||||
Natural Gas Price Swaps and Options
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(68,481
|
)
|
Tax Expense
|
—
|
|
|
—
|
|
|
25,011
|
|
|||
Net of Tax
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(43,470
|
)
|
|
|
|
|
|
|
||||||
Actuarially Determined Long-Term Liability Adjustments* (Note 16)
|
|
|
|
|
|
||||||
Amortization of Prior Service Costs
|
$
|
(193
|
)
|
|
$
|
(2,775
|
)
|
|
$
|
(590
|
)
|
Recognized Net Actuarial Loss
|
302
|
|
|
23,043
|
|
|
23,857
|
|
|||
Settlement Loss
|
—
|
|
|
—
|
|
|
22,196
|
|
|||
Total
|
109
|
|
|
20,268
|
|
|
45,463
|
|
|||
Less: Tax Benefit
|
173
|
|
|
7,499
|
|
|
16,959
|
|
|||
Net of Tax
|
$
|
(64
|
)
|
|
$
|
12,769
|
|
|
$
|
28,504
|
|
|
For the Years Ended December 31,
|
||||||||||
2018
|
|
2017
|
|
2016
|
|||||||
Revenue from Contracts with Customers
|
|
|
|
|
|
||||||
Natural Gas Revenue
|
$
|
1,391,459
|
|
|
$
|
945,382
|
|
|
$
|
670,399
|
|
NGLs Revenue
|
165,883
|
|
|
156,132
|
|
|
97,580
|
|
|||
Condensate Revenue
|
17,559
|
|
|
20,531
|
|
|
22,748
|
|
|||
Oil Revenue
|
3,036
|
|
|
3,179
|
|
|
2,521
|
|
|||
Total Natural Gas, NGLs and Oil Revenue
|
1,577,937
|
|
|
1,125,224
|
|
|
793,248
|
|
|||
|
|
|
|
|
|
||||||
Purchased Gas Revenue
|
65,986
|
|
|
53,795
|
|
|
43,256
|
|
|||
Midstream Revenue
|
89,781
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
||||||
Other Sources of Revenue and Other Operating Income
|
|
|
|
|
|
||||||
(Loss) Gain on Commodity Derivative Instruments
|
(30,212
|
)
|
|
206,930
|
|
|
(141,021
|
)
|
|||
Other Operating Income
|
26,942
|
|
|
69,182
|
|
|
64,485
|
|
|||
Total Revenue and Other Operating Income
|
$
|
1,730,434
|
|
|
$
|
1,455,131
|
|
|
$
|
759,968
|
|
|
For the Years Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
Coal Revenue
|
$
|
1,067,841
|
|
|
$
|
1,168,486
|
|
Other Outside Sales
|
60,066
|
|
|
31,464
|
|
||
Freight-Outside Coal
|
66,297
|
|
|
47,790
|
|
||
Miscellaneous Other Income
|
73,645
|
|
|
74,382
|
|
||
Gain on Sale of Assets
|
—
|
|
|
269,124
|
|
||
Total Revenue and Other Income
|
$
|
1,267,849
|
|
|
$
|
1,591,246
|
|
Total Costs
|
1,147,254
|
|
|
1,652,921
|
|
||
Income (Loss) From Operations Before Income Taxes
|
$
|
120,595
|
|
|
$
|
(61,675
|
)
|
Impairment on Assets Held for Sale
|
—
|
|
|
355,681
|
|
||
Income Tax Expense (Benefit)
|
23,984
|
|
|
(129,153
|
)
|
||
Less: Net Income Attributable to Noncontrolling interest
|
10,903
|
|
|
8,954
|
|
||
Income (Loss) From Discontinued Operations, net
|
$
|
85,708
|
|
|
$
|
(297,157
|
)
|
Cash Consideration
|
$
|
305,000
|
|
CNX Gathering Cash on Hand at January 3, 2018 Distributed to Noble
|
2,620
|
|
|
Fair Value of Previously Held Equity Interest
|
799,033
|
|
|
Total Fair Value of Consideration Transferred
|
$
|
1,106,653
|
|
|
December 31, 2018
|
||
Midstream Revenue
|
$
|
258,074
|
|
Earnings from Continuing Operations Before Income Tax
|
$
|
133,811
|
|
|
For the Year Ended December 31,
|
|||||
(in thousands, except per share data) (unaudited)
|
2017
|
2016
|
||||
Pro Forma Total Revenue and Other Operating Income
|
$
|
1,553,078
|
|
876,987
|
|
|
Pro Forma Net Income from Continuing Operations
|
$
|
427,381
|
|
$
|
(422,284
|
)
|
Less: Pro Forma Net income Attributable to Noncontrolling Interests
|
$
|
74,251
|
|
$
|
62,301
|
|
Pro Forma Net Income(Loss) from Continuing Operations Attributable to CNX
|
$
|
353,130
|
|
$
|
(484,585
|
)
|
Pro Forma Income(Loss) per Share from Continuing Operations (Basic)
|
$
|
1.33
|
|
$
|
(2.11
|
)
|
Pro Forma Income(Loss) per Share from Continuing Operations (Diluted)
|
$
|
1.33
|
|
$
|
(2.11
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Current:
|
|
|
|
|
|
||||||
U.S. Federal
|
$
|
(130,003
|
)
|
|
$
|
(31,791
|
)
|
|
$
|
(101,596
|
)
|
U.S. State
|
—
|
|
|
(1,838
|
)
|
|
(8,699
|
)
|
|||
|
(130,003
|
)
|
|
(33,629
|
)
|
|
(110,295
|
)
|
|||
Deferred:
|
|
|
|
|
|
||||||
U.S. Federal
|
319,813
|
|
|
(166,112
|
)
|
|
80,207
|
|
|||
U.S. State
|
25,747
|
|
|
23,283
|
|
|
(4,315
|
)
|
|||
|
345,560
|
|
|
(142,829
|
)
|
|
75,892
|
|
|||
|
|
|
|
|
|
||||||
Total Income Tax Expense (Benefit)
|
$
|
215,557
|
|
|
$
|
(176,458
|
)
|
|
$
|
(34,403
|
)
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Deferred Tax Assets:
|
|
|
|
||||
Alternative Minimum Tax
|
$
|
102,482
|
|
|
$
|
188,080
|
|
Net Operating Loss - Federal
|
124,341
|
|
|
99,524
|
|
||
Net Operating Loss - State
|
110,339
|
|
|
107,756
|
|
||
Foreign Tax Credit
|
43,194
|
|
|
44,402
|
|
||
Interest Limitation
|
32,147
|
|
|
—
|
|
||
Equity Compensation
|
13,096
|
|
|
21,866
|
|
||
Gas Well Closing
|
10,140
|
|
|
55,486
|
|
||
Salary Retirement
|
9,434
|
|
|
9,404
|
|
||
Capital Lease
|
1,624
|
|
|
2,020
|
|
||
Other
|
13,714
|
|
|
11,831
|
|
||
Total Deferred Tax Assets
|
460,511
|
|
|
540,369
|
|
||
Valuation Allowance
|
(94,455
|
)
|
|
(136,576
|
)
|
||
Net Deferred Tax Assets
|
366,056
|
|
|
403,793
|
|
||
|
|
|
|
||||
Deferred Tax Liabilities:
|
|
|
|
||||
Property, Plant and Equipment
|
(606,342
|
)
|
|
(424,204
|
)
|
||
Investment in Partnership
|
(125,253
|
)
|
|
(1,251
|
)
|
||
Gas Derivatives
|
(26,160
|
)
|
|
(15,248
|
)
|
||
Advance Gas Royalties
|
(3,384
|
)
|
|
(3,648
|
)
|
||
Other
|
(3,599
|
)
|
|
(3,815
|
)
|
||
Total Deferred Tax Liabilities
|
(764,738
|
)
|
|
(448,166
|
)
|
||
|
|
|
|
||||
Net Deferred Tax Liability
|
$
|
(398,682
|
)
|
|
$
|
(44,373
|
)
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|||||||||||||||
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|||||||||
Statutory U.S. federal income tax rate
|
$
|
230,721
|
|
|
21.0
|
%
|
|
$
|
41,503
|
|
|
35.0
|
%
|
|
$
|
(204,872
|
)
|
|
35.0
|
%
|
Net Effect of state income taxes
|
60,814
|
|
|
5.6
|
|
|
15,538
|
|
|
13.1
|
|
|
(20,954
|
)
|
|
3.6
|
|
|||
Non-controlling Interest
|
(18,181
|
)
|
|
(1.7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Uncertain tax positions
|
(4,265
|
)
|
|
(0.4
|
)
|
|
27,359
|
|
|
23.1
|
|
|
1,351
|
|
|
(0.2
|
)
|
|||
Effect of spin on Federal NOL's
|
—
|
|
|
—
|
|
|
24,942
|
|
|
21.0
|
|
|
—
|
|
|
—
|
|
|||
Accrual to tax return reconciliation
|
3,028
|
|
|
0.3
|
|
|
(1,147
|
)
|
|
(1.0
|
)
|
|
(4,564
|
)
|
|
0.8
|
|
|||
IRS and state tax examination settlements
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,463
|
)
|
|
2.3
|
|
|||
Effect of change in state valuation allowance
|
(22,684
|
)
|
|
(2.1
|
)
|
|
(430
|
)
|
|
(0.4
|
)
|
|
18,999
|
|
|
(3.2
|
)
|
|||
Effect of change in federal valuation allowance
|
(18,110
|
)
|
|
(1.7
|
)
|
|
(145,772
|
)
|
|
(122.9
|
)
|
|
184,227
|
|
|
(31.5
|
)
|
|||
Other deferred adjustments
|
5,957
|
|
|
0.6
|
|
|
7,616
|
|
|
6.4
|
|
|
—
|
|
|
—
|
|
|||
Effect of federal and state rate reductions
|
(27,429
|
)
|
|
(2.5
|
)
|
|
(131,784
|
)
|
|
(111.1
|
)
|
|
—
|
|
|
—
|
|
|||
Effect of federal tax credits
|
1,208
|
|
|
0.1
|
|
|
(19,081
|
)
|
|
(16.1
|
)
|
|
—
|
|
|
—
|
|
|||
Other
|
4,498
|
|
|
0.4
|
|
|
4,798
|
|
|
4.0
|
|
|
4,873
|
|
|
(0.8
|
)
|
|||
Income Tax Expense (Benefit) / Effective Rate
|
$
|
215,557
|
|
|
19.6
|
%
|
|
$
|
(176,458
|
)
|
|
(148.9
|
)%
|
|
$
|
(34,403
|
)
|
|
6.0
|
%
|
|
For the Years Ended
|
||||||
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Balance at beginning of period
|
$
|
37,813
|
|
|
$
|
9,103
|
|
Increase in unrecognized tax benefits resulting from tax positions taken during current period
|
—
|
|
|
21,902
|
|
||
Increase in unrecognized tax benefits resulting from tax positions taken during prior periods
|
2,140
|
|
|
7,474
|
|
||
Reduction in unrecognized tax benefits because of the lapse of the applicable statute of limitations
|
(8,437
|
)
|
|
(666
|
)
|
||
Balance at end of period
|
$
|
31,516
|
|
|
$
|
37,813
|
|
|
|
As of December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Balance at beginning of period
|
|
$
|
204,070
|
|
|
$
|
201,006
|
|
Obligations Divested (Note 6)
|
|
(196,643
|
)
|
|
(1,960
|
)
|
||
Accretion expense
|
|
9,874
|
|
|
5,760
|
|
||
Obligations Incurred
|
|
4,795
|
|
|
441
|
|
||
Obligations Settled
|
|
(5,323
|
)
|
|
(6,875
|
)
|
||
Revisions in estimated cash flows
|
|
21,781
|
|
|
5,698
|
|
||
Balance at end of period
|
|
$
|
38,554
|
|
|
$
|
204,070
|
|
|
December 31,
|
||||||
Property, Plant and Equipment
|
2018
|
|
2017
|
||||
Intangible Drilling Cost
|
$
|
4,120,283
|
|
|
$
|
3,849,689
|
|
Proved Gas Properties
|
1,135,411
|
|
|
1,999,891
|
|
||
Gas Gathering Equipment
|
2,126,895
|
|
|
1,182,234
|
|
||
Unproved Gas Properties
|
927,667
|
|
|
919,733
|
|
||
Gas Wells and Related Equipment
|
856,973
|
|
|
834,120
|
|
||
Surface Land and Other Equipment
|
308,297
|
|
|
309,602
|
|
||
Other Gas Assets
|
91,902
|
|
|
221,226
|
|
||
Total Property, Plant and Equipment
|
$
|
9,567,428
|
|
|
$
|
9,316,495
|
|
Less: Accumulated Depreciation, Depletion and Amortization
|
2,624,984
|
|
|
3,526,742
|
|
||
Total Property, Plant and Equipment - Net
|
$
|
6,942,444
|
|
|
$
|
5,789,753
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Unproved Gas Properties
|
$
|
927,667
|
|
|
$
|
919,733
|
|
Gas Advance Royalties
|
12,863
|
|
|
13,220
|
|
||
Total
|
$
|
940,530
|
|
|
$
|
932,953
|
|
|
Amount
|
||
December 31, 2017
|
$
|
—
|
|
Acquisitions
|
796,359
|
|
|
December 31, 2018
|
$
|
796,359
|
|
|
December 31, 2018
|
||
Other Intangible Assets
|
|
||
Customer Relationships
|
$
|
128,781
|
|
Less: Impairment of Other Intangible Assets
|
(18,650
|
)
|
|
Less: Accumulated Amortization for Customer Relationships
|
(6,931
|
)
|
|
Total Other Intangible Assets, net
|
$
|
103,200
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Royalties
|
|
$
|
92,005
|
|
|
$
|
60,008
|
|
Gas derivatives
|
|
61,661
|
|
|
41,291
|
|
||
Accrued interest
|
|
26,333
|
|
|
32,172
|
|
||
Short-term incentive compensation
|
|
20,482
|
|
|
12,062
|
|
||
Transportation charges
|
|
19,661
|
|
|
13,004
|
|
||
Deferred revenue
|
|
17,693
|
|
|
11,559
|
|
||
Accrued other taxes
|
|
7,300
|
|
|
9,779
|
|
||
Accrued payroll & benefits
|
|
6,533
|
|
|
6,615
|
|
||
Other
|
|
31,851
|
|
|
30,083
|
|
||
Current portion of long-term liabilities:
|
|
|
|
|
||||
Salary retirement
|
|
1,578
|
|
|
1,532
|
|
||
Asset retirement obligations
|
|
1,075
|
|
|
5,302
|
|
||
Total Other Accrued Liabilities
|
|
$
|
286,172
|
|
|
$
|
223,407
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Debt:
|
|
|
|
||||
Senior Notes due April 2022 at 5.875% (Principal of $1,294,307 and $1,705,682 plus Unamortized Premium of $2,069 and $3,544, respectively)
|
$
|
1,296,376
|
|
|
$
|
1,709,226
|
|
CNX Revolving Credit Facility
|
612,000
|
|
|
—
|
|
||
CNX Midstream Partners LP Senior Notes due March 2026 at 6.50% (Principal of $400,000 less Unamortized Discount of $5,375 at December 31, 2018)
|
394,625
|
|
|
—
|
|
||
CNX Midstream Partners LP Revolving Credit Facility
|
84,000
|
|
|
—
|
|
||
Senior Notes due April 2023 at 8.00% (Principal of $500,000 less Unamortized Discount of $4,751 at December 31, 2017)
|
—
|
|
|
495,249
|
|
||
Other Note Maturing in 2018 (Principal of $358 less Unamortized Discount of $8 at December 31, 2017)
|
—
|
|
|
350
|
|
||
Less: Unamortized Debt Issuance Costs
|
8,796
|
|
|
17,536
|
|
||
|
2,378,205
|
|
|
2,187,289
|
|
||
Less: Amounts Due in One Year*
|
—
|
|
|
263
|
|
||
Long-Term Debt
|
$
|
2,378,205
|
|
|
$
|
2,187,026
|
|
Year ended December 31,
|
Amount
|
||
2019
|
$
|
—
|
|
2020
|
—
|
|
|
2021
|
—
|
|
|
2022
|
1,294,307
|
|
|
2023
|
696,000
|
|
|
Thereafter
|
400,000
|
|
|
Total Long-Term Debt Maturities
|
$
|
2,390,307
|
|
|
|
Capital
|
|
Operating
|
||||
|
|
Leases
|
|
Leases
|
||||
Year Ended December 31,
|
|
|
|
|
||||
2019
|
|
$
|
8,248
|
|
|
$
|
70,590
|
|
2020
|
|
7,582
|
|
|
69,169
|
|
||
2021
|
|
6,706
|
|
|
59,236
|
|
||
2022
|
|
—
|
|
|
19,212
|
|
||
2023
|
|
—
|
|
|
5,453
|
|
||
Thereafter
|
|
—
|
|
|
36,256
|
|
||
Total minimum lease payments
|
|
$
|
22,536
|
|
|
$
|
259,916
|
|
Less amount representing interest (3.87% – 7.36%)
|
|
2,240
|
|
|
|
|||
Present value of minimum lease payments
|
|
20,296
|
|
|
|
|||
Less amount due in one year
|
|
6,997
|
|
|
|
|||
Total long-term capital lease obligation
|
|
$
|
13,299
|
|
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Change in benefit obligation:
|
|
|
|
|
||||
Benefit obligation at beginning of period
|
|
$
|
36,280
|
|
|
$
|
34,051
|
|
Service cost
|
|
302
|
|
|
375
|
|
||
Interest cost
|
|
1,265
|
|
|
1,201
|
|
||
Actuarial (gain) loss
|
|
(2,645
|
)
|
|
2,127
|
|
||
Plan curtailments
|
|
(126
|
)
|
|
—
|
|
||
Benefits and other payments
|
|
(1,507
|
)
|
|
(1,474
|
)
|
||
Benefit obligation at end of period
|
|
$
|
33,569
|
|
|
$
|
36,280
|
|
|
|
|
|
|
||||
Change in plan assets:
|
|
|
|
|
||||
Fair value of plan assets at beginning of period
|
|
$
|
—
|
|
|
$
|
—
|
|
Company contributions
|
|
1,507
|
|
|
1,474
|
|
||
Benefits and other payments
|
|
(1,507
|
)
|
|
(1,474
|
)
|
||
Fair value of plan assets at end of period
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
||||
Funded status:
|
|
|
|
|
||||
Current liabilities
|
|
$
|
(1,578
|
)
|
|
$
|
(1,532
|
)
|
Noncurrent liabilities
|
|
(31,991
|
)
|
|
(34,748
|
)
|
||
Net obligation recognized
|
|
$
|
(33,569
|
)
|
|
$
|
(36,280
|
)
|
|
|
|
|
|
||||
Amounts recognized in accumulated other comprehensive loss consist of:
|
|
|
|
|
||||
Net actuarial loss
|
|
$
|
10,738
|
|
|
$
|
14,374
|
|
Prior service credit
|
|
(17
|
)
|
|
(626
|
)
|
||
Net amount recognized (before tax effect)
|
|
$
|
10,721
|
|
|
$
|
13,748
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
||||||
Service cost
|
$
|
302
|
|
|
$
|
375
|
|
|
$
|
367
|
|
Interest cost
|
1,265
|
|
|
1,201
|
|
|
1,250
|
|
|||
Amortization of prior service credits
|
(193
|
)
|
|
(362
|
)
|
|
(362
|
)
|
|||
Recognized net actuarial loss
|
865
|
|
|
1,525
|
|
|
1,505
|
|
|||
Curtailment gain
|
(416
|
)
|
|
—
|
|
|
—
|
|
|||
Net periodic benefit cost
|
$
|
1,823
|
|
|
$
|
2,739
|
|
|
$
|
2,760
|
|
|
|
Pension
|
||
|
|
Benefits
|
||
Prior service credit recognition
|
|
$
|
17
|
|
Actuarial loss recognition
|
|
$
|
(239
|
)
|
|
|
As of December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Projected benefit obligation
|
|
$
|
33,569
|
|
|
$
|
36,280
|
|
Accumulated benefit obligation
|
|
$
|
33,169
|
|
|
$
|
35,264
|
|
Fair value of plan assets
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
For the Year Ended
|
||||
|
|
As of December 31,
|
||||
|
|
2018
|
|
2017
|
||
Discount rate
|
|
4.37
|
%
|
|
3.70
|
%
|
Rate of compensation increase
|
|
3.63
|
%
|
|
4.05
|
%
|
|
For the Years ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Discount rate
|
4.28
|
%
|
|
4.26
|
%
|
|
4.55
|
%
|
Rate of compensation increase
|
4.05
|
%
|
|
3.90
|
%
|
|
3.80
|
%
|
|
|
Pension
|
||
Year ended December 31,
|
|
Benefits
|
||
2019
|
|
$
|
1,578
|
|
2020
|
|
$
|
1,669
|
|
2021
|
|
$
|
1,749
|
|
2022
|
|
$
|
1,838
|
|
2023
|
|
$
|
1,927
|
|
Year 2024-2028
|
|
$
|
10,813
|
|
|
|
December 31,
|
December 31,
|
December 31,
|
||||||
|
|
2018
|
2017
|
2016
|
||||||
Weighted average fair value of grants
|
|
$
|
6.50
|
|
$
|
6.19
|
|
$
|
5.73
|
|
Risk-free interest rate
|
|
2.66
|
%
|
1.66
|
%
|
1.13
|
%
|
|||
Expected dividend yield
|
|
—
|
%
|
—
|
%
|
0.27
|
%
|
|||
Expected forfeiture rate
|
|
—
|
%
|
—
|
%
|
2.00
|
%
|
|||
Expected volatility
|
|
52.68
|
%
|
50.85
|
%
|
61.09
|
%
|
|||
Expected term in years
|
|
3.71
|
|
3.71
|
|
4.90
|
|
|
|
|
|
|
|
Weighted
|
|
|
|||
|
|
|
|
|
|
Average
|
|
|
|||
|
|
|
|
Weighted
|
|
Remaining
|
|
Aggregate
|
|||
|
|
|
|
Average
|
|
Contractual
|
|
Intrinsic
|
|||
|
|
|
|
Exercise
|
|
Term (in
|
|
Value (in
|
|||
|
|
Shares
|
|
Price
|
|
years)
|
|
thousands)
|
|||
Outstanding at December 31, 2017
|
|
6,192,315
|
|
|
$21.51
|
|
|
|
|
||
Granted
|
|
21,924
|
|
|
$15.55
|
|
|
|
|
||
Exercised
|
|
(240,887
|
)
|
|
$6.87
|
|
|
|
|
||
Forfeited
|
|
(36,662
|
)
|
|
$6.87
|
|
|
|
|
||
Expired
|
|
(493,770
|
)
|
|
$65.40
|
|
|
|
|
||
Outstanding at December 31, 2018
|
|
5,442,920
|
|
|
$18.74
|
|
4.79
|
|
$
|
12,485
|
|
Exercisable at December 31, 2018
|
|
4,529,180
|
|
|
$21.09
|
|
4.31
|
|
$
|
8,431
|
|
|
|
Number of
|
|
Weighted Average
|
|
|
|
Shares
|
|
Grant Date Fair Value
|
|
Nonvested at December 31, 2017
|
|
937,462
|
|
|
$16.01
|
Granted
|
|
984,286
|
|
|
$13.99
|
Vested
|
|
(446,759
|
)
|
|
$17.23
|
Forfeited
|
|
(47,838
|
)
|
|
$14.31
|
Nonvested at December 31, 2018
|
|
1,427,151
|
|
|
$14.30
|
|
|
Number of
|
|
Weighted Average
|
|
|
|
Shares
|
|
Grant Date Fair Value
|
|
Nonvested at December 31, 2017
|
|
1,273,042
|
|
|
$25.53
|
Granted
|
|
476,121
|
|
|
$18.00
|
PSUs issued as a result of 200% payout
|
|
275,829
|
|
|
$23.75
|
Vested
|
|
(551,657
|
)
|
|
$23.75
|
Forfeited
|
|
(128,350
|
)
|
|
$27.03
|
Nonvested at December 31, 2018
|
|
1,344,985
|
|
|
$19.93
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Interest (net of amounts capitalized)
|
|
$
|
144,756
|
|
|
$
|
152,047
|
|
|
$
|
186,924
|
|
Income taxes
|
|
$
|
(11,505
|
)
|
|
$
|
(121,773
|
)
|
|
$
|
(18,032
|
)
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Gas Wholesalers
|
|
$
|
232,638
|
|
|
$
|
126,387
|
|
NGL, Condensate & Processing Facilities
|
|
12,595
|
|
|
29,841
|
|
||
Other
|
|
7,191
|
|
|
589
|
|
||
Total Accounts Receivable Trade
|
|
$
|
252,424
|
|
|
$
|
156,817
|
|
|
Fair Value Measurements at
December 31, 2018 |
|
Fair Value Measurements at
December 31, 2017 |
||||||||||||||||||||
Description
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||||||
Gas Derivatives
|
$
|
—
|
|
|
$
|
99,456
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
59,949
|
|
|
$
|
—
|
|
Put Option
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3,500
|
)
|
|
$
|
—
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
Cash and Cash Equivalents
|
$
|
17,198
|
|
|
$
|
17,198
|
|
|
$
|
509,167
|
|
|
$
|
509,167
|
|
Long-Term Debt (Excluding Debt Issuance Costs)
|
$
|
2,387,001
|
|
|
$
|
2,290,537
|
|
|
$
|
2,204,825
|
|
|
$
|
2,281,282
|
|
|
December 31,
|
|
Forecasted to
|
||||
|
2018
|
|
2017
|
|
Settle Through
|
||
Natural Gas Commodity Swaps (Bcf)
|
1,484.4
|
|
|
1,067.2
|
|
|
2023
|
Natural Gas Basis Swaps (Bcf)
|
1,056.6
|
|
|
688.1
|
|
|
2023
|
Asset Derivative Instruments
|
|
Liability Derivative Instruments
|
||||||||||||||
|
December 31,
|
|
|
December 31,
|
||||||||||||
|
2018
|
|
2017
|
|
|
2018
|
|
2017
|
||||||||
Commodity Swaps:
|
|
|
|
|
|
|
|
|||||||||
Prepaid Expense
|
$
|
28,612
|
|
|
$
|
62,369
|
|
|
Other Accrued Liabilities
|
$
|
34,640
|
|
|
$
|
5,985
|
|
Other Assets
|
164,310
|
|
|
59,281
|
|
|
Other Liabilities
|
52,011
|
|
|
42,419
|
|
||||
Total Asset
|
$
|
192,922
|
|
|
$
|
121,650
|
|
|
Total Liability
|
$
|
86,651
|
|
|
$
|
48,404
|
|
|
|
|
|
|
|
|
|
|
||||||||
Basis Only Swaps:
|
|
|
|
|
|
|
|
|
||||||||
Prepaid Expense
|
$
|
11,628
|
|
|
$
|
14,965
|
|
|
Other Accrued Liabilities
|
$
|
27,021
|
|
|
$
|
35,306
|
|
Other Assets
|
48,788
|
|
|
24,223
|
|
|
Other Liabilities
|
40,210
|
|
|
17,179
|
|
||||
Total Asset
|
$
|
60,416
|
|
|
$
|
39,188
|
|
|
Total Liability
|
$
|
67,231
|
|
|
$
|
52,485
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash (Paid) Received in Settlement of Commodity Derivative Instruments:
|
|
|
|
|
|
||||||
Commodity Swaps:
|
|
|
|
|
|
||||||
Natural Gas
|
$
|
(41,098
|
)
|
|
$
|
(34,928
|
)
|
|
$
|
225,797
|
|
Propane
|
—
|
|
|
(1,216
|
)
|
|
(650
|
)
|
|||
Natural Gas Basis Swaps
|
(28,622
|
)
|
|
(5,030
|
)
|
|
20,065
|
|
|||
Total Cash (Paid) Received in Settlement of Commodity Derivative Instruments
|
(69,720
|
)
|
|
(41,174
|
)
|
|
245,212
|
|
|||
|
|
|
|
|
|
||||||
Unrealized Gain (Loss) on Commodity Derivative Instruments:
|
|
|
|
|
|
||||||
Commodity Swaps:
|
|
|
|
|
|
||||||
Natural Gas
|
33,026
|
|
|
319,605
|
|
|
(520,170
|
)
|
|||
Propane
|
—
|
|
|
1,147
|
|
|
(1,148
|
)
|
|||
Natural Gas Basis Swaps
|
6,482
|
|
|
(72,648
|
)
|
|
66,604
|
|
|||
Reclassified from Accumulated OCI
|
—
|
|
|
—
|
|
|
68,481
|
|
|||
Total Unrealized Gain (Loss) on Commodity Derivative Instruments
|
39,508
|
|
|
248,104
|
|
|
(386,233
|
)
|
|||
|
|
|
|
|
|
||||||
(Loss) Gain on Commodity Derivative Instruments:
|
|
|
|
|
|
||||||
Commodity Swaps:
|
|
|
|
|
|
||||||
Natural Gas
|
$
|
(8,072
|
)
|
|
$
|
284,677
|
|
|
$
|
(294,373
|
)
|
Propane
|
—
|
|
|
(69
|
)
|
|
(1,798
|
)
|
|||
Natural Gas Basis Swaps
|
(22,140
|
)
|
|
(77,678
|
)
|
|
86,669
|
|
|||
Reclassified from Accumulated OCI
|
—
|
|
|
—
|
|
|
68,481
|
|
|||
Total (Loss) Gain on Commodity Derivative Instruments
|
$
|
(30,212
|
)
|
|
$
|
206,930
|
|
|
$
|
(141,021
|
)
|
|
|
|
|
For the Year Ended
|
||
|
|
|
|
December 31, 2016
|
||
Beginning Balance – Accumulated OCI
|
|
$
|
43,470
|
|
||
Gain Reclassified from Accumulated OCI (Net of tax: $25,011)
|
|
(43,470
|
)
|
|||
Ending Balance – Accumulated OCI
|
|
$
|
—
|
|
|
Amount of Commitment Expiration Per Period
|
||||||||||||||||||
|
Total
Amounts
Committed
|
|
Less Than
1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
Beyond
5 Years
|
||||||||||
Letters of Credit:
|
|
|
|
|
|
|
|
|
|
||||||||||
Firm Transportation
|
$
|
198,131
|
|
|
$
|
191,071
|
|
|
$
|
7,060
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Other
|
265
|
|
|
—
|
|
|
265
|
|
|
—
|
|
|
—
|
|
|||||
Total Letters of Credit
|
198,396
|
|
|
191,071
|
|
|
7,325
|
|
|
—
|
|
|
—
|
|
|||||
Surety Bonds:
|
|
|
|
|
|
|
|
|
|
||||||||||
Employee-Related
|
1,850
|
|
|
1,850
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Environmental
|
11,136
|
|
|
10,876
|
|
|
260
|
|
|
—
|
|
|
—
|
|
|||||
Financial Guarantees
|
57,330
|
|
|
57,330
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
10,034
|
|
|
8,774
|
|
|
1,260
|
|
|
—
|
|
|
—
|
|
|||||
Total Surety Bonds
|
80,350
|
|
|
78,830
|
|
|
1,520
|
|
|
—
|
|
|
—
|
|
|||||
Total Commitments
|
$
|
278,746
|
|
|
$
|
269,901
|
|
|
$
|
8,845
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Operating Lease Obligations Due
|
Amount
|
||
Less than 1 year
|
$
|
70,590
|
|
1 - 3 years
|
128,405
|
|
|
3 - 5 years
|
24,665
|
|
|
More than 5 years
|
36,256
|
|
|
Total Operating Lease Obligations
|
$
|
259,916
|
|
Obligations Due
|
Amount
|
||
Less than 1 year
|
$
|
220,388
|
|
1 - 3 years
|
408,079
|
|
|
3 - 5 years
|
358,820
|
|
|
More than 5 years
|
1,034,145
|
|
|
Total Purchase Obligations
|
$
|
2,021,432
|
|
|
December 31, 2018
|
||
Assets:
|
|
||
Cash
|
$
|
3,966
|
|
Receivables - Related Party
|
17,073
|
|
|
Receivables - Third Party
|
7,028
|
|
|
Other Current Assets
|
2,383
|
|
|
Property, Plant and Equipment, net
|
891,775
|
|
|
Other Assets
|
3,203
|
|
|
Total Assets
|
$
|
925,428
|
|
Liabilities:
|
|
||
Accounts Payable
|
$
|
43,919
|
|
Accounts Payable - Related Party
|
4,980
|
|
|
Revolving Credit Facility
|
84,000
|
|
|
Long-Term Debt
|
393,215
|
|
|
Total Liabilities
|
$
|
526,114
|
|
|
For the Year Ended
|
||
|
December 31, 2018
|
||
Revenue
|
|
||
Gathering Revenue - Related Party
|
$
|
167,048
|
|
Gathering Revenue - Third Party
|
89,620
|
|
|
Total Revenue
|
256,668
|
|
|
Expenses
|
|
||
Operating Expense - Related Party
|
19,814
|
|
|
Operating Expense - Third Party
|
27,343
|
|
|
General and Administrative Expense - Related Party
|
13,867
|
|
|
General and Administrative Expense - Third Party
|
8,595
|
|
|
Loss on Asset Sales
|
2,501
|
|
|
Depreciation Expense
|
21,939
|
|
|
Interest Expense
|
23,614
|
|
|
Total Expense
|
117,673
|
|
|
Net Income
|
$
|
138,995
|
|
|
|
||
Net Cash Provided by Operating Activities
|
$
|
180,115
|
|
Net Cash Used in Investing Activities
|
$
|
(138,869
|
)
|
Net Cash Used in Financing Activities
|
$
|
(40,474
|
)
|
|
CNX Gathering
|
|
CNXM
|
|
Total
|
||||||
Balance at December 31, 2016
|
$
|
151,075
|
|
|
$
|
18,133
|
|
|
$
|
169,208
|
|
Equity in Earnings
|
9,823
|
|
|
38,523
|
|
|
48,346
|
|
|||
Distributions
|
(17,254
|
)
|
|
(24,929
|
)
|
|
(42,183
|
)
|
|||
Asset Transfer
|
(2,527
|
)
|
|
2,527
|
|
|
—
|
|
|||
Balance at December 31, 2017
|
$
|
141,117
|
|
|
$
|
34,254
|
|
|
$
|
175,371
|
|
|
For the Year Ended
|
For the Year Ended
|
||||
|
December 31, 2017
|
December 31, 2016
|
||||
Other Operating Income:
|
|
|
||||
Equity in Earnings of Affiliates - CNX Gathering
|
$
|
9,823
|
|
$
|
17,112
|
|
Equity in Earnings of Affiliates - CNXM
|
$
|
38,523
|
|
$
|
31,148
|
|
|
|
|
||||
Transportation, Gathering and Compression:
|
|
|
||||
Gathering Services - CNX Gathering
|
$
|
914
|
|
$
|
706
|
|
Gathering Services - CNXM
|
$
|
136,068
|
|
$
|
122,256
|
|
|
Marcellus
Shale
|
|
Utica Shale
|
|
Coalbed
Methane
|
|
Other
Gas
|
|
Total E&P
|
|
Midstream
|
|
Unallocated
|
|
Intercompany Eliminations
|
|
Consolidated
|
|
||||||||||||||||||
Natural Gas, NGLs and Oil Revenue
|
$
|
903,316
|
|
|
$
|
445,880
|
|
|
$
|
212,884
|
|
|
$
|
15,857
|
|
|
$
|
1,577,937
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,577,937
|
|
(A)
|
Purchased Gas Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
65,986
|
|
|
65,986
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
65,986
|
|
|
|||||||||
Midstream Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
258,074
|
|
|
—
|
|
|
(168,293
|
)
|
|
89,781
|
|
|
|||||||||
(Loss) Gain on Commodity Derivative Instruments
|
(40,444
|
)
|
|
(19,882
|
)
|
|
(8,767
|
)
|
|
38,881
|
|
|
(30,212
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(30,212
|
)
|
|
|||||||||
Other Operating Income
|
—
|
|
|
—
|
|
|
—
|
|
|
27,218
|
|
|
27,218
|
|
|
—
|
|
|
—
|
|
|
(276
|
)
|
|
26,942
|
|
(B)
|
|||||||||
Total Revenue and Other Operating Income
|
$
|
862,872
|
|
|
$
|
425,998
|
|
|
$
|
204,117
|
|
|
$
|
147,942
|
|
|
$
|
1,640,929
|
|
|
$
|
258,074
|
|
|
$
|
—
|
|
|
$
|
(168,569
|
)
|
|
$
|
1,730,434
|
|
|
Earnings (Loss) From Continuing Operations Before Income Tax
|
$
|
254,310
|
|
|
$
|
194,164
|
|
|
$
|
49,719
|
|
|
$
|
(253,577
|
)
|
|
$
|
244,616
|
|
|
$
|
133,811
|
|
|
$
|
720,241
|
|
|
$
|
—
|
|
|
$
|
1,098,668
|
|
|
Segment Assets
|
|
|
|
|
|
|
|
|
$
|
6,518,597
|
|
|
$
|
1,919,117
|
|
|
$
|
166,679
|
|
|
$
|
(12,223
|
)
|
|
$
|
8,592,170
|
|
(C)
|
||||||||
Depreciation, Depletion and Amortization
|
|
|
|
|
|
|
|
|
$
|
461,149
|
|
|
$
|
32,274
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
493,423
|
|
|
||||||||
Capital Expenditures
|
|
|
|
|
|
|
|
|
$
|
974,059
|
|
|
$
|
142,338
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,116,397
|
|
|
(A)
|
Included in Total Natural Gas, NGLs and Oil Revenue are sales of $219,472 to NJR Energy Services Company and $184,668 to Direct Energy Business Marketing LLC, each of which comprises over 10% of sales.
|
(B)
|
Includes equity in earnings of unconsolidated affiliates of $5,363 for Total E&P.
|
(C)
|
Includes investments in unconsolidated equity affiliates of $18,663 for Total E&P.
|
|
Marcellus
Shale
|
|
Utica Shale
|
|
Coalbed
Methane
|
|
Other
Gas
|
|
Total
E&P
|
|
Unallocated
|
|
Consolidated
|
|
||||||||||||||
Natural Gas, NGLs and Oil Revenue
|
$
|
646,188
|
|
|
$
|
217,020
|
|
|
$
|
208,677
|
|
|
$
|
53,339
|
|
|
$
|
1,125,224
|
|
|
$
|
—
|
|
|
$
|
1,125,224
|
|
(D)
|
Purchased Gas Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
53,795
|
|
|
53,795
|
|
|
—
|
|
|
53,795
|
|
|
|||||||
(Loss) Gain on Commodity Derivative Instruments
|
(30,336
|
)
|
|
1,367
|
|
|
(9,589
|
)
|
|
245,488
|
|
|
206,930
|
|
|
—
|
|
|
206,930
|
|
|
|||||||
Other Operating Income
|
—
|
|
|
—
|
|
|
—
|
|
|
69,182
|
|
|
69,182
|
|
|
—
|
|
|
69,182
|
|
(E)
|
|||||||
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
|
|
|
$
|
(240,050
|
)
|
|
$
|
(63,527
|
)
|
|
$
|
182,108
|
|
|
$
|
118,581
|
|
|
Segment Assets
|
|
|
|
|
|
|
|
|
$
|
6,391,223
|
|
|
$
|
540,690
|
|
|
$
|
6,931,913
|
|
(F)
|
||||||||
Depreciation, Depletion and Amortization
|
|
|
|
|
|
|
|
|
$
|
412,036
|
|
|
$
|
—
|
|
|
$
|
412,036
|
|
|
||||||||
Capital Expenditures
|
|
|
|
|
|
|
|
|
$
|
632,846
|
|
|
$
|
—
|
|
|
$
|
632,846
|
|
|
(D)
|
Included in Total Natural Gas, NGLs and Oil Revenue 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.
|
(E)
|
Includes equity in earnings of unconsolidated affiliates of $49,830 for Total E&P.
|
(F)
|
Includes investments in unconsolidated equity affiliates of $197,921 for Total E&P.
|
|
Marcellus
Shale
|
|
Utica Shale
|
|
Coalbed
Methane
|
|
Other
Gas
|
|
Total
E&P
|
|
Unallocated
|
|
Consolidated
|
|
||||||||||||||
Natural Gas, NGLs and Oil Revenue
|
$
|
414,484
|
|
|
$
|
163,112
|
|
|
$
|
174,323
|
|
|
$
|
41,329
|
|
|
$
|
793,248
|
|
|
$
|
—
|
|
|
$
|
793,248
|
|
(G)
|
Purchased Gas Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
43,256
|
|
|
43,256
|
|
|
—
|
|
|
43,256
|
|
|
|||||||
Gain (Loss) on Commodity Derivative Instruments
|
147,282
|
|
|
29,285
|
|
|
52,396
|
|
|
(369,984
|
)
|
|
(141,021
|
)
|
|
—
|
|
|
(141,021
|
)
|
|
|||||||
Other Operating Income
|
—
|
|
|
—
|
|
|
—
|
|
|
64,485
|
|
|
64,485
|
|
|
—
|
|
|
64,485
|
|
(H)
|
|||||||
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
|
|
|
$
|
(732,924
|
)
|
|
$
|
(594,394
|
)
|
|
$
|
9,046
|
|
|
$
|
(585,348
|
)
|
|
Segment Assets
|
|
|
|
|
|
|
|
|
$
|
6,521,990
|
|
|
$
|
2,657,701
|
|
|
$
|
9,179,691
|
|
(I)
|
||||||||
Depreciation, Depletion and Amortization
|
|
|
|
|
|
|
|
|
$
|
419,939
|
|
|
$
|
—
|
|
|
$
|
419,939
|
|
|
||||||||
Capital Expenditures
|
|
|
|
|
|
|
|
|
$
|
172,739
|
|
|
$
|
—
|
|
|
$
|
172,739
|
|
|
(G)
|
Included in Total Natural Gas, NGLs and Oil Revenue are sales of $106,280 to NJR Energy Services Company, which comprises over 10% of sales.
|
(H)
|
Includes equity in earnings of unconsolidated affiliates of $53,078 for Total E&P.
|
(I)
|
Includes investments in unconsolidated equity affiliates of $190,964 for Total E&P.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Total Segment Revenue from Contracts with External Customers
|
|
$
|
1,733,704
|
|
|
$
|
1,179,019
|
|
|
$
|
836,504
|
|
(Loss) Gain on Commodity Derivative Instruments
|
|
(30,212
|
)
|
|
206,930
|
|
|
(141,021
|
)
|
|||
Other Operating Income
|
|
26,942
|
|
|
69,182
|
|
|
64,485
|
|
|||
Total Consolidated Revenue and Other Operating Income
|
|
$
|
1,730,434
|
|
|
$
|
1,455,131
|
|
|
$
|
759,968
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Segment Income (Loss) Before Income Taxes for Reportable Business Segments:
|
|
|
|
|
|
|
||||||
Total E&P
|
|
$
|
244,616
|
|
|
$
|
(63,527
|
)
|
|
$
|
(594,394
|
)
|
Midstream
|
|
133,811
|
|
|
—
|
|
|
—
|
|
|||
Total Segment Income (Loss) Before Income Taxes for Reportable Business Segments
|
|
378,427
|
|
|
(63,527
|
)
|
|
(594,394
|
)
|
|||
Unallocated Expenses:
|
|
|
|
|
|
|
||||||
Other Income (Expense)
|
|
14,571
|
|
|
(3,826
|
)
|
|
(5,224
|
)
|
|||
Gain on Certain Asset Sales
|
|
154,775
|
|
|
188,063
|
|
|
14,270
|
|
|||
Gain on Previously Held Equity Interest
|
|
623,663
|
|
|
—
|
|
|
—
|
|
|||
Loss on Debt Extinguishment
|
|
(54,118
|
)
|
|
(2,129
|
)
|
|
—
|
|
|||
Impairment of Other Intangible Assets
|
|
(18,650
|
)
|
|
—
|
|
|
—
|
|
|||
Income (Loss) From Continuing Operations Before Income Tax
|
|
$
|
1,098,668
|
|
|
$
|
118,581
|
|
|
$
|
(585,348
|
)
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
|||||
Segment Assets for Total Reportable Business Segments:
|
|
|
|
|
||||
E&P
|
|
$
|
6,518,597
|
|
|
$
|
6,391,223
|
|
Midstream
|
|
1,919,117
|
|
|
—
|
|
||
Intercompany Eliminations
|
|
(12,223
|
)
|
|
—
|
|
||
Items Excluded from Segment Assets:
|
|
|
|
|
||||
Cash and Other Investments
|
|
17,198
|
|
|
509,167
|
|
||
Recoverable Income Taxes
|
|
149,481
|
|
|
31,523
|
|
||
Total Consolidated Assets
|
|
$
|
8,592,170
|
|
|
$
|
6,931,913
|
|
|
|
As of December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Intangible drilling costs
|
|
$
|
4,120,283
|
|
|
$
|
3,849,689
|
|
Proved gas properties
|
|
1,135,411
|
|
|
1,999,891
|
|
||
Gas gathering assets
|
|
1,099,047
|
|
|
1,182,234
|
|
||
Unproved gas properties
|
|
927,667
|
|
|
919,733
|
|
||
Gas wells and related equipment
|
|
856,973
|
|
|
834,120
|
|
||
Other gas assets
|
|
54,395
|
|
|
181,038
|
|
||
Total Property, Plant and Equipment
|
|
$
|
8,193,776
|
|
|
$
|
8,966,705
|
|
Accumulated Depreciation, Depletion and Amortization
|
|
(2,475,917
|
)
|
|
(3,408,606
|
)
|
||
Net Capitalized Costs
|
|
$
|
5,717,859
|
|
|
$
|
5,558,099
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Property acquisitions
|
|
|
|
|
|
|
||||||
Proved properties
|
|
$
|
38,621
|
|
|
$
|
15,850
|
|
|
$
|
—
|
|
Unproved properties
|
|
36,248
|
|
|
32,038
|
|
|
1,537
|
|
|||
Development
|
|
844,081
|
|
|
544,809
|
|
|
138,813
|
|
|||
Exploration
|
|
61,604
|
|
|
48,020
|
|
|
32,259
|
|
|||
Total
|
|
$
|
980,554
|
|
|
$
|
640,717
|
|
|
$
|
172,609
|
|
(*)
|
Includes costs incurred whether capitalized or expensed.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Natural Gas, NGLs and Oil Revenue
|
|
$
|
1,577,937
|
|
|
$
|
1,125,224
|
|
|
$
|
793,248
|
|
(Loss) Gain on Commodity Derivative Instruments
|
|
(30,212
|
)
|
|
206,930
|
|
|
(141,021
|
)
|
|||
Purchased Gas Revenue
|
|
65,986
|
|
|
53,795
|
|
|
43,256
|
|
|||
Total Revenue
|
|
1,613,711
|
|
|
1,385,949
|
|
|
695,483
|
|
|||
Lease Operating Expense
|
|
95,139
|
|
|
88,932
|
|
|
96,434
|
|
|||
Production, Ad Valorem, and Other Fees
|
|
32,750
|
|
|
29,267
|
|
|
31,049
|
|
|||
Transportation, Gathering and Compression
|
|
424,206
|
|
|
382,865
|
|
|
374,350
|
|
|||
Purchased Gas Costs
|
|
64,817
|
|
|
52,597
|
|
|
42,717
|
|
|||
Impairment of Exploration and Production Properties
|
|
—
|
|
|
137,865
|
|
|
—
|
|
|||
Exploration Costs
|
|
12,033
|
|
|
48,074
|
|
|
14,522
|
|
|||
Depreciation, Depletion and Amortization
|
|
461,149
|
|
|
412,036
|
|
|
419,939
|
|
|||
Total Costs
|
|
1,090,094
|
|
|
1,151,636
|
|
|
979,011
|
|
|||
Pre-tax Operating Income (Loss)
|
|
523,617
|
|
|
234,313
|
|
|
(283,528
|
)
|
|||
Income Tax Expense (Benefit)
|
|
102,629
|
|
|
(348,676
|
)
|
|
(69,929
|
)
|
|||
Results of Operations for Producing Activities excluding Corporate and Interest Costs
|
|
$
|
420,988
|
|
|
$
|
582,989
|
|
|
$
|
(213,599
|
)
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Production (MMcfe)
|
|
507,104
|
|
|
407,166
|
|
|
394,387
|
|
|||
Total average sales price before effects of financial settlements (per Mcfe)
|
|
$
|
3.12
|
|
|
$
|
2.76
|
|
|
$
|
2.01
|
|
Average effects of financial settlements (per Mcfe)
|
|
$
|
(0.15
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
0.62
|
|
Total average sales price including effects of financial settlements (per Mcfe)
|
|
$
|
2.97
|
|
|
$
|
2.66
|
|
|
$
|
2.63
|
|
Average lifting costs, excluding ad valorem and severance taxes (per Mcfe)
|
|
$
|
0.19
|
|
|
$
|
0.22
|
|
|
$
|
0.24
|
|
|
|
Gross
|
|
Net(1)
|
||
Producing Gas Wells (including gob wells)
|
|
6,453
|
|
|
4,623
|
|
Producing Oil Wells
|
|
149
|
|
|
1
|
|
Acreage Position:
|
|
|
|
|
||
Proved Developed Acreage
|
|
289,602
|
|
|
289,602
|
|
Proved Undeveloped Acreage
|
|
33,370
|
|
|
33,370
|
|
Unproved Acreage
|
|
4,940,180
|
|
|
3,960,428
|
|
Total Acreage
|
|
5,263,152
|
|
|
4,283,400
|
|
(1)
|
Net acres include acreage attributable to the Company's working interests of the properties. Additional adjustments (either increases or decreases) may be required as the Company further develops title to and further confirms its rights with respect to its various properties in anticipation of development. The Company believes that its assumptions and methodology in this regard are reasonable.
|
|
|
|
|
|
|
Condensate
|
|
Consolidated
|
||||
|
|
Natural Gas
|
|
NGLs
|
|
& Crude Oil
|
|
Operations
|
||||
|
|
(MMcf)
|
|
(Mbbls)
|
|
(Mbbls)
|
|
(MMcfe)
|
||||
Balance December 31, 2015 (a)
|
|
5,060,215
|
|
|
86,212
|
|
|
10,916
|
|
|
5,642,989
|
|
Revisions (b)
|
|
11,559
|
|
|
(19,078
|
)
|
|
510
|
|
|
(99,849
|
)
|
Price Changes
|
|
(179,914
|
)
|
|
(1,647
|
)
|
|
(34
|
)
|
|
(190,009
|
)
|
Extensions and Discoveries (c)
|
|
643,688
|
|
|
10,960
|
|
|
1,783
|
|
|
720,146
|
|
Production
|
|
(348,753
|
)
|
|
(6,710
|
)
|
|
(896
|
)
|
|
(394,387
|
)
|
Purchases of Reserves In-Place (d)
|
|
1,352,759
|
|
|
13,177
|
|
|
1,970
|
|
|
1,443,642
|
|
Sales of Reserves In-Place (d)
|
|
(711,155
|
)
|
|
(22,382
|
)
|
|
(4,240
|
)
|
|
(870,884
|
)
|
Balance December 31, 2016 (a)
|
|
5,828,399
|
|
|
60,532
|
|
|
10,009
|
|
|
6,251,648
|
|
Revisions (e)
|
|
(202,735
|
)
|
|
1,162
|
|
|
(5,834
|
)
|
|
(232,321
|
)
|
Price Changes
|
|
173,738
|
|
|
1,188
|
|
|
(159
|
)
|
|
181,470
|
|
Extensions and Discoveries (c)
|
|
1,769,029
|
|
|
17,887
|
|
|
1,800
|
|
|
1,887,153
|
|
Production
|
|
(364,893
|
)
|
|
(6,456
|
)
|
|
(589
|
)
|
|
(407,166
|
)
|
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
|
|
Revisions (f)
|
|
313,091
|
|
|
441
|
|
|
865
|
|
|
320,925
|
|
Price Changes
|
|
28,100
|
|
|
32
|
|
|
4
|
|
|
28,315
|
|
Extensions and Discoveries (c)
|
|
839,268
|
|
|
16,247
|
|
|
4,010
|
|
|
960,808
|
|
Production
|
|
(468,228
|
)
|
|
(6,011
|
)
|
|
(468
|
)
|
|
(507,104
|
)
|
Purchases of Reserves In-Place
|
|
317,437
|
|
|
756
|
|
|
—
|
|
|
321,975
|
|
Sales of Reserves In-Place (g)
|
|
(715,088
|
)
|
|
(17,252
|
)
|
|
(1,100
|
)
|
|
(825,196
|
)
|
Balance December 31, 2018 (a)
|
|
7,436,338
|
|
|
65,904
|
|
|
8,261
|
|
|
7,881,335
|
|
|
|
|
|
|
|
|
|
|
||||
Proved developed resources:
|
|
|
|
|
|
|
|
|
||||
December 31, 2016
|
|
3,478,464
|
|
|
30,666,000
|
|
|
3,474,000
|
|
|
3,683,302
|
|
December 31, 2017
|
|
4,051,526
|
|
|
56,022,000
|
|
|
3,567,000
|
|
|
4,409,065
|
|
December 31, 2018
|
|
4,242,579
|
|
|
40,180,000
|
|
|
1,870,000
|
|
|
4,494,878
|
|
|
|
|
|
|
|
|
|
|
||||
Proved undeveloped resources:
|
|
|
|
|
|
|
|
|
||||
December 31, 2016
|
|
2,349,934
|
|
|
29,866,000
|
|
|
6,536,000
|
|
|
2,568,346
|
|
December 31, 2017
|
|
3,070,232
|
|
|
15,669,000
|
|
|
1,383,000
|
|
|
3,172,547
|
|
December 31, 2018
|
|
3,193,759
|
|
|
25,724,000
|
|
|
6,391,000
|
|
|
3,386,457
|
|
(a)
|
Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are reserves expected to be recovered through existing wells, with existing equipment and operating methods.
|
(b)
|
The 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.
|
(c)
|
Extensions and Discoveries in 2016, 2017, and 2018 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.
|
(d)
|
Purchases and Sales of Reserves In-Place in 2016 is the result of the Company's fourth quarter realignment of the Marcellus Shale properties as part of dissolving our joint venture with Noble Energy.
|
(e)
|
The downward revisions for 2017 is due to corporate planning changes by our JV partner in Ohio Utica which resulted in all PUD's being removed, causing a 458 Bcfe downward revision, offset, in part by improved well performance due to the enhanced RCS completions and improved operating costs.
|
(f)
|
The upward revision for 2018 of 321 Bcfe is primarily due to a 472 Bcfe upward revision from increased performance through our continued focus on optimization. This is partially offset by a 151 Bcfe downward revision due to plan changes.
|
(g)
|
The sales of reserves in-place is related to the divestiture of our Utica JV assets and substantially all of our conventional properties. Refer to Note 6 - Acquisitions and Dispositions for more information.
|
|
|
For the Year
|
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
|
2018
|
|
Proved Undeveloped Reserves (MMcfe)
|
|
|
|
Beginning proved undeveloped reserves
|
|
3,172,547
|
|
Undeveloped reserves transferred to developed(a)
|
|
(1,037,727
|
)
|
Disposition of reserves in place
|
|
(27,741
|
)
|
Acquisition of reserves in place
|
|
321,975
|
|
Price Revisions
|
|
(2,489
|
)
|
Revisions Due to Plan Changes (b)
|
|
(151,550
|
)
|
Revisions Due to Changes Due to Well Performance (c)
|
|
189,954
|
|
Extension and discoveries (d)
|
|
921,488
|
|
Ending proved undeveloped reserves(e)
|
|
3,386,457
|
|
(a)
|
During 2018, various exploration and development drilling and evaluations were completed. Approximately, $480,003 of capital was spent in the year ended December 31, 2018 related to undeveloped reserves that were transferred to developed.
|
(c)
|
The upward revisions due to well performance is due to results from Marcellus and Utica Shale production.
|
(d)
|
Extensions and discoveries are due mainly to the addition of wells or an extension to previously booked PUD's on our Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.
|
(e)
|
Included in proved undeveloped reserves at December 31, 2018 are approximately 281,696 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 5 - Discontinued Operations for more information) with the rights to this gas being retained by the Company. Evidence also exists that supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance resulting from an external factor. These reasons constitute the specific circumstances that exist to continue recognizing these reserves for CNX.
|
|
|
December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves
|
|
$
|
46,614
|
|
|
$
|
40,149
|
|
|
$
|
40,917
|
|
Costs expensed due to determination of dry hole or abandonment of project
|
|
$
|
809
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Future Cash Flows (a)
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
26,610,100
|
|
|
$
|
19,261,578
|
|
|
$
|
11,303,409
|
|
Production costs
|
|
(7,730,451
|
)
|
|
(7,234,303
|
)
|
|
(5,850,941
|
)
|
|||
Development costs
|
|
(1,600,128
|
)
|
|
(1,710,585
|
)
|
|
(1,550,294
|
)
|
|||
Income tax expense
|
|
(4,147,075
|
)
|
|
(2,475,981
|
)
|
|
(1,482,826
|
)
|
|||
Future Net Cash Flows
|
|
13,132,446
|
|
|
7,840,709
|
|
|
2,419,348
|
|
|||
Discounted to present value at a 10% annual rate
|
|
(8,476,989
|
)
|
|
(4,709,311
|
)
|
|
(1,464,231
|
)
|
|||
Total standardized measure of discounted net cash flows
|
|
$
|
4,655,457
|
|
|
$
|
3,131,398
|
|
|
$
|
955,117
|
|
(a)
|
For 2018, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2018, adjusted for energy content and a regional price differential. For 2018, this adjusted natural gas price was $3.28 per Mcf, the adjusted oil price was $51.68 per barrel and the adjusted NGL price was $27.58 per barrel.
|
|
|
December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Balance at beginning of period
|
|
$
|
3,131,398
|
|
|
$
|
955,117
|
|
|
$
|
1,019,304
|
|
Net changes in sales prices and production costs
|
|
1,732,229
|
|
|
1,983,475
|
|
|
(172,812
|
)
|
|||
Sales net of production costs
|
|
(995,630
|
)
|
|
(831,131
|
)
|
|
(150,819
|
)
|
|||
Net change due to revisions in quantity estimates
|
|
307,030
|
|
|
(145,496
|
)
|
|
(35,502
|
)
|
|||
Net change due to extensions, discoveries and improved recovery
|
|
534,052
|
|
|
588,574
|
|
|
(54,628
|
)
|
|||
Development costs incurred during the period
|
|
844,081
|
|
|
544,809
|
|
|
138,813
|
|
|||
Difference in previously estimated development costs compared to actual costs incurred during the period
|
|
(434,817
|
)
|
|
(129,427
|
)
|
|
(39,821
|
)
|
|||
Purchase of Reserves In-Place
|
|
209,630
|
|
|
—
|
|
|
238,819
|
|
|||
Sales of Reserves In-Place
|
|
(434,103
|
)
|
|
(55,277
|
)
|
|
(137,998
|
)
|
|||
Changes in estimated future development costs
|
|
(49,294
|
)
|
|
(233,017
|
)
|
|
(158,000
|
)
|
|||
Net change in future income taxes
|
|
(507,410
|
)
|
|
(404,582
|
)
|
|
36,513
|
|
|||
Timing and Other
|
|
(69,087
|
)
|
|
712,764
|
|
|
125,529
|
|
|||
Accretion
|
|
387,378
|
|
|
145,589
|
|
|
145,719
|
|
|||
Total discounted cash flow at end of period
|
|
$
|
4,655,457
|
|
|
$
|
3,131,398
|
|
|
$
|
955,117
|
|
|
|
Three Months Ended
|
||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
||||||||
|
|
2018
|
|
2018
|
|
2018
|
|
2018
|
||||||||
Sales (A)
|
|
$
|
485,019
|
|
|
$
|
393,590
|
|
|
$
|
393,223
|
|
|
$
|
431,660
|
|
Costs and Expenses (B)
|
|
$
|
167,785
|
|
|
$
|
140,040
|
|
|
$
|
123,779
|
|
|
$
|
148,480
|
|
Income from Continuing Operations (C)
|
|
$
|
545,546
|
|
|
$
|
61,394
|
|
|
$
|
146,756
|
|
|
$
|
129,415
|
|
Income from Discontinued Operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Net Income Attributable to CNX Resources Shareholders
|
|
$
|
527,563
|
|
|
$
|
42,014
|
|
|
$
|
125,029
|
|
|
$
|
101,927
|
|
Earnings Per Share
|
|
|
|
|
|
|
|
|
||||||||
Basic:
|
|
|
|
|
|
|
|
|
||||||||
Income from Continuing Operations
|
|
$
|
2.38
|
|
|
$
|
0.19
|
|
|
$
|
0.59
|
|
|
$
|
0.51
|
|
Income from Discontinued Operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total Basic Earnings Per Share
|
|
$
|
2.38
|
|
|
$
|
0.19
|
|
|
$
|
0.59
|
|
|
$
|
0.51
|
|
Diluted:
|
|
|
|
|
|
|
|
|
||||||||
Income from Continuing Operations
|
|
$
|
2.35
|
|
|
$
|
0.19
|
|
|
$
|
0.59
|
|
|
$
|
0.50
|
|
Income from Discontinued Operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total Diluted Earnings Per Share
|
|
$
|
2.35
|
|
|
$
|
0.19
|
|
|
$
|
0.59
|
|
|
$
|
0.50
|
|
|
|
Three Months Ended
|
||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
||||||||
|
|
2017
|
|
2017
|
|
2017
|
|
2017
|
||||||||
Sales (A)
|
|
$
|
304,279
|
|
|
$
|
354,410
|
|
|
$
|
267,009
|
|
|
$
|
460,251
|
|
Costs and Expenses (B)
|
|
$
|
162,150
|
|
|
$
|
166,296
|
|
|
$
|
171,608
|
|
|
$
|
214,050
|
|
(Loss) Income from Continuing Operations (C)
|
|
$
|
(91,007
|
)
|
|
$
|
121,807
|
|
|
$
|
(21,796
|
)
|
|
$
|
286,035
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
52,041
|
|
|
$
|
47,703
|
|
|
$
|
(4,645
|
)
|
|
$
|
(9,391
|
)
|
Net (Loss) Income
|
|
$
|
(38,966
|
)
|
|
$
|
169,510
|
|
|
$
|
(26,441
|
)
|
|
$
|
276,644
|
|
Earnings Per Share
|
|
|
|
|
|
|
|
|
||||||||
Basic:
|
|
|
|
|
|
|
|
|
||||||||
(Loss) Income from Continuing Operations
|
|
$
|
(0.40
|
)
|
|
$
|
0.53
|
|
|
$
|
(0.09
|
)
|
|
$
|
1.27
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
0.23
|
|
|
$
|
0.21
|
|
|
$
|
(0.02
|
)
|
|
$
|
(0.04
|
)
|
Total Basic (Loss) Earnings Per Share
|
|
$
|
(0.17
|
)
|
|
$
|
0.74
|
|
|
$
|
(0.11
|
)
|
|
$
|
1.23
|
|
Diluted:
|
|
|
|
|
|
|
|
|
||||||||
(Loss) Income from Continuing Operations
|
|
$
|
(0.40
|
)
|
|
$
|
0.52
|
|
|
$
|
(0.09
|
)
|
|
$
|
1.26
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
0.23
|
|
|
$
|
0.21
|
|
|
$
|
(0.02
|
)
|
|
$
|
(0.05
|
)
|
Total Diluted (Loss) Earnings Per Share
|
|
$
|
(0.17
|
)
|
|
$
|
0.73
|
|
|
$
|
(0.11
|
)
|
|
$
|
1.21
|
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
|
ITEM 9A.
|
CONTROLS AND PROCEDURES
|
ITEM 9B.
|
OTHER INFORMATION
|
ITEM 10.
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
Name
|
|
Age
|
|
Position
|
Nicholas J. DeIuliis
|
|
50
|
|
President and Chief Executive Officer
|
Stephen W. Johnson
|
|
60
|
|
Executive Vice President and Chief Legal Officer
|
Donald W. Rush
|
|
36
|
|
Executive Vice President and Chief Financial Officer
|
Timothy C. Dugan
|
|
57
|
|
Executive Vice President and Chief Operating Officer
|
ITEM 11.
|
EXECUTIVE COMPENSATION
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
|
ITEM 14.
|
PRINCIPAL ACCOUNTING FEES AND SERVICES
|
ITEM 15.
|
EXHIBITS, FINANCIAL STATMENT SCHEDULES
|
(a)(1)
|
|
Financial Statements Contained in Item 8 hereof.
|
(a)(2)
|
|
Financial Statement Schedule-Schedule II Valuation and Qualifying Accounts contained below, following the signature page.
|
(a)(3)
|
|
Exhibits and Exhibit Index.
|
|
Membership Interest and Asset Purchase Agreement dated February 26, 2016, among the Company, 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, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on February 29, 2016.
|
|
|
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.
|
|
|
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.
|
|
|
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.
|
|
|
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.
|
|
|
Restated Certificate of Incorporation of the Company, incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on May 8, 2006.
|
|
|
Certificate of Amendment to the Restated Certificate of Incorporation of the Company, incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
|
|
|
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.
|
|
|
Indenture, dated as of April 16, 2014, among the Company, 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.
|
|
|
Registration Rights Agreement, dated as of April 16, 2014, by and among the Company, 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.
|
|
|
Registration Rights Agreement, dated as of August 12, 2014, by and among the Company, 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.
|
|
|
Registration Rights Agreement, dated as of March 30, 2015, among the Company, 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.
|
|
Purchase and Sale Agreement, dated as of April 30, 2003, by and among the Company, 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.
|
|
|
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.
|
|
|
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.
|
|
|
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 the Company, 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.
|
|
|
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 the Company, 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.
|
|
|
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 the Company, a Delaware corporation, as the Borrower, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2016, filed on November 1, 2016.
|
|
|
Second Amended and Restated Credit Agreement, dated as of March 8, 2018, among the Company, certain of its subsidiaries, PNC Bank, National Association, as administrative agent and collateral agent, JPMorgan Chase Bank, N.A., as syndication agent and the lender parties thereto, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 12, 2018.
|
|
|
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.
|
|
|
Purchase Agreement, dated as of April 10, 2014, among the Company, 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.
|
|
|
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
|
|
|
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
|
|
|
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
|
|
|
Purchase Agreement, dated as of December 14 ,2017, by and among CNX Gas Company LLC, as Buyer, and NBL Midstream, LLC, as Seller, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on January 3, 2018.
|
|
|
Purchase and Sale Agreement, dated June 28, 2018, by and between CNX Gas Company LLC and Ascent Resources - Utica, LLC, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on August 31, 2018.
|
|
|
First Amendment to Purchase and Sale Agreement, dated August 29, 2018, by and between CNX Gas Company LLC and Ascent Resources - Utica, LLC, incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on August 31, 2018.
|
|
|
Letter Agreement, dated August 24, 2007, by and between the Company and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on August 24, 2007.
|
|
|
Change in Control Agreement, dated as of December 30, 2008, by and between the Company and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.7 to Form 10-K (file no. 001-14901) for the year ended December 31, 2008, filed on February 17, 2009.
|
|
|
Change in Control Agreement, dated as of December 30, 2008, by and among CNX Gas Corporation, the Company and Stephen W. Johnson, incorporated by reference to Exhibit 10.4 to the CNX Gas Corporation Form 10-K (file no. 001-32723) for the year ended December 31, 2008, filed on February 17, 2009.
|
|
Amended and Restated Change in Control Severance Agreement, dated as of August 24, 2015, between the Company 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.
|
|
|
Change in Control Severance Agreement, dated August 24, 2015, between the Company and Donald W. Rush, incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
|
|
|
Form of Indemnification Agreement for Directors and Executive Officers of the Company, 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.
|
|
|
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.
|
|
|
CNX Resources Corporation Equity Incentive Plan, as amended and restated effective January 26, 2018, incorporated by reference to Exhibit 10.48 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
|
|
|
Amended and Restated CNX Resources Corporation Executive Annual Incentive Plan, incorporated by reference to Exhibit 10.49 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
|
|
|
Form of Non-Qualified Stock Option Award Agreement for Employees, incorporated by reference to Exhibit 10.26 to Form S-4 (file no. 333-149442) filed on February 28, 2008.
|
|
|
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.
|
|
|
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.
|
|
|
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.
|
|
|
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.
|
|
|
Form of Non-Qualified Stock Option Agreement for Directors, incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
|
|
|
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.
|
|
|
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.
|
|
|
Form of Restricted Stock Unit Award Agreement for Directors, incorporated by reference to Exhibit 10.30 to Form S-4 (file no. 333-149442) filed on February 28, 2008.
|
|
|
Form of Restricted Stock Unit Award Agreement for Directors, incorporated by reference to Exhibit 10.5 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
|
|
|
Form of Restricted Stock Unit Award Agreement for Employees (for 2015 awards), incorporated by reference to Exhibit 10.67 to Form 10-K (file no. 001-14901) for the year ended December 31, 2014, filed on February 6, 2015.
|
|
|
Form of Restricted Stock Unit Award Agreement for Employees (for 2017 awards), incorporated by reference to Exhibit 10.59 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
|
|
|
Form of Restricted Stock Unit Award Agreement for CEO (for 2019 awards), filed herewith.
|
|
|
Form of Restricted Stock Unit Award Agreement for VP and Above (for 2019 awards), filed herewith.
|
|
|
Form of Restricted Stock Unit Award Agreement for Non-VP and Below (for 2019 awards), filed herewith.
|
|
|
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.
|
|
|
Form of Performance Share Unit Award Agreement (for 2015 awards), incorporated by reference to Exhibit 10.69 to Form 10-K (file no. 001-14901) for the year ended December 31, 2014, filed on February 6, 2015.
|
|
|
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.
|
|
|
Form of Performance Share Unit Award Agreement (for 2017 awards), incorporated by reference to Exhibit 10.63 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
|
|
|
Form of Performance Share Unit Award Agreement for CEO (for 2019 awards), filed herewith.
|
|
|
Form of Performance Share Unit Agreement for VP and Above (for 2019 awards), filed herewith.
|
|
|
Form of Performance Share Unit Agreement for Non-VP and Below (for 2019 awards), filed herewith.
|
|
|
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.
|
|
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.
|
|
|
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.
|
|
|
Hypothetical Investment Election Form Relating to Directors' Deferred Fee Plan (2004 Plan), incorporated by reference to Exhibit 10.50 to Form 10-K (file no. 001-14901) for the year ended December 31, 2007, filed on February 19, 2008.
|
|
|
Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
|
|
|
Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.95 to Form 8-K (file no. 001-14901) filed on May 8, 2006.
|
|
|
Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
|
|
|
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.
|
|
|
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.
|
|
|
Amended and Restated Retirement Restoration Plan of CNX Resources Corporation, as amended and restated effective December 2, 2008, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.71 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
|
|
|
Amended and Restated Supplemental Retirement Plan of CNX Resources Corporation effective January 1, 2007, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.72 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
|
|
|
CNX Resources Corporation Defined Contribution Restoration Plan, effective January 1, 2012, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.73 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
|
|
|
Amendment, dated as of July 1, 2018, to the CNX Resources Corporation Defined Contribution Restoration Plan, effective January 1, 2012, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2018, filed on August 2, 2018.
|
|
|
Executive Compensation Clawback Policy of the Company, dated as of January 28, 2014, incorporated by reference to Exhibit 10.11 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
|
|
|
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, incorporated by reference to Exhibit 10.75 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
|
|
|
Subsidiaries of CNX Resources Corporation.
|
|
|
Consent of Ernst & Young LLP
|
|
|
Consent of Netherland Sewell & Associates, Inc.
|
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
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
|
|
|
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
|
|
|
Engineers' Audit Letter
|
|
101
|
|
Interactive Data File (Form 10-K for the year ended December 31, 2018 furnished in XBRL).
|
|
CNX RESOURCES CORPORATION
|
||
|
|
|
|
|
By:
|
|
/s/ NICHOLAS J. DEIULIIS
|
|
|
|
Nicholas J. DeIuliis
|
|
|
|
Director, Chief Executive Officer and President
|
|
|
|
(Duly Authorized Officer and Principal Executive Officer)
|
Signature
|
|
Title
|
|
|
|
/s/ NICHOLAS J. DEIULIIS
|
|
Director, Chief Executive Officer and President
|
Nicholas J. DeIuliis
|
|
(Duly Authorized Officer and Principal Executive Officer)
|
|
|
|
/s/ DONALD W. RUSH
|
|
Chief Financial Officer and Executive Vice President
|
Donald W. Rush
|
|
(Duly Authorized Officer and Principal Financial Officer)
|
|
|
|
/s/ JASON L. MUMFORD
|
|
Chief Accounting Officer and Vice President
|
Jason 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/ J. PALMER CLARKSON
|
|
Director
|
J. Palmer Clarkson
|
|
|
|
|
|
/s/ WILLIAM E. DAVIS
|
|
Director
|
William E. Davis
|
|
|
|
|
|
/s/ MAUREEN E. LALLY-GREEN
|
|
Director
|
Maureen E. Lally-Green
|
|
|
|
|
|
/s/ BERNARD LANIGAN JR.
|
|
Director
|
Bernard Lanigan Jr.
|
|
|
|
|
|
|
Additions
|
|
Deductions
|
|
|
||||||||||||
|
|
Balance at
|
|
|
|
Release of
|
|
|
|
Balance at
|
||||||||||
|
|
Beginning
|
|
Charged to
|
|
Valuation
|
|
Charged to
|
|
End
|
||||||||||
|
|
of Period
|
|
Expense
|
|
Allowance
|
|
Expense
|
|
of Period
|
||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
||||||||||
State operating loss carry-forwards
|
|
$
|
61,560
|
|
|
$
|
—
|
|
|
$
|
(13,596
|
)
|
|
$
|
—
|
|
|
$
|
47,964
|
|
Deferred deductible temporary differences
|
|
9,088
|
|
|
—
|
|
|
(9,088
|
)
|
|
—
|
|
|
—
|
|
|||||
Charitable Contributions
|
|
3,156
|
|
|
141
|
|
|
—
|
|
|
—
|
|
|
3,297
|
|
|||||
162(m) Officers Compensation
|
|
5,957
|
|
|
—
|
|
|
(5,957
|
)
|
|
—
|
|
|
—
|
|
|||||
AMT Credit
|
|
12,413
|
|
|
1,983
|
|
|
(14,396
|
)
|
|
—
|
|
|
—
|
|
|||||
Foreign Tax Credits
|
|
44,402
|
|
|
—
|
|
|
(1,208
|
)
|
|
—
|
|
|
43,194
|
|
|||||
Total
|
|
$
|
136,576
|
|
|
$
|
2,124
|
|
|
$
|
(44,245
|
)
|
|
$
|
—
|
|
|
$
|
94,455
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
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
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
||||||||||
State operating loss carry-forwards
|
|
$
|
42,983
|
|
|
$
|
17,505
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
60,488
|
|
Deferred deductible temporary differences
|
|
9,420
|
|
|
1,170
|
|
|
—
|
|
|
—
|
|
|
10,590
|
|
|||||
Charitable Contributions
|
|
—
|
|
|
5,052
|
|
|
—
|
|
|
—
|
|
|
5,052
|
|
|||||
AMT Credit
|
|
—
|
|
|
166,798
|
|
|
—
|
|
|
—
|
|
|
166,798
|
|
|||||
Foreign Tax Credits
|
|
25,903
|
|
|
13,947
|
|
|
—
|
|
|
—
|
|
|
39,850
|
|
|||||
Total
|
|
$
|
78,306
|
|
|
$
|
204,472
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
282,778
|
|
Name of Recipient:
|
Nicholas DeIuliis
|
|
Award Date:
|
January 30, 2019
|
|
Number of Shares Subject to Award:
|
_________ shares of the Company’s common stock
|
|
Vesting Schedule:
|
Except as otherwise provided in the Terms and Conditions attached to this Letter, three (3) successive equal annual installments upon your completion of each year of continuous employment with the Company and its Affiliates (as such term is defined in the Plan) over the three (3)-year period measured from the Award Date.
|
|
Issuance Schedule:
|
The shares which vest each year under your restricted stock units will be issued to you on the vesting date or if the vesting date is not a business day, on the immediately following business day (or as soon as reasonably practicable but in no event later than the 15th day of the third month following such date), subject to your satisfaction of all applicable income and employment withholding taxes.
|
Name of Recipient:
|
______________________________________________________
|
|
Award Date:
|
__________________ ____, 20____
|
|
Number of Shares Subject to Award:
|
_________ shares of the Company’s common stock
|
|
Vesting Schedule:
|
Except as otherwise provided in the Terms and Conditions attached to this Letter, three (3) successive equal annual installments upon your completion of each year of continuous employment with the Company and its Affiliates (as such term is defined in the Plan) over the three (3)-year period measured from the Award Date.
|
|
Issuance Schedule:
|
The shares which vest each year under your restricted stock units will be issued to you on the vesting date or if the vesting date is not a business day, on the immediately following business day (or as soon as reasonably practicable but in no event later than the 15th day of the third month following such date), subject to your satisfaction of all applicable income and employment withholding taxes.
|
Name of Recipient:
|
______________________________________________________
|
|
Award Date:
|
__________________ ____, 20____
|
|
Number of Shares Subject to Award:
|
_________ shares of the Company’s common stock
|
|
Vesting Schedule:
|
Except as otherwise provided in the Terms and Conditions attached to this Letter, three (3) successive equal annual installments upon your completion of each year of continuous employment with the Company and its Affiliates (as such term is defined in the Plan) over the three (3)-year period measured from the Award Date.
|
|
Issuance Schedule:
|
The shares which vest each year under your restricted stock units will be issued to you on the vesting date or if the vesting date is not a business day, on the immediately following business day (or as soon as reasonably practicable but in no event later than the 15th day of the third month following such date), subject to your satisfaction of all applicable income and employment withholding taxes.
|
Cardinal States Gathering Company (a Virginia general partnership)
|
CNX Gas Company LLC (a Virginia limited liability company)
|
CNX Gas LLC (a Delaware limited liability company)
|
CNX Land LLC (a Delaware limited liability company)
|
CNX Resource Holdings LLC (a Delaware limited liability company)
|
CNX Water Assets LLC (formerly CONSOL of WV LLC) (d/b/a CONVEY Water Systems) (a West Virginia limited liability Company)
|
Mon-View, LLC (a West Virginia limited liability company)
|
Pocahontas Gas LLC (a Delaware limited liability company)
|
|
CNX MIDSTREAM RELATED SUBSIDIARIES
|
CNX Gathering LLC (a Delaware limited liability company)
|
CNX Midstream GP LLC (a Delaware limited liability company)
|
CNX Midstream Partners LP (a Delaware limited liability company)
|
CNX Midstream Finance Corp. (a Delaware limited liability company)
|
CNX Midstream Operating Company LLC (a Delaware limited liability company)
|
CNX Midstream DevCo I GP LLC (a Delaware limited liability company)
|
CNX Midstream DevCo I LP (a Delaware limited liability company)
|
CNX Midstream DevCo III GP LLC (a Delaware limited liability company)
|
CNX Midstream DevCo III LP (a Delaware limited liability company)
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
By:
|
/s/ DANNY D. SIMMONS, P.E.
|
|
Danny D. Simmons, P.E.
|
|
President and Chief Operating Officer
|
1.
|
I have reviewed this Annual Report on Form 10-K of CNX Resources Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 7, 2019
|
|
|
|
|
/s/ Nicholas J. DeIuliis
|
|
|
Nicholas J. DeIuliis
|
|
|
Director, Chief Executive Officer and President
|
|
|
(Principal Executive Officer)
|
|
1.
|
I have reviewed this Annual Report on Form 10-K of CNX Resources Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information;
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 7, 2019
|
|
|
|
|
/s/ Donald W. Rush
|
|
|
Donald W. Rush
|
|
|
Chief Financial Officer and Executive Vice President
(Principal Financial Officer)
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.
|
Date:
|
February 7, 2019
|
|
|
|
|
/s/ Nicholas J. DeIuliis
|
|
|
Nicholas J. DeIuliis
|
|
|
Director, Chief Executive Officer and President
|
|
|
(Principal Executive Officer)
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.
|
Date:
|
February 7, 2019
|
|
|
|
|
/s/ Donald W. Rush
|
|
|
Donald W. Rush
|
|
|
Chief Financial Officer and Executive Vice President
(Principal Financial Officer)
|
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
|||||||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
|
|
Present Worth
|
|||||
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
|||||
Proved Developed Producing
|
|
1,861.9
|
|
|
40,179.9
|
|
|
4,147,598.8
|
|
|
10,099,395.3
|
|
|
3,830,561.6
|
|
Proved Developed Non-Producing
|
|
8.1
|
|
|
—
|
|
|
94,980.5
|
|
|
261,331.1
|
|
|
131,797.0
|
|
Proved Undeveloped
|
|
6,391.2
|
|
|
25,724.9
|
|
|
3,193,759.0
|
|
|
6,918,801.9
|
|
|
2,208,825.1
|
|
Total Proved
|
|
8,261.3
|
|
|
65,904.8
|
|
|
7,436,338.2
|
|
|
17,279,526.9
|
|
|
6,171,184.6
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
|
Texas Registered Engineering Firm F-2699
|
|
|
|
|
|
|
|
|
|
By:
|
/s/ C.H. (Scott) Rees III
|
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
|
Chairman and Chief Executive Officer
|
|
|
|
|
|
By:
|
/s/ Richard B. Talley, Jr.
|
|
By:
|
/s/ Edward C. Roy III
|
|
Richard B. Talley, Jr., P.E. 102425
|
|
|
Edward C. Roy III, P.G. 2364
|
|
Senior Vice President
|
|
|
Vice President
|
|
|
|
|
|
Date Signed: January 31, 2019
|
|
Date Signed: January 31, 2019
|
||
|
|
|
|
|
RBT:LNH
|
|
|
|
SUMMARY OF NET RESERVES AND FUTURE REVENUE
|
|||||||||||||||||||||||||||
CNX RESOURCES CORPORATION INTEREST
|
|||||||||||||||||||||||||||
AS OF DECEMBER 31, 2018
|
|||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
|
|
|
|
|
|||||||||
|
|
Net Reserves
|
|
Future
|
|
Operating
|
|
|
|
Including
|
|
Future Net Revenue (M$)
|
|||||||||||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
Gross Revenue
|
|
Expense
|
|
Taxes
|
|
Abandonment
|
|
|
|
Discounted
|
|||||||||
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
Total
|
|
At 10%
|
|||||||||
Proved Developed Producing
|
|
1,861.9
|
|
|
40,179.9
|
|
|
4,147,598.8
|
|
|
15,448,552.4
|
|
|
4,098,522.6
|
|
|
354,090.6
|
|
|
133,248.9
|
|
|
10,862,693.4
|
|
|
4,459,086.3
|
|
Other Revenue and Costs (1)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(742,387.5
|
)
|
|
20,910.5
|
|
|
—
|
|
|
—
|
|
|
(763,298.0
|
)
|
|
(628,524.8
|
)
|
Total Proved Developed Producing
|
|
1,861.9
|
|
|
40,179.9
|
|
|
4,147,598.8
|
|
|
14,706,164.9
|
|
|
4,119,433.1
|
|
|
354,090.6
|
|
|
133,248.9
|
|
|
10,099,395.3
|
|
|
3,830,561.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Proved Developed Non-Producing
|
|
8.1
|
|
|
—
|
|
|
94,980.5
|
|
|
323,376.3
|
|
|
58,578.9
|
|
|
2,377.5
|
|
|
1,088.9
|
|
|
261,331.1
|
|
|
131,797.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Proved Undeveloped
|
|
6,391.2
|
|
|
25,724.9
|
|
|
3,193,759.0
|
|
|
11,580,561.4
|
|
|
2,836,814.3
|
|
|
359,156.1
|
|
|
1,465,790.2
|
|
|
6,918,801.9
|
|
|
2,208,825.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Total Proved
|
|
8,261.3
|
|
|
65,904.8
|
|
|
7,436,338.2
|
|
|
26,610,100.2
|
|
|
7,014,827.0
|
|
|
715,624.2
|
|
|
1,600,128.0
|
|
|
17,279,526.9
|
|
|
6,171,184.6
|
|