2016 Annual Report
Directors and New Director Nominees
Alvin R. Carpenter
J. Palmer Clarkson*
William E. Davis
(cid:3)
(cid:49)(cid:76)(cid:70)(cid:75)(cid:82)(cid:79)(cid:68)(cid:86)(cid:3)(cid:45)(cid:17)(cid:3)(cid:39)(cid:72)(cid:44)(cid:88)(cid:79)(cid:76)(cid:76)(cid:86)
Maureen E. Lally-Green
Gregory A. Lanham
Bernard Lanigan, Jr.
John T. Mills
Joseph P. Platt
William P. Powell
Edwin S. Roberson
William N. Thorndike, Jr.
* Denotes a new nominee for election to the Board at the May 9, 2017 Annual Meeting of Shareholders.
Executive Officers
Nicholas J. DeIuliis
President and Chief Executive Officer
David M. Khani
Executive Vice President and Chief Financial Officer
Stephen W. Johnson
Executive Vice President and Chief Administrative Officer
James A. Brock
Executive Vice President and Chief Operating Officer – Coal
Timothy C. Dugan
Executive Vice President and Chief Operating Officer – Exploration and Production
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________________________________
FORM 10-K
__________________________________________________
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
For the fiscal year ended December 31, 2016
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 001-14901
__________________________________________________
CONSOL Energy Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
51-0337383
(I.R.S. Employer
Identification No.)
1000 CONSOL Energy Drive
Canonsburg, PA 15317-6506
(724) 485-4000
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
__________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock ($.01 par value)
Preferred Share Purchase Rights
Name of exchange on which registered
New York Stock Exchange
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
__________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for
such shorter period that the registrant was required to submit and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not
be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-
K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
(Check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller Reporting Company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
No
The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 2016, the last business day of the registrant's
most recently completed second fiscal quarter, based on the closing price of the common stock on the New York Stock Exchange on such date was
$1,829,987,445.
The number of shares outstanding of the registrant's common stock as of January 20, 2017 is 229,443,008 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of CONSOL Energy's Proxy Statement for the Annual Meeting of Shareholders to be held on May 9, 2017, are incorporated by reference in
Items 10, 11, 12, 13 and 14 of Part III.
TABLE OF CONTENTS
PART I
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety and Health Administration Safety Data
PART II
Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases
of Equity Securities
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
Controls and Procedures
Other Information
Directors and Executive Officers of the Registrant
Executive Compensation
PART III
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Certain Relationships and Related Transactions and Director Independence
Principal Accounting Fees and Services
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
ITEM 15.
Exhibits and Financial Statement Schedules
SIGNATURES
PART IV
Page
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28
48
48
48
48
49
51
53
98
100
174
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177
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177
177
178
186
2
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are certain terms and abbreviations commonly used in the oil and gas industry and included within this
Form 10-K:
Bbl - One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf - One billion cubic feet of natural gas.
Bcfe - One billion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
Btu - One British Thermal unit.
Mbbls - One thousand barrels of oil or other liquid hydrocarbons.
Mcf - One thousand cubic feet of natural gas.
Mcfe - One thousand cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
MMbtu - One million British Thermal units.
MMcfe - One million cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
NGL - Natural gas liquids - those hydrocarbons in natural gas that are separated from the gas as liquids through the proces.
net - “net” natural gas or “net” acres are determined by adding the fractional ownership working interests the Company has in
gross wells or acres.
proved reserves - quantities of oil, natural gas, and NGLs which, by analysis of geological and engineering data, can be estimated
with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to
operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic
methods are used for the estimation.
proved developed reserves - proved reserves which can be expected to be recovered through existing wells with existing equipment
and operating methods.
proved undeveloped reserves (PUDs) - proved reserves that can be estimated with reasonable certainty to be recovered from
new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
reservoir - a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or
oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Tcfe - One trillion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
3
FORWARD-LOOKING STATEMENTS
We are including the following cautionary statement in this Annual Report on Form 10-K to make applicable and take
advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of us. With the exception of historical matters, the matters discussed in this Annual Report on Form 10-K
are forward-looking statements (as defined in Section 21E of the Exchange Act) that involve risks and uncertainties that could
cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-
looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates
concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When
we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,”
"will," or their negatives, or other similar expressions, the statements which include those words are usually forward-looking
statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-
looking statements in this Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; we disclaim
any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We
have based these forward-looking statements on our current expectations and assumptions about future events. While our
management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business,
economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many
of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
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deterioration in economic conditions in any of the industries in which our customers operate may decrease demand for
our products, impair our ability to collect customer receivables and impair our ability to access capital;
prices for natural gas, natural gas liquids and coal are volatile and can fluctuate widely based upon a number of factors
beyond our control including oversupply relative to the demand available for our products, weather and the price and
availability of alternative fuels;
an extended decline in the prices we receive for our natural gas, natural gas liquids and coal affecting our operating
results and cash flows;
foreign currency fluctuations could adversely affect the competitiveness of our coal and natural gas liquids abroad;
our customers extending existing contracts or entering into new long-term contracts for coal on favorable terms;
our reliance on major customers;
our inability to collect payments from customers if their creditworthiness declines or if they fail to honor their contracts;
the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our natural
gas, natural gas liquids and coal to market;
a loss of our competitive position because of the competitive nature of the natural gas and coal industries, or a loss of our
competitive position because of overcapacity in these industries impairing our profitability;
coal users switching to other fuels in order to comply with various environmental standards related to coal combustion
emissions;
the impact of potential, as well as any adopted environmental regulations including any relating to greenhouse gas
emissions on our operating costs as well as on the market for natural gas and coal and for our securities;
the risks inherent in natural gas and coal operations, including our reliance upon third party contractors, being subject to
unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant
construction or repair of equipment, fires, explosions, accidents and weather conditions which could impact financial
results;
decreases in the availability of, or increases in, the price of commodities or capital equipment used in our coal mining
and natural gas operations;
obtaining and renewing governmental permits and approvals for our natural gas and coal operations;
the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous
substances and wastes generated during our natural gas and coal operations;
our ability to find adequate water sources for our use in natural gas drilling, or our ability to dispose of water used or
removed from strata in connection with our gas operations at a reasonable cost and within applicable environmental rules;
the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut
down our operations;
the potential for liabilities arising from environmental contamination or alleged environmental contamination in
connection with our past or current gas and coal operations;
the effects of mine closing, reclamation, gas well closing and certain other liabilities;
uncertainties in estimating our economically recoverable natural gas, oil and coal reserves;
defects may exist in our chain of title and we may incur additional costs associated with perfecting title for natural gas
rights on some of our properties or failing to acquire these additional rights may result in a reduction of our estimated
reserves;
4
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the outcomes of various legal proceedings, including those which are more fully described in our reports filed under the
Securities Exchange Act of 1934;
exposure to employee-related long-term liabilities;
divestitures and acquisitions we anticipate may not occur or produce anticipated benefits;
joint ventures that we are party to now or in the future may restrict our flexibility, actions taken by our joint ventures may
impact our financial position and operational results;
risks associated with our debt;
replacing our natural gas and oil reserves, which if not replaced, will cause our natural gas and oil reserves and production
to decline;
declines in our borrowing base could occur for a variety of reasons, including lower natural gas or oil prices, declines in
natural gas and oil proved reserves, and lending regulations requirements or regulations;
our hedging activities may prevent us from benefiting from near-term price increases and may expose us to other risks;
changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs,
could cause our financial position and profitability to deteriorate;
failure to appropriately allocate capital and other resources among our strategic opportunities may adversely affect our
financial condition;
failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its obligations under various
arrangements, which we guaranteed, could materially or adversely affect our results of operations, financial position, and
cash flows;
information theft, data corruption, operational disruption and/or financial loss resulting from a terrorist attack or cyber
incident;
operating in a single geographic area;
certain provisions in our multi-year coal sales contracts may provide limited protection during adverse economic
conditions, and may result in economic penalties or permit the customer to terminate the contract;
the majority of our common units in CNX Coal Resources LP and CONE Midstream Partners LP are subordinated, and
we may not receive distributions from CNX Coal Resources LP or CONE Midstream Partners LP;
• with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC, any disruption
to our business, including customer, employee and supplier relationships resulting from this transaction, and the impact
of the transaction on our future operating results;
there is no assurance that the potential drop-downs,spin-off or sale of the coal business will occur, or if it does occur that
we will be able to negotiate favorable terms;
•
• with respect to the termination of the joint venture with NOBLE, any disruption to our business, including customer and
supplier relationships from this transaction, and the impact of the transaction on our future operating and financial results
and liquidity; and
other factors discussed in this 2016 Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which
are on file at the Securities and Exchange Commission.
•
5
ITEM 1.
Business
General
PART I
CONSOL Energy Inc., (CONSOL Energy or the Company) is an integrated energy company operated through two primary
divisions, oil and natural gas exploration and production (E&P) and Pennsylvania (PA) Mining Operations. The E&P division is
focused on Appalachian area natural gas and liquids activities, including production, gathering, processing and acquisition of
natural gas properties in the Appalachian Basin. The PA Mining Operations division is focused on the extraction and preparation
of coal, also in the Appalachian Basin.
CONSOL Energy was incorporated in Delaware in 1991, but its predecessors had been mining coal, primarily in the
Appalachian Basin, since 1864. CONSOL Energy entered the natural gas business in the 1980s initially to increase the safety and
efficiency of our coal mines by capturing methane from coal seams prior to mining, which makes the mining process safer and
more efficient. Over the past ten years, CONSOL Energy's natural gas business has grown by approximately 617% to produce
394.4 net Bcfe in 2016. This business has grown from coalbed methane production in Virginia into other unconventional production,
including hydraulic fracturing in the Marcellus Shale and Utica Shale, in the Appalachian Basin. This growth was accelerated with
the 2010 asset acquisition of the Appalachian Exploration & Production business of Dominion Resources, Inc. Subsequently, on
December 5, 2013, we sold Consolidation Coal Company and certain subsidiaries, including five active coal mines in West Virginia.
Our E&P division operates, develops and explores for natural gas primarily in Appalachia (Pennsylvania, West Virginia,
Ohio, Virginia and Tennessee). Currently, our primary focus is the continued development of our Marcellus Shale acreage and the
delineation and development of our Utica Shale acreage. We believe that our concentrated operating area, our legacy surface
acreage position, our regional operating expertise, our extensive data set from development, joint ventures, non-operated
participation wells, our held by production acreage position and our ability to coordinate gas drilling with coal mining activity
gives us a significant operating advantage over our competitors.
Our land holdings in the Marcellus Shale and Utica Shale plays cover large areas, provide multi-year drilling opportunities
and, collectively, have sustainable lower risk growth profiles. We currently control approximately 413,000 net acres in the Marcellus
Shale and approximately 683,000 net acres that have Utica Shale potential in Ohio, West Virginia, and Pennsylvania. We also have
approximately 2.2 million net acres in our coalbed methane play.
Highlights of our 2016 production include the following:
• Total average production of 1,080,512 Mcfe per day, an increase of 20% over 2015;
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88% Natural Gas, 12% Liquids; and
54% Marcellus, 23% Utica, 17% coalbed methane, and 6% other.
At December 31, 2016, our proved natural gas, NGL, condensate and oil reserves (collectively, "natural gas reserves") had
the following characteristics:
6.3 Tcfe of proved reserves;
93.2% natural gas;
58.9% proved developed;
87.6% operated; and
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• A reserve life ratio of 15.85 years (based on 2016 production).
Highlights of coal activities in 2016 include the following:
•
Production of 24.6 million tons of coal;
• Coal reserve holdings of 2.4 billion tons; and
75% of coal sales to domestic utilities.
•
Additionally, we provide energy services, including coal terminal services (the Baltimore Terminal), water services and land
resource management services.
6
The following map provides the location of CONSOL Energy's E&P and coal operations by region:
E&P and COAL OPERATIONS
TM
CPA GAS OPERATIONS
OH GAS OPERATIONS
CANONSBURG
ENLOW FORK
BAILEY HARVEY
SW PA GAS OPERATIONS
WV GAS OPERATIONS
PHILADELPHIA
BALTIMORE TERMINCAL
VA GAS OPERATIONS
LEGEND
GENERAL OFFICE
COAL OPERATIONS
SALES OFFICE
E&P OPERATIONS
PORT/DOCK
Copyright 2017 CONSOL Energy, Inc.
CONSOL Energy defines itself through its core values which are:
Safety,
•
• Compliance, and
• Continuous Improvement.
These values are the foundation of CONSOL Energy's identity and are the basis for how management defines continued
success. We believe CONSOL Energy's rich resource base, coupled with these core values, allows management to create value
for the long-term. The electric power industry generates approximately two-thirds of its output by burning natural gas or coal, the
two fuels we produce. We believe that the use of natural gas and coal will continue for many years as the principal fuel sources
for electricity in the United States. Additionally, we believe that as worldwide economies grow, the demand for electricity from
fossil fuels will grow as well, resulting in expansion of worldwide demand for our coal and potentially for our natural gas.
CONSOL Energy's Strategy
CONSOL Energy's strategy is to increase shareholder value through the development and growth of its existing natural gas
assets, selective acquisition of natural gas and natural gas liquid acreage leases within its footprint, and through the participation
in global coal markets. Ultimately, we intend to separate our E&P division and our PA Mining Operations division and to focus
on the growth of our E&P division. We also will continue to focus on monetization of assets to accelerate value creation and to
minimize the shortfall between operating cash flows and our growth capital requirements.
We expect natural gas to become a more significant contributor to the domestic electric generation mix, as well as fueling
industrial growth in the U.S. economy. With the recent growth of natural gas exports to Mexico and Canada and the United States
becoming a net exporter of natural gas in 2016, we expect new markets to open up in the coming years. We feel that our significant
increases in natural gas production, our reductions in drilling and operating costs and our vast acreage position will allow CONSOL
Energy to take advantage of these markets.
7
CONSOL Energy’s coal assets align with the PA Mining Operations division's long-term strategic objectives. The production,
which include the Bailey, Enlow Fork, and Harvey mines, can be sold domestically or abroad, as either thermal coal or high volatile
metallurgical coal. These low-cost mines, with five longwalls, produce a high-Btu Pittsburgh-seam coal that is lower in sulfur than
many Northern Appalachian coals.
These mines, along with our 100%-owned Baltimore Terminal, will continue to allow CONSOL Energy to participate in the
world’s thermal and metallurgical coal markets. The ability to serve both domestic and international markets with premium thermal
and metallurgical coal provides tremendous optionality.
CONSOL Energy's E&P Capital Expenditure Budget
In 2017, the E&P division expects capital expenditures of approximately $555 million. The E&P division capital expenditures
are comprised of the following: $465 million for drilling and completion activity; $40 million for midstream, including capital
contributions to CONE Midstream Partners, LP; and $50 million for other activities related to land, permitting, and business
development.
DETAIL E&P OPERATIONS
Our E&P operations are located throughout Appalachia and include the following plays:
Marcellus Shale
We have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 413,000 net Marcellus
Shale acres at December 31, 2016.
The Upper Devonian Shale formation, which includes both the Burkett Shale and Rhinestreet Shale, lies above the Marcellus
Shale formation in southwestern Pennsylvania and northern West Virginia. The company holds a large number of acres that have
Upper Devonian potential; these acres have not been disclosed separately as they coincide with our Marcellus acreage.
In December 2016, CONSOL Energy terminated the 50-50 Joint Venture that was formed in 2011, with Noble Energy, Inc.,
for the exploration, development, and operation of primarily Marcellus Shale properties in Pennsylvania and West Virginia. As a
result of the termination, each party now owns and operates a 100% interest in its properties and wells in two separate operating
areas; and each party will now have independent control and flexibility with respect to the scope and timing of future development
over its operating area.
We also hold a 50% interest in an entity that constructs and operates the gathering system for most of our Marcellus shale
production. As of September 30, 2011, we contributed our existing Marcellus Shale gathering assets to this company. In September
of 2014, the majority of these assets were contributed to CONE Midstream Partners LP. See "Midstream Gas Services" for a more
detailed explanation.
Utica Shale
We have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 683,000 net Utica
Shale acres at December 31, 2016. Approximately 305,000 Utica acres coincide with Marcellus Shale acreage in Pennsylvania,
West Virginia, and Ohio.
Coalbed Methane (CBM)
We have the rights to extract CBM in Virginia from approximately 268,000 net CBM acres, which cover a portion of our
coal reserves in Central Appalachia. We produce CBM natural gas primarily from the Pocahontas #3 seam.
We also have the rights to extract CBM in West Virginia, southwestern Pennsylvania, and Ohio from approximately 912,000
net CBM acres. In central Pennsylvania we have the right to extract CBM from approximately 260,000 net CBM acres. In addition,
we control approximately 584,000 net CBM acres in Illinois, Kentucky, Indiana, and Tennessee. We also have the right to extract
CBM on approximately139,000 net acres in the San Juan Basin in New Mexico. We have no plans to drill CBM wells in these
areas in 2017.
8
Other Gas
Shallow Oil and Gas
We have the rights to extract natural gas from shallow oil and gas positions in Illinois, Indiana, Kentucky, Pennsylvania,
West Virginia, Virginia and New York from approximately 766,000 net acres at December 31, 2016. The majority of our shallow
oil and gas leasehold position is held by production and all of it is extensively overlain by existing third-party gas gathering and
transmission infrastructure.
Chattanooga
We have the rights to extract natural gas in Tennessee from approximately 95,000 net Chattanooga Shale acres at December 31,
2016.
Huron
We have approximately 503,000 net acres of Huron Shale potential in Kentucky, West Virginia, and Virginia; a portion of
this acreage has tight sands potential.
Summary of Properties as of December 31, 2016
Estimated Net Proved Reserves (MMcfe)
Percent Developed
Net Producing Wells (including oil and gob
wells)
Net Acreage Position:
Net Proved Developed Acres
Net Proved Undeveloped Acres
Net Unproved Acres(1)
Total Net Acres(2)
_________
Marcellus
Segment
3,137,336
Utica
Segment
CBM
Segment
Other Gas
Segment
Total
1,371,978
1,254,633
487,701
6,251,648
60%
283
30,737
11,763
370,263
412,763
28%
54
75%
100%
59%
4,359
8,180
12,876
9,649
12,836
355,332
377,817
257,019
5,439
1,900,260
2,162,718
243,877
—
1,119,678
1,363,555
541,282
30,038
3,745,533
4,316,853
(1) Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or
decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties
in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable. See Risk
Factors in Section 1A of this Form 10-K.
(2) Acreage amounts are only included under the target strata CONSOL Energy expects to produce with the exception of certain
CBM acres governed by separate leases, although the reported acres may include rights to multiple gas seams (e.g. we have
rights to Marcellus segment that are disclosed under the Utica segment and we have rights to Utica segment that are disclosed
under the Marcellus segment). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect
the acres in the strata we expect to primarily produce. As more information is obtained or circumstances change, the acreage
classification may change.
Producing Wells and Acreage
Most of our development wells and proved acreage are located in Virginia, West Virginia and Pennsylvania. Some leases
are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments
or other term commitments are satisfied.
9
The following table sets forth, at December 31, 2016, the number of producing wells, developed acreage and undeveloped
acreage:
Producing Gas Wells (including gob wells)
Producing Oil Wells
Net Acreage Position:
Proved Developed Acreage
Proved Undeveloped Acreage
Unproved Acreage
Total Acreage
Gross
Net(1)
17,314
189
12,846
30
549,816
34,467
4,804,804
5,389,087
541,282
30,038
3,745,533
4,316,853
(1) Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases
or decreases) may be required as we further develop title to and further confirm our rights with respect to our various
properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
See Risk Factors in Section 1A of this Form 10-K.
The following table represents the terms under which we hold these acres:
Held by production/fee
Expiration within 2 years
Expiration beyond 2 years
Total Acreage
Net Unproved
Acres
Net Proved
Undeveloped Acres
3,644,799
68,084
32,650
3,745,533
13,967
9,347
6,724
30,038
The leases reflected above as Net Unproved Acres with expiration dates are included in our current drill plan or active land
program. Leases with expiration dates within two years represent approximately 2% of our total acres in the above categories and
leases with expiration dates beyond two years represent approximately 1% of our total acres in the above categories. In each case,
we deemed this acreage to not be material to our overall acreage position. Additionally, based on our current drill plans and lease
management we do not anticipate any material impact to our consolidated financial statements from the expiration of such leases.
Development Wells (Net)
During the years ended December 31, 2016, 2015 and 2014, we drilled 36.0, 132.8 and 180.3 net development wells,
respectively. Gob wells and wells drilled by operators other than our primary joint venture partners at that time, Noble Energy and
Hess Corporation, are excluded from net development wells. In 2016, there were 68 gross development wells drilled but
uncompleted. There were no dry development wells in 2016, 2015, or 2014. As of December 31, 2016, there are 3.0 gross completed
developmental wells ready to be turned in-line. The following table illustrates the net wells drilled by well classification type:
For the Year
Ended December 31,
2016
2015
2014
—
13.0
23.0
—
36.0
44.0
15.8
73.0
—
84.0
18.8
75.0
2.5
132.8
180.3
Marcellus segment
Utica segment
CBM segment
Other Gas segment
Total Development Wells (Net)
10
Exploratory Wells (Net)
There were no exploratory wells drilled during the year ended December 31, 2016. During the years ended December 31,
2015 and 2014, we drilled, in the aggregate, 2.5, and 8.5 net exploratory wells, respectively. As of December 31, 2016, there are
no net exploratory wells in process. The following table illustrates the exploratory wells drilled by well classification type:
For the Year Ended December 31,
2016
2015
2014
Producing Dry
Still Eval.
Producing Dry
Still Eval.
Producing Dry
Still Eval.
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— —
2.5 —
— —
— —
2.5 —
—
—
—
—
—
1.5
1.0
—
—
— —
6.0
8.5
—
—
—
—
—
—
—
Marcellus segment
Utica segment
CBM segment
Other Gas segment
Total Exploratory Wells (Net)
Reserves
The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of
royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under
current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves
are defined by the Securities and Exchange Commission (SEC).
Proved developed reserves
Proved undeveloped reserves
Total proved developed and undeveloped reserves(1)
Net Reserves
(Million cubic feet equivalent)
as of December 31,
2016
2015
2014
3,683,302
3,697,152
3,198,706
2,568,346
1,945,837
3,628,910
6,251,648
5,642,989
6,827,616
___________
(1)
For additional information on our reserves, see Other Supplemental Information–Supplemental Gas Data (unaudited) to the
Consolidated Financial Statements in Item 8 of this Form 10-K.
Discounted Future Net Cash Flows
The following table shows our estimated future net cash flows and total standardized measure of discounted future net cash
flows at 10%:
Discounted Future
Net Cash Flows
(Dollars in millions)
2015
2016
2014
Future net cash flows
Total PV-10 measure of pre-tax discounted future net cash flows (1)
Total standardized measure of after tax discounted future net cash flows
$ 2,419
$ 1,559
$ 2,499
$ 1,659
$ 9,321
$ 4,884
$
955
$ 1,019
$ 2,984
____________
(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
11
standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP
measure-after-tax discounted future net cash flows.
Reconciliation of PV-10 to Standardized Measure
2016
As of December 31,
2015
(Dollars in millions)
2014
Future cash inflows
Future production costs
Future development costs (including abandonments)
Future net cash flows (pre-tax)
10% discount factor
PV-10 (Non-GAAP measure)
Undiscounted income taxes
10% discount factor
Discounted income taxes
Standardized GAAP measure
Gas Production
The following table sets forth net sales volumes produced for the periods indicated:
GAS
Marcellus Sales Volumes (MMcf)
Utica Sales Volumes (MMcf)
CBM Sales Volumes (MMcf)
Other Sales Volumes (MMcf)
LIQUIDS*
NGLs Sales Volumes (MMcfe)
Oil Sales Volumes (MMcfe)
Condensate Sales Volumes (MMcfe)
TOTAL (MMcfe)
$ 11,303
(5,851)
(1,550)
3,902
(2,343)
1,559
(1,483)
879
(604)
955
$
$ 11,838
(6,585)
(1,220)
4,033
(2,374)
1,659
(1,534)
894
(640)
1,019
$
$ 28,503
(10,101)
(3,369)
15,033
(10,149)
4,884
(5,712)
3,812
(1,900)
2,984
$
For the Year
Ended December 31,
2016
2015
2014
186,812
145,747
71,277
68,971
21,693
38,344
74,910
28,286
99,370
10,303
79,459
27,128
40,260
33,180
15,475
410
4,964
592
7,598
681
3,298
394,387
328,657
235,714
*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy
content of oil and natural gas.
CONSOL Energy expects 2017 annual gas production to grow to approximately 415 Bcfe and increase to approximately
485 Bcfe in 2018.
Average Sales Price and Average Lifting Cost
The following table sets forth the total average sales price and the total average lifting cost for all of our natural gas and
liquids production for the periods indicated, including intersegment transactions. Total lifting cost is the cost of raising gas to the
gathering system and does not include depreciation, depletion or amortization. See Part II Item 7 Management's Discussion and
Analysis of Financial Condition and Results of Operations in this Form 10-K for a breakdown by segment.
12
Average Sales Price - Gas (Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Average Sales Price - NGLs (Mcfe)*
Average Sales Price - Oil (Mcfe)*
Average Sales Price - Condensate (Mcfe)*
Total Average Sales Price (per Mcfe)
Average Lifting Costs excluding ad valorem and severance taxes (per Mcfe)
For the Year
Ended December 31,
2014
2015
2016
$ 1.92
$ 0.70
$ 2.42
$ 6.15
$ 4.58
$ 2.17
$ 0.68
$ 2.05
$ 7.99
$ 4.42
$ 4.02
$ 0.11
$ 5.95
$ 14.85
$ 11.16
$ 2.63
$ 0.24
$ 2.81
$ 0.37
$ 4.37
$ 0.59
*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy
content of oil and natural gas.
Sales of NGLs, condensates, and oil enhance our reported natural gas equivalent sales price. Across all volumes, when
excluding the impact of hedging, sales of liquids added $0.09 per Mcfe, $0.05 per Mcfe, and $0.25 per Mcfe for 2016, 2015, and
2014, respectively, to average gas sales prices. CONSOL Energy expects to continue to realize a liquids uplift benefit as additional
wells are brought online in the liquid-rich areas of the Marcellus and Utica shales. We continue to sell the majority of our NGLs
through the large midstream companies that process our natural gas. This approach allows us to take advantage of the processors’
transportation efficiencies and diversified markets. CONSOL Energy’s processing contracts provide for the ability to take our
NGLs “in kind” and market them directly if desired. The processed purity products are ultimately sold to industrial, commercial,
and petrochemical markets.
We enter into physical natural gas sales transactions with various counterparties for terms varying in length. Reserves and
production estimates are believed to be sufficient to satisfy these obligations. In the past, we have delivered quantities required
under these contracts. We also enter into various natural gas swap transactions. These gas swap transactions exist parallel to the
underlying physical transactions and represented approximately 264.9 Bcf of our produced gas sales volumes for the year ended
December 31, 2016 at an average price of $3.04 per Mcf. The notional volumes associated with these gas swaps represented
approximately 173.1 Bcf of our produced gas sales volumes for the year ended December 31, 2015 at an average price of $3.68
per Mcf. As of January 17, 2017, we expect these transactions will represent approximately 311.3 Bcf of our estimated 2017
production at an average price of $2.61 per Mcf, 220.6 Bcf of our estimated 2018 production at an average price of $2.75 per Mcf,
161.7 Bcf of our estimated 2019 production at an average price of $2.76 per Mcf, approximately 85 Bcf of our estimated 2020
production at an average price of $2.91 per Mcf, and approximately 6.8 Bcf of our estimated 2021 production at an average price
of $3.08 per Mcf.
The hedging strategy and information regarding derivative instruments used are outlined in Part II, Item 7A Qualitative and
Quantitative Disclosures About Market Risk and in Note 21 - Derivative Instruments in the Notes to the Audited Consolidated
Financial Statements in Item 8 of this Form 10-K.
Midstream Gas Services
CONSOL Energy has traditionally designed, built and operated natural gas gathering systems to move gas from the wellhead
to interstate pipelines or other local sales points. In addition, CONSOL Energy has acquired extensive gathering assets. CONSOL
Energy now owns or operates approximately 5,000 miles of natural gas gathering pipelines as well as 250,000 horsepower of
compression, of which, approximately 75% is wholly owned with the balance being leased. Along with this compression capacity,
CONSOL Energy owns and operates a number of natural gas processing facilities. This infrastructure is capable of delivering
approximately 750 billion cubic feet per year of pipeline quality gas.
CONSOL Energy owns 50% of CONE Gathering LLC ("CONE" or "CONE Gathering") along with Noble Energy owning
the other 50% interest. CONE Gathering develops, operates and owns substantially all of Noble Energy's and CONSOL Energy's
Marcellus Shale gathering systems. CONSOL Energy operates this equity affiliate. We believe that the network of right-of-ways,
vast surface holdings and experience in building and operating gathering systems in the Appalachian basin will give CONE
Gathering an advantage in building the midstream assets required to develop our Marcellus Shale position. On September 30,
2014, CONE Midstream Partners LP (the Partnership) closed its initial public offering. See Note 25 - Related Party Transactions
in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
13
In the Utica Shale, we and our joint venture partner, Hess, primarily contract with third-parties for gathering services.
CONSOL Energy has developed a diversified portfolio of firm transportation capacity options to support its production
growth plan. CONSOL Energy plans to selectively acquire as needed firm capacity while minimizing transportation costs and
long-term financial obligations and, in the near term if appropriate, plans to optimize and/or release firm transportation to others.
CONSOL Energy also benefits from the strategic location of our primary production areas in Southwest Pennsylvania, Northern
West Virginia, and Eastern Ohio. These areas are currently served by a large concentration of major pipelines that provide us with
the capacity to move our production to the major gas markets, and it is expected that recently-approved pipeline projects will
increase the take-away capacity from our region. In addition to firm transportation capacity, CONSOL Energy has developed a
processing portfolio to support the projected volumes from its wet production areas and has operational and contractual flexibility
to potentially convert a portion of currently processed wet gas volumes to be marketed as dry gas volumes.
CONSOL Energy has the advantage of having gas production from CBM, which can be lower Btu than pipeline specification,
as well as higher Btu Marcellus and Utica shale production. These types of gas can be complementary by reducing and in some
cases eliminating the need for the costly processing of CBM. In addition, our lower Btu CBM and dry Marcellus and Utica
production offer an opportunity to blend ethane back into the gas stream when pricing or capacity in ethane markets dictate. In
developing a diversified approach to managing ethane, CONSOL Energy has entered into ethane supply agreements and is also
discussing future outlet opportunities with ethane customers and midstream companies. These different gas types allow us more
flexibility in bringing Marcellus and Utica shale wells on-line at qualities that meet interstate pipeline specifications.
Natural Gas Competition
The United States natural gas industry is highly competitive. CONSOL Energy competes with other large producers, as well
as a myriad of smaller producers and marketers. CONSOL Energy also competes for pipeline and other services to deliver its
products to customers. According to data from the Natural Gas Supply Association and the Energy Information Agency (EIA), the
five largest U.S. producers of natural gas produced about 16% of dry natural gas production during the first nine months of 2016.
The EIA reported 554,201 producing natural gas wells in the United States at December 31, 2015 (the latest year for which
government statistics are available), which is approximately two percent lower than 2014.
CONSOL Energy expects natural gas to be a significant contributor to the domestic electric generation mix in the long-term,
as well as to fuel industrial growth in the U.S. economy. According to the EIA, based on preliminary results, natural gas represented
34% of U.S. electricity generation during 2016 compared with 33% in 2015. With the recent growth of natural gas exports to
Mexico and Canada and increased liquefied natural gas exports, the U.S. became a net exporter of gas in 2016. CONSOL expects
the high level of U.S. gas exports to continue in the future. In addition, there is potential for natural gas to become a significant
contributor to the transportation market. Our increasing gas production will allow CONSOL Energy to participate in these growing
markets.
CONSOL Energy's gas operations are primarily located in the eastern United States. The gas market is highly fragmented
and not dominated by any single producer. We believe that competition within our market is based primarily on natural gas
commodity trading fundamentals and pipeline transportation availability to the various markets.
Continued demand for CONSOL Energy's natural gas and the prices that CONSOL Energy obtains are affected by natural
gas use in the production of electricity, pipeline capacity, U.S. manufacturing and the overall strength of the economy, environmental
and government regulation, technological developments, the availability and price of competing alternative fuel supplies, and
national and regional supply/demand dynamics.
14
DETAIL COAL OPERATIONS
Coal Reserves
At December 31, 2016, CONSOL Energy had an estimated 2.4 billion tons of proven and probable coal reserves. Reserves
are the portion of the proven and probable tonnage that meet CONSOL Energy's economic criteria regarding mining height,
preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at
year-end price and cost levels.
Spacing of points of observation for confidence levels in reserve calculations is based on guidelines in U.S. Geological
Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). Our estimates for proved reserves have
the highest degree of geologic assurance. Estimates for proved reserves are based on points of observation that are equal to or less
than 0.5 miles apart. Estimates for probable reserves have a moderate degree of geologic assurance and are computed from points
of observation that are between 0.5 to 1.5 miles apart.
An exception is made concerning spacing of observation points with respect to our Pittsburgh coal seam reserves. Because
of the well-known continuity of this seam, spacing requirements are 3,000 feet or less for proved reserves and between 3,000 and
8,000 feet for probable reserves.
CONSOL Energy's estimates of proven and probable coal reserves do not rely on isolated points of observation. Small pods
of reserves based on a single observation point are not considered; continuity between observation points over a large area is
necessary for proved or probable reserves.
CONSOL Energy's proven and probable coal reserves fall within the range of commercially marketed coals in the United
States. The marketability of coal depends on its value-in-use for a particular application, and this is affected by coal quality, such
as sulfur content, ash and heating value. Modern power plant boiler design aspects can compensate for coal quality differences
that occur. Therefore, any of CONSOL Energy's coals can be marketed for the electric power generation industry. Additionally,
the growth in worldwide demand for metallurgical coal allows some of our proven and probable coal reserves, currently classified
as thermal coals, that possess certain qualities to be sold as metallurgical coal. The addition of this cross-over market adds additional
assurance to CONSOL Energy that all of its proven and probable coal reserves are commercially marketable.
CONSOL Energy assigns coal reserves to our mining complex. The amount of coal we assign to the mining complex generally
is sufficient to support mining through the duration of our current mining permit. Under federal law, we must renew our mining
permits every five years. All assigned reserves have their required permits or governmental approvals, or there is a high probability
that these approvals will be secured.
In addition, our mining complex may have access to additional reserves that have not yet been assigned. We refer to these
reserves as accessible. Accessible reserves are proven and probable coal reserves that can be accessed by an existing mining
complex, utilizing the existing infrastructure of the complex to mine and to process the coal in this area. Mining an accessible
reserve does not require additional capital spending beyond that required to extend or to continue the normal progression of the
mine, such as the sinking of airshafts or the construction of portal facilities.
Some reserves may be accessible by more than one mine because of the proximity of many of our mines to one another. In
the table below, the accessible reserves indicated for a mine are based on our review of current mining plans and reflect our best
judgment as to which mine is most likely to utilize the reserve.
Assigned and unassigned coal reserves are proven and probable coal reserves which are either owned or leased. The leases
have terms extending up to 30 years and generally provide for renewal through the anticipated life of the associated mine. These
renewals are exercisable by the payment of minimum royalties. Under current mining plans, assigned reserves reported will be
mined out within the period of existing leases or within the time period of probable lease renewal periods.
15
Mining Complexes
The following table provides the location of CONSOL Energy's active mining complexes and the coal reserves associated with each of the continuing operations.
Proven and Probable Assigned and Accessible Coal Reserves as of December 31, 2016 and 2015
CONSOL ENERGY MINING COMPLEXES
Preparation
Facility
Location
Reserve
Class
Coal
Seam
Average
Seam
Thickness
As Received Heat
Value(1)
(Btu/lb)
Recoverable
Reserves(2)
Owned
Leased
Tons in
Millions
(feet)
Typical
Range
(%)
(%)
12/31/2016
12/31/2015
Enon, PA
Enon, PA
Enon, PA
Assigned Operating
Accessible
Assigned Operating
Accessible
Assigned Operating
Accessible
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
7.5
7.5
6.3
7.6
7.8
7.6
12,950
12,910
13,040
12,900
12,980
13,040
12,860 – 13,030
12,700 – 13,170
12,920 – 13,160
12,840 – 13,130
12,820 – 13,190
12,780 – 13,180
43%
78%
86%
99%
99%
76%
57%
22%
14%
1%
1%
24%
89.0
170.7
20.4
180.1
31.2
275.3
766.7
101.1
170.7
23.4
180.1
10.9
305.3
791.5
Mine/Reserve
ASSIGNED–OPERATING
PA Mining Operations
Bailey
Harvey
Enlow Fork
Total Assigned Operating and
Accessible
16
_____________
(1)
The heat values shown for Assigned Operating reserves are based on the 2016 actual quality and five-year forecasted quality
for each mine/reserve, assuming that the coal is washed to an extent consistent with normal full-capacity operation of the
complex's preparation plant. Actual quality is based on laboratory analysis of samples collected from coal shipments
delivered in 2016. Forecasted quality is derived from exploration sample analysis results, which have been adjusted to
account for anticipated moisture and for the effects of mining and coal preparation. The heat values shown for Accessible
Reserves are based on as received, dry values obtained from drill hole analyses, adjusted for moisture, and prorated by the
associated Assigned Operating product values to account for similar mining and processing methods.
(2) Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average
density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not
be recovered during mining and for losses that occur if the coal is processed after mining. Reserves tons are reported on an
as-received basis, based on the anticipated product moisture. Reserves are reported only for those coal seams that are
controlled by ownership or leases.
The following table sets forth our unassigned proven and probable coal reserves by region:
CONSOL Energy UNASSIGNED Recoverable Coal Reserves as of December 31, 2016 and 2015
Recoverable Reserves(2)
As Received Heat Owned
Leased
Tons in
Millions
Recoverable
Reserves
(Tons in
Millions)
Coal Producing Region
Value(1) (Btu/lb)
(%)
(%)
12/31/2016
12/31/2015
Northern Appalachia (Pennsylvania, Ohio,
Northern West Virginia) (3)
Central Appalachia (Virginia, Southern West
Virginia)
Illinois Basin (Illinois, Western Kentucky,
Indiana)
Total
11,400 – 13,400
85%
12,400 – 14,100
77%
11,600 – 12,000
79%
83%
15%
23%
21%
17%
1,054.0
1,216.7
157.2
322.2
348.7
1,559.9
396.1
1,935.0
_______________
(1)
The heat value (gross calorific values) estimates for Northern Appalachian and Central Appalachian Unassigned coal reserves
include adjustments for moisture that may be added during mining or processing as well as for dilution by rock lying above
or below the coal seam. The heat value estimates for the Illinois Basin Unassigned reserves are based primarily on exploration
drill core data that may not include adjustments for moisture added during mining or processing, or for dilution by rock
lying above or below the coal seam.
(2) Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average
density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not
be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not
include adjustment for moisture that may be added during mining or processing, nor do the calculations include adjustments
for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams that are controlled
by ownership or leases.
140.8 Million tons of the Northern Appalachia leased tons are controlled by Consolidation Coal Company, a former
subsidiary of CONSOL Energy that was sold in December 2013. As of filing these tons are still controlled by Consolidation
Coal Company but are shown in CONSOL Energy's reserves due to a binding agreement that these tons will be released to
CONSOL Energy following the change in name of the Lease Holder.
(3)
17
The following table classifies CONSOL Energy coals by rank, projected sulfur dioxide emissions and heating value (British
thermal units per pound). The table also classifies bituminous coals as high, medium and low volatile which is based on fixed
carbon and volatile matter.
CONSOL Energy Proven and Probable Recoverable Coal Reserves
By Product (In Millions of Tons) as of December 31, 2016
S02/MMBtu
S02/MMBtu
> 2.50 lbs.
S02/MMBtu
Low
Btu
Med
Btu
High
Btu
Low
Btu
Med
Btu
High
Btu
Low
Btu
Med
Btu
High
Btu
Percent By
Total
Product
—
—
—
—
—
—
—
—
—
—
—
5.1
—
5.1
46.0
—
—
—
46.0
51.1
—
—
16.0
16.0
—
—
—
—
—
16.0
—
—
—
—
6.1
—
—
—
6.1
6.1
—
—
—
—
65.4
101.1
—
—
166.5
166.5
39.6
—
26.3
65.9
—
—
—
—
—
—
—
—
—
—
—
—
39.6
5.1
42.3
87.0
12.9
44.5
1,134.4
611.7
1,921.0
—
139.3
108.3
—
—
—
—
—
4.5
240.4
108.3
4.5
152.8
1,273.7
616.2
2,274.2
—
—
—
12.9
78.8
1.7%
0.2%
1.8%
3.7%
81.4%
10.3%
4.6%
0.2%
96.3%
152.8
1,273.7
616.2
2,361.2
100.0%
By Region
Metallurgical(1):
High Vol A Bituminous
Med Vol Bituminous
Low Vol Bituminous
Total Metallurgical
Thermal(1):
High Vol A Bituminous
High Vol B Bituminous
High Vol C Bituminous
Low Vol Bituminous
Total Thermal
Total
Percent of Total
—%
2.2%
0.7%
0.3%
7.1%
3.2%
6.5%
53.9%
26.1%
100.0%
_______________
(1)
143.3 Million tons for the Mason Dixon Project are controlled by Consolidation Coal Company, a former subsidiary of
CONSOL Energy that was sold in December 2013. As of this filing, these tons are still controlled by Consolidation Coal
Company but are shown in CONSOL Energy's reserves due to a binding agreement that these tons will be released to
CONSOL Energy upon consent of the lessor.
Title to coal properties that we lease or purchase and the boundaries of these properties are verified by law firms retained
by us at the time we lease or acquire the properties. Consistent with industry practice, abstracts and title reports are reviewed and
updated approximately five years prior to planned development or mining of the property. If defects in title or boundaries of
undeveloped reserves are discovered in the future, control of and the right to mine reserves could be adversely affected.
The following table sets forth, with respect to properties that we lease to other coal operators, the total royalty tonnage,
acreage leased and the amount of income (net of related expenses) we received from royalty payments for the years ended
December 31, 2016, 2015 and 2014.
Year
2016
2015
2014
Total
Royalty
Tonnage
(in thousands)
3,530
7,459
10,230
Total
Coal
Acreage
Leased
213,371
235,066
281,894
Total
Royalty
Income
(in thousands)
$9,684
$14,914
$18,460
Royalty tonnage leased to third parties is not included in the amounts of produced tons that we report. Proven and probable
reserves do not include reserves attributable to properties that we lease to third parties.
18
Production
In the year ended December 31, 2016, 100% of CONSOL Energy's production came from underground mines equipped
with longwall mining systems. CONSOL Energy employs longwall mining systems in our underground mines where the geology
is favorable and reserves are sufficient. Underground longwall systems are highly mechanized, capital intensive operations. Mines
using longwall systems have a low variable cost structure compared with other types of mines and can achieve high productivity
levels compared with those of other underground mining methods. Because CONSOL Energy has substantial reserves readily
suitable to these operations, CONSOL Energy believes that these longwall mines can increase capacity at a low incremental cost.
The following table shows the production from continuing operations, in millions of tons, for CONSOL Energy's mines for
the years ended December 31, 2016, 2015 and 2014, the location of each mine, the type of mine, the type of equipment used at
each mine, method of transportation and the year each mine was established or acquired by us.
Preparation
Tons Produced
Year
Facility
Mine
Mining
(in millions)
Established
Mine
Location
Type Equipment Transportation
2016
2015
2014
or Acquired
PA Mining Operations
Bailey
Enlow Fork
Harvey (3)
Total
Enon, PA
Enon, PA
Enon, PA
CONSOL Energy Portion of Equity Affiliates
Harrison Resources (1)(2)
Western Allegheny (1)(2)
Cadiz, OH
Young Township, PA
Total CONSOL Energy Portion of Equity
Affiliates
U
U
U
S
U
LW/CM
LW/CM
LW/CM
R R/B
R R/B
R R/B
12.1
10.2
9.6
3.0
9.0
3.6
24.7
22.8
S/L
CM
R T
R T
—
—
—
—
0.4
0.4
1984
1990
2014
2007
2010
12.3
10.6
3.2
26.1
0.3
0.5
0.8
S
U
– Surface
– Underground
LW – Longwall
CM – Continuous Miner
S/L
– Stripping Shovel and Front End Loaders
R
– Rail
R/B – Rail to Barge
T
(1)
(2)
(3)
– Truck
– Harrison Resources,and Western Allegheny (includes facilities operated by independent contractors).
– Production amounts represent CONSOL Energy's 49% ownership interest. Interest in Harrison Resources was sold in October 2014. Interest in Western
Allegheny was sold in September 2015.
– Completed development work and was placed in service in March 2014.
Coal Capital
In 2017, CONSOL Energy expects to invest $135 million in the PA Mining Operation division: $120 million allocated to
production and $15 million allocated to other activities related to land, safety and water.
Coal Marketing and Sales
The following table sets forth the Company produced tons sold and average sales price for the period indicated:
Company Produced PA Mining Operations Tons Sold (in millions)
24.6
22.9
Average Sales Price Per Ton Sold– PA Mining Operations
$
43.31
$
56.36
$
26.1
61.88
Years Ended December 31,
2016
2015
2014
19
We sell coal produced by our mines and additional coal that is purchased by us for resale from other producers. We maintain
United States sales offices in Philadelphia and Pittsburgh. In addition, we sell coal through agents and to brokers and unaffiliated
trading companies.
Approximately 75% of our 2016 coal sales were made to U. S. electric generators, 22% of our 2016 coal sales were priced
on export markets and 3% of our coal sales were made to other domestic customers. We had sales to over 35 customers from our
2016 coal operations. During 2016, two customers each comprised over 10% of our coal sales, and the top four coal customers
accounted for over 40% of our coal sales.
Coal Contracts
We sell coal to an established customer base through opportunities as a result of strong business relationships, or through a
formalized bidding process. Contract volumes range from a single shipment to multi-year agreements for millions of tons of coal.
The average contract term is between one to three years. As a normal course of business, efforts are made to renew or extend
contracts scheduled to expire. Although there are no guarantees, we generally have been successful in renewing or extending
contracts in the past. For the year ended December 31, 2016, over 65% of all the coal we produced was sold under contracts with
terms of one year or more.
CONSOL Energy expects total consolidated PA Mining Operations annual sales to be approximately 26.0 million tons for
both 2017 and 2018.
Coal pricing for contracts with terms of one year or less are generally fixed. Coal pricing for multiple-year agreements
generally provide the opportunity to periodically adjust the contract prices through pricing mechanisms consisting of one or more
of the following:
Fixed price contracts with pre-established prices;
Periodically negotiated prices that reflect market conditions at the time;
Price restricted to an agreed-upon percentage increase or decrease;
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• Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices, or other
negotiated indices; or
• Netback pricing.
The volume of coal to be delivered is specified in each of our coal contracts. Although the volume to be delivered under the
coal contracts is stipulated, the parties may vary the timing of the deliveries within specified limits.
Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the
duration of specified events. Force majeure events include, but are not limited to, unexpected significant geological conditions or
natural disasters. Depending on the language of the contract, some contracts may terminate upon continuance of an event of force
majeure that extends for a period greater than three to twelve months.
Distribution
Coal is transported from CONSOL Energy's mining operations to customers by railroad cars, trucks or a combination of
these means of transportation. Most customers negotiate their own transportation rates and we employ transportation specialists
who negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines, terminal
operators, ocean vessel brokers and trucking companies for certain customers.
Coal Competition
Both the domestic and international coal industries are highly competitive, with numerous producers selling into all markets
that use coal. CONSOL Energy competes against several other large producers and numerous small producers in the United States
and overseas. Demand for our coal by our principal customers is affected by many factors including:
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the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and
renewable energy sources, such as hydroelectric power, wind or solar;
environmental and government regulation;
coal quality;
transportation costs from the mine to the customer;
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the reliability of fuel supply;
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• worldwide demand for steel;
natural disasters/weather; and
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political changes in international governments.
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Continued demand for CONSOL Energy's coal and the prices that CONSOL Energy obtains are affected by demand for
electricity, technological developments, environmental and governmental regulation, and the availability and price of competing
coal and alternative fuel supplies. We sell coal to foreign electricity generators which are significantly affected by international
demand and competition.
Other Operations
CONSOL Energy provides other services both to our own operations and to others. These include land services, coal terminal
services and water services.
Non-Core Mineral Assets and Surface Properties
CONSOL Energy owns significant gas and coal assets that are not in our short or medium term development plans. We
continually explore the monetization of these non-core assets by means of sale, lease, contribution to joint ventures, or a combination
of the foregoing in order to bring the value of these assets forward for the benefit of our shareholders. We also control a significant
amount of surface acreage. This surface acreage is valuable to us in the development of the gathering system for our Marcellus
Shale and Utica Shale production. We also derive value from this surface control by granting rights of way or development rights
to third-parties when we are able to derive appropriate value for our shareholders.
Terminal Services
In 2016, approximately 8.1 million tons of coal were shipped through CONSOL Energy's subsidiary, CNX Marine Terminals
Inc.'s, exporting terminal in the Port of Baltimore. Approximately 63% of the tonnage shipped was produced by CONSOL Energy's
PA Mining Operations. The terminal can either store coal or load coal directly into vessels from rail cars. It is also one of the few
terminals in the United States served by two railroads, Norfolk Southern Corporation and CSX Transportation Inc.
Water Division
CNX Water Assets LLC, doing business as CONVEY Water Systems LLC, is a wholly-owned subsidiary of CONSOL
Energy and supplies turnkey solutions for water sourcing, delivery and disposal for our E&P operations, supplies solutions for
water sourcing, delivery and disposal for third-parties and also provides supplemental water sourcing and marketing efforts on
behalf of CNXC. In coordination with our midstream operations, CONVEY Water Systems works to develop solutions that coincide
with our midstream operations to offer gas gathering and water delivery solutions in one package to third-parties.
Employee and Labor Relations
At December 31, 2016, CONSOL Energy had 2,307 employees. There were no employees represented by the United Mine
Workers of America (UMWA) at December 31, 2016.
Industry Segments
Financial information concerning industry segments, as defined by accounting principles generally accepted in the United
States, for the years ended December 31, 2016, 2015 and 2014 is included in Note 23 - Segment Information in the Notes to the
Audited Consolidated Financial Statements in Item 8 of this Form 10-K and incorporated herein.
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Laws and Regulations
Overview
Our natural gas and coal mining operations are subject to various types of federal, state and local laws and regulations.
Regulations relating to our operations include permitting and other licensing requirements; water withdrawal and procurement
for well stimulation purposes; well drilling and casing; well production; well plugging; venting or flaring of natural gas; pipeline
compression and transmission of natural gas and liquids; reclamation and restoration of properties after natural gas or coal mining
operations are completed; storage, transportation and disposal of materials used or generated by gas and mining operations; the
calculation, reporting and disbursement of taxes; gathering of gas production in certain circumstances; surface subsidence from
underground mining; discharge of water from coal mining operations; air quality standards; protection of wetlands; endangered
plant and wildlife protection; and employee health and safety. Numerous governmental permits and approvals under these laws
and regulations are required for gas and mining operations. Lastly, the electric power generation industry is subject to extensive
regulation regarding the environmental impact of its power generation activities, which could affect demand for our natural gas
and coal products.
Compliance with these laws has substantially increased the cost of natural gas production and mining of coal for all domestic
natural gas and coal producers. We also post performance bonds or letters of credit pursuant to state oil and gas laws and regulations
to guarantee reclamation of gas well sites and plugging of gas wells. We post surety performance bonds or letters of credit pursuant
to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, often including the cost
of treating mine water discharge. We endeavor to conduct our natural gas and mining operations in compliance with all applicable
federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements against
a backdrop of variable geologic and seasonal conditions, permit exceedances and violations during natural gas and mining operations
can and do occur. The possibility exists that new legislation or regulations may be adopted which would have a significant impact
on our natural gas and coal mining operations or our customers' ability to use our gas and coal and may require us or our customers
to change their operations significantly or incur substantial costs.
CONSOL Energy is committed to complying with all laws and regulations. This commitment is evident in CONSOL Energy's
demonstrated cost and effort to abate and control pollution and/or contamination at its facilities. CONSOL Energy made capital
expenditures for environmental control facilities of approximately $0.6 million, $18.4 million, and $19.0 million in the years ended
December 31, 2016, 2015 and 2014, respectively. CONSOL Energy does not expect to have any capital expenditures in 2017 for
environmental control facilities.
Environmental Laws
Clean Air Act and Related Regulations. The federal Clean Air Act (CAA) and corresponding state laws and regulations
regulate air emissions primarily through permitting and/or emissions control requirements. This affects natural gas production and
processing operations as well as coal mining, coal handling, and processing.
We are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit
requirements, or to use specific equipment, technologies or best management practices to control emissions. On August 16, 2012,
the U.S. Environmental Protection Agency (EPA) published final revisions to the New Source Performance Standards (NSPS) to
regulate emissions of volatile organic compounds (VOCs) and sulfur dioxide (SO2) from various oil and gas exploration, production,
processing and transportation facilities. Additionally, revisions were made to the National Emission Standards for Hazardous Air
Pollutants (NESHAPS) to further regulate emissions from the oil and natural gas production sector and the transmission and
storage of natural gas. Section 111 of the CAA authorized the EPA to develop technology based standards which apply to specific
categories of stationary sources. On June 3, 2016, the EPA finalized updates to the final New Source Performance Standards
(NSPS) that created new standards for the regulation of methane and VOC emission sources. The rule includes requirements for
new fugitive emission and leak detection testing and reporting requirements. Also on June 3, 2016, the EPA published the final
Source Determination Rule which clarified the use of the term “adjacent” in determining Title V air permitting requirements as
they apply to the oil and natural gas industry for major sources of air emissions. On August 1, 2016 these updates to the NSPS
were challenged in the D.C. Circuit Court of Appeals by industry and state associations and a request for administrative
reconsideration was also filed. Additionally, 15 states filed suit and asked the Court of Appeals to review the need for the changes.
On November 30, 2016, the EPA finalized amendments to the Petroleum and Natural Gas Systems source category (Subpart
W) of the Greenhouse Gas Reporting Program (GHGRP). This final rule adds new monitoring methods for detecting leaks from
oil and gas equipment in the petroleum and natural gas systems source category consistent with the leak detection methods in the
NSPS. The action also adds emission factors for leaking equipment to be used in conjunction with these monitoring methods to
calculate and report greenhouse gas (GHG) emissions resulting from equipment leaks. The NSPS final rule would add reporting
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of GHG emissions from certain gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing,
and blowdowns of natural gas transmission pipelines.
The CAA also indirectly and more significantly affects the U.S. coal industry by extensively regulating the air emissions
of coal-fired electric power generating plants operated by our customers. Coal contains impurities, such as sulfur, mercury and
other constituents, many of which are released into the air when coal is burned. Carbon dioxide (CO2), a regulated GHG, is also
emitted when coal is burned. Environmental regulations governing emissions from coal-fired electric generating plants increase
the costs to operate and could affect demand for coal as a fuel source and affect the volume of our sales. Moreover, additional
environmental regulations increase the likelihood that existing coal-fired electric generating plants will be decommissioned,
including plants to which CONSOL Energy sells coal to, and reduce the likelihood that new coal-fired plants will be built in the
future.
In early 2012, the EPA promulgated or finalized several rules for New Source Performance Standards (NSPS) for coal- and
oil- fired power plants which also have a negative effect on coal-generating facilities. The Utility Maximum Control Technology
(UMACT) rule requires more stringent NSPS for particulate matter (PM), SO2 and nitrogen oxides (NOX) and the Mercury and
Air Toxics Standards (MATS) rule requires new mercury and air toxic standards. In November 2012, the EPA published a notice
of reconsideration of certain aspects of the UMACT and MATS rules. Following reconsideration in April 2013 and again in April
2014, the EPA promulgated final UMACT and MATS rules in November 2014 at which point the standards become applicable to
new power plants. The final rules have higher emission limits, but the standards are still stringent and compliance with the rules
is expensive.
The CAA requires the EPA to set National Ambient Air Quality Standards (NAAQS) for certain pollutants and the CAA
identifies two types of NAAQS. Primary standards provide public health protection, including protecting the health of "sensitive"
populations such as asthmatics, children, and the elderly. Secondary standards provide public welfare protection, including
protection against decreased visibility and damage to animals, crops, vegetation, and buildings. On October 1, 2015, the EPA
finalized the NAAQS for ozone pollution and reduced the limit to 70 parts per billion (ppb) from the previous 75 ppb standard.
The final rule could have a large impact on both the oil and gas and coal mining industries as states would be required to update
their permitting standards to meet these potentially unachievable limits. Six states have now filed a petition for review in the Court
of Appeals for the D.C. Circuit.
On July 6, 2011, the EPA finalized a rule known as the Cross-State Air Pollution Rule (CSAPR). CSAPR regulates cross-
border emissions of criteria air pollutants such as SO2 and NOX, as well as byproducts, fine particulate matter (PM2.5) and ozone
by requiring states to limit emissions from sources that "contribute significantly" to noncompliance with air quality standards for
the criteria air pollutants. If the ambient levels of criteria air pollutants are above the thresholds set by the EPA, a region is considered
to be in "nonattainment" for that pollutant and the EPA applies more stringent control standards for sources of air emissions located
in the region. In April 2014, the Supreme Court reversed a decision of the D.C. Circuit Court of Appeals that vacated the rule.
Following remand and briefing the D.C. Circuit Court of appeals, in October 2014, granted a motion to lift a stay of the rule and
allow the EPA to modify the CSAPR compliance deadline by three-years, setting the stage for issuance of the proposed rule.
Implementation of CSAPR Phase 1 began in 2015, with Phase 2 scheduled to begin in 2017. On September 7, 2016, the EPA
finalized an update to the CSAPR for the 2008 ozone NAAQS by issuing the final CSAPR Update. Starting in May 2017, this
rule will reduce summertime (May - September) NOX emissions from power plants in 22 states in the eastern United States.
On March 27, 2012, the EPA published its proposed NSPS for CO2 emissions from new coal-powered electric generating
units. The proposed rule would have applied to new power plants and to existing plants that make major modifications. If the rule
had been adopted as proposed, only new coal-fired power plants with CO2 capture and storage (CCS) could have met the proposed
emission limits. Commercial scale CCS is not likely to be available in the near future, and if available, it may make coal-fired
electric generation units uneconomical compared to new gas-fired electric generation units. On January 8, 2014, the EPA re-
proposed NSPS for CO2 for new fossil fuel fired power plants and rescinded the rules that were proposed on April 12, 2012.
On September 20, 2013, the EPA issued a new proposal to control carbon emissions from new power plants. Under the
Clean Power Plan (CPP) proposal, the EPA would establish separate NSPS for CO2 emissions for natural gas-fired turbines and
coal-fired units. The proposed “Carbon Pollution Standard for New Power Plants” replaces the earlier proposal released by the
EPA in 2012. On August 3, 2015, the EPA finalized the Carbon Pollution Standards to cut carbon emissions from new, modified
and reconstructed power plants, which would have become effective on October 23, 2015.
On June 2, 2014, the EPA proposed additional CPP legislation to cut carbon emissions from existing power plants. Under
this proposed rule, the EPA would create emission guidelines for states to follow in developing plans to address GHG emissions
from existing fossil fuel-fired electric generating units. Specifically, the EPA is proposing state-specific rate-based goals for CO2
emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve the state-specific goals.
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On August 3, 2015, the EPA finalized the CPP Rule to cut carbon pollution from existing power plants, which would have become
effective on December 22, 2015. Numerous petitions challenging the CPP Rule have been consolidated into one case, West Virginia
v. EPA. While the litigation is still ongoing at the circuit court level, a mid-litigation application to the Supreme Court resulted in
a stay of the Clean Power Plan Rule. On September 27, 2016, the en banc D.C. Circuit heard oral argument in the case and a
decision is expected in early 2017.
Clean Water Act. The federal Clean Water Act (CWA) and corresponding state laws affect our natural gas and coal operations
by regulating discharges into surface waters. Permits requiring regular monitoring and compliance with effluent limitations and
reporting requirements govern the discharge of pollutants into regulated waters. The CWA and corresponding state laws include
requirements for: improvement of designated "impaired waters" (i.e., not meeting state water quality standards) through the use
of effluent limitations; anti-degradation regulations which protect state designated "high quality/exceptional use" streams by
restricting or prohibiting discharges; requirements to treat discharges from coal mining properties for non-traditional pollutants,
such as chlorides, selenium and dissolved solids; requirements to minimize impacts and compensate for unavoidable impacts
resulting from discharges of fill materials to regulated streams and wetlands; and requirements to dispose of produced wastes and
other oil and gas wastes at approved disposal facilities. In addition, the Spill Prevention, Control and Countermeasure (SPCC)
requirements of the CWA apply to all CONSOL Energy operations that use or produce fluids and require the implementation of
plans to address any spills and the installation of secondary containment around all storage tanks. These requirements may cause
CONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and
cash flows.
Pursuant to a Congressional requirement in the EPA's 2010 budget appropriation, the EPA must conduct a comprehensive
study of the potential adverse impact that hydraulic fracturing may have on water quality and public health. Hydraulic fracturing
is a way of producing natural gas from tight rock formations such as the Marcellus shale and Utica shale. The EPA initiated the
study in early January 2011 and the final assessment report was published on June 4, 2015. The draft report stated that hydraulic
fracturing activities have not led to widespread, systemic impacts to drinking water resources. On December 13, 2016, the EPA
released its final report on the impacts of hydraulic fracturing on drinking water. While the language was changed and included
the possibility of impacts from hydraulic fracturing, it also included the guidance to industry and regulators on how the process
can be done safely.
CONSOL Energy utilizes pipelines extensively for its natural gas, water and coal businesses. Mitigation permits from the
Army Corps of Engineers (ACOE) are typically required for certain impacts these pipelines cause to streams and wetlands. On
April 21, 2014 the EPA published a proposed rule called “Definition of ‘Waters of the United States’ (WoUS) Under the Clean
Water Act.” The proposal would expand the scope of the CWA to include previously non-jurisdictional streams, wetlands, and
waters, making these areas jurisdictional inter-coastal waters of the U.S. In February 2015 the EPA and ACOE issued a memorandum
of understanding to withdraw the WoUS Interpretive Rule. The EPA published the latest version of the WoUS rule (the Clean
Water Rule) on June 29, 2015, which was to become effective on August 28, 2015. However, on August 27, 2015, the District
Court of North Dakota blocked implementation of the rule in 13 states. On October 9, 2015, the Court of Appeals for the Sixth
Circuit blocked implementation of the rule nationwide. The U.S. Supreme Court will now decide which court has jurisdiction -
federal appeals court or district courts. A decision is expected sometime in mid 2017.
Safety of Gas Transmission and Gathering Pipelines. On April 8, 2016, The U.S. Department of Transportation (DOT)
Pipeline and Hazardous Materials Safety Administration (PHMSA) published in the Federal Register a Notice of Proposed Rule
Making (NPRM) that would significantly modify existing regulations related to reporting, impact, design, construction,
maintenance, operations and integrity management of gas transmission and gathering pipelines. The proposed rule addresses four
congressional mandates and six recommendations by the National Transportation Safety Board. The proposed rule broadens the
scope of safety coverage both by adding new assessment and repair criteria for gas transmission pipelines, and by expanding these
protocols to include pipelines not formerly regulated by the federal standards. This means extending regulatory requirements to
transmission and gathering pipelines of 8 inches and greater in rural class 1 areas, which could increase timeframes and cost to
complete projects.
Resource Conservation and Recovery Act. The federal Resource Conservation and Recovery Act (RCRA) and corresponding
state laws and regulations affect natural gas operations and coal mining by imposing requirements for the treatment, storage and
disposal of hazardous wastes. Facilities at which hazardous wastes have been treated, stored or disposed of are subject to corrective
action orders issued by the EPA that could adversely affect our financial results, financial condition and cash flows. On December
28, 2016 the EPA entered into a consent order to resolve outstanding litigation brought by environmental and citizen groups
regarding the applicability of RCRA to wastes from oil and gas development activities. The consent order requires the EPA to
revise the applicability determination by March 15, 2019.
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In 2010, the EPA proposed options for the regulation of Coal Combustion Residuals (CCRs) from the electric power sector
as either hazardous waste or non-hazardous waste. On December 19, 2014, the EPA announced the first national regulations for
the disposal of CCRs from electric utilities and independent power producers under RCRA. On April 17, 2015, the EPA finalized
these regulations under the solid waste provisions (Subtitle D) of RCRA and not the hazardous waste provisions (Subtitle C) which
became effective on October 19, 2015. The EPA affirms in the preamble to the final rule that “this rule does not apply to CCR
placed in active or abandoned underground or surface mines.” Instead, “the U.S. Department of Interior (DOI) and the EPA will
address the management of CCR in mine fills in a separate regulatory action(s).” On November 3, 2015, the EPA published the
final rule Effluent Limitations Guidelines and Standards (ELG), revising the regulations for the Steam Electric Power Generating
category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater
that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last
three decades. The combined effect of the CCR and ELG regulations has forced power generating companies to close existing ash
ponds and will likely force the closure of certain older existing coal burning power plants that can’t comply with the new standards.
Surface Mining Control and Reclamation Act. The federal Surface Mining Control and Reclamation Act (SMCRA)
establishes minimum national operational and reclamation standards for all surface mines, as well as most aspects of underground
mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and
following completion of mining activities. Permits for all mining operations must be obtained from the U.S. Office of Surface
Mining (OSM) or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate
state regulatory authority. States that operate federally approved state programs may impose standards which are more stringent
than the requirements of SMCRA and OSM's regulations and in many instances have done so. Our active mining complexes are
located in Pennsylvania which has primary jurisdiction for enforcement of SMCRA through its approved state program. In addition,
SMCRA imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine
Reclamation Fund (AML Fund), which is used to restore unreclaimed and abandoned mine lands mined before 1977. The current
per ton fee is $0.28 per ton for surface mined coal and $0.12 per ton for underground mined coal. These fees are currently scheduled
to be in effect until September 30, 2021.
Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and to satisfy other
miscellaneous obligations. These bonds are typically renewable on a yearly basis. Surety bond costs have increased while the
market terms of surety bonds have generally become less favorable. It is possible that surety-bond issuers may refuse to renew
bonds or may demand additional collateral. Any failure to maintain, or inability to acquire, surety bonds that are required by state
and federal laws would have a material adverse effect on our ability to produce coal, which could adversely affect our business,
financial condition, results of operations, liquidity and cash flows.
Excess Spoil, Coal Mine Waste, Diversions, and Buffer Zones for Perennial and Intermittent Streams. The OSM has issued
final amendments to regulations concerning stream buffer zones, stream channel diversions, excess spoil, and coal mine waste to
comply with an order issued by the U.S. District Court for the District of Columbia on February 20, 2014, which vacated the
stream buffer zone rule that was published December 12, 2008. On July 27, 2015, the OSM published the proposed Stream
Protection Rule (SPR). After much debate and thousands of comments, the final SPR was published by the OSM in the Federal
Register on December 20, 2016. The final SPR requires the restoration of the physical form, hydrologic function, and ecological
function of the segment of a perennial or intermittent stream that a permittee mines through. Additionally, it requires that the post-
mining surface configuration of the reclaimed mine site include a drainage pattern, including ephemeral streams, similar to the
pre-mining drainage pattern, with exceptions for stability, topographical changes, fish and wildlife habitat, etc. The rule also
requires the establishment of a 100-foot-wide streamside vegetative corridor of native species (including riparian species, when
appropriate) along each bank of any restored or permanently-diverted perennial, intermittent, or ephemeral stream. This rulemaking
is highly anticipated to be subject to Legislative and Executive branch actions to overturn or significantly modify the rule.
Federal Regulation of the Sale and Transportation of Natural Gas
Regulations and orders set forth by the Federal Energy Regulatory Commission (FERC) impact our natural gas business
to a certain degree. Although the FERC does not directly regulate our natural gas production activities, the FERC has stated that
it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the
FERC continues to review its transportation regulations, including whether to allocate all short-term capacity on the basis of
competitive auctions and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias
toward short-term contracts. The FERC has also issued numerous orders confirming the sale and abandonment of natural gas
gathering facilities previously owned by interstate pipelines and acknowledging that if the FERC does not have jurisdiction over
services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance
with state law. We own certain natural gas pipeline facilities that we believe meet the traditional tests which the FERC has used
to establish a pipeline's status as a gatherer not subject to the FERC jurisdiction.
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Health and Safety Laws
Occupational Safety and Health Act. Our gas operations are subject to regulation under the federal Occupational Safety
and Health Act (OSHA) and comparable state laws in some states, all of which regulate health and safety of employees at our
natural gas operations. Also, OSHA's hazardous communication standard requires that information be maintained about hazardous
materials used or produced by our natural gas operations and that this information be provided to employees, state and local
governments and the public.
Mine Safety. Legislative and regulatory changes have required us to purchase additional safety equipment, construct stronger
seals to isolate mined out areas, and engage in additional training. We have also experienced more aggressive inspection protocols
and with new regulations the amount of civil penalties has increased. The actions taken thus far by federal and state governments
include requiring:
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the caching of additional supplies of self-contained self-rescuer (SCSR) devices underground;
the purchase and installation of electronic communication and personal tracking devices underground;
the purchase and installation of proximity detection services on continuous miner machines;
the placement of refuge chambers, which are structures designed to provide refuge for groups of miners during a mine
emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;
the replacement of existing seals in worked-out areas of mines with stronger seals;
the purchase of new fire resistant conveyor belting underground;
additional training and testing that creates the need to hire additional employees;
more stringent rock dusting requirements; and
the purchase of personal dust monitors for collecting respirable dust samples from certain miners.
On October 2, 2015, the Mine Safety and Health Administration (MSHA) published proposed rules for underground coal
mining operations concerning proximity detection systems for coal hauling machines and scoops. On January 15, 2015, MSHA
published a final rule requiring underground coal mine operations to equip continuous mining machines, except full-face continuous
mining machines, with proximity detection systems. The proximity detection system strengthens protection for miners by reducing
the potential of pinning, crushing and striking hazards that result in accidents involving life-threatening injuries and death. The
final rule became effective March 15, 2015 and included a phased in schedule for newly manufactured and in-service equipment.
In 2010 MSHA rolled out the “End Black Lung, Act Now” initiative. As a result, MSHA implemented a new final rule on August
1, 2014 to lower miners’ exposure to respirable coal mine dust including using the new Personal Dust Monitor (PDM) technology.
This final rule was implemented in three phases. The first phase began August 1, 2014 and utilizes the current gravimetric sampling
device to take full shift dust samples from the current designated occupations and areas. It also requires additional record keeping
and immediate corrective action in the event of overexposure. The second phase began February 1, 2016 and requires additional
sampling for designated and other occupations using the new continuous personal dust monitor (CPDM) technology, which provides
real time dust exposure information to the miner. CONSOL Energy ordered the necessary CPDM equipment required to meet
compliance with the new rule at a cost of $2 million. We also hired Dust Coordinators and Dust Technicians to meet the staffing
demand to manage compliance with the new rule. The final phase of the rule was effective on August 1, 2016. when the current
respirable dust standard was reduced from 2.0 to 1.5mg/m3 for designated occupations and from 1.0 to 0.5mg/m3 for Part 90
Miners.
Black Lung Legislation. Under federal black lung benefits legislation, each coal mine operator is required to make payments
of black lung benefits or contributions to:
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current and former coal miners totally disabled from black lung disease;
certain survivors of a coal miner who dies from black lung disease or pneumoconiosis; and
a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before
January 1, 1970, where no responsible coal mine operator has been identified for claims (where a coal miner's last coal
employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment
of such benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep mined coal
and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
The Patient Protection and Affordable Care Act (PPACA) made two changes to the Federal Black Lung Benefits Act. First,
it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled
to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and suffer from a totally
disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or
that the disease was not caused by the miner's work. Second, it changed the law so black lung benefits will continue to be paid to
dependent survivors when the miner passes away, regardless of the cause of the miner's death. The changes have increased the
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cost to CONSOL Energy of complying with the Federal Black Lung Benefits Act. In addition to the federal legislation, we are
also liable under various state statutes for black lung claims.
Other State and Local Laws Related to Our Natural Gas Business
Regulation Affecting Gas Operations. Our natural gas operations are also subject to regulation at the state and in some
cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the siting and construction
of well pads and roads, drilling of wells, bonding requirements, protection of ground water and surface water resources and
protection of drinking water supplies, the method of drilling and casing wells, the surface use and restoration of well sites, gas
flaring, the plugging and abandoning of wells, the disposal of fluids used in connection with operations and natural gas operations
producing coalbed methane in relation to active mining. A number of states have either enacted new laws or may be considering
the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally
includes various safety, environmental and in some circumstances, nondiscriminatory take requirements but does not generally
entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. Our
gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or
services, although we do not believe that they would be affected by such regulation any differently than other natural gas producers
or gatherers. However, these regulatory burdens may affect profitability, and we are unable to predict the future cost or impact of
complying with such regulations.
Ownership of Mineral Rights. CONSOL Energy acquires ownership or leasehold rights to oil and gas properties and coal
properties prior to conducting operations on those properties. As is customary in the natural gas and coal industries, we have
generally conducted only a summary review of the title to oil and gas rights and coal rights that are not in our development plans,
but which we believe we control. This summary review is conducted at the time of acquisition or as part of a review of our land
records to determine control of mineral rights. Given CONSOL Energy's long history as a coal producer, we believe we have a
well-developed ownership position relating to our coal control; however, our ownership of oil and gas rights, particularly those
rights that we acquired in connection with our historic coal operations and some of the rights we acquired in 2010, as part of an
acquisition, are less developed. As we continue to review our land records and confirm title in anticipation of development, we
expect that adjustments to our ownership position (either increases or decreases) will be required.
Prior to the commencement of development operations on natural gas and coal properties, we conduct a thorough title
examination and perform curative work with respect to significant defects. We generally will not commence operations on a
property until we have cured any material title defects on such property. We are typically responsible for the cost of curing any
title defects. In addition, the acquisition of the necessary rights may not be feasible in some cases. Our discovering natural gas
title defects which we are unable to cure may adversely impact our ability to develop those properties and we may have to reduce
our estimated gas reserves including our proved undeveloped reserves. We have completed title work on substantially all of our
natural gas and coal producing properties and believe that we have satisfactory title to our producing properties in accordance
with standards generally accepted in the industry.
Available Information
CONSOL Energy maintains a website on the World Wide Web at www.consolenergy.com. CONSOL Energy makes
available, free of charge, on this website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934,
as amended (the 1934 Act), as soon as reasonably practicable after such reports are available, electronically filed with, or furnished
to the SEC, and are also available at the SEC's website www.sec.gov. Apart from SEC filings, we also use our website to publish
information which may be important to investors, such as presentations to analysts.
Executive Officers of the Registrant
Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Executive
Officers of CONSOL Energy” (included herein pursuant to Item 401(b) of Regulation S-K).
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ITEM 1A.
Risk Factors
Investment in our securities is subject to various risks, including risks and uncertainties inherent in our business. The following
sets forth factors related to our business, operations, financial position or future financial performance or cash flows which could
cause an investment in our securities to decline and result in a loss.
Deterioration in the global economic conditions in any of the industries in which our customers operate, or a worldwide
financial downturn, or negative credit market conditions may have a materially adverse effect on our liquidity, results
of operations, business and financial condition that we cannot predict.
Economic conditions in a number of industries in which our customers operate, such as electric power generation and
steel-making, substantially deteriorated in recent years and reduced the demand for natural gas and coal. The general economic
challenges for some of our customers continued in 2016 and the outlook is uncertain. In addition, liquidity is essential to our
business and developing our assets. Renewed or continued weakness in the economic conditions of any of the industries we
serve or are served by our customers could adversely affect our business, financial condition, results of operation and liquidity
in a number of ways. For example:
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demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened
would negatively impact the revenues, margins and profitability of our natural gas and thermal coal business;
the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect
our trade receivables;
our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital
for our business including for exploration and/or development of our natural gas or coal reserves; and
a decline in our creditworthiness, which may require us to post letters of credit, cash collateral, or surety bonds
to secure certain obligations, all of which would have an adverse effect on our liquidity.
Prices for natural gas, natural gas liquids and coal are volatile and can fluctuate widely based upon a number of
factors beyond our control including oversupply relative to the demand available for our products, weather and the
price and availability of alternative fuels. An extended decline in the prices we receive for our natural gas, natural
gas liquids and coal will adversely affect our business, operating results, financial condition and cash flows.
Our financial results are significantly affected by the prices we receive for our natural gas, natural gas liquids and coal.
Our E&P division’s products (natural gas, natural gas liquids, oil and condensate) accounted for approximately 42% of
the total company outside sales revenues from continuing operations in 2016, with natural gas and natural gas liquids representing
97% of the E&P division’s outside sales revenues. Natural gas, natural gas liquids, oil and condensate prices are very volatile
and can fluctuate widely based upon supply from energy producers relative to demand for these products and other factors beyond
our control. The sale to Murray Energy in 2013 of almost one half of our thermal coal production and the sale of our Buchanan
Mine in 2016 increased our exposure to fluctuations in the price of natural gas, natural gas liquids, oil and condensate.
In particular, while demand for natural gas has recovered to pre-recession levels, the U.S. natural gas industry continues
to face concerns of oversupply due to the success of Marcellus and other new shale plays. The oversupply of natural gas in 2012
resulted in domestic prices hovering around ten year lows, and drilling continued in these plays, despite these lower gas prices,
to meet drilling commitments. Although gas prices recovered somewhat during 2013 and the first quarter of 2014, they again
significantly declined in the latter part of 2014 due to oversupply and remained at depressed levels throughout 2015 and 2016.
Our natural gas operations are geographically concentrated in the mid-Atlantic states. The success of the Marcellus
Shale and Utica plays has resulted in growth in natural gas production in this region with production per day in Pennsylvania,
West Virginia and Ohio more than doubling since 2011. Traditionally, natural gas produced in the mid-Atlantic states sold at a
premium to the benchmark Louisiana Henry Hub prices. However, as Appalachian production increased this premium narrowed
and during 2014 and continuing into 2015 and 2016, the spot prices at some Appalachian hubs fell below Henry Hub prices. This
decline, or negative basis, to the Henry Hub price is forecasted to continue in future years. The oversupply in the Appalachian
Basin may persist if current pipeline projects to move gas out of the basin are delayed by permitting or environmental lawsuits.
An extended period of lower natural gas prices can negatively affect us in several other ways. These include reduced
cash flow, which decreases funds available for capital expenditures to replace reserves or increase production. For example, in
light of the low natural gas prices continuing from 2014 into 2015, we substantially decreased our 2016 capital expenditures and
the drilling of new shale wells. In 2017, we expect our capital expenditures to increase to approximately $555 million from $227
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million in 2016. Also, our access to other sources of capital, such as equity or long-term debt markets, could be severely limited
or unavailable. Additionally, lower natural gas prices may reduce the amount of natural gas that we can produce economically.
This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if
our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting
rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We are
required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the
estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or
whenever management's plans change with respect to those assets. For example, in the second quarter of 2015, we had an
impairment charge of approximately $829 million for our natural gas assets, primarily shallow oil and gas assets. We may incur
impairment charges in the future, which could have an adverse effect on our results of operations in the period taken.
We have increased development activity in areas of shale formations which may also contain natural gas liquids,
condensate and/or oil. The prices for natural gas liquids, condensate and oil are also volatile for reasons similar to those described
above regarding natural gas. As a result of increasing supply, condensate and oil prices have exhibited great volatility. In addition,
similar to the oversupply of natural gas, increased drilling activity by third-parties in formations containing natural gas liquids
has led to a decline of over 60% since 2014 in the uplift we receive, on an Mcfe equivalent basis when excluding hedging impact,
from natural gas liquids. Our results of operation may be adversely affected by a continued depressed level of or further downward
fluctuations in natural gas liquids, condensate and oil prices.
Apart from issues with respect to the supply of products we produce, demand can fluctuate widely due to a number of
matters beyond our control, including:
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•
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•
changes in the consumption pattern of industrial consumers, electricity generators and residential users of
electricity and natural gas;
weather conditions in our markets which affect the demand for natural gas and thermal coal (for example, the
unusually warm 2015 - 2016 winter left utilities with large coal stockpiles and depressed the demand for thermal
coal);
with respect to thermal coal, the price and availability of natural gas and the price and supply of imported liquefied
natural gas;
with respect to natural gas, the price and availability of thermal coal;
technological advances affecting energy consumption;
the costs, availability and capacity of transportation infrastructure;
proximity and capacity of natural gas pipelines and other transportation facilities; and
the impact of domestic and foreign governmental laws and regulations, including environmental and climate
change regulations and regulations affecting the coal mining industry and coal-fired power plants, and delays
in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits.
The coal industry also faces concerns with respect to oversupply from time to time. For example, U.S. coal exports
decreased by 32% during the first half of 2016 compared with the first half of 2015, as global supply exceeded demand for both
thermal and metallurgical coal. Our average sales price per ton sold in 2016 declined 23% from 2015 due to imbalanced supply
and demand, and a substantial or extended decline in the prices we receive for our coal could adversely affect our business, results
of operations, financial condition, cash flows and liquidity.
Foreign currency fluctuations could adversely affect the competitiveness of our coal and natural gas liquids abroad.
We compete in international markets against coal produced in other countries. Coal is sold internationally in U.S. dollars
and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide
our foreign competitors with a competitive advantage. As a result, mining costs in competing producing countries may be reduced
in U.S. dollar terms based on currency exchange rates, providing an advantage to foreign coal producers. If our competitors’
currencies decline against the U.S. dollar or against our foreign customers’ local currencies, those competitors may be able to
continue to offer lower prices for coal to our customers. Furthermore, if the currencies of our overseas customers were to
significantly decline in value in comparison to the U.S. dollar, those customers may seek decreased prices for the coal we sell to
them. We also expect in the future that an international market will develop for exporting domestic natural gas and natural gas
liquids. Consequently, currency fluctuations could adversely affect the competitiveness of our products in international markets,
which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
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If our coal customers do not extend existing contracts or do not enter into new multi-year coal sales contracts on
favorable terms, profitability of CONSOL Energy's operations could be adversely affected.
During the year ended December 31, 2016, approximately 65% of the coal CONSOL Energy produced from continued
operations was sold under multi-year sales contracts. If a substantial portion of our multi-year sales contracts are modified or
terminated, if force majeure is exercised, or if we are unable to replace or extend the contracts or new contracts are priced at
lower levels, our profitability would be adversely affected. The profitability of our multi-year sales coal supply contracts depends
on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production
costs and other factors. Price changes, if any, provided in long-term supply contracts may not reflect our cost increases, and
therefore, increases in our costs may reduce our profit margins. In addition, during periods of declining market prices, provisions
in our long-term coal contracts for adjustment or renegotiation of prices and other provisions may increase our exposure to short-
term coal price and electric power price volatility. As a result, we may not be able to obtain long-term agreements at favorable
prices compared to either market conditions, as they may change from time to time, or our cost structure, which may reduce our
profitability.
The loss of, or significant reduction in, purchases by our largest coal customers or the failure of any of our customers
to buy and pay for coal they committed to purchase could adversely affect our business, financial condition, results
of operation and cash flows.
For the year ended December 31, 2016, we derived over 10% of our coal sales revenue from two coal customers
individually and approximately 40% of our total sales revenue were derived from our four largest coal customers. At December
31, 2016, we had approximately nine coal supply agreements with these top two customers that expire at various times from
2017 to 2018. There are inherent risks whenever a significant percentage of total revenues are concentrated with a limited number
of customers. Revenues from our largest customers may fluctuate from time to time based on numerous factors, including market
conditions, which may be outside of our control. If any of our largest customers experience declining revenues due to market,
economic or competitive conditions, we could be pressured to reduce the prices that we charge for our coal, which could have
an adverse effect on our margins, profitability, cash flows and financial position. In addition, if any customers were to significantly
reduce their purchases of coal from us, including by failing to buy and pay for coal they committed to purchase in sales contracts,
our business, financial condition, results of operations and cash flows could be adversely affected.
Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail
to honor their contracts with us.
Our ability to receive payment for natural gas and coal sold and delivered depends on the continued creditworthiness
of our customers. Many utilities have sold their power plants to non-regulated affiliates or third parties that may be less creditworthy,
thereby increasing the risk we bear with respect to payment default. These new power plant owners may have credit ratings that
are below investment grade. In addition, some of our customers have been adversely affected by the current economic downturn,
which may impact their ability to fulfill their contractual obligations. Competition with other coal suppliers could force us to
extend credit to customers and on terms that could increase the risk we bear with respect to payment default. We also have a
contract to supply coal to an energy trading and brokering customer under which that customer sells coal to end users. If the
creditworthiness of our energy trading and brokering customer declines, we may not be able to collect payment for all coal sold
and delivered to this customer. If the creditworthiness of our customers declines significantly, our business could be adversely
affected. In addition, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation,
our revenues will decrease and we may have to reduce production at our mines until our customers’ contractual obligations are
honored. Our inability to collect payment from counterparties to our sales contracts may have a materially adverse effect on our
business, financial condition, results of operations and cash flows.
Our natural gas business depends on gathering, processing and transportation facilities owned by others and the
disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas and natural
gas liquids. Similarly, the availability and reliability of transportation facilities and fluctuations in transportation
costs could affect the demand for our coal or impair our ability to supply coal to our customers.
We gather, process and transport our natural gas to market by utilizing pipelines and facilities owned by others. If
pipeline or facility capacity is limited, or if pipeline or facility capacity is unexpectedly disrupted for any reason, our natural gas
sales and/or sales of natural gas liquids could be limited, reducing our profitability. If we cannot access processing pipeline
transportation facilities, we may have to reduce our production of natural gas. If our sales of natural gas or natural gas liquids
are reduced because of transportation or processing constraints, our revenues will be reduced and our unit costs will also increase.
If pipeline quality standards change, we might be required to install additional processing equipment which could increase our
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costs. The pipeline could also curtail our flows until the natural gas delivered to their pipeline is in compliance. Any reduction
in our production of natural gas or increase in our costs could materially adversely affect our business, financial condition, results
of operations and cash flows.
Additionally, we have various firm transportation, natural gas processing, gathering and other agreements in place,
many of which have minimum volume delivery commitments. Lower commodity prices may lead to reductions in our drilling
program, which may result in insufficient production to utilize our full firm transportation and processing capacity. We are
obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput. If we have insufficient
production to meet the minimum volumes, our cash flow from operations will be reduced, which may require us to reduce or
delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material
adverse effect our business, financial condition, results of operations and cash flows.
Transportation logistics play an important role in allowing us to supply coal to our customers. Any significant delays,
interruptions or other limitations on the ability to transport our coal could negatively affect our operations. Our coal is transported
from our mining complex by rail, truck or a combination of these methods. To reach markets and end customers, our coal may
also be transported by barge or by ocean vessels loaded at terminals. Disruption of transportation services because of weather-
related problems, strikes, lock-outs, terrorism, governmental regulation, third-party action or other events could temporarily
impair our ability to supply coal to customers and adversely affect our profitability. In addition, transportation costs represent a
significant portion of the delivered cost of coal and, as a result, the cost of delivery is a critical factor in a customers’ purchasing
decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuation in
the price of diesel fuel and demurrage, could make our coal less competitive. Any disruption of the transportation services we
use or increase in transportation costs could have a materially adverse effect on our business, financial condition, results of
operations and cash flows.
Competition within the natural gas and coal industries may adversely affect our ability to sell our products. Increased
competition or a loss of our competitive position could adversely affect our sales of, or our prices for, our natural
gas and coal products, which could impair our profitability.
The natural gas industry is intensely competitive with companies from various regions of the United States. We compete
with these companies and we may compete with foreign companies for domestic sales. Many of the companies we compete with
are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, our
operating results and financial position may be adversely affected. In addition, larger companies may be able to pay more to
acquire new natural gas properties for future exploration, limiting our ability to replace the natural gas we produce or to grow
our production. Our ability to acquire additional properties and to discover new natural gas resources also depends on our ability
to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.
We compete with other coal producers primarily on the basis of price, coal quality, transportation costs and reliability.
We compete with coal producers in various regions of the United States and with some foreign coal producers for domestic sales
primarily to electric power generators. Demand for our thermal coal by our principal electric power generator customers is affected
by the delivered price of competing coals, other fuel supplies and alternative generating sources, including nuclear, natural gas,
oil and renewable energy sources, such as hydroelectric and wind power. The domestic coal industry has experienced consolidation
in recent years, including consolidation among some of our major competitors. In addition, substantial overcapacity exists in the
coal industry and most large coal companies have filed bankruptcy proceedings which could enable them to lower their production
costs and thereby reduce the price for their coal. We cannot assure you that the result of current or further consolidation in the
coal industry or current or future bankruptcy proceedings of our coal competitors will not adversely affect our competitive position.
We also compete with both domestic and foreign coal producers for sales in international markets. We sell coal to foreign electricity
generators, which sales are significantly affected by international demand and competition. Potential changes to international
trade agreements, trade concessions or other political and economic arrangements may benefit coal producers operating in
countries other than the United States. We cannot assure you that we will be able to compete on the basis of price or other factors
with companies that in the future may benefit from favorable foreign trade policies or other arrangements.
Any reduction in our ability to compete in natural gas or coal markets could have a material adverse effect on our
business, financial condition, results of operations and cash flows.
The characteristics of coal may make it costly for electric power generators and other coal users to comply with
various environmental standards regarding the emissions of impurities released when coal is burned which could
cause utilities to replace coal-fired power plants with alternative fuels. In addition, various incentives have been
proposed to encourage the generation of electricity from renewable energy sources. A reduction in the use of coal
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for electric power generation could decrease the volume of our domestic coal sales and adversely affect our results
of operations.
Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are
released into the air along with fine particulate matter and carbon dioxide when it is burned. Complying with regulations on
these emissions can be costly for electric power generators. For example, in order to meet the federal Clean Air Act limits for
sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, use sulfur dioxide emission
allowances (some of which they may purchase) or switch to other fuels. Each option has limitations. Lower sulfur coal may be
more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of
installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching
to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant
portion of our sales, the extent to which electric power generators switch to alternative fuel could materially affect us. Recent
EPA rulemaking proceedings requiring additional reductions in permissible emission levels of impurities by coal-fired plants
will likely make it more costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative
for electric power generation in the future. Examples are (i) implementation of Phase 1 of the Cross-State Air Pollution Rule
(CSAPR) that began in May 2015 with implementation of Phase 2 planned to begin in 2017; (ii) on December 3, 2015 the EPA
issued the proposed CSAPR Update Rule to require reductions of seasonal nitrogen oxides (NOX) emissions from power plants
in 23 of the original 28 proposed Eastern states to address interstate ozone air quality impacts for downwind states; (iii) on
October 1, 2015 the EPA finalized a revised National Ambient Air Quality Standards (NAAQS) for ozone pollution and reduced
the limit to 70 parts per billion from the previous 75 parts per billion standard; and (iv) promulgation in 2011 of the Utility
Maximum Achievable Control Technology (Utility MACT) rule, better known as the Mercury and Air Toxics Standard (MATS)
rule, which included more stringent new source performance standards (NSPS) for particulate matter (PM), mercury, sulfur
dioxide (SO2) and nitrogen oxides (NOX), for new and existing coal-fired power plants (amended in November 2014). On June
29, 2015, the U.S. Supreme Court rejected the EPA MATS rule, ruling that the agency unreasonably overlooked the costs associated
with the regulation, and sent the rule back to the D.C. Circuit Court to determine whether to remand and allow the EPA to address
the rule's deficiencies or to vacate and nullify the rule; nevertheless most coal-fired electric power generators have already taken
steps to comply with the rule. Six states have filed petitions for review of the new EPA NAAQS ozone pollution standard with
the D.C. Circuit Court.
On October 14, 2014, the EPA Clean Water Act Section 316(b) rulemaking went into effect which requires new and
existing power plants, including coal and natural gas-fired plants to reduce fish mortality caused by their cooling water intake
structures through either the installation of technologies or the reduction of intake velocity.
Apart from actual and potential regulation of emissions, waste water, and solid wastes from coal-fired plants, state and
federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal.
Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a
certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none
of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance
the economics of renewable energy sources could make these sources more competitive with coal. Any reductions in the amount
of coal consumed by domestic electric power generators as a result of current or new standards for the emission of impurities or
incentives to switch to alternative fuels or renewable energy sources could reduce the demand for our coal, thereby reducing our
revenues and adversely affecting our business and results of operations.
Regulation of greenhouse gas emissions may increase our operating costs and reduce the value of our natural gas
and coal assets and such regulation, as well as uncertainty concerning such regulation could adversely impact the
market for natural gas and coal, as well as for our securities.
While climate change legislation in the U.S. is unlikely in the next several years, the issue of global climate change
continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity,
especially the emissions of greenhouse gases (GHGs) such as carbon dioxide and methane. Combustion of fossil fuels, such as
the natural gas and coal we produce, results in the creation of carbon dioxide emissions into the atmosphere by natural gas and
coal end-users, such as coal-fired electric power generation plants. Numerous proposals have been made and are likely to
continue to be made at the international, national, regional and state levels of government that are intended to limit emissions
of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Other states have
elected to participate in voluntary regional cap-and-trade programs like the Regional Greenhouse Gas Initiative (RGGI) in the
northeastern U.S.
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The EPA, under the Climate Action Plan, has elected to regulate GHGs under the Clean Air Act (CAA) to limit emissions
of carbon dioxide (CO2) from coal-fired and natural gas-fired power plants. On September 20, 2013, the EPA re-proposed New
Source Performance Standards (NSPS) for CO2 from new power plants and on June 2, 2014, the EPA re-proposed NSPS for
CO2 from existing and modified/reconstructed power plants, which rescinded the rules that were originally proposed in 2012.
On August 3, 2015, the EPA finalized the Carbon Pollution Standards to cut carbon emissions from new, modified and reconstructed
power plants, which became effective on October 23, 2015. In another proposed rulemaking related to CO2 emissions, on June
2, 2014, the EPA proposed the Clean Power Plan Rule to cut carbon emissions from existing power plants. Under this proposed
rule, the EPA would create emission guidelines for states to follow in developing plans to address greenhouse gas emissions from
existing fossil fuel-fired electric generating units. Specifically, the EPA is proposing state-specific rate-based goals for CO2
emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve the state-specific goals.
On August 3, 2015, the EPA finalized the Clean Power Plan Rule to cut carbon pollution from existing power plants, which
became effective on December 22, 2015. Numerous petitions challenging the Clean Power Plan Rule have been consolidated
into one case, West Virginia v. EPA. While the litigation is still ongoing at the circuit court level, a mid-litigation application to
the Supreme Court resulted in a stay of the Clean Power Plan Rule. On September 27, 2016, an en banc panel of the U.S. Court
of Appeals for the D.C. Circuit heard oral arguments in the case and a decision is expected in early 2017.
Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (which was not ratified
by the United States) was nominally extended past its expiration date of December 2012 with a requirement for a new legal
construct to be put into place by 2015. In December 2015, the United Nations Climate Change Conference was held and an
agreement was reached between the countries participating in the conference, including the United States, to limit global warming
to less than 2 degrees Celsius (3.6° Fahrenheit) compared to pre-industrial levels. This agreement, known as the Paris Agreement,
calls for zero net anthropogenic greenhouse gas emission to be reached during the second half of the 21st century. Each party is
to prepare a plan on its contributions to reach this goal; each plan is to be filed in a publicly available registry. In addition, in
November 2014, President Obama announced that the United States would seek to cut net greenhouse gas emissions 26-28
percent below 2005 levels by 2025 in return for China's commitment to seek to peak emissions around 2030, with concurrent
increases in renewable energy. The United States participation in the Paris Agreement is unclear with the change in Administration
in January 2017.
Additionally, coalbed methane must be expelled from our underground coal mines for mining safety reasons and is
vented into the atmosphere when the coal is mined. Coalbed methane has a greater GHG effect than carbon dioxide. If regulation
of GHG emissions does not exempt the release of coalbed methane, we may have to further reduce our methane emissions, pay
higher taxes, incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines
or perhaps curtail coal production.
Apart from governmental regulation, investment banks based both domestically and internationally have announced
that they have adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing
of electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants.
Adoption of comprehensive legislation or regulation focusing on GHG emission reductions for the United States or
other countries where we sell coal (including by adopting plans to implement the Paris Agreement), or the inability of utilities
to obtain financing in connection with coal-fired plants, may make it more costly to operate fossil fuel fired (especially coal-
fired) electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending
on the nature of the regulation or legislation, natural gas-fueled power generation could become more economically attractive
than coal-fueled power generation, substantially increasing the demand for natural gas. Apart from actual regulation, uncertainty
over the extent of regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to
replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal or possibly
natural gas consumed by domestic electric power generators as a result of actual or potential regulation of greenhouse gas emissions
could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business
and results of operations. We or our customers may also have to invest in carbon dioxide capture and storage technologies in
order to burn coal or natural gas and comply with future GHG emission standards.
In addition, there have also been efforts in recent years affecting the investment community, including investment
advisers, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel
equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. The impact
of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and
financial markets.
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Environmental regulations introduce uncertainty that could adversely impact the market for natural gas and coal
with potential short and long-term liabilities.
The Federal Endangered Species Act (ESA) and similar state laws protect species endangered or threatened with
extinction. Protection of endangered and threatened species may cause us to modify gas well pad siting or pipeline right of ways,
mining plans, or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to
endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA.
On January 14, 2016, the US Fish and Wildlife Service (USFWS) finalized a rule exempting certain types of “take” of northern
long-eared bats from the requirement to obtain an incidental take permit, pursuant to Section 4(d) of the Endangered Species
Act. This listing could lead to significant timing and critical path hurdles, ultimately limiting the ability to clear timber for
construction activities in our operations area.
Other species that are being considered for listing as endangered under the ESA are the Big Sandy Crayfish, the
Guyandotte River Crayfish and the Rusty Patched Bumble Bee, all of which if listed have the potential to interfere with the
proposed layout of our mine plans and surface facilities, including natural gas well pads, compressor stations and pipelines, as
well as the manner in which we operate our mines and facilities. USFWS has stated that the primary threats to crayfishes throughout
their respective ranges are land-disturbing activities that increase erosion and sedimentation, which degrades the stream habitat
required by both species. Identified sources of ongoing erosion and sedimentation that occur throughout the ranges of the species
include active surface coal mining, commercial forestry, unpaved roads, natural gas and oil development, and road construction.
This has the potential to disrupt future mining and natural gas activities in Appalachia.
On December 19, 2016, the federal Office of Surface Mining released final regulations to the Stream Protection Rule,
which is intended to prevent or minimize impacts to surface water and groundwater from coal mining. The rule will require
companies to restore streams and return mined areas to the uses they were capable of supporting prior to mining activities, and
replant these areas with native trees and vegetation, unless that would conflict with the implemented land use. The rule requires
the testing and monitoring of the condition of streams that might be affected by mining - before, during and after their operations
- to provide baseline data that ensures operators can detect and correct problems that could arise, and restore mined areas to their
previous condition. The final SPR requires the restoration of the physical form, hydrologic function, and ecological function of
the segment of a perennial or intermittent stream that a permittee mines through. Additionally, it requires that the post-mining
surface configuration of the reclaimed mine site include a drainage pattern, including ephemeral streams, similar to the pre-
mining drainage pattern, with exceptions for stability, topographical changes, fish and wildlife habitat, etc. The rule also requires
the establishment of a 100-foot-wide streamside vegetative corridor of native species (including riparian species, when
appropriate) along each bank of any restored or permanently-diverted perennial, intermittent, or ephemeral stream. This
rulemaking is highly anticipated to be subject to Legislative and Executive branch actions to overturn or significantly modify
the rule.
CONSOL Energy utilizes pipelines extensively for its natural gas, water and coal businesses. Mitigation permits from the
Army Corps of Engineers (ACOE) are typically required for certain impacts these pipelines cause to streams and wetlands. On
April 21, 2014 the EPA published a proposed rule called “Definition of ‘Waters of the United States’ (WoUS) Under the Clean
Water Act.” The proposal would expand the scope of the CWA to include previously non-jurisdictional streams, wetlands, and
waters, making these areas jurisdictional inter-coastal waters of the U.S. In February 2015 the EPA and ACOE issued a memorandum
of understanding to withdraw the WoUS Interpretive Rule. The EPA published the latest version of the WoUS rule (the Clean
Water Rule) on June 29, 2015, which was to become effective on August 28, 2015. However, on August 27, 2015, the District
Court of North Dakota blocked implementation of the rule in 13 states. On October 9, 2015, the Court of Appeals for the Sixth
Circuit blocked implementation of the rule nationwide. The U.S. Supreme Court will now decide which court has jurisdiction -
federal appeals court or district courts. A decision is expected sometime in mid 2017.
Management and regulation of point source discharges covered under the National Pollutant Discharge Eliminations
System (NPDES) of the CWA have undergone recent changes and proposed changes at both the state and federal level that have
the potential to affect the long-term treatment and discharge of water from coal mines. States are required by the CWA to conduct
a comprehensive review of the state water quality standards every three years (the "Triennial Review"). WV has issued an
emergency rule effective June 21, 2014 and proposed amendments under 47 CSR 2 with specific requirements for the discharge
of aluminum and selenium that pose potential impacts on the coal industry. Ohio (OH) is currently reviewing the current 401
and 404 permitting program to propose new amendments.
In April 2015, the EPA proposed a CWA regulation (Effluent Limitations Guidelines and Standards for the Oil and Gas
Extraction Point Source Category) establishing pretreatment standards that would prohibit the indirect discharge of wastewater
from onshore unconventional oil and gas extraction facilities to publicly owned treatment works (POTWs). While discharges
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to POTWs are not currently utilized, unconventional oil and gas extraction wastewater can be generated in large quantities. It is
unclear how the newly proposed rule could affect future water use and disposal practices.
State regulations for horizontal well drilling and well site construction have been proposed and finalized. In September,
2015, PA published a final rulemaking on the revisions to the Environmental Protection Performance Standards at Oil and Gas
Well Sites (Chapters 78 and 78a). These rules are the subject of pending litigation. OH passed Horizontal Well Site Construction
Rules which will become effective in July 2015. OH is also in the process of reviewing and possibly adopting additional horizontal
development rules.
Our natural gas and coal mining operations are subject to operating risks, including our reliance upon third-party
contractors, which could increase our operating expenses and decrease our production levels which could adversely
affect our results of operations. Our natural gas and coal operations are also subject to hazards and any losses or
liabilities we suffer from hazards which occur in our operations may not be fully covered by our insurance policies.
Our exploration for and production of natural gas involves numerous operating risks. The cost of drilling, completing
and operating our shale gas wells, shallow oil and gas wells and coalbed methane (CBM) wells is often uncertain, and a number
of factors can delay or prevent drilling operations, decrease production and/or increase the cost of our natural gas operations at
particular sites for varying lengths of time thereby adversely affecting our operating results. The operating risks that may have
a significant impact on our natural gas operations include:
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unexpected drilling conditions;
title problems;
pressure or irregularities in geologic formations;
equipment failures or repairs;
fires, explosions or other accidents;
adverse weather conditions;
reductions in natural gas prices;
security breaches or terroristic acts;
pipeline ruptures;
lack of adequate capacity for treatment or disposal of waste water generated in drilling, completion and production
operations;
environmental contamination from surface spillage of fluids used in well drilling, completion or operation
including fracturing fluids used in hydraulic fracturing of wells, or other contamination of groundwater or the
environment resulting from our use of such fluids; and
unavailability or high cost of drilling rigs, other field services and equipment.
Our coal mining operations are underground mines. Underground mining and related processing activities present
inherent risks of injury to persons and damage to property and equipment. Our mines are subject to a number of operating risks
that could disrupt operations, decrease production and increase the cost of mining at particular mines for varying lengths of time
thereby adversely affecting our operating results. In addition, if an operating risk occurs in our mining operations, we may not
be able to produce sufficient amounts of coal to deliver under our multi-year coal contracts. Our inability to satisfy contractual
obligations could result in our customers initiating claims against us or canceling their contracts. The operating risks that may
have a significant impact on our coal operations include:
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variations in thickness of the layer, or seam, of coal;
adverse geological conditions, including amounts of rock and other natural materials intruding into the coal that
could affect the stability of the roof and the side walls of the mine - for example, unit costs were negatively
impacted in 2016 due to adverse geological conditions at Enlow Fork mine, primarily related to sandstone
intrusions, which resulted in reduced coal production at that mine;
environmental hazards;
equipment failures or unexpected maintenance problems;
fires or explosions, including as a result of methane, coal, coal dust or other explosive materials and/or other
accidents;
inclement or hazardous weather conditions and natural disasters or other force majeure events;
seismic activities, ground failures, rock bursts or structural cave-ins or slides;
delays in moving our longwall equipment;
railroad derailments;
security breaches or terroristic acts; and
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
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The occurrence of any of these risks at our natural gas or coal mining operations could adversely affect our ability to
conduct natural gas or coal mining operations or result in substantial loss to us as a result of claims for:
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personal injury or loss of life;
damage to and destruction of property, natural resources and equipment, including our coal properties and our
coal production or transportation facilities;
pollution and other environmental damage to our properties or the properties of others;
potential legal liability and monetary losses;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
In addition, the occurrence of any of these events in our coal mining operations which prevents our delivery of coal to
a customer and which is not excusable as a force majeure event under our coal sales agreement, could result in economic
penalties, suspension or cancellation of shipments or ultimately termination of the coal sales agreement.
Although we maintain insurance for a number of risks and hazards, we may not be insured or fully insured against the
losses or liabilities that could arise from a significant accident in our natural gas and coal operations. We may elect not to obtain
insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented.
In addition, pollution and environmental risks generally are not fully insurable. Moreover, a significant mine accident could
potentially cause a mine shutdown. The occurrence of an event that is not fully covered by insurance could have a material adverse
effect on our business, financial condition, results of operations and cash flows.
We also rely upon third-party contractors to provide key services to our natural gas operations. We contract with third-
parties for well services, related equipment, and qualified experienced field personnel to drill wells and conduct field operations.
The demand for these field services in the natural gas and oil industry can fluctuate significantly. Higher oil and natural gas prices
generally stimulate increased demand causing periodic shortages. These shortages may lead to escalating prices for drilling
equipment, crews and associated supplies, equipment and services. Shortages may lead to poor service and inefficient drilling
operations and increase the possibility of accidents due to the hiring of inexperienced personnel and overuse of equipment by
contractors. In addition, the costs and delivery times of equipment and supplies are substantially greater in periods of peak demand.
Accordingly, we cannot assure that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on
satisfactory terms, and we may experience shortages of, or increases in the costs of, drilling equipment, crews and associated
supplies, equipment and field services in the future. We utilize third-party contractors to provide land acquisition and related
services to support our land operational needs for both natural gas and coal segments. We also use third-party contractors to
provide construction and specialized services to our coal mining operations. A decrease in the availability of field services or
equipment and supplies, an increase in the prices charged for field services, equipment and supplies, or the failure of third-party
contractors to provide quality field services to us, could decrease our natural gas and coal production, increase our costs of natural
gas and coal production, and decrease our anticipated profitability.
We attempt to mitigate the risks involved with increased natural gas industrial activity by entering into “take or pay”
contracts with well service providers which commit them to provide field services to us at specified levels and commit us to pay
for field services at specified levels even if we do not use those services. However, these contracts expose us to economic risk
during a downturn in demand or during periods of oversupply. For example, in 2016 due to the oversupply of gas in our markets,
we made payments under these contracts of approximately $33 million for field services that we did not use. Having to pay for
services we do not use decreases our cash flow and increases our costs of production.
We may not be able to obtain equipment, parts and raw materials in a timely manner, in sufficient quantities or at
reasonable costs to support our coal mining and natural gas operations.
Coal mining consumes large quantities of commodities including steel, copper, rubber products and liquid fuels and
requires the use of capital equipment. Some commodities, such as steel, are needed to comply with roof control plans required
by regulation. The prices we pay for commodities and capital equipment are strongly impacted by the global market. A rapid or
significant increase in the costs of commodities or capital equipment we use in our operations could impact our mining operations
costs because we may have a limited ability to negotiate lower prices, and, in some cases, may not have a ready substitute.
We use equipment in our coal mining and transportation operations such as continuous mining units, conveyors, shuttle
cars, rail cars, locomotives, roof bolters, shearers and shields. We procure this equipment from a concentrated group of suppliers,
and obtaining this equipment often involves long lead times. Occasionally, demand for such equipment by mining companies
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can be high and some types of equipment may be in short supply. Delays in receiving or shortages of this equipment, as well as
the raw materials used in the manufacturing of supplies and mining equipment, which, in some cases, do not have ready substitutes,
or the cancellation of our supply contracts under which we obtain equipment and other consumables, could limit our ability to
obtain these supplies or equipment. In addition, if any of our suppliers experiences an adverse event, or decides to no longer do
business with us, we may be unable to obtain sufficient equipment and raw materials in a timely manner or at a reasonable price
to allow us to meet our production goals and our revenues may be adversely impacted. We use considerable quantities of steel
in the mining process. If the price of steel or other materials increases substantially or if the value of the U.S. dollar declines
relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses could increase.
Any of the foregoing events could materially and adversely impact our business, financial condition, results of operations or cash
flows.
Additionally, we rely on a supply of drilling rigs, equipment, personnel and services in our naturual gas operations. The
demand for this equipment and for qualified and experienced field personnel to drill wells and conduct field operations, geologists,
geophysicists, engineers, and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation
with natural gas and oil prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs,
pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We
cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages
could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which events could
materially and adversely impact our business, financial condition, results of operations, or cash flows.
For drilling and mining operations, CONSOL Energy must obtain, maintain, and renew governmental permits and
approvals which if we cannot obtain in a timely manner would reduce our production, cash flow and results of
operations.
State and local authorities regulate various aspects of natural gas drilling and production activities, including the drilling
of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of natural gas properties,
environmental matters, safety standards, market sharing and well site restoration. Delays or denials of natural gas permits could
reduce our production, cash flows and results of operations.
Our coal production is dependent on our ability to obtain various federal and state permits and approvals to mine our
coal reserves. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject
to discretionary interpretations by regulators. The EPA also has the authority to veto permits issued by the U.S. Army Corps of
Engineers under the Clean Water Act’s Section 404 program that prohibits the discharge of dredged or fill material into regulated
waters without a permit. In addition, the public, including non-governmental organizations and individuals, have certain statutory
rights to comment upon and otherwise impact the permitting process, including through court intervention. The pace with which
the government issues permits needed for new operations for on-going operations to continue mining continues to pose
significant negative effects. Further, in 2011 the EPA revoked an ACOE-issued Section 404 permit to a coal mining operator.
Following the U.S. Supreme Court’s refusal in March 2012 to hear an appeal from the D.C. Circuit Court’s ruling upholding the
EPA’s power to revoke a permit, in September 2014 the U.S. Court of Appeals upheld the EPA’s action to revoke the permit. In
addition, in July 2014 the D.C Circuit reversed a lower court’s decision and affirmed the EPA’s authority to adopt the Enhanced
Coordination Process governing coordination with the ACOE in the processing of CWA permits. The Court also rejected
challenges to EPA’s 2012 “Final Guidance” document regarding appropriate permit conditions, namely those affecting acceptable
conductivity limits (e.g., acceptable ionic strength to support aquatic life). However, the Court left it up to the states on whether
to adopt the guideline recommendations when issuing final NPDES permits. This decision has left coal mining permits in some
degree of uncertainty whether the EPA will concur with a state’s draft permit conditions should they not contain specified limits
regarding conductivity, further increasing operational uncertainty and costs.
The pace with which the government issues permits needed for new operations and for on-going operations to continue
coal mining has negatively impacted expected production. These delays or denials of coal mining permits could reduce our
production, cash flows and results of operations.
In addition, in 2005, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a technical guidance
document that imposes standards in the material mining permits that we hold relating to our Pennsylvania Operations, including
costly stream mitigation and monitoring requirements and alterations to our longwall mining plans.
Existing and future government laws, regulations and other legal requirements relating to protection of the
environment, and others that govern our business may increase our costs of doing business for coal and may restrict
our coal operations.
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We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities,
as well as foreign authorities relating to protection of the environment. These include those legal requirements that govern
discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup
of contaminated sites, groundwater quality and availability, threatened and endangered plant and wildlife protection, reclamation
and restoration of mining or drilling properties after mining or drilling is completed, the installation of various safety equipment
in our mines, remediation of impacts of surface subsidence from underground mining, and work practices related to employee
health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a
significant effect on our costs of operations and competitive position.
In addition, there is the possibility that we could incur substantial costs as a result of violations under environmental
laws. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as
well as foreign authorities or new interpretations of existing legal requirements by regulatory bodies relating to the protection of
the environment could further affect our costs of operations and competitive position. The Clean Water Act is being used by
opponents of mountain top removal mining as a means to challenge permits and bring citizen suits to make coal mining more
expensive. At CONSOL Energy’s subsidiary Fola Coal Company, LLC, six citizen suits have been filed challenging water
discharge permits. Two of those suits were settled in 2014, and at least two are potentially affected by recent settlements by
another mining operator in a similar case.
Existing and future government laws, regulations and other legal requirements relating to protection of the
environment, and others that govern our business may increase our costs of doing business for natural gas, and may
restrict our natural gas operations.
Regulations applicable to the natural gas industry are under constant review for amendment or expansion at the federal
and state level. Any future changes may affect, among other things, the pricing or marketing of natural gas production. For
example, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons,
particularly natural gas, from tight formations such as the Marcellus Shale. The process involves the injection of water, sand
and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically
regulated by state oil and gas commissions. Hydraulic fracturing is currently exempt from regulation under the federal Safe
Drinking Water Act, except for hydraulic fracturing using diesel fuel. The disposal of produced water, drilling fluids and other
wastes in underground injection disposal wells is regulated by the EPA under the federal Safe Drinking Water Act or by the states
under counterpart state laws and regulations. The imposition of new environmental initiatives and regulations could include
restrictions on our ability to conduct hydraulic fracturing operations or to dispose of waste resulting from such operations. The
EPA commenced a study of the potential environmental impacts of hydraulic fracturing activities and the final report was issued
in December 2016.
We are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit
requirements, or to use specific equipment, technologies or best management practices to control emissions. On August 16, 2012,
the U.S. Environmental Protection Agency (EPA) published final revisions to the New Source Performance Standards (NSPS)
to regulate emissions of volatile organic compounds (VOCs) and sulfur dioxide (SO2) from various oil and gas exploration,
production, processing and transportation facilities. Additionally, revisions were made to the National Emission Standards for
Hazardous Air Pollutants (NESHAPS) to further regulate emissions from the oil and natural gas production sector and the
transmission and storage of natural gas. Section 111 of the CAA authorized the EPA to develop technology based standards which
apply to specific categories of stationary sources. In September 2009, the EPA finalized the Mandatory Reporting of Greenhouse
Gas Rule. The current version of this rule requires annual reporting of emissions from natural gas wells, coal mines and associated
facilities.
The EPA has proposed to amend the Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse
Gas Reporting Program (GHGRP). This proposed rule would add reporting of greenhouse gas emissions from certain gathering
and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas
transmission pipelines. The rule would also require operators to utilize new monitoring equipment in order to comply with Subpart
W. On September 18, 2015, the EPA proposed updates to the New Source Performance Standards (NSPS) that would create new
standards for the regulation of methane and VOC emission sources. The proposed rule includes requirements for new fugitive
emission and leak detection testing and reporting requirements. On September 18, 2015, the EPA proposed the Source
Determination Rule which would clarify the use of the term “adjacent” in determining Title V air permitting requirements as
they apply to the oil and natural gas industry for major sources of air emissions. Other federal agencies are also examining
hydraulic fracturing, including the U.S. Department of Energy (DOE), the U.S. Government Accountability Office and the
Department of the Interior. Also, some states have adopted, and other states are considering adopting, regulations that could
restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. If hydraulic fracturing is
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regulated at the federal, state or local level, our fracturing activities could become subject to additional permit requirements or
operational restrictions and also to associated permitting delays and potential increases in costs.
Further, air emissions that stem from hydraulic fracturing and completions processes, as well as from midstream activities
such as the gathering and transmission of natural gas, are regulated by federal and state rules. However, interpretations of those
rules, as well as additional changes to the regulations, could negatively impact our ability to meet our stated production objectives
for the company. For example, source aggregation of air emissions to determine whether, under the Clean Air Act a source
comprises a single stationary source and is therefore a major source of air pollution, and thereby subject to the applicability of
Nonattainment Prevention of Significant Deterioration and Title V permitting requirements, has and continues to be debated by
the EPA, state regulatory agencies and the courts. Recently, the Pennsylvania Environmental Hearing Board determined the
emission sources of an upstream subsidiary and a midstream subsidiary of a company were aggregated as a single source, given
the dynamic nature of the issue. Federal and state activities, as well as court decisions could impact the development and
transmission of plans of CONSOL Energy, our joint venture partners, and gathering systems being installed and operated by
CONE Midstream Partners, LP.
Additionally, some states have begun to adopt more stringent regulation and oversight of natural gas gathering lines
than is currently required by federal standards. Pennsylvania, under Act 127, authorized the Public Utility Commission (PUC)
oversight of Class I gathering lines, as well as requiring standards and fees associated with Class II and Class III pipelines. The
state of Ohio also moved to regulate natural gas gathering lines in a similar manner pursuant to Ohio Senate Bill 315 (SB315).
SB315 expanded the Ohio PUC's authority over rural natural gas gathering lines. These changes in interpretation and regulation
affect CONSOL Energy's midstream activities, requiring changes in reporting, as well as increased costs.
Further, some state and local governments in the Marcellus Shale region in Pennsylvania and New York have considered
or imposed a temporary moratorium on drilling operations using hydraulic fracturing until further study of the potential for
environmental and human health impacts by the EPA or the relevant agencies are completed. Further, states could elect to prohibit
hydraulic fracturing altogether, as Governor Andrew Cuomo of the State of New York announced in December 2014 with regard
to fracturing activities in New York. No assurance can be given as to whether or not similar measures might be considered or
implemented in jurisdictions in which our gas properties are located. If new laws or regulations that significantly restrict or
otherwise impact hydraulic fracturing are passed by Congress or adopted in states in which we operate, such legal requirements
could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby could affect the determination
of whether a well is commercially viable. New laws or regulations could also cause delays or interruptions or terminations of
operations, the extent of which cannot be predicted, and could reduce the amount of oil and natural gas that we ultimately are
able to produce in commercially paying quantities from our natural gas properties, all of which could have a materially adverse
effect on our results of operations and financial condition.
On April 8, 2016, The U.S. Department of Transportation (DOT) Pipeline and Hazardous Materials Safety Administration
(PHMSA) published in the Federal Register a Notice of Proposed Rule Making (NPRM) that would significantly modify existing
regulations related to reporting, impact, design, construction, maintenance, operations and integrity management of natural gas
transmission and gathering pipelines. The proposed rule addresses four congressional mandates and six recommendations by the
National Transportation Safety Board to broaden the scope of safety coverage by adding new assessment and repair criteria for
gas transmission pipelines, and by expanding these protocols to include pipelines not formerly regulated by the federal standards.
This includes extending regulatory requirements to transmission and gathering pipelines of 8 inches and greater in rural class 1
areas. Compliance with the rule, as proposed, may prove challenging and costly for operators of older pipelines due to the difficulty
of locating historic records. Compliance could involve significant upfront costs and service disruptions. The relatively short 2-
year timeframe for compliance for gathering pipelines could also be difficult to meet. Costs of compliance with the proposed rule
could potentially affect shippers on pipelines as well as operators themselves, as the Federal Energy Regulatory Commission has
allowed many interstate transmission pipelines to pass along costs attributable to safety measures directly to shippers. If
implemented as proposed, CONSOL Energy (CONE & CNX Coal Resources) will be affected by this rulemaking. However, long-
term costs for compliance will be dependent on the finalized version of the rule.
Our shale gas drilling and production operations require both adequate sources of water to use in the fracturing
process, as well as the ability to dispose of water and other wastes after hydraulic fracturing. Our CBM gas drilling
and production operations also require the removal and disposal of water from the coal seams from which we produce
gas. If we cannot find adequate sources of water for our use or are unable to dispose of the water we use or remove
it from the strata at a reasonable cost and within applicable environmental rules, our ability to produce natural gas
economically and in commercial quantities could be impaired.
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As part of our drilling and production in shale formations, we use hydraulic fracturing processes. Thus, we need access
to adequate sources of water to use in our shale operations. Further, we must remove and dispose of the portion of the water that
we use to fracture our shale gas wells that flows back to the well-bore, as well as drilling fluids and other wastes associated with
the exploration, development or production of natural gas. In addition, in our CBM drilling and production, coal seams frequently
contain water that must be removed and disposed of in order for the natural gas to detach from the coal and flow to the well bore.
Our inability to locate sufficient amounts of water with respect to our shale operations, or the inability to dispose of or recycle
water and other wastes used in our shale and our CBM operations, could adversely impact our operations.
Our mines are subject to stringent federal and state safety regulations that increase our cost of doing business at
active operations and may place restrictions on our methods of operation. In addition, government inspectors under
certain circumstances, have the ability to order our operations to be shutdown based on safety considerations.
The Federal Coal Mine Safety and Health Act and Mine Improvement and New Emergency Response Act impose
stringent health and safety standards on mining operations. Regulations that have been adopted are comprehensive and affect
numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in mine
emergency procedures and other matters. Most states in which we operate have programs for mine safety and health regulation
and enforcement. The various requirements mandated by law or regulation can place restrictions on our methods of operations,
and potentially lead to fees and civil penalties for the violation of such requirements, creating a significant effect on operating
costs and productivity. In addition, government inspectors under certain circumstances, have the ability to order our operation
to be shutdown based on safety considerations. If an incident were to occur at one of our coal mines, it could be shut down for
an extended period of time and our reputation with our customers could be materially damaged.
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may
have environmental contamination, which could result in liabilities to us.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time.
Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred
to as “acid mine drainage.” We could become subject to claims for toxic torts, natural resource damages and other damages, as
well as for the investigation and clean-up of soil, surface water, groundwater, and other media. Such claims may arise, for example,
out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may
acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the
contamination or other damages, or for the entire share.
We maintain coal refuse areas and slurry impoundments at a number of our coal mining complexes. Such areas and
impoundments are subject to extensive regulation. Structural failure of a slurry impoundment or coal refuse area could result in
extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability
for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas,
which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we
could be subject to claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.
Our coal refuse areas and slurry impoundments are designed, constructed, and inspected by our company and by regulatory
authorities according to stringent environmental and safety standards.
In West Virginia there are areas where drainage from coal mining operations contains concentrations of selenium that
without treatment would result in violations of state water quality standards that are set to protect fish and other aquatic life. We
have several operations with selenium discharges. We and other coal companies have worked to expeditiously develop cost
effective means to remove selenium from mine water.
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to
hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us.
An example of this is Naturally Occurring Radioactive Material (NORM) or Technologically-Enhanced, Naturally Occurring
Radioactive Material (TENORM). NORM or TENORM is produced when activities such as deep drilling concentrate or expose
radioactive materials that occur naturally in ores, soils, water, or other natural materials. State and federal agencies are examining
the possibility for worker exposure or associated environmental hazards due to processing and disposal of wastes containing
NORM or TENORM, as well as silica dust associated with natural gas well completions activities.
We have reclamation, mine closing and gas well plugging obligations. If the assumptions underlying our accruals
are inaccurate, we could be required to expend greater amounts than anticipated.
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The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all our
coal mining operations. Also, state laws require us to plug natural gas wells and reclaim well sites after the useful life of our
natural gas wells has ended. We accrue for the costs of current mine disturbance, gas well plugging and of final mine closure,
including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing liabilities
and gas well plugging, which are based upon permit requirements and our experience, were approximately $474 million at December
31, 2016. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs, estimated
proved reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. If
these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results
could be adversely affected.
Most states where we operate require us to post bonds for the full cost of coal mine reclamation (full cost bonding).
West Virginia is not a full cost bonding state. West Virginia has an alternative bond system (ABS) for coal mine reclamation
which consists of (i) individual site bonds posted by the permittee that are less than the full estimated reclamation cost plus (ii) a
bond pool (Special Reclamation Fund) funded by a per ton fee on coal mined in the State which is used to supplement the site
specific bonds if needed in the event of bond forfeiture. In an effort to settle a citizen suit filed in 2012 before the U.S. District
Court in West Virginia related to the Special Reclamation Fund being underfunded the WV legislature authorized an increase in
the per ton fee levied on coal production to make up the shortfall. The Special Reclamation Fund became fully funded in June of
2016. There remains the possibility that WV may move to full cost bonding in the future which could cause individual mining
companies and/or surety companies to exceed bonding capacity and would result in the need to post cash bonds or letters of credit
which would reduce operating capital.
Pennsylvania is expanding its full cost bonding program to cover all coal mine bonding, further increasing the amount
of surety bonds we must seek in order to permit its mining activities.
We have been able to post surety bonds with the states to secure our reclamation obligations. If our creditworthiness
declines, states may seek to require us to post letters of credit or cash collateral to secure those obligations, or we may be unable
to obtain surety bonds, in which case we would be required to post letters of credit. Additionally, the sureties that post bonds on
our behalf may require us to post security in order to secure the obligations underlying these bonds. Posting letters of credit in
place of surety bonds or posting security to support these surety bonds would have an adverse effect on our liquidity.
We face uncertainties in estimating our economically recoverable natural gas and coal reserves, and inaccuracies
in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.
Natural gas and coal reserves are economically recoverable when the price at which they are expected to be sold exceeds
their expected cost of production and selling.
Natural gas reserves require subjective estimates of underground accumulations of natural gas assumptions concerning
natural gas prices, production levels, reserve estimates and operating and development costs. As a result, estimated quantities of
proved natural gas reserves and projections of future production rates and the timing of development expenditures may be
incorrect. For example, a significant amount of our proved undeveloped reserves extensions and discoveries during the last three
years were due to the addition of wells on our Marcellus Shale acreage more than one offset location away from existing production
with reliable technology, which may be more susceptible to positive and negative changes in reserve estimates than our proved
developed reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual
drilling, testing and production. Also, we make certain assumptions regarding natural gas prices, production levels, and operating
and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly
affect our estimates of our natural gas reserves, the economically recoverable quantities of natural gas attributable to any particular
group of properties, the classifications of natural gas reserves based on risk of recovery and estimates of the future net cash flows.
Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in
the actual quantities of natural gas we ultimately recover being different from reserve estimates. The present value of future net
cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves.
We base the estimated discounted future net cash flows from our proved natural gas reserves on historical average prices and
costs. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:
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geological conditions;
changes in governmental regulations and taxation;
the amount and timing of actual production;
assumptions governing future prices;
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future operating costs; and
capital costs of drilling, completion and gathering assets.
The timing of both our production and our incurrence of expenses in connection with the development and production
of natural gas properties will affect the timing of actual future net cash flows from proved reserves and thus their actual present
value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate
discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry
in general. If natural gas prices decline by $0.10 per Mcf, then the pre-tax present value using a 10% discount rate of our proved
natural gas reserves as of December 31, 2016 would decrease from $1.6 billion to $1.4 billion.
We base our coal reserve information on geologic data, coal ownership information and current and proposed mine
plans. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or
mining data. Similar to natural gas reserves, there are uncertainties inherent in estimating quantities and values of economically
recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal
reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and
geological data assembled and analyzed by our staff. Some of the factors and assumptions which impact economically recoverable
coal reserve estimates include:
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geologic conditions;
historical production from the area compared with production from other producing areas;
the assumed effects of regulations and taxes by governmental agencies;
our ability to obtain, maintain and renew all required permits;
future improvements in mining technology;
assumptions governing future prices; and
future operating costs, including the cost of materials and capital expenditures.
In addition, we hold substantial coal reserves in areas containing Marcellus Shale and other shales. These areas are
currently the subject of substantial exploration for oil and natural gas, particularly by horizontal drilling. If a natural gas well is
in the path of our mining for coal, we may not be able to mine through the well unless we purchase it. Although in the past we
have purchased vertical wells, the cost of purchasing a producing horizontal well could be substantially greater. Horizontal wells
with multiple laterals extending from the well pad may access larger natural gas reserves than a vertical well which could result
in higher costs. In future years, the cost associated with purchasing natural gas wells which are in the path of our coal mining
may make mining through those wells uneconomical thereby effectively causing a loss of significant portions of our coal reserves.
Each of the factors which impacts reserve estimation may in fact vary considerably from the assumptions used in estimating
the reserves. For these reasons, estimates of natural gas and coal reserves may vary substantially. Actual production, revenues and
expenditures with respect to our coal and natural gas reserves will likely vary from estimates, and these variances may be material.
As a result, our estimates may not accurately reflect our actual coal and natural gas reserves
Defects may exist in our chain of title for our natural gas estate or undeveloped coal reserves where we have not
done a thorough chain of title examination of our natural gas estate or undeveloped coal reserves. We may incur
additional costs and delays to produce natural gas or mine coal because we have to acquire additional property rights
to perfect our title to natural gas or coal rights. If we fail to acquire additional property rights to perfect our title to
natural gas or coal rights, we may have to reduce our estimated reserves.
Substantial amounts of acreage in which we believe we control natural gas rights are in areas where we have not yet
done a thorough chain of title examination of the natural gas estate. A number of our natural gas properties were acquired primarily
for the coal rights with the focus on the coal estate title, and, in many cases were acquired years ago. In addition, we have acquired
natural gas rights in substantial acreage from third parties who had not performed thorough chain of title work on their natural
gas properties. Our practice, and we believe industry practice, is not to perform a thorough title examination on natural gas
properties until shortly before the commencement of drilling activities at which time we seek to acquire any additional rights
needed to perfect our ownership of the natural gas estate for development and production purposes. When we perform a thorough
chain of title examination, we may discover material defects in our title which would require us to acquire additional property
rights. We may incur substantial costs to acquire these additional property rights. In addition, the acquisition of the necessary
rights may not be feasible in some cases. Our discovering of title defects which we are unable to cure may adversely impact our
ability to develop those properties and we may have to reduce our estimated natural gas reserves including our proved undeveloped
reserves.
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Some states (West Virginia and Virginia) permit us to produce coalbed methane gas without perfected ownership under
an administrative process known as “pooling,” which requires us to give notice to all potential claimants and pay royalties into
escrow until the undetermined rights are resolved. As a result, we may have to pay royalties to produce coalbed methane gas on
acreage that we control and these costs may be material. Further, the pooling process is time-consuming and may delay our
drilling program in the affected areas.
Likewise, title to most of our owned or leased properties and mineral rights is not usually verified until we make a
commitment to mine a property, which may not occur until after we have obtained necessary permits and completed exploration
of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantor's.
Our right to mine certain of our reserves has in the past been, and may again in the future be, adversely affected if defects in title,
boundaries or other rights necessary for mining exist or if a lease expires. Any challenge to our title or leasehold interests could
delay the mining of the property and could ultimately result in the loss of some or all of our interest in the property. From time
to time we also may be in default with respect to leases for properties on which we have mining operations. In such events, we
may have to close down or significantly alter the sequence of such mining operations which may adversely affect our future coal
production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining and
be subject to regulatory sanction and penalties.
In order to obtain, maintain or renew leases or mining contracts to conduct our mining operations on property where
these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate
new leases or mining contracts for properties containing additional reserves, or maintain our leasehold interests in properties
where we have not commenced mining operations during the term of the lease. As a result, our results of operations, business
and financial condition may be materially adversely affected.
CONSOL Energy and its subsidiaries are subject to various legal proceedings, which may have an adverse effect on
our business.
We are party to a number of legal proceedings in the normal course of business activities. Defending these actions,
especially purported class actions, can be costly, and can distract management. For example, we are a defendant in three pending
purported class action lawsuits dealing with claimants’ alleged entitlements to, and accounting for, natural gas royalties. There is
the potential that the costs of defending litigation in an individual matter or the aggregation of many matters could have an adverse
effect on our cash flows, results of operations or financial position. See Note 22- Commitments and Contingent Liabilities in the
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal
proceedings.
We have obligations for long-term employee benefits for which we accrue based upon assumptions which, if
inaccurate, could result in our being required to expense greater amounts than anticipated.
We provide various long-term employee benefits to inactive and retired employees. We accrue amounts for these
obligations. At December 31, 2016, the current and non-current portions of these obligations included:
• postretirement medical and life insurance ($700 million);
• coal workers' black lung benefits ($119 million);
• salaried retirement benefits ($115 million); and
• workers' compensation ($80 million).
However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Salary
retirement benefits are funded in accordance with Employer Retirement Income Security Act of 1974 (ERISA) regulations. The
other obligations are unfunded. In addition, the federal government and several states in which we operate consider changes in
workers' compensation and black lung laws from time to time. Such changes, if enacted, could increase our benefit expense and
our collateral requirements. We post letters of credit and surety bonds as collateral for some of these liabilities that reduce our
profitability and liquidity.
We do not control the timing of divestitures that we plan to engage in and they may not provide anticipated benefits.
Additionally, we may be unable to acquire additional properties in the future and any acquired properties may not
provide the anticipated benefits.
Our business and financing plans include divesting certain assets over time. However, we do not control the timing of
divestitures and delays in entering into divestitures may reduce the benefits from them. Additionally, if assets are held jointly with
another party, we may not be permitted to dispose of these assets without the consent of our joint venture partner. Also, there can
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be no assurance that the assets we divest will produce anticipated proceeds. In addition, the terms of divestitures may cause a
substantial portion of the benefits we anticipate receiving from them to be subject to future matters that we do not control.
In the future we may make acquisitions of businesses that complement or expand our current business. No assurance can
be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for
acquisitions on acceptable terms or successfully acquire the identified targets. The success of any completed acquisition will
depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired
businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.
Our failure to make acquisitions in the future and successfully integrate the acquired businesses and assets into our existing
operations could have a material adverse effect on our financial condition and results of operations
We may operate a material portion of our business with one or more joint venture partners. A joint venture may restrict
our operational and corporate flexibility; actions taken by a joint venture partner may materially impact our financial
position and results of operations; and we may not realize the benefits we expect to realize from a joint venture.
As is common in the industry we may operate one or more of our properties with a joint venture partner. These joint
ventures could require us to share operational and other control with our joint venture partner, such that we may no longer have
the flexibility to control completely the development of these properties. If we do not timely meet our financial commitments in
a joint venture, our rights to participate in such joint venture will be adversely affected and the other party to the joint venture may
have a right to acquire a share of our interest in such joint venture proportionate to, and in satisfaction of, our unmet financial
obligations. If our joint venture partner is unable or fails to pay its portion of development costs, our costs of operations could be
increased and it could result loss of rights to develop the properties held by that joint venture. We could also incur liability as a
result of actions taken by our joint venture partner. Disputes between us and our joint venture partner may result in litigation or
arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their
time and effort on our business.
The provisions of our debt agreements and the risks associated with our debt could adversely affect our business,
financial condition, liquidity and results of operations.
As of December 31, 2016, our total long-term indebtedness was approximately $2.80 billion of which approximately
$1.85 billion was under our 5.875% senior unsecured notes due 2022 plus $5 million of unamortized bond premium, $500 million
was under our 8.000% senior unsecured notes due 2023 less $6 million of unamortized bond discount, $74 million was under our
8.250% senior unsecured notes due 2020, $21 million was under our 6.375% senior unsecured notes due 2021, $103 million was
under our Maryland Economic Development Corporation Port Facilities Refunding Revenue Bonds (MEDCO) 5.75% revenue
bonds due September 2025, $49 million of capitalized leases due through 2021, $5 million of miscellaneous debt and $201 million
in outstanding borrowings under the revolver for CNXC of which we are not a guarantor. The degree to which we are leveraged
could have important consequences, including, but not limited to:
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increasing our vulnerability to general adverse economic and industry conditions;
requiring us to dedicate a substantial portion of our cash flow from operations to the payment of interest and
principal due under our outstanding debt, which will limit our ability to obtain additional financing to fund future
working capital, capital expenditures, acquisitions, development of our gas and coal reserves or other general
corporate requirements;
limiting our flexibility in planning for, or reacting to, changes in our business and in the coal and natural gas
industries;
placing us at a competitive disadvantage compared to our competitors with lower leverage and better access to
capital resources; and
limiting our ability to implement our business strategy.
Our senior secured credit facility and the indentures governing our 5.875% and 8.000% senior unsecured notes limit the
incurrence of additional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreement
and the indentures governing our 5.875% and 8.000% senior unsecured notes subject us to financial and/or other restrictive
covenants. Under our senior secured credit agreement, we must comply with certain financial covenants on a quarterly basis
including a minimum interest coverage ratio, and a minimum current ratio, as defined therein. Our senior secured credit agreement
and the indentures governing our 5.875% and 8.000% senior unsecured notes impose a number of restrictions upon us, such as
restrictions on granting liens on our assets, making investments, paying dividends, stock repurchases, selling assets and engaging
in acquisitions. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could
have a material adverse effect on us.
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If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell
assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful
and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we
could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt
service and other obligations. Our senior secured credit agreement and the indentures governing our 5.875% and 8.000% senior
unsecured notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those
sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service
obligations then due.
Unless we replace our natural gas reserves, our natural gas reserves and production will decline, which would
adversely affect our business, financial condition, results of operations, liquidity and cash flows.
Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon
reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at
December 31, 2016, production is expected to decline even if those proved undeveloped reserves are developed and the wells
produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we
have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore,
our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and
economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional
reserves to replace our current and future production at acceptable costs.
Our lenders use the loan value of our proved natural gas reserves to determine the borrowing base under our $2.0
billion senior secured credit facility. Our borrowing base could decrease for a variety of reasons including lower
natural gas prices, declines in natural gas proved reserves, and lending requirements or regulations. Significant
reductions in our borrowing base below $2.0 billion could have a material adverse effect on our results of operations,
financial condition and liquidity.
Our ability to borrow and have letters of credit issued under our $2.0 billion senior secured credit facility is generally
limited to a borrowing base. Our borrowing base is determined by the required number of lenders in good faith calculating a loan
value of the Company’s proved natural gas reserves. The borrowing base under our senior secured credit facility is currently $2.0
billion. Our borrowing base is redetermined by the lenders twice per year, and the next scheduled borrowing base redetermination
is expected to occur in May 2017. The various matters which we describe in other risk factors that can decrease our proved natural
gas reserves including lower natural gas prices, operating difficulties, and failure to replace our proved reserves could decrease
our borrowing base. Please read: “Risk Factors - We face uncertainties in estimating our economically recoverable natural gas and
coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and
decreased profitability” and - “Unless we replace our natural gas reserves, our natural gas reserves and production will decline,
which would adversely affect our business, financial condition, results of operations and cash flows.” Our borrowing base could
also decrease as a result of new lending requirements or regulations or the issuance of new indebtedness. If our borrowing base
declined significantly below $2.0 billion, we may be unable to implement our drilling and development plans, make acquisitions
or otherwise carry out our business plan which could have a material adverse effect on our financial condition and results of
operation. We also could be required to repay any indebtedness in excess of the redetermined borrowing base. We could face
substantial liquidity problems, might not be able to access the equity or debt capital markets and might be required to sell material
assets or operations to attempt to meet our debt service and other obligations. We may not be able to consummate those sales or
to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service
obligations then due.
Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.
To manage our exposure to fluctuations in the price of natural gas, we enter into hedging arrangements with respect to a
portion of our expected production. As of January 17, 2017, we had hedges on approximately 311.3 Bcf of our 2017 natural gas
production, 220.6 Bcf of our 2018 natural gas production, 161.7 Bcf of our 2019 natural gas production, 85.0 Bcf of our 2020 and
natural gas production and 6.8 Bcf of our 2021 and natural gas production. To the extent that we engage in hedging activities, we
may be prevented from realizing the near-term benefits of price increases above the levels of the hedges. If we choose not to engage
in, or reduce our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas prices
than our competitors who engage in hedging arrangements to a greater extent than we do.
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In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in
which:
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our production is less than expected;
the counterparties to our contracts fail to perform the contracts;
the creditworthiness of our counterparties or their guarantors is substantially impaired;
counterparties have credit limits that may constrain our ability to hedge additional volumes.
Changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling
costs, could cause our financial position and profitability to deteriorate.
The passage of legislation or any other similar changes in U.S. federal income tax law could eliminate or postpone
certain tax deductions that are currently available with respect to natural gas, oil or coal exploration and development. Any such
change could negatively affect our financial condition and results of operations.
Additionally, legislation has been proposed in Ohio and Pennsylvania to introduce a new severance tax on the oil and
gas industry. The proposed rates have varied from 2.5 - 7.5 percent and would represent a significant increased financial burden
on the economics of the wells we drill in these states.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are
challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may
adversely affect our financial condition. Additionally, our development and exploration projects require substantial
capital expenditures and if we fail to obtain required capital or financing on satisfactory terms, our natural gas
reserves may decline.
Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing
our business plan, we consider allocating capital and other resources to various aspects of our businesses including well
development (primarily drilling), reserve acquisitions, exploratory activity, coal development, corporate items and other
alternatives. We also consider our likely sources of capital, including cash generated from operations and borrowings under our
credit facilities. Notwithstanding the determinations made in the development of our business plan, business opportunities not
previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify
optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other
resources in furtherance of our business strategies, our financial condition and future growth may be adversely affected. Moreover,
economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or
respond to those changes may limit our ability to achieve our objectives.
As part of our strategic determinations, we expect to continue to make substantial capital expenditures in the development
and acquisition of natural gas reserves. We cannot assure you that we will have sufficient cash from operations, borrowing capacity
under our credit facilities or the ability to raise additional funds in the capital markets. If cash flow generated by our operations
or available borrowings under our credit facilities are not sufficient to meet our capital requirements, or we are unable to obtain
additional financing, we could be required to curtail the pace of the development of our natural gas properties, which in turn
could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of
operations.
Any failure by Murray Energy to satisfy the liabilities it assumed from us, as well as to perform its obligations under
various agreements whose performance by Murray Energy we guaranteed, or under various agreements with us,
could materially increase our liabilities and materially adversely affect our results of operations, financial position
and cash flows.
In 2013, Murray Energy and its subsidiaries (Murray Energy) acquired approximately $2.4 billion of liabilities which
had been reflected on our books. The consolidated balance sheet liabilities at the time of sale were comprised of approximately
$2.1 billion of OPEB and other liabilities. In addition to these assumed liabilities, (i) Murray Energy acquired our obligations to
make payments per hour worked to the multi-employer defined benefit pension plan for United Mine Workers of America (1974
Pension Plan), (ii) we guaranteed performance by Murray Energy under various West Virginia and Pennsylvania operational
surety bonds and workers compensation obligations, under various equipment leases and to reclaim an impoundment site, (iii)
we leased or subleased various mining equipment to Murray Energy, and (iv) we guaranteed performance by Murray Energy of
certain coal supply agreements that Murray Energy acquired in the transaction. At the time of sale, if the hourly payment obligations
acquired by Murray Energy to the 1974 Pension Plan were to be capitalized, they would have had a present value of approximately
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$941 million, assuming a discount rate of 4.02%.We believe our maximum estimated exposure under our Murray Energy
guarantees as of December 31, 2016 was approximately $74 million. The leases and subleases we entered into with Murray
Energy relate to approximately $106 million of equipment. Murray Energy is primarily liable for the acquired retiree medical
liabilities under the Coal Industry Retiree Health Benefits Act of 1992, which we call the Coal Act, but CONSOL Energy remains
secondarily liable. At the time of the sale, the Coal Act liabilities Murray Energy acquired were approximately $307 million and
it was estimated that the servicing cost for these liabilities would be approximately $26 million for 2017 and would decline
thereafter since the beneficiaries principally are miners who retired prior to 1994. On November 12, 2013, in connection with
the transaction, Moody’s assigned Murray Energy a family credit rating of B3 (speculative and subject to high credit risk) and
its secured second lien notes due 2021 a rating of Caa1 (poor standing and subject to very high credit risk). Since the transaction,
Murray Energy’s credit ratings have been downgraded by Moody’s. In November, 2016, Moody’s upgraded Murray Energy to
a family credit rating of Caa2 and the rating on its secured second lien notes to Caa3 with a stable outlook. Any failure by Murray
Energy to satisfy these assumed liabilities or perform under these agreements could result in substantial claims against us by
third-parties and if, successful, could materially adversely affect our results of operations, financial position and cash flows. In
addition, we regularly evaluate the likelihood of default by Murray Energy under the guarantees we have provided. The results
of the evaluation may materially impact our results of operations. If Murray Energy defaults under the obligations we guaranteed,
our cash flows may also be materially impacted.
Terrorist attacks or a cyber incident could result in information theft, data corruption, operational disruption and/
or financial loss.
We have become increasingly dependent upon digital technologies, including information systems, infrastructure and
cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with
our employees and business partners, analyze seismic and drilling information, estimate quantities of natural gas reserves and
coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater
risk of future physical attacks by terrorists or cyber attacks than other targets in the United States. Deliberate attacks on our assets,
or security breaches in our systems or infrastructure, or the systems or infrastructure of third-parties, or the cloud could lead to
corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing
and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions,
other operational disruptions and third -party liability. Our insurance may not protect us against such occurrences. Consequently,
it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business,
financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to expend
additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability
to cyber incidents.
A substantial majority of sales of thermal coal are from three mines at one location in Pennsylvania, making us
vulnerable to risks associated with operating in a single geographic area.
The substantial majority of our sales of thermal coal, as well as our thermal coal reserves, are from our Bailey Mine,
Enlow Fork Mine and HarveyMine located in Greene County, Pennsylvania. In addition, we also rely upon one coal processing
plant and rail load facility, located in Enon, Pennsylvania for shipping coal from all of these mines. Any disruption in the functioning
of this coal processing plant and rail load-out facility such as the structural failure at the above ground conveyor system which
occurred in 2012 or in transportation in this area could significantly reduce our sales of thermal coal and adversely affect our
results of operation and financial condition.
Certain provisions in our multi-year coal sales contracts may provide limited protection during adverse economic
conditions, may result in economic penalties to us or permit the customer to terminate the contract.
Price adjustment, “price reopener” and other similar provisions in our multi-year coal sales contracts may reduce the
protection from coal price volatility traditionally provided by coal supply contracts. Price reopener provisions are present in
several of our multi-year coal sales contracts. These price reopener provisions may automatically set a new price based on
prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range of
prices. In a limited number of agreements, failure of the parties to agree on a price under a price reopener provision can lead to
termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect
our profitability.
Most of our coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal
quality characteristics such as heat content, sulfur, ash, moisture, volatile matter, grindability, ash fusion temperature and size
consist. Failure to meet these conditions could result in penalties or rejection of the coal at the election of the customer. Our coal
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sales contracts also typically contain force majeure provisions allowing for the suspension of performance by either party for the
duration of specified events. Force majeure events include, but are not limited to, floods, earthquakes, storms, fire, faults in the
coal seam or other geologic conditions, other natural catastrophes, wars, terrorist acts, civil disturbances or disobedience, strikes,
railroad transportation delays caused by a force majeure event and actions or restraints by court order and governmental authority
or arbitration award. Depending on the language of the contract, some contracts may terminate upon continuance of an event of
force majeure that extends for a period greater than three to twelve months and some contracts may obligate us to perform
notwithstanding what would typically be a force majeur event.
The majority our common units in CNX Coal Resources LP and CONE Midstream Partners LP are subordinated to
other common units and we may not receive distributions from CNX Coal Resources LP or CONE Midstream Partners
LP.
As of December 31, 2016, we hold 11.6 million subordinated units (representing a 42.7 percent limited partnership
interest) in CNX Coal Resources LP, which we call CNXC. The balance of our CNXC limited partnership interests are held in
the form of preferred and common units. Subordinated units are not entitled to any distribution from CNXC unless CNXC makes
a minimum quarterly distribution of $0.4678 per Class A Preferred Unit and $0.5125 per common unit. CNXC made minimum
distributions per subordinated unit equal to the distribution per common unit for five of the six quarters since CNXC’s IPO.
CNXC did not met the requirement for a subordinated unit distribution with respect to fiscal quarter ended June 30, 2016 and
we did not receive a distribution per subordinated unit, however, CNXC was able to make minimum distributions per subordinated
unit equal to the distribution per common unit with respect to the fiscal quarter ended September 30, 2016 and declared minimum
distributions per subordinated unit equal to the distribution per common unit with respect to the fiscal quarter ended December
31, 2016. We cannot assure you that CNXC will continue to be able to make or will make the required minimum quarterly
distribution on its preferred and common units or that we will receive any future distributions on our subordinated units. Failure
by CNXC to make distributions to us on our subordinated units could adversely affect our liquidity.
We hold 14.6 million subordinated units (representing 23.0 percent limited partnership interest) in CONE Midstream
Partners LP, which we call CONE. The balance of CONE's limited partnership interests are held either by NOBLE Energy or in
the form of common units. Subordinated units are not entitled to any distribution from CONE unless CONE makes a minimum
quarterly distribution on its common units of $0.2125 per unit. CONE has met this requirement with respect to each of its fiscal
quarters and we received a distribution per subordinated unit equal to the distribution per common unit. However, we cannot
assure you that CONE will continue to be able to make or will make the required minimum quarterly distribution on its common
units or that we will receive any future distributions on our subordinated units. Failure by CONE to make distributions to us on
our subordinated units could adversely affect our liquidity.
ITEM 1B.
Unresolved Staff Comments
None.
ITEM 2.
Properties
See “E&P Operations” and “Coal Operations” in Item 1 of this 10-K for a description of CONSOL Energy's properties.
ITEM 3.
Legal Proceedings
The first through the seventh paragraphs of Note 22–Commitments and Contingent Liabilities in the Notes to the Audited
Consolidated Financial Statements in Item 8 of this Form 10-K are incorporated herein by reference.
ITEM 4.
Mine Safety and Health Administration Safety Data
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank
Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this annual report.
48
PART II
ITEM 5.
Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of
Equity Securities
The Company's common stock is listed on the New York Stock Exchange under the symbol CNX. The following table sets
forth, for the periods indicated, the range of high and low sales prices per share of our common stock as reported on the New York
Stock Exchange and the cash dividends declared on the common stock for the periods indicated:
Year Period Ended December 31, 2016
Quarter Ended March 31, 2016
Quarter Ended June 30, 2016
Quarter Ended September 30, 2016
Quarter Ended December 31, 2016
Year Period Ended December 31, 2015
Quarter Ended March 31, 2015
Quarter Ended June 30, 2015
Quarter Ended September 30, 2015
Quarter Ended December 31, 2015
High
Low
Dividends
$ 12.42
$ 16.40
$ 19.76
$ 22.34
4.54
$
$ 10.53
$ 15.03
$ 16.14
$ 34.56
$ 34.14
$ 22.04
$ 11.99
$ 26.11
$ 21.44
9.29
$
6.30
$
$
$
$
$
$
$
$
$
0.0100
—
—
—
0.0625
0.0625
0.0100
0.0100
As of December 31, 2016, there were 127 holders of record of our common stock.
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the
common stock of CONSOL Energy to the cumulative shareholder return for the same period of a peer group and the Standard &
Poor's 500 Stock Index. The peer group is comprised of CONSOL Energy, Arch Coal Inc., Chesapeake Energy Corp., Devon
Energy Corp., EOG Resources Inc., Noble Energy Inc., Peabody Energy Corp., Southwestern Energy Co., QEP Resources Inc.,
WPX Energy, Inc., Teck Resources Limited, EQT, Range Resources Corp., Cabot Oil & Gas Corp., and Antero Resources Corp.
The graph assumes that the value of the investment in CONSOL Energy common stock and each index was $100 at December 31,
2011. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2016.
CONSOL Energy Inc.
Peer Group
S&P 500 Stock Index
2011
2012
2013
2014
2015
2016
100.0
100.0
100.0
88.1
96.8
111.4
103.4
111.0
144.4
91.7
76.5
21.7
35.0
49.1
87.3
160.8
159.7
174.9
49
Cumulative Total Shareholder Return Among CONSOL Energy Inc., Peer Group and S&P 500 Stock Index
Stock Performance Graph
200.00
180.00
160.00
140.00
120.00
100.00
100.00
80.00
60.00
40.00
20.00
0.00
2011
CNX
S&P 500
Peer Group
2012
2013
2014
2015
2016
Year
The above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).
The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of
Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy suspended its
quarterly dividend following the sale of the Buchanan Mine on March 31, 2016 to further reflect the Company's increased emphasis
on growth. CONSOL Energy’s Board of Directors determines whether dividends will be paid quarterly. The determination to pay
dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual
and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and
such other factors as the Board of Directors deems relevant. The Company's credit facility limits CONSOL Energy's ability to pay
dividends in excess of an annual rate of $0.50 per share when the Company's leverage ratio exceeds 3.50 to 1.00 and subject to
an aggregate amount up to the then cumulative credit calculation. The total leverage ratio was 4.53 to 1.00 and the cumulative
credit was approximately $781 million at December 31, 2016. The calculation of this ratio excludes CNXC. The credit facility
does not permit dividend payments in the event of default. The indentures to the 2022 and 2023 notes limit dividends to $0.50 per
share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other
payment limitations under the indentures. There were no defaults in the year ended December 31, 2016.
See Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters”
for information relating to CONSOL Energy's equity compensation plans.
50
ITEM 6.
Selected Financial Data
The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the
periods indicated. The selected consolidated financial data for, and as of the end of, each of the years ended December 31, 2016,
2015, 2014, 2013 and 2012 are derived from our audited Consolidated Financial Statements. Certain reclassifications of prior year
data have been made to conform to the year ended December 31, 2016 presentation. The selected consolidated financial and
operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated
financial and operating data should be read in conjunction with Item 7 “Management's Discussion and Analysis of Financial
Condition and Results of Operations” and the financial statements and related notes included in this Annual Report.
(Dollars in thousands, except per share data)
Operating revenues from Continuing Operations
(Loss) Income from Continuing Operations
Net (Loss) Income Attributable to CONSOL
Energy Inc. Shareholders
Earnings (Loss) per share:
Basic:
(Loss) Income from Continuing Operations
(Loss) Income from Discontinued Operations
Net (Loss) Income
Dilutive:
(Loss) Income from Continuing Operations
(Loss) Income from Discontinued Operations
Net (Loss) Income
2016
$ 1,839,571
$ (535,965) $ (350,266) $
For the Years Ended December 31,
2015
2013
2014
$ 2,400,187
$ 2,953,365
$ 2,474,815
$
164,947
(16,393) $
2012
$ 2,387,093
245,663
$ (848,102) $ (374,885) $
163,090
$
660,442
$
388,470
$
$
$
$
(2.38) $
(1.32)
(3.70) $
(2.38) $
(1.32)
(3.70) $
(1.57) $
(0.07)
(1.64) $
(1.57) $
(0.07)
(1.64) $
0.72
(0.01)
0.71
0.71
(0.01)
0.70
$
$
$
$
(0.07) $
2.96
2.89
$
(.07) $
2.94
2.87
$
1.08
0.63
1.71
1.07
0.63
1.70
Assets from Continuing Operations
Assets from Discontinued Operations
Total Assets
$ 9,183,898
83
$ 9,183,981
$ 9,908,082
1,021,820
$10,929,902
$10,645,099
1,009,546
$11,654,645
$10,105,731
1,042,204
$11,147,935
$ 8,593,069
3,770,061
$12,363,130
Long-Term Debt from Continuing Operations
(including current portion)
$ 2,774,069
$ 3,700,192
$ 3,247,407
$ 3,137,522
$ 3,140,656
Long-Term Debt from Discontinued Operations
—
(including current portion)
Total Long-Term Debt (including current portion) $ 2,774,069
Cash Dividends Declared Per Share of Common
Stock
See Item 1A, “Risk Factors” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”
for a discussion of an adjustment to operating revenues for all periods and other matters that affect the comparability of the selected
financial data as well as uncertainties that might affect the Company’s future financial condition.
5,640
$ 3,146,296
3,171
$ 3,250,578
3,063
$ 3,140,585
6,665
$ 3,706,857
0.625
0.375
0.250
0.010
0.145
$
$
$
$
$
51
OTHER OPERATING DATA
(unaudited)
Gas:
Net sales volumes produced (in Bcfe)
Average sales price ($ per Mcfe) (A)
Average cost ($ per Mcfe)
Proved reserves (in Bcfe) (B)
Coal:
Tons sold from continuing operations (in thousands)
Tons produced from continuing operations (in thousands)
Average sales price of tons produced ($ per ton produced)
Average Cost of Goods Sold ($ per ton produced)
Recoverable coal reserves (tons in millions) (C)
Number of active mining complexes (at end of period)
2016
394.4
2.63
2.32
6,252
24,604
24,666
43.31
34.35
2,361
1
$
$
$
$
Years Ended December 31,
2013
2014
2015
2012
$
$
$
$
328.7
2.81
2.62
5,643
22,873
22,790
56.36
41.78
3,047
1
$
$
$
$
235.7
4.37
3.13
6,828
26,133
26,066
61.88
43.63
3,238
1
$
$
$
$
172.4
4.30
3.42
5,731
21,230
21,433
63.93
44.53
3,032
1
$
$
$
$
156.3
4.22
3.28
3,993
19,570
19,582
67.67
44.62
4,229
1
____________
(A) Represents average net sales price including the effect of derivative transactions.
(B) Represents proved developed and undeveloped gas reserves at period end.
(C) Represents proven and probable coal reserves at period end, including discontinued operations and excluding equity
affiliates.
52
ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
General
2016 Highlights
• Record total gas production of 394.4 Bcfe in 2016, 20.0% higher than 2015.
• Record Marcellus Shale production of 212.5 Bcfe in 2016, 23.3% higher than 2015.
• Record Utica Shale production of 90.8 Bcfe in 2016, 61.6% higher than 2015.
•
•
•
•
In March 2016, CONSOL Energy completed the sale of its membership interests in CONSOL Buchanan Mining
Company, LLC (BMC), which owned and operated the Buchanan Mine located in Mavisdale, Virginia, various
assets relating to the Amonate Mining Complex located in Amonate, Virginia; and various coal reserves. Cash
proceeds of $402,799 were received at closing.
In August 2016, CONSOL Energy completed the sale of its Miller Creek Mining Complex and Fola Mining
Complex subsidiaries. CONSOL Energy paid $28,271 of cash at closing. In addition, CONSOL Energy will pay a
total of $17,200 in installments over the next four years.
In November 2016, cash proceeds of $70,000 were received in connection with our equity affiliate CONE Midstream
Partners LP acquiring an additional 25% interest in CONE Midstream DevCo I LP, commonly referred to as the
“Anchor Systems.”
In December 2016, with an effective date of October 1, 2016, CONSOL Energy terminated the 50-50 Joint Venture
that was formed in 2011, with Noble Energy, Inc., for the exploration, development, and operation of primarily
Marcellus Shale properties in Pennsylvania and West Virginia. Highlights include: each party will own and operate
a 100% interest in its properties and wells in two separate operating areas; each party will have independent control
and flexibility with respect to the scope and timing of future development over its operating area; and all acreage
operated by CONSOL Energy and Noble Energy, Inc. in their respective operating areas will remain fully dedicated
to CONE Midstream Partners LP. Cash proceeds of $213,295 were received at closing.
• Gas production costs continue to decline - for the year ended December 31, 2016, total gas production costs were
$2.32 per Mcfe, an 11.5% decline from the prior year.
• Made payments on the senior secured credit facility of $952,000, resulting in zero drawings at the end of 2016,
increasing liquidity.
2017 Outlook:
• Our 2017 annual gas production is expected to increase to approximately 415 Bcfe.
• Our 2017 E&P capital investment is expected to be approximately $555 million.
• Our 2017 coal production is expected to be approximately 26.0 million tons.
• Our 2017 coal capital investment is expected to be approximately $135 million.
53
Results of Operations: Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015
Net Loss Attributable to CONSOL Energy Shareholders
CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $848 million, or a loss per diluted
share of $3.70, for the year ended December 31, 2016, compared to a net loss attributable to CONSOL Energy shareholders of
$375 million, or a loss per diluted shared of $1.64, for the year ended December 31, 2015.
(Dollars in thousands)
Loss from Continuing Operations
Loss from Discontinued Operations
Net Loss
Less: Net Income Attributable to Noncontrolling Interests
Net Loss Attributable to CONSOL Energy Shareholders
For the Years Ended December 31,
2016
(535,965) $
(303,183)
(839,148) $
8,954
(848,102) $
2015
(350,266) $
(14,209)
(364,475) $
10,410
(374,885) $
Variance
(185,699)
(288,974)
(474,673)
(1,456)
(473,217)
$
$
$
CONSOL Energy consists of two principal business divisions: Exploration and Production (E&P) and Pennsylvania (PA)
Mining Operations. The E&P division includes four reportable segments: Marcellus, Utica, Coalbed Methane (CBM) and Other
Gas.
The E&P division had a loss before income tax of $379 million for the year ended December 31, 2016, compared to a loss
before income tax of $679 million for the year ended December 31, 2015. Included in the 2016 net loss before income tax was an
unrealized loss on commodity derivative instruments of $386 million. Included in the 2015 net loss before income tax was a loss
of $829 million primarily related to the impairment of the carrying value of CONSOL Energy's shallow oil and natural gas assets
due to depressed NYMEX forward strip prices (see Note 9 - Property, Plant and Equipment of the Notes to the Audited Consolidated
Financial Statements in Item 8 of this Form 10-K for additional information). The impairment loss was partially off-set by an
unrealized gain on commodity derivative instruments of $197 million.
The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the
Company’s natural gas production and sales portfolio.
in thousands (unless noted)
LIQUIDS
NGLs:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
Oil:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
Condensate:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
GAS
Sales Volume (MMcf)
Sales Price ($/Mcf)
Gross Revenue
Hedging Impact ($/Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement
54
For the Years Ended December 31,
2016
2015
Variance
Percent
Change
40,260
6,710
14.52
97,580
410
68
36.90
2,521
4,964
827
27.48
22,748
348,753
1.92
670,823
0.70
245,212
$
$
$
$
$
$
$
$
$
$
33,180
5,530
12.30
68,057
592
99
47.94
4,736
7,598
1,266
26.52
33,586
287,287
2.17
622,080
0.68
196,348
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
7,080
1,180
2.22
29,523
(182)
(31)
(11.04)
(2,215)
(2,634)
(439)
0.96
(10,838)
61,466
(0.25)
48,743
0.02
48,864
21.3 %
21.3 %
18.0 %
43.4 %
(30.7)%
(31.3)%
(23.0)%
(46.8)%
(34.7)%
(34.7)%
3.6 %
(32.3)%
21.4 %
(11.5)%
7.8 %
2.9 %
24.9 %
The E&P division natural gas, NGLs, and oil sales were $794 million for the year ended December 31, 2016, compared to
$729 million for the year ended December 31, 2015. The increase was primarily due to the 20.0% increase in total E&P sales
volumes, offset in part by the 11.5% decrease in the average gas sales price per Mcf without the impact of derivative instruments
from the table above. The decrease in average sales price was the result of the overall decrease in general market prices.
The E&P division sales volumes, average sales price (including the effects of derivatives instruments), and average costs
for all active E&P operations were as follows:
E&P Sales Volumes (Bcfe)
Average Sales Price (per Mcfe)
Average Costs (per Mcfe)
Average Margin
For the Years Ended December 31,
2016
394.4
2015
Variance
Percent
Change
328.7
65.7
20.0 %
$
$
2.63
2.32
0.31
$
$
2.81
2.62
0.19
$
$
(0.18)
(0.30)
0.12
(6.4)%
(11.5)%
63.2 %
Changes in the average costs per Mcfe were primarily related to the following items:
• The improvement in unit costs is primarily due to the continuing shift towards lower cost Marcellus and dry Utica Shale
production, ongoing cost reduction efforts and the 20.0% increase in total volumes sold in the period-to-period comparison.
Marcellus production made up 53.9% of E&P sales volumes in the year ended December 31, 2016, compared to 52.4%
in the year ended December 31, 2015. Utica production made up 23.0% of E&P sales volumes in the year ended
December 31, 2016, compared to 17.1% in the year ended December 31, 2015.
• Lifting costs per unit decreased in the period-to-period comparison primarily due to the increase in overall sales volumes,
as well as a decrease in well site maintenance costs, employee related costs and costs related to wells operated by the
Company's joint venture partners. The decrease was offset, in part, by an increase in total dollars relating to higher salt
water disposal costs.
• Transportation, gathering and compression expense decreased on a per unit basis in the period-to-period comparison due
to the overall increase in E&P sales volumes, the shift towards dry Utica Shale production which has lower gathering
costs since there are no associated processing fees and a decrease in pipeline and facility maintenance expense. The
decrease in unit costs was partially offset by an increase in total dollars related to an increase in utilized firm transportation
costs, increased processing fees associated with NGLs, and an increase in CONE gathering expense directly related to
the increase in Marcellus production. See Note 25 - Related Party Transactions of the Notes to the Audited Consolidated
Financial Statements in Item 8 of this Form 10-K for additional information.
The PA Mining Operations division had earnings before income tax of $131 million for the year ended December 31, 2016,
compared to earnings before income tax of $405 million for the year ended December 31, 2015.
Sales tons, average sales price and average cost of goods sold per ton for the PA Mining Operations division were as follows:
For the Years Ended December 31,
2016
2015
Variance
Percent
Change
Company Produced PA Mining Operations Tons sold (in millions)
24.6
22.9
1.7
7.4 %
Average Sales Price per ton sold
Average Costs of Goods Sold per ton sold
Average Margin
$
$
43.31
34.35
8.96
$
$
56.36
41.78
14.58
$
$
(13.05)
(7.43)
(5.62)
(23.2)%
(17.8)%
(38.5)%
The lower average sales price per ton sold in the 2016 period was primarily the result of the overall decline in the domestic
and global thermal coal markets, particularly in the first half of 2016. This decline was primarily related to higher customer
inventories and lower gas prices after persistently mild 2015 weather. This was off-set by an increase in overall tons sold reflecting
the improvement in both domestic and international coal demand throughout the second half of 2016.
The PA Mining Operations division priced 5.4 million tons on the export market for the year ended December 31, 2016,
compared to 5.5 million tons for the year ended December 31, 2015. All other tons were sold on the domestic market.
55
Changes in the average cost of goods sold per ton were primarily driven by the idling of one longwall at the PA Mining
Operations complex for approximately 90 days, a reduction of staffing levels and a realignment of employee benefits in the current
year. All of the above steps resulted in more consistent operating schedules, reduced labor costs, and improved productivity.
The Other division includes other business activities not assigned to the E&P or PA Mining Operations division and income
taxes. The Other division had a net loss of $287 million for the year ended December 31, 2016, compared to a net loss of $77
million for the year ended December 31, 2015.
Selling, general and administrative (SG&A) costs are allocated to the PA Mining Operations division based upon a shared
service agreement that CONSOL Energy entered into with CNX Coal Resources LP (CNXC) upon execution of the CNXC initial
public offering (IPO). The shared service agreement calls for CONSOL Energy to provide certain selling, general and administrative
services that are paid for monthly, based on an agreed upon fixed fee that is reset at least annually. See Note 25 - Related Party
Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
The remaining SG&A costs are allocated between the E&P and Other divisions based primarily on a percentage of total revenue
and a percentage of total projected capital expenditures.
SG&A costs are excluded from the E&P and PA Mining Operations unit costs above. SG&A costs were $153 million for the
year ended December 31, 2016, compared to $158 million for the year ended December 31, 2015. SG&A costs decreased due to
the following items:
(in millions)
Short-Term Incentive Compensation
Employee Wages and Related Expenses
Advertising and Promotion
Rent
Consulting and Professional Services
Contributions
Stock-Based Compensation
Other
For the Years Ended December 31,
2016
2015
Variance
$
$
29
54
5
8
15
1
31
10
$
40
62
7
8
15
1
25
—
Percent
Change
(27.5)%
(12.9)%
(28.6)%
— %
— %
— %
24.0 %
100.0 %
(3.2)%
(11)
(8)
(2)
—
—
—
6
10
(5)
Total Company Selling, General and Administrative Expense
$
153
$
158
$
• The decrease in Short-Term Incentive Compensation was a result of lower payouts in the current year.
• Employee Wages and Related Expenses decreased $8 million primarily due to the Company reorganization that occurred
•
in the second half of 2015 and the first quarter of 2016, which resulted in an overall decrease in employees.
Stock-Based Compensation increased $6 million in the period-to-period comparison primarily due to additional non-
cash amortization expense recorded in the current period for the Performance Share Unit (PSU) program.
• Other increased $10 million in the period-to-period comparison primarily due to a 401(k) discretionary contribution in
the current period.
Total Company long-term liabilities, such as Other Post-Employment Benefits (OPEB), the salary retirement plan, workers'
compensation, Coal Workers' Pneumoconiosis (CWP), and long-term disability are actuarially calculated for the Company as a
whole. In general, the expenses are then allocated to the segments based upon criteria specific to each liability. Total CONSOL
Energy continuing operations expense related to actuarial liabilities was $74 million for the year ended December 31, 2016,
compared to income of $162 million for the year ended December 31, 2015. The increase of $236 million is primarily due to
modifications made to the OPEB and Pension plans in May 2015. See Note 14—Pension and Other Postretirement Benefit Plans
and Note 15—Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Consolidated
Financial Statements in Item 8 of this Form 10-K for additional details.
56
TOTAL E&P DIVISION ANALYSIS for the year ended December 31, 2016 compared to the year ended December 31, 2015:
The E&P division had a loss before income tax of $379 million for the year ended December 31, 2016 compared to a loss
before income tax of $679 million for the year ended December 31, 2015. Variances by individual E&P segment are discussed
below.
(in millions)
Marcellus
Utica
CBM
Other
Gas
Total
E&P
Marcellus
Utica
CBM
Other
Gas
Total
E&P
For the Year Ended
December 31, 2016
Difference to Year Ended
December 31, 2015
Natural Gas, NGLs and Oil
Sales
Gain (Loss) on Commodity
Derivative Instruments
Purchased Gas Sales
Miscellaneous Other Income
Gain on Sale of Assets
Total Revenue and Other
Income
Lease Operating Expense
Production, Ad Valorem,
and Other Fees
Transportation, Gathering
and Compression
Depreciation, Depletion
and Amortization
Exploration and
Production Related Other
Costs
Purchased Gas Costs
Other Corporate Expenses
Impairment of Exploration
and Production Properties
Selling, General and
Administrative Costs
Total Exploration and
Production Costs
Interest Expense
Total E&P Division Costs
Earnings (Loss) Before Income
Tax
$
415
$
163
$
175
$
41
$
794
$
36
$
70
$
(27) $
(14) $
65
147
—
—
—
562
34
17
228
211
—
—
—
—
—
490
—
490
29
—
—
—
192
22
5
51
86
—
—
—
—
—
52
—
—
—
227
25
6
72
86
—
—
—
—
—
164
—
164
189
—
189
(369)
(141)
43
81
14
(190)
15
3
23
35
15
43
88
—
102
324
3
327
43
81
14
791
96
31
374
418
15
43
88
—
102
1,167
3
1,170
46
—
—
—
82
(10)
(1)
28
49
—
—
—
—
—
66
—
66
23
—
—
—
93
—
3
16
27
—
—
—
—
—
46
—
46
(15)
(588)
(534)
29
19
1
29
19
1
(553)
(8)
(420)
(26)
2
(31)
—
—
5
32
22
1
31
47
5
32
22
—
—
—
(42)
(8)
(1)
(13)
—
—
—
—
—
(829)
(829)
—
—
(20)
—
(20)
(809)
(717)
(3)
(3)
(812)
(720)
$
72
$
28
$
38
$ (517) $ (379) $
16
$
47
$
(22) $
259
$
300
57
MARCELLUS SEGMENT
The Marcellus segment had earnings before income tax of $72 million for the year ended December 31, 2016 compared to
earnings before income tax of $56 million for the year ended December 31, 2015.
Marcellus Gas Sales Volumes (Bcf)
NGLs Sales Volumes (Bcfe)*
Condensate Sales Volumes (Bcfe)*
Total Marcellus Sales Volumes (Bcfe)*
Average Sales Price - Gas (Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Average Sales Price - NGLs (Mcfe)*
Average Sales Price - Condensate (Mcfe)*
Total Average Marcellus Sales Price (per Mcfe)
Average Marcellus Lease Operating Expenses (per Mcfe)
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)
Average Marcellus Transportation, Gathering and Compression Costs (per
Mcfe)
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Marcellus Costs (per Mcfe)
Average Margin for Marcellus (per Mcfe)
For the Years Ended December 31,
2016
186.8
23.5
2.2
212.5
2015
149.4
19.0
3.9
172.3
Variance
37.4
4.5
(1.7)
40.2
$
$
$
$
$
$
$
1.87
0.79
2.38
4.32
2.64
0.16
0.08
1.07
0.99
2.30
0.34
$
$
$
$
$
$
$
2.09
0.67
2.54
5.02
2.79
0.26
0.10
1.16
0.94
2.46
0.33
$
$
$
$
$
$
$
(0.22)
0.12
(0.16)
(0.70)
(0.15)
(0.10)
(0.02)
(0.09)
0.05
(0.16)
0.01
Percent
Change
25.0 %
23.7 %
(43.6)%
23.3 %
(10.5)%
17.9 %
(6.3)%
(13.9)%
(5.4)%
(38.5)%
(20.0)%
(7.8)%
5.3 %
(6.5)%
3.0 %
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content
of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Marcellus segment had natural gas, NGLs and oil sales of $415 million for the year ended December 31, 2016 compared
to $379 million for the year ended December 31, 2015. The $36 million increase is primarily due to a 23.3% increase in total
Marcellus sales volumes, partially offset by a 10.5% decrease in the average gas sales price in the period-to-period comparison.
The increase in total sales volumes is primarily due to additional wells coming on-line in the current year, as well as the termination
of the Marcellus Joint Venture that CONSOL Energy had with Noble Energy (See Note 9 - Property, Plant and Equipment in the
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details). The joint venture
termination was effective October 1st, 2016 and resulted in additional production for the fourth quarter of 2016, as well as the
applicable sales and production costs.
The decrease in the total average Marcellus sales price was primarily the result of the $0.22 per Mcf decrease in gas market
prices, along with a $0.03 per Mcf decrease in the uplift from NGLs and condensate sales volumes, when excluding the impact
of hedging. These decreases were offset, in part, by a $0.12 per Mcf increase in the gain on commodity derivative instruments
resulting from the Company's hedging program. The increase in the gain was due to an increase in volumes hedged and lower
market prices. The notional amounts associated with these financial hedges represented approximately 160.8 Bcf of the Company's
produced Marcellus gas sales volumes for the year ended December 31, 2016 at an average gain of $0.92 per Mcf. For the year
ended December 31, 2015, these financial hedges represented approximately 90.3 Bcf at an average gain of $1.09 per Mcf.
Total exploration and production costs for the Marcellus segment were $490 million for the year ended December 31, 2016
compared to $424 million for the year ended December 31, 2015. The increase in total dollars and decrease in unit costs for the
Marcellus segment were due to the following items:
• Marcellus lease operating expense was $34 million for the year ended December 31, 2016 compared to $44 million for
the year ended December 31, 2015. The decrease in total dollars was primarily due to a reduction in employee related costs, well
tending costs and repairs and maintenance expense in the current period. The reduction in employee related costs was primarily
due to the company reorganization that occurred in the second half of 2015 and the first quarter of 2016. The decrease in unit costs
58
was primarily due to the 23.3% increase in total Marcellus sales volumes, along with the decreased total dollars described above.
The decreases were offset, in part, by an increase in salt water disposal costs in the period-to-period comparison.
• Marcellus production, ad valorem, and other fees were $17 million for the year ended December 31, 2016 compared to
$18 million for the year ended December 31, 2015. The decrease in total dollars was primarily due to the decrease in total average
Marcellus sales price, offset, in part, by the increase in total Marcellus sales volumes.
• Marcellus transportation, gathering and compression costs were $228 million for the year ended December 31, 2016
compared to $200 million for the year ended December 31, 2015. The $28 million increase in total dollars was primarily related
to an increase in the CONE gathering fee due to the increase in total Marcellus sales volumes (See Note 25 - Related Party
Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information),
an increase in processing fees associated with natural gas liquids primarily due to the 23.7% increase in NGLs sales volumes, and
an increase in utilized firm transportation expense. The decrease in unit costs was due to the increase in total Marcellus sales
volumes, offset, in part, by the increase in total dollars.
• Depreciation, depletion and amortization costs attributable to the Marcellus segment were $211 million for the year ended
December 31, 2016 compared to $162 million for the year ended December 31, 2015 driven primarily by the overall increase in
production. These amounts included depletion on a unit of production basis of $0.98 per Mcf and $0.92 per Mcf, respectively.
The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well
closing.
UTICA SEGMENT
The Utica segment had earnings before income tax of $28 million for the year ended December 31, 2016 compared to a loss
before income tax of $19 million for the year ended December 31, 2015.
For the Years Ended December 31,
2016
2015
Utica Gas Sales Volumes (Bcf)
NGLs Sales Volumes (Bcfe)*
Oil Sales Volumes (Bcfe)*
Condensate Sales Volumes (Bcfe)*
Total Utica Sales Volumes (Bcfe)*
Average Sales Price - Gas (Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Average Sales Price - NGLs (Mcfe)*
Average Sales Price - Oil (Mcfe)*
Average Sales Price - Condensate (Mcfe)*
Total Average Utica Sales Price (per Mcfe)
Average Utica Lease Operating Expenses (per Mcfe)
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Utica Costs (per Mcfe)
Average Margin for Utica (per Mcfe)
71.3
16.7
—
2.8
90.8
1.52
0.41
2.49
$
$
$
— $
$
4.78
2.12
0.25
0.05
0.57
0.94
1.81
0.31
$
$
$
$
$
$
$
$
$
$
$
Variance
33.0
2.6
(0.1)
(0.9)
34.6
$ —
$ 0.24
$ 1.10
$ (6.58)
$ 0.99
$ 0.37
(0.14)
0.01
38.3
14.1
0.1
3.7
56.2
1.52
0.17
1.39
6.58
3.79
1.75
0.39
0.04
0.61
1.06
(0.04)
(0.12)
$ (0.29)
2.10
(0.35) $ 0.66
Percent
Change
86.2 %
18.4 %
(100.0)%
(24.3)%
61.6 %
— %
141.2 %
79.1 %
(100.0)%
26.1 %
21.1 %
(35.9)%
25.0 %
(6.6)%
(11.3)%
(13.8)%
188.6 %
*NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content
of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Utica segment had natural gas, NGLs and oil sales of $163 million for the year ended December 31, 2016 compared to
$93 million for the year ended December 31, 2015. The $70 million increase was primarily due to the 61.6% increase in total
59
Utica sales volumes. The 34.6 Bcfe increase in total Utica sales volumes was due to additional wells coming on-line, primarily in
dry Utica areas, in the current period.
The increase in the total average Utica sales price was primarily due to a $0.24 per Mcf increase in the gain on commodity
derivative instruments in the current period, as well as a $0.16 per Mcf increase in the uplift from NGLs and condensate sales
volumes. The increase in the hedging gain was due to an increase in the volumes hedged that were designated as Utica volumes.
Financial hedges represented approximately 31.6 Bcf of the Company's produced Utica gas sales volumes for the year ended
December 31, 2016 at an average gain of $0.93 per Mcf. For the year ended December 31, 2015, these financial hedges represented
approximately 5.9 Bcf at an average gain of $1.08 per Mcf.
Total exploration and production costs for the Utica segment were $164 million for the year ended December 31, 2016
compared to $118 million for the year ended December 31, 2015. The increase in total dollars and decrease in unit costs for the
Utica segment are due to the following items:
• Utica lease operating expense remained flat at $22 million for each of the years ended December 31, 2016 and
December 31, 2015. The decrease in unit costs was primarily due to the 61.6% increase in total Utica sales volumes.
• Utica production, ad valorem, and other fees were $5 million for the year ended December 31, 2016 compared to $2
million for the year ended December 31, 2015. The increase in total dollars was primarily due to the 61.6% increase in total Utica
sales volumes. The increase in unit costs was also due to a credit received from a joint venture partner in the 2015 period, related
to an over-billing of ad valorem taxes.
• Utica transportation, gathering and compression costs were $51 million for the year ended December 31, 2016 compared
to $35 million for the year ended December 31, 2015. The $16 million increase in total dollars was primarily related to increased
gathering and processing fees associated with the increased Utica NGLs and gas sales volumes. The decrease in unit costs was
due to the increase in total Utica sales volumes, predominantly dry Utica, which was offset, in part, by the increase in total dollars.
• Depreciation, depletion and amortization costs attributable to the Utica segment were $86 million for the year ended
December 31, 2016 compared to $59 million for the year ended December 31, 2015 driven primarily by the overall increase in
production. These amounts included depletion on a unit of production basis of $0.93 per Mcf and $1.05 per Mcf, respectively.
The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well
closing.
COALBED METHANE (CBM) SEGMENT
The CBM segment had earnings before income tax of $38 million for the year ended December 31, 2016 compared to
earnings before income tax of $60 million for the year ended December 31, 2015.
CBM Gas Sales Volumes (Bcf)
Average Sales Price - Gas (Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Total Average CBM Sales Price (per Mcf)
Average CBM Lease Operating Expenses (per Mcf)
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)
Average CBM Transportation, Gathering and Compression Costs (per Mcf)
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)
Total Average CBM Costs (per Mcf)
Average Margin for CBM (per Mcf)
For the Years Ended December 31,
2016
2015
Variance
Percent
Change
69.0
74.9
(5.9)
(7.9)%
$
$
$
$
$
2.53
0.76
3.29
0.36
0.09
1.04
1.25
2.74
0.55
$
$
$
$
$
2.70
0.90
3.60
0.44
0.10
1.13
1.13
2.80
0.80
$
$
$
$
$
(0.17)
(0.14)
(6.3)%
(15.6)%
(0.31)
(0.08)
(0.01)
(0.09)
0.12
(0.06)
(0.25)
(8.6)%
(18.2)%
(10.0)%
(8.0)%
10.6 %
(2.1)%
(31.3)%
The CBM segment had natural gas sales of $175 million for the year ended December 31, 2016 compared to $202 million
for the year ended December 31, 2015. The $27 million decrease was primarily due to a 6.3% decrease in the average gas sales
60
price, as well as a 7.9% decrease in CBM gas sales volumes. The decrease in CBM sales volumes was primarily due to normal
well declines and less drilling activity.
The total average CBM sales price decreased $0.31 per Mcf due primarily to a $0.17 per Mcf decrease in gas market prices,
as well as a $0.14 per Mcf decrease in the gain on commodity derivative instruments resulting from the Company's hedging
program. The notional amounts associated with these financial hedges represented approximately 55.0 Bcf of the Company's
produced CBM sales volumes for the year ended December 31, 2016 at an average gain of $0.95 per Mcf. For the year ended
December 31, 2015, these financial hedges represented approximately 57.5 Bcf at an average gain of $1.17 per Mcf.
Total exploration and production costs for the CBM segment were $189 million for the year ended December 31, 2016
compared to $209 million for the year ended December 31, 2015. The decrease in total dollars and decrease in unit costs for the
CBM segment were due to the following items:
• CBM lease operating expense was $25 million for the year ended December 31, 2016 compared to $33 million for the
year ended December 31, 2015. The decrease in total dollars was primarily related to a decrease in contractual services related to
well tending, a decrease in repairs and maintenance expense, a decrease in employee related costs, and a decrease in salt water
disposal costs. The decrease in unit costs was due to the decrease in total dollars, partially offset by the decrease in CBM gas sales
volumes.
• CBM production, ad valorem, and other fees were $6 million for the year ended December 31, 2016 compared to $7
million for the year ended December 31, 2015. The $1 million decrease was due to a decrease in severance tax expense resulting
from the decrease in both gas sales volumes and average sales price. Unit costs were positively impacted by the decrease in total
average CBM sales price which was offset, in part, by the decrease in CBM gas sales volumes.
• CBM transportation, gathering and compression costs were $72 million for the year ended December 31, 2016 compared
to $85 million for the year ended December 31, 2015. The $13 million decrease was primarily related to a decrease in repairs and
maintenance, power and utilized firm transportation expense resulting from the decrease in CBM gas sales volumes. Unit costs
were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in CBM gas sales volumes.
• Depreciation, depletion and amortization costs attributable to the CBM segment were $86 million for the year ended
December 31, 2016 compared to $84 million for the year ended December 31, 2015. These amounts included depletion on a unit
of production basis of $0.82 per Mcf and $0.73 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
61
OTHER GAS SEGMENT
The Other Gas segment had a loss before income tax of $517 million for the year ended December 31, 2016 compared to a
loss before income tax of $776 million for the year ended December 31, 2015.
For the Years Ended December 31,
Other Gas Sales Volumes (Bcf)
Oil Sales Volumes (Bcfe)*
Total Other Sales Volumes (Bcfe)*
Average Sales Price - Gas (Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Average Sales Price - Oil (Mcfe)*
Total Average Other Sales Price (per Mcfe)
Average Other Lease Operating Expenses (per Mcfe)
Average Other Production, Ad Valorem, and Other Fees (per Mcfe)
Average Other Transportation, Gathering and Compression Costs (per Mcfe)
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Other Costs (per Mcfe)
Average Margin for Other (per Mcfe)
2016
2015
21.7
0.4
22.1
1.79
0.75
6.23
2.61
0.69
0.12
$
$
$
$
24.7
0.5
25.2
2.03
0.88
8.15
3.03
0.90
0.14
$
$
$
$
Variance
(3.0)
(0.1)
(3.1)
$ (0.24)
$ (0.13)
$ (1.92)
$ (0.42)
(0.21)
(0.02)
0.96
1.07
1.49
0.11
(0.85)
$ (0.97)
$
$ (0.76) $ (1.31) $ 0.55
2.34
3.37
4.34
$
Percent
Change
(12.1)%
(20.0)%
(12.3)%
(11.8)%
(14.8)%
(23.6)%
(13.9)%
(23.3)%
(14.3)%
11.5 %
(36.3)%
(22.4)%
42.0 %
*Oil is converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural
gas, which is not indicative of the relationship of oil and natural gas prices.
The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes
purchased gas activity, unrealized gain or loss on commodity derivative instruments, exploration and production related other
costs, other corporate expenses and miscellaneous operational activity not assigned to a specific E&P segment.
Other Gas sales volumes are primarily related to shallow oil and gas production, as well as the Chattanooga shale in Tennessee.
Natural gas, NGLs and oil sales related to the Other Gas segment were $41 million for the year ended December 31, 2016 compared
to $55 million for the year ended December 31, 2015. The decrease in natural gas and oil sales primarily related to the $0.24 per
Mcf decrease in average gas sales price. Total exploration and production costs related to these other sales were $76 million for
the year ended December 31, 2016 compared to $115 million for the year ended December 31, 2015. The decrease was primarily
due to a decrease in depreciation, depletion and amortization costs related to the adjustment to the Company's shallow oil and gas
rates after an impairment in the carrying value was recognized in the second quarter of 2015 (see Note 9 - Property, Plant and
Equipment of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).
The Other Gas segment recognized an unrealized loss on commodity derivative instruments of $386 million as well as cash
settlements of $17 million for the year ended December 31, 2016. For the year ended December 31, 2015, the Company recognized
an unrealized gain on commodity derivative instruments of $197 million as well as cash settlements of $22 million. The unrealized
loss/gain on commodity derivative instruments represents changes in the fair value of all of the Company's existing commodity
hedges on a mark-to-market basis and is the result of the December 31, 2014 de-designation of all derivative positions as cash
flow hedges. Changes in fair value were recorded in Accumulated Other Comprehensive Income prior to de-designation.
Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to
fulfill contracts with certain customers. Purchased gas sales revenues were $43 million for the year ended December 31, 2016
compared to $14 million for the year ended December 31, 2015. Purchased gas costs were $43 million for the year ended
December 31, 2016 compared to $11 million for the year ended December 31, 2015. The period-to-period increase in purchased
gas sales revenue was due to the increase in purchased gas sales volumes, offset, in part, by the decrease in market prices.
62
Purchased Gas Sales Volumes (in billion cubic feet)
Average Sales Price (per Mcf)
Average Cost (per Mcf)
For the Years Ended December 31,
2016
2015
Variance
21.7
1.99
1.97
$
$
6.8
2.14
1.59
$
$
14.9
(0.15)
0.38
$
$
Percent
Change
219.1 %
(7.0)%
23.9 %
Miscellaneous other income was $81 million for the year ended December 31, 2016 compared to $62 million for the year
ended December 31, 2015. The $19 million increase was primarily due to the following items:
(in millions)
Right of Way Sales
Equity in Earnings of Affiliates
Gathering Revenue
Other
Total Miscellaneous Other Income
For the Years Ended December 31,
2016
2015
Variance
$
$
15
52
11
3
81
$
$
2
47
10
3
62
$
$
Percent
Change
650.0%
10.6%
10.0%
—%
30.6%
13
5
1
—
19
• Right of Way Sales increased $13 million in the period-to-period comparison due to an initiative in the current year to
generate additional revenue from our unutilized surface rights.
• Equity in Earnings of Affiliates increased $5 million primarily due to an increase in earnings from CONE Midstream
Partners LP and CONE Gathering LLC. See Note 25 - Related Party Transactions of the Notes to the Audited Consolidated
Financial Statements in Item 8 of this Form 10-K for additional information.
Gain on sale of assets was $14 million for the year ended December 31, 2016 compared to $13 million for the year ended
December 31, 2015. The $1 million increase was due to various land asset sales that occurred throughout both periods, none of
which were individually material.
Exploration and production related other costs were $15 million for the year ended December 31, 2016 compared to $10
million for the year ended December 31, 2015. The $5 million increase in costs is primarily related to the following items:
(in millions)
Lease Expiration Costs
Permitting Expense
Land Rentals
Other
Total Exploration and Other Costs
For the Years Ended December 31,
2016
2015
Variance
$
$
7
2
4
2
15
$
$
4
1
5
—
10
$
$
Percent
Change
75.0 %
100.0 %
(20.0)%
100.0 %
50.0 %
3
1
(1)
2
5
• Lease Expiration Costs increased by $3 million in the period-to-period comparison, primarily due to an increase in the
number of leases allowed to expire in the year ended December 31, 2016 as compared to the year ended December 31,
2015.
Other corporate expenses were $88 million for the year ended December 31, 2016 compared to $66 million for the year
ended December 31, 2015. The $22 million increase in the period-to-period comparison was made up of the following items:
63
Severance Expense
Litigation Settlements
Insurance Expense
Unutilized Firm Transportation and Processing Fees
Transaction Fees
Idle Rig Expense
Other
Total Other Corporate Expenses
For the Years Ended December 31,
2016
2015
Variance
$
$
1
1
3
37
4
33
9
88
$
$
5
2
3
33
—
19
4
66
$
$
(4)
(1)
—
4
4
14
5
22
Percent
Change
(80.0)%
(50.0)%
— %
12.1 %
100.0 %
73.7 %
125.0 %
33.3 %
•
Severance Expense decreased $4 million in the period-to-period comparison primarily due to the Company reorganization
that occurred in the third quarter of 2015. Amounts recorded in the current period are primarily due to the Company's
first quarter 2016 reorganization.
• Unutilized Firm Transportation and Processing Fees represent pipeline transportation capacity the E&P segment has
obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity
for natural gas liquids. The increase in the period-to-period comparison was primarily due to the decrease in the utilization
of capacity. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity
to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included
in Gathering Revenue in miscellaneous other income above.
• Transaction Fees of $4 million are associated with the dissolution of the Noble Energy Marcellus Shale joint venture.
•
Idle Rig Expense related to temporary idling of some of the Company's natural gas rigs. The total idle rig expense increased
in the period-to-period comparison due to unfavorable market conditions in the first half of the current period.
• Other increased $5 million in the period-to-period comparison primarily due to a 401(k) discretionary contribution in the
current period, as well as various transactions that occurred throughout both periods, none of which were individually
material.
Impairment of Exploration and Production Properties of $829 million for the year ended December 31, 2015 relates to the
write down of the Company's shallow oil and gas asset values in June 2015. See Note 9- Property, Plant and Equipment of the
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such write
downs occurred in the current period.
Selling, general and administrative (SG&A) costs are allocated to the total E&P segment based on percentage of total revenue
and percentage of total projected capital expenditures. SG&A costs were $102 million for each of the years ended December 31,
2016 and December 31, 2015. Refer to the discussion of total company selling, general and administrative costs contained in the
section "Net Loss Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation.
Interest expense related to the E&P division was $3 million for the year ended December 31, 2016 compared to $6 million
for the year ended December 31, 2015. Interest was incurred by the Other Gas segment on interest allocated to the E&P division
under CONSOL Energy's credit facility.
64
TOTAL PA MINING OPERATIONS DIVISION ANALYSIS for the year ended December 31, 2016 compared to the year
ended December 31, 2015:
The PA Mining Operations division principal activities consist of mining, preparation and marketing of thermal coal to power
generators. The division also includes selling, general and administrative costs, as well as various other activities assigned to the
PA Mining Operations division but not included in the cost components on a per unit basis.
The PA Mining Operations division had earnings before income tax of $131 million for the year ended December 31, 2016,
compared to earnings before income tax of $405 million for the year ended December 31, 2015. Variances are discussed below.
(in millions)
Sales:
Coal Sales
Freight Revenue
Miscellaneous Other Income
Total Revenue and Other Income
Operating Costs and Expenses:
Operating Costs
Depreciation, Depletion and Amortization
Total Operating Costs and Expenses
Other Costs and Expenses:
Other Costs
Depreciation, Depletion and Amortization
Total Other Costs and Expenses
Freight Expense
Selling, General and Administrative Costs
Total PA Mining Operations Costs
Interest Expense
Total PA Mining Operations Division Expense
Earnings Before Income Tax
For the Years Ended December 31,
2016
2015
Variance
$
$
$
1,066
46
13
1,125
$
1,289
20
4
1,313
691
154
845
42
14
56
46
38
985
9
994
131
$
789
167
956
(122)
10
(112)
20
41
905
3
908
405
$
(223)
26
9
(188)
(98)
(13)
(111)
164
4
168
26
(3)
80
6
86
(274)
The PA Mining Operations coal revenue and cost components on a per unit basis for these periods were as follows:
Company Produced PA Mining Operations Tons Sold (in millions)
Average Sales Price Per PA Mining Operations Ton Sold
Total Operating Costs Per Ton Sold
Total Depreciation, Depletion and Amortization Costs Per Ton Sold
Total Costs Per PA Mining Operations Ton Sold
Average Margin Per PA Mining Operations Ton Sold
Coal Sales
For the Years Ended December 31,
2016
2015
24.6
$ 43.31
$ 28.09
6.26
$ 34.35
8.96
$
$
$
$
$
22.9
56.36
34.47
7.31
41.78
14.58
Variance
1.7
$ (13.05)
$ (6.38)
(1.05)
$ (7.43)
$ (5.62)
Percent
Change
7.4%
(23.2%)
(18.5%)
(14.4%)
(17.8%)
(38.5%)
PA Mining Operations coal sales were $1,066 million for the year ended December 31, 2016, compared to $1,289 million
for the year ended December 31, 2015. The $223 million decrease was attributable to a $13.05 per ton lower average sales price,
offset by a 1.7 million increase in tons sold. The lower average sales price per PA Mining Operations ton sold was primarily the
result of the continued decline in both the domestic and global thermal coal markets, particularly in the first half of 2016. The
decline was related to higher customer inventories and lower gas prices after persistently mild 2015 weather.
65
The increase in overall tons sold reflects the improvement in both domestic and international coal demand throughout the
second half of 2016.
Freight Revenue and Freight Expense
Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on the weight of
coal shipped, negotiated freight rates and method of transportation, primarily rail, used by the customers to which the Company
contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue and freight
expense were both $46 million for the year ended December 31, 2016, compared to $20 million for the year ended December 31,
2015. The $26 million increase was due to increased shipments where transportation services were contractually provided.
Miscellaneous Other Income
Miscellaneous other income was $13 million for the year ended December 31, 2016, compared to $4 million for the year
ended December 31, 2015. Approximately $6 million of the increase was the result of a partial coal contract buyout in the current
period. The remaining $3 million increase was the result of various transactions that occurred during both periods, none of which
were individually material.
Operating Costs and Expenses
Operating costs and expenses are comprised of costs related to produced tons sold, along with changes in both the volumes
and carrying values of coal inventory. Operating costs and expenses include items such as direct operating costs, royalty and
production taxes, employee-related expenses and depreciation, depletion, and amortization costs. Total operating costs and expenses
for the PA Mining Operations division were $845 million for the year ended December 31, 2016, or $111 million lower than the
$956 million for the year ended December 31, 2015. Total costs per PA Mining Operations ton sold were $34.35 per ton in the
year ended December 31, 2016, compared to $41.78 per ton in the year ended December 31, 2015. The decrease in the cost of
coal sold was driven by the idling of one longwall at the PA Mining Operations complex for approximately 90 days, a reduction
of staffing levels, vendor concessions and a realignment of employee benefits. All of the above steps resulted in more consistent
operating schedules, reduced labor costs and improved productivity. Productivity for the year ended December 31, 2016, as
measured by tons per employee hour, improved by 17% compared to the year earlier period, despite the reduced number of
longwalls in operation.
Other Costs and Expenses
Other costs and expenses include items that are assigned to the PA Mining Operations division but are not included in unit
costs. Other costs and expenses increased $168 million in the year ended December 31, 2016 compared to the year ended
December 31, 2015. The increase was due to the following:
OPEB Plan Changes
Idle Mine Costs
Purchased Coal Costs
Litigation Expense
Severance Expense
Amortization of Capitalized Interest
Coal Reserve Holding Costs
Other
Other Costs and Expenses
For the Years Ended December 31,
2016
2015
Variance
— $
19
(129) $
—
6
4
1
9
4
13
56
$
—
—
—
9
5
3
(112) $
129
19
6
4
1
—
(1)
10
168
$
$
•
•
Income of $129 million related to OPEB plan changes made in May 2015 for retired employees. Refer to the discussion
of total Company long-term liabilities contained in the section "Net Loss Attributable to CONSOL Energy Shareholders"
of this annual report for a detailed cost explanation. No such transactions occurred during the year ended December 31,
2016.
Idle Mine Costs increased $19 million, due to the temporary idling of one longwall at the PA Mining Operations complex
for approximately 90 days in the first half of 2016 to optimize operating schedules.
66
•
Purchased Coal Costs increased $6 million due to higher volumes of coal that needed to be purchased to fulfill various
contracts.
• Litigation expense relates to approximately $3 million of costs which were incurred during the year ended December 31,
2016 related to the proposed consent decree with respect to the Bailey mine complex. See Note 22 - Commitments and
Contingent Liabilities of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for
additional information. The remaining change was the result of various transactions that occurred, none of which were
individually material.
Severance Expense of $1 million was incurred during the year ended December 31, 2016 in connection with the Company's
ongoing cost reduction efforts. No such transactions occurred in the prior period.
•
• Other increased $10 million in the period-to-period comparison primarily due to a 401(k) discretionary contribution in
the current period.
Selling, General and Administrative Costs
Upon execution of the CNXC IPO, CNXC entered into a service agreement with CONSOL Energy that required CONSOL
Energy to provide certain selling, general and administrative services. These services are paid monthly based on an agreed-upon
fixed fee that is reset at least annually. See Note 25 - Related Party Transactions of the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional information. The amount of selling, general and administrative costs related
to PA Mining Operations was $38 million for the year ended December 31, 2016, compared to $41 million for the year ended
December 31, 2015. Refer to the discussion of total Company selling, general and administrative costs contained in the section
"Net Loss Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation.
Interest Expense
Interest expense, net of amounts capitalized, of $9 million and $3 million for the years ended December 31, 2016 and 2015,
respectively, is primarily comprised of interest on the CNXC revolving credit facility that was drawn upon after the CNXC IPO
on July 7, 2015.
67
OTHER DIVISION ANALYSIS for the year ended December 31, 2016 compared to the year ended December 31, 2015:
The Other division includes expenses from various corporate and diversified business activities that are not allocated to the
E&P or PA Mining Operations divisions. The diversified business activities include coal terminal operations, closed and idle mine
activities, water operations, selling, general and administrative activities, income tax expense (benefit), as well as various other
non-operated activities.
The Other division had a loss before income tax of $277 million for the year ended December 31, 2016, compared to a loss
before income tax of $202 million for the year ended December 31, 2015. The Other division also includes total Company income
tax expense related to continuing operations of $10 million for the year ended December 31, 2016, compared to an income tax
benefit of $125 million for the year ended December 31, 2015.
(in millions)
Other Outside Sales
Miscellaneous Other Income
Gain on Sale of Assets
Total Revenue
Miscellaneous Operating Expense
Selling, General, and Administrative Costs
Depreciation, Depletion and Amortization
Loss on Debt Extinguishment
Interest Expense
Total Other Costs
Loss Before Income Tax
Income Tax Expense (Benefit)
Net Loss
Other Outside Sales
For the Years Ended December 31,
2016
2015
Variance
$
$
$
32
73
5
110
183
13
12
—
179
387
(277)
10
(287) $
$
31
78
61
170
79
15
20
68
190
372
(202)
(125)
(77) $
1
(5)
(56)
(60)
104
(2)
(8)
(68)
(11)
15
(75)
135
(210)
Percent
Change
3.2 %
(6.4)%
(91.8)%
(35.3)%
131.6 %
(13.3)%
(40.0)%
(100.0)%
(5.8)%
4.0 %
(37.1)%
108.0 %
(272.7)%
Other outside sales primarily consists of sales from the Company's coal terminal operations. Coal terminal operations sales
were $32 million for the year ended December 31, 2016, compared to $31 million for the year ended December 31, 2015. The $1
million increase in the period-to-period comparison was primarily due to an increase in throughput rates in the current period.
Miscellaneous Other Income
Miscellaneous other income was $73 million for the year ended December 31, 2016, compared to $78 million for the year
ended December 31, 2015. The change is due to the following items:
(in millions)
Equity in Earnings of Affiliates
Purchased Coal Sales
Rental Income
Interest Income
Right of Way Sales
Royalty Income
Other Income
Total Miscellaneous Other Income
For the Years Ended December 31,
2016
2015
Variance
$
$
1
—
36
1
12
20
3
73
$
$
8
2
37
2
8
15
6
78
$
$
(7)
(2)
(1)
(1)
4
5
(3)
(5)
68
• Equity in Earnings of Affiliates decreased $7 million due to the sale of the Company's 49% interest in Western Allegheny
Energy in September 2015. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional details.
Purchased Coal Sales decreased $2 million due to lower volumes of coal that needed to be purchased to fulfill various
contracts in the current period.
•
• Right of Way Sales increased $4 million in the period-to-period comparison due to an initiative in the current year to
generate additional revenue from the Company's unutilized surface rights.
• Royalty Income increased $5 million primarily due to additional royalties received in the current year resulting from the
sale of Buchanan Mine. See Note 2 - Discontinued Operations in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional details.
Gain on Sale of Assets
Gain on sale of assets decreased $56 million in the period-to-period comparison, primarily due to the sale of the Company's
49% interest in Western Allegheny Energy in September 2015. See Note 3 - Acquisitions and Dispositions in the Notes to the
Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
Miscellaneous Operating Expense
Miscellaneous operating expense related to the Other division was $183 million for the year ended December 31, 2016,
compared to $79 million for the year ended December 31, 2015. Miscellaneous operating expense increased in the period-to-
period comparison due to the following items:
(in millions)
OPEB Plan Changes
Coal Reserve Holding Costs
Litigation Expense
Pension Settlement
Bank Fees
Closed and Idle Mines
Purchased Coal
UMWA Expenses
Workers' Compensation
Lease Rental Expense
Coal Terminal Operations
UMWA OPEB Expense
Severance Payments
Industrial Supplies Working Capital Settlement
Pension Expense
Other
Miscellaneous Operating Expense
For the Years Ended December 31,
2016
2015
Variance
$
$
— $
19
5
22
18
9
—
9
6
30
18
43
1
—
(14)
17
183
$
(125) $
8
—
19
17
9
1
10
7
31
20
47
6
6
6
17
79
$
125
11
5
3
1
—
(1)
(1)
(1)
(1)
(2)
(4)
(5)
(6)
(20)
—
104
•
Income of $125 million was the result of modifications made to the OPEB plan in May 2015 for retired employees. Refer
to the discussion of total Company long-term liabilities contained in the section "Net Loss Attributable to CONSOL
Energy Shareholders" of this annual report and Note 14 - Pension and Other Postretirement Benefit Plans in the Notes
to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information. No such transactions
occurred in the current period.
• Coal Reserve Holding Costs increased $11 million in the period-to-period comparison, primarily as a result of the surrender
•
of various leases in the current period.
Pension Settlement expense is required when lump sum distributions made for a given plan year exceed the total of the
service and interest costs for that same plan year. Settlement accounting was triggered in both periods. See Note 14 -
Pension and Other Postretirement Benefits Plans in the Notes to the Audited Consolidated Financial Statements in Item
8 of this Form 10-K for additional information.
Purchased Coal decreased $1 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.
•
• Lease Rental Expense decreased $1 million primarily due to the buyout of certain leased equipment in the current period.
69
• Coal Terminal Operations decreased $2 million due to a reduction in labor costs.
• UMWA OPEB Expense decreased $4 million primarily due to a decrease in interest costs.
•
Severance Payments decreased $5 million in the period-to-period comparison, primarily related to the company
reorganization that occurred in the year ended December 31, 2015.
Industrial Supplies Working Capital Settlement of $6 million represents the settlement of working capital adjustments
and other matters in the year ended December 31, 2015 related to the divestiture of the Company's industrial supplies
subsidiary in December 2014.
Pension Expense decreased $20 million in the period-to-period comparison due to a decrease in actuarially-calculated
amortization related to modifications made to the pension plan in May 2015. See Note 14 - Pension and Other
Postretirement Benefits Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-
K for additional information.
•
•
Selling, General and Administrative Costs
Selling, general and administrative costs allocated to the Other division were $13 million for the year ended December 31,
2016, compared to $15 million for the year ended December 31, 2015. Refer to the discussion of total Company selling, general
and administrative costs contained in the section "Net Loss Attributable to CONSOL Energy Shareholders" of this annual report
for more information.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased $8 million in the period-to-period comparison, primarily related to a
reduction of the asset retirement obligations at various closed and idled mine locations.
Loss on Debt Extinguishment
Loss on debt extinguishment of $68 million was recognized in the year ended December 31, 2015 due to the partial purchase
of the 8.25% senior notes that were due in 2020 at an average price equal to 104.6% of the principal amount, and the partial
purchase of the 6.375% senior notes that were due in 2021 at an average price equal to 105.0% of the principal amount. No such
transactions occurred in the current period.
Interest Expense
Interest expense of $179 million was recognized in the year ended December 31, 2016, compared to $190 million in the
year ended December 31, 2015. The $11 million decrease in the period-to-period comparison was due to the partial payoff of the
2020 and 2021 bonds in March and April 2015. Also contributing to the decrease was a decrease in the average outstanding balance
on the Company's revolving credit facility, as well as lower interest rates on the 2023 bonds issued in March 2015 when compared
to the interest rate on the 2020 bonds.
Income Taxes
The effective income tax rate for continuing operations when excluding non-controlling interest was (1.9)% for the year
ended December 31, 2016, compared to 26.3% for the year ended December 31, 2015. During the year ended December 31, 2016,
CONSOL Energy settled a Federal audit of the years 2010-2013 and received a favorable private letter ruling from the IRS related
to bonus depreciation. Overall, the Company received approximately $21 million in refunds during 2016 and anticipates additional
cash refunds in 2017.
Some of the factors contributing to these refunds put pressure on deferred tax assets related to AMT credits. Although these
credits never expire, at December 31, 2016, management could not demonstrate sufficient positive evidence to ensure realizability
of these assets in the foreseeable future. As CONSOL Energy was in a three-year cumulative pre-tax loss, the Company did not
consider future generation of income to support the realization of these credits. As a result, the Company recorded a valuation
allowance of $167 million at December 31, 2016. These credits can be fully utilized when sufficient operating income is generated
by the Company.
An additional $38 million valuation allowance was recorded against state deferred tax assets related to state net operating
losses and other temporary differences, Federal charitable contribution and foreign tax credit carryforwards.
See Note 6-Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for
additional information.
70
Total Company Loss Before Income Tax excluding
Noncontrolling Interest
Income Tax Expense (Benefit)
Effective Income Tax Rate
For the Years Ended December 31,
2016
2015
Variance
$
$
$
$
(535)
10
(1.9)%
$
$
(476)
(125)
26.3%
(59)
135
(28.2)%
Percent
Change
12.4 %
(108.0)%
71
Results of Operations: Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014
Net (Loss) Income Attributable to CONSOL Energy Shareholders
CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $375 million, or a loss per diluted
share of $1.64, for the year ended December 31, 2015, compared to net income attributable to CONSOL Energy shareholders of
$163 million, or earnings of $0.70 per diluted share, for the year ended December 31, 2014.
(Dollars in thousands)
(Loss) Income from Continuing Operations
Loss from Discontinued Operations
Net (Loss) Income
Less: Net Income Attributable to Noncontrolling Interests
Net (Loss) Income Attributable to CONSOL Energy Shareholders
$
$
$
Variance
For the Years Ended December 31,
2014
164,947
(1,857)
163,090
—
163,090
2015
(350,266) $
(14,209)
(364,475) $
10,410
(374,885) $
$
$
$
(515,213)
(12,352)
(527,565)
10,410
(537,975)
CONSOL Energy consists of two principal business divisions: Exploration and Production (E&P) and Pennsylvania (PA)
Mining Operations. The E&P division includes four reportable segments: Marcellus, Utica, Coalbed Methane (CBM) and Other
Gas.
The E&P division contributed a loss before income tax of $679 million for the year ended December 31, 2015, compared
to earnings before income tax of $190 million for the year ended December 31, 2014. Included in the 2015 net loss before income
tax was a loss of $829 million primarily related to the impairment of the carrying value of CONSOL Energy's shallow oil and
natural gas assets due to depressed NYMEX forward strip prices (see Note 9 - Property, Plant and Equipment of the Notes to the
Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).
The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the
Company’s natural gas production and sales portfolio.
in thousands (unless noted)
LIQUIDS
NGLs:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
Oil:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
Condensate:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
GAS
Sales Volume (MMcf)
Sales Price ($/Mcf)
Gross Revenue
Hedging Impact ($/Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement
72
For the Years Ended December 31,
2015
2014
Variance
Percent
Change
33,180
5,530
12.30
68,057
$
$
15,475
2,579
35.70
92,136
17,705
2,951
$
$
(23.40)
(24,079)
592
99
681
114
(89)
(15)
47.94
4,736
$
$
89.10
10,108
$
$
(41.16)
(5,372)
7,598
1,266
26.52
33,586
287,287
2.17
622,080
0.68
196,348
$
$
$
$
$
$
3,298
550
66.96
36,808
$
$
4,300
716
(40.44)
(3,222)
216,260
71,027
4.02
$
(1.85)
868,329
$ (246,249)
0.11
23,193
$
$
0.57
173,155
$
$
$
$
$
$
$
$
$
$
114.4 %
114.4 %
(65.5)%
(26.1)%
(13.1)%
(13.2)%
(46.2)%
(53.1)%
130.4 %
130.2 %
(60.4)%
(8.8)%
32.8 %
(46.0)%
(28.4)%
518.2 %
746.6 %
The E&P division natural gas, NGLs, and oil sales were $729 million for the year ended December 31, 2015, compared
to $1,008 million for the year ended December 31, 2014. The decrease was primarily due to the 46.0% decrease in the average
Gas sales price per Mcf without the impact of derivative instruments, offset in part, by the 39.5% increase in total E&P sales
volumes. The decrease in average sales price was the result of the overall decrease in general market prices.
The E&P division sales volumes, average sales price (including the effects of derivative instruments), and average costs
for all active E&P operations were as follows:
E&P Sales Volumes (Bcfe)
Average Sales Price (per Mcfe)
Average Costs (per Mcfe)
Average Margin
For the Years Ended December 31,
2015
328.7
2014
Variance
Percent
Change
235.7
93.0
39.5 %
$
$
2.81
2.62
0.19
$
$
4.37
3.13
1.24
$
$
(1.56)
(0.51)
(1.05)
(35.7)%
(16.3)%
(84.7)%
Changes in the average costs per Mcfe were primarily related to the following items:
• The improvement in unit costs is primarily due to the continuing shift towards lower cost Marcellus and Utica Shale
production, ongoing cost reduction efforts and the 39.5% increase in total volumes sold in the period-to-period comparison.
Marcellus production made up 52.4% of E&P sales volumes in the year ended December 31, 2015, compared to 47.4%
in the year ended December 31, 2014. Utica production made up 17.1% of E&P sales volumes in the year ended
December 31, 2015, compared to 7.1% in the year ended December 31, 2014.
• Depreciation, depletion and amortization decreased on a per-unit basis primarily due to the adjustment to the Company's
shallow oil and gas rates following the impairment in carrying value that was recognized in the second quarter of 2015
(see Note 9 - Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of
this Form 10-K for more information), as well as the increase in E&P sales volumes from the Company's lower cost
Marcellus and Utica production. The decrease was offset, in part, by an overall increase in rates due to the reduction in
the 2015 year-end reserves, as well as an increase in total dollars as production continued to grow.
• Lease operating expenses decreased on a per-unit basis in the period-to-period comparison due to the overall increase in
E&P sales volumes. The decrease in unit costs was partially offset by an increase in repairs and maintenance, salt water
disposal costs, and contractual services related to well tending.
The PA Mining Operations division had earnings before income tax of $405 million for the year ended December 31, 2015,
compared to earnings before income tax of $431 million for the year ended December 31, 2014.
Sales tons, average sales price and average cost of goods sold per ton for the PA Mining Operations division were as follows:
For the Years Ended December 31,
2015
2014
Variance
Percent
Change
Company Produced PA Mining Operations Tons sold (in millions)
22.9
26.1
(3.2)
(12.3)%
Average Sales Price per ton sold
Average Cost of Goods Sold per ton
Average Margin
$
$
56.36
41.78
14.58
$
$
61.88
43.63
18.25
$
$
(5.52)
(1.85)
(3.67)
(8.9)%
(4.2)%
(20.1)%
The lower average sales price per ton sold in the 2015 period was primarily the result of the continued decline in both the
domestic and global thermal coal markets. Due to the weak domestic thermal spot market, the PA Mining Operations division
priced 5.5 million tons on the export market for the year ended December 31, 2015, compared to 3.3 million tons for the year
ended December 31, 2014. All other tons were sold on the domestic market.
Changes in the average cost of goods sold per ton were primarily driven by improved operational efficiencies, better geological
conditions, a reduced workforce, a decrease in stream subsidence expense and other ongoing cost reduction efforts. In order to
preserve margins, PA Mining Operations moved to a four-day work week in May 2015, compared to a normal five-day per week
schedule. The decrease in unit costs was primarily the result of Pension and OPEB plan modifications for active employees in
73
September 2014. Refer to the discussion of total Company long-term liabilities below for more information on the effect of the
Pension and OPEB plan modifications.
The Other division includes other business activities not assigned to the E&P or PA Mining Operations divisions, income
taxes, and industrial supplies activity (this subsidiary was sold in December 2014). The Other division had a net loss of $77 million
for the year ended December 31, 2015, compared to a net loss of $452 million for the year ended December 31, 2014.
Selling, general and administrative (SG&A) costs are allocated to the PA Mining Operations division based upon a shared
service agreement that CONSOL Energy entered into with CNX Coal Resources LP (CNXC) upon execution of the CNXC initial
public offering (IPO). The shared service agreement calls for CONSOL Energy to provide certain selling, general and administrative
services that are paid for monthly, based on an agreed upon fixed fee that is reset at least annually. See Note 25 - Related Party
Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
The remaining SG&A costs are allocated between the E&P and Other divisions based primarily on a percentage of total revenue
and a percentage of total projected capital expenditures.
SG&A costs are excluded from the E&P and PA Mining Operations unit costs above. SG&A costs were $158 million for the
year ended December 31, 2015, compared to $211 million for the year ended December 31, 2014. SG&A costs decreased due to
the following items:
(in millions)
Short-Term Incentive Compensation
Stock-Based Compensation
Contributions
Employee Wages and Related Expenses
Consulting and Professional Services
Advertising and Promotion
Rent
Other
For the Years Ended December 31,
2015
2014
Variance
$
$
40
25
1
62
15
7
8
—
$
55
40
9
70
20
7
8
2
Percent
Change
(27.3)%
(37.5)%
(88.9)%
(11.4)%
(25.0)%
— %
— %
(100.0)%
(25.1)%
(15)
(15)
(8)
(8)
(5)
—
—
(2)
(53)
Total Company Selling, General and Administrative Expense
$
158
$
211
$
• The decrease in Short-Term Incentive Compensation was a result of lower payouts in the current period.
•
Stock-Based Compensation decreased $15 million in the period-to-period comparison primarily due to accelerated non-
cash amortization recorded in the prior period for employees who received awards under the Company's Equity Incentive
Plan.
• Contributions decreased $8 million primarily due to a charitable contribution of $6 million to the Boy Scouts of America
that was recorded during the year ended December 31, 2014. The remaining $2 million decrease is due to various
transactions that occurred throughout both periods, none of which were individually material.
• Employee Wages and Related Expenses decreased $8 million primarily due to the Company reorganization that occurred
in the year ended December 31, 2015.
• Consulting and Professional Services decreased $5 million due to various transactions that occurred throughout both
periods, none of which were individually material, including a general decrease in legal expenses during the year ended
December 31, 2015.
Total Company long-term liabilities, such as Other Post-Employment Benefits (OPEB), the salary retirement plan, workers'
compensation, Coal Workers' Pneumoconiosis (CWP), and long-term disability are actuarially calculated for the Company as a
whole. In general, the expenses are then allocated to the segments based upon criteria specific to each liability. Total CONSOL
Energy continuing operations expense related to actuarial liabilities was income of $162 million for the year ended December 31,
2015, compared to expense of $96 million for the year ended December 31, 2014. The decrease of $258 million was primarily
due to modifications made to the OPEB and Pension plans in September 2014 and May 2015. Not included in the 2014 long-term
liability expense totals discussed above is $46 million of expense for cash payments made to active employees in the fourth quarter
of 2014. See Note 14—Pension and Other Postretirement Benefit Plans and Note 15—Coal Workers' Pneumoconiosis (CWP) and
Workers' Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional
details.
74
TOTAL E&P DIVISION ANALYSIS for the year ended December 31, 2015 compared to the year ended December 31, 2014:
The E&P division had a loss before income tax of $679 million for the year ended December 31, 2015 compared to earnings
before income tax of $190 million for the year ended December 31, 2014. Variances by individual E&P segment are discussed
below.
(in millions)
Marcellus
Utica
CBM
Other
Gas
Total
E&P
Marcellus
Utica
CBM
Other
Gas
Total
E&P
For the Year Ended
December 31, 2015
Difference to Year Ended
December 31, 2014
Natural Gas, NGLs and Oil
Sales
Gain on Commodity Derivative
Instruments
Purchased Gas Sales
Miscellaneous Other Income
Gain on Sale of Assets
Total Revenue and Other
Income
Lease Operating Expense
Production, Ad Valorem,
and Other Fees
Transportation, Gathering
and Compression
Depreciation, Depletion
and Amortization
Exploration and
Production Related Other
Costs
Purchased Gas Costs
Other Corporate Expenses
Impairment of Exploration
and Production Properties
Selling, General and
Administrative Costs
Total Exploration and
Production Costs
Interest Expense
Total E&P Division Costs
Earnings (Loss) Before Income
Tax
$
379
$
93
$
202
$
55
$
729
$
(78) $
101
—
—
—
480
44
18
200
162
—
—
—
—
—
424
—
424
6
—
—
—
99
22
2
35
59
—
—
—
—
—
67
—
—
—
269
33
7
85
84
—
—
—
—
—
219
393
14
62
13
363
23
3
23
66
10
11
66
829
102
14
62
13
1,211
122
30
343
371
10
11
66
829
102
86
—
—
—
8
(2)
—
96
30
—
—
—
—
—
118
—
118
209
—
209
1,133
1,884
6
6
1,139
1,890
124
—
124
6
5
—
—
—
11
4
1
28
41
—
—
—
—
—
74
—
74
$ (141) $
(66) $ (279)
63
—
—
—
(78)
(9)
(5)
(11)
216
370
5
2
5
2
(33)
(33)
124
(10)
(5)
(9)
65
(17)
(9)
104
47
(5)
(19)
—
—
—
—
—
(30)
—
(30)
(13)
(13)
4
19
4
19
829
829
(27)
(27)
769
(3)
766
937
(3)
934
$
56
$
(19) $
60
$ (776) $ (679) $
(116) $
(63) $
(48) $ (642) $ (869)
75
MARCELLUS SEGMENT
The Marcellus segment had earnings before income tax of $56 million for the year ended December 31, 2015 compared to
earnings before income tax of $172 million for the year ended December 31, 2014.
Marcellus Gas Sales Volumes (Bcf)
NGLs Sales Volumes (Bcfe)*
Condensate Sales Volumes (Bcfe)*
Total Marcellus Sales Volumes (Bcfe)*
Average Sales Price - Gas (Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Average Sales Price - NGLs (Mcfe)*
Average Sales Price - Condensate (Mcfe)*
Total Average Marcellus Sales Price (per Mcfe)
Average Marcellus Lease Operating Expenses (per Mcfe)
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)
Average Marcellus Transportation, Gathering and Compression Costs (per
Mcfe)
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Marcellus Costs (per Mcfe)
Average Margin for Marcellus (per Mcfe)
For the Years Ended December 31,
2015
149.4
19.0
3.9
172.3
$
$
$
$
$
$
$
2.09
0.67
2.54
5.02
2.79
0.26
0.10
1.16
0.94
2.46
0.33
$
$
$
$
$
$
$
2014
99.4
10.9
1.4
111.7
3.82
0.15
5.77
10.47
4.23
0.41
0.16
0.93
1.19
2.69
1.54
Variance
50.0
8.1
2.5
60.6
$
$
$
$
$
$
$
(1.73)
0.52
(3.23)
(5.45)
(1.44)
(0.15)
(0.06)
0.23
(0.25)
(0.23)
(1.21)
Percent
Change
50.3 %
74.3 %
178.6 %
54.3 %
(45.3)%
346.7 %
(56.0)%
(52.1)%
(34.0)%
(36.6)%
(37.5)%
24.7 %
(21.0)%
(8.6)%
(78.6)%
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content
of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Marcellus segment had natural gas, NGLs and oil sales of $379 million for the year ended December 31, 2015 compared
to $457 million for the year ended December 31, 2014. The $78 million decrease was primarily due to a 45.3% decrease in the
average gas sales price in the period-to-period comparison, partially offset by a 54.3% increase in total Marcellus sales volumes.
The increase in total sales volumes is primarily due to additional wells coming on-line in the current period.
The decrease in the total average Marcellus sales price was primarily the result of the $1.73 per Mcf decrease in gas market
prices, along with a $0.17 per Mcfe decrease in the uplift from NGLs and condensate sales volumes, when excluding the impact
of hedging. These decreases were offset, in part, by a $0.52 per Mcf increase in the gain on commodity derivative instruments
resulting from the Company's hedging program. The increase in the gain was due to an increase in volumes hedged and lower
market prices. These financial hedges represented approximately 90.3 Bcf of the Company's produced Marcellus gas sales volumes
for the year ended December 31, 2015 at an average gain of $1.09 per Mcf. For the year ended December 31, 2014, these financial
hedges represented approximately 70.4 Bcf at an average gain of $0.21 per Mcf.
Total exploration and production costs for the Marcellus segment were $424 million for the year ended December 31, 2015
compared to $300 million for the year ended December 31, 2014. The increase in total dollars and decrease in unit costs for the
Marcellus segment are due to the following items:
• Marcellus lease operating expense was $44 million for the year ended December 31, 2015 compared to $46 million for
the year ended December 31, 2014. The decrease in total dollars was primarily due to a reduction in employee related costs in the
year ended December 31, 2015. The decrease in unit costs was primarily due to the 54.3% increase in total Marcellus sales volumes.
• Marcellus production, ad valorem, and other fees were $18 million for the years ended December 31, 2015 and 2014.
The decrease in unit costs was primarily due to the 54.3% increase in total Marcellus sales volumes offset, in part, by the decrease
in total average Marcellus sales price.
76
• Marcellus transportation, gathering and compression costs were $200 million for the year ended December 31, 2015
compared to $104 million for the year ended December 31, 2014. The $96 million increase in total dollars was primarily related
to an increase in the CONE gathering fee due to the increase in total Marcellus sales volumes (See Note 25 - Related Party
Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information),
an increase in processing fees associated with natural gas liquids primarily due to the 74.3% increase in NGLs sales volumes, and
an increase in utilized firm transportation expense. The increase in unit costs was due to the overall increase in total dollars.
• Depreciation, depletion and amortization costs attributable to the Marcellus segment were $162 million for the year ended
December 31, 2015 compared to $132 million for the year ended December 31, 2014. These amounts included depreciation on a
unit of production basis of $0.92 per Mcf and $1.16 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
UTICA SEGMENT
The Utica segment had a loss before income tax of $19 million for the year ended December 31, 2015 compared to earnings
before income tax of $44 million for the year ended December 31, 2014.
For the Years Ended December 31,
2015
2014
Utica Gas Sales Volumes (Bcf)
NGLs Sales Volumes (Bcfe)*
Oil Sales Volumes (Bcfe)*
Condensate Sales Volumes (Bcfe)*
Total Utica Sales Volumes (Bcfe)*
Average Sales Price - Gas (Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Average Sales Price - NGLs (Mcfe)*
Average Sales Price - Oil (Mcfe)*
Average Sales Price - Condensate (Mcfe)*
Total Average Utica Sales Price (per Mcfe)
Average Utica Lease Operating Expenses (per Mcfe)
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)
38.3
14.1
0.1
3.7
56.2
1.52
0.17
1.39
6.58
3.79
1.75
0.39
0.04
0.61
1.06
$
$
$
$
$
$
$
$
$
$
$
$
Total Average Utica Costs (per Mcfe)
Average Margin for Utica (per Mcfe)
$
$
$
2.10
(0.35) $
Variance
28.0
9.5
0.1
1.9
10.3
4.6
—
1.8
16.7
39.5
3.46
0.12
6.39
$ (1.94)
$ 0.05
$ (5.00)
— $ 6.58
$ (7.90)
11.69
5.27
1.05
0.08
0.42
1.11
2.66
2.61
$ (3.52)
(0.66)
(0.04)
0.19
(0.05)
$ (0.56)
$ (2.96)
Percent
Change
271.8 %
206.5 %
100.0 %
105.6 %
236.5 %
(56.1)%
41.7 %
(78.2)%
100.0 %
(67.6)%
(66.8)%
(62.9)%
(50.0)%
45.2 %
(4.5)%
(21.1)%
(113.4)%
*NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content
of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Utica segment had natural gas, NGLs and oil sales of $93 million for the year ended December 31, 2015 compared
to $87 million for the year ended December 31, 2014. The $6 million increase was primarily due to the 236.5% increase in total
Utica sales volumes, partially offset by the 56.1% decrease in average gas sales price. The 39.5 Bcfe increase in total Utica sales
volumes was due to additional wells coming on-line, primarily in dry Utica areas, in the year ended December 31, 2015.
The decrease in the total average Utica sales price was primarily due to the $1.94 per Mcf decrease in average market
prices, along with a $1.61 decrease in the uplift from NGLs and condensate sales volumes, when excluding the impact of hedging.
These decreases were offset, in part, by a $0.05 per Mcf increase in the gain on commodity derivative instruments in the current
period. Financial hedges represented approximately 5.9 Bcf of the Company's produced Utica gas sales volumes for the year ended
December 31, 2015 at an average gain of $1.08 per Mcf. For the year ended December 31, 2014, these financial hedges represented
approximately 3.5 Bcf at an average gain of $0.35 per Mcf.
77
Total exploration and production costs for the Utica segment were $118 million for the year ended December 31, 2015
compared to $44 million for the year ended December 31, 2014. The increase in total dollars and decrease in unit costs for the
Utica segment are due to the following items:
• Utica lease operating expense was $22 million for the year ended December 31, 2015 compared to $18 million for the
year ended December 31, 2014. The increase in total dollars was primarily due to the increase in production which resulted in
increased repair and maintenance costs, as well as increased contractual services related to well tending. The decrease in unit costs
was primarily due to the 236.5% increase in total Utica sales volumes.
• Utica production, ad valorem, and other fees were $2 million for the year ended December 31, 2015 compared to $1
million for the year ended December 31, 2014. The increase in total dollars was primarily due to an increase in severance tax
expense caused by the increase in total Utica sales volumes. Unit costs were positively impacted by both the increased sales
volumes and the decreased average sales price.
• Utica transportation, gathering and compression costs were $35 million for the year ended December 31, 2015 compared
to $7 million for the year ended December 31, 2014. The $28 million increase in total dollars was primarily related to increased
gathering and processing fees associated with the increased Utica NGLs and gas sales volumes. The increase in unit costs was
due to the increase in total dollars and was offset, in part, by the increase in total Utica sales volumes.
• Depreciation, depletion and amortization costs attributable to the Utica segment were $59 million for the year ended
December 31, 2015 compared to $18 million for the year ended December 31, 2014. These amounts included depreciation on a
unit of production basis of $1.05 per Mcf and $1.09 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
COALBED METHANE (CBM) SEGMENT
The CBM segment had earnings before income tax of $60 million for the year ended December 31, 2015 compared to
earnings before income tax of $108 million for the year ended December 31, 2014.
CBM Gas Sales Volumes (Bcf)
Average Sales Price - Gas (Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Total Average CBM Sales Price (per Mcf)
Average CBM Lease Operating Expenses (per Mcf)
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)
Average CBM Transportation, Gathering and Compression Costs (per Mcf)
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)
Total Average CBM Costs (per Mcf)
Average Margin for CBM (per Mcf)
For the Years Ended December 31,
2015
2014
Variance
Percent
Change
74.9
79.5
(4.6)
(5.8)%
$
$
$
$
$
2.70
0.90
3.60
0.44
0.10
1.13
1.13
2.80
0.80
$
$
$
$
$
4.32
0.05
4.37
0.52
0.15
1.20
1.14
3.01
1.36
$
$
$
$
$
(1.62)
0.85
(37.5)%
1,700.0 %
(0.77)
(0.08)
(0.05)
(0.07)
(0.01)
(0.21)
(0.56)
(17.6)%
(15.4)%
(33.3)%
(5.8)%
(0.9)%
(7.0)%
(41.2)%
The CBM segment had natural gas sales of $202 million for the year ended December 31, 2015 compared to $343 million
for the year ended December 31, 2014. The $141 million decrease was primarily due to a 37.5% decrease in the average gas sales
price, as well as a 5.8% decrease in CBM gas sales volumes. The decrease in CBM sales volumes was primarily due to normal
well declines and less drilling activity.
The total average CBM sales price decreased $0.77 per Mcf due primarily to a $1.62 per Mcf decrease in gas market prices.
The decrease was offset, in part, by a $0.85 per Mcf increase in the gain on commodity derivative instruments resulting from the
Company's hedging program. The increase in the gain was due to lower market prices. These financial hedges represented
approximately 57.5 Bcf of the Company's produced CBM sales volumes for the year ended December 31, 2015 at an average gain
78
of $1.17 per Mcf. For the year ended December 31, 2014, these financial hedges represented approximately 70.0 Bcf at an average
gain of $0.06 per Mcf.
Total exploration and production costs for the CBM segment were $209 million for the year ended December 31, 2015
compared to $239 million for the year ended December 31, 2014. The decrease in total dollars and decrease in unit costs for the
CBM segment were due to the following items:
• CBM lease operating expense was $33 million for the year ended December 31, 2015 compared to $42 million for the
year ended December 31, 2014. The decrease in total dollars was primarily related to a decrease in contractual services related to
well tending and a decrease in repairs and maintenance expense. The decrease in unit costs was due to the decrease in total dollars,
partially offset by the decrease in CBM gas sales volumes.
• CBM production, ad valorem, and other fees were $7 million for the year ended December 31, 2015 compared to $12
million for the year ended December 31, 2014. The $5 million decrease was due to a decrease in severance tax expense resulting
from the decrease in both gas sales volumes and average sales price. Unit costs were positively impacted by the decrease in total
average CBM sales price which was offset, in part, by the decrease in CBM gas sales volumes.
• CBM transportation, gathering and compression costs were $85 million for the year ended December 31, 2015 compared
to $96 million for the year ended December 31, 2014. The $11 million decrease was primarily related to a decrease in repairs and
maintenance, power and utilized firm transportation expense resulting from the decrease in CBM gas sales volumes. Unit costs
were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in CBM gas sales volumes.
• Depreciation, depletion and amortization costs attributable to the CBM segment were $84 million for the year ended
December 31, 2015 compared to $89 million for the year ended December 31, 2014. These amounts included depreciation on a
unit of production basis of $0.73 per Mcf and $0.75 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
OTHER GAS SEGMENT
The Other Gas segment had a loss before income tax of $776 million for the year ended December 31, 2015 compared to a
loss before income tax of $134 million for the year ended December 31, 2014.
For the Years Ended December 31,
Other Gas Sales Volumes (Bcf)
Oil Sales Volumes (Bcfe)*
Total Other Sales Volumes (Bcfe)*
Average Sales Price - Gas (Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Average Sales Price - Oil (Mcfe)*
Total Average Other Sales Price (per Mcfe)
Average Other Lease Operating Expenses (per Mcfe)
Average Other Production, Ad Valorem, and Other Fees (per Mcfe)
Average Other Transportation, Gathering and Compression Costs (per Mcfe)
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Other Costs (per Mcfe)
Average Margin for Other (per Mcfe)
2015
2014
Variance
(2.3)
(0.2)
(2.5)
Percent
Change
(8.5)%
(28.6)%
(9.0)%
27.1
0.7
27.8
$
4.04
0.11
$
$ 14.81
$ (2.01)
$ 0.77
$ (6.66)
(49.8)%
700.0 %
(45.0)%
24.8
0.5
25.3
2.03
0.88
8.15
$
$
$
$
$
4.40
3.03
1.24
0.27
0.90
0.14
$ (1.37)
(0.34)
(0.13)
(0.21)
(0.51)
$ (1.19)
$
$ (1.31) $ (1.13) $ (0.18)
0.96
2.34
1.17
2.85
4.34
5.53
$
(31.1)%
(27.4)%
(48.1)%
(17.9)%
(17.9)%
(21.5)%
(15.9)%
*Oil is converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural
gas,which is not indicative of the relationship of oil and natural gas prices.
79
The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes
purchased gas activity, unrealized gain or loss on commodity derivative instruments, exploration and production related other
costs, other corporate expenses and miscellaneous operational activity not assigned to a specific E&P segment.
Other Gas sales volumes are primarily related to shallow oil and gas production, as well as the Chattanooga shale in Tennessee.
Natural gas, NGLs and oil sales related to the Other Gas segment were $55 million for the year ended December 31, 2015 compared
to $121 million for the year ended December 31, 2014. The decrease in natural gas and oil sales primarily related to the 49.8%
decrease in average gas sales price. Total exploration and production costs related to these other sales were $115 million for the
year ended December 31, 2015 compared to $158 million for the year ended December 31, 2014. The decrease was primarily due
to a decrease in depreciation, depletion and amortization related costs related to the adjustment to the Company's shallow oil and
gas rates after an impairment in the carrying value was recognized in the second quarter of 2015 (see Note 9 - Property, Plant and
Equipment of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information),
as well as a decrease in employee related costs.
The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $197 million as well as cash
settlements of $22 million for the year ended December 31, 2015. For the year ended December 31, 2014, the Company recognized
cash settlements of $3 million. The unrealized gain on commodity derivative instruments represents changes in the fair value of
all of the Company's existing commodity hedges on a mark-to-market basis and is the result of the December 31, 2014 de-
designation of all derivative positions as cash flow hedges. Changes in fair value were recorded in Accumulated Other
Comprehensive Income prior to de-designation.
Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to
fulfill contracts with certain customers. Purchased gas sales revenues were $14 million for the year ended December 31, 2015
compared to $9 million for the year ended December 31, 2014. Purchased gas costs were $11 million for the year ended
December 31, 2015 compared to $7 million for the year ended December 31, 2014. The period-to-period increase in purchased
gas sales revenue was due to the increase in purchased gas sales volumes, offset, in part, by the decrease in market prices.
Purchased Gas Sales Volumes (in billion cubic feet)
Average Sales Price (per Mcf)
Average Cost (per Mcf)
For the Years Ended December 31,
2015
2014
Variance
6.8
2.14
1.59
$
$
1.9
4.65
3.75
$
$
4.9
(2.51)
(2.16)
$
$
Percent
Change
257.9 %
(54.0)%
(57.6)%
Miscellaneous other income was $62 million for the year ended December 31, 2015 compared to $60 million for the year
ended December 31, 2014. The $2 million increase was primarily due to the following items:
(in millions)
Equity in Earnings of Affiliates
Gathering Revenue
Other
Total Miscellaneous Other Income
For the Years Ended December 31,
2015
2014
Variance
$
$
47
10
5
62
$
$
32
24
4
60
$
$
15
(14)
1
2
Percent
Change
46.9 %
(58.3)%
25.0 %
3.3 %
• Equity in Earnings of Affiliates increased $15 million due to an increase in earnings from CONE Midstream Partners LP
and CONE Gathering LLC. See Note 25 - Related Party Transactions of the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional information.
• Gathering Revenue primarily relates to the release (sale) of unutilized firm transportation capacity when possible and
when beneficial in order to minimize unutilized firm transportation expense. Gathering revenue decreased $14 million
in the period-to-period comparison, primarily due to a decrease in the release of capacity.
Gain on sale of assets was $13 million for the year ended December 31, 2015 compared to $46 million for the year ended
December 31, 2014. The $33 million decrease was primarily due to the sale of Utica rights in Marshall County, WV to Noble
Energy, which closed in December 2014 and resulted in a pre-tax gain of $25 million. The remaining decrease was due to various
land asset sales that occurred throughout both periods, none of which were individually material.
80
Exploration and production related other costs were $10 million for the year ended December 31, 2015 compared to $23
million for the year ended December 31, 2014. The $13 million decrease is due to the following items:
(in millions)
Lease Expiration Costs
Seismic Activity
Land Rentals
Permitting Expense
Other
Total Exploration and Other Costs
For the Years Ended December 31,
2015
2014
Variance
$
$
4
—
5
1
—
10
$
$
9
5
5
1
3
23
$
$
(5)
(5)
—
—
(3)
(13)
Percent
Change
(55.6)%
(100.0)%
— %
— %
(100.0)%
(56.5)%
• Lease Expiration Costs decreased by $5 million in the period-to-period comparison, primarily due to a decreased number
•
of leases expiring in the year ended December 31, 2015 as compared to the year ended December 31, 2014.
Seismic Activity decreased by $5 million in the period-to-period comparison, primarily due to cost reduction efforts in
the 2015 period.
Other corporate expenses were $66 million for the year ended December 31, 2015 compared to $47 million for the year
ended December 31, 2014. The $19 million increase in the period-to-period comparison was made up of the following items:
(in millions)
Idle Rig Expense
Severance Expense
Litigation Expense
Insurance Expense
Bank Fees
Unutilized Firm Transportation and Processing Fees
Other
Total Other Corporate Expenses
For the Years Ended December 31,
2015
2014
Variance
$
$
19
5
2
3
—
33
4
66
$
$
— $
—
—
4
4
38
1
47
$
19
5
2
(1)
(4)
(5)
3
19
Percent
Change
100.0 %
100.0 %
100.0 %
(25.0)%
(100.0)%
(13.2)%
300.0 %
40.4 %
•
•
Idle rig fees are related to the temporary idling of some of the Company's natural gas rigs. The Company incurred $19
million of idle rig fees during the year ended December 31, 2015 in response to declining market conditions. No idle rig
fees were incurred during the year ended December 31, 2014.
Severance Expense was a result of the Company reorganization that occurred in the 2015 period. There was no such
expense in the 2014 period.
• Bank Fees decreased $4 million due to the termination of the CNX Gas Senior Secured Credit Agreement on June 18,
2014.
• Unutilized firm transportation costs represent pipeline transportation capacity that the E&P division has obtained to enable
gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas
liquids. Unutilized Firm Transportation and Processing Fees decreased $5 million in the period-to-period comparison
due to an increase in the utilization of the capacity. The Company attempts to minimize this expense by releasing (selling)
unutilized firm transportation capacity to other parties when possible and when beneficial. This revenue is included in
Gathering Revenue in miscellaneous other income above.
Impairment of Exploration and Production Properties of $829 million for the year ended December 31, 2015 relates to the
write down of the Company's shallow oil and gas asset values in June 2015. See Note 9- Property, Plant and Equipment of the
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such write
downs occurred in the year ended December 31, 2014.
Selling, general and administrative (SG&A) costs are allocated to the total E&P segment based on percentage of total
revenue and percentage of total projected capital expenditures. SG&A costs were $102 million for the year ended December 31,
2015 compared to $129 million for the year ended December 31, 2014. Refer to the discussion of total company selling, general
and administrative costs contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this annual
report for a detailed cost explanation.
81
Interest expense related to the E&P division was $6 million for the year ended December 31, 2015 compared to $9 million
for the year ended December 31, 2014. Interest expense was incurred by the Other Gas segment on interest allocated to the E&P
division under CONSOL Energy's credit facility.
TOTAL PA MINING OPERATIONS DIVISION ANALYSIS for the year ended December 31, 2015 compared to the year
ended December 31, 2014:
The PA Mining Operations division principal activities consist of mining, preparation and marketing of thermal coal to power
generators. The division also includes selling, general and administrative costs, as well as various other activities assigned to the
PA Mining Operations division but not included in the cost components on a per unit basis.
The PA Mining Operations division had earnings before income tax of $405 million for the year ended December 31, 2015,
compared to earnings before income tax of $431 million for the year ended December 31, 2014. Variances are discussed below.
(in millions)
Sales:
Coal Sales
Freight Revenue
Miscellaneous Other Income
Gain on Sale of Assets
Total Revenue and Other Income
Operating Costs and Expenses:
Operating Costs
Depreciation, Depletion and Amortization
Total Operating Costs and Expenses
Other Costs and Expenses:
Other Costs
Depreciation, Depletion and Amortization
Total Other Costs and Expenses
Freight Expense
Selling, General and Administrative Costs
Total PA Mining Operations Costs
Interest Expense
Total PA Mining Operations Division Expense
Earnings Before Income Tax
$
$
For the Years Ended December 31,
2015
2014
Variance
$
1,289
20
4
—
1,313
789
167
956
(122)
10
(112)
20
41
905
3
908
405
$
1,617
23
38
1
1,679
975
165
1,140
8
8
16
23
69
1,248
—
1,248
$
431
$
(328)
(3)
(34)
(1)
(366)
(186)
2
(184)
(130)
2
(128)
(3)
(28)
(343)
3
(340)
(26)
The PA Mining Operations coal revenue and cost components on a per unit basis for these periods were as follows:
Company Produced PA Mining Operations Tons Sold (in millions)
Average Sales Price Per PA Mining Operations Ton Sold
Total Operating Costs Per Ton Sold
Total Depreciation, Depletion and Amortization Costs Per Ton Sold
Total Costs Per PA Mining Operations Ton Sold
Average Margin Per PA Mining Operations Ton Sold
For the Years Ended December 31,
2015
2014
Variance
22.9
56.36
34.47
7.31
41.78
14.58
26.1
61.88
37.29
6.34
43.63
18.25
$
$
$
$
$
$
$
$
$
$
$
$
(3.2)
(5.52)
(2.82)
0.97
(1.85)
(3.67)
Percent
Change
(12.3%)
(8.9%)
(7.6%)
15.3%
(4.2%)
(20.1%)
82
Coal Sales
PA Mining Operations coal sales were $1,289 million for the year ended December 31, 2015, compared to $1,617 million
for the year ended December 31, 2014. The $328 million decrease was attributable to a 3.2 million decrease in company produced
tons sold and a $5.52 lower average sales price per ton sold. The lower tons sold and average sales price per PA Mining Operations
ton sold were primarily the result of the continued decline in both the domestic and global thermal coal markets. Due to the weak
domestic thermal spot market, 5.5 million tons were sold on the export market for the year ended December 31, 2015, compared
to 3.3 million tons for the year ended December 31, 2014.
Freight Revenue and Freight Expense
Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on the weight of
coal shipped, negotiated freight rates and method of transportation, primarily rail, used by the customers to which the Company
contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue and freight
expense were both $20 million for the year ended December 31, 2015, compared to $23 million for the year ended December 31,
2014. The $3 million decrease was due to decreased shipments where transportation services were contractually provided.
Miscellaneous Other Income
Miscellaneous other income was $4 million for the year ended December 31, 2015, compared to $38 million for the year
ended December 31, 2014. Approximately $30 million of the decrease related to a coal customer contract buyout in the prior
period. The remaining $4 million decrease was the result of various transactions that occurred during both periods, none of which
were individually material.
Operating Costs and Expenses
Operating costs and expenses are comprised of costs related to produced tons sold, along with changes in both the volumes
and carrying values of coal inventory. Operating costs and expenses include items such as direct operating costs, royalty and
production taxes, employee-related expenses and depreciation, depletion, and amortization costs. Total operating costs and expenses
for the PA Mining Operations division were $956 million for the year ended December 31, 2015, or $184 million lower than the
$1,140 million for the year ended December 31, 2014. Total costs per PA Mining Operations ton sold were $41.78 per ton in the
year ended December 31, 2015, compared to $43.63 per ton in the year ended December 31, 2014. The decrease in the cost of
coal sold was driven by improved operational efficiencies, better geological conditions, a reduced workforce, a decrease in stream
subsidence expense and other ongoing cost reduction efforts. In order to preserve margins, PA Mining Operations moved to a four-
day work week in May 2015, compared to a normal five-day per week schedule. The decrease in unit costs was primarily the
result of a change in allocation methodology, whereby OPEB plan changes are no longer included in unit costs.
Other Costs And Expenses
Other costs and expenses include items that are assigned to the PA Mining Operations division but are not included in unit
costs, such as OPEB plan changes (beginning in the 2015 period), coal reserve holding costs and purchased coal costs. Total other
costs and expenses decreased $128 million in the year ended December 31, 2015 compared to the year ended December 31, 2014.
The decrease was primarily due to income of $129 million related to OPEB plan changes made in May 2015 for retired employees.
Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income Attributable to CONSOL
Energy Shareholders" of this annual report for a detailed cost explanation. No such transactions occurred during the year ended
December 31, 2014.
Selling, General and Administrative Costs
Upon execution of the CNXC IPO, CNXC entered into a service agreement with CONSOL Energy that required CONSOL
Energy to provide certain selling, general and administrative services. These services are paid monthly based on an agreed-upon
fixed fee that is reset at least annually. See Note 25 - Related Party Transactions of the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional information. The amount of selling, general and administrative costs related
to PA Mining Operations was $41 million for the year ended December 31, 2015, compared to $69 million for the year ended
December 31, 2014. Refer to the discussion of total Company selling, general and administrative costs contained in the section
"Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this annual report for a detailed cost explanation.
83
Interest Expense
Interest expense, net of amounts capitalized, of $3 million for the year ended December 31, 2015 is primarily comprised of
interest on the CNXC revolving credit facility that was drawn upon after the CNXC IPO on July 7, 2015.
OTHER DIVISION ANALYSIS for the year ended December 31, 2015 compared to the year ended December 31, 2014:
The Other division includes expenses from various corporate and diversified business activities that are not allocated to the
E&P or PA Mining Operations divisions. The diversified business activities include coal terminal operations, closed and idle mine
activities, water operations, selling, general and administrative activities, income tax (benefit) expense, as well as various other
non-operated activities. In previous periods, this division included activity from the sales of industrial supplies (this subsidiary
was sold in December 2014).
The Other division had a loss before income tax of $202 million for the year ended December 31, 2015, compared to a loss
before income tax of $437 million for the year ended December 31, 2014. The Other division also includes a total Company income
tax benefit related to continuing operations of $125 million for the year ended December 31, 2015, compared to total Company
income tax expense of $15 million for the year ended December 31, 2014.
(in millions)
Other Outside Sales
Miscellaneous Other Income
Gain (Loss) on Sale of Assets
Total Revenue
Miscellaneous Operating Expense
Selling, General and Administrative Costs
Depreciation, Depletion and Amortization
Loss on Debt Extinguishment
Interest Expense
Total Other Costs
Loss Before Income Tax
Income Tax (Benefit) Expense
Net Loss
Other Outside Sales
For the Years Ended December 31,
2015
2014
Variance
$
$
$
31
78
61
170
79
15
20
68
190
372
(202)
(125)
(77) $
$
276
109
(4)
381
460
13
36
95
214
818
(437)
15
(452) $
(245)
(31)
65
(211)
(381)
2
(16)
(27)
(24)
(446)
235
(140)
375
Percent
Change
(88.8)%
(28.4)%
(1,625.0)%
(55.4)%
(82.8)%
15.4 %
(44.4)%
(28.4)%
(11.2)%
(54.5)%
(53.8)%
(933.3)%
(83.0)%
In the year ended December 31, 2015, other outside sales revenue primarily consists of sales from the Company's coal
terminal operations. Coal terminal operations sales were $31 million for the year ended December 31, 2015, compared to $41
million for the year ended December 31, 2014. The $10 million decrease in the period-to-period comparison was primarily due
to a decrease in through-put volumes and rates in the current period.
In the year ended December 31, 2014, other outside sales revenue of $235 million was generated from the Company's
industrial supplies subsidiary. This subsidiary was sold in December 2014. See Note 3 - Acquisitions and Dispositions in the Notes
to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
Miscellaneous Other Income
Miscellaneous other income was $78 million for the year ended December 31, 2015, compared to $109 million for the year
ended December 31, 2014. The change is due to the following items:
84
(in millions)
Equity in Earnings of Affiliates
Purchased Coal Sales
Rental Income
Royalty Income
Interest Income
Right of Way Sales
Other Income
Total Miscellaneous Other Income
For the Years Ended December 31,
2015
2014
Variance
8
2
37
15
2
8
6
78
$
$
18
9
43
20
2
7
10
109
$
$
(10)
(7)
(6)
(5)
—
1
(4)
(31)
$
$
• Equity in Earnings of Affiliates decreased $10 million due to the sale of the Company's 49% interest in Western Allegheny
Energy in September 2015, and the sale of two equity affiliates during the year ended December 31, 2014. See Note 3 -
Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-
K for additional details.
Purchased Coal Sales decreased $7 million due to lower volumes of coal that needed to be purchased to fulfill various
contracts in the current period.
•
• Rental Income decreased $6 million due to a decrease in revenue received from the buyout of certain equipment that was
leased by CONSOL Energy and then subleased to a third-party.
• Royalty Income related to non-operated coal properties decreased $5 million primarily due to the overall decrease in
domestic coal pricing.
Gain (Loss) on Sale of Assets
Gain (loss) on sale of assets increased $65 million in the period-to-period comparison, primarily due to the sale of the
Company's 49% interest in Western Allegheny Energy in September 2015. See Note 3 - Acquisitions and Dispositions in the Notes
to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
Miscellaneous Operating Expense
Miscellaneous operating expense related to the Other division was $79 million for the year ended December 31, 2015,
compared to $460 million for the year ended December 31, 2014. Miscellaneous operating expense decreased in the period-to-
period comparison due to the following items:
85
(in millions)
Industrial Supplies
OPEB Plan Changes
Purchased Coal
Closed and Idle Mines
Pension Settlement
Corporate Initiative Fees and Other Legal Charges
Coal Terminal Operations
Coal Reserve Holding Costs
Revolver Modification Fees
Litigation Expense
Bank Fees
Lease Rental Expense
UMWA Expenses
Workers' Compensation
Severance Payments
Industrial Supplies Working Capital Settlement
Pension Expense
OPEB Expense
Other
For the Years Ended December 31,
2015
2014
Variance
$
— $
(125)
1
9
19
—
20
8
—
—
17
31
10
7
6
6
6
47
17
79
$
231
10
14
20
29
10
26
11
3
3
19
33
10
4
1
—
—
16
20
460
$
$
(231)
(135)
(13)
(11)
(10)
(10)
(6)
(3)
(3)
(3)
(2)
(2)
—
3
5
6
6
31
(3)
(381)
Miscellaneous Operating Expense
$
•
• The decrease in Industrial Supplies is due to the divestiture of the Company's industrial supplies subsidiary in December
2014. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item
8 of this Form 10-K for additional details.
Income of $125 million was the result of modifications made to the OPEB plan in May 2015 for retired employees.
Income of $36 million was the result of changes made to the OPEB plan during the year ended December 31, 2014, offset
by $46 million of expense for cash payments made to active employees. Refer to the discussion of total Company long-
term liabilities contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this annual
report and Note 14—Pension and Other Postretirement Benefit Plans in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for more information.
Purchased Coal costs decreased $13 million due to lower volumes of coal that needed to be purchased to fulfill various
contracts.
•
• Closed and Idle Mines decreased $11 million, primarily due to a $7 million decrease in property taxes and a $5 million
decrease in permitting and compliance costs. The remaining change was due to various transactions that occurred
throughout both periods, none of which were individually material.
Pension Settlement expense is required when lump sum distributions made for a given plan year exceed the total of the
service and interest costs for that same plan year. Settlement accounting was triggered in both periods. See Note 14 -
Pension and Other Postretirement Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item
8 of this Form 10-K for additional detail.
•
• Corporate Initiative Fees and Other Legal Charges reflect various fees for services related to corporate initiatives to
evaluate structure changes and various asset sales. These fees also include legal charges related to land title issues raised
by the Company's joint venture partners in the prior period. See Note 9 - Property, Plant and Equipment and Note 22 -
Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form
10-K for additional information.
• Coal Terminal Operations costs decreased $6 million due to decreased throughput volumes in the current period.
• Revolver Modification Fees decreased $3 million due to an acceleration of previously deferred financing fees in the prior
period.
• Lease Rental Expense decreased $2 million primarily due to the buyout of certain leased equipment in the current period.
• Workers' Compensation increased $3 million primarily due to a change in the allocation methodology in the current
period. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income
Attributable to CONSOL Energy Shareholders" of this Annual Report on Form 10-K for more information.
86
•
•
•
Severance Payments increased $5 million in the period-to-period comparison, primarily related to the company
reorganization that occurred in the year ended December 31, 2015.
Industrial Supplies Working Capital Settlement of $6 million represents the settlement of working capital adjustments
and other matters in the year ended December 31, 2015 related to the divestiture of the Company's industrial supplies
subsidiary in December 2014.
Pension Expense increased $6 million in the period-to-period comparison primarily due to a change in the allocation
methodology in 2015, offset in part, by modifications made to the Pension plan in September 2014. Refer to the discussion
of total Company long-term liabilities contained in the section "Net (Loss) Income Attributable to CONSOL Energy
Shareholders" of this Annual Report on Form 10-K for more information.
• OPEB Expense increased $31 million primarily due to a change in the allocation methodology in 2015. Refer to the
discussion of total Company long-term liabilities contained in the section "Net (Loss) Income Attributable to CONSOL
Energy Shareholders" of this Annual Report on Form 10-K for more information.
Selling, General and Administrative Costs
Selling, general and administrative costs allocated to the Other division were $15 million for the year ended December 31,
2015, compared to $13 million for the year ended December 31, 2014. Refer to the discussion of total Company selling, general
and administrative costs contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this annual
report for more information.
Depreciation, Depletion and Amortization
Deprecation, depletion, and amortization decreased $16 million in the period-to-period comparison, primarily related to a
reduction of the asset retirement obligations at various closed and idled mine locations. The decrease was also the result of the
Company's divestiture of its industrial supplies subsidiary in December 2014, as well as fewer assets placed in service in the
period-to-period comparison.
Loss on Debt Extinguishment
Loss on debt extinguishment of $68 million was recognized in the year ended December 31, 2015 due to the partial purchase
of the 8.25% senior notes that were due in 2020 at an average price equal to 104.6% of the principal amount, and the partial
purchase of the 6.375% senior notes that were due in 2021 at an average price equal to 105.0% of the principal amount. Loss on
debt extinguishment of $95 million was recognized in the year ended December 31, 2014 due to the purchase of all of the 8.00%
senior notes that were due in 2017 at an average premium of 104.0% of the principal amount, and the partial purchase of the 8.25%
senior notes that were due in 2020 at an average premium of 107.5% of the principal amount.
Interest Expense
Interest expense of $190 million was recognized in the year ended December 31, 2015, compared to $214 million in the year
ended December 31, 2014. The $24 million decrease was primarily due to the partial payoff of the 2020 and 2021 bonds in the
year ended December 31, 2015 and the early payoff of the 2017 bonds, issued in March 2015, and the 2022 bonds, issued in April
and August 2014. The decrease was offset, in part, by interest on short-term borrowings.
Income Taxes
The effective income tax rate for continuing operations when excluding noncontrolling interest was 26.3% for the year ended
December 31, 2015, compared to 8.3% for the year ended December 31, 2014. The effective rates for the years ended December 31,
2015 and 2014 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related
to certain discrete transactions. For the year ended December 31, 2015, CONSOL Energy recognized certain tax benefits related
to a prior-year tax provision. In order to maximize cash flow, CONSOL Energy elected to take bonus depreciation upon filing the
2014 tax return. As a result, CONSOL Energy realized a cash refund of $24 million for 2014. The bonus depreciation also created
a net operating loss which was carried back to 2012. The carryback resulted in an additional cash refund of $31 million. However,
these changes resulted in an expense of $27 million related to decreased percentage depletion deductions, offset, in part, by $5
million of tax benefit due to changes in the deduction for certain stock-related compensation.
For the year ended December 31, 2014, CONSOL Energy recognized certain tax benefits as a result of changes in estimates
related to a prior-year tax provision that resulted in a benefit of $10 million primarily related to increased percentage of depletion.
Also, the Internal Revenue Service issued its audit report relating to the examination of CONSOL Energy's 2008 and 2009 U.S.
income tax returns during the year ended December 31, 2014. The result of these findings was a change in timing of certain tax
87
deductions which increased the tax benefit of percentage of depletion by $7 million. Also, as a result of closing the IRS audit,
CONSOL Energy filed amended state income tax returns. The Company filed the required amended returns and realized a discrete
state income tax charge of $5 million which was offset by a federal income tax benefit of $2 million. See Note 6 - Income Taxes
in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Upon changes in facts and circumstances, management may conclude that deferred tax assets for which no valuation allowance
is currently recorded may not be realizable in future periods, resulting in a future charge to record a valuation allowance. A valuation
allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available
evidence, both positive and negative, must be considered in determining the need for a valuation allowance. Positive evidence
considered includes financial and tax earnings generated over the past three years, future income projections based on existing
fixed price contracts and forecasted expenses, reversals of financial to tax temporary differences and the implementation of and/
or ability to employ various tax planning strategies. Negative evidence includes financial and tax losses generated in prior periods
and the inability to achieve forecasted results for those periods. Existing valuation allowances are re-examined under the same
standards of positive and negative evidence. If it is determined that it is more likely than not that a deferred tax asset will be
realized, the appropriate amount of the valuation allowance, if any, is released. Deferred tax assets and liabilities are also re-
measured to reflect changes in underlying tax rates due to law changes. For the year ended December 31, 2015, a review of positive
and negative evidence regarding these tax benefits concluded that the valuation allowances for various CONSOL Energy
subsidiaries was warranted. As a result, CONSOL Energy recorded a valuation allowance of $65 million against certain deferred
tax assets that the Company determined would not be realized.
Total Company (Loss) Earnings Before Income Tax excluding
Noncontrolling Interest
Income Tax (Benefit) Expense
Effective Income Tax Rate
$
$
$
$
(476)
(125)
26.3%
$
$
180
15
8.3%
(656)
(140)
18.0%
For the Years Ended December 31,
2015
2014
Variance
Percent
Change
(364.4)%
(933.3)%
Critical Accounting Policies
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of
America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities,
revenues and expenses, and related disclosure of contingent assets and liabilities in the Consolidated Financial Statements and at
the date of the financial statements. See Note 1-Significant Accounting Policies in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for further discussion. We base our estimates on historical experience and on various other
assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making the judgments
about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates on
an on-going basis. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management
believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments,
assumptions and estimates used in the preparation of the Consolidated Financial Statements.
Other Post Employment Benefits (OPEB), Salaried Pensions, Workers’ Compensation and Coal Workers’ Pneumoconiosis
(CWP)
Liabilities and expenses for OPEB, pension, workers’ compensation and CWP are determined using actuarial methodologies
and incorporate significant assumptions, including the interest rate used to discount the future estimated liability, the expected
long-term rate of return on plan assets, and several assumptions relating to the employee workforce (salary increases, health care
cost trend rates, retirement age, and mortality).
The interest rate used to discount future estimated liabilities is determined using a Company-specific yield curve model
(above-mean) developed with the assistance of an external actuary. The Company-specific yield curve uses a subset of the expanded
bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody’s or Standard
& Poor’s as of the measurement date. The yield curve model parallels the plans’ projected cash flows.
The assumed rate of return on plan assets can also impact CONSOL Energy’s pension liability. The market related asset
value is derived by taking the cost value of assets as of December 31, 2016 and multiplying it by the average 36-month ratio of
the market value of assets to the cost value of assets. CONSOL Energy’s pension plan weighted average asset allocations at
December 31, 2016 consisted of 50% equity securities and 50% debt securities.
88
The estimated liabilities recognized at December 31, 2016 and the benefit payments made for the year end December 31,
2016 were as follows:
Plan
OPEB
Pension
Workers’ Compensation
CWP
Estimated Liability as of
December 31, 2016
$700,085
$115,447
$79,693
$118,836
Benefit Payments for the year ended
December 31, 2016
$45,387
$2,726
$17,028
$11,409
Mine Closure and Gas Well Closing Obligations
The Surface Mining Control and Reclamation Act established operational, reclamation and closure standards for all aspects
of surface mining as well as most aspects of deep mining. CONSOL Energy accrues for the costs of current coal mine disturbance
and final coal mine and gas well closure, including the cost of treating mine water discharge where necessary. Estimates of our
total mine-closing and gas well closing liabilities, which are based upon permit requirements and CONSOL Energy engineering
expertise related to these requirements, including the current portion, were approximately $473.5 million at December 31, 2016.
This liability is reviewed annually, or when events and circumstances indicate an adjustment is necessary, by CONSOL Energy
management and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental
regulations change significantly.
Accounting for Asset Retirement Obligations requires that the fair value of an asset retirement obligation be recognized in
the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset
retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate
to the closure of mines and gas wells and the reclamation of land upon exhaustion of coal and gas reserves. Changes in the variables
used to calculate the liabilities can have a significant effect on the mine closing and gas well closing liabilities. The amounts of
assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated
proved reserves, assumptions involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rate.
Accounting for Asset Retirement Obligations also requires depreciation of the capitalized asset retirement cost and accretion
of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas
the accretion to be recognized will escalate over the life of the producing assets, typically as production declines.
Income Taxes
Deferred tax assets and liabilities are recognized using enacted tax rates for the estimated future tax effects of temporary
differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation
allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. All available evidence, both
positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2016, CONSOL
Energy has deferred tax assets in excess of deferred tax liabilities of approximately $4 million. At December 31, 2016, CONSOL
Energy had a valuation allowance of $283 million on deferred tax assets.
CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more
likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an
evaluation to determine the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to
be realized upon ultimate settlement is determined. A previously recognized tax position is reversed when it is subsequently
determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability
of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various
other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily
apparent from other sources, form the basis for recognizing an uncertain tax liability. Actual results could differ from those estimates
upon subsequent resolution of identified matters. CONSOL Energy has $9 million of uncertain tax liabilities at December 31,
2016.
Stock-Based Compensation
As of December 31, 2016, we have issued four types of share-based payment awards: options, restricted stock units,
performance stock options, and performance share units.
89
The fair value of each restricted stock unit awarded is equivalent to the closing market price of a share of the Company's
stock on the date of the grant. The fair value of each performance share unit is determined by a Monte Carlo simulation method.
The fair value of each option is determined using the Black-Scholes option pricing model. All outstanding performance stock
options are fully vested.
As of December 31, 2016, $40,234 of total unrecognized compensation cost related to unvested awards is expected to be
recognized over a weighted-average period of 2.73 years. See Note 17 - Stock-based Compensation in the Notes to the Audited
Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
Contingencies
CONSOL Energy is currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for
the resolution of these claims. This estimate has been developed in consultation with legal counsel involved in the defense of these
matters and is based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar
matters, and management's intended response. Future results of operations for any particular quarter or annual period could be
materially affected by changes in our assumptions or the outcome of these proceedings. Legal fees associated with defending these
various lawsuits and claims are expensed when incurred. See Note 22-Commitments and Contingent Liabilities in the Notes to
the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
Derivative Instruments
CONSOL Energy enters into financial derivative instruments to manage exposure to natural gas and oil price volatility. We
measure every derivative instrument at fair value and record them on the balance sheet as either an asset or liability. Changes in
fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives
designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in
earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are
reported in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted
transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year. Prior to de-designation
CONSOL Energy utilized only cash flow hedges that were considered highly effective.
CONSOL Energy formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is
highly effective in offsetting changes in fair values or cash flows of the hedge item. If it is determined that a derivative is not
highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge
accounting prospectively.
On December 31, 2014, CONSOL Energy de-designated all of its derivative positions as hedging instruments. Subsequent
changes in fair value were recorded in current earnings. Deferred gains and losses in other comprehensive income as of that date
were recorded in earnings when the related physical transaction occured.
Natural Gas, NGL, Condensate and Oil Reserve ("Natural Gas Reserve") and Coal Reserve Values
There are numerous uncertainties inherent in estimating quantities and values of economically recoverable natural gas and
coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable natural gas and coal
reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and
geological data assembled and analyzed by our staff. Our natural gas reserves are reviewed by independent experts each year. Our
coal reserves are periodically reviewed by an independent third party consultant. Some of the factors and assumptions which
impact economically recoverable reserve estimates include:
•
•
•
•
•
geological conditions;
historical production from the area compared with production from other producing areas;
the assumed effects of regulations and taxes by governmental agencies;
assumptions governing future prices; and
future operating costs.
Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons,
estimates of the economically recoverable quantities of gas and coal attributable to a particular group of properties, and
classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual
90
production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be
material. See "Risk Factors" in Item 1A of this report for a discussion of the uncertainties in estimating our reserves.
Impairment of Long-lived Assets:
CONSOL Energy performs a quantitative annual impairment test during the fourth quarter of each year over proved properties
using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. During
interim periods, management updates these annual tests whenever events or changes in circumstances indicate that a property’s
carrying amount may not be recoverable. Impairment tests require that the Company first compare future undiscounted cash flows
by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows,
a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined
based on discounted cash flow techniques using a market-specific weighted average cost of capital. During the year ended December
31, 2015, certain of the Company’s proved properties, primarily shallow oil and gas assets, failed the undiscounted cash flow
portion of the test. After performing the discounted cash flow portion of the test, CONSOL Energy recorded an impairment of
$824,742 in the Impairment of Exploration and Production Properties in the Consolidated Statements of Income. See Note 1 -
Significant Accounting Policies in Item 8 of this Form 10-K for more information.
There were no other additional impairments related to proved properties in the year ended December 31, 2015. There were
no such impairments for the years ended December 31, 2016 or 2014.
CONSOL Energy evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis. Indicators
of potential impairment include potential shifts in business strategy, overall economic factors and historical experience. If it is
determined that the properties will not yield proved reserves, the related costs are expensed in the period the determination is
made. For the year ended December 31, 2015, unproved property impairments related to the determination that the properties will
not yield proved reserves were $4,163 and are included in Impairment of Exploration and Production Properties in the Consolidated
Statements of Income. No such impairments occurred in the year ended December 31, 2016. See Note 1 - Significant Accounting
Policies in Item 8 of this Form 10-K for more information.
There were no other additional impairments related to unproved properties in the year ended December 31, 2015. There were
no such impairments for the years ended December 31, 2016 and 2014.
91
Liquidity and Capital Resources
CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service
obligations with cash generated from operations and proceeds from borrowings. On June 18, 2014, CONSOL Energy entered into
a five year Credit Agreement for a $2.0 billion senior secured revolving credit facility. In November 2016, the Company's lending
group reaffirmed the $2.0 billion borrowing base of the facility, which expires on June 18, 2019. The facility is secured by
substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up
to $2.0 billion of borrowings, which includes a $750 million letters of credit aggregate sub-limit. CONSOL Energy can request
an additional $500 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the
percentage of facility utilization, measured quarterly. Availability under the facility is limited to a borrowing base, which is
determined by the lenders syndication agent and approved by the required number of lenders in good faith by calculating a value
of CONSOL Energy's proved gas reserves. The facility includes a minimum interest coverage ratio covenant of no less than 2.50
to 1.00, measured quarterly. The interest coverage ratio is calculated as the ratio of Adjusted EBITDA to cash interest expense of
CONSOL Energy and certain of its subsidiaries, excluding CNXC. The interest coverage ratio was 3.49 to 1.00 at December 31,
2016. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction
expenses, extraordinary gains and losses, gains and losses on discontinued operations, losses on debt extinguishment and includes
cash distributions received from affiliates, plus pro-rata earnings from material acquisitions. The facility also includes a minimum
current ratio covenant of no less than 1.00 to 1.00, measured quarterly. The minimum current ratio is calculated as the ratio of
current assets, plus revolver availability, to current liabilities, excluding borrowings under the revolver. This calculation also
excludes all of CNXC's current assets, current liabilities and revolver availability. The current ratio was 2.59 to 1.00 at December 31,
2016. Affirmative and negative covenants in the facility limit the Company's ability to dispose of assets, make investments, purchase
or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the
senior unsecured notes. The credit facility allows unlimited investments in joint ventures for the development and operation of
natural gas gathering systems. The facility permits CONSOL Energy to separate its natural gas and coal businesses if the leverage
ratio (which, is essentially the ratio of debt to EBITDA) of the natural gas business immediately after the separation would not
be greater than 2.75 to 1.00. At December 31, 2016, the facility had $326 million letters of credit outstanding and no outstanding
borrowings, leaving $1,674 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances
to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to
comply with federal, state or other government agencies' statutes and regulations. CONSOL Energy sometimes uses letters of
credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.
In April 2016, the facility was amended to require the Company to: (i) prepay outstanding loans under the revolving credit
facility to the extent that cash on hand exceeds $150 million for two consecutive business days; (ii) mortgage 85% of its proved
reserves and 80% of its proved developed producing reserves, in each case, which are included in the borrowing base; (iii) maintain
applicable deposit, securities and commodities accounts with the lenders or affiliates thereof; and (iv) enter into control agreements
with respect to such applicable accounts. In addition, the Company pledged the equity interest it holds in CONE Gathering, LLC,
and CONE Midstream Partners, LP as collateral to secure loans under the credit agreement.
CONSOL Energy terminated its accounts receivable securitization facility effective July 7, 2015. The outstanding borrowings
were repaid, and the outstanding letters of credit were transferred against the revolving credit facility.
Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. These risks include declines in
the Company's stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial
bank failures. Financial market disruptions may impact the Company's collection of trade receivables. As a result, CONSOL
Energy regularly monitors the creditworthiness of its customers and counterparties and manages credit exposure through payment
terms, credit limits, prepayments and security. CONSOL Energy believes that its current group of customers is financially sound
and represents no abnormal business risk.
CONSOL Energy believes that cash generated from operations, asset sales and the Company's borrowing capacity will be
sufficient to meet the Company's working capital requirements, anticipated capital expenditures (other than major acquisitions),
scheduled debt payments, anticipated dividend payments and to provide required letters of credit. Nevertheless, the ability of
CONSOL Energy to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures,
or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in
the natural gas and coal industries and other financial and business factors, some of which are beyond CONSOL Energy’s control.
In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various
physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has
also entered into various natural gas and NGL swap and option transactions, which exist parallel to the underlying physical
92
transactions. The fair value of these contracts was a net liability of $188 million at December 31, 2016 and a net asset of $267
million at December 31, 2015. The Company has not experienced any issues of non-performance by derivative counterparties.
CONSOL Energy frequently evaluates potential acquisitions. CONSOL Energy has funded acquisitions with cash generated
from operations and a variety of other sources, depending on the size of the transaction, including debt and equity financing. There
can be no assurance that additional capital resources, including debt and equity financing, will be available to CONSOL Energy
on terms which CONSOL Energy finds acceptable, or at all.
Cash Flows (in millions)
Cash provided by operating activities
Cash provided by (used in) investing activities
Cash (used in) provided by financing activities
For the Years Ended December 31,
2016
2015
Change
$
$
$
$
469
487
$
(969) $
$
506
(996) $
$
386
(37)
1,483
(1,355)
Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:
• Net loss increased $475 million in the period-to-period comparison.
• Adjustments to reconcile net income to cash provided by operating activities decreased $829 million due to the
impairment of exploration and production properties recorded in 2015. (See Note 9 - Property, Plant, And Equipment,
in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information). This
adjustment was offset by an increase in the (gain) loss on commodity derivative instruments of $534 million, a net
change in discontinued operations of $293 million (See Note 2 - Discontinued Operations in the Notes to the Audited
Consolidated Financial Statements in Item 8 of this Form 10-K for more information), an increase of $262 million in
other post-employee benefits plan amendments recorded in 2015, and an increase of $261 million related to changes
in deferred taxes.
• Other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout
both periods also contributed to the decrease in operating cash flows.
Cash provided by (used in) investing activities changed in the period-to-period comparison primarily due to the following
items:
• Capital expenditures decreased $756 million in the period-to-period comparison due to the following:
E&P division capital expenditures decreased $667 million due to decreased expenditures in both the Marcellus
and Utica plays resulting from decreased drilling activity, as well as other various transactions that occurred
throughout both periods none of which were individually material.
PA Mining Operations division capital expenditures decreased $85 million primarily due to a $37 million
decrease in equipment purchases and rebuilds, a $25 million decrease in land project expenditures, and various
other items that occurred throughout both periods, none of which were individually material.
Other capital expenditures decreased $4 million due to various transactions that occurred throughout both
periods, none of which were individually material.
•
Proceeds from the sale of assets increased $163 million primarily due to the $213 million received in December 2016
related to the separation of the Marcellus Shale Joint Venture with Noble Energy. This was offset, in part, by the $76
million received in September 2015 related to the sale of CONSOL Energy's interest in its Western Allegheny Energy
joint venture. See Note 3 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements
in Item 8 of this Form 10-K for additional details. The remaining change was due to various land and equipment asset
sales that occurred throughout both periods, none of which were individually material.
• Net investment in equity affiliates changed $158 million in the period-to-period comparison due to $70 million received
in November 2016 in connection with equity affiliate CONE Midstream Partners, LP acquiring an additional 25%
interest in CONE Midstream DevCo I LP, commonly referred to as the "Anchor Systems" (See Note 25 - Related Party
Transactions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional
information), as well as the sale of the Company's 49% interest in Western Allegheny Energy in September 2015
discussed above.
• Discontinued Operations increased $407 million primarily as a result of the sale of the Buchanan Mine and certain
other metallurgical coal reserves and the sale of the Miller Creek and Fola mining complexes in the year ended December
93
31, 2016. (See Note 2 - Discontinued Operations in the Notes to the Audited Consolidated Financial Statements in Item
8 of this Form 10-K for additional information).
Cash (used in) provided by financing activities changed in the period-to-period comparison primarily due to the following
items:
•
•
•
•
•
In the year ended December 31, 2016, CONSOL Energy made payments on the senior secured credit facility of $952
million compared to proceeds from the senior secured credit facility of $952 million in the year ended December 31,
2015.
In the year ended December 31, 2015, CONSOL Energy made net payments of $771 million related to the partial
extinguishment of the 2020 and 2021 bonds offset, in part, by the issuance of the 2023 bonds. No such transactions
occurred in the 2016 period. (See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional details).
In the year ended December 31, 2016, there were $16 million of net proceeds under the CNX Coal Resources LP credit
facility, compared with $185 million in the year ended December 31, 2015.
In the year ended December 31, 2015, CONSOL Energy received proceeds of $148 million from the IPO of CNX Coal
Resources LP. No such transaction occurred in the 2016 period.
In the year ended December 31, 2015, CONSOL Energy repurchased $72 million of its common stock on the open
market under the previously announced share repurchase program. No repurchases were made in the year ended
December 31, 2016.
• The remaining changes are due to various transactions that occurred throughout both periods.
The following is a summary of our significant contractual obligations at December 31, 2016 (in thousands):
Purchase Order Firm Commitments
Gas Firm Transportation and Processing
Long-Term Debt
Interest on Long-Term Debt
Capital (Finance) Lease Obligations
Interest on Capital (Finance) Lease Obligations
Operating Lease Obligations
Long-Term Liabilities—Employee Related (a)
Other Long-Term Liabilities (b)
Total Contractual Obligations (c)
Less Than
1 Year
$
62,680
147,117
1,677
170,229
10,323
2,915
103,325
67,655
532,174
$ 1,098,095
$
$
Payments due by Year
1-3 Years
3-5 Years
More Than
5 Years
Total
31,989
253,235
920
340,319
20,389
4,030
101,792
133,280
93,028
978,982
$
1,542
241,992
296,565
318,432
18,685
1,280
54,537
130,222
57,140
$ 1,120,395
$
— $
622,509
2,453,209
139,181
—
—
80,693
586,601
340,999
$ 4,223,192
96,211
1,264,853
2,752,371
968,161
49,397
8,225
340,347
917,758
1,023,341
$ 7,420,664
_________________________
(a)
Employee related long-term liabilities include other post-employment benefits, work-related injuries and illnesses.
Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from
the pay-out table due to the uncertainty regarding amounts to be contributed. CONSOL Energy does not expect to contribute
to the pension in 2017.
Other long-term liabilities include mine reclamation and closure and other long-term liability costs.
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.
(b)
(c)
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Debt
At December 31, 2016, CONSOL Energy had total long-term debt and capital lease obligations of $2,802 million outstanding,
including the current portion of long-term debt of $12 million. This long-term debt consisted of:
• An aggregate principal amount of $74 million of 8.25% senior unsecured notes due in April 2020. Interest on the notes
is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes is guaranteed by most
of CONSOL Energy’s subsidiaries.
• An aggregate principal amount of $21 million of 6.375% senior unsecured notes due in March 2021. Interest on the notes
is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes is guaranteed by
most of CONSOL Energy's subsidiaries.
• An aggregate principal amount of $1,850 million of 5.875% senior unsecured notes due in April 2022 plus $5 million of
unamortized bond premium. Interest on the notes is payable April 15 and October 15 of each year. Payment of the principal
and interest on the notes is guaranteed by most of CONSOL Energy's subsidiaries.
• An aggregate principal amount of $500 million of 8.00% senior unsecured notes due in April 2023 less $6 million of
unamortized bond discount. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal
and interest on the notes is guaranteed by most of CONSOL Energy's subsidiaries.
• An aggregate principal amount of $103 million of industrial revenue bonds which were issued to finance the Baltimore
port facility and bear interest at 5.75% per annum and mature in September 2025. Interest on the industrial revenue bonds
is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes is guaranteed by
CONSOL Energy.
• Advance royalty commitments of $3 million with an average interest rate of 7.73% per annum.
• An aggregate principal amount of $2 million on a note maturing through March 2018.
• An aggregate principal amount of $49 million of capital leases with a weighted average interest rate of 6.45% per annum.
• An aggregate principal amount of $201 million in outstanding borrowings under the revolver for CNXC. CONSOL
Energy is not a guarantor of CNXC's revolving credit facility.
At December 31, 2016, CONSOL Energy had no borrowings outstanding and approximately $326 million of letters of credit
outstanding under the $2 billion senior secured revolving credit facility.
Total Equity and Dividends
CONSOL Energy had total equity of $3,941 million at December 31, 2016 compared to $4,856 million at December 31,
2015. See the Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for additional details.
Dividend information for the current year to date is as follows:
Declaration Date
February 1, 2016
Amount Per Share
$0.0100
Record Date
February 16, 2016
Payment Date
March 3, 2016
The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of
Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of
Directors determines whether dividends will be paid quarterly. CONSOL Energy suspended its quarterly dividend following the
sale of the Buchanan Mine on March 31, 2016 to further reflect the Company's increased emphasis on growth. The determination
to pay dividends in the future will depend upon, among other things, general business conditions, CONSOL Energy’s financial
results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by
CONSOL Energy and such other factors as the Board of Directors deems relevant. The Company's credit facility limits CONSOL
Energy's ability to pay dividends in excess of an annual rate of $0.50 per share when the Company's leverage ratio exceeds 3.50
to 1.00 and subject to an aggregate amount up to a cumulative credit calculation set forth in the facility. The total leverage ratio
was 4.53 to 1.00 and the cumulative credit was approximately $781 million at December 31, 2016. The calculation of this leverage
ratio excludes CNXC. The credit facility does not permit dividend payments in the event of default. The indentures to the 2022
and 2023 notes limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no defaults,
ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the year ended
December 31, 2016.
On January 20, 2017 the Board of Directors of CONE Midstream GP LLC, the general partner of CONE Midstream Partners
LP, announced the declaration of a cash distribution of $0.2724 per unit with respect to the fourth quarter of 2016. The distribution
will be made on February 14, 2017 to unitholders of record as of the close of business on February 6, 2017. The distribution, which
equates to an annual rate of $1.0896 per unit, represents an increase of 3.6% over the prior quarter, and an increase of 15.3% over
the distribution paid with respect to the fourth quarter of 2015.
95
On January 24, 2017, the Board of Directors of CNXC declared a cash distribution of $0.5125 per unit to all common and
subordinated partner unitholders, including the holder of the general partner interest, and $0.4678 per preferred unit. The cash
distribution will be made on February 15, 2017 to such holders of record at the close of business on February 9, 2017.
Off-Balance Sheet Transactions
CONSOL Energy does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with
unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s financial
condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital
resources which are not disclosed in the Notes to the Audited Consolidated Financial Statements. CONSOL Energy participates
in the UMWA Combined Benefit Fund and the UMWA 1992 Benefit Plan which generally accepted accounting principles recognize
on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance
sheet at December 31, 2016. The various multi-employer benefit plans are discussed in Note 16—Other Employee Benefit Plans
in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K. CONSOL Energy also uses a combination
of surety bonds, corporate guarantees and letters of credit to secure our financial obligations for employee-related, environmental,
performance and various other items which are not reflected on the balance sheet at December 31, 2016. Management believes
these items will expire without being funded. See Note 22—Commitments and Contingencies in the Notes to the Audited
Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details of the various financial guarantees
that have been issued by CONSOL Energy.
Recent Accounting Pronouncements
In January 2017, the FASB issued Update 2017-01 - Business Combinations (Topic 805). This update clarifies the definition
of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for
as acquisitions (or disposals) of assets or businesses. For public business entities, the amendments in this Update are effective for
fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The adoption of this new
guidance is not expected to have a material impact on CONSOL Energy's financial statements.
In December 2016, the FASB issued Update 2016-19 - Technical Corrections and Improvements, which covers a wide range
of Topics in the Accounting Standards Codification (ASC). The amendments in this Update represent changes to clarify, correct
errors, or make minor improvements to the ASC, making it easier to understand and apply by eliminating inconsistencies and
providing clarifications. The amendments generally fall into one of the following categories: amendments related to differences
between original guidance and the ASC, guidance clarification and reference corrections, simplification, or minor improvements.
Most of the amendments in this Update do not require transition guidance and are effective upon issuance of this Update.
In October 2016, the FASB issued Update 2016-17 - Consolidation (Topic 810): Interests Held through Related Parties that
are Under Common Control, which amends the consolidation guidance on how a reporting entity that is the single decision maker
of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common
control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The Update requires the
reporting entity, in determining whether it satisfies the second characteristic of a primary beneficiary, to include its indirect variable
interests in a VIE held through related parties that are under common control on a proportionate basis as opposed to in their entirety.
The amendments in this Update will be applied retrospectively and are effective for fiscal years beginning after December 15,
2016, including interim periods within those fiscal years. The adoption of this new guidance is not expected to have a material
impact on CONSOL Energy's financial statements.
In August 2016, the FASB issued Update 2016-15 - Statement of Cash Flows (Topic 230): Classification of Certain Cash
Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity
in practice. The amendments relate to debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments
or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing,
contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds
from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, and beneficial
interests in securitization transactions. The Update also states that, in the absence of specific guidance for cash receipts and
payments that have aspects of more than one class of cash flows, an entity should classify each separately identifiable source or
use within the cash receipts and payments on the basis of their nature in financing, investing, or operating activities. In situations
in which cash receipts or payments cannot be separated by source or use, the appropriate classification should depend on the
activity that is likely to be the predominant source or use of cash flows for the item. The amendments in the Update will be applied
using a retrospective transition method to each period presented and, for public entities, are effective for fiscal years beginning
after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim
period. The Company is currently evaluating the impact this guidance may have on CONSOL Energy's financial statements.
96
In June 2016, the FASB issued Update 2016-13 - Financial Instruments-Credit Losses (Topic 326): Measurement of Credit
Losses on Financial Instruments, which provides financial statement users with more decision-useful information about the
expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting
date. To achieve this, the amendments in this Update replace the incurred loss impairment methodology in current Generally
Accepted Accounting Principals (GAAP) with a methodology that reflects expected credit losses and requires consideration of a
broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit
losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable
and supportable forecasts that affect the collectibility of the reported amount. The amendments in this Update will be applied using
a modified-retrospective approach and, for public entities, are effective for fiscal years beginning after December 15, 2019 and
interim periods within those annual periods. Early adoption is permitted for fiscal years beginning after December 15, 2018 and
interim periods within those annual periods. The Company believes this guidance will not have a material impact on CONSOL
Energy's financial statements.
In May 2014, the FASB issued Update 2014-09 - Revenue from Contracts with Customers (Topic 606), which supersedes
the revenue recognition requirements in Topic 605 - Revenue Recognition and most industry-specific guidance throughout the
Industry Topics of the Codification. The objective of the amendments in this Update is to improve financial reporting by creating
common revenue recognition guidance for U.S. GAAP and International Financial Reporting Standards (IFRS). The core principle
of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an
amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services and should
disclose sufficient information, both qualitative and quantitative, to enable users of financial statements to understand the nature,
amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The following updates to Topic
606 were made during 2016:
•
•
•
•
In March 2016, the FASB issued Update 2016-08 - Principal versus Agent Considerations (Reporting Revenue Gross
versus Net), which clarifies how an entity determines whether it is a principal or an agent for goods or services promised
to a customer as well as the nature of the goods or services promised to their customers.
In April 2016, the FASB issued Update 2016-10 - Revenue from Contracts with Customers: Identifying Performance
Obligations and Licensing, which seeks to address implementation issues in the areas of identifying performance
obligations and licensing.
In May 2016, the FASB issued Update 2016-12 - Revenue from Contracts with Customers: Narrow Scope Improvements
and Practical Expedients, which seeks to address implementation issues in the areas of collectibility, presentation of sales
taxes, noncash consideration, and completed contracts and contract modifications at transition.
In December 2016, the FASB issued Update 2016-20 - Technical Corrections and Improvements to Topic 606, Revenue
from Contracts with Customers, which includes amendments related to loan guarantee fees, contract costs, provisions
for losses on construction and production-type contracts, scope, disclosures, contract modification, contract asset versus
receivable, refund liability and advertising costs.
The new standards are effective for annual reporting periods beginning after December 15, 2017, with the option to adopt
as early as annual reporting periods beginning after December 15, 2016. Management continues to evaluate the impacts that these
standards will have on CONSOL Energy's financial statements, specifically as it relates to contracts that contain positive electric
power price related adjustments. CONSOL Energy anticipates using the modified retrospective approach at adoption as it relates
to ASU 2014-09.
In March 2016, the FASB issued Update 2016-09 - Compensation-Stock Compensation (Topic 718): Improvements to
Employee Share-Based Payment Accounting, which simplifies several aspects of the accounting for share-based payment
transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on
the statement of cash flows. Specifically, this Update states that: all excess tax benefits and tax deficiencies should be recognized
as income tax expense or benefit in the income statement; excess tax benefits should be classified along with other income tax
cash flows as an operating activity; an entity can make an accounting policy election to either estimate the number of awards that
are expected to vest or account for forfeitures when they occur; the threshold to qualify for equity classification permits withholding
up to the maximum statutory tax rates in the applicable jurisdictions; and cash paid by an employer when directly withholding
shares for tax-withholding purposes should be classified as a financing activity. For public entities, the amendments in this Update
are effective for fiscal years beginning after December 15, 2016 and interim periods within those annual periods. Early adoption
is permitted. The adoption of this new guidance is not expected to have a material impact on CONSOL Energy's financial statements.
In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842), which increases transparency and comparability
among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about
leasing arrangements. Update 2016-02 does retain a distinction between finance leases and operating leases, which is substantially
similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance.
97
Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease
to not significantly change from previous GAAP. For leases with a term of 12 months or less, a lessee is permitted to make an
accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities, but to recognize lease
expense on a straight-line basis over the lease term. For both financing and operating leases, the right-to-use asset and lease liability
will be initially measured at the present value of the lease payments in the statement of financial position.The accounting applied
by a lessor is largely unchanged from that applied under previous GAAP. For public business entities, the amendments in this
Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early
application is permitted. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the
earliest period presented using a modified retrospective approach. The Company is currently evaluating the impact this guidance
may have on CONSOL Energy's financial statements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In addition to the risks inherent in operations, CONSOL Energy is exposed to financial, market, political and economic
risks. The following discussion provides additional detail regarding CONSOL Energy's exposure to the risks of changing commodity
prices, interest rates and foreign exchange rates.
CONSOL Energy is exposed to market price risk in the normal course of selling natural gas and to a lesser extent in the sale
of coal. CONSOL Energy uses fixed-price contracts, options and derivative commodity instruments to minimize exposure to
market price volatility in the sale of natural gas and NGLs. CONSOL Energy sells coal under both short-term and long-term
contracts with fixed price and/or indexed price contracts that reflect market value. Under our risk management policy, it is not our
intent to engage in derivative activities for speculative purposes.
CONSOL Energy has established risk management policies and procedures to strengthen the internal control environment
of the marketing of commodities produced from its asset base. All of the derivative instruments without other risk assessment
procedures are held for purposes other than trading. They are used primarily to mitigate uncertainty, volatility and cover underlying
exposures. CONSOL Energy's market risk strategy incorporates fundamental risk management tools to assess market price risk
and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.
CONSOL Energy believes that the use of derivative instruments, along with our risk assessment procedures and internal
controls, mitigates our exposure to material risks. However, the use of derivative instruments without other risk assessment
procedures could materially affect CONSOL Energy's results of operations depending on market prices. Nevertheless, we believe
that use of these instruments will not have a material adverse effect on our financial position or liquidity.
For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.
At December 31, 2016, our open derivative instruments were in a net liability position with a fair value of $188 million. A
sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments
at December 31, 2016. A hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to
derivatives by $253 million.
CONSOL Energy's interest expense is sensitive to changes in the general level of interest rates in the United States. At
December 31, 2016, CONSOL Energy had $2,573 million aggregate principal amount of debt outstanding under fixed-rate
instruments and $201 million of debt outstanding under variable-rate instruments. CONSOL Energy's primary exposure to market
risk for changes in interest rates relates to our revolving credit facility, under which there were no borrowings at December 31,
2016, and CNXC's revolving credit facility, under which there were $201 million of borrowings at December 31, 2016. A
hypothetical 100 basis-point increase in the average rate for CONSOL Energy's and CNXC's revolving credit facilities would
decrease pre-tax future earnings related to interest expense by $2 million.
Almost all of CONSOL Energy’s transactions are denominated in U.S. dollars, and, as a result, it does not have material
exposure to currency exchange-rate risks.
98
Natural Gas Hedging Volumes
As of January 17, 2017 our hedged gas volumes, which includes a combination of NYMEX financial hedges and index
(NYMEX and basis) hedges and contracts, for the periods indicated are as follows:
For the Three Months Ended
March 31,
June 30,
September 30,
December 31,
Total Year
2017 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf $
2018 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf $
2019 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf $
2020 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf $
2021 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf $
73.3
2.67
54.4
2.75
39.9
2.75
21.1
2.91
1.7
3.08
$
$
$
$
$
76.0
2.62
55.0
2.76
40.3
2.75
21.1
2.91
1.7
3.08
$
$
$
$
$
81.0
2.59
55.6
2.76
40.7
2.75
21.4
2.91
1.7
3.08
$
$
$
$
$
81.0
2.61
55.6
2.75
40.8
2.75
21.4
2.92
1.7
3.08
$
$
$
$
$
311.3
2.61
220.6
2.75
161.7
2.76
85.0
2.91
6.8
3.08
99
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheets at December 31, 2016 and 2015
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015, 2014
Notes to the Audited Consolidated Financial Statements
Page
101
102
103
104
106
107
108
100
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CONSOL Energy Inc. and Subsidiaries
We have audited the accompanying consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries as of December 31,
2016 and 2015, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows
for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed
in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial
position of CONSOL Energy Inc. and Subsidiaries at December 31, 2016 and 2015, and the consolidated results of their operations
and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted
accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
CONSOL Energy Inc. and Subsidiaries' internal control over financial reporting as of December 31, 2016, based on criteria
established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (2013 framework) and our report dated February 8, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 8, 2017
101
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per share data)
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales
(Loss) Gain on Commodity Derivative Instruments
Coal Sales
Other Outside Sales
Purchased Gas Sales
Freight-Outside Coal
Miscellaneous Other Income (Note 4)
Gain on Sale of Assets
Total Revenue and Other Income
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense
Transportation, Gathering and Compression (Note 25)
Production, Ad Valorem, and Other Fees
Depreciation, Depletion and Amortization
Exploration and Production Related Other Costs
Purchased Gas Costs
Other Corporate Expenses
Impairment of Exploration and Production Properties
Selling, General and Administrative Costs
Total Exploration and Production Costs
PA Mining Operations Costs
Operating and Other Costs
Depreciation, Depletion and Amortization
Freight Expense
Selling, General and Administrative Costs
Total PA Mining Operations Costs
Other Costs
Miscellaneous Operating Expense
Selling, General and Administrative Costs
Depreciation, Depletion and Amortization
Loss on Debt Extinguishment
Interest Expense
Total Other Costs
For the Years Ended December 31,
2016
2015
2014
$
$
793,248
(141,021)
1,065,582
32,038
43,256
46,468
167,306
19,498
2,026,375
96,434
374,350
31,049
417,853
14,519
42,717
87,913
—
102,503
1,167,338
733,300
168,195
46,468
37,512
985,475
$
726,921
392,942
1,289,036
30,967
14,450
20,499
144,351
74,173
2,693,339
121,847
343,403
30,438
370,374
10,120
10,721
65,939
828,905
102,229
1,883,976
666,302
176,864
20,499
40,843
904,508
182,869
12,717
12,455
—
191,476
399,517
2,552,330
(525,955)
10,010
(535,965)
(303,183)
(839,148)
8,954
(848,102) $
78,743
14,918
19,882
67,751
199,266
380,560
3,169,044
(475,705)
(125,439)
(350,266)
(14,209)
(364,475)
10,410
(374,885) $
1,004,924
23,193
1,616,874
276,242
8,999
23,133
207,460
43,198
3,204,023
139,242
239,579
39,418
323,600
23,355
7,251
46,838
—
128,731
948,014
982,749
173,316
23,133
68,597
1,247,795
460,429
13,307
35,727
95,267
223,333
828,063
3,023,872
180,151
15,204
164,947
(1,857)
163,090
—
163,090
Total Costs and Expenses
(Loss) Earnings from Continuing Operations Before Income Tax
Income Tax Expense (Benefit) (Note 6)
(Loss) Income from Continuing Operations
Loss from Discontinued Operations, net
Net (Loss) Income
Less: Net Income Attributable to Noncontrolling Interests
Net (Loss) Income Attributable to CONSOL Energy Shareholders
$
The accompanying notes are an integral part of these financial statements.
102
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(CONTINUED)
(Dollars in thousands, except per share data)
(Loss) Earnings Per Share
Basic
(Loss) Income from Continuing Operations
Loss from Discontinued Operations
Total Basic (Loss) Earnings Per Share
Dilutive
(Loss) Income from Continuing Operations
Loss from Discontinued Operations
Total Dilutive (Loss) Earnings Per Share
Dividends Declared Per Share
For the Years Ended December 31,
2016
2015
2014
$
$
$
$
$
(2.38) $
(1.32)
(3.70) $
(2.38) $
(1.32)
(3.70) $
(1.57) $
(0.07)
(1.64) $
(1.57) $
(0.07)
(1.64) $
0.72
(0.01)
0.71
0.71
(0.01)
0.70
0.01
$
0.145
$
0.25
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
Net (Loss) Income
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments (Net
of tax: $16,281, $53,252, ($56,304))
Net Increase in the Value of Cash Flow Hedge (Net of tax: $-,
$-, ($55,767))
Reclassification of Cash Flow Hedges from Other
Comprehensive Income to Earnings (Net of tax: $25,011,
$45,054, $10,465)
For the Years Ended December 31,
2016
2015
2014
$
(839,148) $
(364,475) $
163,090
(33,226)
(86,447)
—
—
94,989
97,316
(43,470)
(78,051)
(18,288)
Other Comprehensive (Loss) Income
(76,696)
(164,498)
174,017
Comprehensive (Loss) Income
(915,844)
(528,973)
337,107
Less: Comprehensive Income Attributable to Noncontrolling
Interests
9,216
10,410
—
Comprehensive (Loss) Income Attributable to CONSOL
Energy Inc. Shareholders
$
(925,060) $
(539,383) $
337,107
The accompanying notes are an integral part of these financial statements.
103
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
ASSETS
Current Assets:
Cash and Cash Equivalents
Accounts and Notes Receivable:
Trade
Other Receivables
Inventories (Note 8)
Recoverable Income Taxes
Prepaid Expenses
Current Assets of Discontinued Operations (Note 2)
Total Current Assets
Property, Plant and Equipment (Note 9):
Property, Plant and Equipment
Less—Accumulated Depreciation, Depletion and Amortization
Property, Plant and Equipment of Discontinued Operations, Net (Note 2)
Total Property, Plant and Equipment—Net
Other Assets:
Deferred Income Taxes (Note 6)
Investment in Affiliates
Other
Other Assets of Discontinued Operations (Note 2)
Total Other Assets
TOTAL ASSETS
December 31,
2016
December 31,
2015
$
60,475
$
72,574
220,222
69,901
65,461
116,851
93,146
83
626,139
151,383
121,735
66,792
13,887
297,287
81,105
804,763
13,771,388
5,630,949
—
8,140,439
13,794,907
5,062,201
936,671
9,669,377
4,290
190,964
222,149
—
417,403
$ 9,183,981
—
237,330
214,388
4,044
455,762
$ 10,929,902
The accompanying notes are an integral part of these financial statements.
104
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except per share data)
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable
Current Portion of Long-Term Debt (Note 12 and Note 13)
Short-Term Notes Payable (Note 10)
Other Accrued Liabilities (Note 11)
Current Liabilities of Discontinued Operations (Note 2)
Total Current Liabilities
Long-Term Debt:
Long-Term Debt (Note 12)
Capital Lease Obligations (Note 13)
Long-Term Debt of Discontinued Operations (Note 2)
Total Long-Term Debt
Deferred Credits and Other Liabilities:
Deferred Income Taxes (Note 6)
Postretirement Benefits Other Than Pensions (Note 14)
Pneumoconiosis Benefits (Note 15)
Mine Closing (Note 7)
Gas Well Closing (Note 7)
Workers’ Compensation (Note 15)
Salary Retirement (Note 14)
Reclamation (Note 7)
Other
Deferred Credits and Other Liabilities of Discontinued Operations (Note 2)
Total Deferred Credits and Other Liabilities
TOTAL LIABILITIES
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 500,000,000 Shares Authorized, 229,443,008 Issued and
Outstanding at December 31, 2016; 229,054,236 Issued and Outstanding at December 31,
2015
Capital in Excess of Par Value
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding
Retained Earnings
Accumulated Other Comprehensive Loss
Common Stock in Treasury, at Cost—No Shares at December 31, 2016 and 2015
Total CONSOL Energy Inc. Stockholders’ Equity
Noncontrolling Interest
TOTAL EQUITY
TOTAL LIABILITIES AND EQUITY
December 31,
2016
December 31,
2015
$
$
241,616
12,000
—
680,348
6,050
940,014
2,722,995
39,074
—
2,762,069
—
659,474
108,073
218,631
223,352
67,277
112,543
—
151,660
—
1,541,010
5,243,093
250,609
9,409
952,000
421,827
51,514
1,685,359
2,703,899
34,884
5,001
2,743,784
74,629
630,892
111,903
227,339
163,842
69,812
91,596
25
166,957
107,988
1,644,983
6,074,126
2,298
2,460,864
—
1,727,789
(392,556)
—
3,798,395
142,493
3,940,888
$ 9,183,981
2,294
2,435,497
—
2,579,834
(315,598)
—
4,702,027
153,749
4,855,776
$ 10,929,902
The accompanying notes are an integral part of these financial statements.
105
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Dollars in thousands, except per share data)
December 31, 2013
Net Income
Gas Cash Flow Hedge (Net of
($45,302) Tax)
Actuarially Determined Long-Term
Liability Adjustments (Net of
($56,304) Tax)
Comprehensive Income
Issuance of Treasury Stock
Issuance of Common Stock
Tax Benefit from Stock-Based
Compensation
Amortization of Stock-Based
Compensation Awards
Dividends ($0.25 per share)
December 31, 2014
Net (Loss) Income
Gas Cash Flow Hedge (Net of
$45,054 Tax)
Actuarially Determined Long-Term
Liability Adjustments (Net of $53,252
Tax)
Comprehensive (Loss) Income
Treasury Stock Activity
Issuance of Common Stock
Retirement of Common Stock
(2,213,100 shares)
Tax Cost from Stock-Based
Compensation
Amortization of Stock-Based
Compensation Awards
Distributions to Noncontrolling
Interest
Proceeds from Sale of MLP Interest
Dividends ($0.145 per share)
December 31, 2015
Net (Loss) Income
Gas Cash Flow Hedge (Net of
$25,011 Tax)
Actuarially Determined Long-Term
Liability Adjustments (Net of $16,281
Tax)
Comprehensive (Loss) Income
Issuance of Common Stock
Treasury Stock Activity
Tax Cost From Stock-Based
Compensation
Amortization of Stock-Based
Compensation Awards
Distributions to Noncontrolling
Interest
Dividends ($0.01 per share)
Common
Stock
Capital in
Excess
of Par
Value
Retained
Earnings
(Deficit)
Accumulated
Other
Comprehensive
Income
(Loss)
Total
CONSOL
Energy Inc.
Stockholders’
Equity
Common
Stock in
Treasury
Non-
Controlling
Interest
Total
Equity
$
2,294
$2,364,592
$ 2,964,520
$
(325,117) $
— $ 5,006,289
$
— $ 5,006,289
—
—
—
—
—
12
—
—
—
—
—
—
—
—
15,004
2,629
41,877
163,090
—
—
163,090
(15,954)
—
—
—
—
(57,506)
—
79,028
94,989
174,017
—
—
—
—
—
2,306
2,424,102
3,054,150
(151,100)
(374,885)
—
—
—
—
—
—
10
—
—
—
—
—
—
—
(374,885)
(12,181)
8,278
—
(22)
(17,683)
(53,969)
—
—
—
—
—
(3,706)
24,506
—
—
—
—
—
—
—
(33,281)
(78,051)
(86,447)
(164,498)
—
—
—
—
—
—
—
—
2,294
2,435,497
2,579,834
(315,598)
—
—
—
—
4
—
—
—
—
—
—
—
—
—
—
—
(4,931)
30,298
—
—
(848,102)
—
—
—
(848,102)
—
(1,649)
—
—
—
(2,294)
(43,470)
(33,488)
(76,958)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
163,090
79,028
94,989
337,107
(15,954)
15,016
2,629
41,877
(57,506)
5,329,458
—
—
—
—
—
—
—
—
—
—
163,090
79,028
94,989
337,107
(15,954)
15,016
2,629
41,877
(57,506)
5,329,458
(374,885)
10,410
(364,475)
(78,051)
(86,447)
—
—
(78,051)
(86,447)
(539,383)
10,410
(528,973)
(12,181)
8,288
(71,674)
(3,706)
24,506
—
—
—
—
—
—
—
(5,060)
148,399
(33,281)
—
(12,181)
8,288
(71,674)
(3,706)
24,506
(5,060)
148,399
(33,281)
4,702,027
153,749
4,855,776
(848,102)
8,954
(839,148)
(43,470)
—
(43,470)
(33,488)
(925,060)
4
(1,649)
(4,931)
262
9,216
(33,226)
(915,844)
—
—
—
4
(1,649)
(4,931)
30,298
1,185
31,483
—
(21,657)
(2,294)
—
(21,657)
(2,294)
December 31, 2016
$
2,298
$2,460,864
$ 1,727,789
$
(392,556) $
— $ 3,798,395
$ 142,493
$ 3,940,888
The accompanying notes are an integral part of these financial statements.
106
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
Cash Flows from Operating Activities:
Net (Loss) Income
For the Years Ended December 31,
2016
2015
2014
$
(839,148) $
(364,475) $
163,090
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided By Continuing Operating
Activities:
Net Loss from Discontinued Operations
Depreciation, Depletion and Amortization
Impairment of Exploration and Production Properties
Non-Cash Other Post-Employment Benefits
Stock-Based Compensation
Gain on Sale of Assets
Loss on Debt Extinguishment
Loss (Gain) on Commodity Derivative Instruments
Net Cash Received in Settlement of Commodity Derivative Instruments
Deferred Income Taxes
Return on Equity Investment
Equity in Earnings of Affiliates
Changes in Operating Assets:
Accounts and Notes Receivable
Inventories
Prepaid Expenses
Changes in Other Assets
Changes in Operating Liabilities:
Accounts Payable
Accrued Interest
Other Operating Liabilities
Changes in Other Liabilities
Other
Net Cash Provided by Continuing Operating Activities
Net Cash Provided by Discontinued Operating Activities
Net Cash Provided by Operating Activities
Cash Flows from Investing Activities:
Capital Expenditures
Proceeds from Noble Exchange Settlement
Proceeds from Sales of Assets
Net Investments in Equity Affiliates
Net Cash Provided by (Used in) Continuing Investing Activities
Net Cash Provided by (Used in) Discontinued Investing Activities
Net Cash Provided by (Used in) Investing Activities
Cash Flows from Financing Activities:
(Payments on) Proceeds from Short-Term Borrowings
Payments on Miscellaneous Borrowings
Payments on Long-Term Notes, including Redemption Premium
Net Proceeds from Revolver - MLP
Distributions to Noncontrolling Interest
Proceeds from Sale of MLP Interest
Proceeds from Issuance of Long-Term Notes
Tax Benefit from Stock-Based Compensation
Dividends Paid
Proceeds from Issuance of Common Stock
Purchases of Treasury Stock
Debt Issuance and Financing Fees
Net Cash (Used in) Provided by Continuing Financing Activities
Net Cash Used in Discontinued Financing Activities
Net Cash (Used in) Provided by Financing Activities
Net Decrease in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
303,183
598,503
—
—
31,483
(19,498)
—
141,021
245,212
120,305
22,268
(53,078)
(48,014)
1,330
84,026
(98,572)
(27,371)
(1,040)
(20,356)
(9,724)
28,820
459,350
9,935
469,285
(226,820)
213,295
59,902
73,743
120,120
367,251
487,371
(952,000)
(8,312)
—
16,000
(21,657)
—
—
—
(2,294)
4
—
(482)
(968,741)
(14)
(968,755)
(12,099)
72,574
60,475
14,209
567,120
828,905
(261,750)
24,513
(74,173)
67,751
(392,942)
196,348
(140,472)
35,466
(54,897)
160,370
5,573
128,405
3,311
(145,875)
26,649
(147,110)
(9,916)
32,667
499,677
6,172
505,849
(982,934)
—
110,571
(84,221)
(956,584)
(39,633)
(996,217)
952,000
(4,282)
(1,263,719)
185,000
(5,060)
148,359
492,760
208
(33,281)
8,288
(71,674)
(22,586)
386,013
(56)
385,957
(104,411)
176,985
72,574
$
1,857
532,643
—
(45,749)
41,877
(43,198)
95,267
(23,193)
19,025
(7,319)
102,174
(49,791)
(89,928)
49,443
4,788
(16,242)
3,974
(9,868)
227,467
(161,024)
45,093
840,386
96,390
936,776
(1,459,452)
—
356,836
95,207
(1,007,409)
(33,973)
(1,041,382)
(11,736)
(10,286)
(1,819,005)
—
—
—
1,859,920
2,629
(57,506)
15,016
—
(24,861)
(45,829)
—
(45,829)
(150,435)
327,420
176,985
$
$
The accompanying notes are an integral part of these financial statements.
107
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
NOTE 1—SIGNIFICANT ACCOUNTING POLICIES:
A summary of the significant accounting policies of CONSOL Energy Inc. and subsidiaries ("CONSOL Energy" or "the
Company") is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial
Statements.
Basis of Consolidation:
The Consolidated Financial Statements include the accounts of CONSOL Energy Inc, and its wholly owned and majority-
owned and/or controlled subsidiaries, including certain variable interest entities that the Company is required to consolidate
pursuant to the Consolidated topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification. The
portion of these entities that is not owned by the Company is presented as non-controlling interest. Investments in business entities
in which CONSOL Energy does not have control, but has the ability to exercise significant influence over the operating and
financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been
eliminated in consolidation. Investments in oil and natural gas producing entities are accounted for under the proportionate
consolidation method.
Discontinued Operations:
Businesses divested are classified in the Consolidated Financial Statements as either discontinued operations or held for sale
when the provision of Accounting Standards Codification (ASC) Topic 205 or ASC Topic 360 are met. For businesses classified
as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation
to assets and liabilities of discontinued operations on the Consolidated Balance Sheets and to discontinued operations on the
Consolidated Statements of Income and Cash Flows for all periods presented. The gains or losses associated with these divested
businesses are recorded in discontinued operations on the Consolidated Statements of Income. The disclosures outside of Note 2-
Discontinued Operations, for all periods presented, in the accompanying notes generally do not include the assets, liabilities, or
operating results of businesses classified as discontinued operations.
Use of Estimates:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses, as well as various disclosures. Actual results could differ from those estimates. The most significant estimates
included in the preparation of the consolidated financial statements are related to other postretirement benefits, coal workers'
pneumoconiosis, workers' compensation, salary retirement benefits, stock-based compensation, asset retirement obligations,
deferred income tax assets and liabilities, contingencies and the values of coal and natural gas, NGLs, condensate and oil
(collectively "natural gas") reserves.
Cash and Cash Equivalents:
Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term
securities with original maturities of three months or less.
Trade Accounts Receivable:
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CONSOL Energy reserves for specific
accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer
bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances.
CONSOL Energy regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific
identification method. Account balances are charged off against the allowance after all means of collection have been exhausted
and the potential for recovery is considered remote. Reserves for uncollectable amounts were not material in the periods presented.
In addition, there were no material financing receivables with a contractual maturity greater than one year at December 31, 2016
or 2015.
108
Inventories:
Inventories are stated at the lower of cost or net realizable value. The cost of coal inventories is determined by the first-in,
first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead, depreciation, depletion,
amortization, and other related costs. The cost of supplies inventory is determined by the average cost method and includes
operating and maintenance supplies to be used in the Company's E&P and coal operations.
Property, Plant and Equipment:
CONSOL Energy uses the successful efforts method of accounting for natural gas producing activities. Costs of property
acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic
valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful
exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after
finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and
mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs
are also amortized on a units-of-production method. Units-of-production amortization rates are revised at least once per year, or
more frequently if events and circumstances indicate an adjustment is necessary. Such revisions are accounted for prospectively
as changes in accounting estimates.
Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing
plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period.
Costs of additional mine facilities required to maintain production after a mine reaches the production stage, generally referred
to as “receding face costs,” are expensed as incurred; however, the costs of additional airshafts and new portals are capitalized.
Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred.
Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location,
extent or quality of ore or minerals before beginning the development stage of the mine.
Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground
development costs, which are costs incurred to make the mineral physically accessible, include costs to prepare property for shafts,
driving main entries for ventilation, haulage, personnel, construction of airshafts, roof protection and other facilities.
Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as
the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. The Company employs this method
to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates
are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or
at a minimum once per year. Any material effect from changes in estimates is disclosed in the period the change occurs. Amortization
of development cost begins when the development phase is complete and the production phase begins. At an underground mine,
the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic
extraction is substantially complete. Coal extracted during the development phase is incidental to the mine's production capacity
and is not considered to shift the mine into the production phase.
Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary; however, the lease
terms are generally extended automatically through the exhaustion of economically recoverable reserves, as long as active mining
continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction and are legally considered
real property interests. Depletion of leased coal interests is computed using the units-of-productions method over proven and
probable coal reserves. The Company also makes advance payments (advanced mining royalties) to lessors under certain lease
agreements that are recoupable against future production, and it makes payments that are generally based upon a specified rate
per ton or a percentage of gross realization from the sale of the coal. The Company evaluates its properties periodically for
impairment issues or whenever events or circumstances indicate that the carrying amount may not be recoverable.
Gas advance royalties are similar in nature to advance mining royalties and are evaluated periodically, or at a minimum once
per year, for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be
recoverable. Any revisions are accounted for prospectively as changes in accounting estimates.
109
Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms,
generally as follows:
Buildings and improvements
Machinery and equipment
Leasehold improvements
Years
10 to 45
3 to 25
Life of Lease
Costs to obtain coal lands are capitalized based on the cost at acquisition and are amortized using the units-of-production
method over all estimated proven and probable coal reserve tons assigned and accessible to the mine. Proven and probable coal
reserves are calculated on a clean coal ton equivalent, which excludes non-recoverable coal reserves and anticipated preparation
plant processing refuse. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed
when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests
begins when the coal reserve is produced. At an underground coal mine, a ton is considered produced once it reaches the surface
area of the mine. Any material effect from changes in estimates is disclosed in the period the change occurs.
Costs for purchased and internally developed software are expensed until it has been determined that the software will result
in probable future economic benefits and management has committed to funding the project. Thereafter, all direct costs of materials
and services incurred in developing or obtaining software, including certain payroll and benefit costs of employees associated
with the project, are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed
seven years.
Capitalization of Interest:
Interest costs associated with the development of significant properties and projects are capitalized until the project is
substantially complete and ready for its intended use. A weighted average cost of borrowing rate is used. For the years ended
December 31, 2016, 2015, and 2014, capitalized interest totaled $1,467, $2,509 and $13,573, respectively.
Impairment of Long-lived Assets:
Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows
estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced
to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity
investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the
assets' carrying value.
Impairment of Proved Properties
CONSOL Energy performs a quantitative annual impairment test, during the fourth quarter of each year, over proved properties
using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. During
interim periods, management updates these annual tests whenever events or changes in circumstances indicate that a property’s
carrying amount may not be recoverable. Impairment tests require that the Company first compare future undiscounted cash flows
by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows,
a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined
based on discounted cash flow techniques using a market-specific weighted average cost of capital.
During the year ended December 31, 2015, certain of the Company’s proved properties, primarily shallow oil and gas assets,
failed the undiscounted cash flow portion of the test. After performing the discounted cash flow portion of the test, CONSOL
Energy recorded an impairment of $824,742, included in Impairment of Exploration and Production Properties in the Consolidated
Statements of Income. Valuation of the impaired assets is a Level 3 measurement as it incorporates significant unobservable inputs,
such as future production levels and operating costs, within the discounted cash flow analysis. The impairment related to
approximately 95% of the Company’s shallow oil and gas assets in West Virginia and Pennsylvania.
There were no other additional impairments related to proved properties in the year ended December 31, 2015. There were
no such impairments for the years ended December 31, 2016 or 2014.
110
Impairment of Unproved Properties
CONSOL Energy evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis. Indicators
of potential impairment include potential shifts in business strategy, overall economic factors and historical experience. If it is
determined that the properties will not yield proved reserves, the related costs are expensed in the period the determination is
made. For the year ended December 31, 2015, unproved property impairments relating to the determination that the properties
will not yield proved reserves were $4,163 and are included in Impairment of Exploration and Production Properties in the
Consolidated Statements of Income. Valuation of the impaired assets is a Level 3 measurement as it incorporates significant
unobservable inputs, such as future production levels and operating costs, within the discounted cash flow analysis. This impairment
primarily related to the court ruling in June 2015 in the state of New York that officially bans hydraulic fracturing.
There were no other additional impairments related to unproved properties in the year ended December 31, 2015. There were
no such impairments for the years ended December 31, 2016 and 2014.
Exploration expense, which is associated primarily with lease expirations, was $14,519, $10,120 and $23,355 for the years
ended December 31, 2016, 2015 and 2014, respectively, and is included in Exploration and Production Related Other Costs in the
Consolidated Statements of Income.
Income Taxes:
Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized
in CONSOL Energy's financial statements or tax returns. The provision for income taxes represents income taxes paid or payable
for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result
from differences between the financial and tax bases of CONSOL Energy's assets and liabilities and are adjusted for changes in
tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more
likely than not that a deferred tax benefit will not be realized.
CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more
likely than not to be sustained upon examination. For positions that do not meet the more likely than not to be sustained criteria,
the Company determines, on a cumulative probability basis, the largest amount of benefit that is more likely than not to be realized
upon ultimate settlement. A previously recognized tax position is reversed when it is subsequently determined that a tax position
no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the
probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that
the Company believes are reasonable under the circumstances. The results of these estimates, that are not readily apparent from
other sources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates
upon subsequent resolution of identified matters.
Postretirement Benefits Other Than Pensions:
Postretirement benefit obligations established by the Coal Industry Retiree Health Benefit Act of 1992 (the Coal Act) are
treated as a multi-employer plan which requires expense to be recorded for the associated obligations as payments are made.
Postretirement benefits other than pensions, except for those established pursuant to the Coal Act, are accounted for in accordance
with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the FASB
Accounting Standards Codification, which requires employers to accrue the cost of such retirement benefits for the employees'
active service periods. Such liabilities are determined on an actuarial basis and CONSOL Energy is primarily self-insured for these
benefits. Differences between actual and expected results or changes in the value of obligations are recognized through Other
Comprehensive Income.
Pneumoconiosis Benefits and Workers' Compensation:
CONSOL Energy is required by federal and state statutes to provide benefits to certain current and former totally disabled
employees or their dependents for awards related to coal workers' pneumoconiosis. CONSOL Energy is also required by various
state statutes to provide workers' compensation benefits for employees who sustain employment-related physical injuries or some
types of occupational disease. Workers' compensation benefits include compensation for their disability, medical costs, and on
some occasions, the cost of rehabilitation. CONSOL Energy is primarily self-insured for these benefits. Provisions for estimated
benefits are determined on an actuarial basis.
111
Gas Well Closing and Mine Closing Costs:
CONSOL Energy accrues for dismantling and removing costs of gas-related facilities, mine closing costs, perpetual water
care costs, and surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental
Obligations Topic of the FASB Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation
be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Accrued costs of dismantling
and removing natural gas-related facilities, mine closing costs (including surface reclamation costs) and perpetual care costs are
regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements. The present
value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Amortization of
the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement
obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines.
Accretion is included in Deprecation, Depletion and Amortization on the Consolidated Statements of Income. Asset retirement
obligations primarily relate to the closure of natural gas wells and coal mines, which includes treatment of water and the reclamation
of land upon exhaustion of coal and natural gas reserves.
Subsidence:
Subsidence occurs when there is sinking or shifting of the ground surface due to the removal of underlying coal. Areas
affected may include, although are not limited to, streams, property, roads, pipelines and other land and surface structures. Total
estimated subsidence claims are recognized in the period when the related coal has been extracted and are included in Operating
and Other Costs on the Consolidated Statements of Income and Other Accrued Liabilities on the Consolidated Balance Sheets.
On occasion, CONSOL Energy prepays the estimated damages prior to undermining the property, in return for a release of liability.
Prepayments are included as assets and either recognized as Prepaid Expenses or in Other Assets on the Consolidated Balance
Sheets if the payment is made less than or greater than one year, respectively, prior to undermining the property.
Retirement Plans:
CONSOL Energy has non-contributory defined benefit retirement plans. Effective December 31, 2015, CONSOL's qualified
defined benefit retirement plans have been frozen. The benefits for these plans are based primarily on years of service and employees'
pay. These plans are accounted for using the guidance outlined in the Compensation - Retirement Benefits Topic of the FASB
Accounting Standards Codification. The cost of these retiree benefits are recognized over the employees' service periods. CONSOL
Energy uses actuarial methods and assumptions in the valuation of defined benefit obligations and the determination of expense.
Differences between actual and expected results or changes in the value of obligations and plan assets are recognized through
Other Comprehensive Income.
Revenue Recognition:
Revenues are recognized when title passes to the customers. For natural gas, NGL and oil sales, this occurs at the contractual
point of delivery. For domestic coal sales, this generally occurs when coal is loaded at the mine, the preparation facility, or offsite
storage locations. For export coal sales, this generally occurs when coal is loaded onto marine vessels at terminal locations. For
terminal, land, and research and development, revenue is recognized generally as the service is provided to the customer.
CONSOL Energy has operational natural gas-balancing agreements. These imbalance agreements are managed internally
using the sales method of accounting. The sales method recognizes revenue when the gas is taken by the purchaser.
CONSOL Energy sells natural gas to accommodate the delivery points of its customers. In general, this gas is purchased at
market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include
a legal right of offset of obligations and have been simultaneously entered into with the counterparty. These transactions qualify
for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are, therefore, recorded
net within the Consolidated Statements of Income in the Purchased Gas Sales line.
CONSOL Energy purchases natural gas produced by third-parties at market prices less a fee. The gas purchased from third-
parties is then resold to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as
Purchased Gas Sales in the Consolidated Statements of Income. Purchased gas sales are recognized when title passes to the
customer. Purchased gas costs are recognized when title passes to CONSOL Energy from the third-party.
112
Freight Revenue and Expense:
Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight-Outside Coal
revenue and Freight Expense, respectively.
Contingencies:
From time to time, CONSOL Energy, or its subsidiaries, is subject to various lawsuits and claims with respect to such matters
as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including
environmental remediation), employment and contract disputes, and other claims and actions, arising out of the normal course of
business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably
estimated. Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based
upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and
management's intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third-parties.
Legal fees associated with defending these various lawsuits and claims are expensed when incurred.
Stock-Based Compensation:
Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated
in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. CONSOL
Energy recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally
the award's vesting term. See Note 17–Stock-Based Compensation for more information.
Earnings per Share:
Basic earnings per share are computed by dividing net income attributable to CONSOL Energy Shareholders by the weighted
average shares outstanding during the reporting period. Dilutive earnings per share are computed similarly to basic earnings per
share, except that the weighted average shares outstanding are increased to include additional shares from stock options,
performance stock options, restricted stock units and performance share units, if dilutive. The number of additional shares is
calculated by assuming that outstanding stock options and performance share options were exercised, that outstanding restricted
stock units and performance share units were released, and that the proceeds from such activities were used to acquire shares of
common stock at the average market price during the reporting period. CONSOL Energy includes the impact of pro forma deferred
tax assets in determining potential windfalls and shortfalls for purposes of calculating assumed proceeds under the treasury stock
method.
The table below sets forth the share-based awards that have been excluded from the computation of the diluted earnings per
share because their effect would be anti-dilutive:
Anti-Dilutive Options
Anti-Dilutive Restricted Stock Units
Anti-Dilutive Performance Share Units
Anti-Dilutive Performance Share Options
For the Years Ended
December 31,
2015
3,621,002
1,375,659
2016
6,208,813
663,003
2,400,326
802,804
113,531
802,804
2014
358,731
—
—
—
10,074,946
5,912,996
358,731
113
The computations for basic and dilutive earnings per share are as follows:
Numerator:
(Loss) Income from Continuing Operations
Less: Net Income Attributable to Noncontrolling Interest
Net (Loss) Income from Continuing Operations attributable to CONSOL
Energy Shareholders
Loss from Discontinued Operations
Net (Loss) Income Attributable to CONSOL Energy Shareholders
Denominator:
Weighted-average shares of common stock outstanding
Effect of dilutive shares
Weighted-average diluted shares of common stock outstanding
(Loss) Earnings Per Share:
Basic (Continuing Operations)
Basic (Discontinued Operations)
Total Basic
Dilutive (Continuing Operations)
Dilutive (Discontinued Operations)
Total Dilutive
Shares of common stock outstanding were as follows:
Balance, Beginning of Year
Issuance Related to Stock-Based Compensation (1)
Retirement of Common Stock (2)
Balance, End of Year
(1) See Note 17–Stock-Based Compensation for additional information.
(2) See Note 5–Stock Repurchase for additional information.
Other Comprehensive Loss:
For the Years Ended
December 31,
2015
2014
2016
$
$
$
$
(535,965) $
8,954
(350,266) $
10,410
164,947
—
(544,919) $
(360,676) $
164,947
(303,183) $
(14,209) $
(1,857)
(848,102) $
(374,885) $
163,090
229,387,403
—
229,387,403
229,186,125
—
229,186,125
229,994,407
1,585,871
231,580,278
$
$
$
$
(2.38) $
(1.32)
(3.70) $
(2.38) $
(1.32)
(3.70) $
(1.57) $
(0.07)
(1.64) $
(1.57) $
(0.07)
(1.64) $
0.72
(0.01)
0.71
0.71
(0.01)
0.70
2016
2015
2014
229,054,236
230,265,463
229,145,736
388,772
—
229,443,008
1,001,873
(2,213,100)
229,054,236
1,119,727
—
230,265,463
Changes in Accumulated Other Comprehensive Loss by component, net of tax, were as follows:
Balance at December 31, 2015
Other Comprehensive Loss before Reclassifications
Amounts Reclassified from Accumulated Other Comprehensive Loss
Current Period Other Comprehensive Loss
Less: Other Comprehensive Income Attributable to Non-Controlling
Interest
Balance at December 31, 2016
Gains on Cash
Flow Hedges
43,470
$
—
(43,470)
(43,470)
Postretirement
Benefits
$
(359,068) $
(61,730)
28,504
(33,226)
Total
(315,598)
(61,730)
(14,966)
(76,696)
$
—
— $
262
(392,556) $
262
(392,556)
114
The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:
Derivative Instruments (Note 21)
Natural Gas Price Swaps and Options
Tax Expense
Net of Tax
Actuarially Determined Long-Term Liability Adjustments* (Note 14 and
Note 15)
Amortization of Prior Service Costs
Recognized Net Actuarial Loss
Curtailment Loss (Gain)
Settlement Loss
Total
Tax (Benefit) Expense
Net of Tax
For the Years Ended December 31,
2016
2015
2014
(68,481) $
25,011
(43,470) $
(123,105) $
45,054
(78,051) $
(28,753)
10,465
(18,288)
(590) $
23,857
—
22,196
45,463
(16,959)
28,504
$
(336,993) $
119,222
5
19,053
(198,713)
74,687
(124,026) $
(22,381)
46,155
(36,182)
29,095
16,687
(6,139)
10,548
$
$
$
$
*Excludes amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the years ended
December 31, 2016, December 31, 2015 and December 31, 2014.
Accounting for Derivative Instruments:
CONSOL Energy enters into financial derivative instruments to manage its exposure to commodity price volatility. The
derivatives are accounted for as an asset or a liability in the accompanying Consolidated Balance Sheets at their fair value using
“Level Two” inputs, which is further defined in Note 20 - Fair Value of Financial Instruments. Changes in the fair values of
derivatives are recorded in earnings unless special hedge accounting criteria are met. For derivatives designated as cash flow
hedges, the effective portions of changes in the fair values of the derivatives are reported in Other Comprehensive Income or Loss
(OCI) on the Consolidated Balance Sheets, net of tax, and reclassified into Gain (Loss) on Commodity Derivative Instruments on
the Consolidated Statements of Income in the same period or periods in which the forecasted transactions affect earnings. Any
ineffective portion of a hedge is recognized in earnings in the current period.
CONSOL Energy de-designated all of its cash flow hedges on December 31, 2014 and accounts for all existing and future
natural gas and NGL commodity hedges on a mark-to-market basis, and records changes in fair value in current period earnings.
In connection with this de-designation, CONSOL Energy froze the balances recorded in Accumulated Other Comprehensive
Income at December 31, 2014 and reclassified balances to earnings as the underlying physical transactions occurred. As of
December 31, 2016, all gains deferred in OCI have been recognized in earnings.
All of CONSOL Energy’s derivative instruments are subject to master netting arrangements with its counterparties, none of
which currently require CONSOL Energy to post collateral for any of its hedges. However, as stated in the counterparty master
agreements, if CONSOL Energy's obligations with one of its counterparties cease to be secured on the same basis as similar
obligations with the other lenders under the credit facility, CONSOL Energy would be required to post collateral for hedges that
are in a liability position in excess of defined thresholds. Each of CONSOL Energy's counterparty master agreements allows, in
the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CONSOL Energy
and the applicable counterparty would net settle all open hedge positions.
CONSOL Energy is exposed to credit risk in the event of non-performance by counterparties, whose creditworthiness is
subject to continuing review. Historically, CONSOL Energy has not experienced any issues of non-performance by derivative
counterparties.
Recent Accounting Pronouncements:
In January 2017, the FASB issued Update 2017-01 - Business Combinations (Topic 805). This update clarifies the definition
of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for
as acquisitions (or disposals) of assets or businesses. For public business entities, the amendments in this Update are effective for
115
fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The adoption of this new
guidance is not expected to have a material impact on CONSOL Energy's financial statements.
In December 2016, the FASB issued Update 2016-19 - Technical Corrections and Improvements, which covers a wide range
of Topics in the Accounting Standards Codification (ASC). The amendments in this Update represent changes to clarify, correct
errors, or make minor improvements to the ASC, making it easier to understand and apply by eliminating inconsistencies and
providing clarifications. The amendments generally fall into one of the following categories: amendments related to differences
between original guidance and the ASC, guidance clarification and reference corrections, simplification, or minor improvements.
Most of the amendments in this Update do not require transition guidance and are effective upon issuance of this Update.
In October 2016, the FASB issued Update 2016-17 - Consolidation (Topic 810): Interests Held through Related Parties that
are Under Common Control, which amends the consolidation guidance on how a reporting entity that is the single decision maker
of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common
control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The Update requires the
reporting entity, in determining whether it satisfies the second characteristic of a primary beneficiary, to include its indirect economic
interests in a VIE held through related parties that are under common control on a proportionate basis as opposed to in their entirety.
The amendments in this Update will be applied retrospectively and are effective for fiscal years beginning after December 15,
2016, including interim periods within those fiscal years. The adoption of this new guidance is not expected to have a material
impact on CONSOL Energy's financial statements.
In August 2016, the FASB issued Update 2016-15 - Statement of Cash Flows (Topic 230): Classification of Certain Cash
Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity
in practice. The amendments relate to debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments
or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing,
contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds
from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, and beneficial
interests in securitization transactions. The Update also states that, in the absence of specific guidance for cash receipts and
payments that have aspects of more than one class of cash flows, an entity should classify each separately identifiable source or
use within the cash receipts and payments on the basis of their nature in financing, investing, or operating activities. In situations
in which cash receipts or payments cannot be separated by source or use, the appropriate classification should depend on the
activity that is likely to be the predominant source or use of cash flows for the item. The amendments in the Update will be applied
using a retrospective transition method to each period presented and, for public entities, are effective for fiscal years beginning
after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim
period. The Company is currently evaluating the impact this guidance may have on CONSOL Energy's financial statements.
In June 2016, the FASB issued Update 2016-13 - Financial Instruments-Credit Losses (Topic 326): Measurement of Credit
Losses on Financial Instruments, which provides financial statement users with more decision-useful information about the
expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting
date. To achieve this, the amendments in this Update replace the incurred loss impairment methodology in current Generally
Accepted Accounting Principals (GAAP) with a methodology that reflects expected credit losses and requires consideration of a
broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit
losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable
and supportable forecasts that affect the collectibility of the reported amount. The amendments in this Update will be applied using
a modified-retrospective approach and, for public entities, are effective for fiscal years beginning after December 15, 2019 and
interim periods within those annual periods. Early adoption is permitted for fiscal years beginning after December 15, 2018 and
interim periods within those annual periods. The Company believes this guidance will not have a material impact on CONSOL
Energy's financial statements.
In May 2014, the FASB issued Update 2014-09 - Revenue from Contracts with Customers (Topic 606), which supersedes
the revenue recognition requirements in Topic 605 - Revenue Recognition and most industry-specific guidance throughout the
Industry Topics of the Codification. The objective of the amendments in this Update is to improve financial reporting by creating
common revenue recognition guidance for U.S. GAAP and International Financial Reporting Standards (IFRS). The core principle
of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an
amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services and should
disclose sufficient information, both qualitative and quantitative, to enable users of financial statements to understand the nature,
amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The following updates to Topic
606 were made during 2016:
116
•
•
•
•
In March 2016, the FASB issued Update 2016-08 - Principal versus Agent Considerations (Reporting Revenue Gross
versus Net), which clarifies how an entity determines whether it is a principal or an agent for goods or services promised
to a customer as well as the nature of the goods or services promised to their customers.
In April 2016, the FASB issued Update 2016-10 - Revenue from Contracts with Customers: Identifying Performance
Obligations and Licensing, which seeks to address implementation issues in the areas of identifying performance
obligations and licensing.
In May 2016, the FASB issued Update 2016-12 - Revenue from Contracts with Customers: Narrow Scope Improvements
and Practical Expedients, which seeks to address implementation issues in the areas of collectibility, presentation of sales
taxes, noncash consideration, and completed contracts and contract modifications at transition.
In December 2016, the FASB issued Update 2016-20 - Technical Corrections and Improvements to Topic 606, Revenue
from Contracts with Customers, which includes amendments related to loan guarantee fees, contract costs, provisions
for losses on construction and production-type contracts, scope, disclosures, contract modification, contract asset versus
receivable, refund liability and advertising costs.
The new standards are effective for annual reporting periods beginning after December 15, 2017, with the option to adopt
as early as annual reporting periods beginning after December 15, 2016. Management continues to evaluate the impacts that these
standards will have on CONSOL Energy's financial statements, specifically as it relates to contracts that contain positive electric
power price related adjustments. CONSOL Energy anticipates using the modified retrospective approach at adoption as it relates
to ASU 2014-09.
In March 2016, the FASB issued Update 2016-09 - Compensation-Stock Compensation (Topic 718): Improvements to
Employee Share-Based Payment Accounting, which simplifies several aspects of the accounting for share-based payment
transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on
the statement of cash flows. Specifically, this Update states that: all excess tax benefits and tax deficiencies should be recognized
as income tax expense or benefit in the income statement; excess tax benefits should be classified along with other income tax
cash flows as an operating activity; an entity can make an accounting policy election to either estimate the number of awards that
are expected to vest or account for forfeitures when they occur; the threshold to qualify for equity classification permits withholding
up to the maximum statutory tax rates in the applicable jurisdictions; and cash paid by an employer when directly withholding
shares for tax-withholding purposes should be classified as a financing activity. For public entities, the amendments in this Update
are effective for fiscal years beginning after December 15, 2016 and interim periods within those annual periods. Early adoption
is permitted. The adoption of this new guidance is not expected to have a material impact on CONSOL Energy's financial statements.
In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842), which increases transparency and comparability
among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about
leasing arrangements. Update 2016-02 does retain a distinction between finance leases and operating leases, which is substantially
similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance.
Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease
to not significantly change from previous GAAP. For leases with a term of 12 months or less, a lessee is permitted to make an
accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities, but to recognize lease
expense on a straight-line basis over the lease term. For both financing and operating leases, the right-to-use asset and lease liability
will be initially measured at the present value of the lease payments in the statement of financial position.The accounting applied
by a lessor is largely unchanged from that applied under previous GAAP. For public business entities, the amendments in this
Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early
application is permitted. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the
earliest period presented using a modified retrospective approach. The Company is currently evaluating the impact this guidance
may have on CONSOL Energy's financial statements.
Reclassifications:
During the year ended December 31, 2016, CONSOL Energy made reclassifications within its financial statements to better
align the Company's financial reporting with its peer group. These reclassifications impacted the Lease Operating Expense,
Transportation, Gathering and Compression, Direct Administrative and Selling, Production Royalty Interests and Purchased Gas
Sales, Production Royalty Interests and Purchased Gas Costs, Operating and Other Costs and Selling, General and Administrative
Costs line items on the Company's Consolidated Statements of Income. These changes are reflected in CONSOL Energy's current
and historic Consolidated Statements of Income, with no effect on previously reported net income (loss).
117
Subsequent Events:
The Company has evaluated all subsequent events through the date the financial statements were issued. No material
recognized or non-recognizable subsequent events were identified.
NOTE 2—DISCONTINUED OPERATIONS:
In August 2016, CONSOL Energy completed the sale of its Miller Creek Mining Complex and Fola Mining
Complex subsidiaries. In the transaction, the buyer acquired the Miller Creek and Fola assets and assumed the Miller Creek and
Fola mine closing and reclamation liabilities; in order to equalize the value exchange, CONSOL Energy paid $28,271 cash at
closing, which included property taxes associated with the properties sold and other closing costs (a portion of which will be held
in escrow for purposes of obtaining the surety bonds required for the the permits to transfer). These amounts were included in Net
Cash Provided by Discontinued Investing Activities on the Consolidated Statements of Cash Flow. In addition, CONSOL Energy
will pay a total of $17,200 in installments over the next four years. The net loss on sale of $53,130, excluding the related impairment
charge discussed below, was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income. Prior
to the closing, the Miller Creek and Fola Mining Complexes were classified as held for sale in discontinued operations and in
accordance with the accounting guidance for Property, Plant and Equipment, assets held for sale are required to be measured at
the lower of the carrying value or fair value less costs to sell. Upon meeting the assets held for sale criteria, the Company determined
the carrying value of the Miller Creek and Fola Mining Complexes exceeded the fair value less costs to sell. As a result, an
impairment charge of $355,681 was recorded during the year ended December 31, 2016. This impairment is included in the Loss
from Discontinued Operations, net on the Consolidated Statements of Income.
In March 2016, CONSOL Energy completed the sale of its membership interests in CONSOL Buchanan Mining Company,
LLC (BMC), which owned and operated the Buchanan Mine located in Mavisdale, Virginia; various assets relating to the Amonate
Mining Complex located in Amonate, Virginia; Russell County, Virginia coal reserves and Pangburn Shaner Fallowfield coal
reserves located in Southwestern, Pennsylvania to Coronado IV LLC ("Coronado"). Various CONSOL Energy assets were excluded
from the sale including coalbed methane, natural gas and minerals other than coal, current assets of BMC, certain coal seams,
certain surface rights, and the Amonate Preparation Plant. Coronado assumed only specified liabilities and various CONSOL
Energy liabilities were excluded and not assumed. The excluded liabilities included BMC’s indebtedness, trade payables and
liabilities arising prior to closing, as well as the liabilities of the subsidiaries other than BMC which are parties to the sale. In
addition, the buyer agreed to pay CONSOL Energy for Buchanan Mine coal sold outside the U.S. and Canada during the five
years following closing a royalty of 20% of any excess of the gross sales price per ton over the following amounts: (1) year one,
$75.00 per ton; (2) year two, $78.75 per ton; (3) year three, $82.69 per ton; (4) year four, $86.82 per ton; (5) year five, $91.16 per
ton. At closing, the parties entered into several agreements including, among others, agreements relating to the coordination and
conduct of gas operations at the mines, an option to purchase the Amonate Preparation Plant and transition services. Cash proceeds
of $402,799 were received at closing and are included in Net Cash Provided by Discontinued Investing Activities on the
Consolidated Statements of Cash Flow. The net loss on the sale was $38,364 and was included in Loss from Discontinued Operations,
net on the Consolidated Statements of Income.
For all periods presented in the accompanying Consolidated Statements of Income, BMC along with the various other assets
and the Miller Creek and Fola Mining Complexes are classified as discontinued operations.
The following table details selected financial information for the divested business included within discontinued operations:
For the Years Ended December 31,
Coal Sales
Freight-Outside Coal
Miscellaneous Other Income
(Loss) Gain on Sale of Assets
Total Revenue and Other Income
Total Costs
Loss From Operations Before Income Taxes
Impairment on Assets Held for Sale
Income Tax Benefit
Loss From Discontinued Operations, net
118
$
$
2016
102,904
1,322
740
(91,785)
13,181
134,248
$ (121,067) $
355,681
(173,565)
$ (303,183) $
$
$
$
2015
367,234
5,098
51
336
372,719
395,913
(23,194) $
—
(8,985)
(14,209) $
$
2014
426,263
5,015
2,635
(6,640)
427,273
431,344
(4,071)
—
(2,214)
(1,857)
The major classes of assets and liabilities of discontinued operations:
Assets:
Accounts Receivable - Trade
Inventories
Prepaid Expense
Other Current Assets
Total Current Assets
Property, Plant and Equipment, Net
Other Assets
Total Assets of Discontinued Operations
Liabilities:
Accounts Payable
Other Current Liabilities
Total Current Liabilities
Long Term Debt
Pneumoconiosis Benefits
Mine Closing
Reclamation
Other liabilities
Total Liabilities of Discontinued Operations
December 31,
2016
December 31,
2015
$
$
$
$
$
$
83
—
—
—
83
—
—
83
36
6,014
6,050
—
—
—
—
—
6,050
$
$
$
$
$
$
49,125
30,646
970
364
81,105
936,671
4,044
1,021,820
20,786
30,728
51,514
5,001
1,129
71,941
34,126
792
164,503
NOTE 3—ACQUISITIONS AND DISPOSITIONS:
In September 2015, CONSOL Energy sold its 49% interest in Western Allegheny Energy (WAE), a joint venture with Rosebud
Mining Company engaged in coal mining activities in Pennsylvania. At closing, CONSOL Energy received $76,297 in cash and
a $2,136 reduction in certain liabilities. During the third quarter of 2015, CONSOL Energy also received a cash distribution of
$10,780 from WAE. The net gain on the sale was $48,468 and was included in the Gain on Sale of Assets in the Consolidated
Statements of Income.
In December 2014, CNX Gas Company LLC (CNX Gas Company), wholly-owned subsidiary of CONSOL Energy, finalized
an agreement with Columbia Energy Ventures (CEVCO) to sublease from CEVCO approximately 20,000 acres of Utica Shale
and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West
Virginia. Up-front bonus consideration of up to $96,106 was to be paid by CONSOL Energy over a five year period, as drilling
occurs, in addition to royalties. CONSOL Energy made payments of $9,000 to CEVCO in the year ended December 31, 2016,
while $50,969 of payments were made in the year ended December 31, 2015. At December 31, 2016, the amounts recorded in
Other Current Liabilities and Other Long-Term Liabilities both on a discounted basis were $3,947 and $26,461, respectively. At
December 31, 2015, the amounts recorded in Other Current Liabilities and Other Long-Term Liabilities on a discounted basis
were $8,349 and $29,333, respectively.
In December 2014, CONSOL Energy completed the sale of its industrial supplies subsidiary to an unrelated third party for
expected net proceeds of approximately $51,000, of which $44,035 was received and included in cash flows from investing
activities during the year ended December 31, 2014. In connection with the sale, CONSOL Energy signed a supply agreement
under which, among other things, it will continue to purchase certain goods exclusively from the new entity for a period of at least
three years. CONSOL Energy recorded a net loss on the sale of $30,845, which was included in Gain on Sale of Assets in the
Consolidated Statements of Income. In December 2015, there was $6,258 of expense related to the settlement of working capital
adjustments and other matters in conjunction with the sale, which was included in Other Costs - Miscellaneous Operating Costs
in the Consolidated Statements of Income.
119
NOTE 4—MISCELLANEOUS OTHER INCOME:
Equity in Earnings of Affiliates - CONE
Rental Income
Right of Way Issuance
Royalty Income - Non-Operated Coal
Gathering Revenue
Coal Contract Buyout
Purchased Coal Sales
Equity in Earnings of Affiliates - Other
Interest Income
Other
Miscellaneous Other Income
NOTE 5— STOCK REPURCHASE:
For the Years Ended December 31,
2014
2015
2016
$
$
48,260
36,059
27,343
20,083
10,834
6,288
5,757
4,818
1,507
6,357
167,306
$
$
43,799
37,984
13,289
15,402
9,530
—
1,596
11,098
2,299
9,354
144,351
$
$
29,807
45,059
7,333
19,653
23,520
30,000
9,029
19,984
2,303
20,772
207,460
In December 2014, CONSOL Energy’s Board of Directors approved a stock repurchase program under which CONSOL
Energy could have purchased up to $250,000 of its common stock over a two year period. Under the terms of the program, CONSOL
Energy was permitted to make repurchases in the open market, in privately negotiated transactions, accelerated repurchase programs
or in structured share repurchase programs. Any repurchases of common stock were to be funded from available cash on hand or
short-term borrowings. The program did not obligate CONSOL Energy to acquire any particular amount of common stock, and
could have been modified or suspended at any time at the Company’s discretion. The program was conducted in compliance with
applicable legal requirements and within the limits imposed by any credit agreement, receivables purchase agreement or indenture
and was subject to market conditions and other factors. No shares were repurchased under this program during the year ended
December 31, 2016. During the year ended December 31, 2015, 2,213,100 shares were repurchased and retired at an average price
of $32.37 per share.
120
NOTE 6—INCOME TAXES:
Income tax expense (benefit) provided on earnings from continuing operations consisted of:
Current:
U.S. Federal
U.S. State
Non-U.S.
Deferred:
U.S. Federal
U.S. State
For The Years Ended December 31,
2014
2015
2016
$
(103,562) $
(8,699)
1,966
(110,295)
$
19,726
(5,657)
964
15,033
124,766
(4,461)
120,305
(181,859)
41,387
(140,472)
18,388
2,724
1,411
22,523
(12,581)
5,262
(7,319)
Total Income Tax Expense (Benefit)
$
10,010
$
(125,439) $
15,204
The components of the net deferred taxes are as follows:
Deferred Tax Assets:
Postretirement benefits other than pensions
Alternative minimum tax
Net operating loss - Federal
Net operating loss - State
Gas derivatives
Gas well closing
Pneumoconiosis benefits
Salary retirement
Mine closing
Foreign tax credit
Workers' compensation
Mine subsidence
Capital lease
Equity Partnerships
Reclamation
Other
Total Deferred Tax Assets
Valuation Allowance
Net Deferred Tax Assets
Deferred Tax Liabilities:
Property, plant and equipment
Equity Partnerships
Advance mining royalties
Gas derivatives
Other
Total Deferred Tax Liabilities
$
December 31,
2016
2015
$
260,959
219,872
144,450
74,310
72,105
68,585
43,997
42,393
39,860
39,850
30,758
29,532
2,925
—
—
66,724
1,136,320
(282,778)
853,542
(782,710)
(40,200)
(22,326)
—
(4,016)
(849,252)
257,604
143,122
165,951
76,171
—
79,246
44,830
30,177
63,399
39,850
31,544
44,317
4,404
45,746
14,122
65,427
1,105,910
(78,306)
1,027,604
(946,778)
—
(44,921)
(105,864)
(4,670)
(1,102,233)
Net Deferred Tax Asset (Liability)
$
4,290
$
(74,629)
121
A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be
realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance.
For the years ended December 31, 2016 and 2015, positive evidence considered included financial earnings generated over the
past three years for certain subsidiaries, reversals of financial to tax temporary differences and the implementation of and/or ability
to employ various tax planning strategies. Negative evidence included financial and tax losses generated in prior periods, the
inability to achieve forecasted results for those periods and the expectation that future financial results from normal operations
would not be sufficient to support full utilization of certain tax credits within the foreseeable future. CONSOL Energy continues
to report, on an after federal tax basis, a deferred tax asset related to state operating losses of $74,310 with a related valuation
allowance of $60,488 at December 31, 2016. The deferred tax asset related to state operating losses, on an after tax adjusted basis,
was $76,171 with a related valuation allowance of $42,983 at December 31, 2015. A review of positive and negative evidence
regarding these tax benefits concluded that the valuation allowances for various CONSOL Energy subsidiaries was warranted.
The net operating losses expire at various times between 2017 and 2036. A valuation allowance on foreign tax credits of $39,850
and $25,903 has been recorded at December 31, 2016 and 2015, respectively. The foreign tax credits expire at various times
between 2021 and 2023. A valuation allowance on charitable contribution carry-forwards of $5,051 has been recorded for 2016.
The charitable contributions carry-forwards expire at various times between 2018 and 2021. No such valuation allowance was
recorded for 2015.
The deferred tax assets attributable to the state tax effect of future deductible temporary differences for certain CONSOL
Energy subsidiaries with histories of financial and tax losses were also reviewed for positive and negative evidence regarding the
realization of the deferred tax assets. A valuation allowance of $10,591 and $9,420 on an after federal tax adjusted basis has also
been recorded for 2016 and 2015, respectively.
During 2016, the deferred tax asset relating to federal alternative minimum tax credits increased $76,750, to $219,872 at
December 31, 2016 from $143,122 at December 31, 2015. This increase was primarily attributable to restoring previously
monetized alternative minimum tax credits. This restoration was created by an agreement reached with the IRS to accelerate certain
tax depreciation deductions in exchange for forgoing previously claimed alternative minimum tax credit monetization. At
December 31, 2016, a valuation allowance of $166,798 was recorded against these alternative minimum tax credits, based on
management's view that negative evidence with respect to their realizability outweighed positive evidence. There was no such
valuation allowance at December 31, 2015. These credits do not expire and will be able to be fully utilized when sufficient operating
income is generated by the Company.
Management will continue to assess the potential for realized deferred tax assets based upon income forecast data and the
feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future
periods, as appropriate, that could materially impact net income.
The following is a reconciliation, stated as a percentage of pretax income, of the United States statutory federal income tax
rate to CONSOL Energy's effective tax rate:
2016
For the Years Ended December 31,
2015
2014
Percent
Amount
Percent
Statutory U.S. federal income tax rate
Excess tax depletion
Effect of domestic production activities
Federal tax accrual to tax return reconciliation
IRS and state tax examination settlements
Net effect of state income taxes
Effect of change in federal valuation allowance
Effect of change in state valuation allowance
Effect of foreign tax
Other
Amount
$ (187,218)
(18,960)
—
(6,789)
36,619
(25,629)
187,759
20,047
1,966
2,215
Income Tax Expense (Benefit) / Effective Rate
$
10,010
3.5
—
1.3
35.0 % $ (166,497)
(29,526)
—
13,576
(36)
(10,109)
25,903
39,492
(6.8)
4.8
(35.1)
(3.7)
964
(0.4)
794
(0.5)
(1.9)% $ (125,439)
Amount
63,053
(42,302)
(1,235)
(8,331)
(5,248)
5,235
—
(1,436)
1,411
4,057
15,204
35.0% $
6.2
—
(2.9)
—
2.1
(5.4)
(8.3)
(0.2)
(0.2)
26.3% $
Percent
35.0%
(23.5)
(0.7)
(4.6)
(2.9)
2.9
—
(0.8)
0.8
2.1
8.3%
As part of CONSOL Energy's IRS examination of the tax years 2010-2013, bonus depreciation was claimed resulting in a
net cash refund of $92,000. The bonus depreciation deduction adversely impacts earnings by reducing the Company's percentage
depletion adjustment on its mining operations and reducing the Section 199 manufacturing deduction in the years 2008-2012. This
122
resulted in a net non-cash charge to earnings of $36,619.
A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:
Balance at beginning of period
Increase in unrecognized tax benefits resulting from tax positions taken during current period
Increase in unrecognized tax benefits resulting from tax positions taken during prior periods
Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities
Balance at end of period
For the Years Ended
December 31,
2016
12,702
666
—
(4,265)
9,103
2015
$
4,265
—
8,437
—
$ 12,702
$
$
If these unrecognized tax benefits were recognized, $666 and $4,265 would affect CONSOL Energy's effective income tax
rate for 2016 and 2015, respectively.
CONSOL Energy and its subsidiaries file income tax returns in the United States and returns within various states and
Canadian jurisdictions. With few exceptions, the Company is no longer subject to United States federal, state, local or non-U.S.
income tax examinations by tax authorities for the years before 2010.
CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. As of December 31,
2016 and 2015, the Company had an accrued liability of $305 and $53, respectively, for interest related to uncertain tax positions.
Interest expense of $252 and $53 was recorded in the Company's Consolidated Statements of Income for the years ended
December 31, 2016 and 2015, respectively. During the years ended December 31, 2016 and 2015, CONSOL Energy paid no
interest related to income tax deficiencies.
CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of December 31,
2016 and 2015, CONSOL Energy had no accrued liabilities for tax penalties.
NOTE 7—GAS WELL CLOSING and MINE CLOSING:
CONSOL Energy accrues for dismantling and removing costs of natural gas related facilities, mine closing costs, perpetual
water care costs, and surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental
Obligations Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes capitalized asset retirement costs
by increasing the carrying amount of related long-lived assets. The obligation for asset retirements is included in Gas Well Closing,
Mine Closing and Other Accrued Liabilities on the Consolidated Balance Sheets.
The reconciliation of changes in the asset retirement obligations at December 31, 2016 and 2015 is as follows:
Balance at beginning of period
Accretion expense
Payments
Revisions in estimated cash flows
Other
Balance at end of period
$
$
$
As of December 31,
2015
2016
454,832
429,967
32,438
23,924
(18,033)
(15,882)
(33,984)
36,320
(5,286)
(785)
429,967
473,544
$
For the year ended December 31, 2015, Other includes ($2,133) related to the disposition of two Perpetual Care sites as part
of the WAE sale (see Note 3 - Acquisitions and Dispositions for more information) and ($2,355) related to the disposition of a
non-producing mine.
123
NOTE 8—INVENTORIES:
Coal
Supplies
Total Inventories
NOTE 9—PROPERTY, PLANT AND EQUIPMENT:
E&P Property, Plant and Equipment
Intangible drilling cost
Proved gas properties
Unproved gas properties
Gas gathering equipment
Gas wells and related equipment
Other gas assets
Gas advance royalties
Total E&P Property, Plant and Equipment
Less: Accumulated Depreciation, Depletion and Amortization
Total E&P Property, Plant and Equipment - Net
PA Mining Operations Property, Plant and Equipment
Coal and other plant and equipment
Coal properties and surface lands
Airshafts
Mine development
Coal advance mining royalties
Leased coal lands
Total PA Mining Operations Property, Plant and Equipment
Less: Accumulated Depreciation, Depletion and Amortization
Total PA Mining Operations Property, Plant and Equipment - Net
Other Property, Plant and Equipment
Coal and other plant and equipment
Coal properties and surface lands
Airshafts
Mine development
Coal advance mining royalties
Leased coal lands
Total Other Property, Plant and Equipment
Less: Accumulated Depreciation, Depletion and Amortization
Total Other Property, Plant and Equipment - Net
December 31,
2016
2015
$
$
7,800
57,661
65,461
$
$
4,660
62,132
66,792
December 31,
2016
$ 3,583,565
2,016,916
1,116,282
1,138,299
791,996
190,406
13,762
$ 8,851,226
3,106,296
$ 5,744,930
2015
$ 3,452,989
1,922,602
1,421,083
1,147,173
785,744
125,691
19,745
$ 8,875,027
2,695,674
$ 6,179,353
$ 2,307,668
458,398
371,752
326,152
16,224
26,566
$ 3,506,760
1,768,712
$ 1,738,048
$ 2,284,103
456,044
351,870
326,225
16,263
26,402
$ 3,460,907
1,603,642
$ 1,857,265
$
$
532,919
481,126
10,003
17,988
310,530
569,333
484,348
10,002
18,073
312,452
60,836
$ 1,413,402
64,765
$ 1,458,973
755,941
657,461
$
762,885
696,088
$
Total Company Property, Plant and Equipment
$ 13,771,388
$ 13,794,907
Less - Total Company Accumulated Depreciation, Depletion and Amortization
5,630,949
5,062,201
Total Company Property, Plant and Equipment - Net
$ 8,140,439
$ 8,732,706
124
The following assets are amortized using the units-of-production method. Amounts reflect properties where mining or drilling
operations have not yet commenced and therefore, are not being amortized for the years ended December 31, 2016 and 2015,
respectively.
Unproved gas properties
Coal properties
Leased coal lands
Airshafts
Coal advance mining royalties
Gas advance royalties
Mine development
Total
December 31,
2016
2015
$ 1,116,282
195,354
36,788
19,693
16,270
13,762
7,771
$ 1,405,920
$ 1,421,083
258,099
44,805
24,674
21,544
19,745
7,930
$ 1,797,880
As of December 31, 2016 and 2015, plant and equipment includes gross assets under capital lease of $77,438 and $79,551,
respectively. Included in Gas gathering equipment under the E&P division is a capital lease for the Jewell Ridge Pipeline of $66,919
at December 31, 2016 and 2015. The E&P division also maintains a capital lease for vehicles of $6,015 and $7,474 at December 31,
2016 and 2015, respectively, which is included in Other gas assets. At December 31, 2016 and 2015, the PA Mining segment
maintains capital leases for vehicles of $2,525 and $1,923, respectively, which are included in Coal and other plant and equipment.
At December 31, 2016 and 2015, the Other segment maintains capital leases for vehicles and computer equipment of $1,979 and
$3,235, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was
$51,213 and $46,503 at December 31, 2016 and 2015, respectively. Amortization expense for capital leases is included in
Depreciation, Depletion and Amortization in the Consolidated Statements of Income. See Note 13–Leases for further discussion
of capital leases.
Industry Participation Agreements
CONSOL Energy had two significant industry participation agreements (referred to as "joint ventures" or "JVs") that provided
drilling and completion carries for the Company's retained interests.
CNX Gas Company is party to a joint development agreement with Hess Ohio Developments, LLC (Hess) with respect to
approximately 155 thousand net Utica Shale acres in Ohio in which each party has a 50% undivided interest. Under the agreement,
as amended, Hess was obligated to pay a total of approximately $335,000 in the form of a 50% drilling carry of certain CONSOL
Energy working interest obligations as the acreage is developed. As of December 31, 2016, Hess' entire carry obligation has been
met.
CNX Gas Company was party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately
700 thousand net Marcellus Shale oil and gas acres in West Virginia and Pennsylvania, in which each party owned a 50% undivided
interest. On October 29, 2016, CNX Gas entered into an Exchange Agreement with Noble Energy, which terminated the joint
development agreement related to the jointly owned gas assets held in connection with the joint venture with Noble and divided
such jointly owned gas assets among CNX Gas and Noble Energy. The transactions contemplated by the Exchange Agreement
was closed on December 1, 2016 with an effective date of October 1, 2016. As part of the exchange: each party will own and
operate a 100% interest in its properties and wells in two separate operating areas; each party will have independent control and
flexibility with respect to the scope and timing of future development over its operating area; and all acreage operated by CONSOL
Energy and Noble Energy, Inc. in their respective operating areas will remain fully dedicated to CONE Midstream Partners LP.
Cash proceeds of approximately $213,295 were received at closing and are included in cash flows from investing activities in the
Consolidated Statements of Cash Flows. The exchange was accounted for as a mineral conveyance, thus no gain or loss was
recorded in connection with the transaction.
NOTE 10—SHORT-TERM NOTES PAYABLE:
CONSOL Energy's current senior secured credit agreement expires on June 18, 2019. The credit facility allows for up to
$2,000,000 of borrowings, which includes a $750,000 letters of credit sub-limit. CONSOL Energy can also request an additional
$500,000 increase in the aggregate borrowing limit amount.
125
The current facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. Fees and
interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is limited
to a borrowing base, which is determined by the lenders syndication agent and approved by the required number of lenders in
good faith by calculating a value of CONSOL Energy's proved natural gas reserves.
The current facility contains a number of affirmative and negative covenants that limit the Company's ability to dispose of
assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation
and amend, modify or restate the senior unsecured notes. In April 2016, the facility was amended to require that the Company
must: (i) prepay outstanding loans under the revolving credit facility to the extent that cash on hand exceeds $150,000 for two
consecutive business days; (ii) mortgage 85% of its proved reserves and 80% of its proved developed producing reserves, in each
case, which are included in the borrowing base; (iii) maintain applicable deposit, securities and commodities accounts with the
lenders or affiliates thereof; and (iv) enter into control agreements with respect to such applicable accounts. In addition, the
Company pledged the equity interest it holds in CONE Gathering, LLC and CONE Midstream Partners, LP as collateral to secure
loans under the credit agreement.
The facility also requires that CONSOL Energy maintains a minimum interest coverage ratio of no less than 2.50 to 1.00,
which is calculated as the ratio of Adjusted EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries,
measured quarterly. CONSOL Energy must also maintain a minimum current ratio of no less than 1.00 to 1.00, which is calculated
as the ratio of current assets, plus revolver availability, to current liabilities, excluding borrowings under the revolver, measured
quarterly. At December 31, 2016, the interest coverage ratio was 3.49 to 1.00 and the current ratio was 2.59 to 1.00. Further, the
credit facility allows unlimited investments in joint ventures for the development and operation of natural gas gathering systems
and permits CONSOL Energy to separate its E&P and coal businesses if the leverage ratio (which is, essentially, the ratio of debt
to EBITDA) of the E&P business immediately after the separation would not be greater than 2.75 to 1.00. The calculation of all
of the ratios exclude CNX Coal Resources LP (CNXC).
At December 31, 2016, the $2,000,000 facility had no borrowings outstanding and $325,676 of letters of credit outstanding,
leaving $1,674,324 of unused capacity. At December 31, 2015, the $2,000,000 facility had $952,000 of borrowings outstanding
and $258,177 of letters of credit outstanding, leaving $789,823 of unused capacity.
NOTE 11—OTHER ACCRUED LIABILITIES:
Gas derivatives
Subsidence liability
Royalties
Accrued interest
Accrued payroll & benefits
Accrued other taxes
Short-term incentive compensation
Deferred Revenue
Equipment leases
Other
Current portion of long-term liabilities:
Postretirement benefits other than pensions
Gas well closing
Mine closing
Workers' compensation
Pneumoconiosis benefits
Long-term disability
Salary retirement
Reclamation
Total Other Accrued Liabilities
126
December 31,
2016
231,573
104,437
44,657
37,366
24,649
20,679
19,497
18,211
15,286
59,025
42,001
17,285
14,276
13,874
10,763
3,865
2,904
—
680,348
$
$
2015
12,206
86,860
38,707
38,406
24,952
10,927
6,802
11,557
15,286
60,052
46,105
15,648
22,599
14,803
9,382
4,248
2,772
515
421,827
$
$
NOTE 12—LONG-TERM DEBT:
Debt:
Senior Notes due April 2022 at 5.875% (Principal of $1,850,000 plus Unamortized
Premium of $4,731 and $5,617, respectively)
Senior Notes due April 2023 at 8.00% (Principal of $500,000 less Unamortized Discount
of $5,656 and $6,561, respectively)
Revolving Credit Facility - CNX Coal Resources LP
MEDCO Revenue Bonds in Series due September 2025 at 5.75%
Senior Notes due April 2020 at 8.25%, Issued at Par Value
Senior Notes due March 2021 at 6.375%, Issued at Par Value
Advance Royalty Commitments (7.73% and 16.35% Weighted Average Interest Rate,
respectively)
Other Long-Term Note Maturing in 2018 (Principal of $1,789 and $3,096 less
Unamortized Discount of $117 and $327, respectively)
Less: Unamortized Debt Issuance Costs
Less: Amounts Due in One Year*
Long-Term Debt
December 31,
2016
2015
$
1,854,731
$
1,855,617
494,344
201,000
102,865
74,470
20,611
493,439
185,000
102,865
74,470
20,611
2,678
3,964
1,672
27,699
2,724,672
1,677
2,722,995
$
2,769
33,017
2,705,718
1,819
2,703,899
$
*Excludes current portion of Capital Lease Obligations of $10,323 and $7,590 at December 31, 2016 and 2015, respectively.
Annual undiscounted maturities on long-term debt during the next five years and thereafter are as follows:
Year ended December 31,
2017
2018
2019
2020
2021
Thereafter
Total Long-Term Debt Maturities
$
Amount
1,804
672
292
275,740
20,861
2,454,043
$
2,753,412
In March 2015, CONSOL Energy closed on the private placement of $500,000 of 8.00% senior notes due in 2023 (the
"Notes") less $7,240 of unamortized bond discount. The Notes are guaranteed by substantially all of CONSOL Energy's wholly-
owned domestic restricted subsidiaries. CONSOL Energy used the net proceeds of the sale of the Notes, together with borrowings
under its revolving credit facility, to purchase $937,822 of its outstanding 8.25% senior notes due in 2020 and $229,176 of its
outstanding 6.375% senior notes due in 2021. As part of this transaction, $67,734 was included in Loss on Debt Extinguishment
on the Consolidated Statements of Income.
In April 2015, CONSOL Energy purchased $2,508 of its outstanding 8.25% senior notes due in 2020 and $213 of its
outstanding 6.375% senior notes due in 2021. As part of this transaction, $17 was included in Loss on Debt Extinguishment on
the Consolidated Statements of Income.
In July 2015, CNXC entered into a Credit Agreement for a $400,000 revolving credit facility. As of December 31, 2016 and
2015, CNXC had $201,000 and $185,000 of borrowings outstanding on the facility, respectively. CONSOL Energy is not a guarantor
of CNXC's revolving credit facility. See Note 25 - Related Party Transactions for more information.
127
NOTE 13—LEASES:
CONSOL Energy uses various leased facilities and equipment in its operations. Future minimum lease payments under
capital and operating leases, together with the present value of the net minimum capital lease payments, at December 31, 2016
are as follows:
Year Ended December 31,
2017
2018
2019
2020
2021
Thereafter
Total minimum lease payments
Less amount representing interest (2.00% – 7.36%)
Present value of minimum lease payments
Less amount due in one year
Total Long-Term Capital Lease Obligation
Capital
Leases
Operating
Leases
$
$
103,325
64,520
37,272
27,722
26,816
80,692
340,347
$
$
$
13,237
12,442
11,977
11,007
8,959
—
57,622
8,225
49,397
10,323
39,074
Rental expense under operating leases was $108,698, $109,789, and $111,257 for the years ended December 31, 2016, 2015
and 2014, respectively.
At December 31, 2016, certain of the above capital leases for mining equipment are subleased to a third-party. The following
represents the minimum payments including interest for those capital subleases:
2017
2018
2019
2020
2021
Thereafter
Total
$
3,699
$
3,699
$
3,699
$
3,699
$
2,157
$
— $
16,953
At December 31, 2016, certain of the above operating leases for mining equipment are subleased to third-parties. The
following represents the minimum rental payments for those operating subleases:
2017
2018
2019
2020
2021
Thereafter
Total
$
40,299
$
13,819
$
6,909
$
— $
— $
— $
61,027
CONSOL Energy leases certain owned mining equipment to a third-party under operating leases. The owned equipment
included in gross property, plant and equipment was $26,005, with $15,603 accumulated depreciation at December 31, 2016.
At December 31, 2016, scheduled minimum rental payments for operating leases related to this equipment were as follows:
2017
2018
2019
2020
2021
Thereafter
Total
$
4,496
$
2,992
$
1,701
$
627
$
— $
— $
9,816
128
NOTE 14—PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:
Pension:
CONSOL Energy has non-contributory defined benefit retirement plans. Effective December 31, 2015, CONSOL Energy's
qualified defined benefit retirement plan was frozen. The benefits for these plans are based primarily on years of service and
employees' pay. CONSOL Energy's qualified pension plan allows for lump-sum distributions of benefits earned up until
December 31, 2005, at the employees' election.
On September 30, 2014, the qualified pension plan was remeasured to reflect an announced plan amendment that reduced
future accruals of pension benefits as of January 1, 2015. The plan amendment called for a hard freeze of the qualified defined
benefit pension plan on January 1, 2015 for employees who were under age 40 or had less than 10 years of service as of September
30, 2014. Employees who were age 40 or over and had at least 10 years of service continued in the defined benefit pension plan
unchanged. The modifications to the pension plan resulted in a $21,624 reduction in the pension liability.
On August 31, 2015, the qualified pension plan was remeasured to reflect an announced plan amendment that reduced accruals
of pension benefits as of January 1, 2016. The plan amendment called for a hard freeze of the qualified defined benefit pension
plan on January 1, 2016 for all remaining participants in the plan. The modifications to the pension plan resulted in a $26,352
reduction in the pension liability. The amendment resulted in a remeasurement of the qualified pension plan at August 31, 2015,
which increased the pension liability by $17,793.
In the third quarter of 2015, CONSOL Energy remeasured its pension plan as a result of the previously discussed plan
amendment. In conjunction with this remeasurement, the method used to estimate the service and interest components of net
periodic benefit cost for pension was changed. This change was also made to other postretirement benefits in the fourth quarter
during the annual remeasurement of that plan. This change, compared to the previous method, resulted in a decrease in the service
and interest components for pension cost in the third quarter. Historically, CONSOL Energy estimated these service and interest
cost components utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit
obligation at the beginning of the period. CONSOL Energy has elected to utilize a full yield curve approach in the estimation of
these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to
the relevant projected cash flows. This change was made to provide a more precise measurement of service and interest costs by
improving the correlation between projected benefit cash flows to the corresponding spot yield curve rates. This change is
immaterial to CONSOL's financial statements. CONSOL Energy has accounted for this change as a change in accounting estimate
that is inseparable from a change in accounting principle and, accordingly, accounted for it prospectively.
According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards
Codification, if the lump sum distributions made during a plan year, which for CONSOL Energy is January 1 to December 31,
exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum
payments exceeded this threshold during the years ended December 31, 2016, 2015, and 2014. Accordingly, CONSOL Energy
recognized settlement expense of $22,196, $19,053, and $29,095 for the years ended December 31, 2016, 2015 and 2014
respectively, in Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. The settlement charges
resulted in remeasurements of the pension plan during 2016, 2015 and 2014.
Other Postretirement Benefit Plans:
Certain subsidiaries of CONSOL Energy provide medical and prescription drug benefits to retired employees covered by
the Coal Industry Retiree Health Benefit Act of 1992 (the Coal Act). Represented hourly employees are eligible to participate
based upon the terms of the National Bituminous Coal Wage Agreement of 2011.
On September 30, 2014, the Salaried OPEB plan and Production and Maintenance (P&M) OPEB plans were remeasured to
reflect an announced plan amendment that reduced retiree medical and life insurance benefits as of September 30, 2014. Effective
September 30, 2014, no retiree medical, prescription drug or life benefits were to be provided to active employees. Salaried and
P&M retirees as of September 30, 2014 were to continue in the OPEB plans for a maximum period up to December 31, 2019 and
coverage thereafter was eliminated (see below for information on an additional amendment made to these plans in 2015). The
Company elected to make cash transition payments totaling approximately $46,282 to the active employees whose retiree medical,
prescription drug and life insurance benefits were eliminated by the changes to the OPEB plans. These cash payments are not
considered to be post-retirement benefits, and as such, they are not reflected in the actuarial calculations related to the OPEB plans.
The amendment to the OPEB plans resulted in a $315,439 reduction in the OPEB liability and a curtailment gain of $35,633.
129
On May 31, 2015, the Salaried OPEB and P&M OPEB plans were remeasured to reflect another plan amendment which
eliminated Salaried and P&M OPEB benefits at December 31, 2015. The amendment to the OPEB plans resulted in a $43,598
reduction in the OPEB liability. The amendment also resulted in a remeasurement of the OPEB plan at May 31, 2015, which
decreased the liability by $1,070. CONSOL Energy recognized income of $235,541 related to amortization of prior service credit,
coupled with recognition of actuarial losses in PA Mining Operations Costs - Operating and Other Costs and Other Costs -
Miscellaneous Operating Expense in the Consolidated Statements of Income for the year ended December 31, 2015 as a result of
the changes made to the Salaried and P&M OPEB plans.
The Company will incur savings from cost containment changes related to pharmacy benefits, which were implemented on
January 1, 2017, and increased member responsibility when using out-of-network providers and facilities, which will be
implemented on March 27, 2017. These plan amendments resulted in a $28,164 reduction in the OPEB liability during the year
ended December 31, 2016.
The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2016
and 2015 is as follows:
Change in benefit obligation:
Benefit obligation at beginning of period
Service cost
Interest cost
Actuarial loss (gain)
Plan amendments
Plan transfer*
Plan curtailments
Plan settlements
Participant contributions
Benefits and other payments
Benefit obligation at end of period
Change in plan assets:
Fair value of plan assets at beginning of period
Actual return (loss) on plan assets
Company contributions
Participant contributions
Benefits and other payments
Plan settlements
Fair value of plan assets at end of period
Funded status:
Current liabilities
Noncurrent liabilities
Net obligation recognized
Amounts recognized in accumulated other
comprehensive income consist of:
Net actuarial loss
Prior service credit
Net amount recognized (before tax effect)
$
$
$
$
$
$
$
$
Pension Benefits
at December 31,
Other Postretirement Benefits
at December 31,
2016
2015
2016
2015
763,407
1,927
25,491
46,962
—
—
—
(54,197)
—
(35,709)
747,881
669,039
50,575
2,726
—
(35,709)
(54,197)
632,434
$
$
$
$
870,471
8,653
32,095
(39,563)
—
—
(26,352)
(51,497)
—
(30,400)
763,407
751,176
(9,293)
9,053
—
(30,400)
(51,497)
669,039
$
$
$
$
671,755
—
24,241
77,640
(28,164)
—
—
—
—
(45,387)
700,085
$
$
— $
—
45,387
—
(45,387)
—
— $
760,959
—
27,238
(9,224)
(43,598)
(5,242)
—
—
1,649
(60,027)
671,755
—
—
58,378
1,649
(60,027)
—
—
(2,904) $
(112,543)
(115,447) $
(2,772) $
(91,596)
(94,368) $
(40,611) $
(659,474)
(700,085) $
(40,863)
(630,892)
(671,755)
299,865
(1,611)
298,254
$
$
288,695
(2,201)
286,494
$
$
426,392
(28,164)
398,228
$
$
367,920
—
367,920
*The plan transfer relates to the IBNR (incurred but not reported) costs associated with the terminated Salaried and P&M OPEB
plans. These costs are now included in Other Accrued Liabilities in the Consolidated Balance Sheets.
130
The components of net periodic benefit costs are as follows:
Pension Benefits
Other Postretirement Benefits
For the Years Ended December 31,
For the Years Ended December 31,
2016
2015
2014
2016
2015
2014
Components of net periodic benefit
cost:
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service
credits
Recognized net actuarial loss
Curtailment loss (gain)
Settlement loss (gain)
Net periodic benefit cost (credit)
$
$
$
1,927
25,491
(46,674)
$
8,653
32,095
(51,528)
17,187
35,363
(51,400)
(590)
9,694
—
22,196
12,044
$
(666)
21,519
5
19,053
29,131
$
(1,217)
23,927
(549)
29,095
52,406
$
$
— $
— $
24,241
—
—
19,168
—
—
43,409
27,238
—
(336,327)
102,875
—
(8,932)
$ (215,146) $
7,089
44,177
—
(21,163)
28,682
(35,633)
—
23,152
Amounts included in accumulated other comprehensive loss which are expected to be recognized in 2017 net periodic benefit
costs:
Prior service credit recognition
Actuarial loss recognition
Pension
Benefits
Other
Postretirement
Benefits
$
$
(590) $
$
9,403
(2,405)
23,112
CONSOL Energy utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the
Pension Plan. Cumulative gains and losses that are in excess of 10% of the greater of either the projected benefit obligation (PBO)
or the market-related value of plan assets are amortized over the expected remaining future lifetime of all plan participants for the
Pension plan.
CONSOL Energy also utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under
the OPEB Plan. Cumulative gains and losses that are in excess of 10% of the greater of either the accumulated postretirement
benefit obligation (APBO) or the market-related value of plan assets are amortized over the average future remaining lifetime of
the current inactive population for the OPEB plan.
The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan
assets:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
As of December 31,
2016
2015
$
$
$
747,881
745,793
632,434
$
$
$
763,407
761,124
669,039
131
Assumptions:
The weighted-average assumptions used to determine benefit obligations are as follows:
Discount rate
Rate of compensation increase
Pension Benefits
For the Year Ended
December 31,
Other Postretirement Benefits
For the Year Ended
December 31,
2016
2015
2016
2015
4.31%
3.90%
4.50%
3.80%
4.22%
—
4.50%
—
The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance
of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to
determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as
of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the
bonds included in the models exceed the cash flows needed to satisfy the Company plans.
The weighted-average assumptions used to determine net periodic benefit costs are as follows:
Discount rate
Expected long-term return on plan assets
Rate of compensation increase
Pension Benefits at
Other Postretirement Benefits at
December 31,
December 31,
2016
2015
2014
2016
2015
2014
4.52%
7.25%
3.80%
4.07%
7.75%
3.80%
4.87%
7.75%
4.21%
4.50%
4.03%
4.88%
—
—
—
—
—
—
The long-term rate of return is the sum of the portion of total assets in each asset class held multiplied by the expected return
for that class, adjusted for expected expenses to be paid from the assets. The expected return for each class is determined using
the plan asset allocation at the measurement date and a distribution of compound average returns over a twenty year time horizon.
The model uses asset class returns, variances and correlation assumptions to produce the expected return for each portfolio. The
return assumptions used forward-looking gross returns influenced by the current Treasury yield curve. These returns recognize
current bond yields, corporate bond spreads and equity risk premiums based on current market conditions.
The assumed health care cost trend rates are as follows:
Health care cost trend rate for next year
Rate to which the cost trend is assumed to decline (ultimate trend rate)
Year that the rate reaches ultimate trend rate
At December 31,
2016
2015
2014
6.31%
4.50%
2038
6.49%
4.50%
2038
6.03%
4.50%
2026
Assumed health care cost trend rates have a significant effect on the amounts reported for the medical plans. A one-percentage
point change in assumed health care cost trend rates would have the following effects:
Effect on total of service and interest cost components
Effect on accumulated postretirement benefit obligation
1 Percentage
1 Percentage
Point Increase
Point Decrease
$
$
3,659
84,381
$
$
(3,053)
(71,751)
132
Plan Assets:
The Company’s overall investment strategy is to meet current and future benefit payment needs through diversification
across asset classes, fund strategies and fund managers to achieve an optimal balance between risk and return and between income
and growth of assets through capital appreciation. Consistent with the objectives of the Trust and in consideration of the Trust’s
current funded status and the current level of market interest rates, the Retirement Board has approved an asset allocation strategy
that will change over time in response to future improvements in the Trust’s funded status and/or changes in market interest rates.
Such changes in asset allocation strategy are intended to allocate additional assets to the fixed income asset class should the Trust’s
funded status improve. In this framework, the current target allocation for plan assets are 26% U.S. equity securities, 16.5% non-
U.S. equity securities, 7.5% global equity securities and 50% fixed income. Both the equity and fixed income portfolios are
comprised of both active and passive investment strategies. The Trust is primarily invested in Mercer Common Collective Trusts.
Equity securities consist of investments in large and mid/small cap companies with non-U.S. equities being derived from both
developed and emerging markets. Fixed income securities consist of U.S. as well as international instruments, including emerging
markets. The core domestic fixed income portfolios invest in government, corporate, asset-backed securities and mortgage-backed
obligations. The average quality of the fixed income portfolio must be rated at least “investment grade” by nationally recognized
rating agencies. Within the fixed income asset class, investments are invested primarily across various strategies such that its
overall profile strongly correlates with the interest rate sensitivity of the Trust’s liabilities in order to reduce the volatility resulting
from the risk of changes in interest rates and the impact of such changes on the Trust’s overall financial status. Derivatives, interest
rate swaps, options and futures are permitted investments for the purpose of reducing risk and to extend the duration of the overall
fixed income portfolio; however, they may not be used for speculative purposes. All or a portion of the assets may be invested in
mutual funds or other commingled vehicles so long as the pooled investment funds have an adequate asset base relative to their
asset class; are invested in a diversified manner; and have management and/or oversight by an Investment Advisor registered with
the SEC. The Retirement Board, as appointed by the CONSOL Energy Board of Directors, reviews the investment program on
an ongoing basis including asset performance, current trends and developments in capital markets, changes in Trust liabilities and
ongoing appropriateness of the overall investment policy.
In May 2015, the FASB issued an Accounting Standards Update that removes the requirement to categorize within the fair
value hierarchy investments for which fair values are estimated using the net asset value practical expedient provided by Accounting
Standards Codification 820, Fair Value Measurement. This new guidance is effective for public entities for fiscal years beginning
after December 15, 2015. In accordance with this Update, certain investments in 2016 and 2015 that are measured at fair value
using the net asset value per share (or its equivalent) practical expedient have not been classified as Level 1, 2 or 3 in the below
fair value hierarchy but are included in the total.
The fair values of plan assets at December 31, 2016 and 2015 by asset category are as follows:
Fair Value Measurements at December 31, 2016
Fair Value Measurements at December 31, 2015
Quoted
Prices in
Active
Quoted
Prices in
Active
Markets for
Significant
Significant
Markets for
Significant
Significant
Identical
Observable
Unobservable
Identical
Observable
Unobservable
Assets
Inputs
Inputs
Assets
Inputs
Inputs
Total
(Level 1)
(Level 2)
(Level 3)
Total
(Level 1)
(Level 2)
(Level 3)
Asset Category
Cash/Accrued Income
US Equities (a)
$
639
$
639
$
— $
— $
631
$
631
$
— $
Mercer Common Collective Trusts (b)
631,784
11
11
—
—
—
—
10
— 668,398
10
—
—
—
Total
__________
$632,434
$
650
$
— $
— $669,039
$
641
$
— $
—
—
—
—
(a) This category includes investments in US common stocks and corporate debt.
(b) Certain investments that are measured at fair value using the net asset value per share (or its equivalent) practical expedient
have not been classified in the fair value hierarchy but are included in the total.
There are no investments in CONSOL Energy stock held by these plans at December 31, 2016 or 2015.
There are no assets in the other postretirement benefit plans at December 31, 2016 or 2015.
133
Cash Flows:
If necessary, CONSOL Energy intends to contribute to the pension trust using prudent funding methods. However, the
Company does not expect to contribute to the pension plan trust in 2017. Pension benefit payments are primarily funded from the
trust. CONSOL Energy expects to pay benefits of $2,904 from the non-qualified pension plan in 2017. CONSOL Energy does not
expect to contribute to the other postemployment plan in 2017 and intends to pay benefit claims as they are due.
The following benefit payments, reflecting expected future service, are expected to be paid:
2017
2018
2019
2020
2021
Year 2022-2026
Pension
Benefits
Other
Postretirement
Benefits
$
$
$
$
$
$
47,374
47,100
46,211
45,773
44,206
223,745
$
$
$
$
$
$
40,611
43,829
43,932
44,136
44,233
215,248
NOTE 15—COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION:
Under the Federal Coal Mine Health and Safety Act of 1969, as amended, CONSOL Energy is responsible for medical and
disability benefits to employees and their dependents resulting from occurrences of coal workers' pneumoconiosis disease.
CONSOL Energy is also responsible under various state statutes for pneumoconiosis benefits. CONSOL Energy primarily provides
for these claims through a self-insurance program. The calculation of the actuarial present value of the estimated pneumoconiosis
obligation is based on an annual actuarial study by independent actuaries and uses assumptions regarding disability incidence,
medical costs, indemnity levels, mortality, death benefits, dependents and interest rates which are derived from actual company
experience and outside sources. Recent legislative changes have not been favorable for CWP. Although these changes have not
had a significant impact on the liability, CONSOL has noticed an increase in claims. Actuarial gains or losses can result from
differences in incident rates and severity of claims filed as compared to original assumptions.
CONSOL Energy must also compensate individuals who sustain employment-related physical injuries or some types of
occupational diseases and, on some occasions, for costs of their rehabilitation. Workers' compensation laws will also compensate
survivors of workers who suffer employment-related deaths. Workers' compensation laws are administered by state agencies, and
each state has its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course
of employment. CONSOL Energy primarily provides for these claims through a self-insurance program. CONSOL Energy
recognizes an actuarial present value of the estimated workers' compensation obligation calculated by independent actuaries. The
calculation is based on claims filed and an estimate of claims incurred but not yet reported as well as various assumptions, including
discount rate, future healthcare trend rate, benefit duration and recurrence of injuries. Actuarial gains or losses associated with
workers' compensation have resulted from discount rate changes and differences in claims experience and incident rates as compared
to prior assumptions.
134
Change in benefit obligation:
Benefit obligation at beginning of period
State administrative fees and insurance bond
premiums
Service cost
Interest cost
Actuarial loss (gain)
Benefits paid
Curtailment gain
Settlements
Benefit obligation at end of period
Current assets
Current liabilities
Noncurrent liabilities
Net obligation recognized
Amounts recognized in accumulated other
comprehensive income consist of:
Net actuarial gain
Net amount recognized (before tax effect)
$
$
$
$
$
The components of the net periodic cost are as follows:
CWP
at December 31,
2016
2015
Workers' Compensation
at December 31,
2016
2015
$
122,503
$
126,098
$
83,165
$
89,741
—
4,327
4,283
439
(11,409)
(1,307)
—
118,836
$
— $
(10,763)
(108,073)
(118,836) $
—
6,491
5,116
(5,089)
(10,113)
—
—
122,503
$
— $
(9,471)
(113,032)
(122,503) $
3,265
7,618
2,550
123
(17,028)
—
—
79,693
$
$
1,458
(13,874)
(67,277)
(79,693) $
3,581
9,389
3,195
(4,089)
(18,999)
—
347
83,165
1,450
(14,803)
(69,812)
(83,165)
(62,714) $
(62,714) $
(68,101) $
(68,101) $
(12,914) $
(12,914) $
(13,440)
(13,440)
CWP
For the Years Ended
December 31,
Workers’ Compensation
For the Years Ended
December 31,
2016
2015
2014
2016
2015
2014
Service cost
Interest cost
Recognized net actuarial gain
State administrative fees and insurance
bond premiums
Curtailment gain
Settlement gain
Net periodic cost
$
$
4,327
4,283
(4,948)
—
(1,307)
—
2,355
$
$
$
6,491
5,116
(5,576)
$
5,674
5,537
(6,196)
$
7,618
2,550
(403)
$
9,389
3,195
(31)
9,781
3,577
(382)
—
—
—
6,031
$
—
—
—
5,015
$
3,265
—
—
13,030
$
3,581
—
—
16,134
$
3,352
—
—
16,328
(Income) expense attributable to discontinued operations included in the CWP net periodic cost was $(1,290), $297 and $87
for the years ended December 31, 2016, 2015 and 2014, respectively.
On March 31, 2016, CONSOL Energy completed the sale of its membership interests in BMC (see Note 2 - Discontinued
Operations). As a result of the sale, certain obligations of the CWP plan were transferred to the buyer. This transfer triggered a
curtailment gain of $1,307. The curtailment resulted in a plan remeasurement increasing plan liabilities by $7,713 at March 31,
2016.
135
The following are amounts included in accumulated other comprehensive income that are expected to be recognized in 2017
net periodic benefit costs:
Actuarial gain recognition
CWP
Benefits
Workers'
Compensation
Benefits
$
(7,631) $
(610)
CONSOL Energy utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the
Workers’ Compensation and CWP plans. Cumulative gains and losses that are in excess of 10% of the greater of either the estimated
liability or the market-related value of plan assets are amortized over the expected average remaining future service of the current
active membership of the Workers’ Compensation and CWP plans.
Assumptions:
The weighted-average discount rates used to determine benefit obligations and net periodic cost (benefit) are as follows:
Benefit obligations
Net periodic cost
CWP
For the Years Ended
December 31,
Workers' Compensation
For the Years Ended
December 31,
2016
4.40%
4.60%
2015
4.60%
4.21%
2014
4.21%
4.75%
2016
4.05%
4.26%
2015
4.26%
3.84%
2014
3.84%
4.57%
Discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of
an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to
determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as
of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the
bonds included in the models exceed the cash flows needed to satisfy the Company's plans.
Cash Flows:
CONSOL Energy does not intend to make contributions to the CWP or Workers' Compensation plans in 2017, but it intends
to pay benefit claims as they become due.
The following benefit payments, which reflect expected future claims as appropriate, are expected to be paid:
Workers' Compensation
Actuarial
Benefits
Other
Benefits
Total
Benefits
15,897
15,193
15,061
15,044
15,056
76,577
$
$
$
$
$
$
12,416
11,625
11,404
11,295
11,214
55,876
$
$
$
$
$
$
3,481
3,568
3,657
3,749
3,842
20,701
2017
2018
2019
2020
2021
Year 2022-2026
CWP
Benefits
$
$
$
$
$
$
10,763
8,417
7,606
7,137
6,963
35,714
$
$
$
$
$
$
136
NOTE 16—OTHER EMPLOYEE BENEFIT PLANS:
UMWA Benefit Trusts:
The Coal Act created two multi-employer benefit plans: (1) the United Mine Workers of America Combined Benefit Fund
(the Combined Fund) into which the former UMWA Benefit Trusts were merged, and (2) the United Mine Workers of America
1992 Benefit Plan (1992 Benefit Plan). CONSOL Energy accounts for required contributions to these multi-employer trusts as
expense when incurred.
The Combined Fund provides medical and death benefits for all beneficiaries of the former UMWA Benefit Trusts who were
actually receiving benefits as of July 20, 1992. The 1992 Benefit Plan provides medical and death benefits to orphan UMWA-
represented members eligible for retirement on February 1, 1993, and for those who retired between July 20, 1992 and
September 30, 1994. The Coal Act provides for the assignment of beneficiaries to former employers and the allocation of unassigned
beneficiaries (referred to as orphans) to companies using a formula set forth in the Coal Act. The Coal Act requires that responsibility
for funding the benefits to be paid to beneficiaries be assigned to their former signatory employers or related companies. This cost
is recognized when contributions are assessed. CONSOL Energy's total contributions under the Coal Act were $8,455, $9,239 and
$10,121 for the years ended December 31, 2016, 2015 and 2014, respectively. Based on available information at December 31,
2016, CONSOL Energy's obligation for the Combined Fund and 1992 Benefit Plans is estimated to be approximately $93,795.
Pursuant to the provisions of the Tax Relief and Healthcare Act of 2006 (the 2006 Act) and the 1992 Benefit Plan, CONSOL
Energy is required to provide security in an amount based on the annual cost of providing health care benefits for all individuals
receiving benefits from the 1992 Benefit Plan who are attributable to CONSOL Energy, plus all individuals receiving benefits
from an individual employer plan maintained by CONSOL Energy who are entitled to receive such benefits. In accordance with
the terms of the 2006 Act and the 1992 Benefit Plan, CONSOL Energy must secure its obligations by posting letters of credit,
which were $19,170, $21,473 and $21,394 at December 31, 2016, 2015 and 2014, respectively. The 2016, 2015 and 2014 security
amounts were based on the annual cost of providing health care benefits and included a reduction in the number of eligible
employees.
Investment Plan:
CONSOL Energy has an investment plan available to most non-represented employees. Throughout the year ended December
31, 2016, the Company's matching contribution was 6% of eligible compensation contributed by eligible employees. In conjunction
with the qualified pension plan changes in 2015, the Company contributed an additional 3% of eligible compensation into the 401
(k) plan accounts for employees hired or rehired on or after October 1, 2014 or who were under age 40 or had less than 10 years
of service with the Company as of September 30, 2014. This additional contribution was eliminated on January 1, 2016. The
Company may also make discretionary contributions to the Plan ranging from 1% to 6% (1% to 4% prior to January 1, 2016) of
eligible compensation for eligible employees (as defined by the Plan). Discretionary contributions made by the Company were
$12,260 for the year ended December 31, 2016. There were no such discretionary contributions made by the Company for the
years ended December 31, 2015 and 2014. Total payments and costs were $20,784, $20,058 and $18,341 for the years ended
December 31, 2016, 2015 and 2014, respectively.
Long-Term Disability:
CONSOL Energy has a Long-Term Disability Plan available to all eligible full-time salaried employees. The benefits for
this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled.
Benefit cost
Discount rate assumption used to determine net periodic benefit costs
For the Years Ended
December 31,
2015
$ 2,619
2014
$ 2,213
2016
$ 2,128
3.71%
3.18%
3.53%
Liabilities incurred under the Long-Term Disability Plan are included in Other Accrued Liabilities and Deferred Credits and
Other Liabilities–Other in the Consolidated Balance Sheets and amounted to a combined total of $19,144 and $19,789 at
December 31, 2016 and 2015, respectively.
137
NOTE 17—STOCK-BASED COMPENSATION:
CONSOL Energy adopted the CONSOL Energy Inc. Equity Incentive Plan (the Equity Incentive Plan) on April 7, 1999.
The Equity Incentive Plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments
to the Equity Incentive Plan have been adopted and approved by the Board of Directors and the Company's Shareholders since
the commencement of the plan. Most recently, in May 2016, the Board of Directors and the Company's Shareholders adopted and
approved a 10,550,000 increase to the total number of shares available for issuance, which brought the total number of shares of
common stock that can be covered by grants to 42,350,000. At December 31, 2016, 8,733,169 shares of common stock remain
available for all awards. The Equity Incentive Plan provides that the aggregate number of shares available for issuance will be
reduced by one share for each share issued in settlement of stock options and by 1.62 for each share issued in settlement of
Performance Share Units (PSUs) or Restricted Stock Units (RSUs). No award of stock options may be exercised under the Equity
Incentive Plan after the tenth anniversary of the effective date of the award.
For only those shares expected to vest, CONSOL Energy recognizes stock-based compensation costs on a straight-line basis
over the requisite service period of the award, which is generally the vesting term. Awards granted in 2014 vest immediately if
granted to retiree-eligible employees who are aged 62 and older. Awards granted in 2014 vest at the end of one year when granted
to employees aged 55 to 62 and who have also completed ten years of service. Awards granted in 2014 vest over a three-year term
at 33% per year for all other employees. Awards granted in 2015 vest over a three-year term at 33% per year. Options and RSUs
granted in 2016 vest over a three-year term at 33% per year. Performance share units granted in 2016 vest over a five-year term
at 20% per year subject to performance conditions. If an employee leaves the Company, all unvested shares are forfeited. The
vesting of all awards will accelerate in the event of death and disability and may accelerate upon a change in control of CONSOL
Energy. See each specific award section for special vesting terms related to non-employee directors and other specific awards.
The total stock-based compensation expense recognized during the years ended December 31, 2016, 2015 and 2014 was $31,483,
$24,513 and $41,877, respectively. The related deferred tax benefit totaled $11,255, $9,229 and $15,243, for the years ended
December 31, 2016, 2015 and 2014, respectively.
As of December 31, 2016, CONSOL Energy has $40,234 of unrecognized compensation cost related to all nonvested stock-
based compensation awards, which is expected to be recognized over a weighted-average period of 2.73 years. When stock options
are exercised and restricted and performance stock unit awards become vested, the issuances are made from CONSOL Energy's
common stock shares.
Stock Options:
CONSOL Energy examined its historical pattern of option exercises in an effort to determine if there were any discernable
activity patterns based on certain employee populations. From this analysis, CONSOL Energy identified two distinct employee
populations and used the Black-Scholes option pricing model to value the options for each of the employee populations. The
expected term computation presented in the table below is based upon a weighted average of the historical exercise patterns and
post-vesting termination behavior of the two populations. The risk-free interest rate was determined for each vesting tranche of
an award based upon the calculated yield on U.S. Treasury obligations for the expected term of the award. The expected forfeiture
rate is based upon historical forfeiture activity. A combination of historical and implied volatility is used to determine expected
volatility and future stock price trends. The total fair value of options granted during the year ended December 31, 2016 was
$19,305, based on the following assumptions and weighted average fair values:
Weighted average fair value of grants
$
Risk-free interest rate
Expected dividend yield
Expected forfeiture rate
Expected volatility
Expected term in years
CONSOL Energy did not grant stock option awards during the years ended December 31, 2015 or 2014.
December 31,
2016
5.73
1.13%
0.27%
2.00%
61.09%
4.90
138
A summary of the status of stock options granted is presented below:
Balance at December 31, 2015
Granted
Exercised
Forfeited
Balance at December 31, 2016
Vested
Exercisable at December 31, 2016
Shares
3,621,002
3,369,197
—
(781,386)
6,208,813
2,990,263
2,990,263
Term (in
years)
Weighted
Average
Weighted Remaining Aggregate
Intrinsic
Average Contractual
Value (in
Exercise
thousands)
Price
$43.15
$4.22
—
$36.32
$22.88
$43.12
$43.12
6.02
2.57
2.57
—
—
—
$
$
$
At December 31, 2016, there are 5,888,075 employee stock options outstanding under the Equity Incentive Plan. Non-
employee director stock options vest one year after the grant date. There are 320,738 fully vested stock options outstanding under
these grants.
The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CONSOL
Energy's closing stock price on the last trading day of the year ended December 31, 2016 and the option's exercise price, multiplied
by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their
options on December 31, 2016. This amount varies based on the fair market value of CONSOL Energy's stock. No options were
exercised during the year ended December 31, 2016. The total intrinsic value of options exercised for the years ended December 31,
2015 and 2014 was $2,744 and $14,545, respectively.
Cash received from option exercises for the years ended December 31, 2015 and 2014 was $8,281 and $15,011, respectively.
The tax impact from option exercises totaled $208 and $2,629 for the years ended December 31, 2015 and 2014, respectively.
This excess tax benefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.
Restricted Stock Units:
Under the Equity Incentive Plan, CONSOL Energy grants certain employees and non-employee directors restricted stock
unit awards, which entitle the holder to shares of common stock as the award vests. Non-employee director restricted stock units
vest at the end of one year. In 2014, restricted stock units were granted that will vest over a five year period unless certain market
conditions are met, in which the award will accelerate. Compensation expense is recognized over the vesting period of the units,
described above. The total fair value of restricted stock units granted during the years ended December 31, 2016, 2015 and 2014
was $493, $26,550 and $31,360, respectively. The total fair value of restricted stock units vested during the years ended
December 31, 2016, 2015 and 2014 was $19,095, $20,793 and $15,686, respectively. The following table represents the nonvested
restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant:
Nonvested at December 31, 2015
Granted
Vested
Forfeited
Nonvested at December 31, 2016
Performance Share Units:
Number of Weighted Average
Shares
1,303,573
27,379
(579,246)
(88,703)
663,003
Grant Date Fair Value
$32.60
$17.99
$32.97
$30.42
$31.97
Under the Equity Incentive Plan, CONSOL Energy grants certain employees performance share unit awards, which entitle
the holder to shares of common stock subject to the achievement of certain market and performance goals. Compensation expense
is recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation
Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. For the PSUs
issued in 2014 and 2015, achievement of the market goals is not probable, but achievement of the performance goals is probable.
139
Achievement of the market goals is probable for the first tranche of the PSUs issued in 2016. The total fair value of performance
share units granted during the years ended December 31, 2016, 2015 and 2014 was $24,283, $18,771 and $11,853, respectively.
No performance share units vested during the year ended December 31, 2016. The total fair value of performance share units
vested during the years ended December 31, 2015 and 2014 was $20,083 and $18,759, respectively. The following table represents
the nonvested performance share units and their corresponding fair value (based upon the closing share price) on the date of grant:
Nonvested at December 31, 2015
Granted
Vested
Forfeited
Nonvested at December 31, 2016
Performance Options:
Number of Weighted Average
Shares
491,493
950,404
—
(17,346)
1,424,551
Grant Date Fair Value
$27.83
$25.55
—
$19.62
$26.41
Under the Equity Incentive Plan in 2010, CONSOL Energy granted certain employees performance options, which entitled
the holder to shares of common stock subject to the achievement of certain performance goals. Compensation expense was
recognized over the vesting period of the options, described above. The Black-Scholes option valuation model was used to value
each tranche separately. No performance options were granted in 2016, 2015, or 2014. No performance options vested in 2016 or
2015. The total fair value of performance options vested during the year ended December 31, 2014 was $4,949. A summary of
the status of performance options granted is presented below:
Balance at December 31, 2015
Granted
Exercised
Forfeited
Balance at December 31, 2016
Vested
Exercisable at December 31, 2016
CONSOL Stock Units:
Shares
802,804
—
—
—
802,804
802,804
802,804
Term (in
years)
Weighted
Average
Weighted Remaining Aggregate
Intrinsic
Average Contractual
Value (in
Exercise
Price
thousands)
$45.05
—
—
—
$45.05
$45.05
$45.05
3.42
3.42
3.42
—
—
—
$
$
$
Under the Equity Incentive Plan in 2013, CONSOL Energy granted certain employees CONSOL Stock Unit Awards, which
entitled the holder to shares of common stock subject to the achievement of certain market and performance goals. Compensation
expense was recognized over the performance measurement period of the units in accordance with the provisions of the Stock
Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions.
CONSOL Energy used the Monte Carlo methodology to estimate the fair value of the CONSOL Stock Units. The achievement
of the market and performance goals was not attained and therefore, all shares were forfeited in 2016. No CONSOL Stock Units
were granted in 2016. The total fair value of CONSOL Stock Units granted during the years ended December 31, 2015 and 2014
was $110 and $189 respectively. The following table represents the nonvested CONSOL Stock Unit awards and their corresponding
fair value at the grant date:
Nonvested at December 31, 2015
Granted
Forfeited
Nonvested at December 31, 2016
140
Number of Weighted Average
Shares
803,998
—
(803,998)
—
Grant Date Fair Value
$33.68
—
$33.68
—
NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION:
The following are non-cash transactions that impact the investing and financing activities of CONSOL Energy. For non-
cash transactions that relate to acquisitions and dispositions, see Note 2 - Discontinued Operations and Note - 3 Acquisitions and
Dispositions.
CONSOL Energy obtains capital lease arrangements for company-used vehicles. For the years ended December 31, 2016,
2015 and 2014, CONSOL Energy entered into non-cash capital lease arrangements of $55, $4,973 and $1,540, respectively.
As of December 31, 2016, 2015 and 2014, CONSOL Energy purchased goods and services related to capital projects in the
amount of $6,706, $24,347 and $68,800, respectively, which are included in accounts payable.
The following table shows cash paid (received) during the year for:
Interest (net of amounts capitalized)
Income taxes
$
$
For the Years Ended December 31,
2015
$
207,094
(59,584) $
2016
$
186,924
(18,032) $
2014
233,631
(81,962)
NOTE 19—CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS:
CONSOL Energy markets natural gas primarily to gas wholesalers and thermal coal principally to electric utilities in the
United States.
Concentration of credit risk is summarized below:
Gas wholesalers
Thermal coal utilities
Coal brokers and distributors
Other
Total Accounts Receivable Trade
December 31,
2016
2015
124,509
62,525
28,955
4,233
220,222
$
$
72,664
58,281
14,435
6,003
151,383
$
$
No sales to any E&P or coal customer exceeded 10% of the Company's revenues during the year ended December 31, 2016.
During the year ended December 31, 2015, coal sales to Duke Energy were $242,020, which comprised over 10% of the
Company's revenues.
During the year ended December 31, 2014, E&P sales to NJR Energy Services Company were $295,779, which comprised
over 10% of the Company's revenues.
NOTE 20—FAIR VALUE OF FINANCIAL INSTRUMENTS:
CONSOL Energy determines the fair value of assets and liabilities based on the exchange price that would be received for
an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an
orderly transaction between market participants. The fair values are based on assumptions that market participants would use when
pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to
valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable.
Observable inputs reflect market data obtained from independent sources (including NYMEX forward curves, LIBOR-based
discount rates and basis forward curves), while unobservable inputs reflect the Company's own assumptions of what market
participants would use.
The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below:
Level One - Quoted prices for identical instruments in active markets.
Level Two - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach
models that use significant observable inputs, including NYMEX forward curves, LIBOR-based discount rates and basis forward
curves.
141
Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity. The
significant unobservable inputs used in the fair value measurement of the Company's third party guarantees are the credit risk of
the third party and the third party surety bond markets. A significant increase or decrease in these values, in isolation, would have
a directionally similar effect resulting in higher or lower fair value measurement of the Company's Level 3 guarantees.
In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy,
the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value
hierarchy.
The financial instruments measured at fair value on a recurring basis are summarized below:
Description
Gas Derivatives
Murray Energy Guarantees
$
$
Level 1
Fair Value Measurements at
December 31, 2016
Level 2
— $ (188,156) $
— $
— $
Level 3
— $
$
(1,362)
Fair Value Measurements at
December 31, 2015
Level 2
Level 1
Level 3
— $ 266,558
— $
$
— $
—
(1,228)
The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:
Cash and cash equivalents: The carrying amount reported in the balance sheets for cash and cash equivalents approximates
its fair value due to the short-term maturity of these instruments.
Short-term notes payable: The carrying amount reported in the Consolidated Balance Sheets for short-term notes payable
approximates its fair value due to the short-term maturity of these instruments.
Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using
discounted cash flow analyses. The discounted cash flow analyses are based on current market rates for instruments with similar
cash flows.
The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
December 31, 2016
December 31, 2015
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
Cash and Cash Equivalents
Short-Term Notes Payable
Long-Term Debt
60,475
$
$
$ 2,752,371
$
— $
60,475
$
— $
72,574
952,000
$ 2,738,735
72,574
$
$
952,000
$ 1,808,936
$ 2,717,582
Cash and cash equivalents represent highly-liquid instruments and constitute Level 1 fair value measurements. Certain of the Company’s
debt is actively traded on a public market and, as a result, constitute Level 1 fair value measurements. The portion of the Company’s
debt obligations that are not actively traded are valued through reference to the applicable underlying benchmark rate and, as a result,
constitute Level 2 fair value measurements.
NOTE 21—DERIVATIVE INSTRUMENTS:
CONSOL Energy enters into financial derivative instruments to manage its exposure to commodity price volatility.
CONSOL Energy de-designated all of its cash flow hedges on December 31, 2014 and accounts for all existing and future gas
and NGL commodity hedges on a mark-to-market basis with changes in fair value recorded in current period earnings. In connection
with this de-designation, CONSOL Energy froze the balances recorded in Accumulated Other Comprehensive Income at December
31, 2014 and reclassified balances to earnings as the underlying physical transactions occurred. As of December 31, 2016, all
gains deferred in OCI have been recognized in earnings.
CONSOL Energy is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of
counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative
counterparties.
None of the Company's counterparty master agreements currently require CONSOL Energy to post collateral for any of
its positions. However, as stated in the counterparty master agreements, if CONSOL Energy's obligations with one of its
counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CONSOL
Energy would have to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's
142
derivative instruments are subject to master netting arrangements with our counterparties. CONSOL Energy recognizes all financial
derivative instruments as either assets or liabilities at fair value on the Consolidated Balance Sheets on a gross basis.
Each of CONSOL Energy's counterparty master agreements allows, in the event of default, the ability to elect early
termination of outstanding contracts. If early termination is elected, CONSOL Energy and the applicable counterparty would net
settle all open hedge positions.
The total notional amounts of production of CONSOL Energy's derivative instruments at December 31, 2016 and
December 31, 2015 were as follows:
Natural Gas Commodity Swaps (Bcf)
Natural Gas Basis Swaps (Bcf)
Propane Commodity Swaps (Mbbls)
December 31,
2016
2015
744.7
482.0
126.0
456.1
124.4
—
Forecasted to
Settle Through
2021
2020
2017
The gross fair value of CONSOL Energy's derivative instruments at December 31, 2016 and December 31, 2015 were
as follows:
Asset Derivative Instruments
Liability Derivative Instruments
December 31,
2016
2015
Commodity Swaps:
Prepaid Expense
Other Assets
Total Asset
Basis Only Swaps:
Prepaid Expense
Other Assets
Total Asset
$
$
$
$
16
29,596
29,612
56,916
35,603
92,519
$
$
$
$
234,409 Other Accrued Liabilities
44,539 Other Liabilities
278,948 Total Liability
5,429 Other Accrued Liabilities
1,093 Other Liabilities
6,522 Total Liability
December 31,
2016
2015
$
$
$
$
209,980
67,139
277,119
21,593
11,575
33,168
$
$
$
$
—
5,137
5,137
12,206
1,569
13,775
143
The effect of derivative instruments on CONSOL Energy's Consolidated Statements of Income was as follows:
Year Ended December 31,
2015
2014
2016
Cash Received (Paid) in Settlement of Commodity Derivative Instruments:
Commodity Swaps:
Natural Gas
Propane
Natural Gas Basis Swaps
Total Cash Received in Settlement of Commodity Derivative Instruments
$
$
$
225,797
(650)
20,065
245,212
193,976
—
2,372
196,348
19,025
—
—
19,025
Unrealized (Loss) Gain on Commodity Derivative Instruments:
Commodity Swaps:
Natural Gas
Propane
Natural Gas Basis Swaps
Reclassified from Accumulated OCI
Gain Recognized for Ineffectiveness*
Total Unrealized (Loss) Gain on Commodity Derivative Instruments
(Loss) Gain on Commodity Derivative Instruments:
Commodity Swaps:
Natural Gas
Propane
Natural Gas Basis Swaps
Reclassified from Accumulated OCI
Gain Recognized for Ineffectiveness*
Total (Loss) Gain on Commodity Derivative Instruments
* No amounts were excluded from effectiveness testing of cash flow hedges.
(520,170)
(1,148)
66,604
68,481
—
(386,233)
81,142
—
(7,653)
123,105
—
196,594
—
—
—
—
4,168
4,168
$
$
(294,373) $
(1,798)
86,669
68,481
—
(141,021) $
275,118
—
(5,281)
123,105
—
392,942
$
$
19,025
—
—
—
4,168
23,193
Changes in Accumulated OCI, net of tax, attributable to cash flow hedges that were de-designated December 31, 2014
were as follows:
Year Ended December 31,
2015
2014
2016
Beginning Balance – Accumulated OCI
Gain Recognized in Accumulated OCI
Gain Reclassified from Accumulated OCI (Net of tax: $25,011, $45,054,
$10,465)
Ending Balance – Accumulated OCI
$
$
$
43,470
—
121,521
—
(43,470)
— $
(78,051)
43,470
$
$
42,493
97,316
(18,288)
121,521
NOTE 22—COMMITMENTS AND CONTINGENT LIABILITIES:
CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal
injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental
remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. CONSOL
Energy accrues the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's
current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position,
results of operations or cash flows of CONSOL Energy. It is possible that the aggregate loss in the future with respect to these
lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CONSOL Energy;
however, such amounts cannot be reasonably estimated. The amount claimed against CONSOL Energy is disclosed below when
an amount is expressly stated in the lawsuit or claim, which is not often the case. The maximum aggregate amount claimed in
those lawsuits and claims, regardless of probability, where a claim is expressly stated or can be estimated, exceeds the aggregate
amounts accrued for all lawsuits and claims by approximately $937,421.
The following lawsuits and claims include those for which a loss is probable and an accrual has been recognized.
144
Hale Litigation: This class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia. The
putative class consists of force-pooled unleased gas owners whose ownership of the coalbed methane (CBM) gas was declared to
be in conflict with rights of others. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on
allegations CNX Gas Company failed to either pay royalties due to conflicting claimants or deemed lessors or paid them less than
required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions.
On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to
the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the
Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April
23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, and on June 23, 2015, CNX Gas Company filed its Opposition
to same. The Court held a hearing on the Motion on September 18, 2015 and has not yet ruled. CONSOL Energy continues to
believe this action cannot properly proceed as a class action in any form, believes the case has meritorious defenses, and intends
to defend it vigorously. The Company has established an accrual to cover its estimated liability for this case. This accrual is
immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated
Balance Sheets.
Addison Litigation: This class action lawsuit was filed on April 28, 2010 in the U.S. District Court in Abingdon, Virginia. The
putative class consists of gas lessors whose gas ownership is in conflict. The lawsuit seeks a judicial declaration of ownership of
the CBM and damages based on the allegations that CNX Gas Company failed to either pay royalties due to these conflicting
claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking
alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class,
and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit
agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further
proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, and on
June 23, 2015, CNX Gas Company filed its Opposition to same. The Court held a hearing on the Motion on September 18, 2015
and has not yet ruled. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form,
believes the case has meritorious defenses, and intends to defend it vigorously. The Company has established an accrual to cover
its estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included
in Other Accrued Liabilities on the Consolidated Balance Sheets.
The following royalty, land rights and other lawsuits and claims include those for which a loss is reasonably possible, but
not probable, and accordingly, an accrual may not have been recognized. These claims are influenced by many factors which
prevent the estimation of a range of potential loss. These factors include, but are not limited to, generalized allegations of unspecified
damages (such as improper deductions), discovery having not commenced or not having been completed, unavailability of expert
reports on damages and non-monetary issues being tried. For example, in instances where a gas lease termination is sought, damages
would depend on speculation as to if and when the gas production would otherwise have occurred, how many wells would have
been drilled on the lease premises, what their production would be, what the cost of production would be, and what the price of
gas would be during the production period. An estimate is calculated, if applicable, when sufficient information becomes available.
Fitzwater Litigation: Two nonunion retired coal miners have sued CONSOL Energy Inc., Fola Coal Company and
Consolidation Coal Company in West Virginia Federal Court alleging ERISA violations in the termination of retiree health care
benefits. The Plaintiffs contend they relied to their detriment on oral statements and promises of "lifetime health benefits" allegedly
made by various members of management during Plaintiffs' employment and that they were allegedly denied access to Summary
Plan Documents that clearly reserved to the Company the right to modify or terminate the CONSOL Energy Inc. Retiree Health
and Welfare Plan. Plaintiffs request that retiree health benefits be reinstated and seek to represent a class of all nonunion retirees
of CONSOL Energy and its subsidiaries. The Company believes it has meritorious defense and intends to vigorously defend this
suit.
Virginia Mine Void Litigation: The Company is currently defending three lawsuits naming Consolidation Coal Company
(CCC), Island Creek Coal Company (ICCC), CNX Gas Company, and/or CONSOL Energy. The lawsuits were filed in the U.S.
District Court for the Western District of Virginia. On October 26, 2015, the trial court granted summary judgment in favor of the
defendants in two of the actions upon its finding that plaintiffs' claims are barred by the applicable statutes of limitation. Plaintiffs
have appealed both cases to the U.S. Court of Appeals for the Fourth Circuit. Oral argument was held on December 8, 2016. The
third case remains pending in the trial court. On January 26, 2016, six mine void lawsuits that have twice before been filed and
voluntarily dismissed, were refiled for a third time in state court but have not been served. The Complaints seek damages and
injunctive relief in connection with the transfer of water from mining activities at Buchanan Mine into void spaces in inactive
ICCC mines adjacent to the Buchanan operations, voids ostensibly underlying plaintiffs’ properties. While some of the plaintiffs
have an ownership interest in the coal, others have some interest in one or more of the fee, surface, oil/gas or other mineral estates.
The suits allege the water storage precludes access to and has damaged coal, impeded coalbed methane gas production and was
145
made without compensation to the property owners. Plaintiffs seek recovery in tort, contract and trespass assumpsit (quasi-contract).
The suits each seek damages between $50,000 and in excess of $100,000 plus punitive damages. The Company intends to vigorously
defend these suits.
At December 31, 2016, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations
and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the
maximum potential of total future payments that the Company could be required to make under these instruments. These amounts
have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under
reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these
financial guarantees and letters of credit are recorded as liabilities in the financial statements. CONSOL Energy management
believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse
effect on financial condition.
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:
Employee-Related
Environmental
Other
Total Letters of Credit
Surety Bonds:
Employee-Related
Environmental
Other
Total Surety Bonds
Guarantees:
Other
Total Guarantees
$
$
82,273
998
242,405
325,676
112,810
514,851
22,417
650,078
74,203
74,203
$
67,871
600
228,313
296,784
111,510
483,604
21,591
616,705
41,285
41,285
$
14,402
398
14,092
28,892
1,300
31,247
824
33,371
17,767
17,767
— $
—
—
—
—
—
2
2
13,401
13,401
Total Commitments
$ 1,049,957
$
954,774
$
80,030
$
13,403
$
—
—
—
—
—
—
—
—
1,750
1,750
1,750
Included in the above table are commitments and guarantees entered into in conjunction with the sale of Consolidation Coal
Company and certain of its subsidiaries, which contain all five of its longwall coal mines in West Virginia, and its river operations
to a subsidiary of Murray Energy Corporation (Murray Energy). As part of the sales agreement, CONSOL Energy has guaranteed
certain equipment lease obligations and coal sales agreements that were assumed by Murray Energy. In the event that Murray
Energy would default on the obligations defined in the agreements, CONSOL Energy would be required to perform under the
guarantees. If CONSOL Energy would be required to perform, the stock purchase agreement provides various recourse actions.
At December 31, 2016 and December 31, 2015, the fair value of these guarantees was $1,362 and $1,228, respectively, and are
included in Other Accrued Liabilities on the Consolidated Balance Sheets. The fair value of certain of the guarantees was determined
using CONSOL Energy’s risk-adjusted interest rate. Significant increases or decreases in the risk-adjusted interest rates may result
in a significantly higher or lower fair value measurement. Coal sales agreement guarantees were valued based on an evaluation
of coal market pricing compared to contracted sales price and includes an adjustment for nonperformance risk. No other amounts
related to financial guarantees and letters of credit are recorded as liabilities in the financial statements. Significant judgment is
required in determining the fair value of these guarantees. The guarantees of the leases and sales agreements are classified within
Level 3 of the fair value hierarchy.
As part of the sale of Buchanan Mine (See Note 2 - Discontinued Operations), CONSOL Energy has guaranteed certain
equipment lease obligations that were assumed by Coronado. In the event that Coronado would default on the obligations defined
in the agreements, CONSOL Energy would be required to perform under the guarantees.
CONSOL Energy regularly evaluates the likelihood of default for all guarantees based on an expected loss analysis and
records the fair value, if any, of its guarantees as an obligation in the consolidated financial statements.
CONSOL Energy and CNX Gas Company enter into long-term unconditional purchase obligations to procure major
equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase
146
obligations are not recorded on the Consolidated Balance Sheets. As of December 31, 2016, the purchase obligations for each of
the next five years and beyond were as follows:
Obligations Due
Less than 1 year
1 - 3 years
3 - 5 years
More than 5 years
Total Purchase Obligations
NOTE 23—SEGMENT INFORMATION:
Amount
209,797
285,224
243,534
622,509
1,361,064
$
$
CONSOL Energy consists of two principal business divisions: Exploration and Production (E&P) and Pennsylvania (PA)
Mining Operations. The principal activity of the E&P division, which includes four reportable segments, is to produce pipeline
quality natural gas for sale primarily to gas wholesalers. The E&P division's reportable segments are Marcellus Shale, Utica Shale,
Coalbed Methane, and Other Gas. The Other Gas segment is primarily related to shallow oil and gas production and the Chattanooga
Shale in Tennessee, neither of which are significant to the Company. It also includes the Company's purchased gas activities,
unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, other corporate
expenses, selling, general and administrative activities, as well as various other activities assigned to the E&P division but not
allocated to each individual segment. The principal activities of the PA Mining Operations division are mining, preparation and
marketing of thermal coal, sold primarily to power generators. It also includes selling, general and administrative activities, as
well as various other activities assigned to the PA Mining Operations division.
CONSOL Energy’s Other division includes expenses from various corporate and diversified business activities that are not
allocated to the E&P or PA Mining Operations divisions. The diversified business activities include coal terminal operations,
closed and idle mine activities, water operations, selling, general and administrative activities, as well as various other non-operated
activities, none of which are individually significant to the Company. In previous periods, this division included activity from the
sales of industrial supplies (this subsidiary was sold in December 2014).
Prior to the sale of the Buchanan Mine on March 31, 2016 and the Fola and Miller Creek Complexes on August 1, 2016
(see Note 2 - Discontinued Operations), CONSOL Energy had a Coal division. The Coal division had three reportable segments;
PA Operations, Virginia (VA) Operations and Other Coal. The VA Operations segment included the Buchanan Mine and the Other
Coal segment was primarily comprised of the assets and operations of the Fola and Miller Creek Complexes, as well as coal
terminal operations, closed and idle mine activities, selling, general and administrative activities and various other non-operated
activities. PA Operations now constitutes its own division and reportable segment and the remaining activity in the Other Coal
segment became part of CONSOL Energy's diversified business activities in the Other division. Prior periods have been reclassified
to align with current period presentation.
In the preparation of the following information, intersegment sales have been recorded at amounts approximating market.
Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at
the division level for E&P and are not allocated between each individual E&P segment. These assets are not allocated to each
individual segment due to the diverse asset base controlled by CONSOL Energy, whereby each individual asset may service more
than one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment
by segment basis.
147
Industry segment results for the year ended December 31, 2016 are:
Sales—Outside
$ 414,484
$ 163,112
$ 174,323
$
41,329
$
793,248
$ 1,065,582
$
— $
— $
1,858,830
Marcellus
Shale
Utica
Shale
Coalbed
Methane
Other
Gas
Total
E&P
PA Mining
Operations
Other
Adjustments
and
Eliminations
Consolidated
Gain (Loss) on Commodity Derivative Instruments
147,282
29,285
52,396
(369,984)
(141,021)
Other Outside Sales
Sales—Purchased Gas
Freight—Outside
Intersegment Transfers
Total Sales and Freight
Earnings (Loss) From Continuing Operations
Before Income Tax
Segment Assets
Depreciation, Depletion and Amortization
Capital Expenditures
—
—
—
—
—
—
—
—
—
—
—
424
—
—
43,256
43,256
—
—
—
424
—
—
—
46,468
—
—
32,038
—
—
—
$ 561,766
$ 192,397
$ 227,143
$ (285,399)
$
72,141
$
28,390
$
37,999
$ (517,370)
$
$
695,907
$ 1,112,050
$
32,038
(378,840)
$
130,708
$ (277,399)
$ 6,235,568
$ 1,982,206
$ 966,124
$
$
417,853
165,101
$
$
168,195
50,809
$
$
12,455
10,910
$
$
$
$
$
—
—
—
—
(424)
(424)
(424)
83
$
$
$
(141,021)
32,038
43,256
46,468
—
1,839,571
(525,955) (A)
9,183,981 (B)
— $
— $
598,503
226,820
(A) Includes equity in earnings of unconsolidated affiliates of $51,742 and $1,336 for Total E&P and Other, respectively.
(B)
Includes investments in unconsolidated equity affiliates of $188,376 and $2,588 for Total E&P and Other, respectively.
148
Industry segment results for the year ended December 31, 2015 are:
Sales—Outside
$ 379,453
$ 92,223
$
200,645
$
54,600
$
726,921
$ 1,289,036
$
— $
— $
2,015,957 (C)
Marcellus
Shale
Utica
Shale
Coalbed
Methane
Other
Gas
Total
E&P
PA Mining
Operations
Other
Adjustments
and
Eliminations
Consolidated
Gain on Commodity Derivative Instruments
100,785
6,430
67,281
218,446
392,942
Other Outside Sales
Sales—Purchased Gas
Freight—Outside
Intersegment Transfers
Total Sales and Freight
Earnings (Loss) From Continuing Operations
Before Income Tax
Segment Assets
Depreciation, Depletion and Amortization
Capital Expenditures
—
—
—
—
—
—
—
—
—
—
—
1,538
—
14,450
—
—
—
14,450
—
1,538
—
—
—
20,499
—
—
30,967
—
—
—
$ 480,238
$ 98,653
$
56,116
$ (19,428)
$
$
269,464
$ 287,496
$ 1,135,851
$ 1,309,535
59,662
$ (775,207)
$
(678,857)
$
404,994
$ 6,892,284
$ 2,076,301
$
$
370,374
832,446
$
$
176,864
136,291
$
$
$
$
$
30,967
(200,304)
939,497
19,882
14,197
$
$
$
$
$
—
—
—
—
(1,538)
(1,538)
(1,538)
$
$
392,942
30,967
14,450
20,499
—
2,474,815
(475,705) (D)
1,021,820
$ 10,929,902 (E)
— $
567,120
— $
982,934
(C) Included in the PA Mining Operations segment are sales of $242,020 to Duke Energy, which comprises over 10% of sales.
(D) Includes equity in earnings of unconsolidated affiliates of $46,614 and $8,283 for Total E&P and Other, respectively.
(E)
Includes investments in unconsolidated equity affiliates of $234,803 and $2,527 for Total E&P and Other, respectively.
149
Industry segment results for the year ended December 31, 2014 are:
Sales—Outside
$ 457,679
$ 86,948
$ 340,739
$
119,558
$ 1,004,924
$
1,616,874
$
— $
— $
2,621,798 (F)
Marcellus
Shale
Utica
Shale
Coalbed
Methane
Other
Gas
Total
E&P
PA Mining
Operations
Other
Adjustments
and
Eliminations
Consolidated
Gain on Commodity Derivative Instruments
14,764
1,247
4,103
Other Outside Sales
Sales—Purchased Gas
Freight—Outside
Intersegment Transfers
Total Sales and Freight
Earnings (Loss) From Continuing Operations
Before Income Tax
Segment Assets
Depreciation, Depletion and Amortization
Capital Expenditures
—
—
—
—
—
—
—
—
—
—
—
2,458
3,079
—
8,999
—
—
23,193
—
8,999
—
2,458
$ 472,443
$ 88,195
$ 347,300
$
131,636
$ 1,039,574
$ 171,902
$ 43,645
$ 108,107
$ (133,940)
$
189,714
$ 7,364,185
$
323,600
$ 1,103,656
—
—
—
23,133
—
1,640,007
430,968
—
276,242
—
—
78,229
354,471
(438,073)
$
$
2,094,041
$ 1,186,874
173,316
341,229
$
$
35,727
14,567
$
$
$
$
$
$
$
$
$
$
—
—
—
—
(80,687)
(80,687)
(2,458)
$
$
23,193
276,242
8,999
23,133
—
2,953,365
180,151 (G)
1,009,546
$ 11,654,646 (H)
— $
532,643
— $
1,459,452
(F) Included in the Total E&P segment are sales of $295,779 to NJR Energy Services Company, which comprises over 10% of sales.
(G) Includes equity in earnings of unconsolidated affiliates of $32,217 and $17,574 for Total E&P and Other, respectively.
(H) Includes investments in unconsolidated equity affiliates of $121,721 and $31,237 for Total E&P and Other, respectively.
150
Reconciliation of Segment Information to Consolidated Amounts:
Revenue and Other Income:
Total Segment Sales and Freight from External Customers
(Loss) Gain on Commodity Derivative Instruments
Other Income not Allocated to Segments (Note 4)
Gain on Sale of Assets
Total Consolidated Revenue and Other Income
(Loss) Earnings From Continuing Operations Before Income Tax:
Segment (Loss) Income Before Income Taxes for reportable business
segments
Segment (Loss) Income Before Income Taxes for all other business
segments
Interest expense
Eliminations
Loss on debt extinguishment
(Loss) Earnings From Continuing Operations Before Income Tax
Total Assets:
Segment assets for total reportable business segments
Segment assets for all other business segments
Items excluded from segment assets:
Cash and other investments
Recoverable income taxes
Deferred tax assets
Discontinued Operations
Total Consolidated Assets
For the Years Ended December 31,
2014
2015
2016
$
$
1,980,592
(141,021)
167,306
19,498
2,026,375
$
$
2,081,873
392,942
144,351
74,173
2,693,339
$
$
2,930,172
23,193
207,460
43,198
3,204,023
For the Years Ended December 31,
2014
2015
2016
$
(248,132) $
(273,863) $
620,682
(85,923)
(191,476)
(424)
—
(525,955) $
66,713
(199,266)
(1,538)
(67,751)
(475,705) $
(119,473)
(223,333)
(2,458)
(95,267)
180,151
$
December 31,
2016
8,217,774
797,830
$
2015
8,968,585
859,675
47,153
116,851
4,290
83
9,183,981
65,935
13,887
—
1,021,820
$ 10,929,902
$
$
151
Enterprise-Wide Disclosures:
CONSOL Energy's Revenues by geographical location (I):
United States
Asia
Europe
South America
Canada
Total Revenues and Freight from External Customers (J)
_________________________
For the Years Ended December 31,
2014
2015
2016
$
$
1,799,336
109,312
40,704
25,406
5,834
1,980,592
$
$
1,822,452
106,954
112,844
28,060
11,563
2,081,873
$
$
2,713,833
66,912
121,909
19,013
8,505
2,930,172
(I) CONSOL Energy attributes revenue to individual countries based on the location of the customer.
(J) CONSOL Energy has contractual relationships with certain U.S. based customers who distribute coal to
international markets. The table above reflects the ultimate destination of CONSOL Energy coal.
CONSOL Energy's Property, Plant and Equipment by geographical location:
United States
Canada
Discontinued Operations
Total Property, Plant and Equipment, net
December 31,
2016
2015
$
8,129,415
$
8,721,682
11,024
—
11,024
936,671
$
8,140,439
$
9,669,377
NOTE 24—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:
The payment obligations under the $74,470, 8.250% per annum senior notes due April 1, 2020, the $20,611, 6.375% per
annum senior notes due March 1, 2021, the $1,854,731, 5.875% per annum senior notes due April 15, 2022, and the $494,344,
8.000% per annum senior notes due April 1, 2023 issued by CONSOL Energy are jointly and severally, and also fully and
unconditionally, guaranteed by certain subsidiaries of CONSOL Energy. In accordance with positions established by the Securities
and Exchange Commission (SEC), the following financial information sets forth separate financial information with respect to
the parent, CNX Gas, a guarantor subsidiary, CNX Coal Resources LP (CNXC), a non-guarantor subsidiary, and the remaining
guarantor and non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries and certain
intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and
liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment
liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this
presentation.
On September 30, 2016, CNXC acquired an additional 5% undivided interest in the Pennsylvania Mining Complex from
CONSOL Energy, increasing their total undivided interest to 25%. To account for the acquisition, CNXC recast its consolidated
financial statements to retrospectively reflect the additional 5% interest as if the business was owned for all periods presented.
This resulted in corresponding retrospective adjustments between the Other Subsidiary Guarantors and the CNXC Non-Guarantor
columns below. See Note 25 - Related Party Transactions of the Notes to the Audited Consolidated Financial Statements in Item
8 of this Form 10-K for additional information.
152
Income Statement for the Year Ended December 31, 2016:
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales
Loss on Commodity Derivative
Instruments
Coal Sales
Other Outside Sales
Purchased Gas Sales
Freight-Outside Coal
Miscellaneous Other Income
Gain (Loss) on Sale of Assets
Total Revenue and Other Income
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense
Transportation, Gathering and
Compression
Production, Ad Valorem, and Other
Fees
Depreciation, Depletion and
Amortization
Exploration and Production Related
Other Costs
Purchased Gas Costs
Other Corporate Expenses
Selling, General and Administrative
Costs
Total Exploration and Production
Costs
PA Mining Operations Costs
Operating and Other Costs
Depreciation, Depletion and
Amortization
Freight Expense
Selling, General and Administrative
Costs
Total PA Mining Operations Costs
Other Costs
Miscellaneous Operating Expense
Selling, General and Administrative
Costs
Depreciation, Depletion and
Amortization
Interest Expense
Total Other Costs
Total Costs And Expenses
(Loss) Earnings from Continuing
Operations Before Income Tax
Income Tax (Benefit) Expense
(Loss) Income From Continuing
Operations
Loss From Discontinued
Operations, net
Net (Loss) Income
Less: Net Income Attributable to
Noncontrolling Interest
Net (Loss) Income Attributable to
CONSOL Energy Shareholders
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination
Consolidated
$
— $ 793,672
$
— $
— $
— $
(424) $
793,248
— (141,021)
—
—
—
—
43,256
—
—
—
80,444
(712,927)
14,870
—
791,221
(712,927)
—
799,187
32,038
—
34,865
83,735
4,637
954,462
—
266,395
—
—
11,603
3,128
(9)
281,117
—
—
—
—
—
—
—
—
96,434
374,350
31,049
417,853
14,519
42,717
87,913
102,503
— 1,167,338
—
—
—
—
—
43,533
—
568
173,327
217,428
217,428
—
—
—
—
—
—
—
—
2,723
2,723
1,170,061
(930,355)
(82,253)
(378,840)
(150,551)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
550,299
183,001
126,201
34,865
27,563
738,928
139,289
12,717
11,887
6,707
170,600
909,528
44,934
242,832
41,994
11,603
9,949
246,547
—
—
—
8,719
8,719
255,266
25,851
—
25,851
—
25,851
(848,102)
(228,289)
(197,898)
—
(848,102)
—
(228,289)
—
(197,898)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
47
—
—
—
47
47
—
—
—
—
—
712,926
—
712,502
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(141,021)
1,065,582
32,038
43,256
46,468
167,306
19,498
2,026,375
96,434
374,350
31,049
417,853
14,519
42,717
87,913
102,503
1,167,338
733,300
168,195
46,468
37,512
985,475
182,869
12,717
12,455
191,476
399,517
2,552,330
(47)
(18)
(29)
712,502
—
(525,955)
10,010
712,502
(535,965)
(303,183)
(303,212)
—
712,502
(303,183)
(839,148)
—
—
—
—
—
8,954
8,954
$ (848,102) $ (228,289) $ (197,898) $
25,851
$ (303,212) $ 703,548
$
(848,102)
153
Balance Sheet at December 31, 2016:
Property, Plant and Equipment
114,611
8,851,226
3,928,861
876,690
Assets:
Current Assets:
Cash and Cash Equivalents
Accounts and Notes Receivable:
Trade
Other Receivables
Inventories
Recoverable Income Taxes
Prepaid Expenses
Current Assets of Discontinued
Operations
Total Current Assets
Property, Plant and Equipment:
Less-Accumulated Depreciation,
Depletion and Amortization
Total Property, Plant and Equipment-
Net
Other Assets:
Deferred Income Taxes
Investment in Affiliates
Other
Total Other Assets
Total Assets
Liabilities and Equity:
Current Liabilities:
Accounts Payable
Accounts Payable
(Recoverable)-Related Parties
Current Portion of Long-Term
Debt
Other Accrued Liabilities
Current Liabilities of
Discontinued Operations
Total Current Liabilities
Long-Term Debt:
Deferred Credits and Other Liabilities:
Postretirement Benefits Other
Than Pensions
Pneumoconiosis Benefits
Mine Closing
Gas Well Closing
Workers’ Compensation
Salary Retirement
Other
Total Deferred Credits and
Other Liabilities
Total CONSOL Energy Inc.
Stockholders’ Equity
Noncontrolling Interest
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC
Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination
Consolidated
$
49,722
$
83
$
— $
9,785
$
885
$
— $
60,475
—
20,097
—
175,877
12,828
124,509
34,773
15,301
(59,026)
60,500
72,295
14,516
38,669
—
16,306
—
—
—
258,524
176,140
141,786
23,418
515
11,491
—
3,512
—
48,721
84,788
3,106,296
1,997,687
442,178
29,823
5,744,930
1,931,174
434,512
25,904
(21,614)
7,974,260
19,960
8,020,124
188,376
67,096
233,858
—
27,269
114,030
141,299
—
—
21,063
21,063
—
—
—
—
—
83
968
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(7,998,941)
—
(7,998,941)
220,222
69,901
65,461
116,851
93,146
83
626,139
13,771,388
5,630,949
8,140,439
4,290
190,964
222,149
417,403
$ 8,308,471
$ 6,154,928
$ 2,214,259
$
504,296
$
968
$ (7,998,941) $
9,183,981
$
48,666
$
127,309
$
36,039
$
18,797
$
— $
10,805
$
241,616
1,832,908
1,034,138
(2,648,416)
1,666
(209,491)
(10,805)
—
1,533
75,039
6,369
337,374
4,010
223,705
—
1,958,146
2,421,511
—
—
1,505,190
(2,384,662)
26,884
115,685
—
—
—
—
—
112,543
17,876
—
—
—
195,704
—
—
117,658
659,474
106,016
209,384
27,549
64,187
—
15,663
88
44,230
—
64,781
197,989
—
2,057
9,247
99
3,090
—
463
130,419
313,362
1,082,273
14,956
—
—
6,050
(203,441)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12,000
680,348
6,050
940,014
2,762,069
659,474
108,073
218,631
223,352
67,277
112,543
151,660
1,541,010
3,798,395
4,309,492
3,400,963
226,570
204,409
(8,141,434)
3,798,395
—
—
—
—
—
142,493
142,493
Total Liabilities and Equity
$ 8,308,471
$ 6,154,928
$ 2,214,259
$
504,296
$
968
$ (7,998,941) $
9,183,981
154
Condensed Statement of Cash Flows for the Year Ended December 31, 2016:
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC
Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination Consolidated
$ 943,652
$ (165,861) $
58,648
$
73,098
$ (377,257) $ (72,930) $
459,350
—
—
—
—
9,935
—
9,935
$ 943,652
$ (165,861) $
58,648
$
73,098
$ (367,322) $ (72,930) $
469,285
Net Cash Provided by (Used in)
Continuing Operating Activities
Net Cash Provided by Discontinued
Operating Activities
Net Cash Provided by (Used in)
Operating Activities
Cash Flows from Investing Activities:
Capital Expenditures
$
(2,990) $ (165,101) $ (46,025) $ (12,704) $
— $
— $
(226,820)
CNXC Acquisition of 5%
Pennsylvania Mining Complex
Proceeds from Noble Exchange
Settlement
Proceeds From Sales of Assets
Net Investments in Equity Affiliates
Net Cash (Used in) Provided
by Continuing Investing
Activities
Net Cash Provided by
Discontinued Investing
Activities
Net Cash (Used in) Provided
by Investing Activities
Cash Flows from Financing Activities:
Payments on Short-Term
Borrowings
Payments on Miscellaneous
Borrowings
Proceeds from Revolver - MLP
Distributions of Noncontrolling
Interest
Net Change in Parent
Advancements
Dividends Paid
Proceeds from Issuance of Common
Stock
Debt Issuance and Financing Fees
Net Cash (Used in) Provided
by Continuing Financing
Activities
Net Cash Used in
Discontinued Financing
Activities
Net Cash (Used in) Provided
by Financing Activities
—
—
—
—
—
21,500
(21,500)
213,295
44,710
79,103
—
15,169
(5,360)
—
23
—
(2,990)
172,007
(14,716)
(34,181)
—
—
—
—
—
—
—
—
—
367,251
—
—
—
—
—
—
—
213,295
59,902
73,743
120,120
367,251
$
(2,990) $ 172,007
$ (14,716) $ (34,181) $ 367,251
$
— $
487,371
$ (952,000) $
— $
— $
— $
— $
— $
(952,000)
(1,645)
(6,138)
(450)
(79)
—
—
—
(2,294)
4
—
—
—
—
—
—
—
—
—
—
—
—
(482)
16,000
(42,634)
(8,953)
—
—
—
(955,935)
(6,138)
(932)
(35,666)
—
—
—
—
—
—
—
—
—
—
(8,312)
16,000
20,977
(21,657)
8,953
—
—
—
—
(2,294)
4
(482)
29,930
(968,741)
—
—
—
—
(14)
—
(14)
$ (955,935) $
(6,138) $
(932) $ (35,666) $
(14) $
29,930
$
(968,755)
155
Statement of Comprehensive Income for the Year Ended December 31, 2016:
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination Consolidated
Net (Loss) Income
$
(848,102) $
(228,289) $
(197,898) $
25,851
$
(303,212) $
712,502
$
(839,148)
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term
Liability Adjustments
Reclassification of Cash Flow Hedge
from OCI to Earnings
(33,226)
—
(34,044)
(43,470)
(43,470)
—
Other Comprehensive (Loss) Income:
(76,696)
(43,470)
(34,044)
818
—
818
—
—
—
33,226
(33,226)
43,470
76,696
(43,470)
(76,696)
Comprehensive (Loss) Income
(924,798)
(271,759)
(231,942)
26,669
(303,212)
789,198
(915,844)
Less: Comprehensive Income
Attributable to Noncontrolling Interest
Comprehensive (Loss) Income
Attributable to CONSOL Energy Inc.
Shareholders
—
—
—
—
—
9,216
9,216
$
(924,798) $
(271,759) $
(231,942) $
26,669
$
(303,212) $
779,982
$
(925,060)
156
Income Statement for the Year Ended December 31, 2015:
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination
Consolidated
$
— $ 728,458
$
— $
— $
— $
(1,537) $
726,921
—
—
—
—
—
(172,450)
—
(172,450)
392,942
—
—
14,450
—
62,340
12,540
1,210,730
—
966,775
30,967
—
16,690
82,690
61,572
1,158,694
—
322,261
—
—
3,809
880
61
327,011
—
—
—
—
—
4,105
—
4,105
—
—
—
—
—
166,786
—
165,249
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales
Gain on Commodity Derivative
Instruments
Coal Sales
Other Outside Sales
Purchased Gas Sales
Freight-Outside Coal
Miscellaneous Other Income
Gain on Sale of Assets
Total Revenue and Other Income
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense
Transportation, Gathering and
Compression
Production, Ad Valorem, and Other
Fees
Depreciation, Depletion and
Amortization
Exploration and Production Related
Other Costs
Purchased Gas Costs
Other Corporate Expenses
Impairment of Exploration and
Production Properties
Selling, General and Administrative
Costs
Total Exploration and Production
Costs
PA Mining Operations Costs
Operating and Other Costs
Depreciation, Depletion and
Amortization
Freight Expense
Selling, General and Administrative
Costs
Total PA Mining Operations Costs
Other Costs
Miscellaneous Operating Expense
Selling, General and Administrative
Costs
Depreciation, Depletion and
Amortization
Loss on Debt Extinguishment
Interest Expense
Total Other Costs
Total Costs And Expenses
(Loss) Earnings from Continuing
Operations Before Income Tax
Income Tax (Benefit) Expense
(Loss) Income From Continuing
Operations
Loss From Discontinued
Operations, net
Net (Loss) Income
Less: Net Income Attributable to
Noncontrolling Interest
Net (Loss) Income Attributable to
CONSOL Energy Shareholders
392,942
1,289,036
30,967
14,450
20,499
144,351
74,173
2,693,339
121,847
343,403
30,438
370,374
10,120
10,721
65,939
828,905
102,229
—
—
—
—
(9)
—
—
—
—
(9)
1,883,976
—
—
—
—
—
—
—
666,302
176,864
20,499
40,843
904,508
78,743
14,918
—
—
(8,803)
(8,803)
(8,812)
19,882
67,751
199,266
380,560
3,169,044
174,061
—
(475,705)
(125,439)
174,061
(350,266)
—
—
—
—
—
—
—
—
—
121,847
343,403
30,438
370,374
10,120
10,721
65,939
828,905
102,229
— 1,883,976
—
—
—
—
—
69,059
—
604
67,751
186,291
323,705
323,705
—
—
—
—
—
—
—
—
—
5,613
5,613
1,889,589
(496,155)
(121,270)
(678,859)
(257,056)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
472,341
193,961
132,728
16,690
29,912
651,671
9,176
14,918
19,278
—
6,453
49,825
701,496
457,198
251,558
44,136
3,809
10,931
252,837
—
—
—
—
9,636
9,636
262,473
64,538
—
64,538
—
64,538
—
—
—
—
9
—
—
—
—
9
—
—
—
—
—
508
—
—
—
76
584
593
3,512
1,329
2,183
(374,885)
(421,803)
205,640
—
(374,885)
—
(421,803)
—
205,640
(14,209)
(12,026)
—
174,061
(14,209)
(364,475)
—
—
—
—
—
10,410
10,410
$ (374,885) $ (421,803) $ 205,640
$
64,538
$ (12,026) $ 163,651
$
(374,885)
157
Property, Plant and Equipment
156,348
8,875,027
3,898,005
865,527
Balance Sheet at December 31, 2015:
Assets:
Current Assets:
Cash and Cash Equivalents
Accounts and Notes Receivable:
Trade
Other Receivables
Inventories
Recoverable Income Taxes
Prepaid Expenses
Current Assets of Discontinued Operations
Total Current Assets
Property, Plant and Equipment:
Less-Accumulated Depreciation,
Depletion and Amortization
Property, Plant and Equipment of
Discontinued Operations
Total Property, Plant and Equipment-Net
Other Assets:
Investment in Affiliates
Other
Other Assets of Discontinued Operations
Total Other Assets
Total Assets
Liabilities and Equity:
Current Liabilities:
Accounts Payable
Accounts Payable (Recoverable)-Related
Parties
Current Portion of Long-Term Debt
Short-Term Notes Payable
Other Accrued Liabilities
Current Liabilities of Discontinued
Operations
Deferred Credits and Other Liabilities:
Deferred Income Taxes
Postretirement Benefits Other Than
Pensions
Pneumoconiosis Benefits
Mine Closing
Gas Well Closing
Workers’ Compensation
Salary Retirement
Reclamation
Other
Deferred Credits and Other Liabilities of
Discontinued Operations
Total Deferred Credits and Other
Liabilities
Total CONSOL Energy Inc. Stockholders’
Equity
Noncontrolling Interest
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC
Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination
Consolidated
$
64,995
$
75
$
— $
6,534
$
970
$
— $
72,574
—
18,933
—
72,913
27,245
—
72,664
99,001
13,815
(59,026)
244,680
—
59,321
3,330
40,739
—
20,273
—
184,086
371,209
123,663
19,398
471
12,238
—
5,089
—
43,730
111,367
2,695,674
1,854,249
400,911
—
—
—
—
44,981
6,179,353
2,043,756
464,616
—
—
—
—
—
81,105
82,075
—
—
936,671
936,671
—
—
—
—
—
—
—
—
—
—
—
151,383
121,735
66,792
13,887
297,287
81,105
804,763
13,794,907
5,062,201
936,671
9,669,377
10,563,985
53,529
—
10,617,514
$ 10,846,581
234,803
47,892
—
282,695
$6,833,257
6,293
95,369
—
101,662
$ 2,269,081
—
17,598
—
17,598
525,944
237,330
— (10,567,751)
214,388
—
—
4,044
—
4,044
455,762
(10,567,751)
4,044
$(10,567,751) $ 10,929,902
$ 1,022,790
$
$
32,245
$ 149,930
$
37,212
$
17,405
$
— $
13,817
$
250,609
2,650,732
1,521,442
(3,953,215)
1,509
952,000
63,668
6,798
—
102,753
1,041
—
218,186
4,310
61
—
37,220
(209,452)
(13,817)
—
—
—
—
5,001
5,001
—
—
—
—
—
—
—
—
—
—
9,409
952,000
421,827
51,514
1,685,359
2,738,783
5,001
2,743,784
74,629
630,892
111,903
227,339
163,842
69,812
91,596
25
166,957
107,988
1,644,983
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(122,547)
197,176
—
—
—
—
—
—
91,596
—
56,390
—
—
—
135,174
—
—
—
105,588
630,892
109,969
218,936
28,572
66,883
—
25
4,266
—
—
1,934
8,403
96
2,929
—
—
713
—
—
—
—
107,988
25,439
437,938
1,059,543
14,075
107,988
Total Current Liabilities
3,700,154
1,780,923
(3,696,776)
58,996
(157,938)
—
—
—
—
51,514
Long-Term Debt:
Long-Term Debt
Long-Term Debt of Discontinued
Operations
2,418,961
33,141
105,611
181,070
—
—
—
—
Total Long-Term Debt
2,418,961
33,141
105,611
181,070
4,702,027
4,581,255
4,800,703
271,803
1,067,739
(10,721,500)
4,702,027
—
—
—
—
—
153,749
153,749
Total Liabilities and Equity
$ 10,846,581
$6,833,257
$ 2,269,081
$
525,944
$ 1,022,790
$(10,567,751) $ 10,929,902
158
Condensed Statement of Cash Flows for the Year Ended December 31, 2015:
Net Cash (Used in) Provided by
Continuing Operating Activities
Net Cash Provided by Discontinued
Operating Activities
Net Cash (Used in) Provided by
Operating Activities
Cash Flows from Investing Activities:
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC
Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination Consolidated
$ (153,930) $
624,788
$
21,906
$
76,908
$
33,422
$ (103,417) $
499,677
—
—
—
—
6,172
—
6,172
$ (153,930) $
624,788
$
21,906
$
76,908
$
39,594
$ (103,417) $
505,849
Capital Expenditures
$
(9,752) $ (832,446) $ (106,663) $ (34,073) $
— $
— $ (982,934)
Proceeds From Sales of Assets
Net Investments in Equity
Affiliates
142
—
10,298
100,060
(79,756)
(4,465)
71
—
(9,610)
(901,904)
(11,068)
(34,002)
—
—
—
—
(39,633)
—
—
—
—
—
—
—
110,571
(84,221)
(956,584)
(39,633)
Net Cash Used in Continuing
Investing Activities
Net Cash Used in
Discontinued Investing
Activities
Net Cash Used in Investing
Activities
Cash Flows from Financing Activities:
Proceeds from (Payments on)
Short-Term Borrowings
(Payments on) Proceeds from
Miscellaneous Borrowings
Payments on Long-Term Notes,
including Redemption Premium
Proceeds from Revolver - MLP
Distributions to Noncontrolling
Interest
Proceeds from Sale of MLP
Interest
Proceeds from Issuance of Long-
Term Notes
Net Distributions from Offering to
Parent
Net Change in Parent
Advancements
Tax Benefit from Stock-Based
Compensation
Dividends Paid
Proceeds from Issuance of
Common Stock
Purchases of Treasury Stock
Debt Issuance and Financing Fees
Net Cash Provided by (Used
in) Continuing Financing
Activities
Net Cash Used in
Discontinued Financing
Activities
Net Cash Provided by (Used
in) Financing Activities
$
(9,610) $ (901,904) $ (11,068) $ (34,002) $ (39,633) $
— $ (996,217)
$ 952,000
$
252,900
$
— $
— $
— $ (252,900) $
952,000
(1,281)
(6,391)
3,443
(53)
(1,263,719)
—
—
—
492,760
—
—
208
(33,281)
8,288
(71,674)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(10,951)
185,000
(11,353)
148,359
16,990
— (342,711)
—
—
—
—
—
(17,328)
—
—
—
—
(14,281)
(4,329)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(4,282)
10,951
(1,263,719)
—
185,000
6,293
(5,060)
—
148,359
(16,990)
492,760
342,711
17,328
—
—
—
—
(3,976)
—
—
208
(33,281)
8,288
(71,674)
(22,586)
83,301
246,509
(10,838)
(36,376)
—
103,417
386,013
—
—
—
—
(56)
—
(56)
$
83,301
$
246,509
$ (10,838) $ (36,376) $
(56) $ 103,417
$
385,957
159
Statement of Comprehensive Income for the Year Ended December 31, 2015:
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination Consolidated
Net (Loss) Income
$
(374,885) $
(421,803) $
205,640
$
64,538
$
(12,026) $
174,061
$
(364,475)
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term
Liability Adjustments
Reclassification of Cash Flow Hedge
from OCI to Earnings
Other Comprehensive (Loss) Income:
(164,498)
(78,051)
(84,607)
Comprehensive (Loss) Income
(539,383)
(499,854)
121,033
(86,447)
—
(84,607)
(1,840)
(78,051)
(78,051)
—
—
—
—
(12,026)
86,447
(86,447)
78,051
164,498
338,559
(78,051)
(164,498)
(528,973)
—
(1,840)
62,698
Less: Comprehensive Income
Attributable to Noncontrolling Interest
Comprehensive (Loss) Income
Attributable to CONSOL Energy Inc.
Shareholders
—
—
—
—
—
10,410
10,410
$
(539,383) $
(499,854) $
121,033
$
62,698
$
(12,026) $
328,149
$
(539,383)
160
Income Statement for the Year Ended December 31, 2014:
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination
Consolidated
$
— $1,007,381
$
— $
— $
— $
(2,457) $ 1,004,924
—
—
—
—
—
420,030
—
420,030
23,193
—
— 1,212,627
41,255
—
—
8,999
18,941
—
138,201
60,634
(2,926)
45,917
1,408,098
1,146,124
—
404,247
—
—
4,192
9,475
185
418,099
—
—
234,987
—
—
10,305
22
245,314
—
—
—
—
—
(431,185)
—
(433,642)
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales
Gain on Commodity Derivative
Instruments
Coal Sales
Other Outside Sales
Purchased Gas Sales
Freight-Outside Coal
Miscellaneous Other Income
Gain (Loss) on Sale of Assets
Total Revenue and Other Income
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense
Transportation, Gathering and
Compression
Production, Ad Valorem, and Other
Fees
Depreciation, Depletion and
Amortization
Exploration and Production Related
Other Costs
Purchased Gas Costs
Other Corporate Expenses
Selling, General and Administrative
Costs
Total Exploration and Production
Costs
PA Mining Operations Costs
Operating and Other Costs
Depreciation, Depletion and
Amortization
Freight Expense
Selling, General and Administrative
Costs
Total PA Mining Operations Costs
Other Costs
Miscellaneous Operating Expense
Selling, General and Administrative
Costs
Depreciation, Depletion and
Amortization
Loss on Debt Extinguishment
Interest Expense
Total Other Costs
Total Costs And Expenses
Earnings (Loss) from Continuing
Operations Before Income Tax
Income Tax (Benefit) Expense
Income (Loss) From Continuing
Operations
Loss From Discontinued
Operations, net
Net Income (Loss) Attributable to
CONSOL Energy Shareholders
23,193
1,616,874
276,242
8,999
23,133
207,460
43,198
3,204,023
139,242
239,579
39,418
323,600
23,355
7,251
46,838
—
(12)
—
—
(119)
—
—
—
128,731
(131)
948,014
—
—
—
—
—
—
—
—
—
(17,608)
(17,608)
(17,739)
(415,903)
—
982,749
173,316
23,133
68,597
1,247,795
460,429
13,307
35,727
95,267
223,333
828,063
3,023,872
180,151
15,204
—
—
—
—
—
—
—
—
—
—
—
—
—
—
99,273
788
640
95,267
213,384
409,352
409,352
10,678
(152,412)
139,242
239,591
39,418
323,600
22,718
7,251
46,838
128,731
947,389
—
—
—
—
—
—
—
—
—
9,021
9,021
956,410
189,714
66,441
—
—
—
—
637
—
—
—
637
—
—
—
—
—
—
—
—
—
742,886
239,863
129,979
12,575
57,814
943,254
129,257
12,519
33,273
—
9,608
184,657
1,128,548
279,550
96,926
43,337
4,192
17,149
304,541
—
—
—
—
8,683
8,683
313,224
104,875
—
—
—
—
—
119
—
—
—
119
—
—
6,366
(6,366)
—
231,899
—
1,814
—
245
233,958
234,077
11,237
4,249
163,090
123,273
182,624
104,875
6,988
(415,903)
164,947
—
—
—
—
(1,857)
—
(1,857)
$ 163,090
$ 123,273
$ 182,624
$
104,875
$
5,131
$ (415,903) $
163,090
161
Condensed Statement of Cash Flows for the Year Ended December 31, 2014:
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC
Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination Consolidated
$ (178,921) $
567,851
$
(4,086) $ 142,636
$ (59,441) $ 372,347
$
840,386
—
—
—
—
96,390
—
96,390
$ (178,921) $
567,851
$
(4,086) $ 142,636
$
36,949
$ 372,347
$
936,776
Net Cash (Used in) Provided by
Continuing Operating Activities
Net Cash Provided by Discontinued
Operating Activities
Net Cash (Used in) Provided by
Operating Activities
Cash Flows from Investing Activities:
Capital Expenditures
$
(4,420) $(1,103,656) $ (266,300) $ (85,076) $
— $
— $ (1,459,452)
Proceeds From Sales of Assets
Net Investments in Equity
Affiliates
Net Cash Provided by (Used
in) Continuing Investing
Activities
Net Cash Used in
Discontinued Investing
Activities
Net Cash Provided by (Used
in) Investing Activities
Cash Flows from Financing Activities:
Payments on Short-Term
Borrowings
(Payments on) Proceeds from
Miscellaneous Borrowings
Payments on Long-Term Notes,
including Redemption Premium
Proceeds from Issuance of Long-
Term Notes
Net Change in Parent
Advancements
Tax Benefit from Stock-Based
Compensation
Dividends Paid
Proceeds from Issuance of
Common Stock
44,049
92,507
201,221
19,046
—
85,248
9,959
—
39,629
(925,901)
(55,120)
(66,030)
13
—
13
—
—
356,836
95,207
— (1,007,409)
—
—
—
—
(33,973)
—
(33,973)
$
39,629
$ (925,901) $ (55,120) $ (66,030) $ (33,960) $
— $ (1,041,382)
$ (11,736) $
— $
— $
— $
— $
— $
(11,736)
(399)
387,663
(7,233)
(24)
(2,630)
(387,663)
(10,286)
(1,819,005)
1,859,920
—
2,629
(57,506)
15,016
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(2,311)
14,214
(88,485)
—
—
—
—
—
—
—
—
—
—
—
—
—
2,311
(1,819,005)
(14,214)
1,859,920
88,485
—
—
—
—
—
—
2,629
(57,506)
15,016
(24,861)
—
Debt Issuance and Financing Fees
(24,861)
Other Financing Activities
—
(5,169)
5,169
Net Cash (Used in) Provided
by Financing Activities
$ (35,942) $
382,494
$
(2,064) $ (76,606) $
(2,630) $ (311,081) $
(45,829)
162
Statement of Comprehensive Income for the Year Ended December 31, 2014:
Parent
Issuer
CNX Gas
Guarantor
Other
Subsidiary
Guarantors
CNXC Non-
Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination Consolidated
Net Income (Loss)
$
163,090
$
123,273
$
182,624
$
104,875
$
5,131
$
(415,903) $
163,090
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term
Liability Adjustments
Net Increase (Decrease) in the Value of
Cash Flow Hedge
Reclassification of Cash Flow Hedge
from OCI to Earnings
94,989
—
53,190
41,799
97,316
97,316
(18,288)
(18,288)
—
—
—
—
Other Comprehensive Income (Loss):
174,017
79,028
53,190
41,799
—
—
—
—
(94,989)
94,989
(97,316)
97,316
18,288
(18,288)
(174,017)
174,017
Comprehensive Income (Loss)
Attributable to CONSOL Energy Inc.
Shareholders
$
337,107
$
202,301
$
235,814
$
146,674
$
5,131
$
(589,920) $
337,107
NOTE 25—RELATED PARTY TRANSACTIONS
CONE Gathering LLC and CONE Midstream Partners LP
In September 2011, CNX Gas Company, a wholly owned subsidiary of CONSOL Energy, and Noble Energy, Inc. (Noble
Energy), an unrelated third party, formed CONE Gathering LLC (CONE) to develop and operate each company's gas gathering
system needs in the Marcellus Shale play. CONSOL Energy accounts for CNX Gas Company's 50% ownership interest in CONE
under the equity method of accounting.
In May 2014, CONSOL Energy and Noble Energy (collectively, “the Sponsors”) formed CONE Midstream Partners LP (the
Partnership), a master limited partnership, to own, operate, develop and acquire natural gas gathering and other midstream energy
assets to service each company’s production in the Marcellus Shale in Pennsylvania and West Virginia. The Partnership's general
partner is CONE Midstream GP LLC, a wholly owned subsidiary of CONE.
In September 2014, the Partnership closed its initial public offering of 20,125,000 common units representing limited
partnership interests, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters.
Following the IPO, CONE had a 2% general partner interest in the Partnership, while each sponsor had a 32.1% limited partner
interest. CNX Gas Company accounts for its portion of the earnings in the Partnership under the equity method of accounting.
In November 2016, the Partnership acquired from CONE an additional 25% ownership interest in CONE Midstream DevCo
I LP, commonly referred to as the “Anchor Systems.” The transaction included a total purchase consideration of $248,000,
comprised of $140,000 in cash and issuance of approximately 5,200,000 common limited partnership units to the Sponsors.
Following the acquisition, CONE continues to have a 2% general partner interest in the Partnership, while each Sponsor’s limited
partner interest increased to 33.5%. At December 31, 2016, CNX Gas Company and Noble Energy each continue to own a 50%
interest in the assets of CONE that were not contributed to the Partnership.
163
The following is a summary of the Company's Investment in Affiliates balances included within the Consolidated Balance
Sheets associated with CONE and the Partnership, respectively:
Balance at December 31, 2014
Equity in Earnings
Additional Contributions
Distribution of Earnings
Balance at December 31, 2015
Equity in Earnings
Additional Contributions
Distribution of Earnings
Funds received on dropdown transaction
Basis differential
Balance at December 31, 2016
CONE
94,467
20,916
87,187
—
202,570
17,112
4,621
(8,224)
(70,000)
4,996
151,075
$
$
The Partnership
4,883
$
$
22,883
—
(16,719)
11,047
31,148
—
(19,066)
—
(4,996)
18,133
$
$
Total
99,350
43,799
87,187
(16,719)
213,617
48,260
4,621
(27,290)
(70,000)
—
169,208
The following transactions were included within Miscellaneous Other Income and Transportation, Gathering and
Compression within the Consolidated Statements of Income:
For the Years Ended December 31,
2015
2014
2016
Miscellaneous Other Income:
Equity in Earnings of Affiliates - CONE
Equity in Earnings of Affiliates - the Partnership
Transportation, Gathering and Compression:
Gathering Services - CONE
Gathering Services - the Partnership
$
$
$
$
17,112
31,148
706
123,020
$
$
$
$
20,916
22,883
1,077
104,291
$
$
$
$
25,521
4,286
219
65,365
At December 31, 2016 and December 31, 2015, CONSOL Energy had a net payable of $5,815 and $12,216, respectively,
due to both the Partnership and CONE primarily for accrued but unpaid gathering services. Additionally, during the year ended
December 31, 2015, CONSOL Energy purchased $2,239 of supply inventory from the Partnership. CONSOL Energy did not have
any supply inventory purchases from the Partnership during the year ended December 31, 2016.
CNX Coal Resources LP
In July 2015, CNX Coal Resources LP (CNXC) closed its initial public offering of 5,000,000 common units representing
limited partnership interests at a price to the public of $15.00 per unit. Additionally, Greenlight Capital entered into a common
unit purchase agreement with CNXC pursuant to which Greenlight Capital agreed to purchase, and CNXC agreed to sell, 5,000,000
common units at a price per unit equal to $15.00, which equates to $75,000 in net proceeds. CNXC's general partner is CNX Coal
Resources GP, a wholly owned subsidiary of CONSOL Energy. The underwriters of the IPO filing exercised an over-allotment
option of 561,067 common units to the public at $15.00 per unit.
In connection with the Initial Public Offering (IPO), CNXC entered into a $400,000 senior secured revolving credit facility
with certain lenders and PNC Bank, National Association (PNC), as administrative agent. Obligations under the revolving credit
facility are guaranteed by CNXC's subsidiaries (the guarantor subsidiaries) and are secured by substantially all of CNXC's and
CNXC's subsidiaries' assets pursuant to a security agreement and various mortgages. Under the new revolving credit facility,
CNXC made an initial draw of $200,000, and after origination fees of $3,000, the net proceeds were $197,000.
The total net proceeds related to these transactions that were distributed to CONSOL Energy were $342,711.
In September 2016, CNXC and its wholly owned subsidiary, CNX Thermal Holdings LLC (CNX Thermal), entered into a
Contribution Agreement with CONSOL Energy, CONSOL Pennsylvania Coal Company LLC and Conrhein Coal Company (the
Contributing Parties) under which CNX Thermal acquired an additional 5% undivided interest in and to the Pennsylvania Mine
164
Complex, in exchange for (i) cash consideration in the amount of $21,500 and (ii) CNXC's issuance of 3,956,496 Class A Preferred
Units representing limited partner interests in CNXC at an issue price of $17.01 per Class A preferred Unit (the "Class A Preferred
Unit Issue Price"), or an aggregate $67,300 in equity consideration. The Class A Preferred Unit Issue Price was calculated as the
volume-weighted average trading price of CNXC's common units (the "Common Units") over the trailing 15-day trading period
ending on September 29, 2016 (or $14.79 per unit), plus a 15% premium.
In connection with the PA Mining acquisition, in September 2016, the General Partner and CNXC entered into the First
Amended and Restated Omnibus Agreement (the "Amended Omnibus Agreement") with CONSOL Energy and certain of its
subsidiaries. Under the Amended Omnibus Agreement, CONSOL Energy indemnified CNXC for certain liabilities. The Amended
Omnibus Agreement also amended CNXC's obligations to CONSOL Energy with respect to the payment of an annual administrative
support fee and reimbursement for the provisions of certain management and operating services provided, in each case to reflect
structural changes in how those services are provided to CNXC by CONSOL Energy.
Charges for services from CONSOL Energy include the following:
Operating and Other Costs
Selling, General and Administrative Expenses
Total Services from CONSOL Energy
For the Years Ended December 31,
2014
2015
2016
$
$
4,251
3,826
8,077
$
$
6,793
8,926
15,719
$
$
6,707
11,384
18,091
At December 31, 2016 and December 31, 2015, CNXC had a net payable to CONSOL Energy in the amount of $1,666 and
$4,310, respectively. This payable includes reimbursements for business expenses, executive fees, stock-based compensation and
other items under the omnibus agreement.
165
Supplemental Gas Data (unaudited):
The following information was prepared in accordance with the FASB's Accounting Standards Update No. 2010-03,
“Extractive Activities-Oil and Gas (Topic 932).”
Capitalized Costs:
Proved gas properties
Unproved gas properties
Intangible drilling costs
Gas wells and related equipment
Gas gathering assets
Gas well plugging
Total Property, Plant and Equipment
Accumulated Depreciation, Depletion and Amortization
Net Capitalized Costs
Costs incurred for property acquisition, exploration and development (*):
Property acquisitions
Proved properties
Unproved properties
Development
Exploration
Total
__________
(*)
Includes costs incurred whether capitalized or expensed.
As of December 31,
2015
2016
$
$
2,016,916
1,116,282
3,583,565
791,996
1,138,299
176,961
8,824,019
(3,099,622)
5,724,397
$
$
1,922,602
1,421,083
3,452,989
785,744
1,147,173
115,121
8,844,712
(2,691,005)
6,153,707
For the Years Ended December 31,
2016
2015
2014
$
— $
— $
—
1,537
138,813
32,259
76,676
666,315
95,371
119,597
952,733
45,006
$
172,609
$
838,362
$ 1,117,336
166
Results of Operations for Producing Activities:
Natural Gas, NGLs and Oil Sales
(Loss) Gain on Commodity Derivative Instruments
Purchased Gas Sales
Total Revenue
Lease Operating Expense
Production, Ad Valorem, and Other Fees
Transportation, Gathering and Compression
Purchased Gas Costs
Impairment of Exploration and Production Properties
Other Costs
DD&A
Total Costs
Pre-tax Operating Income / (Loss)
Income Taxes / (Benefit)
Results of Operations for Producing Activities excluding Corporate and
Interest Costs
For the Years Ended December 31,
2015
2016
$
$
793,673
(141,021)
43,256
695,908
96,434
31,049
374,350
42,717
—
14,519
417,853
976,922
(281,014)
(69,308)
$
728,458
392,942
14,450
1,135,850
121,847
30,438
343,403
10,721
828,905
10,120
370,374
1,715,808
(579,958)
(250,220)
2014
1,007,381
23,193
8,999
1,039,573
139,242
39,418
239,591
7,251
—
22,718
323,600
771,820
267,753
45,162
$
(211,706) $
(329,738) $
222,591
The following is production, average sales price and average production costs, excluding ad valorem and severance taxes,
per unit of production:
Production (MMcfe)
Total average sales price before effects of financial settlements (per Mcfe)
Average effects of financial settlements (per Mcfe)
Total average sales price including effects of financial settlements (per
Mcfe)
Average lifting costs, excluding ad valorem and severance taxes (per
Mcfe)
For the Years Ended December 31,
2014
2015
2016
394,387
328,657
235,714
$
$
$
$
2.01
0.62
2.63
0.24
$
$
$
$
2.22
0.60
2.82
0.37
$
$
$
$
4.27
0.10
4.37
0.59
During the years ended December 31, 2016, 2015 and 2014, we drilled 36.0, 132.8, and 180.3 net development wells,
respectively. There were no net dry development wells in 2016, 2015, or 2014.
During the year ended December 31, 2016, there were no net exploratory wells. During the years ended December 31, 2015
and 2014, we drilled 2.5 and 8.5 net exploratory wells, respectively. There were no net dry exploratory wells in 2016, 2015, or
2014.
At December 31, 2016, there were 15.0 net development wells and no exploratory wells that have been partially drilled but
not turned in-line. Additionally there are 65.5 net developmental wells that are drilled but uncompleted and 3.0 net developmental
wells and no net exploratory well that have been completed and are awaiting final tie-in to production.
We are committed to provide 431.4 Bcf of gas under existing sales contracts or agreements over the course of the next four
years. We expect to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.
167
Most of our development wells and proved acreage are located in Virginia, West Virginia and Pennsylvania. Some leases
are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments
or other term commitments are satisfied. The following table sets forth, at December 31, 2016, the number of producing wells,
developed acreage and undeveloped acreage:
Producing Gas Wells (including gob wells)
Producing Oil Wells
Acreage Position:
Proved Developed Acreage
Proved Undeveloped Acreage
Unproved Acreage
Total Acreage
Gross
Net(1)
17,314
189
12,846
30
549,816
34,467
4,804,804
5,389,087
541,282
30,038
3,745,533
4,316,853
____________
(1) Net acres include acreage attributable to our working interests of the properties. Additional adjustments (either increases or
decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties
in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
Proved Oil and Gas Reserves Quantities:
Annually, the preparation of natural gas reserves estimates are completed in accordance with CONSOL Energy's prescribed
internal control procedures, which include verification of input data into a gas reserves forecasting and economic evaluation
software, as well as multi-functional management review. The input data verification includes reviews of the price and cost
assumptions used in the economic model to determine the reserves. Also, the production volumes are reconciled between the
system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for
overseeing the preparation of the reserve estimates is a petroleum engineer with over 10 years of experience in the oil and gas
industry. Our 2016 gas reserves results, which are reported in the Supplemental Gas Data year ended December 31, 2016 Form
10-K, were audited by Netherland, Sewell & Associates, Inc. The technical person primarily responsible for overseeing the audit
of our reserves is a registered professional engineer in the state of Texas with over 15 years of experience in the oil and gas industry.
The gas reserves estimates are as follows:
168
Balance December 31, 2013 (a)
Revisions (b)
Price Changes
Extensions and Discoveries (c)
Production
Balance December 31, 2014 (a)
Revisions (d)
Price Changes
Extensions and Discoveries (e)
Production
Balance December 31, 2015 (a)
Revisions (f)
Price Changes
Extensions and Discoveries (g)
Production
Purchases of Reserves In-Place (h)
Sales of Reserves In-Place (h)
Balance December 31, 2016 (a)
Proved developed reserves (i):
December 31, 2014
December 31, 2015
December 31, 2016
Proved undeveloped reserves:
December 31, 2014
December 31, 2015
December 31, 2016
Natural Gas
(MMcf)
5,585,107
(46,560)
15,512
979,801
(216,260)
6,317,600
1,052,978
(2,866,123)
840,800
(285,041)
5,060,214
21,280
(179,914)
643,688
(358,474)
1,352,759
(711,155)
5,828,398
2,979,906
3,310,894
3,478,464
3,337,694
1,749,320
2,349,934
NGLs
(Mbbls)
21,546
40,363
—
18,459
(2,578)
77,790
45,993
(45,675)
13,916
(5,812)
86,212
(20,669)
(1,647)
10,960
(5,119)
13,177
(22,382)
60,532
32,405
59,196
30,666
45,385
27,016
29,866
Condensate
& Crude Oil
(Mbbls)
Consolidated
Operations
(MMcfe)
2,806
3,756
—
1,314
(664)
7,212
6,662
(3,208)
1,707
(1,458)
10,915
481
(35)
1,783
(867)
1,970
(4,240)
10,007
4,061
5,180
3,474
3,151
5,736
6,536
5,731,214
218,168
15,512
1,098,436
(235,714)
6,827,616
1,368,909
(3,159,421)
934,542
(328,657)
5,642,989
(99,849)
(190,009)
720,146
(394,387)
1,443,642
(870,884)
6,251,648
3,198,706
3,697,152
3,683,302
3,628,910
1,945,837
2,568,346
__________
(a)
Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally,
these reserves would be commercially recovered under current economic conditions, operating methods and government
regulations. CONSOL Energy cautions that there are many inherent uncertainties in estimating proved reserve quantities,
projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated
quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating conditions and government regulations. Proved
developed reserves are reserves expected to be recovered through existing wells, with existing equipment and operating
methods.
(b) Revisions for 2014 are primarily due to efficiencies in operations and well optimization and had the total effect of positive
revisions. Additionally, the 2014 revisions include a reclassification of ethane volumes from natural gas to NGLs.
(c) Extensions and Discoveries in 2014 are primarily due to the addition of wells on our Marcellus and Utica Shale acreage.
We also included Marcellus Shale wells which are more than one offset location away due to continued use of reliable
technology.
(d) The upward revisions in 2015 are attributable to efficiencies in operations and well performance.
(e) Extensions and Discoveries in 2015 are due mainly to the high grading of locations which resulted in the addition of wells
on our Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.
The net downward revisions for 2016 are primarily due to changes in plans related to future locations.
(f)
(g) Extensions and Discoveries in 2016 are due to the addition of wells on our Marcellus and Utica Shale acreage more than
one offset location away with continued use of reliable technology.
(h) Purchases and Sales of Reserves In-Place in 2016 is the result of our fourth quarter realignment of the Marcellus Shale
properties as part of dissolving our joint venture with Noble Energy.
169
(i)
Included in our proved developed reserves at December 31, 2016 are producing wells with negative undiscounted cash flows
that represent 199.3 Bcfe of natural gas and equivalents which represents 3.2% of our total reserves quantities. These consist
primarily of conventional wells and the company includes these wells in our reserves as we continue to produce the properties.
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves
Undeveloped reserves transferred to developed(a)
Disposition of reserves in place
Acquisition of reserves in place
Price Changes
Plan and other revisions (b)
Extension and discoveries (c)
Ending proved undeveloped reserves(d)(e)
For the Year
Ended
December 31,
2016
1,945,837
(211,876)
(199,401)
547,680
(188,066)
4,906
669,266
2,568,346
_________
(a) During 2016, various exploration and development drilling and evaluations were completed. Approximately, $58,694 of
capital was spent in the year ended December 31, 2016 related to undeveloped reserves that were transferred to developed.
(b) Plan and other revisions are due to high grading of locations. These changes along with upward revisions attributable to
(c)
(d)
(e)
efficiencies in operations and well performance had the total affect of a positive revision.
Extensions and discoveries are due mainly to the high grading of locations which resulted in the addition of wells on our
Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.
Included in proved undeveloped reserves at December 31, 2016 are approximately 215,861 MMcfe of reserves that have
been reported for more than five years. These reserves specifically relate to GOB (a rubble zone formed in the cavity created
by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined
seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the
Buchanan Mine that was sold in March 2016 to Coronado IV LLC (See Note 2 - Discontinued Operations for more information)
with the rights to this gas being retained by the Company. Evidence also exists that supports the continual operation of the
mine beyond the current plan, unless there was an extreme circumstance resulting from an external factor. These reasons
constitute the specific circumstances that exist to continue recognizing these reserves for CONSOL Energy.
Included in proved undeveloped reserves at December 31, 2016 are 175 gross proved undeveloped locations that generate
positive future net revenue but have negative present worth discounted at 10 percent as of December 31, 2016, representing
58.9% of our total proved undeveloped reserves. Additionally, the 1,511.8 Bcfe of natural gas and equivalents attributable
to these locations represent approximately 24.2% of our total proved reserves. The Company includes these well sites in its
current drilling plans and currently intends to drill these sites as our economic modeling of these well locations generate
positive future cash flows.
At December 31, 2016 there were no wells pending the determination of proved reserves.
The following table represents the capitalized exploratory well cost activity as indicated:
Costs reclassified to wells, equipment and facilities based on the
determination of proved reserves
Costs expensed due to determination of dry hole or abandonment of
project
$
$
40,917
$
17,179
$
27,453
— $
— $
2,041
CONSOL Energy's proved natural gas reserves are located in the United States.
2016
December 31,
2015
2014
170
Standardized Measure of Discounted Future Net Cash Flows:
The following information has been prepared in accordance with the provisions of the Financial Accounting Standards
Board's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the
standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year.
Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from
year to year based on the market conditions that occurred.
The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be
interpreted as representing current value to CONSOL Energy. Material revisions to estimates of proved reserves may occur in the
future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to
vary significantly from those used; and actual costs may vary. CONSOL Energy's investment and operating decisions are not based
on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on
different price and cost assumptions.
The standardized measure is intended to provide a better means for comparing the value of CONSOL Energy's proved
reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve
quantities.
Future Cash Flows (a)
Revenues
Production costs
Development costs
Income tax expense
Future Net Cash Flows
Discounted to present value at a 10% annual rate
Total standardized measure of discounted net cash flows
2016
December 31,
2015
2014
$ 11,303,409
(5,850,941)
(1,550,294)
(1,482,826)
2,419,348
(1,464,231)
955,117
$
$ 11,837,732
(6,584,947)
(1,220,010)
(1,532,454)
2,500,321
(1,481,017)
1,019,304
$
$ 28,502,852
(10,100,868)
(3,368,621)
(5,711,989)
9,321,374
(6,337,216)
2,984,158
$
(a)
For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each
month during 2016, adjusted for energy content and a regional price differential. For 2016, this adjusted natural gas price
was $1.73 per mcf, the adjusted oil price was $25.04 per barrel and the adjusted NGL price was $15.77 per barrel.
For 2015, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each
month during 2015, adjusted for energy content and a regional price differential. For 2015, this adjusted natural gas price
was $2.02 per mcf, the adjusted oil price was $25.29 per barrel and the adjusted NGL price was $15.59 per barrel.
For 2014, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each
month during 2014, adjusted for energy content and a regional price differential. For 2014, this adjusted natural gas price
was $3.85 per mcf, the adjusted oil price was $77.30 per barrel and the adjusted NGL price was $46.54 per barrel.
171
The following are the principal sources of change in the standardized measure of discounted future net cash flows for
consolidated operations during:
Balance at beginning of period
Net changes in sales prices and production costs
Sales net of production costs
Net change due to revisions in quantity estimates
Net change due to extensions, discoveries and improved recovery
Development costs incurred during the period
Difference in previously estimated development costs compared to actual
costs incurred during the period
$
Purchase of Reserves In-Place
Sales of Reserves In-Place
Changes in estimated future development costs
Net change in future income taxes
Accretion of discount and other
Total discounted cash flow at end of period
Supplemental Coal Data (unaudited)
2016
1,019,304
(172,812)
(150,819)
(35,502)
(54,628)
138,813
(39,821)
238,819
(137,998)
(158,000)
36,513
271,248
December 31,
2015
$
$
2,984,158
(4,151,684)
(589,533)
408,006
157,016
666,315
8,911
—
—
374,982
1,259,744
(98,611)
1,019,304
2014
1,680,811
517,731
(559,563)
151,233
418,775
952,733
(102,949)
—
—
595,221
(798,470)
128,636
$
955,117
$
$
2,984,158
Millions of Tons
For the Year Ended December 31,
2014
2013
2015
2012
2016
Proven and probable coal reserves at beginning of period
Purchased reserves
Reserves sold in place
Production
Revisions and other changes
Consolidated proven and probable coal reserves at end of period* (1)
3,047
—
(601)
(26)
(59)
2,361
3,238
24
(43)
(29)
(143)
3,047
3,032
4,229
4,314
—
(233)
(32)
471
1
(1,199)
(55)
56
—
(155)
(55)
125
3,238
3,032
4,229
Proportionate share of proven and probable coal reserves of unconsolidated
equity affiliates (excluded from the table above)*
______________
* Proven and probable coal reserves are the equivalent of “demonstrated reserves” under the coal resource classification system
of the U.S. Geological Survey. Generally, these reserves would be commercially mineable at year-end prices and cost levels, using
current technology and mining practices.
(1) 143.3 Million tons for the Mason Dixon Project are controlled by CCC, a former subsidiary of CONSOL Energy that was sold
in December 2013. As of filing, these tons are still controlled by CCC but are shown in CONSOL Energy's reserves due to a
binding agreement that these tons will be released to CONSOL Energy upon consent of the lessor.
57
—
55
41
—
CONSOL Energy's coal reserves are located in nearly every major coal-producing region in North America. Our estimate
of proven and probable coal reserves has been determined by CONSOL Energy. At December 31, 2016, 141 million tons were
assigned to mines either in production or temporarily idled. The proven and probable coal reserves at December 31, 2016 include
2,274 million tons of thermal coal reserves, of which approximately 2 percent has a sulfur content equivalent to less than 1.2
pounds sulfur dioxide per million British thermal unit (Btu), 8 percent has a sulfur content equivalent to between 1.2 and 2.5
pounds sulfur dioxide per million Btu, and 90 percent has a sulfur content equivalent to greater than 2.5 pounds sulfur dioxide per
million Btu. The reserves also include 87 million tons of metallurgical coal in consolidated reserves, of which approximately 24
percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu and 76 percent has a sulfur content
equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu.
172
Supplemental Quarterly Information (unaudited):
(Dollars in thousands, except per share data)
Sales (A)
Freight Revenue
Costs and Expenses (B)
Freight Expense
(Loss) Income from Continuing Operations
(Loss) Income from Discontinued Operations
Net (Loss) Income Attributable to CONSOL Energy
Shareholders
Earnings Per Share
Basic:
(Loss) Income from Continuing Operations
(Loss) Income from Discontinued Operations
Net (Loss) Income
Dilutive:
(Loss) Income from Continuing Operations
(Loss) Income from Discontinued Operations
Net (Loss) Income
Sales (A)
Freight Revenue
Costs and Expenses (B)
Freight Expense
Income (Loss) from Continuing Operations (C)
Income (Loss) from Discontinued Operations
Net Income (Loss) Attributable to CONSOL Energy
Shareholders
Earnings Per Share
Basic:
Income (Loss) from Continuing Operations
Income (Loss) from Discontinued Operations
Net Income (Loss)
Dilutive:
Income (Loss) from Continuing Operations
Income (Loss) from Discontinued Operations
Net Income (Loss)
Three Months Ended
March 31,
2016
June 30,
2016
September 30, December 31,
2016
2016
$
478,864
$
13,110
$
329,071
13,110
$
(43,291) $
(53,167) $
$
235,251
$
11,447
$
369,392
11,447
$
(234,044) $
(234,605) $
$
688,590
$
9,392
$
361,551
$
9,392
$
62,568
(34,975) $
390,398
12,519
415,224
12,519
(321,198)
19,564
(97,572) $
(469,828) $
25,345
$
(306,047)
(0.19) $
(0.24) $
(0.43) $
(0.19) $
(0.24) $
(0.43) $
(1.03) $
(1.02) $
(2.05) $
(1.03) $
(1.02) $
(2.05) $
0.26
$
(0.15) $
$
0.11
$
0.26
(0.15) $
$
0.11
(1.42)
0.09
(1.33)
(1.42)
0.09
(1.33)
Three Months Ended
March 31,
June 30,
September 30, December 31,
2015
2015
2015
2015
715,740
5,018
399,281
5,018
52,964
26,067
79,031
0.23
0.11
0.34
0.23
0.11
0.34
$
$
$
$
$
$
$
$
$
$
$
$
$
503,825
2,750
351,200
$
$
$
$
2,750
(577,884) $
(25,417) $
631,979
2,436
267,826
2,436
$
$
$
$
129,312
$
(3,842) $
602,772
10,295
243,267
10,295
45,342
(11,017)
(603,301) $
118,980
$
30,405
(2.52) $
(0.12) $
(2.64) $
(2.52) $
(0.12) $
(2.64) $
$
0.54
(0.02) $
$
0.52
0.54
$
(0.02) $
$
0.52
0.18
(0.05)
0.13
0.18
(0.05)
0.13
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(A) Includes natural gas, NGLs, and oil sales; gain (loss) on commodity derivative instruments; coal sales; other outside sales;
and purchased gas sales.
(B) Includes exploration and production costs, coal costs and miscellaneous operating expense, excluding DD&A, other corporate
expenses, selling, general and administrative, loss on debt extinguishment, interest expense and freight expense.
173
(C) Includes an impairment of $828,905 that was recorded during the three months ended June 30, 2015 related to CONSOL
Energy's exploration and production properties. The impairment primarily related to the write down of the Company's shallow oil
and gas asset values including impairments to unproved property. See Note 1 - Significant Accounting Policies in Item 8 of this
Form 10-K for additional information.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure controls and procedures. CONSOL Energy, under the supervision and with the participation of its management,
including CONSOL Energy’s principal executive officer and principal financial officer, evaluated the effectiveness of the
Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as
amended (the “Exchange Act”), as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation,
CONSOL Energy’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls
and procedures are effective as of December 31, 2016 to ensure that information required to be disclosed by CONSOL Energy in
reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods
specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that
information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s
management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate, to allow
timely decisions regarding required disclosure.
Management's Annual Report on Internal Control Over Financial Reporting. CONSOL Energy's management is
responsible for establishing and maintaining adequate internal control over financial reporting. CONSOL Energy's internal control
over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
CONSOL Energy's internal control over financial reporting includes policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide
reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations
of management and the directors of CONSOL Energy; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of CONSOL Energy's assets that could have a material effect on our
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of CONSOL Energy's internal control over financial reporting as of December 31,
2016. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework) (COSO) in Internal Control-Integrated Framework. Based on our assessment and those
criteria, management has concluded that CONSOL Energy maintained effective internal control over financial reporting as of
December 31, 2016.
The effectiveness of CONSOL Energy's internal control over financial reporting as of December 31, 2016 has been audited
by Ernst and Young, an independent registered public accounting firm, as stated in their report set forth in the Report of Independent
Registered Public Accounting Firm in Part II, Item 9A of this annual report on Form 10-K.
Changes in internal controls over financial reporting. There were no changes in the Company's internal controls over
financial reporting that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have
materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
174
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CONSOL Energy Inc. and Subsidiaries
We have audited CONSOL Energy Inc. and Subsidiaries' internal control over financial reporting as of December 31, 2016,
based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (2013 framework) (the COSO criteria). CONSOL Energy Inc. and Subsidiaries' management is
responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal
control over financial reporting included in the accompanying Management's Annual Report on Internal Control Over Financial
Reporting appearing under Item 9A. Our responsibility is to express an opinion on the Company's internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control
over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in
the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, CONSOL Energy Inc. and Subsidiaries maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries as of December 31, 2016 and 2015, and the related
consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the
period ended December 31, 2016 of CONSOL Energy Inc. and Subsidiaries and our report dated February 8, 2017 expressed an
unqualified opinion thereon.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 8, 2017
175
ITEM 9B.
OTHER INFORMATION
NONE
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item is incorporated herein by reference from the information under the captions
“PROPOSAL NO. 1-ELECTION OF DIRECTORS-Biographies of Nominees,” “BOARD OF DIRECTORS AND
COMPENSATION INFORMATION and “SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the
Proxy Statement for the annual meeting of shareholders to be held on May 9, 2017 (the “Proxy Statement”).
Executive Officers of CONSOL Energy
The following is a list, as of February 1, 2017, of CONSOL Energy executive officers, their ages and their positions and
offices held with CONSOL Energy.
Name
Nicholas J. DeIuliis
Stephen W. Johnson
David M. Khani
Timothy C. Dugan
James A. Brock
Age
48
58
53
55
60
Position
President and Chief Executive Officer
Executive Vice President - Chief Administrative Officer
Executive Vice President and Chief Financial Officer
Executive Vice President and Chief Operating Officer - Exploration and Production
Executive Vice President and Chief Operating Officer - Coal
Nicholas J. DeIuliis has been President of CONSOL Energy since February 23, 2011 and on May 7, 2014 he was named
CONSOL's Chief Executive Officer. Mr. DeIuliis previously served in various positions at CNX Gas Corporation, including
President, Chief Executive Officer and Chief Operating Officer. He is currently Chairman of the Board at CNX Gas Corporation.
He was Executive Vice President and Chief Operating Officer of CONSOL Energy from January 16, 2009 until February 23, 2011.
Prior to that time, he held the following positions at CONSOL Energy: Senior Vice President - Strategic Planning (November 1,
2004 to August 2005); Vice President Strategic Planning (April 1, 2002 to November 1, 2004); Director-Corporate Strategy
(October 1, 2001 to April 1, 2002); Manager-Strategic Planning (January 1, 2001 to October 2001); and Supervisor-Process
Engineering (April 1, 1999 to January 1, 2001). He was appointed a directer and elected Chairman of the Board of the general
partner of CNX Coal Resources, LP effective March 16, 2015.
Stephen W. Johnson has been Executive Vice President and Chief Administrative Officer of CONSOL Energy and CNX Gas
Corporation since April 13, 2015. From December 31, 2012 until April 13, 2015, he served as Executive Vice President and Chief
Legal and Corporate Affairs Officer of CONSOL Energy and CNX Gas Corporation. Prior to that time, Mr. Johnson served as
Senior Vice President and General Counsel of CONSOL Energy and CNX Gas Corporation from February 5, 2009 through
December 31, 2012. Prior to February 5, 2009, he served in the following positions with CNX Gas Corporation: General Counsel
(September 1, 2005 to December 2, 2005); Senior Vice President and General Counsel (December 2, 2005 to June 21, 2007); and
Executive Vice President, General Counsel and Secretary (June 21, 2007 to February 5, 2009). Effective May 30, 2014, Mr. Johnson
became a director of the general partnership of CONE Midstream Partners LP. He was appointed a director of the general partner
of CNX Coal Resources, LP effective March 16, 2015.
David M. Khani joined CONSOL Energy on September 1, 2011 as its Vice President - Finance, and was promoted to Executive
Vice President and Chief Financial Officer effective March 1, 2013. Prior to joining CONSOL Energy, Mr. Khani was with FBR
Capital Markets & Co. ("FBR"), an investment banking and advisory firm and held the following positions: Director of Research
from February 2007 through October 2010, and then Co-Director of Research from November 2010 through August 2011. Effective
May 30, 2014, Mr. Khani became a director and the Chief Financial Officer of the general partnership of CONE Midstream Partners
LP. He was appointed a director of the general partner of CNX Coal Resources, LP effective March 16, 2015.
Timothy C. Dugan has been Chief Operating Officer- Exploration & Production of CONSOL Energy since January 28, 2014.
On September 20, 2016 he was given the additional title of Executive Vice President. He was President and Chief Operating Office
of CNX Gas Corporation from May 22, 2014 to December 1, 2014, when he became President and Chief Executive Officer. Prior
to joining CONSOL Energy, Mr. Dugan was Vice President - Appalachia South Business Unit at Chesapeake Energy Corporation.
176
During his seven years with Chesapeake Energy, he held the titles of Senior Asset Manager, Operations Superintendent, Senior
Asset Manager and District Manager. From 2001 to 2007, Mr. Dugan was employed with EQT Corporation, where he held the
titles of Regional Reservoir Engineer and Director of Operations - Engineering.
James A. Brock has been Chief Operating Officer - Coal of CONSOL Energy since December 10, 2010. On September 20,
2016 he was given the additional title of Executive Vice President. Prior to this appointment, he served as Senior Vice President
- Northern Appalachia - West Virginia Operations of CONSOL Energy beginning December 3, 2007. From September 7, 2006
until December 3, 2007 he served as Vice President-Operations. Mr. Brock began his career with CONSOL Energy in 1979 at
the Matthews Mine and since then has served at various locations in many positions including Section Foreman, Mine Longwall
Coordinator, General Mine Foreman, and Superintendent. Mr. Brock was appointed the Chief Executive Officer and a director of
the general partner of CNX Coal Resources, LP effective March 16, 2015.
CONSOL Energy has a written Code of Business Conduct that applies to CONSOL Energy's Chief Executive Officer
(Principal Executive Officer), Chief Financial Officer (Principal Financial Officer) and others. The Code of Business Conduct is
available on CONSOL Energy's website at www.consolenergy.com. Any amendments to, or waivers from, a provision of our code
of employee business conduct and ethics that applies to our principal executive officer, our principal financial and accounting
officer and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 of Regulation S-K shall be
disclosed by posting such information on our website at www.consolenergy.com.
By certification dated June 8, 2016, CONSOL Energy's Chief Executive Officer certified to the New York Stock Exchange
(NYSE) that he was not aware of any violation by the Company of the NYSE corporate governance listing standards. In addition,
the required Sarbanes-Oxley Act, Section 302 certifications regarding the quality of our public disclosures were filed by CONSOL
Energy as exhibits to this Form 10-K.
ITEM 11.
EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from the information under the captions “BOARD OF
DIRECTORS AND COMPENSATION INFORMATION and “EXECUTIVE COMPENSATION INFORMATION” (excluding
the Compensation Committee Report) in the Proxy Statement.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by this Item is incorporated by reference from the information under the captions “BENEFICIAL
OWNERSHIP OF SECURITIES” and “SECURITIES AUTHORIZED FOR ISSUANCE UNDER CONSOL ENERGY EQUITY
COMPENSATION PLAN” in the Proxy Statement.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
The information requested by this Item is incorporated by reference from the information under the caption “PROPOSAL
NO. 1-ELECTION OF DIRECTORS - Related Party Policy and Procedures and PROPOSAL NO. 1 - ELECTION OF
DIRECTORS - Determination of Director Independence in the Proxy Statement.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated by reference from the information under the caption “ACCOUNTANTS
AND AUDIT COMMITTEE-INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in the Proxy Statement.
177
ITEM 15.
EXHIBIT INDEX
PART IV
In reviewing any agreements incorporated by reference in this Form 10-K or filed with this 10-K, please remember that
such agreements are included to provide information regarding their terms. They are not intended to be a source of financial,
business or operational information about CONSOL Energy or any of its subsidiaries or affiliates. The representations, warranties
and covenants contained in these agreements are made solely for purposes of the agreements and are made as of specific dates;
are solely for the benefit of the parties; may be subject to qualifications and limitations agreed upon by the parties in connection
with negotiating the terms of the agreements, including being made for the purpose of allocating contractual risk between the
parties instead of establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties
that differ from those applicable to investors or security holders. Investors and security holders should not rely on the representations,
warranties and covenants or any description thereof as characterizations of the actual state of facts or condition of CONSOL Energy
or any of its subsidiaries or affiliates or, in connection with acquisition agreements, of the assets to be acquired. Moreover,
information concerning the subject matter of the representations, warranties and covenants may change after the date of the
agreements. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they
were made or at any other time.
(A)(1)
(A)(2)
Financial Statements Contained in Item 8 hereof.
Financial Statement Schedule-Schedule II Valuation and qualifying accounts.
2.1
2.2
2.3
2.4
2.5
2.6
3.1
3.2
4.1
4.2
4.3
Asset Acquisition Agreement dated August 17, 2011 between CNX Gas Company LLC and Noble Energy, Inc.,
incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on August 18, 2011.
Joint Development Agreement by and among CNX Gas Company LLC and Noble Energy, Inc. dated as of September
30, 2011, incorporated by reference to Exhibit 2.2 to Form 10-Q (file no. 001-14901) for the quarter ended September
30, 2011, filed on October 31, 2011.
Stock Purchase Agreement, dated October 25, 2013, among CONSOL Energy Inc., Consolidation Coal Company,
Ohio Valley Resources, Inc., and, as to certain provisions of the Purchase Agreement, Murray Energy Corporation,
incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on December 11, 2013.
Membership Interest and Asset Purchase Agreement dated February 26, 2016 among CONSOL Energy Inc., CONSOL
Mining Holding Company LLC, CONSOL Buchanan Mining Company LLC, CONSOL Amonate Mining Company
LLC CONSOL Mining Company LLC, CNX Land LLC, CNX Marine Terminals Inc., CNX RCPC LLC, CONSOL
Pennsylvania Coal Company LLC and CONSOL Amonate Facility LLC and Coronado IV LLC which is incorporated
by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on February 29, 2016.
Exchange Agreement dated October 29, 2016, by and between CNX Gas Company LLC and Noble Energy, Inc.
including Appendix I (Definitions) thereto, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901)
filed on October 31, 2016.
First Amendment to Exchange Agreement dated as of December 1, 2016, by and between CNX Gas Company LLC
and Noble Energy, Inc. Exhibits and Schedules identified in the First Amendment to Exchange Agreement are not
being filed but will be furnished supplementally to the Securities and Exchange Commission upon request.
Restated Certificate of Incorporation of CONSOL Energy Inc., incorporated by reference to Exhibit 3.1 to Form 8-K
(file no. 001-14901) filed on May 8, 2006.
CONSOL Energy Inc. Bylaws (Amended and Restated on September 20, 2016), incorporated by reference to Exhibit
3.1 to Form 8-K (file no. 001-14901) filed on September 26, 2016.
Supplemental Indenture, dated as of April 30, 2010, among Dominion Exploration & Production, Inc., Dominion
Reserves, Inc., Dominion Coalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian
Development Properties, LLC, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as
trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.6 to Form 8-K/A
(file no. 001-14901) filed on August 6, 2010.
Supplemental Indenture No. 2, dated as of June 16, 2010, among Cardinal States Gathering Company, CNX Gas
Company LLC, CNX Gas Corporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation,
CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25%
Senior Notes due 2020, incorporated by reference to Exhibit 4.7 to Form 8-K/A (file no. 001-14901) filed on August
6, 2010.
Supplemental Indenture No. 3, dated as of August 24, 2011, to Indenture dated as of April 1, 2010 among CONSOL
Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York,
as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 to Form 8-K
(file no. 001-14901) filed on August 29, 2011.
178
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
10.1
10.2
Supplemental Indenture No. 4, dated as of September 10, 2013, to Indenture dated as of April 1, 2010, by and among
CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as
successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 8.25% Senior Notes
due 2020, incorporated by reference to Exhibit 4.2 of Form 10-Q (file no. 001-14901) filed on November 1, 2013.
Supplemental Indenture No. 5, dated as of March 23, 2015, to the Indenture dated as of April 1, 2010 by and among
CONSOL Energy Inc., the Subsidiary Guarantors listed on the signature pages thereof and Wells Fargo Bank, National
Association, a national banking association, as successor trustee, with respect to the 8.25% Senior Notes due 2020,
incorporated by reference to Exhibit 4.4 of Form 10-Q (file no. 001-14901) filed on May 5, 2015.
Indenture, dated as of March 9, 2011, among CONSOL Energy Inc., the Subsidiaries named therein and The Bank of
Nova Scotia Trust Company of New York, as trustee, with respect to the 6.375% Senior Notes due 2021, incorporated
by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on March 11, 2011.
Supplemental Indenture No. 1, dated as of August 24, 2011, to Indenture dated as of March 9, 2011 among CONSOL
Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York,
as trustee, with respect to the 6.375% Senior Notes due 2021, incorporated by reference to Exhibit 4.3 to Form 8-K
(file no. 001-14901) filed on August 29, 2011.
Supplemental Indenture No. 2, dated as of September 10, 2013, to Indenture dated as of March 9, 2011, by and among
CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as
successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 6.375 % Senior Notes
due 2021, incorporated by reference to Exhibit 4.3 of Form 10-Q (file no. 001-14901) filed on November 1, 2013.
Supplemental Indenture No. 3, dated as of March 23, 2015, to the Indenture dated as of March 9, 2011 by and among
CONSOL Energy Inc., the Subsidiary Guarantors listed on the signature pages thereof and Wells Fargo Bank, National
Association, a national banking association, as successor trustee, with respect to the 6.375% Senior Notes due 2021,
incorporated by reference to Exhibit 4.3 of Form 10-Q (file no. 001-14901) filed on May 5, 2015.
Indenture, dated as of April 16, 2014, among CONSOL Energy Inc., the Subsidiary Guarantors named therein and
Wells Fargo Bank, National Association, a national banking association, as trustee, with respect to the 5.875% Senior
Notes due 2022, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
Indenture, dated as of March 30, 2015, among CONSOL Energy Inc., the subsidiary guarantors party thereto and Well
Fargo, National Association, as Trustee, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901)
filed on March 30, 2015.
Registration Rights Agreement, dated as of April 16, 2014, by and among CONSOL Energy Inc., the guarantors
signatory thereto and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the
several initial purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on April
16, 2014.
Registration Rights Agreement, dated as of August 12, 2014, by and among CONSOL Energy Inc., the guarantors
signatory thereto and Goldman, Sachs & Co., as the initial purchasers, incorporated by reference to Exhibit 4.2 to
Form 8-K (file no. 001-14901) filed on August 12, 2014.
Registration Rights Agreement, dated as of March 30, 2015, among CONSOL Energy Inc., the subsidiary guarantors
party thereto and Goldman, Sachs & Co. as the initial purchaser named therein, incorporated by reference to Exhibit
4.2 to Form 8-K (file no. 001-14901) filed on March 30, 2015.
Agreement of Resignation, Appointment and Acceptance, dated July 22, 2013, by and among CONSOL Energy Inc.,
certain subsidiaries of CONSOL Energy Inc. signatory thereto, Wells Fargo Bank, National Association, as Successor
Trustee to The Bank of Nova Scotia Trust Company of New York, and The Bank of Nova Scotia Trust Company of
New York, as Resigning Trustee (related to the Indenture dated as of April 1, 2010 with respect to the 8.00% Senior
Notes due 2017, the Indenture dated as of April 1, 2010 with respect to the 8.25% Senior Notes due 2020, and the
Indenture dated as of March 9, 2011 with respect to the 6.375% Senior Notes due 2021), incorporated by reference
to Exhibit 4.4 of Form 10-Q (file no. 001-14901) filed on November 1, 2013.
Purchase and Sale Agreement, dated as of April 30, 2003, by and among CONSOL Energy Inc., CONSOL Sales
Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island
Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-
Four Mining Company, CNX Gas Company LLC, CNX Marine Terminals Inc. and CNX Funding Corporation,
incorporated by reference to Exhibit 10.30 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2003,
filed on August 13, 2003.
First Amendment to Purchase and Sale Agreement dated as of April 30, 2007, entered into among CONSOL Energy
Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company,
Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company,
Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals Inc., each an
“Originator” and CNX Funding Corporation, incorporated by reference to Exhibit 10.31 to Form 10-K for the year
ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
179
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
Second Amendment to Purchase and Sale Agreement dated as of November 16, 2007, entered into among CONSOL
Energy Inc. (“CONSOL Energy”), CONSOL Energy Sales Company, CONSOL of Kentucky Inc., Consol
Pennsylvania Coal Company LLC, Consolidation Coal Company, Island Creek Coal Company, McElroy Coal
Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals Inc. (each
an “Existing Originator”) and collectively the “Existing Originators”), Fola Coal Company, LLC., Little Eagle Coal
Company, LLC., Mon River Towing, Inc., Terry Eagle Coal Company, LLC., Tri-River Fleeting Harbor Service, Inc.,
and Twin Rivers Towing Company (each, a “New Originator” and collectively the “New Originators”; the Existing
Originators and the New Originators, each an “Originator” and collectively, the “Originators”), Windsor Coal Company
(the “Released Originator”) and CNX Funding Corporation, incorporated by reference to Exhibit 10.32 to Form 10-
K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
Third Amendment to the Purchase and Sale Agreement, dated as of March 12, 2010, among CNX Marine Terminals
Inc., CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania
Coal Company LLC, Consolidated Coal Company, Eighty-Four Mining Company, Fola Coal Company, L.L.C., Island
Creek Coal Company, Keystone Coal Mining Corporation, Little Eagle Coal Company, L.L.C., McElroy Coal
Company, Mon River Towing, Inc., Terry Eagle Coal Company, L.L.C., Twin Rivers Towing Company and CNX
Funding Corporation, incorporated by reference to Exhibit 10.6 to Form 8-K (file no. 001-14901) filed on March 16,
2010.
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.
Purchase and Sale Agreement dated July 19, 2016, among AMVEST West Virginia Coal, L.L.C., Braxton-Clay Land
& Mineral, Inc., Nicholas-Clay Land & Mineral, Inc., Peters Creek Mineral Services, Inc., Terry Eagle Limited
Partnership, Terry Eagle Coal Company, L.L.C., Fola Coal Company, L.L.C., Little Eagle Coal Company, L.L.C.,
and Vaughan Railroad Company and Southeastern Land, LLC, incorporated by reference to Exhibit 2.2 to Form 8-K
(file no. 001-14901) filed on July 25, 2016.
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.
Amended and Restated Receivable Purchase Agreement, dated as of April 30, 2007, by and among CNX Funding
Corporation, CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL
Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company,
McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company, CNX Marine Terminals
Inc., Market Street Funding LLC, Liberty Street Funding LLC, PNC Bank, National Association, and the Bank of
Nova Scotia, incorporated by reference to Exhibit 10.33 to Form 10-K for the year ended December 31, 2007 (file no.
001-14901), filed on February 19, 2008.
First Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 9, 2007, entered into
among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Conduit Purchasers listed on the
signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the
signature pages thereto and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by
reference to Exhibit 10.34 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on
February 19, 2008.
Second Amendment to Amended and Restated Receivables Purchase Agreement, dated as of July 27, 2007, entered
into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer (in such capacity, the “Servicer”),
the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto,
the LC Participants listed on the signature pages thereto and PNC Bank, National Association, as Administrator and
as LC Bank, incorporated by reference to Exhibit 10.35 to Form 10-K for the year ended December 31, 2007 (file no.
001-14901), filed on February 19, 2008.
Third Amendment to Amended and Restated Receivables Purchase Agreement, dated as of November 16, 2007, entered
into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various new sub-servicers
listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents
listed on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank, National
Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.36 to Form 10-K for the year
ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.
Fourth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 27, 2009, among
CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the
signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on
the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National
Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.4 to Form 8-K (file no.
001-14901) filed on March 16, 2010.
180
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
Fifth Amendment to Amended and Restated Receivables Purchase Agreement and Waiver, dated as of March 12,
2010, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers
listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents
listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National
Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.5 to Form 8-K (file no.
001-14901) filed on March 16, 2010.
Sixth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 23, 2010, among
CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the
signature pages of the Amendment, the Conduit Purchasers listed on the signature pages of the Amendment, the
Purchaser Agents listed on the signature pages of the Amendment, the LC Participants listed on the signature pages
of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference
to Exhibit 10.13 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February 10, 2011.
Seventh Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 30, 2012, among
CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the
signature pages of the Amendment, the Conduit Purchasers listed on the signature pages of the Amendment, the
Purchaser Agents listed on the signature pages of the Amendment, the LC Participants listed on the signature pages
of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference
to Exhibit 10.5 to Form 10-Q for the quarter ended March 31, 2012 (file no. 001-14901), filed on April 30, 2012.
Eighth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of November 8, 2012, by
and among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the
signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on
the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National
Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no.
001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
Ninth Amendment to Amended and Restated Receivables Purchase Agreement, dated September 23, 2013, by and
among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the
signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on
the signature pages thereto, the LC Participants listed on the signature pages thereto, Market Street Funding LLC, as
Assignor, and PNC Bank, National Association, as Administrator, as LC Bank and as Assignee, incorporated by
reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2013, filed on
November 1, 2013.
Tenth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 28, 2014, by and
among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed
on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents
listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National
Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no.
001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
Eleventh Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 23, 2014, by and
among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed
on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents
listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National
Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no.
001-14901) filed on May 5, 2015.
Twelfth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 27, 2015, by and
among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed
on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents
listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National
Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.3 of Form 10-Q (file no.
001-14901) filed on May 5, 2015..
Letter Agreement re: Receivables Purchase Agreement - Dilution Ratio, dated June 21, 2012, incorporated by reference
to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2012 (file no. 001-14901), filed on August 1, 2012.
Letter Agreement Re: Receivables Purchase Agreement - Delinquency Ratio and Default Ratio, dated April 18, 2014,
incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) filed on May 5, 2015.
Payoff and Termination Letter re: Amended and Restated Receivables Purchase Agreement, dated as of July 7, 2015,
by and among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the Servicer, the Sub-Servicers listed
on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents
listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National
Association, as Administrator, and as LC Bank, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no.
001-14901) filed on July 31, 2015.
181
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
10.37
Amended and Restated Credit Agreement, dated as of April 12, 2011, by and among CONSOL Energy Inc., the
Guarantors Party thereto, the Lenders Party thereto, PNC Bank, National Association, as the Administrative Agent,
Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and
Sovereign Bank, as the Co-Documentation Agents, and PNC Capital Markets LLC and Merrill Lynch, Pierce, Fenner
& Smith Incorporated, as Joint Lead Arrangers, incorporated by reference to Exhibit 10.1 to Form 8-K (file no.
001-14901) filed on April 18, 2011.
Amendment No. 1 to Credit Agreement, dated as of December 5, 2013, to the Amended and Restated Credit Agreement,
dated as of April 12, 2011, by and among CONSOL Energy Inc., the lenders and agents party thereto and PNC Bank,
National Association, as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no.
001-14901) filed on December 11, 2013.
Amended and Restated Credit Agreement, dated as of June 18, 2014, by and among CONSOL Energy Inc., the lenders
and agents party thereto and PNC Bank, National Association, as administrative agent, incorporated by reference to
Exhibit 10.1 to Form 8-K/A (file no. 001-14901) filed on June 25, 2014.
Amendment No. 1, dated as of May 22, 2015, to the Amended and Restated Credit Agreement, dated as of June 18,
2014, by and among CONSOL Energy Inc., the subsidiary guarantors party thereto and certain lenders and PNC Bank,
National Association as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no.
001-14901) filed on May 26, 2015.
Amendment No. 2, dated as of April 20, 2016, to the Amended and Restated Credit Agreement, dated as of June 18,
2014, and the Amended and Restated Security Agreement, dated as of June 18, 2014, by and among CONSOL Energy
Inc., the subsidiary guarantors party thereto, certain lenders and PNC Bank, National Association as administrative
agent and as collateral agent, incorporated by reference to Exhibit 10.1 to the Form 8-K (file no. 001-14901) filed on
April 26, 2016.
Resignation, Consent and Appointment Agreement entered into as of September 12, 2016, by and among Bank of
America, N.A., as the resigning Syndication Agent under that certain Amended and Restated Credit Agreement, dated
as of June 18, 2014, JPMorgan Chase Bank, N.A., as the successor Syndication Agent, and CONSOL Energy Inc., a
Delaware corporation, as the Borrower, incorporated by reference to Exhibit 10.3 to the Form 10-Q (file no. 001-14901)
for the quarter ended September 30, 2016, filed on November 1, 2016.
Amended and Restated Collateral Trust Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc.
and its Designated Subsidiaries, Wilmington Trust Company, as Corporate Trustee and David A. Vanaskey, as
Individual Trustee, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on May 13, 2010.
Amended and Restated Pledge Agreement, dated as of May 7, 2010, made and entered into by each of the pledgors
listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time
by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference
to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on May 13, 2010.
Amended and Restated Security Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc., each of
the parties listed on the signature pages thereto and each other persons and entities that become bound thereto from
time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated
by reference to Exhibit 2.4 to Form 8-K (file no. 001-14901) filed on May 13, 2010.
Patent, Trademark and Copyright Security Agreement, dated as of June 27, 2007, by and among each of the pledgors
listed on the signature pages thereto and each of the other persons and entities that become bound thereby from time
to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by
reference to Exhibit 10.20 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February
10, 2011.
First Amendment to Amended and Restated Patent, Trademark and Copyright Security Agreement, dated as of May
7, 2010, by and among each of the pledgors listed on the signature pages thereto and each other persons and entities
that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company,
as Collateral Trustee, incorporated by reference to Exhibit 2.5 to Form 8-K (file no. 001-14901) filed on May 13,
2010.
Patent, Trademark and Copyright Assignment and Assumption, dated as of April 12, 2011, between Wilmington Trust
Company as assignor and PNC Bank, National Association as assignee, incorporated by reference to Exhibit 2.1 to
Form 8-K (file no. 001-14901) filed on April 18, 2011.
Guaranty and Suretyship Agreement, dated as of April 30, 2003, by CONSOL Energy Inc., as guarantor in favor of
CNX Funding Corporation, incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter
ended March 31, 2011, filed on May 3, 2011.
Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of May 7, 2010, jointly and
severally given by each of the undersigned thereto and each of the other persons which become Guarantors thereunder
from time to time in favor of PNC Bank, National Association, in its capacity as the administrative agent for the
Lenders, in connection with that certain Amended and Restated Credit Agreement, as defined therein, incorporated
by reference to Exhibit 10.22 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on
February 10, 2011.
182
10.38
10.39
10.40
10.41
10.42
10.43
10.44
10.45
10.46
10.47
10.48
10.49
10.50
10.51
10.52
CNX Gas Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, by CNX Gas Corporation
and certain of its subsidiaries, incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on
April 18, 2011.
Successor Agent Agreement, dated as of April 12, 2011, by and among among Wilmington Trust Company and David
A. Varansky as existing agents, PNC Bank, National Association as Collateral Trustee and CONSOL Energy Inc. and
certain of its subsidiaries, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on April
18, 2011.
Amended and Restated Credit Agreement, dated as of April 12, 2011, by and among CNX Gas Corporation, the
Guarantors Party thereto, the Lenders Party thereto, PNC Bank, National Association, as the Administrative Agent,
Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and
Wells Fargo Bank, N.A., as the Co-Documentation Agents, and PNC Capital Markets LLC and Merrill Lynch, Pierce,
Fenner & Smith Incorporated, as Bookrunners and Joint Lead Arrangers, incorporated by reference to Exhibit 10.3
to Form 8-K (file no. 001-14901) filed on April 18, 2011.
Amendment No. 1 to Credit Agreement, dated as of December 14, 2011, by and among CNX Gas Corporation, the
lenders and agents party thereto and PNC Bank, National Association, as Administrative Agent, incorporated by
reference to Exhibit 10.29 to Form 10-K for the year ended December 31, 2012 (file no. 01-14901), filed on February
7, 2013.
Amendment No. 2 to Credit Agreement, dated as of March 12, 2013, to the Amended and Restated Credit Agreement,
dated as of April 12, 2011, as amended by Amendment No. 1, dated December 14, 2011, by and among CNX Gas
Corporation, the lenders and agents party thereto and PNC Bank, National Association, as administrative agent,
incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013,
filed on May 7, 2013.
Collateral Trust Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation, its Designated Subsidiaries,
Wilmington Trust Company, as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by
reference to Exhibit 2.1 to the CNX Gas Corporation Form 8-K (file no. 001-32723) filed on May 13, 2010.
Pledge Agreement, dated as of May 7, 2010, by each of the pledgors listed on the signature pages thereto and each of
the other persons and entities that become bound thereby from time to time by joinder, assumption or otherwise and
Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.2 to the CNX Gas Corporation
Form 8-K (file no. 001-32723) filed on May 13, 2010.
Security Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation and each of the undersigned
parties thereto and each of the other persons and entities that become bound thereby from time to time by joinder,
assumption or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit
2.3 to the CNX Gas Corporation Form 8-K (file no. 001-32723) filed on May 13, 2010.
CONSOL Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, by
CONSOL Energy and certain of its subsidiaries, incorporated by reference to Exhibit 10.4 to Form 8-K (file no.
001-14901) filed on April 18, 2011.
Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, among CNX
Gas Company LLC and certain of its subsidiaries, incorporated by reference to Exhibit 10.5 to Form 8-K (file no.
001-14901) filed on April 18, 2011.
Successor Agent Agreement, dated as of April 12, 2011, by and among Wilmington Trust Company and David A.
Vanaskey as existing agents, PNC Bank, National Association as Collateral Trustee and CNX Gas Corporation and
certain of its subsidiaries, incorporated by reference to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on April
18, 2011.
Closing Agreement by and between CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011,
incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended September 30,
2011, filed on October 31, 2011.
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.
Amendment No. 1, dated April 19, 2013, to the Asset Acquisition Agreement, dated August 17, 2011, between CNX
Gas Company LLC and Noble Energy, Inc, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no. 001-14901)
for the quarter ended June 30, 2013, filed on August 5, 2013.
Purchase Agreement, dated as of April 10, 2014, among CONSOL Energy Inc., the subsidiary guarantors party thereto
and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the several initial
purchasers named therein, incorporated by reference to Exhibit 1.1 to Form 8-K (file no. 001-14901) filed on April
16, 2014.
10.53* Amended and Restated Employment Agreement, dated March 21, 2014, between CONSOL Energy Inc. and J. Brett
Harvey incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 26, 2014.
10.54*
Letter Agreement, dated August 24, 2007, by and between CONSOL Energy Inc. and Nicholas J. DeIuliis, incorporated
by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on August 24, 2007.
183
10.55* Change in Control Agreement by and between CONSOL Energy Inc. and Nicholas J. DeIuliis, incorporated by
reference to Exhibit 10.7 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on
February 17, 2009.
10.56* Amended and Restated Change in Control Severance Agreement, dated as of April 10, 2014, between CONSOL
Energy Inc. and David M. Khani, incorporated by reference to Exhibit 10.8 to Form 10-Q (file no. 001-14901) for
the quarter ended March 31, 2014, filed on May 6, 2014.
10.57* Amended and Restated Change in Control Severance Agreement, dated as of October 9, 2015, between CONSOL
Energy Inc., and David M. Khani, incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for
the quarter ended September 30, 2015, filed on November 3, 2015.
10.58* Amended and Restated Change in Control Severance Agreement, dated as of April 10, 2014, between CONSOL
Energy Inc. and James Grech, incorporated by reference to Exhibit 10.9 to Form 10-Q (file no. 001-14901) for the
quarter ended March 31, 2014, filed on May 6, 2014.
10.59* Change in Control Agreement by and among CNX Gas Corporation, CONSOL Energy Inc. and Stephen W. Johnson,
incorporated by reference to Exhibit 10.4 to Form 10-K for the year ended December 31, 2008 of CNX Gas Corporation
(file no. 001-32723) filed on February 17, 2009.
10.60* Amended and Restated Change in Control Severance Agreement, dated as of August 24, 2015, between CONSOL
Energy Inc., and James A. Brock, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for
the quarter ended September 30, 2015, filed on November 3, 2015
10.61* Amended and Restated Change in Control Severance Agreement, dated as of February 7, 2017, between CNX Coal
Resources GP LLC, and James A. Brock.
10.62* Amended and Restated Change in Control Severance Agreement, dated as of August 24, 2015, between CONSOL
Energy Inc., and Timothy Dugan, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for
the quarter ended September 30, 2015, filed on November 3, 2015.
10.63* Agreement, dated as of April 28, 2016, between CONSOL Energy Inc. and James C. Grech, incorporated by reference
to Exhibit 10.1 to the Form 8-K (file no. 001-14901) filed on May 4, 2016.
10.64*
10.65*
Form of Indemnification Agreement for Directors and Executive Officers of CONSOL Energy Inc., incorporated by
reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3,
2009.
Form of Indemnification Agreement for Directors and Executive Officers of CNX Gas Corporation, incorporated by
reference to Exhibit 10.7 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3,
2009.
10.66* CONSOL Energy Inc. Equity Incentive Plan, as amended and restated effective May 11, 2016, incorporated by
reference to Exhibit 99.1 to the Form S-8 (file no. 333-211286) filed on May 4, 2016.
10.67* Amended and Restated CONSOL Energy Inc. Executive Annual Incentive Plan, incorporated by reference to Appendix
A to the Form DEF 14A (file no. 001-14901) filed on March 29, 2013.
10.68*
10.69*
10.70*
10.71*
10.72*
10.73*
10.74*
10.75*
10.76*
10.77*
10.78*
10.79*
Form of Non-Qualified Stock Option Award Agreement For Employees, incorporated by reference to Exhibit 10.26
to the Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.
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 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 the
Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.
Form of Restricted Stock Unit Award Agreement for Employees (for 2015 awards), incorporated by reference to
Exhibit 10.67 to Form 10-K for the year ended December 31, 2014 (file no. 001-14901), filed on February 6, 2015.
Form of Restricted Stock Unit Award Agreement for Employees (With Deferral Election) (for 2017 awards).
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 for the year ended December 31, 2014 (file no. 001-14901), filed on February 6, 2015.
184
10.80*
10.81*
10.82*
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).
Summary of Non-Employee Director Compensation, incorporated by reference to Exhibit 10.69 to Form 10-K (file
no. 001-14901) for the year ended December 31, 2013, filed on February 7, 2014.
10.83* Directors Deferred Compensation Plan (1999 Plan), incorporated by reference to Exhibit 10.1 to Form 10-Q (file no.
001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.84* Directors' Deferred Fee Plan (2004 Plan) (Amended and Restated on December 4, 2007), incorporated by reference
to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.86*
10.85* Hypothetical Investment Election Form Relating to Directors' Deferred Fee Plan (2004 Plan), incorporated by reference
to Exhibit 10.50 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19,
2008.
Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.95 to the Form 8-K
(file no. 001-14901) filed on May 8, 2006.
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.
10.87*
10.88*
10.89* Amended and Restated Retirement Restoration Plan of CONSOL Energy Inc., incorporated reference to Exhibit 10.30
to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
10.90* Amended and Restated Supplemental Retirement Plan of CONSOL Energy Inc. effective January 1, 2007, as amended
and restated on September 8, 2009, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed
on September 11, 2009.
10.91* Amendment to CONSOL Energy Inc. Supplemental Retirement Plan, dated as of October 17, 2011, incorporated by
reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901), for the quarter ended September 30, 2011, filed on
October 31, 2011.
10.92* CONSOL Energy Inc. Defined Contribution Restoration Plan, effective January 1, 2012, incorporated by reference
to Exhibit 10.12 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.93*
Executive Compensation Clawback Policy of CONSOL Energy Inc., dated as of January 28, 2014, incorporated by
reference to Exhibit 10.11 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6,
2014.
12
14.1
21
23.1
23.2
31.1
31.2
32.1
32.2
95
99
101
Computation of Ratio of Earnings to Fixed Charges.
Code of Employee Business Conduct and Ethics
Subsidiaries of CONSOL Energy Inc.
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
Mine Safety Disclosure Exhibit
Engineers' Audit Letter
Interactive Data File (Form 10-K for the year ended December 31, 2016 furnished in XBRL).
* Denotes the management contracts and compensatory arrangements in which any director or any named executive officer
participates
Supplemental Information
No annual report or proxy material has been sent to shareholders of CONSOL Energy at the time of filing of this Form 10-
K. An annual report will be sent to shareholders and to the commission subsequent to the filing of this Form 10-K.
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.
185
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized, as of the 8th day of February, 2017.
SIGNATURES
CONSOL ENERGY INC.
By:
/s/ NICHOLAS J. DEIULIIS
Nicholas J. DeIuliis
Director, Chief Executive Officer and President
(Duly Authorized Officer and Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 8th day of
February, 2017, by the following persons on behalf of the registrant in the capacities indicated:
Signature
Title
/s/ NICHOLAS J. DEIULIIS
Director, Chief Executive Officer and President
Nicholas J. DeIuliis
(Duly Authorized Officer and Principal Executive Officer)
/s/ DAVID M. KHANI
Chief Financial Officer and Executive Vice President
David M. Khani
(Duly Authorized Officer and Principal Financial Officer)
/s/ C. KRISTOPHER HAGEDORN
Controller and Vice President
C. Kristopher Hagedorn
(Duly Authorized Officer and Principal Accounting Officer)
/s/ WILLIAM N. THORNDIKE
Director and Chairman of the Board
William N. Thorndike
/s/ ALVIN R. CARPENTER
Director
Alvin R. Carpenter
/s/ WILLIAM E. DAVIS
Director
William E. Davis
/s/ MAUREEN E. LALLY-GREEN
Director
Maureen E. Lally-Green
/s/ GREGORY A. LANHAM
Director
Gregory A. Lanham
/s/ BERNARD LANIGAN JR.
Bernard Lanigan Jr.
Director
/s/ JOHN T. MILLS
Director
John T. Mills
/s/ JOSEPH P. PLATT
Joseph P. Platt
Director
/s/ WILLIAM P. POWELL
Director
William P. Powell
/s/ EDWIN S. ROBERSON
Edwin S. Roberson
Director
186
SCHEDULE II
CONSOL ENERGY INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(Dollars in thousands)
Additions
Deductions
Balance at
Beginning Charged to Valuation Charged to
of Period
Allowance
Release of
Expense
Expense
Balance at
End
of Period
Year Ended December 31, 2016
State operating loss carry-forwards
Deferred deductible temporary differences
Charitable Contributions
AMT Credit
Foreign Tax Credits
Total
Year Ended December 31, 2015
$
$
42,983
9,420
—
—
25,903
78,306
$
$
17,505
1,170
5,052
166,798
13,947
204,472
$
$
— $
—
—
—
—
— $
60,488
— $
10,590
—
5,052
—
166,798
—
—
39,850
— $ 282,778
State operating loss carry-forwards
$
6,080
$
31,578
$
5,325
$
— $
42,983
Deferred deductible temporary differences
Foreign Tax Credits
Total
16
—
7,914
25,903
1,490
—
—
—
9,420
25,903
$
6,096
$
65,395
$
6,815
$
— $
78,306
Year Ended December 31, 2014
State operating loss carry-forwards
Deferred deductible temporary differences
Total
$
$
7,527
5
7,532
$
$
157
11
168
$
$
(1,323) $
—
(1,323) $
(281) $
—
(281) $
6,080
16
6,096
187
CONSOL Energy Inc.
CONSOL Energy Inc. (NYSE: CNX) is a Pittsburgh-based energy producer, and one of the largest independent natural gas
exploration, development and production companies, with operations centered in the major shale formations of the
Appalachian basin. The company deploys an organic growth strategy focused on developing its substantial resource base. As
of December 31, 2016, CONSOL Energy had 6.3 trillion cubic feet equivalent of proved natural gas reserves. CONSOL
Energy is a member of the Standard & Poor's Midcap 400 Index. Additional information may be found at
www.consolenergy.com.
Headquarters
CONSOL Energy Inc.
CNX Center
1000 CONSOL Energy Drive
Canonsburg, PA 15317
Website
http://www.consolenergy.com
Transfer Agent and Registrar
Computershare
P.O. Box 30170
College Station, TX 77842-3170
This Annual Report of CONSOL Energy Inc. is being delivered to the shareholders of CONSOL Energy to comply with the
annual report delivery requirements of the New York Stock Exchange and Rule 14a-3 of the Securities Exchange Act of
1934. All information required by those applicable rules is contained in this Annual Report, including certain information
contained in the Form 10-K included herein, which has previously been filed by CONSOL Energy with the Securities and
Exchange Commission.
CONSOL Energy may also provide a summary annual report to its shareholders. Any such summary annual report is not
meant to replace this Annual Report or satisfy the applicable rules of the New York Stock Exchange or Securities and
Exchange Commission, but is meant only to provide shareholders with a summary of information concerning CONSOL
Energy that has been previously disseminated to the public.