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  • 10-K (Feb 5, 2016)
  • 10-K (Feb 6, 2015)
  • 10-K (Feb 7, 2014)
  • 10-K (Feb 8, 2013)
  • 10-K (Feb 7, 2013)

 
Quarterly Reports

 
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CNX Resources Corp 10-K 2017
Document


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 __________________________________________________
FORM 10-K
  __________________________________________________ 
(Mark One)
x
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
o
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
 
51-0337383
(State or other jurisdiction of
incorporation or organization)
 
(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
 
 
 
Name of exchange on which registered
Common Stock ($.01 par value)
 
 
 
New York Stock Exchange
Preferred Share Purchase Rights
 
 
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
__________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  x    No  o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  o    No  x
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x    No  o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  x    No   o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  x    Accelerated filer  o    Non-accelerated filer  o    Smaller Reporting Company  o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  o    No  x
The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 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

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


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:

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



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



PART I

ITEM 1.
Business

General

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;
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
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:
a20170206ir2.jpg
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
 
 
Marcellus
 
Utica
 
CBM
 
Other Gas
 
 
 
 
Segment
 
Segment
 
Segment
 
Segment
 
Total
Estimated Net Proved Reserves (MMcfe)
 
3,137,336

 
1,371,978

 
1,254,633

 
487,701

 
6,251,648

Percent Developed
 
60
%
 
28
%
 
75
%
 
100
%
 
59
%
Net Producing Wells (including oil and gob wells)
 
283

 
54

 
4,359

 
8,180

 
12,876

Net Acreage Position:
 
 
 
 
 
 
 
 
 
 
Net Proved Developed Acres
 
30,737

 
9,649

 
257,019

 
243,877

 
541,282

Net Proved Undeveloped Acres
 
11,763

 
12,836

 
5,439

 

 
30,038

Net Unproved Acres(1)
 
370,263

 
355,332

 
1,900,260

 
1,119,678

 
3,745,533

     Total Net Acres(2)
 
412,763

 
377,817

 
2,162,718

 
1,363,555

 
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:
 
 
Gross
 
Net(1)
Producing Gas Wells (including gob wells)
 
17,314

 
12,846

Producing Oil Wells
 
189

 
30

Net Acreage Position:
 
 
 
 
Proved Developed Acreage
 
549,816

 
541,282

Proved Undeveloped Acreage
 
34,467

 
30,038

Unproved Acreage
 
4,804,804

 
3,745,533

     Total Acreage
 
5,389,087

 
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:    
 
 
Net Unproved Acres
 
Net Proved Undeveloped Acres
Held by production/fee
 
3,644,799

 
13,967

Expiration within 2 years
 
68,084

 
9,347

Expiration beyond 2 years
 
32,650

 
6,724

    Total Acreage
 
3,745,533

 
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
Marcellus segment
 

 
44.0

 
84.0

Utica segment
 
13.0

 
15.8

 
18.8

CBM segment
 
23.0

 
73.0

 
75.0

Other Gas segment
 

 

 
2.5

     Total Development Wells (Net)
 
36.0

 
132.8

 
180.3








10



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.
Marcellus segment
 

 

 

 

 

 

 
1.5

 

 

Utica segment
 

 

 

 
2.5

 

 

 
1.0

 

 

CBM segment
 

 

 

 

 

 

 

 

 

Other Gas segment
 

 

 

 

 

 

 
6.0



 

     Total Exploratory Wells (Net)
 

 

 

 
2.5

 

 

 
8.5

 

 


Reserves

The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the Securities and Exchange Commission (SEC).
 
 
Net Reserves
 
 
(Million cubic feet equivalent)
 
 
as of December 31,
 
 
2016
 
2015
 
2014
Proved developed reserves
 
3,683,302

 
3,697,152

 
3,198,706

Proved undeveloped reserves
 
2,568,346

 
1,945,837

 
3,628,910

Total proved developed and undeveloped reserves(1)
 
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)
 
 
2016
 
2015
 
2014
Future net cash flows
 
$
2,419

 
$
2,499

 
$
9,321

Total PV-10 measure of pre-tax discounted future net cash flows (1)
 
$
1,559

 
$
1,659

 
$
4,884

Total standardized measure of after tax discounted future net cash flows
 
$
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
 
 
As of December 31,
 
 
2016
 
2015
 
2014
 
 
(Dollars in millions)
Future cash inflows
 
$
11,303

 
$
11,838

 
$
28,503

Future production costs
 
(5,851
)
 
(6,585
)
 
(10,101
)
Future development costs (including abandonments)
 
(1,550
)
 
(1,220
)
 
(3,369
)
Future net cash flows (pre-tax)
 
3,902

 
4,033

 
15,033

10% discount factor
 
(2,343
)
 
(2,374
)
 
(10,149
)
PV-10 (Non-GAAP measure)
 
1,559

 
1,659

 
4,884

Undiscounted income taxes
 
(1,483
)
 
(1,534
)
 
(5,712
)
10% discount factor
 
879

 
894

 
3,812

Discounted income taxes
 
(604
)
 
(640
)
 
(1,900
)
Standardized GAAP measure
 
$
955

 
$
1,019

 
$
2,984


Gas Production

The following table sets forth net sales volumes produced for the periods indicated:
 
 
For the Year
 
 
Ended December 31,
 
 
2016
 
2015
 
2014
GAS
 
 
 
 
 
 
Marcellus Sales Volumes (MMcf)
 
186,812

 
145,747

 
99,370

Utica Sales Volumes (MMcf)
 
71,277

 
38,344

 
10,303

CBM Sales Volumes (MMcf)
 
68,971

 
74,910

 
79,459

Other Sales Volumes (MMcf)
 
21,693

 
28,286

 
27,128

LIQUIDS*
 
 
 
 
 
 
NGLs Sales Volumes (MMcfe)
 
40,260

 
33,180

 
15,475

Oil Sales Volumes (MMcfe)
 
410

 
592

 
681

Condensate Sales Volumes (MMcfe)
 
4,964

 
7,598

 
3,298

TOTAL (MMcfe)
 
394,387

 
328,657

 
235,714

*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



 
 
For the Year
 
 
Ended December 31,
 
 
2016
 
2015
 
2014
Average Sales Price - Gas (Mcf)
 
$
1.92

 
$
2.17

 
$
4.02

Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
 
$
0.70

 
$
0.68

 
$
0.11

Average Sales Price - NGLs (Mcfe)*
 
$
2.42

 
$
2.05

 
$
5.95

Average Sales Price - Oil (Mcfe)*
 
$
6.15

 
$
7.99

 
$
14.85

Average Sales Price - Condensate (Mcfe)*
 
$
4.58

 
$
4.42

 
$
11.16

 
 
 
 
 
 
 
Total Average Sales Price (per Mcfe)
 
$
2.63

 
$
2.81

 
$
4.37

Average Lifting Costs excluding ad valorem and severance taxes (per Mcfe)
 
$
0.24

 
$
0.37

 
$
0.59

*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.
CONSOL ENERGY MINING COMPLEXES
 
Proven and Probable Assigned and Accessible Coal Reserves as of December 31, 2016 and 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recoverable
 
 
 
 
 
 
 
 
 
Average
 
As Received Heat
 
Reserves(2)
 
 
 
Preparation
 
 
 
 
 
Seam
 
Value(1)
 
 
 
 
 
Tons in
 
 
 
Facility
 
Reserve
 
Coal
 
Thickness
 
(Btu/lb)
 
Owned
 
Leased
 
Millions
 
Mine/Reserve
 
Location
 
Class
 
Seam
 
(feet)
 
Typical
 
Range
 
(%)
 
(%)
 
12/31/2016
 
12/31/2015
 
ASSIGNED–OPERATING
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PA Mining Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bailey
 
Enon, PA
 
Assigned Operating
 
Pittsburgh
 
7.5
 
12,950
 
12,860 – 13,030
 
43%
 
57%
 
89.0

 
101.1

 
 
 
 
 
Accessible
 
Pittsburgh
 
7.5
 
12,910
 
12,700 – 13,170
 
78%
 
22%
 
170.7

 
170.7

 
Harvey
 
Enon, PA
 
Assigned Operating
 
Pittsburgh
 
6.3
 
13,040
 
12,920 – 13,160
 
86%
 
14%
 
20.4

 
23.4

 
 
 
 
 
Accessible
 
Pittsburgh
 
7.6
 
12,900
 
12,840 – 13,130
 
99%
 
1%
 
180.1

 
180.1

 
Enlow Fork
 
Enon, PA
 
Assigned Operating
 
Pittsburgh
 
7.8
 
12,980
 
12,820 – 13,190
 
99%
 
1%
 
31.2

 
10.9

 
 
 
 
 
Accessible
 
Pittsburgh
 
7.6
 
13,040
 
12,780 – 13,180
 
76%
 
24%
 
275.3

 
305.3

 
Total Assigned Operating and Accessible
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
766.7

 
791.5

 


16



_____________
(1)
The heat values shown for Assigned Operating reserves are based on the 2016 actual quality and five-year forecasted quality for each mine/reserve, assuming that the coal is washed to an extent consistent with normal full-capacity operation of the complex's preparation plant. Actual quality is based on laboratory analysis of samples collected from coal shipments delivered in 2016. Forecasted quality is derived from exploration sample analysis results, which have been adjusted to account for anticipated moisture and for the effects of mining and coal preparation. The heat values shown for Accessible Reserves are based on as received, dry values obtained from drill hole analyses, adjusted for moisture, and prorated by the associated Assigned Operating product values to account for similar mining and processing methods.
(2)
Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserves tons are reported on an as-received basis, based on the anticipated product moisture. Reserves are reported only for those coal seams that are controlled by ownership or leases.

The following table sets forth our unassigned proven and probable coal reserves by region:
CONSOL Energy UNASSIGNED Recoverable Coal Reserves as of December 31, 2016 and 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recoverable
 
 
 
 
Recoverable Reserves(2)
 
Reserves
 
 
 
 
 
 
 
 
Tons in
 
(Tons in
 
 
As Received Heat
 
Owned
 
Leased
 
Millions
 
Millions)
Coal Producing Region
 
Value(1) (Btu/lb)
 
(%)
 
(%)
 
12/31/2016
 
12/31/2015
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia) (3)
 
11,400 – 13,400
 
85%
 
15%
 
1,054.0

 
1,216.7

Central Appalachia (Virginia, Southern West Virginia)
 
12,400 – 14,100
 
77%
 
23%
 
157.2

 
322.2

Illinois Basin (Illinois, Western Kentucky, Indiana)
 
11,600 – 12,000
 
79%
 
21%
 
348.7

 
396.1

Total
 
 
 
83%
 
17%
 
1,559.9

 
1,935.0

_______________
(1)
The heat value (gross calorific values) estimates for Northern Appalachian and Central Appalachian Unassigned coal reserves include adjustments for moisture that may be added during mining or processing as well as for dilution by rock lying above or below the coal seam. The heat value estimates for the Illinois Basin Unassigned reserves are based primarily on exploration drill core data that may not include adjustments for moisture added during mining or processing, or for dilution by rock lying above or below the coal seam.
(2)
Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustment for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams that are controlled by ownership or leases.
(3)
140.8 Million tons of the Northern Appalachia leased tons are controlled by Consolidation Coal Company, a former subsidiary of CONSOL Energy that was sold in December 2013. As of filing these tons are still controlled by Consolidation Coal Company but are shown in CONSOL Energy's reserves due to a binding agreement that these tons will be released to CONSOL Energy following the change in name of the Lease Holder.








17



The following table classifies CONSOL Energy coals by rank, projected sulfur dioxide emissions and heating value (British thermal units per pound). The table also classifies bituminous coals as high, medium and low volatile which is based on fixed carbon and volatile matter.
CONSOL Energy Proven and Probable Recoverable Coal Reserves
By Product (In Millions of Tons) as of December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
≤ 1.20 lbs.
 
> 1.20 ≤ 2.50 lbs.
 
> 2.50 lbs.
 
 
 
 
 
 
 
S02/MMBtu
 
S02/MMBtu
 
S02/MMBtu
 
 
 
 
 
 
 
Low
 
Med
 
High
 
Low
 
Med
 
High
 
Low
 
Med
 
High
 
 
 
Percent By
By Region
 
Btu
 
Btu
 
Btu
 
Btu
 
Btu
 
Btu
 
Btu
 
Btu
 
Btu
 
Total
 
Product
Metallurgical(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
High Vol A Bituminous
 

 

 

 

 

 
39.6

 

 

 

 
39.6

 
1.7
%
 
Med Vol Bituminous
 

 
5.1

 

 

 

 

 

 

 

 
5.1

 
0.2
%
 
Low Vol Bituminous
 

 

 
16.0

 

 

 
26.3

 

 

 

 
42.3

 
1.8
%
 
   Total Metallurgical
 

 
5.1

 
16.0

 

 

 
65.9

 

 

 

 
87.0

 
3.7
%
Thermal(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
High Vol A Bituminous
 

 
46.0

 

 
6.1

 
65.4

 
12.9

 
44.5

 
1,134.4

 
611.7

 
1,921.0

 
81.4
%
 
High Vol B Bituminous
 

 

 

 

 
101.1

 

 

 
139.3

 

 
240.4

 
10.3
%
 
High Vol C Bituminous
 

 

 

 

 

 

 
108.3

 

 

 
108.3

 
4.6
%
 
Low Vol Bituminous
 

 

 

 

 

 

 

 

 
4.5

 
4.5

 
0.2
%
 
   Total Thermal
 

 
46.0

 

 
6.1

 
166.5

 
12.9

 
152.8

 
1,273.7

 
616.2

 
2,274.2

 
96.3
%
 
      Total
 

 
51.1

 
16.0

 
6.1

 
166.5

 
78.8

 
152.8

 
1,273.7

 
616.2

 
2,361.2

 
100.0
%
 
Percent of Total
 
%
 
2.2
%
 
0.7
%
 
0.3
%
 
7.1
%
 
3.2
%
 
6.5
%
 
53.9
%
 
26.1
%
 
100.0
%
 
 
_______________
(1)
143.3 Million tons for the Mason Dixon Project are controlled by Consolidation Coal Company, a former subsidiary of CONSOL Energy that was sold in December 2013. As of this filing, these tons are still controlled by Consolidation Coal Company but are shown in CONSOL Energy's reserves due to a binding agreement that these tons will be released to CONSOL Energy upon consent of the lessor.

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

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

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





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
 
Enon, PA
 
U
 
LW/CM
 
R R/B
 
12.1

 
10.2

 
12.3

 
1984
Enlow Fork
 
Enon, PA
 
U
 
LW/CM
 
R R/B
 
9.6

 
9.0

 
10.6

 
1990
Harvey (3)
 
Enon, PA
 
U
 
LW/CM
 
R R/B
 
3.0

 
3.6

 
3.2

 
2014
Total
 
 
 
 
 
 
 
 
 
24.7

 
22.8

 
26.1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CONSOL Energy Portion of Equity Affiliates
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Harrison Resources (1)(2)
 
Cadiz, OH
 
S
 
S/L
 
R T
 

 

 
0.3

 
2007
Western Allegheny (1)(2)
 
Young Township, PA
 
U
 
CM
 
R T
 

 
0.4

 
0.5

 
2010
Total CONSOL Energy Portion of Equity Affiliates
 
 
 
 
 
 
 
 
 

 
0.4

 
0.8

 
 

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

Coal Capital

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

Coal Marketing and Sales

The following table sets forth the Company produced tons sold and average sales price for the period indicated:
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
Company Produced PA Mining Operations Tons Sold (in millions)
 
24.6

 
22.9

 
26.1

Average Sales Price Per Ton Sold– PA Mining Operations
 
$
43.31

 
$
56.36

 
$
61.88




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

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

Coal Contracts

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

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

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

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

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

Distribution

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

Coal Competition

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

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


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

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

Other Operations

CONSOL 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:

the caching of additional supplies of self-contained self-rescuer (SCSR) devices underground;
the purchase and installation of electronic communication and personal tracking devices underground;
the purchase and installation of proximity detection services on continuous miner machines;
the placement of refuge chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;
the replacement of existing seals in worked-out areas of mines with stronger seals;
the purchase of new fire resistant conveyor belting underground;
additional training and testing that creates the need to hire additional employees;
more stringent rock dusting requirements; and
the purchase of personal dust monitors for collecting respirable dust samples from certain miners.

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

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

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


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

Other State and Local Laws Related to Our Natural Gas Business

Regulation Affecting Gas Operations. Our natural gas operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the siting and construction of well pads 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:

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:

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, includi