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Company Presentation Q3 2016
Cautionary Language
2
This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities
Exchange Act of 1934, as amended). Statements that are not historical, are forward-looking, and include our operational and strategic plans; estimates of
coal and gas reserves and resources; the projected timing and rates of return of future investments; and projections and estimates of future production,
revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially
from those statements, plans, estimates and projections. Accordingly, investors should not place undue reliance on forward-looking statements as a
prediction of future actual results. Factors that could cause future actual results to differ materially from the forward-looking statements are included in our
earnings release, and include risks, contingencies and uncertainties that relate to, among other matters, the following: we may not receive the prices we
expect to receive for our natural gas and coal; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately
estimate our economically recoverable natural gas, oil and condensate; we may encounter unexpected operational issues when we drill and mine, including
equipment failures, geological conditions and higher than expected costs for equipment, supplies, services and labor; we may not achieve the efficiencies we
expect to realize in our drilling and completion operations, and as a result, our projected cost savings may not be fully realized; our joint venture partners,
who operate assets in which we have a significant interest, may not perform as we expect; we may not be able to sell non-core assets on acceptable terms;
we may be unable to incur indebtedness on reasonable terms; 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; with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC - 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; with respect
to the proposed termination of the joint venture with Noble, risks that the conditions to closing may not be satisfied and the transaction may not occur,
including our ability to obtain regulatory approvals on the proposed terms and schedule, disruption to our business, including customer and supplier
relationships resulting from this transaction, and the impact of the transaction on our future operating and financial results and liquidity and other factors,
many of which are beyond our control. Additional factors are described in detail under the captions "Forward Looking Statements" and "Risk Factors" in
CONSOL Energy Inc.’s annual report on Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission (SEC), as
updated by any subsequent quarterly reports on Form 10-Qs. The forward-looking statements in this presentation speak only as of the date of this
presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company
anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We
may use certain terms in this presentation, such as EUR (estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules
strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these estimates may
be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more speculative than estimates of
reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from
aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is
customary in the gas industry, prior to the commencement of gas drilling operations on our properties, we conduct a thorough title examination and perform
curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. As a result of our title review or
otherwise, we may be required to acquire property rights from third parties at our expense in order to effectively drill and produce the oil and gas rights we
control and third parties may participate in the wells we drill, thereby reducing our working interest in those wells.
This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CONSOL Energy Inc. or CNX Coal Resources LP.
Coal-E&P Revenue Split, 2012
E&P Revenues
Coal Revenues
3
CONSOL Energy: Company Overview
December 5, 2013 – Transaction with Murray Energy Corp. in which we sold half of coal
assets and related assets
April 19, 2014 – CONSOL Energy 150th Anniversary
September 25, 2014 – IPO of CONE Midstream Partners LP (NYSE: CNNX)
July 1, 2015 – IPO of CNX Coal Resources (NYSE: CNXC)
July 28, 2015 – Announced first PA Dry Utica well result in Westmoreland County
March 31, 2016 – Sold Buchanan Mine and associated met reserves
August 2, 2016 – Divested Miller Creek and Fola Complexes in Central Appalachia
September 30, 2016 – Dropped down an additional 5% interest in PA Mining
Complex to CNXC for total consideration of $88.8 million
October 31, 2016 – Announced agreement to separate Marcellus Shale joint venture with
Noble Energy
Coal-E&P Revenue Split, 2014
E&P Revenues
Coal Revenues
Coal-E&P Revenue Split, 2015, excl. Buchanan
E&P Revenues
Coal Revenues
CONSOL Energy is now a pure-play E&P company
Journey Towards Becoming a Top Tier Appalachian E&P Company Complete
4
Marcellus Joint Venture (JV) Exchange Agreement 1. Exchange agreement of jointly owned Oil & Gas properties,
consisting of:
Developed properties with associated current production of
1,070 MMcfe/d, net to the JV. CNX and NBL to receive net
production of ~620 and ~450 MMcfe/d, respectively
Undeveloped properties, including 75 drilled but uncompleted
locations (DUCs), and ~669,000 Marcellus Shale acres, net to
the JV - CNX to receive 53 DUCs and ~306,000 net Marcellus Shale acres
- NBL to receive 22 DUCs and ~363,000 net Marcellus Shale acres
CONSOL will receive a disproportionately greater value in the
property exchange, with the difference equal to ~$275 million
2. Cash payment from NBL to CNX equal to ~$205 million
3. Cancellation of remaining drilling “carry” obligation due from NBL
to CNX equal to $1.6 billion; “carry” was only to be paid when
Henry Hub natural gas price was equal to or greater than $4/MMBtu
for 3 consecutive months, with an annual limit of $400 million
4. Anticipate closing in Q4 2016; effective as of October 1, 2016
Firm Transportation (FT) and Processing Commitments:
NBL and CNX have agreed to work with the pipelines to reallocate
firm transportation to better align with the upstream assets
The targeted reallocation between CNX and NBL attempts to be
value neutral to both parties, while optimizing firm capacity to post-
alignment production expectations
No material changes to previous financial FT and processing
commitments - No NGL sales commitments were impacted by the NBL transaction
Post-Exchange Acreage Map
The transaction is designed to deliver approximately $480 million of value to CNX
in exchange for the cancellation of the drilling “carry” obligation
5
Post-Exchange Agreement: Pro Forma Analysis
(1) The 2016E production increase is a result of 85 MMcfe/d of additional production associated with the exchange agreement, as well as continued productivity improvements.
(2) 7,000' laterals x 750' spacing.
Impact on Marcellus Shale Operations
CONSOL Energy Before
JV Exchange Agreement
After
JV Exchange Agreement
2016E Production(1) (Bcfe) 380-385 390-395
2016E Average per Unit Operating Expenses ($/Mcfe) $2.27 - $2.49 $2.27 - $2.49
Net Marcellus DUC Inventory (Wells) 37.5 53.0
Marcellus Joint Venture Assets
CONSOL Interest in
Total JV Assets
Before Exchange Agreement
JV Assets Held by CONSOL
After Exchange Agreement
Working Interest 50% 100%
Net Undeveloped Acres 335,000 306,000
Net Future Locations(2) 2,790 2,550
Net PDPs (Wells) 258 280
Net PDP Flowing Production (MMcfe/D) 535 620
6
Strategic Overview Agreement to Separate Marcellus Shale Joint Venture
Full autonomy to develop, operate, or divest assets
- Flexibility to operate these assets as we choose
- Facilitates stacked pay development opportunities
- Unlocks development of assets
- Increases ability to execute asset sales
- Increases production
Increases interest in the highest return acreage
- Increase proved undeveloped reserves (PUDs) in the core areas of the Marcellus Shale
- Retain high return acreage
Further strengthens the balance sheet
- Expected to increase EBITDA and free cash flow
- Reduces debt and leverage ratio
- Increases DUCs providing additional production opportunity with little additional required capital
- Improves liquidity
Top-tier Appalachian E&P company
- The Marcellus assets retained provide growth opportunities in best-in-class areas, with low cost potential
- Completes the transformation of CONSOL to a pure-play E&P
The exchange agreement provides CONSOL more control in capital allocation
decisions and creates greater opportunities to grow shareholder value
7
The exchange agreement provides CONSOL Energy the ability to drive NAV per share higher
through:
Greater flexibility in our capital allocation strategy and long-term development plan
- Optimize the development plan between the Marcellus and Utica horizons
- Should increase value in CONE Midstream Partners LP
Better control and flexibility to monetize E&P assets that were previously part of the JV
Pulls forward value for the JV “carry”
Quicker balance sheet de-levering and improves liquidity without issuing equity
Joint Venture Separation Drives Long-Term Value Growth
Key Takeaways of the Exchange Agreement
Completes the transformation of the company to a pure-play E&P
8
E&P Operations
9
Marcellus Shale Footprint Before and After the Joint Venture Exchange Agreement with Noble Energy
(1) 7,000' laterals x 750' spacing.
JV Marcellus Footprint:
Before-Exchange
CNX Marcellus Footprint:
Post-Exchange 9
WI (%) 50
Net
Undeveloped
Acres
335,000
Net Future
Locations(1)
(Count)
2,790
Net PDP (Wells) 258
PDP Flowing
Production
(MMcfe/D)
535
Marcellus Shale
Before Exchange Agreement
WI (%) 100
Net
Undeveloped
Acres
306,000
Net Future
Locations(1)
(Count)
2,550
Net PDP (Wells) 280
PDP Flowing
Production
(MMcfe/D)
620
Marcellus Shale
After Exchange Agreement
10
E&P Division: Q3 2016 Operations Summary
Sub-
Regions
Horizontal
Rigs Drilled Completed
Turned
In Line
(TIL)
Avg. TIL
Lateral
Length
(ft)
Counties
Southwest
PA ---- ---- 6 1 7,206
Greene,
Washington,
Allegheny, PA
Central PA ---- ---- ---- ---- ----
Indiana,
Westmoreland,
PA
Northern
WV Dry ---- ---- ---- ---- ----
Barbour,
Doddridge,
Lewis, WV
Ohio ---- ---- ---- ---- ---- Monroe, OH
North Wet
Gas ---- ---- ---- 6 10,571
Greene,
Washington,
PA; Marshall,
WV
South Wet
Gas ---- ---- ---- ---- ----
Doddridge,
Tyler, Ritchie,
WV
Total 0 0 6 7 10,090
Sub-
Regions
Horizontal
Rigs Drilled Completed
Turned
In Line
(TIL)
Avg. TIL
Lateral
Length (ft)
Counties
Core Wet ---- ---- ---- ---- ---- Noble, OH
Surrounding
Core Wet ---- ---- ---- ---- ----
Harrison,
Belmont, OH
Dry Utica 2 2 ---- ---- ----
Monroe, OH;
Marshall, WV
Westmoreland,
Greene, PA
Total 2 2 ---- ---- ----
Marcellus Shale Quarterly Summary Utica Shale Quarterly Summary
E&P Operations
Drilling & Completions update
─ Dual Fuel: D&C set up for Monroe County Utica – realized
$122k in savings on GH58 completion
─ Drilling Capital Efficiencies: Reduced drilling capital by 70%
over 8 Monroe County Utica wells
─ Plugless Completions: Currently flowing back the second
plugless completion test on GH58 pad
Production update
─ Lifting Efficiencies: Lifting costs further declined to $0.234/mcfe
for 3Q16, which yielded an ~$1.05 million reduction from 2Q16
─ Utica Production Capital Efficiencies: Monroe County facility
design and installation costs reduced from ~$900k/well on the 1st
pad to ~$535k/well on the 2nd pad (~41% reduction)
─ Marcellus Production Optimization: Tubing installs, plunger lift
systems, and soap injection - Implementation yielded a total uplift
of ~11.2 mmcf/d and 16 bcpd with payback periods less than 120
days
─ Production Control Room Efficiency: Average downtime per
incident was reduced in our SWPA District by ~20% which
resulted in an increased production of ~2.1mmcf/d
─ Operational Efficiency: Electric Demand Response Audit –
completed the 1 hour test which generated ~$812k in annual
savings
11
2016 Activity Overview and 2017 Drilled and Uncompleted Opportunity Set
E&P Activity Summary – 2016 Plan
E&P Operations: Pro Forma DUC Inventory
Note: Plan as of 9/30/2016.
Implied inventory exiting 2016 anticipated to consist of 70 Marcellus and Utica
Shale wells, of which CONSOL will have 100% WI in 65 wells
Expected New
Wells Drilled in
H2 2016
Drilled
Uncompleted
Inventory
Drilled
Completed
Inventory
2016 TIL's
Remaining
Implied
2017
Inventory
2016
Completions
Remaining
Marcellus
SW PA Operated - 12 8 6 14 -
SW PA Non-Op - - - - - -
WV Operated - 41 - - 41 -
WV Non-Op - - - - - -
Total Marcellus - 53 8 6 55 -
Utica
SW PA Operated - - - - - -
OH Operated 9 1 - - 10 -
OH Non-Op - 5 - - 5 -
Total Utica 9 6 - - 15 -
Total Gross Marcellus/Utica
Wells 9 59 8 6 70 -
12
Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth
E&P Operations: Capital Expenditures
Deferring activity, increasing capital efficiency
improvements and identification of additional
de-bottlenecking activities
2016 E&P capital budget of $190-$205 million
- Drilling and Completion: $140-$145 million
o Includes $8-$12 million for coalbed methane (CBM)
activity
- Midstream of $34-$39 million (including approximately
$22 million associated with CONE Midstream capital
contributions)
- Other activities (land, permitting, and business
development): $17-$22 million
2016 E&P Capital Budget:
$190-$205 Million
Base case assumes drilling nine new wells in Monroe County, Ohio in H2 2016
D&C72%
Midstream18%
Other10%
$0.23 $0.38 $0.24 $0.16
$1.10$1.02
$1.04$0.93
$0.17 $0.17$0.09
$0.09
$0.84 $0.59
$0.37
$0.26
$1.17
$1.11
$0.82
$0.48
$3.51
$3.27
$2.56
$1.92
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
2013 2014 2015 2016E²
SG&A¹ Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE
13
Full-cycle Breakeven Operating Metrics Declined from $3.51 to $1.92 per Mcfe, a 45% Projected Decline
E&P Operations: Benchmarking vs Peers
Cash OpEx
(plus SG&A) of
$1.28/Mcfe,
plus PUD-to-
PDP CapEx of
$0.48/Mcfe,
equals total full
cycle cash
costs of
$1.92/Mcfe
As of YE 2015 A B C D E F G Wtd. Avg. CNX
E&P Per Unit Future PUD F&D ($/Mcfe) $0.60 $0.75 $0.91 $0.41 $0.48 $0.69 $1.33 $0.79 $0.48
(1) SG&A does not include short-term or long-term incentive compensation
(2) 2016E reflects midpoint of guidance range. Numbers may differ slightly due to rounding.
Source: Company filings and presentations. Peers include AR, COG, EQT, GPOR, RICE, RRC and SWN.
Exceeded cost reduction target of 15% in 2015 with a 22% reduction from 2014
and projecting an additional 25% reduction from 2015
14
E&P Operations: Drilling Improvements
Realized ~60+% Reduction in Days to Drill Expect Additional
~16% Reduction
Met previously stated goal of drilling a Monroe County Dry Utica well in 26 days
- Exceeded goal by three days on third well
Improvement of 76% over the first well drilled and a 38% improvement over last well drilled in
2015
New goal of 20 days to drill Monroe County Dry Utica wells
0.0
5,000.0
10,000.0
15,000.0
20,000.0
25,000.0
0.00 20.00 40.00 60.00 80.00 100.00 120.00
De
pth
(ft
.)
Days
Days vs. Depth(Wells in order of Horizontal TD Date)
SWITZ6B
SWITZ6D
SWITZ6F
SWITZ6H
SWITZ16J
SWITZ16D
SWITZ5J
SWITZ16B
Utica Shale: Days vs. Depth (Wells in order of Horizontal TD Date)
Great improvements in drilling efficiency
$1,740 $1,810
$1,380 $1,340
$1,150 $1,060 $1,040 $1,040
$950
$800
$1,000
$1,200
$1,400
$1,600
$1,800
$2,000
Switz 6B Switz 6D Switz 6H Switz 6F Switz 16J Switz 16D Q2 Switz 16D Act Switz 5J Switz 16B
Drilli
ng C
ost
($/late
ral ft
)
Switz Drilling Cost ($/lateral ft) (Wells in order of Tophole TD)
15
Utica Shale: Drilling Cost Improvements
Expected cost from Q2 Actual costs
Improvement of 26% in drilling costs over first 3 wells drilled and a 39% improvement over last
well drilled in 2015
Exceeded previous goal of $1,060/lateral ft drilling costs stated in Q2 2016
16
Gas Marketing
CONSOL basin exports are projected to
increase approximately 73,000 Dth/day for
FY 2016 over FY 2015 as TETCO’s U2GC
and TEAM OPEN projects were put into
service in late 2015, increasing expected
realizations by marketing gas to the
higher priced Midwest and Gulf Coast
markets.
Directly-marketed ethane volumes were
612,000 barrels in Q3 -- an increase of
132% from Q2 and, on an equivalent
basis, yielded a premium price over the
Texas Eastern M2 gas market.
─ An additional ethane contract with
favorable terms commenced October 1,
2016.
17
Gas Marketing Q3 2016 Gas Realization and Marketing Highlights
2016 2015
Q3 Q2 Q1 Q3
NYMEX Natural Gas ($/MMBtu) 2.81$ 1.95$ 2.09$ 2.77$
Average Differential (0.86) (0.46) (0.36) (1.00)
BTU Conversion (MMBtu/Mcf)* 0.11 0.09 0.10 0.09
Gain on Commodity Derivative
Instruments-Cash Settlements 0.47 0.91 0.98 0.60
Realized Gas Price per Mcf 2.53$ 2.49$ 2.81$ 2.46$
*Conversion Factor 1.06 1.06 1.06 1.05
Q3 2016 Natural Gas Price Reconciliation
Ethane volume growth and improving NGL pricing seen in Q3
continued into early Q4 2016
In addition to the upstream
deal, CNX and NBL have
agreed to work with the
pipelines to reallocate firm
transportation to better
align with the upstream
assets
The targeted reallocation
attempts to be value neutral
to both parties, while
optimizing firm capacity to
post-alignment production
expectations
Remains subject to FERC
and pipeline approvals
18
Gas Marketing Firm Transportation
FT reallocation retains low average cost and market exposure and improves
alignment of FT with current production and growth areas
$0.24 $0.25
$0.29 $0.30
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
2016 2017 2018 2019
Expected Avg. Demand per MMBtu:
2016E-2019E After Reallocation
Expected Firm Capacity by Pipeline After FT Reallocation
Charts also include transportation under precedent agreements
Pipeline YE 2016 YE 2018
ANR Pipeline 47 47
Columbia (TCO) 212 562
Dominion (DTI) 345 317
East Tennessee 282 202
Nexus - 115
TETCO 174 174
TETCO (via firm sales) 285 125
(1000s MMBtu/day) 1,345 1,542
Expected FT Capacities After Reallocation
TETCO
TETCO (via firm sales)
Dominion
East Tennessee
Columbia
ANR
NEXUS
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
Jan 16 Jan 17 Jan 18 Jan 19
1000s
MM
Btu
/da
y
19
Gas Marketing Natural Gas Sales: Expected Market Mix
Sales mix remains mostly unchanged after the transaction
MIDWEST TETCO M3
TETCO M2
EAST TENNESEE
TETCO ELA
TETCO WLA
TCO POOL
DOMINION SOUTH
Gas Sales 2016E 2017E
Columbia (TCO) 17% 17%
TETCO (M2) 29% 28%
TETCO (M3) 16% 15%
Dominion (DTI) 15% 15%
East Tennessee 10% 10%
TETCO ELA & WLA 8% 8%
Midwest (Chicago) 5% 7%
100% 100%
0
100
200
300
400
500
600
Jan 16 Jan 17 Jan 18 Jan 19
MM
cf/
da
y
MVC
CNX and NBL have also agreed to
work with processing
counterparties to realign processing
capacity with the upstream assets
After the swap of capacity, CNX’s
volume of firm processing capacity
and minimum volume commitment
will be roughly unchanged
CNX will retain the flexibility to
bypass processing with certain
“damp” gas to continue facilitating
optimization of that gas
No NGL sales commitments were
impacted by the NBL transaction
20
Gas Marketing Natural Gas Processing and NGLs
Note: CONSOL Energy had processing capacity expansion rights of 110,000 Mcf/d.
Processing capacity is to be transferred in line with the asset areas it supports;
minimal impact to parties based on current volumes but gives
CNX additional flexibility in the future
CNX Expected Contracted Processing Capacity
21
Ethane 64%
Propane 22%
I-Butane 3%
N-Butane 6%
Natural gasoline
5%
Maximum Ethane Recovery* Potential Scenario
* Assumes 85% ethane recovery level
Ethane 36%
Propane 37%
I-Butane 5%
N-Butane 11%
Natural gasoline
11%
3Q16 Est NGL Sales Comp
Gas Marketing: Liquids Realizations Natural Gas Liquids, Oil, and Condensate
Q3 2016 Avg. “NGL Barrel” Composition Q3 2016 liquids sold: 13.6 Bcfe, up 29% from Q2 2016
Total weighted average price of all liquids decreased
1.6% to $15.48 per Bbl in Q3 2016 from $15.73 per Bbl in
Q2 2016. Excluding ethane, average sales price was up
8.8% from Q2.
Directly-marketed ethane volumes were 612,000 barrels
in Q3 -- an increase of 132% from Q2 and, on an
equivalent basis, yielded a premium price over the Texas
Eastern M2 gas market
Liquids comprised approximately 14% of Q3 2016
production volumes, 14% of E&P sales revenue and 5%
of total Company revenue
17.5 million gallons of propane hedged from April of 2016
through March of 2017 at an average price of $0.48 per
gallon
CONE Gathering and Midstream systems provide CONSOL unique flexibility to
either (a) blend in ethane to meet specifications, allowing for nearly 100%
Marcellus ethane rejection or (b) extract ethane when accretive
Average Price Realization (per Bbl)
2016 2015
Q3 Q2 Q1 Q3 Q2 Q1
NGLs 13.14$ 12.84$ 12.30$ 4.80$ 12.48$ 20.40$
Oil 42.06 33.72 30.84 54.18 46.14 47.82
Condensate 37.26 31.68 14.64 27.84 31.26 20.82
22
(1) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements.
(2) At the midpoint of production guidance of 390-395 Bcfe.
(3) Hedge positions as of 10/13/2016. FY 2016 includes actual settlements of 225.3 Bcf.
Gas Hedges
Gas Marketing
E&P Hedge Program:
Program and actively
monitored hedges
─ Program Hedge - protect
margins on up to 90% of
our Proved Developed
Production
─ Active Hedge Process -
supplements program
hedges up to 80% of our
total production including
proved undeveloped
production
Since 6/30/16, added 64 Bcf
of NYMEX gas hedges and
172 Bcf of basis hedges
through 2020, further
protecting downside
Approximately 69% of total
FY 2016E production
volumes hedged2
CNX Gas Volumes Hedged 2016-2020
Hedge Volume and Pricing 2016-2020 Q4 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
NYMEX + Basis¹
Volumes (Bcf) 61.8 264.5 207.5 151.6 75.2 40.5
Average Prices ($/Mcf) 3.16$ 3.03$ 2.61$ 2.64$ 2.53$ 2.77$
NYMEX Only Hedges Exposed to Basis
Volumes (Bcf) 1.8 - 30.3 11.8 25.2 2.6
Average Prices ($/Mcf) 3.41$ -$ 3.02$ 3.10$ 3.04$ 3.18$
Physical Sales With Fixed Basis Exposed to NYMEX
Volumes (Bcf) - 7.3 - - - -
Average Hedged Basis Value ($/Mcf) -$ (0.06)$ -$ -$ -$ -$
Total Volumes Hedged (Bcf)3
63.6 271.8 237.8 163.4 100.4 43.1
0
50
100
150
200
250
300
Q4 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
Gas V
olu
me
s H
ed
ge
d (B
cf)
Physical Sales With Fixed Basis Exposed to NYMEX
NYMEX Only Hedges Exposed to Basis
NYMEX + Basis¹
23
Financial
24
Net earnings attributable to continuing operations(1) in the 2016 third quarter of $62.6 million, or $0.26 per
diluted share
Adjusted net loss attributable to continuing operations(1) in the 2016 third quarter of $35.5 million, or ($0.15)
per diluted share
- Excludes the following pre-tax items:
$159.6 million unrealized gain on commodity derivative instruments
$3.7 million loss related to pension settlement
$0.2 million in severance expense
Q3 2016 production of 96.4 Bcfe, up approximately 10.3 Bcfe from Q3 2015, a 12% increase
Production volumes expected to grow to approximately 390-395 Bcfe in 2016
(1) Q3 2016 net income includes a net loss of ($35) million from discontinued operations, net of tax.
Note: The terms "adjusted net loss attributable to continuing operations," "adjusted EBITDA," “adjusted EBITDA attributable to continuing operations,” "free cash flow," and "organic
free cash flow from continuing operations" are non-GAAP financial measures, which are defined and reconciled to GAAP net (loss)/income and net cash provided by continuing
operations below, under the caption “Non-GAAP Reconciliation."
Third Quarter 2016 Results
Financial: Q3 2016 Review
Q3 2016 Summary Y/Y Q-to-Q Seq. Q-to-Q
($ in millions, except per share data) 3Q2016 3Q2015 Change 3Q2016 2Q2016 Change
Net Income (Loss) Attributable to CNX Shareholders $25 $119 ($94) $25 ($470) $495
Earnings (Loss) per Diluted Share $0.11 $0.52 ($0.41) $0.11 ($2.05) $2.16
Revenue and Other Income $746 $721 $25 $746 $286 $460
Net Cash Provided by Continuing Operations $166 $147 $19 $166 $82 $84
Adjusted EBITDA Attributable to Continuing
Operations $156 $146 $10 $156 $135 $21
(1) (1)
25
Generated positive free cash flow
- Organic free cash flow from continuing operations in Q3 2016 of $103 million; first nine months 2016 total organic
FCF of $188 million
- Total free cash flow in Q3 2016 of $92 million; first nine months 2016 total free cash flow of $608 million
Reduced outstanding borrowings on the revolving credit facility by approximately $112 million, which
increased liquidity and de-levered the balance sheet
- Used free cash flow generated during the quarter, plus cash on hand
Total capital expenditures in Q3 2016 of $64 million: First nine months 2016 total capital expenditures of
$179 million
Source: Company filings.
Note: Numbers may not sum and may differ slightly from totals and financial statements due to rounding.
Net (Decrease)/Increase in Cash
Financial: Q3 2016 Review (Cont’d)
Q3 2016 Cash Flow Summary (including Discontinued Operations) Y/Y Q-to-Q Seq. Q-to-Q
($ in millions) 3Q2016 3Q2015 Change 3Q2016 2Q2016 Change
Net Cash Provided by Operating Activities $163 $110 $53 $163 $95 $68
Capital Expenditures ($64) ($248) $184 ($64) ($38) ($26)
Proceeds From Asset Sales $21 $76 ($55) $21 $10 $11
Other Investing ($27) ($38) $11 ($27) ($1) ($26)
(Payments on)/Proceeds From Short-Term Debt & Misc. Borrowings ($114) ($110) ($4) ($114) ($388) $274
Dividends Paid - ($2) $2 - - -
Other Financing 4 $285 ($281) $4 ($7) $11
Net (Decrease) / Increase in Cash ($17) $73 ($90) ($17) ($329) $312
26
E&P Division: Results Summary
Financial: Q3 2016 Review (Cont’d)
(1) Average Sales Prices for 3Q2016, 3Q2015 and 2Q2016 include gains on commodity derivative instruments (cash settlements) of $0.47, $0.60 and $0.91, respectively.
(2) Average Costs for 3Q2016, 3Q2015 and 2Q2016 include DD&A of $1.05, $1.05 and $1.04, respectively.
Adjusted earnings before income tax for E&P Division of $1.7 million(1)
Production increased by 12% in third quarter 2016, compared to year-earlier quarter
Marcellus Shale all-in unit costs were $2.33 per Mcfe in the third quarter, a decrease of $0.13 from $2.46 per Mcfe
in the year-earlier quarter, or a 5% improvement
Utica Shale all-in unit costs were $1.81 per Mcfe in the third quarter, a decrease of $0.29 from $2.10 per Mcfe in
the year-earlier quarter, or a 14% improvement
CBM all-in unit costs were $2.84 per Mcfe in the third quarter, an increase of $0.04 from $2.80 per Mcfe in the
year-earlier quarter, or a 1% increase
Other Gas all-in unit costs were $3.37 per Mcfe in the third quarter, a decrease of $0.02 from $3.39 per Mcfe in the
year-earlier quarter
(1) Adjusted earnings before income tax for the E&P Division of $1.6 million for the three months ended September 30, 2016 is calculated as GAAP earnings before income tax of
$161.1 million less total pre-tax adjustments of $159.5 million. The $159.5 million adjustment is the $159.6 million pre-tax gain related to the unrealized gain on commodity derivative
instruments and a pre-tax loss of $0.1 million related to severance expense.
Y/Y Q-to-Q Seq. Q-to-Q
E&P Division 3Q2016 3Q2015 Change 3Q2016 2Q2016 Change
Average Sales Price(1)
($ / Mcfe) $2.54 $2.35 $0.19 $2.54 $2.50 $0.04
Average Costs(2)
($ / Mcfe) $2.36 $2.54 ($0.18) $2.36 $2.27 $0.09
Sales Volumes (Bcfe) 96.4 86.1 10.3 96.4 99.3 (2.9)
Sales Volumes (Bcfe) by Category
Marcellus 51.8 45.9 5.9 51.8 53.1 (1.3)
Utica 22.5 15.3 7.2 22.5 23.3 (0.8)
CBM 17.0 18.5 (1.5) 17.0 17.1 (0.1)
Other 5.1 6.4 (1.3) 5.1 5.8 (0.7)
27
$2.0 billion Revolving Credit Facility:
5 year credit facility expires June 2019
Paid down approximately $600 million of revolving debt on the credit facility year-to-date
Gas reserves based lending facility: fall redetermination process expected to be completed in November
Includes the right to separate the coal and gas business subject to a leverage test
Strong Liquidity Position of ~$1.4 Billion
Financial: Liquidity
(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $80 million as of 9/30/2016, $6 million of which was CNXC’s and consolidated in CNX’s financial statements per
US GAAP accounting.
(2) Revolving credit facility as of 9/30/2016.
Sept. 30,
Maintenance Covenants Limit 2016
CONSOL Energy Revolver:
Minimum Interest Coverage Ratio < 2.5 to 1.0 4.0 to 1.0
Minimum Current Ratio < 1.0 to 1.0 2.7 to 1.0
Amount/ Amount Letters Amount
September 30, 2016 ($ in million) Capacity Drawn of Credit Available
Cash and Cash Equivalents(1) $74 - - $74
Revolving Credit Facility(2) $2,000 $354 $324 $1,322
Total $2,074 $354 $324 $1,396
Ample liquidity of $1.4 billion with business plans focused on positive free cash
flow generation and de-leveraging the balance sheet
28
Debt and Liquidity Profile
Financial: Liquidity (Cont’d)
Note: Some numbers may not match exactly to financial statements due to rounding.
(1) The 2022 and 2023 senior notes includes $5 million and $6 million of unamortized bond premium / discount, which will be amortized over the life of the notes, respectively.
(2) Total Debt of $3.151 billion excludes total unamortized debt issuance costs of $29 million.
(3) Net Debt equals Total Debt less Cash and Cash Equivalents.
(4) As of 9/30/2016, CNX had approximately $354 million of borrowings and $324 million of outstanding letters of credit under its revolving credit facility, leaving approximately $1,322 million of
availability. CNXC had $208 million outstanding on its revolving credit facility leaving approximately $192 million of availability.
(5) Number of MLP units owned by CNX as of 9/30/2016 and unit prices as of market close on 10/21/2016.
(6) CNX Coal Resources liquidity data is as of 9/30/2016 and CONE Midstream data is as of 6/30/2016.
(7) Adjusted EBITDA Attributable to CNX Shareholders is a non-GAAP financial measure and the
reconciliation is provided in the Appendix. Bank methodology LTM EBITDA equals LTM Adjusted EBITDA of
$680 million less a loss on sale of assets of $6 million, plus gain related to changes in retiree medical
(OPEB) plan of $110 million, less the $50 million of CNXC EBITDA net of cash distributions attributable to
CNX, less $3 million of other net adjustments. For a reconciliation of CNXC’s EBITDA please see the
Company’s form 10Q’s and 10K’s. Bank net debt equals debt of $3.151 billion, less $74 million cash on hand
excluding CNXC’s cash, less $208 million of CNXC revolver debt, less $3 million of advance mining
royalties, plus $240 million of net letters of credit related to firm transportation obligations, mining equipment
leases, and insurance policies.
Transaction further strengthens the balance sheet as leverage ratio falls
and liquidity rises $205 million to $1.6 billion
CNX
Consolidated
CNXC:
100%
CNX
Attributable
Capitalization and Liquidity 9/30/2016 9/30/2016 9/30/2016
Capitalization
Cash and Cash Equivalents $80 $6 $74
Revolving Credit Facility Balance 562 208 354
Capital Lease Obligations 37 - 37
Total Secured Debt $599 $208 $391
8.25% Senior Notes due 2020 $74 - $74
6.375% Senior Notes due 2021 21 - 21
5.875% Senior Notes due 2022 (1) 1,855 - 1,855
8.0% Senior Notes due 2023 (1) 494 - 494
Baltimore 5.75% Revenue Bonds due 2025 103 - 103
Miscellaneous Debt 5 - 5
Total Debt (2) $3,151 $208 $2,943
Net Debt (3) $3,071 $202 $2,869
Stockholders’ Equity $4,290 $143 $4,147
Total Capitalization $7,441 $351 $7,090
Liquidity
Cash and Cash Equivalents $80 $6 $74
Revolving Credit Facility Capacity (4) 1,514 192 1,322
Total Liquidity $1,594 $198 $1,396
Equity Value of Ownership in
Affiliated Public MLPs
CNX
Owned LP
Units(5)
Unit
Price(5)
Market
Value
CNX Coal Resources LP (CNXC:NYSE) 16.6 $17.50 $291
CONE Midstream Partners LP (CNNX:NYSE) 19.1 $20.80 $397
Total Equity Value of Ownership Interests in Affiliated Public MLPs $688
Liquidity of Affiliated MLPs
Total
Facility
Capacity
Outstanding
Balance
Available
CapacityCash
Total
Liquidity of
Affiliates
CNX Coal Resources LP (6)
$400 $208 $192 $6 $198
CONE Midstream Partners LP (6)
$250 $47 $203 $5 $208
Total Liquidity of Affiliated
Public MLPs $650 $255 $395 $11 $406
Leverage Ratio 9/30/2016
LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7)
$731
LTM Bank Net Debt / Adj. EBITDA (7)
4.3x
$4,345
$1,902 $1,694
$1,542 $1,385 $1,374
$370
$148 $153 $137
$100 $100
$0
$50
$100
$150
$200
$250
$300
$350
$400
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
FY 2012 FY 2013 FY 2014 FY 2015 Q3 2016 FY 2016E
An
nu
al
Ca
sh
Se
rvic
ing
Co
sts
($
in
Millio
ns
)
Le
ga
cy L
iab
ilit
ies
($
in
millio
ns
)
Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost
As of Period End: 12/31/2012 12/31/2013 12/31/2014 12/31/2015 9/30/2016 12/31/2016E
Legacy Liabilities ($MM)
LTD $39 $20 $22 $20 $18 $17
WC 180 85 90 83 82 82
CWP 184 121 126 123 126 125
OPEB 3,018 1,022 761 672 655 655
Salary Retirement/Pension 225 53 119 94 92 89
Asset Retirement Obligations 699 601 576 550 412 406
Total Legacy Liabilities $4,345 $1,902 $1,694 $1,542 $1,385 $1,374
FY 2012 FY 2013 FY 2014 FY 2015 Q3 2016 FY 2016E
Total Annual Legacy Liabilities Cash Servicing Cost $370 $148 $153 $137 $100 $100
29
Significant Legacy Liability Reductions Over Past 3 Years
Financial: Legacy Liabilities
Flows through P&L in operating
costs (impact reflected in operating
cost guidance)
Flows through P&L within DD&A
Flows through Other Segment in
“Miscellaneous Operating Expense”
Projected $100MM Annual Cash
Servicing Cost for FY 2016, a
$37MM reduction from the year-
end 2015 run-rate of $137MM
Legacy liabilities reduced and cash servicing costs reduced by more than 60%
since 2012, with further reductions expected going forward
30
Organizational Structure and CNX Ownership
Financial: CNX Coal Resources LP (CNXC:NYSE)
In July 2015 IPO, sold 10.6 million LP units, or 44.6%,
raising approximately $158 million in gross proceeds;
CNXC also distributed $197 million in cash to
CONSOL related to the revolver drawdown
In September 2016, CNXC acquired an additional 5%
undivided interest in the PA Mining Complex for total
consideration of $88.8 million ($21.5 million in cash
and preferred units valued at $67.3 million) implying
total complex value of $1.8 billion
CONSOL Energy retains a 75% undivided interest in
the Pennsylvania mining complex and owns 100% of
CNXC’s general partner, as well as the incentive
distribution rights
CNXC owns a 25% undivided interest(1) in, and
operational control over, CONSOL Energy’s Pennsylvania
mining complex (Bailey, Enlow Fork and Harvey mines)
(1) Unless otherwise specified, all figures relating to reserves and production of the Pennsylvania mining complex in this presentation are on a 100% basis.
75% undivided
ownership interest
CNX Coal Resources LP
NYSE: CNXC
CNX Coal Resources GP
LLC
Pennsylvania
Mining Complex
100% ownership
interest
60% limited
partner
interest
2% general partner
interest and IDRs
25% undivided
ownership interest and
management and control
rights
limited partner
interest
CONSOL Energy Inc.
("CONSOL Energy")
NYSE: CNX
Public
Greenlight
Capital
CNXC is a vehicle to separate the businesses
(in millions except for per unit amounts)
Total LP Units held by CONSOL Energy 16.6
Unit Price (as of close on 10.21.2016) $17.50
CNXC Units Equity Value to CONSOL Energy $290.8
CONSOL Energy's Ownership Interest in CNX Coal
Resources LP (CNXC:NYSE)
CONSOL owns 32.1% of CONE Midstream Partners LP’s
(NYSE: CNNX) LP units and 50% of the General Partner
(“GP”), which has a 2% interest in CNNX (and rights to IDRs)
CNNX owns interests in 3 development companies
The remaining un-dropped portion of the development
companies’ interests are held by CONE Gathering LLC
(“CGLLC”), a privately held Joint Venture between CONSOL
Energy (NYSE: CNX) and Noble Energy (NYSE: NBL)
CNX’s share of CONE Midstream’s Net Income (CNNX &
CGLLC) flows into the E&P segment’s “Equity in Earnings of
Affiliates,” which in CNX’s consolidated financial statements
falls within the “Miscellaneous Other Income” line item
Distributions run straight through CNX’s cash flow statement in
the “Return on Equity Investment” line item
CNX has seen increasing benefit from CONE’s EBITDA and
cash distributions, on top of which CNNX recently increased its
cash distribution 3.7% from 2Q16
31
Financial: CONE’s Growing Cash Contribution
Note: For a reconciliation of CONE’s EBITDA please see the CNNX’s form 10Q’s and 10K’s.
Source: CONE Midstream Partners LP and CONSOL Energy Inc.
CNNX: CNX Ownership and Cash Contribution
$10 $15
$29
$44
$57
$0
$10
$20
$30
$40
$50
$60
FY 2012 FY 2013 FY 2014 FY 2015 3Q16Annualized
CONE Midstream's and Gathering's Pro Rata Net Income Contribution to CNX
CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's NetIncome
$10$15
$34
$50
$62
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
FY 2012 FY 2013 FY 2014 FY 2015 3Q16Annualized
CONE Midstream's and Gathering's Pro Rata EBITDA Contribution to CNX
CNX Pro Rata Share of CONE Midstream Partners LP's CashDistributionsCNX Total Pro Rata Share of CNNX and CONE Gathering, LLC'sEBITDA
$68
$82
$18
$20
(in millions except for per unit amounts)
Total LP Units held by CONSOL Energy 19.1
Unit Price (as of close on 10.21.2016) $20.80
CNNX Units Equity Value to CONSOL Energy $397.3
CONSOL Energy's Ownership Interest in CONE
Midstream Partners LP (CNNX:NYSE)
($ in millions)
($ in millions)
32
Guidance
Note: Guidance as of 11/1/2016.
(1) Represents estimated unutilized firm transportation and processing expense less estimated gathering revenue (resold firm transportation).
E&P Segment Guidance 2016E
Production Volumes:
Natural Gas (Bcf) 346 - 349
NGLs (MBbls) 6,500 - 6,750
Oil (MBbls) 62 - 68
Condensate (MBbls) 800 - 850
Total Production (Bcfe) 390 - 395
Natural Gas Basis Differential to NYMEX ($Mcf) ($0.65) - ($0.75)
NGL Realized Prices ($Bbl) $13.00 - $15.00
Condensate Realized Prices % of WTI 65% - 70%
Oil Realized Prices % of WTI 85% - 90%
Capital Expenditures ($ in millions):
Drilling and Completion $160 - $165
Midstream $25 - $30
Land and Other $5 - $10
Total E&P and Midstream CapEx $190 - $205
Average per unit operating expenses ($/Mcfe):
Lifting (including Direct Admin.) $0.24 - $0.28
Impact Fees/Ad Valorem/Production Taxes $0.08 - $0.10
Gathering, Transportation, Compression & Processing $0.91 - $0.95
Depreciation, Depletion and Amortization $1.04 - $1.07
Total Production and Gathering Cost $2.27 - $2.40
Other Expenses ($ in millions):
Selling, General and Administrative Costs $58 - $62
Unutilized Firm Transportation Expense, net:(1) $15 - $16
33
Guidance
Note: Guidance as of 11/1/2016. CONSOL Energy is unable to provide a reconciliation of projected CNXC Adjusted EBITDA, CONSOL's Other Coal Division EBITDA, and
CONSOL's Other Miscellaneous Coal EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown
effect, timing and potential significance of certain income statement items.
(1) Includes estimated contribution from Miller Creek and Other Coal Operations for fiscal year 2016 and 1Q16 for Buchanan, and excludes Loss on Sale of Buchanan and the
Loss on Sale for the Miller Creek and Fola mines.
(2) Includes miscellaneous other income (net of applicable expenses) associated with the company's Terminal Operations, Rental Income, Water Operations, Coal Royalty Income,
and other miscellaneous land income.
(3) Includes Legacy Liability Costs of approximately $80-85 million; Other Coal-Related Corporate Expenses, and other miscellaneous items. Excludes stock-based compensation
and pension settlement charges.
Coal Segment Guidance 2016E
Estimated Total PA Mining Operations Sales Volumes (in millions of tons) 23.6 - 24.4
Sales Volumes Attributed to Discontinued Operations (in millions of tons) 2.1
% PA Mining Operations Tonnage Sold 100%
Total Consolidated Coal Segment Capital Expenditures ($ in millions):
Production $60 - $76
Other (Land/Water/Safety/Terminal) $15 - $24
Total Coal Capital Expenditures $75 - $100
Adjusted EBITDA Guidance
CNXC EBITDA $74 - $82
4x
100% PA Mining Operations Operating EBITDA $296 - $328
Less: Noncontrolling Interest ($26) - ($30)
Plus: Other Coal Operating EBITDA(1)
$15 - $16
Plus: Other Coal Misc. EBITDA(2)
$24 - $30
Less: Misc. Other Expenses (including Legacy Liabilities' Cash Costs)(3)
($104) - ($109)
CNX Pro Rata Coal and Other Segment Adjusted EBITDA $205 - $235
34
Milestones:
Improving E&P performance from high-grading activities, improving completion techniques, reducing
cycle times, and service cost deflation
Adding two rigs while maintaining discipline on capital expenditures
Benefits from recent long-term contracting activities and operating cost reductions
CONE MLP growth – July 22nd announced 3.7% increase to quarterly distribution to $0.254 per unit,
the 5th consecutive increase since July 2015
Positive initial well results from operated dry Utica (Gaut 4IH, GH9, and Switz 6D)– sets up future
stacked pay opportunities
Improved free cash flow and opportunistic asset sales to de-lever
Marcellus Shale joint venture separation provides more control and flexibility for future development
Our management team is motivated and incentivized to generate FCF and NAV/share, which is
consistent with the metrics used in the short and long term incentive programs for 2016
Plans and Goals Aligned to Drive Increased Valuation
Key Takeaways
We will continue to be focused on increasing shareholder value while staying
within our core values of safety, compliance, and continuous improvement
35
Appendix
36
Non-GAAP Reconciliation: EBITDA and Adj. EBITDA
Appendix
Source: Company filings.
Note: Income tax effect of Total Pre-tax Adjustments was ($57,599) and ($54,680) for the three months ended September 30, 2016 and September 30, 2015, respectively. Adjusted
net income attributable to CONSOL Energy shareholders for the three months ended September 30, 2016 is calculated as GAAP net income from continuing operations of $62,568
less total pre-tax adjustments of $155,675, plus the tax expense of $57,599, equals the adjusted net loss from continuing operations of $35,508.
(1) CONSOL Energy's Other Division includes expenses from various other corporate and diversified business unit activities including legacy liabilities costs and income tax expense
that are not allocated to E&P or PA Mining Operations Divisions.
Three Months Ended Twelve Months Ended
September 30,
2016 2016 2016 2016 2015
($ in thousands)E&P
Division
PA Mining
Operations
Division
Other1 Total
Company
Total
Company
Net Income/(Loss) $161,075 $34,741 ($168,223) $27,593 $125,470
Less: Loss from Discontinued Operations - - 34,975 34,975 3,842
Add: Interest Expense 669 2,309 44,339 47,317 48,558
Less: Interest Income - - (214) (214) (361)
Add: Income Taxes Benefit - - 52,858 52,858 65,868
Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 161,744 37,050 (36,265) 162,529 243,377
Add: Depreciation, Depletion & Amortization 101,257 42,370 8,085 151,712 146,844
Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from
Continuing Operations $263,001 $79,420 ($28,180) $314,241 $390,221
Adjustments:
Unrealized Gain on Commodity Derivative Instruments (159,555) - - (159,555) (99,138)
Severance Expense 129 14 86 229 7,683
Pension Settlement - - 3,651 3,651 3,132
Gain on Sale of Western Allegheny - - - - (48,468)
OPEB Plan Changes - - - - (100,947)
Total Pre-tax Adjustments ($159,426) $14 $3,737 ($155,675) ($237,738)
Adjusted EBITDA $103,575 $79,434 ($24,443) $158,566 $152,483
Less: Noncontrolling Interest - (2,248) - (2,248) (6,490)
Adjusted EBITDA Attributable to Continuing Operations $103,575 $77,186 ($24,443) $156,318 $145,993
37
Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA
Appendix
Source: Company filings.
Three Months
Ended
Three Months
Ended
Three Months
Ended
Three Months
Ended
Twelve Months
Ended
December 31, March 31, June 30, September 30, September 30,
($ in thousands) 2015 2016 2016 2016 2016
Net Income / (Loss) $34,326 ($96,458) ($468,649) $27,593 ($503,188)
Less: Income from Discontinued Operations 11,017 53,167 234,605 34,975 333,764
Add: Interest Expense 49,081 49,865 47,427 47,317 193,690
Less: Interest Income (431) (214) (547) (214) (1,406)
Add: Income Taxes 125,742 (23,800) (100,856) 52,858 53,944
Earnings Before Interest & Taxes (EBIT) from Continuing Operations 219,735 (17,440) (288,020) 162,529 76,804
Add: Depreciation, Depletion & Amortization 139,988 154,988 135,220 151,712 581,908
Earnings Before Interest, Taxes and DD&A (EBITDA) from
Continuing Operations $359,723 $137,548 ($152,800) $314,241 $658,712
Adjustments:
OPEB Plan Changes (109,879) - - - (109,879)
Unrealized (Gain)/Loss on Commodity Derivative Instruments (62,388) 29,271 279,715 (159,555) 87,043
Pension Settlement 15,921 - 13,696 3,651 33,268
Industrial Supplies Working Capital Settlement 6,258 - - - 6,258
Gain on Sale of Non-core Assets (7,551) 13,735 - - 6,184
Severance Expense - 2,918 1,451 229 4,598
Coal Contract Buyout - - (6,288) - (6,288)
Total Pre-tax Adjustments ($157,639) $45,924 $288,574 ($155,675) $21,184
Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $202,084 $183,472 $135,774 $158,566 $679,896
Less: Noncontrolling Interest ($3,920) ($1,114) ($1,179) ($2,248) ($8,461)
Adjusted EBITDA Attributable to Continuing Operations $198,164 $182,358 $134,595 $156,318 $671,435
38
Free Cash Flow Reconciliation
Appendix
Source: Company filings.
Three Months Ended Nine Months Ended
September 30, September 30,
($ in thousands) 2016 2016
Net Cash provided by Continuing Operations 166,064$ 372,211$
Capital Expenditures (64,132) (179,389)
Net Investment in Equity Affiliates 1,023 (4,555)
Organic Free Cash Flow From Continuing Operations 102,955$ 188,267$
Net Cash Provided By Operating Activities 162,897$ 386,638$
Capital Expenditures (64,132) (179,389)
Capital Expenditures of Discontinued Operations 11 (8,284)
Net Investment in Equity Affiliates 1,023 (4,555)
Proceeds From Sales of Assets 20,693 38,977
Payments on Sale of Miller Creek and Fola Complexes (28,271) (28,271)
Proceeds From Sales of Buchanan Mine - 402,806
Total Free Cash Flow 92,221$ 607,922$