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TRANSCRIPT
SCOTIA HOWARD WEIL
2017 ENERGY CONFERENCE
MARCH 27-28, 2017
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 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, natural gas liquids, and coal, including due to oversupply relative to the demand available for our products; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately estimate the volume of hydrocarbons that are recoverable from our oil and natural gas assets; we may encounter unexpected operational issues or disruptions when we drill and mine, including equipment failures, geological conditions, and higher than expected costs for equipment, supplies, services and labor, including with respect to third-party contractors; 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 participation in joint ventures may restrict our operational and corporate flexibility, and actions taken by a joint venture partner may impact our financial position and operational results; with respect to the termination of the joint venture with Noble, any 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; we may not be able to sell non-core assets on acceptable terms; acquisitions and divestitures that we anticipate making or have made may not occur or produce anticipated benefits, or may cause disruptions to our business operations; we may be subject to environmental and other government regulations that adversely impact our operating costs and the market for our natural gas and coal; 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; we may be unable to incur indebtedness on reasonable terms; provisions in our multi-year coal sales contracts may provide limited protection and may result in economic penalties to us or permit the customer to terminate the contract; the majority of our common units in CNX Coal Resources LP are subordinated, and we may not receive related distributions; 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, 2016 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. Currently, 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 natural 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 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.
Who We Are: Differentiating Ourselves Through Three Pillars
3
Values:
• Never compromised regardless of circumstance
• Operate daily free of injuries and environmental incidents
• Pursuit of perfection driving towards best-in-class performance
• Mitigates business risk profile and supports license to operate in an industry that is subject to intense public scrutiny
Business philosophy:
• NAV/share focused
• Production growth is a byproduct
• Capital allocation process drives decision-making
• Delivering responsible, long-term value
Asset base:
• Substantial drilling inventory equates to scalable advantages
• Considerable percentage of held by production (HBP) acreage provides unique flexibility in development plans
• Largest stacked pay opportunity set in the lowest cost basin in the U.S.
• Marcellus JV separation unlocks significant stacked pay opportunities
The Path Forward: Realization of Value
4
How we plan to close the value gap:
Realization of Value...
Today $15.73 Closing price 3/20/2016 1 GROW EBITDA –
PRUDENT GROWTH OF E&P PRODUCTION EFFICIENT CAPITAL ALLOCATION TO HIGH IRR, NAV ACCRETIVE AOIs
PAY DOWN DEBT – ORGANIC FREE CASH FLOW AND ASSET MONETIZATIONS DRIVE LEVERAGE RATIO IMPROVEMENT BELOW TARGET OF 2.5x
REDUCE SHARE COUNT – OPPORTUNISTICALLY BUY BACK SHARES AS MARKET ALLOWS
2
3
$-
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
$35,000
$40,000
2015 2016
$ in
mill
ion
s
Weathered Downturn Without Issuing Equity
5
Since the beginning of 2014, total follow-on equity issued by Appalachian peers totaled $10.6 billion:
• All seven Appalachian peers have issued follow-on equity since the beginning of 2014
• CONSOL was able to de-lever the balance sheet and improve liquidity through organically growing free cash flow (FCF) and monetizing assets
• Avoiding issuing equity has resulted in not diluting shareholders and providing further upside potential
Source: Scotia Howard Weil Note: Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN
Follow-On Equity Issued Across Energy Industry 2015-2016
EXPLORATION & PRODUCTION
6
Continuous Improvement
7
0%
20%
40%
60%
80%
100%
120%
140%
160%
0.4
60
.60
0.7
80
.83
0.9
71
.04
1.2
71
.43
1.6
41
.95
2.0
42
.20
1.0
31
.09
1.2
41
.47
1.6
31
.85
1.9
81
.99
2.0
32
.16
2.1
92
.41
2.4
92
.55
1.2
71
.52
1.8
82
.22
2.4
32
.45
2.5
62
.64
2.7
12
.96
3.0
13
.11
3.6
03
.74
3.8
84
.34
2014 2015 2016
BTA
X IR
R (
%)
EUR/Capex (Mcfe/$)
Capital Efficiency
1.24 Mcfe/$ 1.83 Mcfe/$ 2.78 Mcfe/$
Note: Bars represent well-level economics, which includes total capital employed
NAV growth being driven by improved capital efficiency
Operational Evolution
8
Key Performance Metrics(1) 2014 2016E
Average EUR (Bcfe/1,000’) 1.4 2.8
Total Marcellus capital ($/ft) 1,345 835
Lease operating expense (LOE) ($/Mcfe) 0.41 0.19
Average drilling days on well 27 18
Average completion days on well 32 15
Completion stage spacing (ft) 300 150-225
Completion proppant volume (lbs/ft) 1,300 2,500-3,000
Improved operational performance:
• Lean manufacturing
• Supply chain management
• Zero-based budgeting
Sustained growth at lower $/EUR
(1) Combined Marcellus and Utica key performance indicators (KPIs)
Cumulative Production vs. Incremental Wells TIL by Year
0
10
20
30
40
50
60
70
80
0
100
200
300
400
500
2014 2015 2016
Incr
emen
tal W
ells
On
line
Cu
mu
lati
ve G
as P
rod
uct
ion
, BC
F
Marcellus-Utica Cumulative Production New Wells Online
64% increase in Marcellus core acreage:
• Full control of stacked pay opportunity set
• Incremental 85 MMcfe/d of production
• Further strengthens balance sheet
• Higher weighted average EUR, compared to pre-dissolution
Post-Exchange Marcellus Acreage Map
Dissolution of the Marcellus Shale Joint Venture
9
Marcellus Impact
Pre- JV Dissolution
Post- JV Dissolution
Change
Flowing PDP (MMcfe/d)
535 620 +16%
DUCs 37.5 53 +41%
Net acres (1) 336,000 306,000 (30,000)
Core(2) 99,000 162,000 +64%
Non-core(3) 237,000 144,000 (39%)
(1) Net acres include undeveloped only (2) Core: Prospective reservoir at current gas price forecast, de-risked by drilling, midstream, and market availability, with capacity for development and non-op potential (3) Non-Core: Non-prospective reservoir at current gas price forecast, acreage not a main driver, minor to no delineation, and minor to no non-op potential
New World View: Stacked Pay
10
Rhinestreet
Middlesex
Burkett
West River
Formation Name
Pay
Cashaqua
Tully
Hamilton
Marcellus
Onondaga
Utica
Point Pleasant
Trenton 0 GR 400 LITHOLOGY
• 40+ years of stacked pay inventory(1)
• The JV separation gives CONSOL complete operational control in stacked pay opportunities
• The Upper Devonian provides triple stacked pay potential, on top of Marcellus and Utica
• Stacked pays allow CONSOL to take advantage of a dry gathering system
• $0.10-$0.25/Mcfe Utica gathering
• Stacked pays take advantage of infrastructure sunk capital
(1) Stacked pay inventory includes core and non-core undeveloped acreage
Stacked Pay Value for SWPA: Pad Level Example
11
Stacked Pay Efficiencies
Unstacked Stacked Unstacked Stacked
LOE ($/Mcf) $0.12 $0.05 $0.15 $0.05
Gathering Rate ($/Mcf) $0.45 $0.39 $0.24 $0.18
Capital ($ in thousands) $5,900 $5,450 $13,200 $12,300
Dry Marcellus Dry Utica
Stacked pay development improves IRR by 10-20 percentage points
• Marginal horizons may be pulled into the development plan due to stacked pay economic improvement
• Stacked pay development concentrates large-scale operations in a small footprint
• Concurrently developing two horizons enables cost effective infrastructure build-out for both plays
• Significant reduction in both lifting and gathering operating costs due to higher volumes
(1) Assumes six Marcellus wells and four Utica wells per pad; 7,000’ laterals
Stacked Pay Pad Economics Example(1)
0%
20%
40%
60%
80%
100%
120%
$0
$20,000
$40,000
$60,000
$80,000
$100,000
$120,000
$140,000
$160,000
$2.00 $2.50 $3.00
BTA
X IR
R (
%)
BTA
X N
PV
($
in m
illio
ns)
Gas Price
Unstacked NPVStacked NPVUnstacked IRR %Stacked IRR %
Delineation Schedule (Gross Wells)
2016 2017 2018 2019
2 3 4 4
Moving Utica Non-Core to Core
12
Delineating the Utica through operated
and non-operated wells, data trades, and data purchases:
• Provides geologic and reservoir data to
evaluate NAV impact and helps assess
development risk
• 170,000 dry Utica core acres
• Potential to increase core position by
250,000+ acres by expanding the core
Delineation Opportunities
Non-Operated TIL Forecast (Gross Wells)
2016 2017 2018
Utica 13 17 15
X X X
GH-9 Greene Co. PA
3rd Party Harrison Co. OH
3rd Party Guernsey Co. OH
3rd Party Washington Co. PA
X
Aikens-5 Westmoreland Co. PA
X X
3rd Party Indiana Co. PA
3rd Party Monongalia Co. WV
X
MAJ-6 Marshall Co. WV
X
SWPA Prospect Allegheny Co. PA
X
CPA Prospect Westmoreland Co. PA
X
SWPA Prospect Greene Co. PA
X
SWPA Prospect Greene Co. PA
X
WV Prospect Monongalia Co. WV
X Jan-16 Jan-17 Jan-18 Jan-19 Dec-19
Stacked Pay with the Utica: The Size of the Prize
13
360,000+ Net Acres
20 Tcfe
Recoverable Resource in Place
5,000+ Triple Stacked Core Locations
40+ Years of Drilling
• 360,000 net acres of double stacked pay opportunity
in the core and non-core areas
• 180,000 core acres with double stacked pay opportunity
• Utica stacked pay delineation in the next 2 years drives
stacked pay development
• 30 Utica non-operated participation wells
• Concentrates the footprint of stacked pays: Upper Devonian
(Rhinestreet, Burkett), Marcellus and Utica
• Accelerates locations into the near-term plan by uplifting
lower value formations
• The Marcellus and Utica stacked pays supports a 4-rig
program for over 40 years
• Drilled 14 dry Utica wells and participated in 18 other wells
Two-Year Development Plan
14
• Consistently complete DUCs from December 2016 through 2018
- Total of 33 DUCs to be completed in two-year plan
• High value areas in Monroe County, OH and SWPA will be developed throughout 2017, 2018, and beyond
• Delineation prospects will continue to be drilled and evaluated
2017 2018TD FRAC TIL Capex TD FRAC TIL Capex
Marcellus 12 13 13 $80 54 42 40 $260
Utica 0 0 0 $0 3 3 3 $40
Upper Devonian - 2 3 $15 - - - -
Marcellus - 20 18 $95 - - 2 $10
3rd Party Marcellus 2 11 11 $5 4 - - $5
CPA Utica 2 2 2 $25 1 1 1 $15
Utica 17 22 22 $210 12 15 13 $140
3rd Party Utica 20 20 20 $15 16 16 16 $25
VA CBM 61 51 51 $20 28 33 33 $5
TOTAL(1) 31 59 58 $465 70 61 58 $500
SWPA
WV
OH
($ in millions)
(1) Total includes CONSOL-operated Marcellus, Utica, and Upper Devonian TD, Frac, and TIL for 2017E and 2018E
E&P Capital Expenditure Guidance
15
($ in millions) 2017E 2018E
Drilling and Completion $465
Midstream $40
Land, Permitting, and Other $50
Total E&P and Midstream Capital $555 $600
Total Production (Bcfe) 415 485
Expected Production Growth 5% 17%
2017E E&P Capital Plans
• Capital expenditure projections based on current market conditions and forecast
- Flexibility exists to adjust spending as necessitated by commodity fluctuations
• Increase in Land, Permitting, and Other capital driven by return to activity and blocking up acreage
• Running three rigs by end of 2017
• To hold 2016 production flat in 2017, maintenance capital would be approximately $250-$300 million
Drilling & Completions
84%
Midstream 6%
Land, Permitting, and Other
10%
E&P Capital and Production Plans
E&P Marketing: Gas Hedges
16
(1) Hedge positions as of 1/17/2017. FY 2017 includes actual settlements of 25.0 Bcf. (2) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements. (3) Based on total production guidance of 415 Bcfe in 2017E.
Hedged Open
Hedge Position (Outer ring = NYMEX; Inner ring = Basis)
2017
2018
020406080
100120140160180200220240260280300320
FY 2017 FY 2018 FY 2019 FY 2020 FY 2021
Gas
Vo
lum
es
He
dge
d (
Bcf
)
NYMEX Only Hedges Exposed to Basis
NYMEX + Basis (2)(2)
Hedge Volumes and Pricing 2017 2018 2019 2020 2021
NYMEX Only Hedges
Volumes (Bcf) 278.9 218.9 153.2 81.6 6.8
Average Prices ($/Mcf) $3.18 $3.15 $3.07 $3.17 $3.08
Index Hedges and Contracts
Volumes (Bcf) 32.4 1.7 8.5 3.4 -
Average Prices ($/Mcf) $3.19 $2.42 $2.52 $2.35 -
Total Volumes Hedged (Bcf) (1)311.3 220.6 161.7 85.0 6.8
NYMEX + Basis (fully-covered volumes)(2)
Volumes (Bcf) 287.1 182.4 108.6 57.0 -
Average Prices ($/Mcf) $2.57 $2.67 $2.60 $2.79 -
NYMEX Only Hedges Exposed to Basis
Volumes (Bcf) 24.2 38.2 53.1 28.0 6.8
Average Prices ($/Mcf) $3.18 $3.15 $3.07 $3.17 $3.08
Total Volumes Hedged (Bcf)(1)
311.3 220.6 161.7 85.0 6.8
• Approximately 75% of total 2017E production volumes hedged(3)
• NYMEX hedges added during Q4: 215 Bcf (2017-2021)
• Basis hedges added during Q4: 149 Bcf (2017-2020)
2017 2018 2019 2020 2020
DIVERSIFIED BUSINESS UNITS
17
CONSOL has a strong track record of successful divestitures:
• 20 NAV-enhancing divestitures since 2012
• Over $5 billion of combined value
Team is now focused on divesting E&P assets:
• Recent Marcellus JV separation provides more control and flexibility with asset base
• Continually evaluating NAV-accretive opportunities
CONSOL has a significant asset base:
• 60+ years of drilling inventory
• Acres all throughout the Appalachian basin in all horizons
Flexible approach:
• Outright sales
• Swaps and trades
• AMI / participations
• Acquisitions
2017 total asset sales target between $400-$600 million
Business Development: Strategy
18
Finance: Legacy Liabilities
19
Significant legacy liability reductions over
past three years: • Miller Creek/Fola transaction drove
substantial reduction in legacy liabilities
in 2016
• Continue to actively manage the reduction
of legacy liabilities
Balance Sheet Liability Long-Term Liability Guidance
12/31/2016 FY 2017E FY 2018E
LTD $19
WC 80 CWP 119
OPEB 700
Salary Retirement/Pension 115
Asset Retirement Obligations 233
Total Legacy Liabilities $1,266
Total Cash Servicing Cost $92 $74 - $79 $70 - $75
EBITDA Impact ($60 - $65) ($18 - $23) ($21 - $26)
$4,187
$1,703 $1,497
$1,362 $1,266 $1,229
$365
$144 $139 $133
$92$77
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
2012 2013 2014 2015 2016 2017E
An
nu
al C
ash
Se
rvic
ing
Co
sts
($ in
Mill
ion
s)
Lega
cy L
iab
iliti
es
($ in
mill
ion
s)
Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost
Note: 12/31/16 liability balance includes approximately $27 million and $40 million in employee-related and environmental liabilities associated with Pennsylvania Mining Operation (PAMC), respectively. Future EBITDA loss and cash servicing costs related to these liabilities will run through the PAMC segment financial detail and therefore the cash servicing costs and EBITDA loss related to these liabilities are excluded from the 2017 & 2018 forecast presented above. For FY 2017, the cash servicing costs associated with PAMC long-term liabilities are forecasted to approximate $8 million, while the EBITDA loss associated thereto is forecasted to approximate $12 million. Excludes gas well closing.
FINANCE
20
Financial Outlook: NAV/Share Value Drivers Accelerating
We expect growth while generating free cash flow:
• Stringent focus on capital allocation to drive the highest NAV per share decisions
• Become a leader in capital allocation, when compared to the best global companies
• Invest when rates of return are meaningfully higher than the cost of capital
• Reduce capital intensity across the whole enterprise
We have improved transparency and predictability:
• Extending out public forecasts across all business units
• Providing the tools to build out the NAV of the company
- Asset development provides 22 years of core development with large upside – JV dissolution reset
- Fast delineation of our acreage position to capture large NAV optionality
Our plan forecasts strengthening financial metrics:
• Maintain strong liquidity above $1.5 billion
• Improving credit metrics and leverage ratio below 2.5x
• Provide flexibility to finish separating the E&P and coal businesses
• Use the approximately $1 billion of free cash flow through 2018 to reduce debt and equity
• Drive down E&P cost of capital to 8% by year-end 2018
21
Conditions Improving for Complete Separation from CNXC
22
Path to Completing Separation from CNXC
Financial Conditions
Improving CNXC Performance
Capital Market Strength Reduction in financing costs
Growing revenue and margins
Growing CNX Free Cash Flow Greater sponsor flexibility
Pursuing 3 parallel paths:
- Outright sale
- Spin-off
- Additional dropdowns of undivided
interest into CNXC
Finance: Leverage Ratio and Liquidity Projection
23
(1) Leverage ratio equals expected year-end net debt divided by expected EBITDA. CONSOL Energy is unable to provide a reconciliation of projected 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.
(2) Excludes letters of credit of $243 million Note: Guidance as of 1/31/2017. Assumes $400-$600 million in asset sales in 2017 and a 20% CNXC drop in 2018 Forecasts based on strip pricing for open volumes as of 1/3/2017
• Year-end 2016 leverage ratio below prior forecast; 2017E and 2018E targets reduced by 0.2x and 0.3x, respectively
• Path to reaching and maintaining a sub-2.5x leverage ratio
• Liquidity rises by estimated $1 billion in free cash flow by 2018
• Plan Upside: - Increased efficiencies - Rising commodity prices - Accelerated drops - Additional asset sales
Leverage Ratio 2016-2018E(1)
Liquidity 2016-2018E
Asset Sales Organic
FCF Sources 2017E-2018E
4.4
2.2
1.4
0.0
1.0
2.0
3.0
4.0
5.0
2016 2017E 2018E
1.7
2.3
2.8
0.0
0.5
1.0
1.5
2.0
2.5
3.0
2016 2017E 2018E
$ in
bill
ion
s
(2) (2)
Finance: E&P Guidance
24
Note: Guidance as of 1/31/2017 (1) Excludes stock-based compensation (2) Includes Idle Rig Charges, Unutilized Firm Transportation Expense (Net Of 3rd Party Revenue), Land Rentals, Lease Expiration Costs, Misc. Gas, and Exploration Expense
E&P Segment Guidance 2017E 2018E
Production Volumes:
Natural Gas (Bcf) 375 445 NGLs (MBbls) 5,800 5,950 Oil (MBbls) 45 40 Condensate (MBbls) 740 730
Total Production (Bcfe) 415 485 % Liquids 10% 8%
Open Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.63) ($0.50) NGL Realized Price ($/Bbl) 19.70 19.50 Condensate Realized Price % of WTI 70% 70% Oil Realized Price % of WTI 90% 90%
Capital Expenditures ($ in millions):
Drilling and Completions $465 Midstream $40 Land, Permitting and Other $50
Total E&P and Midstream CapEx $555 $600 Average per unit operating expenses ($/Mcfe):
Lease Operating Expense 0.23 Production, Ad Valorem, and Other Fees 0.07 Transportation, Gathering and Compression 0.77
Total Cash Production and Gathering Costs 1.06 1.05
Other Expenses ($ in millions):
Selling, General, and Administrative Costs(1) $70 $70
Other Corporate Expenses(2) $80 $60
Finance: PA Mining Operations Guidance
25
• Capital expenditures expected to be approximately $5 per ton in 2017 and beyond
PA Mining Operations – Consolidated 100% Basis 2017E 2018E
Estimated Total Coal Sales Volumes (in millions of tons) 26.0 26.0 Total Committed Volumes (Contracted & Priced) 25.4
% Committed 98% Capital Expenditures ($ in millions):
Production $120 Other (Land/Water/Safety) $15 Total Coal Capital Expenditures ($ in millions) $135 $140
Note: Guidance as of 1/31/2017
Finance: 2017E EBITDA Guidance
26
(1) Includes forecasted Earnings of Equity Affiliates of $36 million in 2017 associated with CNX's proportionate share of ownership in CONE Midstream. This income is reflected within Miscellaneous Other Income in the CNX Income Statement.
Base plan assumes NYMEX as of 1/3/2017 $3.38 per MMBtu + weighted average basis of ($0.65) per MMBtu on open volumes. Note: Guidance as of 1/31/2017. CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.
EBITDA Guidance by Segment – 2017E
($ in millions) E&P(1) Coal Other Current
Total (1/31/17)
Prior Total
(12/13/16)
Earnings Before Interest, Taxes and DD&A (EBITDA)
$705 $390 ($15) $1,080 $840
Adjustments: Unrealized Loss/(Gain) on Commodity Derivative Instruments
(200) - - (200) (5)
Stock-Based Compensation 20 10 - 30 30
Adjusted EBITDA $525 $400 ($15) $910 $865
Noncontrolling Interest - (45) - (45) (45)
Adjusted EBITDA Attributable to CNX $525 $355 ($15) $865 $820
CONSOL Energy Represents a Unique Value Story
27
Focus on NAV/Share Growth
Driving NAV/share growth:
• Significant increases to estimated ultimate recoveries (EURs)
• Reducing drilling and completion (D&C) costs and capital intensity
• Proving up and de-risking reserves
• Accelerating activity
• Continued focus on de-levering the balance sheet
E&P Assets
Asset base is unique:
• Prolific stacked pay positions create significant competitive advantage
• Early efforts to delineate the Utica Shale are driving up net present value
(NPV) estimates
• Large inventory of acreage for potential monetization opportunities
Supplementary Value Drivers
Supplemental value drivers growing over time:
• Diversified Business Units (DBU), which includes:
- CONVEY Water Systems and the Baltimore Marine Terminal
• CNX Coal Resources LP
• CONE Midstream Partners LP
APPENDIX
28
Finance: Q4 2016 Review
29
Non-GAAP Reconciliation: EBITDA and Adjusted EBITDA
Source: Company filings. Note: Income tax effect of Total Pre-tax Adjustments was $90,956 and $36,257 for the three months ended December 31, 2016 and December 31, 2015, respectively. Adjusted net income for the three months ended December 31, 2016 is calculated as GAAP net loss from continuing operations of $321,198 plus total pre-tax adjustments from the above table of $245,826, less the associated tax expense of $90,956, plus a valuation allowance charge of $166,798 for alternative minimum tax credits equals the adjusted net income from continuing operations of $470. (1) CONSOL Energy's Other Division includes expenses from various other corporate and diversified business unit activities including legacy liabilities costs and income tax
expense that are not allocated to E&P or PA Mining Operations Divisions.
Three Months Ended
December 31,
2016 2016 2016 2016 2015
($ in thousands)
E&P Division
PA Mining
Operations
DivisionOther(1) Total Company Total Company
Net (Loss) Income ($222,454) $50,121 ($129,301) ($301,634) $34,325
Less: (Income) Loss from Discontinued Operations, net - - (19,564) (19,564) 11,017
Add: Interest Expense 646 2,502 43,719 46,867 49,081
Less: Interest Income - - (532) (532) (431)
Add: Tax Valuation Allowance - - 166,798 166,798 65,395
Add: Income Taxes - - (84,990) (84,990) 60,347
(Loss) Earnings Before Interest & Taxes (EBIT) (221,808) 52,623 (23,870) (193,055) 219,734
Add: Depreciation, Depletion & Amortization 105,730 42,861 7,992 156,583 139,988
(Loss) Earnings Before Interest, Taxes and DD&A (EBITDA) from
Continuing Operations ($116,078) $95,484 ($15,878) ($36,472) $359,722
Adjustments:
Unrealized Gain/(Loss) on Commodity Derivative Instruments 236,802 - - $236,802 (62,388)
Severance Expense - - 424 $424 -
Pension Settlement - - 4,848 $4,848 15,921
Marcellus Dissolution - - 3,752 $3,752 -
Industrial Supplies Working Capital Settlement - - - - 6,258
OPEB Plan Changes - - - - (109,879)
Gain on Sale of Non-Core Assets - - - - (7,551)
Total Pre-tax Adjustments $236,802 - $9,024 $245,826 ($157,639)
Adjusted EBITDA $120,724 $95,484 ($6,854) $209,354 $202,083
Less: Net Income Attributable to Noncontrolling Interest - 4,413 - 4,413 3,920
Adjusted EBITDA Attributable to Continuing Operations $120,724 $91,071 ($6,854) $204,941 $198,163
Finance: Q4 2016 Review
30
Non-GAAP Reconciliation: Trailing Twelve Months EBIT, EBITDA, and Adjusted EBITDA
Source: Company filings.
Three Months
Ended
Three Months
Ended
Three Months
Ended
Three Months
Ended
Year
Ended
March 31, June 30, September 30, December 31, December 31,
($ in thousands) 2016 2016 2016 2016 2016
Net Income / (Loss) ($96,458) ($468,649) $27,593 ($301,634) ($839,148)
Less: Loss from Discontinued Operations 53,167 234,605 34,975 (19,564) 303,183
Add: Interest Expense 49,865 47,427 47,317 46,867 191,476
Less: Interest Income (214) (547) (214) (532) (1,507)
Add: Tax Valuation Allowance - - - 166,798 166,798
Add: Income Taxes (23,800) (100,856) 52,858 (84,990) (156,788)
Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations (17,440) (288,020) 162,529 (193,055) (335,986)
Add: Depreciation, Depletion & Amortization 154,988 135,220 151,712 156,583 598,503
Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from
Continuing Operations $137,548 ($152,800) $314,241 ($36,472) $262,517
Adjustments:
Unrealized Gain/(Loss) on Commodity Derivative Instruments 29,271 279,715 (159,555) 236,802 386,233
Severance Expense 2,918 1,451 952 424 5,745
Pension Settlement - 13,696 3,652 4,848 22,196
Noble Transaction Fees - - - 3,752 3,752
Coal Contract Buyout - (6,288) - - (6,288)
Gain/(Loss) on Sale of Non-core Assets 12,636 - - - 12,636
Total Pre-tax Adjustments $44,825 $288,574 ($154,951) $245,826 $424,274
Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $182,373 $135,774 $159,290 $209,354 $686,791
Less: Noncontrolling Interest $1,114 $1,179 $2,248 $4,413 $8,954
Adjusted EBITDA Attributable to Continuing Operations $181,259 $134,595 $157,042 $204,941 $677,837
Finance: Q4 2016 Review
31
Free Cash Flow Reconciliation
Source: Company filings.
Three Months Ended Year Ended
December 31, December 31,
($ in thousands) 2016 2016
Net Cash provided by Continuing Operations $87,139 $459,350
Capital Expenditures (47,431) (226,820)
Net Investment in Equity Affiliates 78,298 73,743
Organic Free Cash Flow From Continuing Operations $118,006 $306,273
Net Cash Provided By Operating Activities $82,647 $469,285
Capital Expenditures (47,431) (226,820)
Net Investment in Equity Affiliates 78,298 73,743
Proceeds from Noble Exchange 213,295 213,295
Proceeds from Sale of Assets 20,925 59,902
Capital Expenditures of Discontinued Operations - (8,295)
Payments on Sale of Miller Creek/Fola - (28,271)
Proceeds from Sale of Buchannan Mine 1,000 403,817
Free Cash Flow $348,734 $956,656