analyst and investor day - cnx resources...
TRANSCRIPT
ANALYST AND INVESTOR DAY
December 13, 2016
Cautionary Language
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 joint venture partner, who operate assets in which we have a significant interest, may not perform as we expect and these and other circumstances could cause us not to realize the benefits we anticipate from our joint venture; we may not be able to sell non-core assets on acceptable terms; 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 sales contracts may provide limited protection and may result in economic penalties to us or permit the customer to terminate the contract; 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, 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. 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.
2
3
Agenda
Company Overview
Nick DeIuliis, President and CEO
Exploration & Production Tim Dugan, COO Andrea Passman, VP-E&P Development
Don Rush, VP-E&P Marketing
Diversified Business Units Steve Johnson, EVP-DBU Rodney Wilson, Director-Business Development
Marshall Roberts, Director-CONVEY Water Systems Katharine Fredriksen, SVP-DBU & Environmental Affairs
Financial Overview Dave Khani, CFO Chuck Hardoby, VP-Finance
Regulatory Update
Tommy Johnson, VP-Government & Public Relations
Closing Remarks
Nick DeIuliis
Q&A
Lunch / CNX Coal Resources LP Breakout Session
CONE Midstream Partners LP Breakout Session
Acquisition of Dominion Resources E&P assets tripling Marcellus Shale acreage position
4
CONSOL Energy’s Evolution
2014-2015 CONE Midstream Partners LP (NYSE: CNNX) formed with Noble Energy to provide gathering services in the Marcellus Shale and CNX Coal Resources LP (NYSE: CNXC) formed to house and manage CONSOL’s PA coal assets
2010 2013 2016 2016
Announces sale of five thermal coal mines in West Virginia to Murray Energy
With the sale of the Buchanan mine and other remaining legacy coal assets, CONSOL’s transformation into a premier natural gas Company is completed
2017+ CONSOL and Noble Energy announce separation of Marcellus JV, providing CONSOL with additional operational flexibility and the ability to reach leverage targets more rapidly
Looking to the future – working towards complete separation from coal; monetizing assets where possible; continuous operational improvement
+179% YTD
CONSOL Energy Has Continued to Transform Itself in 2016
RBL
Reaffirmation
Restarted Drilling
(Accelerated
Schedule)
NBL JV
Resolution Buchanan Sale
Jan 2016 Today
P2AA Asset Optimization
(Phase 2)
Zero-Based Budgeting
P2AA Asset Optimization
(Phase 1)
Integrated
Model
Miller Creek & Fola Sale
Re-org (Streamlined Operations &
Planning)
Turned DUC Inventory
Online
Restructured Agreement
with
Penguins
CNX Share Price YTD 2016(1)
Capital Allocation
Driven
Cash
Stabilization CNXC/
CNNX Drops
5
(1) As of 12/7/2016
$0
$5
$10
$15
$20
$25
Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16
Who We Are: Differentiating Ourselves Through Three Pillars
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
6
Business Philosophy: Zero-Based Budgeting in Action
Transformed balance sheet:
• Reduced legacy liabilities by $3 billion
Reduced expenses:
• Cash servicing costs reduced by more than $250 million since 2012
Transformed culture:
• Executive compensation less than half 2012 levels
- Compensation widely aligned with shareholders’ interests
• Executive perks and benefits eliminated; exited arena naming rights agreement, providing significant cost savings
-61%
(1) Includes corporate jets/hangar, membership fees, and arena naming fees (2) Annual legacy liability cash servicing costs
Overhead(1)
Executive Pay
Legacy Liabilities(2)
Selling G&A
2012 2016E
7
Reductions in Expenses 2012-2016E
The Path Forward: Realization of Value
How we plan to close the value gap:
Realization of Value...
Today $22.05 Closing price 12/7/2016 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
8
$-
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
$35,000
$40,000
2015 YTD 2016
$ in
mill
ion
s
Weathered Downturn Without Issuing Equity
9
Since the beginning of 2014, total follow-on equity issued by Appalachian peers totaled $10.6 billion:
• All seven Appalachian peers have issued follow-on equity since the beginning of 2014
• CONSOL was able to de-lever the balance sheet and improve liquidity through organically growing free cash flow (FCF) and monetizing assets
• Avoiding issuing equity has resulted in not diluting shareholders and providing further upside potential
Source: Scotia Howard Weil Note: Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN
Follow-On Equity Issued Across Energy Industry FY2015-YTD 2016
CONSOL Energy Represents a Unique Value Story
10
Focus on NAV/Share Growth
Driving NAV/share growth:
• Significant increases to estimated ultimate recoveries (EURs)
• Reducing drilling and completion (D&C) costs and capital intensity
• Proving up and de-risking reserves
• Accelerating activity
• Continued focus on de-levering the balance sheet
E&P Assets
Asset base is unique:
• Prolific stacked pay positions create significant competitive advantage
• Early efforts to delineate the Utica Shale are driving up net present value
(NPV) estimates
• Large inventory of acreage for potential monetization opportunities
Supplementary Value Drivers
Supplemental value drivers growing over time:
• Diversified Business Units (DBU), which includes:
- CONVEY Water Systems and the Baltimore Marine Terminal
• CNX Coal Resources LP
• CONE Midstream Partners LP
EXPLORATION & PRODUCTION
11
E&P Operations: NAV/Share Drivers
12
CONVERTING NON-CORE ACREAGE TO CORE
MAJOR OPERATIONAL IMPROVEMENTS SINCE 2014
STACKED PAY OPPORTUNITIES
Continuous Improvement
0%
20%
40%
60%
80%
100%
120%
140%
160%
0.4
60
.60
0.7
80
.83
0.9
71
.04
1.2
71
.43
1.6
41
.95
2.0
42
.20
1.0
31
.09
1.2
41
.47
1.6
31
.85
1.9
81
.99
2.0
32
.16
2.1
92
.41
2.4
92
.55
1.2
71
.52
1.8
82
.22
2.4
32
.45
2.5
62
.64
2.7
12
.96
3.0
13
.11
3.6
03
.74
3.8
84
.34
2014 2015 2016
BTA
X IR
R (
%)
EUR/Capex (Mcfe/$)
Capital Efficiency
1.24 Mcfe/$ 1.83 Mcfe/$ 2.78 Mcfe/$
13
Note: Bars represent well-level economics, which includes total capital employed
NAV growth being driven by improved capital efficiency
E&P Industry: F&D Costs
Source: Scotia Howard Weil: 2015 F&D Cost Study Note: Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN (1) (Land Acquisition Costs + Exploration + Development)/Drilling Reserve Additions
CONSOL has had some of the lowest F&D costs in the industry over the last five years
Drilling Finding and Development Cost 5-yr. Average 2011-2015(1)
14
$0.80
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
1 2C
NX 3 4 5 6 7
$/M
cfe
Technological Evolution Driving Growth
15
Tools and Procedures 2014 2016E
Earth model - ✔
Fracture simulation - ✔
Reservoir simulation - ✔
Rate transient analysis (RTA) - ✔
Risk analysis - ✔
Portfolio NAV optimization - ✔
NAV/Share Growth Drivers Since 2014:
• 100% increase in EUR/1,000'
• 38% improvement in capital deployment
• 54% reduction in lease operating expense (LOE) ($/Mcfe)
• 40% of dry Utica acreage converted from non-core to core
Operational Evolution
16
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
0
100
200
300
400
500
600
700
0 10 20 30 40 50
Cum
pro
d (
MM
cfe
/1,0
00')
Normalized months
CNX 1/2014 - 5/2015 CNX 6/2015+
0
500
1,000
1,500
2,000
CNX 1 2 3 4 5 CNX 2014 - 5/2015
Mcfe
/d
3 Mo (20:1) 6 Mo (20:1) Avg 3 Mo (20:1) Avg 6 Mo (20:1)
Well Performance Over Time
17
Horizontal well production per 1,000’ since June 2015 – CNX vs. Peers
142% Increase
Source: IHS Enerdeq via Credit Suisse Note: Peers include CVX, EQT, RICE, RRC, Vantage
CNX Well Performance Improved well performance:
• Enhanced completions design
• Optimized landing points
• Managed pressure drawdown
Large Acreage Position
CNX vs. Appalachian Peers – Acreage Position and Production
18
Only 4% of total Marcellus and Utica Shale inventory developed to date:
• 8% of the Marcellus acreage developed
- Marcellus 90% HBP
• 1% of the Utica acreage developed
- Utica 91% HBP
• 60+ years(1) of production runway in inventory
• 89% net revenue interest (NRI)
• 22 years of inventory in stacked pay in core areas(2)
(1) Inventory calculated assuming 100 wells drilled per year (2) Stacked pay core areas include Marcellus and Utica
720,000 615,000
406,000
640,000
480,000
175,000 200,000
490,000
400,000
608,000
370,000
375,000
160,000
210,000
0
500
1,000
1,500
2,000
2,500
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1 2 CNX 3 4 5 6 7
Dai
ly P
rod
uct
ion
(M
Mcf
e/d
)
Net
Acr
es
Marcellus Utica Q3 Daily Production
19
New World View: Assets Before and After JV Separation
SWPA WV CPA OH Total Total Change
Upper Devonian Net Acres 102,000 112,000 21,000 - 235,000 280,000 (45,000)
Net Acres 98,000 61,000 232,000 15,000 406,000 436,000 (30,000)
Fee Acres 32,000 1,000 20,000 3,000 56,000 41,000 15,000
Approx. Net Locations (1)
533 370 1,465 116 2,484
Net Producing Wells (PDPs) 188 34 60 1 283 258 25
Net Acres 119,000 162,000 208,000 119,000 608,000 623,000 (15,000)
Fee Acres 42,000 8,000 12,500 36,000 98,500 100,000 (1,500)
Approx. Net Locations(1)
673 987 1,177 517 3,354
Gross Producing Wells (PDPs) 1 - 1 94 96 97 (1)
Marcellus
Utica
Post-JV Dissolution Pre-JV Dissolution
(1) Total net locations calculated from modeling inputs expected lateral lengths and spacing for each respective asset region and formation
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
20
Dissolution of the Marcellus Shale Joint Venture
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
Development Optimization
Production Modeling
Engineering Workflow Drives Decisions
21
Earth Modeling
NPV/Well
Portfolio Risk Analysis
Rate Transient Analysis
Forecasting
ITERATIVE CYCLE
3D Frac Modeling
Asset Region 1: Southwest Pennsylvania Overview
22
Marcellus Shale average EUR/1,000’ of lateral increased 29% to 2.7 Bcfe(1)
• Total net acres: 98,000
• Total NRI: 89%
• Sizable capital expenditure in the next 2 years
• 2 rigs in 2017 and 3 rigs in 2018
Utica Shale
• Average EUR/1,000’ of 3.1 Bcf(1)
• Total net acres: 119,000
• Total NRI: 89%
• Continue to delineate through participation and drilling
Upper Devonian Shale
• Total net acres: 102,000
• 3 wells expected to be turned in line (TIL) in 2017
(1) Average EUR represents the type curve guidance area depicted on the map Note: Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx
64% Utica/Marcellus core over core acreage overlap
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
7000' LL
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
8500' LL
Southwest Pennsylvania Modeling Inputs and Economics
23
SWPA Marcellus Type Curve (2.7 Bcfe/1000')
SWPA Utica Type Curve (3.1 Bcf/1000')
BTAX ROR % (3)
Realized Price 8,500'
$2.00 39%
$2.50 71%
$3.00 109%
BTAX ROR % (3)
Realized Price 7,000'
$2.00 19%
$2.50 34%
$3.00 52%
(1) Assuming 8,500 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing (3) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.
Assumptions
IP (MMcfe/d) 19.0
Decline 69%
B-factor 1.65
EUR/1000’ (Bcfe) 2.7
Lateral Length 8,500’
Wells Per Pad 6
Capital ($ millions) $7.1
Fixed Cost ($/mo./well) $730
LOE ($/Mcfe) $0.12
Gathering ($/Mcfe) $0.48
Reserves Detail
Gross EUR (Bcfe) 22.6
BTU 1,130
Assumptions
IP (MMcf/d) 23.1
Decline 67%
B-factor 1.20
EUR/1000’ (Bcf) 3.1
Lateral Length 7,000’
Wells Per Pad 5
Capital ($ millions) $13.2
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Gathering ($/Mcf) $0.23
Interest / Net Locations
WI / NRI (%) 100% / 89%
Net Locations(1) ~533
Wells Online (9/30/16) 188
Reserves Detail
Gross EUR (Bcf) 21.4
BTU 1,010
Interest / Net Locations
WI / NRI (%) 100% / 89%
Net Locations(2) ~673
Wells Online (9/30/16) 1
Asset Region 2: West Virginia Overview
24
Marcellus Shale average EUR/1,000’ of lateral increased 61% to 2.9 Bcfe(1)
• Total net acres: 61,000
• Total NRI: 86%
• Focus on completing DUC inventory: sunk capital results in improved IRR
Utica Shale
• Average EUR/1,000’ of 2.8 Bcf
• Total net acres: 162,000
• Total NRI: 88%
• Delineation through participation
(1) Average EUR represents the type curve guidance area depicted on the map Note: “CNX Utica Resource Potential” as depicted on the map represents an additional 220,000 acres of Utica resource potential in WV not included in company totals Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx
14% Utica/Marcellus acreage overlap
0
10,000
20,000
30,000
40,000
50,000
0
100,000
200,000
300,000
400,000
0 12 24 36 48
NG
L/C
ND
Pro
du
ctio
n (
BB
L/m
on
th)
Gro
ss G
as P
rod
uct
ion
(M
cf/m
on
th)
Months After TIL
Gas
NGL
CND
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
6500' LL
BTAX ROR % (4)
Realized Price 6,500'
$2.00 10%
$2.50 20%
$3.00 31%
25
West Virginia Modeling Inputs and Economics
WV Marcellus Type Curve (2.9 Bcfe/1000')
BTAX ROR % (4)
Realized Price 8,000'
$2.00 37%
$2.50 56%
$3.00 76%
(1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 6,500 ft lateral @ 1,100 ft inter-lateral spacing (3) See NGL and CND assumptions on type curve data file located at www.consolenergy.com (4) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.
WV Utica Type Curve (2.8 Bcf/1000')
Assumptions
IP (MMcf/d) 14.0
Decline 69%
B-factor 1.65
EUR/1000’ (Bcfe) 2.9
Lateral Length 8,000'
Wells Per Pad 6
NGL Yield (Bbl/MMcf)(3) 74.1
CND Yield (Bbl/MMcf)(3) 12.8
Capital ($ millions) $6.6
Fixed Cost ($/mo./well) $730
LOE ($/Mcf) $0.12
Gathering/Processing
($/Mcf) $0.93
NGL OpEx ($/Bbl) $5.00
CND OpEx ($/Bbl) $5.00
Reserves Detail
Gross EUR (Bcfe) 22.8
BTU 1,260
Interest / Net Locations
WI / NRI (%) 100% / 86%
Net Locations(1) ~123
Wells Online (9/30/16) 34
Assumptions
IP (MMcf/d) 15.3
Decline 58%
B-factor 1.10
EUR/1000’ (Bcf) 2.8
Lateral Length 6,500'
Wells Per Pad 3
Capital ($ millions) $12.7
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Gathering ($/Mcf) $0.23
Reserves Detail
Gross EUR (Bcf) 17.9
BTU 1,015
Interest / Net Locations
WI / NRI (%) 100% / 88%
Net Locations(2) ~987
Wells Online (9/30/16) -
Asset Region 3: Central Pennsylvania Overview
26
Marcellus Shale
• Average EUR/1,000’ of 1.8 Bcf(1)
• Total net acres: 232,000
• Total NRI: 88%
• Weighted average EUR/1000’ for the entire region is 1.5 Bcf
• Evaluate Marcellus development in conjunction with Utica
Utica Shale average EUR/1,000’ of lateral up 17% to 3.5 Bcf
• Total net acres: 208,000
• Total NRI: 89%
• Continued drilling expected in 2017 and 2018
• 2 wells planned in 2017 and 1 well in 2018
• Non-operated participation opportunities
(1) Average EUR represents the type curve guidance area depicted on the map, which is approximately 111,000 acres in CPA Note: “CNX Utica Resource Potential” as depicted on the map represents an additional 22,000 Utica resource potential in CPA not included in company totals Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx
96% Utica/Marcellus acreage overlap
0
100,000
200,000
300,000
400,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
9000' LL
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
1,000,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
7000' LL
27
Central Pennsylvania Modeling Inputs and Economics
CPA Marcellus Type Curve (1.8 Bcf/1000')
BTAX ROR % (3)
Realized Price 9,000'
$2.00 23%
$2.50 39%
$3.00 62%
CPA Utica Type Curve (3.5 Bcf/1000')
(1) Assuming 9,000 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing (3) Escalation not applied to gas pricing, capex, and opex (4) IP held flat for 14 months at 21.6 MMcf/d Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.
BTAX ROR % (3)
Realized Price 7,000'
$2.00 63%
$2.50 107%
$3.00 152%
Assumptions
IP (MMcf/d) 13.3
Decline 69%
B-factor 1.65
EUR/1000’ (Bcf) 1.8
Lateral Length 9,000'
Wells Per Pad 6
Capital ($ millions) $6.2
Fixed Cost ($/mo./well) $730
LOE ($/Mcf) $0.12
Gathering ($/Mcf) $0.32
Reserves Detail
Gross EUR (Bcf) 15.8
BTU 1,000
Interest / Net Locations
WI / NRI (%) 100% / 88%
Net Locations(1) ~1,465
Wells Online (9/30/16) 60
Assumptions
IP (MMcf/d)(4) 21.6
Decline 74%
B-factor 1.20
EUR/1000’ (Bcf) 3.5
Lateral Length 7,000'
Wells Per Pad 6
Capital ($ millions) $12.6
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Gathering ($/Mcf) $0.23
Reserves Detail
Gross EUR (Bcf) 24.8
BTU 1,010
Interest / Net Locations
WI / NRI (%) 100% / 89%
Net Locations(2) ~1,177
Wells Online (9/30/16) 1
28
Asset Region 4: Ohio Overview
Total Ohio Utica:
• Total net acres: 119,000
• Total NRI: 89%
Utica Dry:
• Average EUR/1,000’ of 2.8 Bcfe(1)
• 23,000 net undeveloped acres
• Continued development of Monroe County
• 101 net locations
Utica Wet:
• Average EUR/1,000’ of 2.1 Bcfe(2)
• 42,000 net undeveloped acres
• Continue to monitor pricing for continued development
• 305 net locations
(1) Average EUR represents the type curve guidance area depicted on the map by a solid blue line (Utica Dry) (2) Average EUR represents the type curve guidance area depicted on the map by a dotted blue line (Utica Wet) Note: Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx
0
5,000
10,000
15,000
20,000
25,000
30,000
0
100,000
200,000
300,000
400,000
500,000
0 12 24 36 48
NG
L/C
ND
Pro
du
ctio
n (
BB
L/m
on
th)
Gro
ss G
as P
rod
uct
ion
(M
cf/m
on
th)
Months After TIL
Gas
NGL
CND
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
9000' LL
29
Ohio Modeling Inputs and Economics
OH Wet Utica Type Curve (2.1 Bcfe/1000')
OH Dry Utica Type Curve (2.8 Bcf/1000')
BTAX ROR % (4)
Realized Price 8,000'
$2.00 13%
$2.50 27%
$3.00 47%
BTAX ROR % (4)
Realized Price 9,000'
$2.00 55%
$2.50 90%
$3.00 127%
Assumptions
IP (MMcf/d) 16.3
Decline 71%
B-factor 1.40
EUR/1000’ (Bcfe) 2.1
Lateral Length 8,000’
Wells Per Pad 5
NGL Yield (Bbl/MMcf)(3) 32.6
CND Yield (Bbl/MMcf)(3) 4.0
Capital ($ millions) $7.6
Fixed Cost ($/mo./well) $1,371
LOE ($/Mcf) $0.29
Gathering/Processing
($/Mcf) $0.78
NGL OpEx ($/Bbl) $6.78
CND OpEx ($/Bbl) $6.25
Assumptions
IP (MMcf/d) 20.4
Decline 56%
B-factor 1.10
EUR/1000’ (Bcf) 2.8
Lateral Length 9,000’
Wells Per Pad 4
Capital ($ millions) $9.4
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Gathering ($/Mcf) $0.21
Ohio Wet - Reserves Detail
Gross EUR (Bcfe) 16.9
BTU 1,150
Ohio Wet - Interest / Net Locations
WI / NRI (%) 50% / 45%
Net Locations(2) ~305
Ohio Dry - Reserves Detail
Gross EUR (Bcf) 25.0
BTU 1,060
Ohio Dry - Interest / Net Locations
WI / NRI (%) 100% / 89%
Net Locations(2) ~101
OH Utica Total
Net Locations(1) ~517
Wells Online (9/30/16) 94
(1) Assuming average 8,500 ft lateral @1,100’ spacing (2) Assuming 8,000 ft and 9,000 ft lateral @ 1,100’ spacing for Ohio Wet and Ohio Dry, respectively (3) See NGL and CND assumptions on type curve data file located at www.consolenergy.com (4) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.
Virginia Coalbed Methane
Virginia coalbed methane (CBM): • 267,000 net acres
- 88,000+ undeveloped acres - WI / NRI: 100% / 87.5%
• 4,000+ wells online - 3,690 future locations - 0.5 Bcf/well average EUR - 2,000+ refrac opportunities
• Net production: 182 MMcf/d - Annual decline rate of approximately 5-7% - Access to multiple markets: TCO, ETNG Mainline,
Transco Zone 5
30
Capex(1) Opex(2) D&C Cycle Time(3)
2015 $300,000 $1.63 93 2016E $223,000 $1.42 29 2017E $215,000 $1.20 19
(1) Average combined capital per well (2) Cash costs ($/Mcf) (3) Days spud to TIL Note: Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx
0%
10%
20%
30%
40%
50%
60%
$2.50 $2.75 $3.00 $3.25 $3.50
Future Locations Refracs
38%
28%
CBM IRR
Development Methodology
31
CONSOL utilizes a portfolio
optimization development methodology to: • Assess the value of the assets
within the portfolio to drive decision making targeted towards maximizing NAV/share
• Assess the risk associated with developing the assets within the portfolio
• Determine investment, acquisition and divesture opportunities to optimize E&P portfolio
Asset
Assessment
GIS Mapping
Geology/ Reservoir
Engineering
Land, Title, JAD
Marketing Water Midstream Drilling,
Completion, Production
Purchase Additional FT
Land Swap Potential
Build Pipeline/ infrastructure
Water Optimization Opportunities
Pick up/ Lay Down
Rigs
Complete DUCs
1722
(200)
(100)
-
100
200
300
400
-
50
100
150
200
250
300
2016
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2040
$M
M
Ne
t M
mcf/
d
Monroe Optimized CaseAvg Daily Production Net wells drilled
Cumulative PV (Secondary)
Performance Studies Portfolio Classification Asset Development and Optimization Monte Carlo Risk Analysis
New World View: Stacked Pay
Rhinestreet
Middlesex
Burkett
West River
Formation Name
Pay
Cashaqua
Tully
Hamilton
Marcellus
Onondaga
Utica
Point Pleasant
Trenton 0 GR 400 LITHOLOGY
32
• 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-$0.25/Mcfe Utica gathering
• Stacked pays take advantage of infrastructure sunk capital
(1) Stacked pay inventory includes core and non-core undeveloped acreage
Stacked Pay Value for SWPA: Pad Level Example
33
Stacked Pay Efficiencies
Unstacked Stacked Unstacked Stacked
LOE ($/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 %
Stacked Pay Value for SWPA Marcellus: Well Level
34
0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
200%
1.3
2
1.3
8
1.5
6
1.6
5
1.7
5
2.0
5
2.3
9
2.4
2
2.5
0
2.6
4
2.6
6
2.6
6
2.6
9
2.7
8
2.8
2
2.8
7
2.9
5
2.9
5
2.9
6
3.2
2
3.2
5
3.2
7
3.3
4
3.3
8
3.4
5
3.9
1
3.9
7
4.0
6
4.1
9
4.2
2
4.3
3
4.7
2
5.5
0
BTA
X IR
R (
%)
EUR/Capex (Mcfe/$)
Unstacked Stacked Pay
2016 Capital Efficiency
Stacked Pay Potential
Capital Efficiency Mcfe/$
Unstacked (actual) 2.78
Stacked (potential) 3.02
Change +9%
BTAX IRR +15 percentage points
Stacked Pay Optimization: Richhill Field
• 33% NPV uplift due to stacked pay development
• 17,000 Marcellus acres with Utica rights
• Marcellus damp gas on its own requires processing
• Blending Marcellus with dry Utica gas allows the avoidance of processing costs
• Concurrent development of Marcellus and Utica reduces capex and opex and increases combined NPV
• 100% WI provides CONSOL ability to maximize field NPV through stacked pay development flexibility
35
Richhill Optimization
Richhill Case Study
Marcellus Utica Stacked % Difference
Well Count 125 123 248 N/A
BTU 1,130 1,015 1,070 N/A
Opex ($/Mcfe) $1.16 $0.32 $0.41 -46%
Capex ($ in millions) $829 $2,007 $2,630 -7%
NPV ($ in millions) $317 $389 $939 +33%
Upper Devonian: Rhinestreet and Burkett
Provides triple stacked pay potential, on top of Marcellus and Utica
• 235,000 net acres
• 16 operated Upper Devonian wells
• Combination with Marcellus and Utica development driven by gas price trigger
0%
10%
20%
30%
40%
50%
60%
70%
$2.00 $2.50 $3.00 $3.50 $4.00
BTA
X IR
R (
%)
$/MMBtu
36
SWPA 7000’ Burkett
Delineation Schedule (Gross Wells)
2016 2017 2018 2019
2 3 4 4
37
Moving Utica Non-Core to Core
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
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
0
5,000
10,000
15,000
20,000
25,000
30,000
9/23/15 1/1/16 4/10/16 7/19/16 10/27/16 2/4/17
Cas
ing
Pre
ssu
re (
psi
)
Flo
w R
ate
(Mcf
/d)
Flow Rate MCf/Day Casing Pressure
• Consistent reservoir and geologic conditions indicate additional wells in the Gaut area should have similar performance
Gaut 4IH 61.4 MMcf/d IP Initial SICP = 9,921 psig 5,808’ Lateral Length 7.8 Bcf by 01/2017
38
Why We Love the Utica: Gaut 4IH Westmoreland County, PA
Testing period Mcf/d
Stacked Pay with the Utica: The Size of the Prize
39
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
• 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
40
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
($ in millions) 2016E 2017E 2018E
Drilling and Completion $175 $465
Midstream $20 $40
Land, Permitting, and Other $10 $50
Total E&P and Midstream Capital $205 $555 $600
Total Production (Bcfe) 395 415 485
Expected Production Growth 20% 5% 17%
41
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 2016E 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
42
E&P Marketing: NAV/Share Drivers
43
MAXIMIZING CASH FLOW AT THE WELLHEAD
FLEXIBLE FT STRATEGY TO MINIMIZE COSTS AND ENSURE PRODUCTION GROWTH
SIGNIFICANT HEDGE BOOK PROTECTING DOWNSIDE, WHILE PRESERVING MEANINGFUL UPSIDE
E&P Marketing
44
Ability to deal with the increasing uncertainty in a volatile marketplace:
• A consistent, yet flexible strategy is necessary to help mitigate the uncertainty
• Strategic and tactical expertise
Contributing to NAV/share through a "barbell" strategy: • Previously focused primarily on providing operational support
• Focused now on providing strategic support that drives corporate decisions
• Planning, revenue management, and hedging are now one fluid process
• Ensuring near-term financial success while adding future value through additional hedging and new
approaches
Programmatic Hedging
• Create incremental free cash flow (FT cost & capacity optimization, ensure gas flow, diverse sales portfolio)
• Asset management agreements
• Dry / Wet optionality
• Arbitrage pipeline flexibility, create 3rd party opportunities
• Utilize flexibility
CURRENT & NEAR TERM
LONGER TERM
• Enhanced risk management
• Capital allocation protection
• Develop arbitrage opportunities and new diversified netbacks
• Maintain efficient flexibility
• Additional margin
& balance sheet protection
Increased Volatility
45
U.S. LNG Export Forecast Current infrastructure and systems are not built to handle new gas market:
• Storage capacity has remained the same, while supply has increased significantly
- 50 Bcf/d in 2005 vs. approximately 75 Bcf/d in 2017
• Existing supply quickly falls, over 20% per year, if drilling slows
• Demand sensitivity to price and weather is increasing significantly
- LNG and Mexican exports - Increased power and heating use
• A supply and demand imbalance of only 2 Bcf/d on average for a year, is the difference between an alarmingly high inventory level coming out of winter and an alarmingly low inventory level coming out of winter
The system is bigger and more volatile on both the supply and demand sides with the same amount of storage, leading to increased volatility
$0
$1
$2
$3
$4
$5
$6
$7
Henry Hub and Dominion South Pricing (Historical First of Month and Forward Strip)
Dominion South Henry Hub
Source: Morningstar
Source: Historical prices-SNL; Strips- Intercontinental Exchange and CME
Volatility Can Be Good
46
Take-away capacity is coming to the region:
• Over 18 Bcf/d of projects in process: question of when, not if
• Only need half to come online by 2018 to support the expected production growth
• It will all eventually come online to allow a visible growth path for the next 5+ years
A normal or colder-than-normal winter will have a large effect:
• Inventory levels are not excessively higher than they have been in the past
• The demand pull on the system is higher than it has ever been (power, heating, Mexico, LNG)
Working Gas Inventory (Bcf):
• Region proven it can handle approximately 7 Bcf/d of extra supply
• Supply relative to demand and storage can swing positive as quickly as they have swung negative, and CONSOL is positioned to succeed under either situation
Projected Basin Takeaway Capacity
Year Year Prior Max Year Min. Avg. NYMEX Price
2014 3,834 824 $4.42
2013 3,928 1,674 $3.65
2016E 4,009 2,468 $2.46
2017E 4,017 ? $3.25
Source: Historical Supply-Spring Rock; Demand + Takeaway and Supply Potential-various public sources, CONSOL interpretation
Source: EIA
-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
Ave
rage
MM
cf/d
Demand + Takeaway Capable Excess
AVG Supply Supply Potential
The Benefits of Flexible Firm Transportation
47
FT strategy:
• Sufficient short- and long-term FT at a cost lower than peers going to markets that maximize netbacks without over-committing
- Use FT, IT, AMAs, customers’ capacity, varying terms, releases, etc.
• NYMEX differentials in-line with peer average, with 1/8 of the average “take-or-pay” FT obligation of peers
• Keep basis differentials lower than the cost of greenfield FT prices
• Proactively ensure CONSOL can grow production
Basis plan will utilize:
• A unique sales focus for each market
• Strategically selecting FT
• Diversified sales portfolio
• Programmatic basis hedges placed years in advance
• Opportunistic basis hedges when appropriate
(1) Company filings as of Q3 2016; gas price differentials based on first nine months of 2016 Note: Peers include AR, CHK, COG, EQT, GPOR, RICE, RRC, SWN
$(2.00)
$(1.50)
$(1.00)
$(0.50)
$-
$0.0
$2.0
$4.0
$6.0
$8.0
$10.0
$12.0
$14.0
$16.0
$18.0
$20.0
CNX 1 2 3 4 5 6 7 8
Dif
f. t
o N
YMEX
($
/MM
Btu
)
Tota
l Ob
ligat
ion
s ($
in b
illio
ns)
Transportation, Gathering, & Processing Commitments and Differentials(1)
FT, Gathering, and Processing Obligations
Gas Price Diff. to NYMEX
Peer Average Gas Price Diff to NYMEX
The Benefits of Flexible Firm Transportation (Cont’d)
48
Avoiding long-term, burdensome FT on new projects that go underwater:
• Many greenfield project demand fees appear to exceed the forecasted price uplift at various basis locations
• Short-term gains will be minimal compared to long-term deterioration
• Avoiding significant, long-term exposure to out-of-the-money positions
$-
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
$0.70
$0.80
$0.90
2018 2019 2020 2021 2022 2023
Esti
mat
ed
$/D
th
Future Spreads vs. Estimated Demand Fees(1)
Project A Spread Project B Spread Project A Calculated Fee Project B Calculated Fee
(1) Project costs were obtained from FERC filings; demand fees conservatively estimated using only expected project costs and an assumed 15% rate of return
Firm Transportation Management
49
Diversified sales and FT portfolios:
• Result in competitive basis differentials and
balanced basket of prices
• Strategically aligned with the best AMA partners in
our markets to optimize asset value and realize
other tangible benefits
• In-basin exposure mitigated through basis hedge
program and diversified sales mix
Positioned significantly ahead of peers as
in-basin market stays volatile: • Peers’ expensive long-haul FT cost will fluctuate
with netbacks being in and out of the money
• Will limit their flexibility and tend to worsen with
time as more costs hit their income statements
and they face minimum volume commitments in
more recent contracts
0
200
400
600
2016 2017 2018
Bcf
Sales Portfolio Market Mix
In Basin Open In Basin Hedged East Coast Total
Far Midwest Total Gulf Total
In-Basin Prices and Basis 2017E-2022E
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
2017 2018 2019 2020 2021 2022
An
nu
al P
rice
($
/MM
Btu
)
TETCO M2 NYMEX
Source: Intercontinental Exchange and CME
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
MM
Btu
/d
Cumulative NYMEX Hedges Cumulative Basis Hedges
Hedging Strategy
50
Newly instituted programmatic hedge program:
• Systematically layering in hedges to protect margins on up to 90% of proved developed production
• Protecting from in-basin blowout through regional basis hedges
• Lock in revenue: Match NYMEX and basis hedge volumes
We are hedging PDP volumes out to 2020:
• Systematic approach protects from market downturns
• Increased drilling activity and opportunistic hedge program capture market upswings, de-risking capital decisions
Hedge Position (Outer ring = NYMEX; Inner ring = Basis)
Hedge Volumes and Pricing FY 2017 FY 2018 FY 2019 FY 2020
NYMEX Only Hedges Volumes (Bcf)
233.8
187.3
124.3
62.1
Average Prices ($/Mcf) $ 3.08 $ 3.13 $ 3.07 $ 3.19
Index Hedges and Contracts
Volumes (Bcf) 32.4 - 6.8 3.4 Average Prices ($/Mcf) $ 3.19 - $ 2.54 $ 2.35
NYMEX + Basis (fully-covered volumes) Volumes (Bcf)
263.8
177.3
103.5
53.7
Average Prices ($/Mcf) $ 2.52 $ 2.66 $ 2.61 $ 2.79
NYMEX Only Hedges Exposed to Basis Volumes (Bcf)
2.4
10.0
27.6
11.8
Average Prices ($/Mcf) $3.08 $ 3.13 $ 3.07 $ 3.19
Total Volumes Hedged (Bcf)(1) 266.2 187.3 131.1 65.5
(1) Hedge position as of 12/7/16. Includes financial and physical hedges.
Hedged Open Hedged Open
2017 2018
Hedges made across different years and different
sales points for basis throughout the year
NGL Strategy
51
Processing flexibility on a third of wet volumes:
• Avoid processing fees when NGL pricing is low
• Capture NGL uplift during peak pricing
• Leverage dry Utica blend-stock
Plant optionality on nearly half of wet volumes:
• Optimize on residue gas takeaway
• Enhance NGL marketability
• Drive down costs through competition
Direct ethane sales netbacks tracking Mt. Belvieu pricing:
• Achieved without burdensome FT commitment
• Equivalent of selling gas with a +$0.68/MMBtu basis
40% of C3+ in 2017-2018 expected to be sold internationally:
• Exposure to multiple price points
• Over half of production will stay domestic to feed increasingly attractive markets
2017 Direct Ethane Sales Netback Estimate(1)
Gas $ High
Gas $ Low
NGL $ Low NGL $ High
Avoid Processing
Optimize Send to Processing
Optimize
22 Bcf
Wet Gas Flexibility
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
2017
Eth
ane
($/g
al)
Mt. Belvieu Ethane CNX Netback Appalachian Gas Alternative
(1) As of 11/28/16 forward strip (2) Avoiding approximately $0.16/gal cost and long-term commitment to obtain Mt. Belvieu pricing
(2)
Key Marketing Financial Parameters
52
(1) Based on 12/6/2016 strip prices
Expected Market Mix 2017E 2018E
Columbia (TCO) 14% 16%
TETCO (M2) 38% 41%
TETCO (M3) 12% 7%
Dominion (DTI) 15% 13%
East Tennessee 9% 7%
TETCO ELA & WLA 6% 5%
Midwest (Michcon) 6% 11%
100% 100%
Estimated utilized firm transportation demand expense ($ in millions) $77.2 $108.4
Estimated firm transportation demand expense per unit of production ($/Mcf) $0.21 $0.24
Expected average basis w/o regard to hedging (based on market mix) ($/Mcf) (1) ($0.63) ($0.50)
Expected average basis, including hedges currently in place ($/Mcf) (1) ($0.58) ($0.47)
Volumes with basis currently hedged (Bcf) 263.8 177.3
Average price of basis hedges currently in place ($/Mcf) ($0.62) ($0.47)
% of production 70% 40%
DIVERSIFIED BUSINESS UNITS
53
Diversified Business Units: NAV/Share Drivers
54
$400-$600 MILLION IN 2017 ASSET SALES
GROWING MISCELLANEOUS OTHER EBITDA
SIGNIFICANTLY REDUCING LEGACY LIABILITIES
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-$600 million
55
Business Development: Strategy
Other Miscellaneous: Income and Expense Sources
Miscellaneous Other Income 2016E 2017E 2018E
Baltimore Terminal
Royalty Income
Right of Way Sales
CONVEY Water Systems
Rental Income & Other
Miscellaneous Other Costs 2016E 2017E 2018E
Baltimore Terminal
Lease Rental Expense
Coal Reserve Holding Cost
CONVEY Water Systems
Long-Term Liabilities
Bank Fees and Other
Net of Income and Cost ($MM) -$60 to -$65 -$15 to -$20 -$10 to -$15
56
Increasing value from a range of often overlooked sources:
CONVEY Water Systems
57
Provides water related services for CNX and third party upstream E&P companies:
• Fresh water delivery for well completion operations
• Recycle and disposal of produced fluids
• One of the largest water pipeline network in Appalachia
• 2017E water life cycle management of approximately 2.8 million gal/day
• Rapid expansion of 3rd party customer base
• Leverage expansive pipeline system and surface acreage position to achieve best in class operating cost
• Volumetric service fee structure provides revenue and operating cash flow
Organic value creation through spin-off or drop-down opportunity
• Highly attractive midstream EBITDA valuation multiple (9.0x – 12.0x)
Projected 2017 EBITDA of approximately $50 million
Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items. 2017 EBITDA projection is based on rates charged to CNX Gas, which are subject to change
CONVEY Water System Assets Marcellus Utica Other Total
Water Pipelines (Miles) 291 18 216 525
Storage Impoundments 8 1 9
Water Sourcing Dams 2 2
UIC Well 1 1
2017 CONVEY Capex ($MM) 15 10 25
2017 Water Pipelines (Miles) 10 15 25
2017 Storage Impoundments - - -
Total 2017 Infrastructure
Water Pipelines (Miles) 301 33 216 550
Storage Impoundments 8 1 - 9
Water Source 2 2
UIC well 1 1
Baltimore Marine Terminal
58
Overview: • Coal export terminal
• 15 million tons per year capacity throughput; 1.1 million tons coal storage yard capacity
• Strategically located: able to access the attractive seaborne markets supplying both Europe and Asia
• The only coal export terminal on the East Coast served by two railroads: Norfolk Southern and CSX Corporation
Note: 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.
2016 achievements: • Baltimore Terminal expected to generate approximately $15 million in EBITDA for a projected 8.5 million ton
throughput, despite challenging coal export market conditions in 2016
• Opened the terminal up for throughput capacity from third party shippers: Signed 3 million tons in 2017 (with take or pay provisions) from third party shipping contracts in addition to legacy contracts of 12 million tons reserve (not take or pay)
• Achieved significant service and operating cost efficiencies in 2016
2017 outlook: • Strong met and stronger thermal export market indications provide reasonable expectation of 9-10 million
ton throughput providing $19-$22 million of EBITDA
• Cost savings of at least $1 million from scheduling and supply chain optimization
Recent Transactions: Legacy Assets
59
Buchanan Mine transaction:
• Includes potential royalty payment based on rising met coal prices
- 20% royalty on export sales of any excess of the gross FOB mine sales price over certain minimums that increase each year and end after five years
• Solid met coal pricing in recent quarters has positioned CNX to receive a royalty in Q4 2016
• 2017 forecasted EBITDA associated with the Buchanan royalty is forecasted to be between $10-$20 million
Miller Creek / Fola transaction:
• Eliminated small non-core coal operation
• Removed $100 million of long-term liabilities from CONSOL’s balance sheet
• Sold approximately 230 million and 185 million tons of reserves or resources, respectively, in the two complexes
Example Average Buchanan Mine Monthly Export Price(1) $ 150.00
Royalty Threshold Price (Year 2) $ 78.75
Average Export Sales Price Over Threshold $ 71.25
Royalty 20%
Royalty Revenue Per Ton at 20% $ 14.25
Example Annual Export Tons(1) 2,500
Example Annual Royalty Revenue ($ millions)(2) $ 35.6
(1) Average monthly export price and export ton quantity for example purposes only (2) Due to uncertainty in metallurgical coal markets, CONSOL uses a risked view for planning purposes Note: 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.
Example 2017 Royalty Calculation
Financial: Legacy Liabilities
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
60
Balance Sheet Liability Long-Term Liability Guidance
12/31/2016E FY 2017 FY 2018
LTD $17
WC 82 CWP 125
OPEB 655
Salary Retirement/Pension 89
Asset Retirement Obligations 227
Total Legacy Liabilities $1,194
Total Cash Servicing Cost $95 $74 - $79 $70 - $75
EBITDA Impact ($60 - $65) ($18 - $23) ($21 - $26)
Note: 12/31/16 liability balance includes approximately $33.5 million and $34.1 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 LTL are forecasted to approximate $8.1 million, while the EBITDA loss associated thereto is forecasted to approximate $11.9 million. Excludes gas well closing.
$4,187
$1,703 $1,497 $1,362
$1,194
$365
$144 $139 $133
$95
$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
$4,500
2012 2013 2014 2015 2016E
An
nu
al C
ash
Ser
vici
ng
Co
sts
($ in
mill
ion
s)
Lega
cy L
iab
iliti
es (
$ in
mill
ion
s)
Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost
FINANCE
61
Finance: NAV/Share Drivers
62
REDUCING COST OF CAPITAL
CAPITAL ALLOCATION
IMPROVING FORECASTING CAPABILITY AND TRANSPARENCY
Financial Accomplishments Since 2014
Reduced Debt
By attacking all parts of our business, we have reduced the nominal and per unit spend by 45% and 55%, respectively.
Paid down approximately $1 billion in debt
Managed Legacy Liabilities
Reduced legacy liabilities by approximately $300 million and annual cash service costs by approximately $50 million
Launched Two MLP IPOs
Created CNXC and CONE Midstream MLPs to provide clarity for investors and followed each IPO with an additional drop
Drove Down Operating Costs
Dramatically reduced operating costs to be competitive with top-tier Appalachian E&Ps
Lowered SG&A Incorporated zero-based budgeting and substantially reduced SG&A with a range of initiatives
63
Tools to Grow NAV/Share
64
Safety
Compliance
Operating Efficiencies
Liability Management
Capital Allocation
Revenue Management
NAV/Share Growth
Prudent capital allocation is one of the most important tools to grow NAV/share; a clear and consistent methodology to assess capital allocation options and make decisions is essential.
Zero-Based
Budgeting
Capital Allocation Decision Making
Production
KEY PERFORMANCE METRICS
Proved Reserves
Borrowing Base PV9
Discount Rate
Free Cash Flow
Liquidity
NAV/Share
Managing Risk Appropriately Throughout the Commodity Cycle
Leverage Ratio
CAPITAL SOURCES CAPITAL USES
• Pulling back capital spend/activity level
• Selling assets/drop downs
• Issuing debt
• Issuing equity
• Reducing dividends/distributions
• Developing high rate of return Marcellus and Utica opportunities
• Paying down/buying back debt
• Buying back equity to reduce share count
• Paying dividends/distributions
• Acquiring assets (M&A)
65
2017E-2018E E&P Capital Allocation
66
Note: Based on D&C capital
Ranking projects and capital allocation priorities 2017E-2018E
Full Well IRR
Sunk Cost IRR
DUCs
CPA Utica
OH Dry Utica
SWPA Marcellus
VA CBM SWPA Utica
0%
10%
20%
30%
40%
50%
60%
70%
IRR
Benchmarking: Capital Yield Has Been Improving
67
Note: Methodology and 2014-2016E peer estimates from KLR Group. CNX 2016E-2018E based on internal plan. Capital Yield = E&P Operating Cash Margin / (CapEx/Change in Production) * Initial Recovery Percentage. Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN.
• Focused on improving capital yield through reducing capital intensity and operating costs
• Disciplined capital spending through the downturn positioned the company to dramatically improve its 2016 and 2017 capital yield
• Driving down operational expenses have improved cash margins in a depressed pricing environment
• As operational initiatives continue to take root, CONSOL is expected to maintain capital efficiency levels well above historical averages
-20%
30%
80%
130%
180%
1 2 3 4 5 6 7 CNX -20%
30%
80%
130%
180%
1 2 3 4 5 6 7 CNX -20%
30%
80%
130%
180%
CNX 1 2 3 4 5 6 7
2014: Capital Yield 2015: Capital Yield 2016E: Capital Yield
CONSOL Capital Yield 2014-2018E
-20%
30%
80%
130%
180%
2014 2015 2016E 2017E 2018E
-
50
100
150
200
250
300
2012 2013 2014 2015 2016E 2017E 2018E
$ in
mill
ion
s
Cash SG&A Expense Stock Compensation
SG&A Nominal and Unit Reductions
$0.55
$0.31
$0.20
$0.00
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
2014 2015 YTD 2016
SG&
A S
pen
d (
$/M
cfe(2
) )
CNX E&P E&P Peers Average
Total Company SG&A(1) 2012-2018E
(1) Historical years recast to align with current reporting. Total includes stock compensation and short-term incentive compensation in all periods. (2) Cost per Mcfe excludes stock-based compensation. Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN.
• Initial declines tied to asset divestitures
• Implemented zero-based budgeting in 2015
• Reduction of top five executive pay by combined approximately 50%
• Termination of various corporate perks and arena naming rights
• Reorganized to be able to fully separate E&P and coal in 2017
Since 2014, CONSOL Energy has reduced its SG&A $/Mcfe faster than its peers
68
SG&A $/Mcfe 2014-YTD 2016
Improving Transparency: E&P Guidance
Note: Forecast based on strip pricing as of 11/3/2016 close (1) Excludes stock-based compensation (2) Includes Idle Rig Charges, Unutilized Firm Transportation Expense (Net Of 3rd Party Revenue), Land Rentals, Lease Expiration Costs, Misc. Gas, and Exploration Expense
69
E&P Segment Guidance 2016E 2017E 2018E
Production Volumes:
Natural Gas (Bcf) 348 375 445 NGLs (MBbls) 6,740 5,800 5,950 Oil (MBbls) 70 45 40 Condensate (MBbls) 860 740 730
Total Production (Bcfe) 395 415 485 % Liquids 12% 10% 8%
Open Natural Gas Basis Differential to NYMEX ($/Mcf), as of 11/03/16 ($0.60) ($0.63) ($0.50) NGL Realized Price ($/Bbl) 14.00 16.00 16.50 Condensate Realized Price % of WTI 70% 70% 70% Oil Realized Price % of WTI 90% 90% 90%
Capital Expenditures ($ in millions):
Drilling and Completions $175 $465 Midstream $20 $40 Land, Permitting and Other $10 $50
Total E&P and Midstream CapEx $205 $555 $600 Average per unit operating expenses ($/Mcfe):
Lease Operating Expense 0.26 0.23 Production, Ad Valorem, and Other Fees 0.08 0.07 Transportation, Gathering and Compression 0.93 0.77
Total Cash Production and Gathering Costs 1.27 1.06 1.05
Other Expenses ($ in millions):
Selling, General, and Administrative Costs(1) $70 $70 $70
Other Corporate Expenses(2) $70 $80 $60
PA Mining Operations Guidance
70
• Due to mines being well capitalized, CNXC was able to reduce capital spending on discretionary projects to offset the challenging coal market conditions, heading into 2016
• Capital expenditures expected to revert to the approximately $5 per ton starting in 2017 and beyond
PA Mining Operations 2016E 2017E 2018E
Estimated Total Coal Sales Volumes (in millions of tons) 24.0 26.5 26.5
Total Committed Volumes (Contracted & Priced) 23.3 23.1
% Committed 97% 87%
Capital Expenditures ($ in millions):
Production $70 $120
Other (Land/Water/Safety) $20 $15
Total Coal Capital Expenditures ($ in millions) $90 $135 $140
EBITDA Guidance
(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.
(2) Base plan assumes NYMEX as of 11/3/2016 $2.99 + basis of ($0.70). Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.
EBITDA Guidance by Segment – 2017E
EBTIDA Sensitivity to E&P Price Fluctuations vs. Plan
71
($ in millions) E&P(1) Coal Other Total
EBITDA $465 $390 ($15) $840
Adjustments:
Unrealized Gain Loss on Hedging ($5) - - ($5)
Stock-Based Compensation $20 $10 $0 $30
Adjusted EBITDA $480 $400 ($15) $865
Less: Noncontrolling Interest - ($45) - ($45)
Adj. EBITDA Attributable to CNX $480 $355 ($15) $820
2017E E&P
Base Plan(2)
(strip pricing as of 11/3/16)
Open Price (NYMEX + Basis) $1.30 $1.80 $2.30 $2.80 $3.30
EBITDA ($ in millions 690 760 820 890 960
Leverage Ratio 3.0x 2.7x 2.4x 2.1x 1.9x
E&P Reserves Guidance
72
Note: Reserve estimates follow the same approach used for calculating year-end SEC Proved Reserves. Pricing based on forward curve as of 11/03/16.
Reserves Growth Estimates 2014-2018E (Net)
2014 2015 2016E 2017E 2018E
Assumed 12 mo. average price $/MMBtu $4.35 $2.59 $2.48 $2.99 $2.94
Marcellus/Utica PUD well count (net) 458 126 201 373 485
6,200
8,000
11,000
6,827
5,643 5,800 6,500
9,000
$-
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
0
2,000
4,000
6,000
8,000
10,000
12,000
2014 2015 2016E 2017E 2018E
Ass
um
ed 1
2 M
o. A
vera
ge P
rice
$/M
MB
tu
Bcf
e
Reserves Estimated Range Assumed 12 Mo, Average Price $/MMBTUAssumed 12 Mo. Average Price ($/MMBtu)
0.7x
1.8x 1.7x
1.3x
2.4x
2.8x
3.5x 3.4x
0.6x
1.3x 1.4x 1.5x 1.7x
2.3x 2.4x 2.7x
-
1.0x
2.0x
3.0x
4.0x
1 2 3 4 CNX 5 6 72017 Net Debt/EBITDA 2018 Net Debt/EBITDA
• Enables the company to weather volatility in commodity prices and limits the risk that leverage ratio moves into the commercial banks perceived danger zone of 3.5x or higher
• Protects liquidity; can avoid selling assets, tapping capital markets, or hedging at the bottom of cycle
• Provides additional protection in the event of a split; as E&P loses the coal cash flow and diversification benefits, the company will be smaller and have more concentration risk (as will CNXC)
• Low leveraged names in a weak market avoid a discount to share price.
2017 peer average: 2.2x(1)
2018 peer average: 1.7x
Cost of Capital: Leverage Ratio Target Between 2.0x to 2.5x
• Provides the financial flexibility to grow NAV per share through several means: drilling pace, buybacks, delineation drilling of our non-core assets, and M&A
• Maintains optimal cost of capital, enabling access to the capital markets throughout the cycle if the opportunities arise
• Increases ability to sell assets from a position of strength and maximize NAV per share
• Low leveraged names in a normal market receive a premium attached to share price
(1) Peer leverage ratios based on consensus EBITDA and consensus net debt (Capital IQ). (2) Forecasts based on strip pricing for open volumes as of 11/3/2016; assumes $400-$600 million in asset sales in 2017 and a 20% CNXC drop in 2018. Note: 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.
CNX AR
EQT
RICE RRC
CHK
ECR
COG
SWN DVN
WPX
NBL
GPOR XEC
CRK
XCO
APA QEP
BBG
SD
R² = 0.8945
-
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
(80%) (60%) (40%) (20%) - 20%
20
15
YE
Net
Deb
t/EB
ITD
A
Esti
mat
e
Stock Performance, 12/1/14 to 7/7/15
73
Leverage vs. Stock Performance Industry Leverage Ratios 2017E-2018E
Importance of the Target: Offense Importance of the Target: Defense
(2)
Leverage Ratio and Liquidity Projection
(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.
Note: 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 11/3/2016
• Path to reaching and maintaining a sub-2.5x leverage ratio
• Liquidity rises by estimated $1 billion in free cash flow by 2018
• Bank revolver reaffirmed at $2 billion for fall 2016
• Plan Upside: - Increased efficiencies - Rising commodity prices - Accelerated drops - Additional asset sales
74
Leverage Ratio 2016E-2018E(1)
Liquidity 2016E-2018E
Asset Sales Organic
FCF Sources 2017E-2018E
4.7
2.4
1.7
0.0
1.0
2.0
3.0
4.0
5.0
2016E 2017E 2018E
1.7
2.3
2.7
0.0
0.5
1.0
1.5
2.0
2.5
3.0
2016E 2017E 2018E
$ in
bill
ion
s
E&P WACC History
(1) Risk free rate is 30 year TTM risk free rate (2) Peer beta is average 2 year beta. Peers include APC, RICE, COG, PDCE, GPOR, CHK, AR, SWN, EQT Note: Forecasts based on strip pricing for open volumes as of 11/3/2016
8%
9%
10%
11%
Jan2016
Feb2016
Mar2016
Apr2016
May2016
Jun2016
Jul 2016 Aug2016
Sep2016
Oct2016
Nov2016
CNX E&P WACC Over Time
Measures taken to manage WACC:
• Created strong modeling predictability
• Reduced SG&A
• Reduced leverage ratio
• Improved liquidity
• Increased production
• Reduced unit costs
• Reduced interest expense
• Continued NYMEX and basis hedging
Goals:
• Further reduce debt
• Repurchase high cost equity
• Improve outlook and E&P team coverage from ratings agencies
Sample WACC Calculation
CNX E&P Cost of Capital Nov-16
Equity
Risk Free Rate(1) 2.6%
Beta (Peer Beta)(2) 1.4
Equity Market Risk Premium 6.5%
Cost of Equity 11.7%
Debt
Risk Free Rate (TTM) 2.6%
Spread To Treasury 5.5%
Pre-Tax Cost of Debt 8.1%
Marginal Tax Rate 38.0%
After Tax Cost of Debt 5.0%
Enterprise ($ in millions)
Market Capitalization 4,045
Market Value Net Debt 3,042
Enterprise Value 7,087
WACC 8.8%
75
Annual E&P WACC 2014 2015 2016
11.2% 10.1% 8.8%
CONE Midstream Drives Value to CONSOL Energy
CONE Midstream Partners LP value to CNX is comprised of four main drivers:
How CNX views the total value of CONE Midstream Partners LP:
Retained EBITDA Cash Distributions Drop Downs Ownership of LP and GP/IDR
76
CONE Value Streams to CNX($ in millions, except per share data) 2016E 2018E
IDRs
Cash Flow 1.87$
Multiple 30.0x
Ownership 50.0%
Value 28$
LP Units
Unit Price 21.00$
Current Yield 4.9%
Units Held 21.69
Distributions through 2018 -
Value 456$
CONE Gathering
Pro Rata EBITDA Contribution to CNX
Adjusted EBITDA 29.6
Market Multiple 9.0x
Value 267$
Total Potential Value 750$ 1,100$
Value per CNX Share 3.27$ 4.80$
Note: 2018 valuation is based on preliminary estimates
$267
$456
$28
$750
2016E
Retained EBITDA LP Units IDRs
CONE Value to CNX 2016E
CONE Distributions Expected to Grow Meaningfully
(1) CAGR based on potential LP distribution growth cases
77
Net to CNX GP & IDR Distribution Cases
Net to CNX LP Distribution Cases
$0
$10
$20
$30
$40
$50
2015 2016 2017 2018 2019 2020 2021
$ in
mill
ion
s
10% CAGR 15% CAGR 20% CAGR
$0
$10
$20
$30
$40
$50
$60
2015 2016 2017 2018 2019 2020 2021
$ in
mill
ion
s
10% CAGR 15% CAGR 20% CAGR
2017E
Retained EBITDA LP Units Cash Distributions
CNXC: Value of CNX Passive Ownership in PA Operations
75% ownership of PA Mining Complex
16.6 million total LP units held by CNX(2)
CNX % LP Units' share 60.1%
CNX % GP Units' share 1.7%
CNX Total % Interest in
CNXC 61.8%
Base plan to drop remaining ownership over multiple years
CNXC Value Representation(1)
(1) Graph not indicative of actual CNXC valuation to CNX (2) LP units of various classes, on an as-converted basis (3) Unit price as of market close 12/1/2016
78
CNX Coal Resources LP value to CNX is comprised of four main drivers:
Retained EBITDA Cash Distributions Drop Downs Ownership of LP and GP/IDR
CNXC Value Streams to CNX(units and $ in millions, except per share data)
2017E Cash Distributions (LP&GP)
Common Units 9.7$
Subordinated Units 23.8$
GP Units 1.2$
Total 2017E Cash Distributions 34.7$
LP Units
Unit Price(3) 18.40$
Units Held 16.6
LP Unit Value 305.8$
CNXC EBITDA Contribution to CNX
2017E Retained EBITDA 400.0$
Total combined interest in PA Mining Ops: 90%
Conditions Improving for Complete Separation from CNXC
79
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
Base plan: Multi-Year Drops
- Forecast assumes 20% drop in 2018
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
80
REGULATORY UPDATE
81
Core Themes Driving the CONSOL Value Story
82
OPERATIONAL IMPROVEMENT
Increasing EURs
Decreasing Costs
Disciplined Capital Spending
UNIQUE ASSET BASE
Robust Stacked Pay Opportunities
Turning Non-Core Acreage to Core
Supplemental Value Streams
CAPITAL ALLOCATION
Growing Free Cash Flow
Improving Balance Sheet
Path to Share Repurchases
GROWING NAV/Share
Q&A
83