ANALYST AND INVESTOR DAY
December 13, 2016
INVESTOR DAY December 13, 2016 Cautionary Language This - - PowerPoint PPT Presentation
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).
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
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
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
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
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:
that is subject to intense public scrutiny
Business philosophy:
Asset base:
unique flexibility in development plans
6
Business Philosophy: Zero-Based Budgeting in Action
Transformed balance sheet:
Reduced expenses:
$250 million since 2012
Transformed culture:
2012 levels
shareholders’ interests
exited arena naming rights agreement, providing significant cost savings
(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
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
8
$- $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 $40,000 2015 YTD 2016 $ in millions
Weathered Downturn Without Issuing Equity
9
Since the beginning of 2014, total follow-on equity issued by Appalachian peers totaled $10.6 billion:
and improve liquidity through organically growing free cash flow (FCF) and monetizing assets
diluting shareholders and providing further upside potential
Source: Scotia Howard Weil Note: Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN
Follow-On Equity Issued Across Energy Industry FY2015-YTD 2016
CONSOL Energy Represents a Unique Value Story
10
Focus on NAV/Share Growth Driving NAV/share growth:
E&P Assets Asset base is unique:
(NPV) estimates
Supplementary Value Drivers Supplemental value drivers growing over time:
11
E&P Operations: NAV/Share Drivers
12
CONVERTING NON-CORE ACREAGE TO CORE MAJOR OPERATIONAL IMPROVEMENTS SINCE 2014 STACKED PAY OPPORTUNITIES
Continuous Improvement
0% 20% 40% 60% 80% 100% 120% 140% 160% 0.46 0.60 0.78 0.83 0.97 1.04 1.27 1.43 1.64 1.95 2.04 2.20 1.03 1.09 1.24 1.47 1.63 1.85 1.98 1.99 2.03 2.16 2.19 2.41 2.49 2.55 1.27 1.52 1.88 2.22 2.43 2.45 2.56 2.64 2.71 2.96 3.01 3.11 3.60 3.74 3.88 4.34 2014 2015 2016 BTAX IRR (%) EUR/Capex (Mcfe/$)
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 2 CNX 3 4 5 6 7 $/Mcfe
Technological Evolution Driving Growth
15
Tools and Procedures 2014 2016E Earth model
Fracture simulation
Reservoir simulation
Rate transient analysis (RTA)
Risk analysis
Portfolio NAV optimization
NAV/Share Growth Drivers Since 2014:
Operational Evolution
16
Key Performance Metrics(1) 2014 2016E Average EUR (Bcfe/1,000’) 1.4 2.8 Total Marcellus capital ($/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:
Sustained growth at lower $/EUR
(1) Combined Marcellus and Utica key performance indicators (KPIs)
Cumulative Production vs. Incremental Wells TIL by Year
10 20 30 40 50 60 70 80 100 200 300 400 500 2014 2015 2016 Incremental Wells Online Cumulative Gas Production, BCF Marcellus-Utica Cumulative Production New Wells Online
100 200 300 400 500 600 700 10 20 30 40 50 Cum prod (MMcfe/1,000') Normalized months CNX 1/2014 - 5/2015 CNX 6/2015+ 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:
Large Acreage Position
CNX vs. Appalachian Peers – Acreage Position and Production
18
Only 4% of total Marcellus and Utica Shale inventory developed to date:
developed
developed
runway in inventory
stacked pay in core areas(2)
(1) Inventory calculated assuming 100 wells drilled per year (2) Stacked pay core areas include Marcellus and Utica
720,000 615,000 406,000 640,000 480,000 175,000 200,000 490,000 400,000 608,000 370,000 375,000 160,000 210,000 500 1,000 1,500 2,000 2,500 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1 2 CNX 3 4 5 6 7 Daily Production (MMcfe/d) Net Acres 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
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
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)
673 987 1,177 517 3,354 Gross Producing Wells (PDPs) 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:
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)
next 2 years
Utica Shale
participation and drilling
Upper Devonian Shale
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
100,000 200,000 300,000 400,000 500,000 600,000 700,000 12 24 36 48
Gas Production (Mcf/month) Months After TIL
7000' LL
100,000 200,000 300,000 400,000 500,000 600,000 12 24 36 48
Gas Production (Mcf/month) 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)
inventory: sunk capital results in improved IRR
Utica Shale
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
10,000 20,000 30,000 40,000 50,000 100,000 200,000 300,000 400,000 12 24 36 48
NGL/CND Production (BBL/month) Gross Gas Production (Mcf/month) Months After TIL
Gas NGL CND 100,000 200,000 300,000 400,000 500,000 600,000 12 24 36 48
Gas Production (Mcf/month) 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
the entire region is 1.5 Bcf
in conjunction with Utica
Utica Shale average EUR/1,000’
2017 and 2018
well in 2018
(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
100,000 200,000 300,000 400,000 12 24 36 48
Gas Production (Mcf/month) Months After TIL
9000' LL
100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000 12 24 36 48
Gas Production (Mcf/month) 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:
Utica Dry:
Monroe County
Utica Wet:
continued development
(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
5,000 10,000 15,000 20,000 25,000 30,000 100,000 200,000 300,000 400,000 500,000 12 24 36 48
NGL/CND Production (BBL/month) Gross Gas Production (Mcf/month) Months After TIL
Gas NGL CND 100,000 200,000 300,000 400,000 500,000 600,000 12 24 36 48
Gas Production (Mcf/month) 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):
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 $3.50 Future Locations Refracs
38% 28%
CBM IRR
Development Methodology
31
CONSOL utilizes a portfolio
methodology to:
within the portfolio to drive decision making targeted towards maximizing NAV/share
developing the assets within the portfolio
and divesture opportunities to
Asset Assessment
GIS Mapping Geology/ Reservoir Engineering Land, Title, JAD Marketing Water Midstream Drilling, Completion, Production Purchase Additional FT Land Swap Potential Build Pipeline/ infrastructure Water Optimization Opportunities Pick up/ Lay Down Rigs Complete DUCs
17 22
100 150 200 250 300 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 Net Mmcf/d Cumulative PV (Secondary)
Performance Studies Portfolio Classification Asset Development and Optimization Monte Carlo Risk Analysis
New World View: Stacked Pay
Rhinestreet Middlesex Burkett West River
Formation Name
P a yCashaqua Tully Hamilton Marcellus Onondaga Utica Point Pleasant Trenton
0 GR 400 LITHOLOGY32
pay potential, on top of Marcellus and Utica
advantage of a dry gathering system
sunk capital
(1) Stacked pay inventory includes core and non-core undeveloped acreage
Stacked Pay Value for SWPA: Pad Level Example
33
Stacked Pay Efficiencies Unstacked Stacked Unstacked Stacked LOE ($/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
development plan due to stacked pay economic improvement
effective infrastructure build-out for both plays
(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 $3.00 BTAX IRR (%) BTAX NPV ($ in millions) Gas Price Unstacked NPV Stacked NPV Unstacked IRR % Stacked IRR %
Stacked Pay Value for SWPA Marcellus: Well Level
34 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% 1.32 1.38 1.56 1.65 1.75 2.05 2.39 2.42 2.50 2.64 2.66 2.66 2.69 2.78 2.82 2.87 2.95 2.95 2.96 3.22 3.25 3.27 3.34 3.38 3.45 3.91 3.97 4.06 4.19 4.22 4.33 4.72 5.50 BTAX IRR (%) 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
avoidance of processing costs
reduces capex and opex and increases combined NPV
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 $0.41
Capex ($ in millions) $829 $2,007 $2,630
NPV ($ in millions) $317 $389 $939 +33%
Upper Devonian: Rhinestreet and Burkett
Provides triple stacked pay potential,
development driven by gas price trigger
0% 10% 20% 30% 40% 50% 60% 70% $2.00 $2.50 $3.00 $3.50 $4.00 BTAX IRR (%) $/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:
evaluate NAV impact and helps assess development risk
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
1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 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 Casing Pressure (psi) Flow Rate (Mcf/d) Flow Rate MCf/Day Casing Pressure
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
Net Acres
Recoverable Resource in Place
Triple Stacked Core Locations
Years of Drilling
in the core and non-core areas
stacked pay development
(Rhinestreet, Burkett), Marcellus and Utica
lower value formations
program for over 40 years
Two-Year Development Plan
from December 2016 through 2018
completed in two-year plan
County, OH and SWPA will be developed throughout 2017, 2018, and beyond
continue to be drilled and evaluated
40
2017 2018
TD FRAC TIL Capex TD FRAC TIL Capex
Marcellus 12 13 13 $80 54 42 40 $260 Utica $0 3 3 3 $40 Upper Devonian
3 $15 -
18 $95 -
$10 3rd Party Marcellus 2 11 11 $5 4 -
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
forecast
spending as necessitated by commodity fluctuations
capital driven by return to activity and blocking up acreage
maintenance capital would be approximately $250-$300 million
Drilling & Completions 84% Midstream 6% Land, Permitting, and Other 10%
E&P Capital and Production Plans
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:
Contributing to NAV/share through a "barbell" strategy:
approaches
Programmatic Hedging
cash flow (FT cost & capacity optimization, ensure gas flow, diverse sales portfolio)
agreements
flexibility, create 3rd party
CURRENT & NEAR TERM LONGER TERM
management
protection
diversified netbacks
flexibility
& balance sheet protection
Increased Volatility
45
U.S. LNG Export Forecast Current infrastructure and systems are not built to handle new gas market:
supply has increased significantly
in 2017
if drilling slows
increasing significantly
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:
when, not if
the expected production growth
growth path for the next 5+ years
A normal or colder-than-normal winter will have a large effect:
have been in the past
ever been (power, heating, Mexico, LNG)
Working Gas Inventory (Bcf):
extra supply
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.
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
10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Average MMcf/d Demand + Takeaway Capable Excess AVG Supply Supply Potential
The Benefits of Flexible Firm Transportation
47
FT strategy:
lower than peers going to markets that maximize netbacks without over-committing
varying terms, releases, etc.
with 1/8 of the average “take-or-pay” FT
greenfield FT prices
production
Basis plan will utilize:
advance
(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 $20.0 CNX 1 2 3 4 5 6 7 8
Total Obligations ($ in billions)
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:
$- $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 $0.80 $0.90 2018 2019 2020 2021 2022 2023 Estimated $/Dth
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:
balanced basket of prices
program and diversified sales mix
Positioned significantly ahead of peers as in-basin market stays volatile:
with netbacks being in and out of the money
time as more costs hit their income statements and they face minimum volume commitments in more recent contracts
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 $3.50 2017 2018 2019 2020 2021 2022 Annual Price ($/MMBtu) TETCO M2 NYMEX
Source: Intercontinental Exchange and CME
200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000
MMBtu/d Cumulative NYMEX Hedges Cumulative Basis Hedges
Hedging Strategy
50
Newly instituted programmatic hedge program:
up to 90% of proved developed production
hedges
We are hedging PDP volumes out to 2020:
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
3.4 Average Prices ($/Mcf) $ 3.19
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:
Plant optionality on nearly half of wet volumes:
Direct ethane sales netbacks tracking Mt. Belvieu pricing:
basis
40% of C3+ in 2017-2018 expected to be sold internationally:
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 $0.30 2017 Ethane ($/gal)
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%
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:
Team is now focused on divesting E&P assets:
and flexibility with asset base
CONSOL has a significant asset base:
horizons
Flexible approach:
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)
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:
million gal/day
position to achieve best in class operating cost
Organic value creation through spin-off or drop-down opportunity
(9.0x – 12.0x)
Projected 2017 EBITDA of approximately $50 million
Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected
due to the unknown effect, timing, and potential significance of certain income statement items. 2017 EBITDA projection is based on rates charged to CNX Gas, which are subject to change
CONVEY Water System Assets
Marcellus Utica Other Total Water Pipelines (Miles) 291 18 216 525 Storage Impoundments 8 1 9 Water Sourcing Dams 2 2 UIC Well 1 1 2017 CONVEY Capex ($MM) 15 10 25 2017 Water Pipelines (Miles) 10 15 25 2017 Storage Impoundments
Water Pipelines (Miles) 301 33 216 550 Storage Impoundments 8 1
Water Source 2 2 UIC well 1 1
Baltimore Marine Terminal
58
Overview:
million tons coal storage yard capacity
seaborne markets supplying both Europe and Asia
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:
throughput, despite challenging coal export market conditions in 2016
(with take or pay provisions) from third party shipping contracts in addition to legacy contracts of 12 million tons reserve (not take or pay)
2017 outlook:
ton throughput providing $19-$22 million of EBITDA
Recent Transactions: Legacy Assets
59
Buchanan Mine transaction:
met coal prices
the gross FOB mine sales price over certain minimums that increase each year and end after five years
positioned CNX to receive a royalty in Q4 2016
Buchanan royalty is forecasted to be between $10-$20 million
Miller Creek / Fola transaction:
from CONSOL’s balance sheet
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:
substantial reduction in legacy liabilities in 2016
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 $4,500 2012 2013 2014 2015 2016E Annual Cash Servicing Costs ($ in millions) Legacy Liabilities ($ in millions) Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost
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
spend/activity level
dividends/distributions
Utica opportunities
back debt
share count
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.
and operating costs
company to dramatically improve its 2016 and 2017 capital yield
a depressed pricing environment
to maintain capital efficiency levels well above historical averages
30% 80% 130% 180%
1 2 3 4 5 6 7 CNX
30% 80% 130% 180%
1 2 3 4 5 6 7 CNX
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
30% 80% 130% 180% 2014 2015 2016E 2017E 2018E
100 150 200 250 300 2012 2013 2014 2015 2016E 2017E 2018E $ in millions 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 $0.60 2014 2015 YTD 2016 SG&A Spend ($/Mcfe(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.
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 $60
PA Mining Operations Guidance
70
PA Mining Operations 2016E 2017E 2018E Estimated Total Coal Sales Volumes (in millions of tons) 24.0 26.5 26.5 Total Committed Volumes (Contracted & Priced) 23.3 23.1 % Committed 97% 87% Capital Expenditures ($ 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)
Stock-Based Compensation $20 $10 $0 $30 Adjusted EBITDA $480 $400 ($15) $865 Less: Noncontrolling Interest
$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 2,000 4,000 6,000 8,000 10,000 12,000 2014 2015 2016E 2017E 2018E
Assumed 12 Mo. Average Price $/MMBtu Bcfe
Reserves Estimated Range Assumed 12 Mo, Average Price $/MMBTU Assumed 12 Mo. Average Price ($/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
2.0x 3.0x 4.0x 1 2 3 4 CNX 5 6 7 2017 Net Debt/EBITDA 2018 Net Debt/EBITDA
commodity prices and limits the risk that leverage ratio moves into the commercial banks perceived danger zone of 3.5x or higher
capital markets, or hedging at the bottom of cycle
as E&P loses the coal cash flow and diversification benefits, the company will be smaller and have more concentration risk (as will CNXC)
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
share through several means: drilling pace, buybacks, delineation drilling of our non-core assets, and M&A
the capital markets throughout the cycle if the
strength and maximize NAV per share
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
2.0 3.0 4.0 5.0 6.0 7.0 8.0 (80%) (60%) (40%) (20%)
2015 YE Net Debt/EBITDA Estimate
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
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 billions
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% Jan 2016 Feb 2016 Mar 2016 Apr 2016 May 2016 Jun 2016 Jul 2016 Aug 2016 Sep 2016 Oct 2016 Nov 2016
CNX E&P WACC Over Time Measures taken to manage WACC:
Goals:
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
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 millions 10% CAGR 15% CAGR 20% CAGR $0 $10 $20 $30 $40 $50 $60 2015 2016 2017 2018 2019 2020 2021 $ in millions 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
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
Financial Outlook: NAV/Share Value Drivers Accelerating
We expect growth while generating free cash flow:
We have improved transparency and predictability:
Our plan forecasts strengthening financial metrics:
80
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
83