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TRANSCRIPT
Company Presentation Q4 2015
Cautionary Language
2
This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities
Exchange Act of 1934, as amended). Statements that are not historical, are forward-looking, and include our operational and strategic plans; estimates of
coal and gas reserves and resources; the projected timing and rates of return of future investments; and projections and estimates of future production,
revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially
from those statements, plans, estimates and projections. Accordingly, investors should not place undue reliance on forward-looking statements as a
prediction of future actual results. Factors that could cause future actual results to differ materially from the forward-looking statements include risks,
contingencies and uncertainties that relate to, among other matters, the following: we may not receive the prices we expect to receive for our natural gas and
coal; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately estimate our economically recoverable gas, oil
and condensate; we may encounter unexpected operational issues when we drill and mine, including equipment failures, geological conditions and higher
than expected costs for equipment, supplies, services and labor; we may not achieve the efficiencies we expect to realize in our drilling and completion
operations, and as a result, our projected cost savings may not be fully realized; our joint venture partners, who operate assets in which we have a significant
interest, may not perform as we expect; we may not be able to sell non-core assets on acceptable terms; we may be unable to incur indebtedness on
reasonable terms; 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, 2014 filed with the Securities and
Exchange Commission (SEC), as updated by any subsequent quarterly reports on Form 10-Qs. The forward-looking statements in this presentation speak
only as of the date of this presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company
anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We
may use certain terms in this presentation, such as EUR (estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules
strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these estimates may
be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more speculative than estimates of
reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from
aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is
customary in the gas industry, prior to the commencement of gas drilling operations on our properties, we conduct a thorough title examination and perform
curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. As a result of our title review or
otherwise, we may be required to acquire property rights from third parties at our expense in order to effectively drill and produce the oil and gas rights we
control and third parties may participate in the wells we drill, thereby reducing our working interest in those wells.
This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CONSOL Energy Inc. or CNX Coal Resources LP.
Key Takeaways
3
CONSOL Energy’s E&P Division has demonstrated that it can stand on its own as a premier Appalachian Basin
producer:
Gas production has grown significantly
Capital intensity and costs are down dramatically
Dry Utica has opened up a new opportunity set
Our base plan is achievable and will help us to more easily reach our free cash flow targets due to conservative
plan assumptions:
NYMEX strip gas pricing with conservative basis differentials
Conservative thermal and met pricing
CONSOL Energy’s gas hedges and coal contract position significantly de-risk the business and support the
company’s organic FCF plan in 2016
CONSOL Energy’s base plan, coupled with additional asset sales, will result in
significant flexibility, including the ability, if appropriate, to separate its Coal and
E&P divisions
4
Q4 2015 Overview
5
Net income Attributable to CONSOL Energy Shareholders for the fourth quarter was $30.4 million
- Includes the following pre-tax items:
$109.9 million benefit related to changes in retiree medical OPEB plan
$62.4 million unrealized gain on commodity derivative instruments
15.9 million in pension settlement expense
$6.3 million in expenses for adjustment settlements related to the prior sale of CONSOL's industrial supply
subsidiary, which closed during the fourth quarter of 2014
$7.6 million gain on the sale of non-core assets
(1) Adjusted EBITDA is a non-GAAP financial measure and a consolidated number, please refer to the reconciliation is provided in the Appendix.
CONSOL Energy: Fourth Quarter 2015 Results
Q4 2015 Overview
Q4 2015 Summary Y/Y Q-to-Q Seq. Q-to-Q
($ in millions, except per share data) 4Q2015 4Q2014 Change 4Q2015 3Q2015 Change
Net (Loss) Income Attributable to CNX Shareholders $30 $74 ($44) $30 $119 ($89)
Earnings per Diluted Share $0.13 $0.32 ($0.19) $0.13 $0.52 ($0.39)
Revenue and Other Income $762 $936 ($174) $762 $814 ($52)
Net Cash Provided by Continuing Operations $102 $100 $2 $102 $110 ($8)
Adjusted EBITDA Attributable to CNX Shareholders(1) $206 $273 ($67) $206 $136 $70
6
E&P Division:
- 2015 production of 328.7 Bcfe, up approximately 93.0 Bcfe from 2014, a 39.5% increase
- Production volumes expected to grow approximately 15% in 2016 over 2015
- Capital efficiency improvements, including lean manufacturing, enable grow with less capital
2016 E&P capital budget guidance of $205 – $325 million
- Continued implementation of zero-based budgeting reducing operating and overhead costs
- Improvements in Appalachia takeaway infrastructure to lower basin differentials and improve realized prices
- Goal is to maintain and improve our solid liquidity position
Coal Division:
- Pennsylvania Operations’ sales secured by agreements, with approximately 100% of projected volumes sold for
FY 2016, based on the midpoint of the guidance range of 22-26 million tons
Source: Company filings. Sum of numbers may differ slightly from totals and financial statements due to rounding.
(1) Approximately $180 million of 3Q 2015 Proceeds from LT debt is comprised entirely of CNXC LT revolver debt, consolidated on CNX financial statements per US GAAP accounting rules.
CONSOL Energy: Net (Decrease)/Increase in Cash
Q4 2015 Overview
Cash Flow Summary Y/Y Q-to-Q Seq. Q-to-Q
($ in millions) 4Q2015 4Q2014 Change 4Q2015 3Q2015 Change
Net Cash Provided by Operating Activities $102 $87 $15 $102 $110 ($8)
Capital Expenditures ($127) ($319) $191 ($127) ($259) $132
Proceeds From Asset Sales $28 $216 ($188) $28 $76 ($49)
Other Investing ($14) ($13) ($1) ($14) ($26) $12
Proceeds From /(Payments on) Short-Term Debt & Misc. Borrowings $9 ($6) $15 $9 ($149) $158
Proceeds From /(Payments on) Long-Term Debt(1) - - - - $180 ($180)
Dividends Paid ($2) ($14) $12 ($2) ($2) ($0)
Proceeds from the sale of MLP interest (CNXC IPO) - - - - $148 ($148)
Other Financing ($5) $2 ($7) ($5) ($4) ($1)
Net (Decrease) / Increase in Cash ($10) ($49) $39 ($10) $73 ($83)
7
$2 billion Revolving Credit Facility:
5 year credit facility expires June 2019
Gas reserves based lending facility: Lending group reaffirmed CONSOL's $2 billion borrowing base in
November 2015
- Borrowing base is redetermined semi-annually in the Spring and Fall
Obtained the right to separate the coal and gas business subject to a leverage test
Solid Liquidity Position of ~$856 Million
Q4 2015 Overview
December 31,
Negative Covenants Limit 2015
CONSOL Energy Revolver:
Minimum Interest Coverage Ratio < 2.5 to 1.0 5.3 to 1.0
Minimum Current Ratio < 1.0 to 1.0 2.3 to 1.0
Ample liquidity of $856 million with business plans focused on positive free cash
flow generation through 2016 and deleveraging the balance sheet
(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $73 million as of 12/31/2015, $7 million of which was CNXC’s and consolidated in CNX’s financial statements
per US GAAP accounting
(2) Revolving credit facility as of 12/31/2015
Amount/ Amount Letters Amount
December 31, 2015 ($ in million) Capacity Drawn of Credit Available
Cash and Cash Equivalents(1) $66 - - $66
Revolving Credit Facility(2) $2,000 $952 $258 $790
Total $2,066 $952 $258 $856
Y/Y Q-to-Q Seq. Q-to-Q
E&P Division 4Q2015 4Q2014 Change 4Q2015 3Q2015 Change
Average Sales Price(1)
($ / Mcfe) $2.78 $3.90 ($1.12) $2.78 $2.35 $0.43
Average Costs(2)
($ / Mcfe) $2.45 $3.19 ($0.74) $2.45 $2.63 ($0.18)
Sales Volumes (Bcfe) 95.5 70.5 25.0 95.5 86.1 9.4
Sales Volumes (Bcfe) by Category
Marcellus 48.5 36.5 12.0 48.5 44.9 3.6
CBM 18.7 20.0 (1.3) 18.7 18.5 0.2
Utica 20.7 7.1 13.6 20.7 15.3 5.4
Other 7.6 6.9 0.7 7.6 7.4 0.2
8
E&P Division: Q4 2015 Results Summary
Q4 2015 Overview
(1) Average Sales Prices for 4Q2015, 4Q2014 and 3Q2015 include gains on commodity derivative instruments (cash settlements) of $0.95, $0.39 and $0.60, respectively.
(2) Average Costs for 4Q2015, 4Q2014 and 3Q2015 include DD&A of $1.05, $1.28 and $1.05, respectively.
E&P Division’s fourth quarter net income was $57.1 million
- Production increased by 35% in the fourth quarter compared to year-earlier quarter
- Due to depressed commodity prices, revenue decreased by $10.1 million in the fourth quarter, compared to the
year-earlier quarter
- Marcellus Shale all-in unit costs were $2.46 per Mcfe in the fourth quarter, a decrease of $0.37 from $2.83 per Mcfe
in the year-earlier quarter, or a 13% improvement
- Utica Shale production volumes were 20.7 Bcfe in the fourth quarter, a 194% increase from 7.1 Bcfe in the year-
earlier quarter
- Utica Shale all-in unit costs were $1.91 per Mcfe in the fourth quarter, a decrease of $0.33 from $2.24 per Mcfe in
the year-earlier quarter, or a 15% improvement
9
E&P Division: Q4 2015 Operations Summary
Sub-
Regions
Horizontal
Rigs Drilled Completed
Turned
In Line
(TIL)
Avg. TIL
Lateral
Length
(ft)
Counties
Southwest
PA ---- ---- 11 ---- ----
Greene,
Washington,
PA
Central PA ---- ---- ---- ---- ----
Indiana,
Westmoreland,
PA
Northern
WV Dry ---- ---- ---- ---- ----
Barbour,
Doddridge,
Lewis, WV
Ohio ---- ---- ---- 1 6,164 Monroe, OH
North Wet
Gas ---- ---- ---- ---- ----
Greene,
Washington,
PA; Marshall,
WV
South Wet
Gas ---- ---- ---- ---- ----
Doddridge,
Tyler, Ritchie,
WV
Total 0 0 11 1 6,164
Sub-
Regions
Horizontal
Rigs Drilled Completed
Turned
In Line
(TIL)
Avg. TIL
Lateral
Length (ft)
Counties
Core Wet ---- ---- 4 3 9,048 Noble, OH
Surrounding
Core Wet 1 4 4 5 7,152
Harrison,
Belmont, OH
Dry Utica ---- 1 1 6* 8,375
Monroe, OH;
Marshall, WV
Westmoreland,
Greene, PA
Total 1 5 9 14 8,082
Marcellus Shale Quarterly Summary Utica Shale Quarterly Summary
Q4 2015 Overview
*Dry Utica TIL includes one JV well, MND6, located in Marshall County, WV
SWITZ 6 Pad (4 Utica Laterals) averaged 109 MMcf/d during a 24
hour flowback period
Accelerated Learning Curve – PA Utica Completions (GH9 vs
Gaut4I)
─ 29% improvement in stimulation efficiencies
─ $1.5 million in savings on equivalent size stages
─ Successfully tested dissolvable plug technology on GH9 Utica,
which resulted in a $250,000 savings
Strong production response from SWPA gathering system
de-bottlenecking project:
─ CONE de-bottlenecking efforts added ~2.7 Bcf in Q4 alone
─ Optimizing high pressure and low pressure gathering systems
─ Recent project added ~100 MMcf/d of additional capacity
─ Optimized system to maximize production and overcome dew
point constraints
─ Utilize multiple sales points to optimize production
Completion improvements
─ 42% improvement in drillout time year over year
─ Average days per well decreased by 10 days year over year
10
Coal Division: Q4 2015 Results Summary
Q4 2015 Overview
Y/Y Q-to-Q Seq. Q-to-Q
Coal Division 4Q2015 4Q2014 Change 4Q2015 3Q2015 Change
Average Sales Price ($ / ton) $52.37 $61.19 ($8.82) $52.37 $56.34 ($3.97)
Average Costs ($ / ton) $41.97 $44.99 ($3.02) $41.97 $43.39 ($1.42)
Coal Production (millions of tons) 6.2 8.0 (1.8) 6.2 7.3 (1.1)
Sales Volumes (millions of tons) 6.6 8.1 (1.5) 6.6 7.2 (0.6)
Sales Per Ton ($ / ton)
Pennsylvania Operations $52.57 $60.10 ($7.53) $52.57 $56.99 ($4.42)
Virginia Operations $48.41 $68.58 ($20.17) $48.41 $51.82 ($3.41)
Other Operations $60.65 $59.38 $1.27 $60.65 $57.36 $3.29
81%
13%
6%
FY 2016E Sales Tons by Segment
PA Ops VA Ops Other
11
Coal Division: FY 2016 and FY 2017 Marketing Forecasts
Q4 2015 Overview
2016E Coal Sales Facts and Goals
Contracted tons for 2016: 97%
- Priced: 94%
~96% of the PA Ops tons are expected to be sold
domestically
~60%-65% of the VA Ops tons are expected to be
sold overseas
100% of the Other tons are expected to be sold
domestically
2017E Coal Sales Facts and Goals
Contracted tons for 2017: 59%
- Priced: 40%
Note: PA Ops tons reflecting volumes at 100% interest and are not pro rata for CNX ownership of the PA Complex or CNXC.
(1) Tons in millions.
Coal Sales
Guidance(1)
2015A 2016E 2017E
PA Ops 22.9 22.0-26.0 25.0-27.0
VA Ops 4.4 3.5-4.2 3.7-4.2
Other 1.9 1.5-1.8 1.8-2.2
Total 29.2 27.0-32.0 30.5-33.4
12
E&P Division
13
2016 Planned E&P Activity Overview
E&P Activity Summary – 2016 Plan
E&P Division
Note: Average net revenue interest for Marcellus/Utica shales is 43.7%. Table includes two 100% CONSOL-owned wells: one dry Utica Shale well in Monroe County,
Ohio; one dry Utica Shale well (GH9) in Greene County, Pennsylvania. Marcellus and Utica wells are horizontal wells, and CBM wells are primarily vertical wells.
Drilled
Uncompleted
Inventory
Drilled
Completed
Inventory
2016
Completions
2016
TIL
Marcellus
SW PA Operated 29 23 25 42
SW PA Non-Op 5 10 - 10
WV Operated 7 - - -
WV Non-Op 49 - - -
Total Marcellus 90 33 25 52
Utica
SW PA Operated - 1 - 1
OH Operated 1 4 - 4
OH Non-Op 11 4 6 10
Total Utica 12 9 6 15
CBM
CBM Operated - 4 43 47
Total Gross Wells 102 46 74 114
128154 156
172
236
329
~15%
0
50
100
150
200
250
300
350
400
450
0
50
100
150
200
250
300
350
400
450
2010 2011 2012 2013 2014 2015 2016E
Bcfe
Marcellus CBM Utica Other
E&P Division
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Production volumes grew ~93 Bcfe in 2015, a 39.5% increase;
~15% year-over-year growth target for 2016
E&P Production Volumes
Gas Division Production Growth
Source: Company filings.
Note: Acquired ~23 Bcfe of Conventional gas production from Dominion E&P in 2010. Divested ~11 Bcfe in 2011.
Production by Area
2015A 2016E
Marcellus 51% 54%
CBM 23% 19%
Utica (Wet & Dry) 17% 21%
Other 9% 6%
236
-38
8
15
~104 ~329
-50
235
~71 ~378
0
50
100
150
200
250
300
350
400
2014 TotalProduction
2015 Basedecline
2015: GatheringDe-bottlenecking
2015: Non-Op(Ex NBL/HES)
Prod. Adds
2015: ProductionAdds
2015 TotalProduction
2016 Basedecline
2016: GatheringDe-bottlenecking
2016: Non-Op(Ex NBL/HES)
Prod. Adds
2016: ProductionAdds
2016 TotalProduction
Bcfe
E&P Division
15
2016 production growth primarily driven by wells’ productivity improvements, pipeline
infrastructure debottlenecking projects and completion of inventory of drilled but
uncompleted wells
Bridging to Growth
Note: Production volumes reflect the mid-point of their contribution to the 2015 and 2016 production guidance ranges.
Source: Company filings and estimates.
16
Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth
E&P Division: Capital Expenditures
Revised planned 2016 E&P capital budget lower by $185 million
Deferring activity, increasing capital efficiency
improvements and identification of additional de-
bottlenecking activities
Revised 2016 E&P capital budget of $205-$325
million, $185 million lower than previous guidance
of $400-$500 million at the midpoint (a 41%
reduction)
- Drilling and Completion: $110-$210 million
o Includes $10-$15 for coalbed methane (CBM) activity
- Midstream of $40-$50 million (including approximately $22
million associated with CONE Midstream capital
contributions)
- Other activities (land, permitting, and business
development): $55-$65 million
60%
17%
23%
D&C Midstream Other
2016 E&P Capital Budget:
$205-$325 Million
17
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). Gross locations are as of 12/31/2014.
(1) Comprised of ~119,000 net acres in Ohio Utica (~79,000 in the JV and ~40,000 non-JV) and ~306,000 and ~197,000 net prospective acres in PA and WV respectively.
Utica Shale Overview: A Leading Position in the Utica Shale
E&P Division
~622,000 CONSOL net
acres(1)
Over 3,000 gross locations
─ 87 wells online, as of
12/31/2015
─ 14 wells TIL in Q4 2015
─ 8,082 ft average TIL
laterals in Q4 2015
─ 4 wells per pad on
average
─ 120-acre spacing
(assuming 7,000 ft lateral)
EURs:
─ Ohio Wet: 2.3 Bcfe
EUR/1,000 ft of lateral
─ Ohio Dry: 2.8 Bcfe
EUR/1,000 ft of lateral
─ PA/WV Dry: 3.0 Bcfe
EUR/1,000 ft of lateral
18
E&P Division Utica Shale: PA/WV Dry Gas
REXX – Cheeseman 1
IP Gas: 9,200 Mcf/d
IP Oil: 0 Bbl/d
CHK – Thompson 3H
IP Gas: 6,400 Mcf/d
IP Oil: 0 Bbl/d
RRC– Zahn #1
IP Gas: ~4,500 Mcf/d
IP Oil: 0 Bbl/d
CHK – Brown 10H
IP Gas: 9,500 Mcf/d
IP Oil: 0 Bbl/d
HES – NAC 3H-3*
IP Gas: 11,000 Mcf/d
IP Oil: 0 Bbl/d
CHK– Hubbard 3H
IP Gas: 11,00 Mcf/d
IP Oil: 0 Bbl/d
RRC Claysville Sportman’s Club
IP Gas: 59 MMcf/d
IP Oil: 0 Bbl/d
EQT – Pettit
Spud in Aug. 2015
13,400 ft. TVD; 4,000-4,500 ft. lateral
CVX – Conner 6H
IP Gas: 25,000 Mcf/d
IP Oil: 0 Bbl/d
Permits submitted for 2 add. laterals HES – Potterfield 1H-17*
IP Gas: 17,200 Mcf/d
IP Oil: 0 Bbl/d
RICE – Bigfoot 9H
IP Gas: 42,000 Mcf/d
IP Oil: 0Bbd
GPOR – Stutzman 1-14
IP Gas: 21,000 Mcf/d
IP Oil: 0 Bbd
GPOR – Irons 1-4
IP Gas: 30,200 Mcf/d
IP Oil: 0 Bbd CNX – Switz 6D
44.7 MMcf/d @ 6,835 psig
24-hr test rate
MHR – Stalder 3UH
IP Gas: 32,500 Mcf/d
IP Oil: 0 Bbl/d
MHR – Winland Pad
IP Gas: 46,500 Mcf/d
HGE – Whiteacre 2H
IP Gas: 9,000 Mcf/d
IP Oil: 0 Bbl/d
Eclipse – Tippens 6H
IP Gas: 30,000 Mcf/d
IP Oil: 0 Bbl/d
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
*Subsequently sold to Ascent Resources LLC.
GST – Simms Pad
4447' Lateral
1st 48 Hour Prod 29.4 MMcf/d
IP 33 MMcf/d @ 9000psi
SGY – Pribble 6US
IP Gas: 30 MMcf/d
IP Oil: 0 Bbl/d
Dry Utica is being aggressively tested in Northern WV and PA, where CONSOL
holds 100% WI in approximately 503,000 net acres
Noble Energy/CNX – MND6
39.1 MMcf/d @ 7,126 psig
24-hr test rate
CNX – GH9
61.9 MMcf/d @ 8,312 psig
24-hr test rate
CNX – Gaut 4IH
61.4 MMcf/d @ 7,968 psig
24-hr test rate
EQT – Scotts Run
24 Hour Prod 72.9 MMcf/d
CHK – Messenger WTZ 3UH
IP Gas: ~30 MMcf/d
EQT – Big 190
Spud in Sept. 2015
12,700 ft. TVD; 3,500-4,000 ft. lateral
Antero – Rymer 4HD
20 MMcf/d 20-day avg. rate
CONSOL has over 110,000 acres of Utica leasehold in
Westmoreland and Indiana Counties, PA 19
CONSOL – GAUT4IH
61.4 MMcf/d 24-hr IP rate @
7,968 psi; 5,840 ft. lateral
~ 5,800’ single lateral; 100% WI to
CONSOL
30 stage completion
200’ stages with 500k# proppant:
160k# 100 mesh + 200k # 40/80
ceramic + 140k# 30/50 ceramic
Ready supply of water
Production facilities and gathering
system with available capacity
Underutilized FT available
Achieved Peak 24-hr rate of 61.4
MMcf/d in July 2015
Utica Shale: Gaut 4IH – Westmoreland County, PA
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
5000
5500
6000
6500
7000
7500
8000
8500
9000
9500
10000
0
5,000
10,000
15,000
20,000
25,000
30,000
9/25/2015 10/15/2015 11/4/2015 11/24/2015 12/14/2015 1/3/2016
Cas
ing
Flo
win
g P
ress
ure
(p
sig)
Gas
Rat
e (
Mcf
/d)
Flow Rate MCf/Day Casing Pressure PSIG
The well has produced 1.26 Bcf in 60 days of operations while average flowing casing
pressure is approximately 8,100 psi 20
Utica Shale: Gaut 4IH Westmoreland County, PA
Conducted a Modified Isochronal Test with planned extended drawdown and build-up
Results of test have provided reliable values for reservoir pressure, height, permeability and extent as well as well-spacing for future wells
We are following a managed pressure drawdown where we are currently dropping pressure at 20-25 psi/day
21
Range Resources - Claysville Sportsman’s Club #1
IP Gas – 59.0 MMcf/d
CONSOL GH9
24 hr IP – 61.9 MMcf/d
@ 8,312 psig
6,141 ft. lateral
100% WI and 96% NRI to CONSOL
TVD: 13,400’
Frac’d in Q4 2015
24-hour IP of 61.9 MMcf/d at 8,312 psi
Drilled lateral length of 6,141 ft.
Situated in existing Marcellus field
Ready supply of water
Production facilities and gathering
system with available capacity
EQT – Scotts Run
24 hr IP – 72.9 MMcf/d.
3,221’ Treated interval.
CNX’s GH9 Utica well is
less than 4 miles away from
EQT’s Scotts Run well
Utica Shale: GH 9 Greene County, PA
CONSOL has ~84,000 net acres prospective for the Utica in the SWPA operating
area, including ~58,000 net acres in Greene and Washington counties, PA
EQT – Pettit Spud in Aug. 2015
13,400 ft. TVD
4,000-4,500 ft. lateral
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
Utica Shale: Ohio Dry Gas
22
CNX Activity and Recent IP Rates In-and-Around Monroe County, OH
GPOR Irons 1-4H (Utica):
30.3 MMcf/d – Avg 24-hr rate
MHR 3-UH (Utica):
32.5 MMcf/d – Avg 24-hr rate
MHR 2-MH (Marcellus):
3.7 MMcf/d of gas and 312 Bbls of
condensate per day, peak test
rates
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
Recent nearby results have surrounded our contiguous Monroe County leasehold,
which contains ~2.1 Tcfe of resource
MHR Stewart Winland Pad:
46.5 MMcf/d – Avg 24-hr rate
ECR Shroyer 2-well pad (Utica):
7,819 – Avg later length
42.5 MMcf/d – Combined Rate
CNX SWITZ 6 Pad (Utica) :
4 Utica Wells & 1 Marcellus
CNX – Switz 6D: 24-hr test rate
44.7 MMcf/d @ 6,835 psi
9,761 ft. lateral
CVX Conner well (Utica):
25.0 MMcf/d – Avg 24-hr rate
GST Simms:
4,447' Lateral
1st 48 Hour Prod 29.4mm
IP 33 MMcf/d @ 9000psi
NBL / CNX MND 6H (Utica):
1 Utica Well
39.1 MMcf/d 24-hr IP @7,126 psi
9,345 ft. lateral
CONSOL has over 13,000 contiguous acres of Utica leasehold in
Monroe County, OH
23
CONSOL – SWITZ 6 Pad (Utica):
4 Utica wells & 1 Marcellus well
CNX – Switz 6D: 24-hr test rate
44.7 MMcf/d @ 6,835 psig
Remaining wells flowing back
4 Utica Wells and 1 Marcellus Well
Avg. Utica Lateral Length = 8,821’
Longest Utica Lateral = 10,122’
100% WI to CONSOL
Tested 3 proppant types
350K pounds/stage @ 200’ spacing
Multi-Market availability
Offset pad fully permitted with 5 wells
Utica Shale: Switz 6 Monroe County, OH
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
0
2000
4000
6000
8000
10000
0
10,000
20,000
30,000
40,000
50,000
10/13/2015 10/14/2015 10/15/2015 10/16/2015 10/17/2015 10/18/2015 10/19/2015 10/20/2015
Flo
win
g C
asin
g P
ress
ure
(p
sig)
Gas
Rat
e (
Mcf
/d)
Gas Rate Casing Pressure
24
Utica Shale: Switz 6D Monroe County, OH
The Switz 6D well had a peak 24-hr IP of ~45 MMcf/d with an average flowing casing
pressure of 6,835 psig, which is the 5th highest IP in the Utica to date and the best in
SE OH
The limited decline in flowing
casing pressure bodes well for
a strong stabilized production
rate going forward
Temporarily shut-in to
flowback other wells
on the SWITZ pad
0
5,000
10,000
15,000
20,000
25,000
0 20 40 60 80 100 120
Mea
sure
d D
epth
(ft
.)
Days
Days vs. Depth (Well in order of Horizontal TD Date)
Switz-6B-HSU
Switz-6F-HSU
Switz-6H-HSU
Switz-6D-HSU
Switz-16J-HSU
$509.76
$540.17
$321.59
$344.98
$231.80
$0
$100
$200
$300
$400
$500
$600
Switz-6B-HSU Switz-6D-HSU Switz-6H-HSU Switz-6F-HSU Switz-16J-HSU
Dri
llin
g C
ost ($
/ft.)
Switz Drilling Cost/Ft. (In order by Tophole TD)
~55% Reduction in Drilling Costs
25
Utica Shale: Monroe Cty, OH Cost Improvements
Accelerating rate of change in CONSOL’s efficiency improvements: drilling costs
reduced by 55% in the Monroe County, OH between just the 1st Utica well to the 5th
~60+% Reduction in Days to Drill
26
Utica Shale: PA Utica D&C Cost Reduction Plan
$12.4
(0.8)
$26.2 (8.2)
(2.2)
(0.4)(1.2) (1.1)
$0.0
$5.0
$10.0
$15.0
$20.0
$25.0
$30.0
Prior AFE Per Well Drilling Efficiency Drilling Science Cost Casing Design Multi-Well Pad (4) Completion Design Proppant Optimization Development AFE PerWell
Waterfall Diagram - PA Dry Utica Drilling and Completion Costs Per WellAssume 7000' lateral on a development 4-well pad
($ in millions)
High degree of confidence towards lowering D&C costs in the PA Dry Utica, similar to
successful cost reduction efforts in the Marcellus; plans in place targeting more than
a 50% reduction in D&C costs per well Notes: Numbers may not sum due to rounding.
(1) Data reflects CONSOL Energy Inc.’s estimated per well Authorization for Expenditure (AFE) for drilling, completion and associated costs in the Utica Shale and Point Pleasant intervals in SWPA.
(2) Actual costs for Gaut 4IH well. Actual costs may vary from AFEs.
(3) Estimated, actuals may vary.
(2) (3)
PA Dry Utica: Drilling and Completion Cost Reductions
Waterfall Chart Data(1) ($ in millions) Probability(3) Comments
Prior Well Cost(2) $26.2 Initial - Drilling & Completion Cost on Gaut 4I
Cost Reductions:
Drilling Efficiency (8.2) High Elimination of non-productive time experienced on Gaut 4I; top down drilling saves mobilization/de-mobilization cost and time
Drilling Science Cost (2.2) High Elimination of extensive science work conducted on Gaut 4I: geological evaluation - pilot hole, logging, plugback, etc.
Casing Design (0.4) Medium Elimination of additional casing string not required by regulation
Multi-Well Pad (4) (0.8) Medium Fixed costs shared across wells (ex. pad, mob./de-mob., containment); efficiencies of scale
Completion Design (1.2) Medium Hybrid stage spacing; elimination of drill-out phase; utilization of normal dry gas flowback package
Proppant Optimization (1.1) High Modification of proppant type (ceramic to resin); 3rd party chemicals; 25% reduction in gel use
Total Reductions(3) (13.8)
Development Well AFE(3) $12.4
27
Gas Marketing
Average gas price for the fourth quarter of 2015, including hedging, was a +$0.36 per MMBtu differential to
NYMEX ($2.63 vs. $2.27); excluding hedging, gas price was $(0.54) per MMBtu below NYMEX ($1.73 vs.
$2.27)
─ Q4 2015 saw one of the warmest starts to winter on record and the 2015-2016 winter is projected to be 15%
warmer than the prior year
CONSOL basin exports are projected to increase approximately 73,000 Dth /day for FY 2016 over FY 2015
as TETCO’s U2GC and TEAM OPEN projects were put into service in late 2015, increasing expected
realizations by marketing gas to the higher priced Midwest and Gulf Coast markets
CONSOL entered into ethane, propane, and butane sales agreements under which volumes will be shipped
via Mariner East pipelines to the Marcus Hook Industrial Complex and ultimately exported to Europe
─ The deals, the first of which is expected to commence later this quarter, are expected to yield price premiums
compared with in-basin pricing and expose a portion of the company’s LPG portfolio to Brent Crude linked
pricing
Q4 2015 natural gas price reconciliation:
28
Gas Marketing E&P Marketing Highlights
2014
Q4 Q3 Q2 Q1 Q4
NYMEX natural gas ($/MMBtu) 2.27$ 2.77$ 2.64$ 2.98$ 4.00$
Average differential (0.54) (1.00) (0.68) 0.03 (0.84)
BTU conversion (MMBtu/Mcf)* 0.10 0.09 0.07 0.09 0.15
Gain on Commodity Derivative Instruments - Cash Settlements 0.95 0.60 0.64 0.48 0.39
Realized gas price per Mcf 2.78$ 2.46$ 2.67$ 3.58$ 3.70$
*Conversion factor 1.06 1.05 1.04 1.03 1.05
2015
Targeting pipeline projects that
access favorable markets at
favorable rates
Will supplement direct FT with
firm sales to customers that
have matching firm capacity
Working with marketing partners
to monetize/utilize regionally
underutilized capacity
Near term, will optimize and/or
release FT to enhance revenues
Plan to selectively acquire firm
capacity while minimizing long-
term transportation costs and
long-term financial obligations
Stacked pay opportunities will
help optimize FT portfolio
29
Gas Marketing Firm Transportation
Low average demand costs of $0.24 to $0.28/Dth reflect a well balanced portfolio
between in-basin/out-of-basin markets; minimum relative long-term financial risk
(1) Charts also include transportation under precedent agreements
$0.25 $0.24 $0.28
$0.11 $0.11 $0.11
$-
$0.10
$0.20
$0.30
$0.40
$0.50
2016 2017 2018
$/D
th
CNX's Firm Transportation Costs
Avg. Demand Avg. Variable
$0.36 $0.35 $0.39
TETCO
Dominion
East Tennessee
Columbia
ANR
NEXUS
-
200
400
600
800
1,000
1,200
1,400
1,600
Jan 15 Jan 16 Jan 17 Jan 181000s M
MB
tu/d
ay
TETCO Dominion East Tennessee Columbia ANR NEXUS
FT Capacities
Pipeline (MMcf/d) YE 2015 YE 2018
ANR Pipeline 47 47
Columbia (TCO) 215 305
Dominion (DTI) 245 342
East Tennessee 282 202
Nexus - 150
TETCO 127 127
TETCO (via firm sales) 285 225
1,201 1,398
(1)
30
Gas Marketing
TETCO M2
TETCO M3
TCO Pool
Dominion South
East Tennessee
TETCO ELA
Midwest
Gas Sales CY 2016 Est.
Columbia (TCO) 21%
TETCO (M2) 20%
TETCO (M3) 16%
Dominion (DTI) 12%
East Tennessee 10%
TETCO ELA & WLA 8%
Midwest (Chicago) 13%
100%
Natural Gas Sales
Source: SNL Financial.
TETCO WLA
Current sales portfolio of 100 active customers priced in seven index markets;
actively negotiating with major Midwest, Gulf Coast and LNG customers
Contracted capacity meets
current requirements
─ Inlet wet gas volumes to
processing plants were ~176
MMcf/d above CONSOL’s
aggregate minimum
committed volume in Q4 2015
Maintained the flexibility
to leave ethane in the
residue gas stream
Operational and contractual
flexibility to potentially convert
a portion of currently
processed wet gas volumes to
be marketed as dry gas
volumes, which would lower
processing fees and improve
netbacks
31
Gas Marketing Natural Gas Processing
Flexible contracts permit us to optimize the timing and volume of our flows
Note: We have processing capacity expansion rights of 110,000 Mcf/d
0
50
100
150
200
250
300
350
400
450
500
Jan-15 Jan-16 Jan-17 Jan-18
MM
cf/
d
Contracted Capacity at Processing Plants
$1.1 $2.0
$2.4
$4.0 $4.6 $4.9
$5.5
$14.3
$17.5
Average: $6.3 Bn
20% 19%
71%
52% 36%
167%
70%
95%
152%
0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
$-
$2.0
$4.0
$6.0
$8.0
$10.0
$12.0
$14.0
$16.0
$18.0
$20.0
CNX A B C D E F G H
FT C
om
mit
me
nts
as
% o
f EV
$ B
illio
ns
Short-term uplift in realizations can come at the expense of over-committing to
expensive FT incurring long term off-balance sheet liabilities
32
Notes: Peers include AR, CHK, COG, EQT, GPOR, RICE, RRC and SWN.
Commitments are as of most recently provided company financial statements.
Total Off Balance Sheet Firm Transportation, Gathering and Processing Commitments
Gas Marketing: Firm Transport–Asset or Liability?
33
(1) Includes the impact of NYMEX, index and basis-only hedges as
well as physical sales agreements.
(2) At the midpoint of production guidance.
(3) Hedge positions as of 1/15/2016.
Gas Hedges
Gas Marketing: Hedges
E&P Hedge Program:
Program and actively
monitored hedges
─ Program Hedge - protect
margins on up to 90% of our
Proved Developed
Production
─ Active Hedge Process -
supplements program
hedges up to 80% of our
total production including
proved undeveloped
production
Approximately 60% of total
FY 2016E production
volumes hedged(2)
0
25
50
75
100
125
150
175
200
225
250
1Q16 FY 2016 FY 2017 FY 2018
Gas V
olu
mes H
edged (
Bcf)
Physical Sales With Fixed Basis Exposed to NYMEX
NYMEX Only Hedges Exposed to Basis
NYMEX + Basis (1)
1Q16 FY 2016 FY 2017 FY 2018
NYMEX + Basis (1)
Volumes (Bcf) 55.6 223.3 67.6 31.6
Average Prices ($/Mcf) $3.55 $3.28 $3.07 $2.90
NYMEX Only Hedges Exposed to Basis
Volumes (Bcf) - 0.4 89.0 40.8
Average Prices ($/Mcf) - $3.58 $3.08 $3.17
Physical Sales With Fixed Basis Exposed to NYMEX
Volumes (Bcf) 3.3 - - -
Average Hedge Basis Value ($/Mcf) $0.31 - - -
Total Volumes Hedged (Bcf)(3) 58.9 223.7 156.6 72.4
34
Ethane 64%
Propane 22%
I-Butane 3%
N-Butane 6%
Natural gasoline
5%
Maximum
Ethane
Recovery*
Potential
Scenario
* Assumes 85% ethane recovery level
Ethane 0%
Propane 58%
I-Butane 9%
N-Butane
18%
Natural gasoline
15%
4Q15 Actual (~100% Ethane
Rejection)
CONE Gathering and Midstream systems provide CONSOL unique flexibility to
either (a) blend in ethane to meet specifications, allowing for nearly 100% ethane
rejection or (b) extract ethane when accretive
Gas Marketing Natural Gas Liquids, Oil, and Condensate
Q4 2015 Avg. “NGL Barrel” Composition
Q4 2015 liquids sold: 12.0 Bcfe
Total weighted average price of liquids increased
~64% to $16.34 in Q4 2015 from $9.99 in Q3 2015
Liquids composed approximately 13% of Q4 2015
production volumes, 12% of E&P sales revenue and
4% of total Company revenue
Average price realization (per Bbl):
Q4 Q3 Q2 Q1
NGLs $14.16 $4.80 $12.48 $20.40
Oil $39.06 $54.18 $46.14 $47.82
Condensate $25.38 $27.84 $31.26 $20.82
2015
35
Coal Division
$31.58 $35.25 $57.44
$25-37 Margin
$21-157 Margin
$3-17 Margin
5-yr Avg Price: $64
5-yr Avg Price: $111
5-yr Avg Price: $67
Bailey Buchanan Miller Creek
Cash Margin per ton ($)
36
Pennsylvania (“PA”) Operations Virginia (“VA”) Operations Other
Type of Coal Primarily Thermal Primarily Met Primarily Thermal
Method 5 Longwalls and
Continuous Mining Machines
1 Longwall System and
Continuous Mining Machines
Stripping Shovels and
Front-end Loaders
Seam Pittsburgh 8 Pocahontas 3
Upper Dorothy (Coalburg), Kittanning,
Freeport, Coalburg Rider, Stockton and 5
Block
Reserves(1) 785 MT 92 MT 115 MT
Mine Life 25+ years 20+ years 20+ years
Production
Capacity 28 MMT 5.2 MMT 4 MMT
High Quality, Low Cost Assets with Long Mine Life
Coal Division
1 Based on end of year 2014 reserve estimate. 2 Cash cost per ton calculated as total cost per ton less DD&A per ton.
2
(1) For the period ending and as of 12/31/2014.
(2) Source: EIA. Represents average power plant deliveries for the twelve months ended 12/31/2014.
(3) Source: Company filings from FELP, ARLP, WMLP and RNO.
Pennsylvania Mining Complex
Coal Division
37
Pennsylvania mining complex consists of three like-new
underground mines and related infrastructure with high-Btu
bituminous coal (785.6 million tons proven and probable(1))
Train loadout facility (up to 9,000 tons per hour) with dual rail
access with Norfolk Southern and CSX
High-Btu bituminous thermal coal is primarily sold to utility
companies in the eastern United States - 13,000 Btus per pound
average gross heat content and 2.37% average sulfur content
Reserves are mined from the Pittsburgh No. 8 Coal Seam located in
the Northern Appalachian Basin
Five longwalls and 18 continuous mining sections
Access to seaborne markets through CONSOL-owned Baltimore
Marine Terminal for exporting thermal and metallurgical coal
Mine
Total
Recoverable
Reserves
(tons) (1)
Average
Gross Heat
Content
(Btu/lb) (1)
Average
Sulfur
Content (1)
Annual
Production
Capacity
(tons) (1)
2015
Production
(tons) (1)
Bailey 254.5 12,929 2.68% 11.5 10.2
Enlow Fork 322.8 12,942 2.21% 11.5 9.0
Harvey 208.3 13,080 2.25% 5.5 3.6
Total 785.6 12,974 2.37% 28.5 22.8
Illinois Basin 11,396 2.94%
Other NAPP 12,134 3.19%
Other Coal
MLPs 11,619 2.74%
(2)
(3)
654925_1.w or (NY0086JT)
Baltimore
Terminal
PA Mining
Complex
Active Complex
Port/Dock
CNXC Customers
We couldn't fine the original
artwork 655159_Graphic.ai
NY0086JT so we had to
ungroup it and make the
edits.
(2)
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
0
5
10
15
20
25
CN
X/C
NX
C A
sse
ts (
5)
Mari
on C
ounty
(1
)
Mon
ongalia
County
(1
)
Em
era
ld (
1)
Federa
l (1
)
Harr
ison C
oun
ty (
1)
Mou
nta
in V
iew
(1)
Leer
(1)
Mars
hall
Coun
ty (
2)
Cum
berla
nd (
1)
Centu
ry (
1)
Oh
io C
ounty
(1)
Tunne
l Rid
ge (
1)
Pow
hata
n (
1)
Su
lfu
r (%
as r
ece
ived
)
Pro
du
cti
on
(m
illio
n t
on
s)
2015 Production - CNX/CNXC Assets 2015 Production - Other Longwalls 2015 Sulfur
Source: EIA 923, MSHA; Number of longwalls indicated in parentheses.
Not All NAPP Longwalls Are Created Equal
Coal Division
38
PA Mining Complex is uniquely positioned among NAPP longwall producers to provide
sustained supply of high-quality coal to rail-served power plants in the eastern U.S.
Closed
in 2015
Serve River Markets
Primarily
Met Coal
Producer
Mine Mouth
Operations
Near End of
Reserve Life
Higher
Sulfur
Closed
in 2015
39
Financial
40
Financial: Focused on Free Cash Flow
Solid liquidity position
CNXC and CONE
Asset monetization program
Reduction in legacy liabilities
Guidance: Production, price realizations, operating and capital costs
- Growing E&P production volumes
- Reductions to operating and overhead costs
- Reductions in E&P capital intensity
Service cost deflation: beating expectations; improves capital spending efficiency
Leverage in-place infrastructure
Continue to high-grade development plan (Dry Gas Utica potential)
- Steady coal production with lower cost base
CONSOL remains focused on lowering costs and deleveraging the balance sheet
through organic operations and potential asset sales
41
Debt and Liquidity Profile
Financial: Liquidity
Note: Some numbers may not match exactly to financial statements due to rounding.
(1) The 2022 and 2023 senior notes includes $6 million and $7 million of unamortized bond premium / discount, which will be amortized over the life of the notes, respectively.
(2) Total Debt of $3.740 billion excludes total unamortized debt issuance costs of $33 million.
(3) Net Debt equals Total Debt less Cash and Cash Equivalents.
(4) As of 12/31/2015, CNX had approximately $952 million of borrowings and $258 million of outstanding letters of credit under its revolving credit facility, leaving approximately $790 million of
availability. CNXC had $185 million outstanding on its revolving credit facility leaving approximately $215 million of availability.
Goal to lower leverage ratio and increase liquidity over the next 18 months
CNX
Consolidated
CNXC:
100%
CNX
Attributable
Capitalization and Liquidity 12/31/2015 12/31/2015 12/31/2015
Capitalization
Cash and Cash Equivalents $73 $7 $66
Revolving Credit Facility Balance 1,137 185 952
Capital Lease Obligations 43 - 43
Total Secured Debt $1,180 $185 $995
8.25% Senior Notes due 2020 $74 - $74
6.375% Senior Notes due 2021 21 - 21
5.875% Senior Notes due 2022 (1) 1,856 - 1,856
8.0% Senior Notes due 2023 (1) 493 - 493
Baltimore 5.75% Revenue Bonds due 2025 103 - 103
Miscellaneous Debt 13 - 13
Total Debt (2) $3,740 $185 $3,555
Net Debt (3) $3,667 $178 $3,489
Stockholders’ Equity $4,856 $154 $4,702
Total Capitalization $8,596 $339 $8,257
Liquidity
Cash and Cash Equivalents $73 $7 $66
Revolving Credit Facility Capacity (4) 1,005 215 790
Total Liquidity $1,078 $222 $856
(5) Number of MLP units owned by CNX as of 12/31/2015 and unit prices as of market close on 1/22/2016.
(6) CNX Coal Resources liquidity data is as of 12/31/2015 and CONE Midstream data is as of 9/30/2015.
(7) Adjusted EBITDA Attributable to CNX Shareholders is a non-GAAP financial measure and the
reconciliation is provided in the Appendix. Bank methodology EBITDA equals Adjusted EBITDA of $793
million plus gain on sale of assets of $56 million, plus gain related to changes in retiree medical (OPEB)
plan of $244 million, less the $94 million of CNXC EBITDA Attributable to CNX, plus the $51 million of
CNXC cash distributions to CNX less $21 million of other net adjustments. For a reconciliation of CNXC’s
EBITDA please see the Company’s form 10Q’s and 10K’s. Bank net debt equals debt of $3.555 billion, less
$66 million cash on hand excluding CNXC’s cash, $10 million of advance mining royalties, plus $191 million
of net letters of credit related to firm transportation obligations, mining equipment leases and insurance
policies.
CNX
Onwed LP
Units(5)
Unit
Price(5)
Market
Value
CNX Coal Resources LP (CNXC:NYSE) 12.7 $6.76 $86
CONE Midstream Partners LP (CNNX:NYSE) 19.1 $9.97 $190
Total Equity Value of Ownership Interests in Affiliated Public MLPs $276
Liquidity of Affiliated MLPs
Total
Facility
Capacity
Outstanding
Balance
Available
CapacityCash
Total
Liquidity of
Affiliates
CNX Coal Resources LP (6)
$400 $185 $215 $7 $222
CONE Midstream Partners LP (6)
$250 $57 $193 $1 $194
Total Liquidity of Affiliated
Public MLPs $650 $242 $408 $8 $416
Leverage Ratio 12/31/2015
LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7) $1,028
LTM Bank Net Debt / Adj. EBITDA (7)
3.6x
Equity Value of Ownership in Affiliated Public MLPs
As of Period End: 12/31/2012 12/31/2013 12/31/2014 12/31/2015 12/31/2016E
Legacy Liabilities ($MM)
LTD $39 $20 $22 $20 $18
WC 180 85 90 83 86
CWP 184 121 126 123 120
OPEB 3,018 1,022 761 672 678
Salary Retirement/Pension 225 53 119 94 85
Asset Retirement Obligations 699 601 576 550 550
Total Legacy Liabilities $4,345 $1,902 $1,694 $1,542 $1,537
FY 2012 FY 2013 FY 2014 FY 2015 FY 2016E
Total Annual Legacy Liabilities Cash Servicing Cost $370 $148 $153 $137 $109
Legacy liabilities reduced and cash servicing costs reduced by more than 60%
since 2012, with further reductions expected going forward
42
Significant Legacy Liability Reductions Over Past 3 Years
Financial: Legacy Liabilities
$4,345
$1,902 $1,694 $1,542 $1,537
$370
$148 $153 $137
$109
$100
$125
$150
$175
$200
$225
$250
$275
$300
$325
$350
$375
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
12/31/2012 12/31/2013 12/31/2014 12/31/2015 FY 2016E
An
nu
al C
ash
Se
rvic
ing
Co
st
Lega
cy L
iab
iliti
es
Projected $107MM Annual Cash
Servicing Cost for FY 2016, a
$28MM reduction from the year-
end 2015 run-rate of $137MM
Flows through P&L in operating
costs (impact reflected in
operating cost guidance)
Flows through P&L in Coal
Division’s “Other Costs”
Flows through P&L within:
E&P–Operating Expense
Coal Divisions–Other Costs
43
CNXC: Organizational Structure and CNX Ownership
Financial: CNX Coal Resources LP (CNXC:NYSE)
In July 2015 IPO, sold 10.6 million LP units, or 44.6%,
raising approximately $158 million in gross proceeds;
CNXC also distributed $197 million in cash to
CONSOL related to the revolver drawdown
CONSOL retained a 53.4% interest in the LP units and
owns 100% of the GP, which has a 2% interest
CONSOL Energy retained an 80% undivided interest
in the Pennsylvania mining complex and owns 100%
of CNXC’s general partner, as well as the incentive
distribution rights
CNXC owns a 20% undivided interest(1) in, and
operational control over, CONSOL Energy’s Pennsylvania
mining complex (Bailey, Enlow Fork and Harvey mines)
(1) Unless otherwise specified, all figures relating to reserves and production of the Pennsylvania mining complex in this presentation are on a 100% basis.
CNXC is an avenue for CONSOL’s transition to a pure play Appalachian Basin E&P Company
80% undivided
ownership interest
CNX Coal Resources LP
NYSE: CNXC
CNX Coal Resources GP
LLC
Pennsylvania
mining complex
Public
100% ownership
interest
limited partner
interest
2% general
partner interest
and IDRs
20% undivided
ownership interest and
management and control
rights
limited partner
interest
CONSOL Energy Inc.
("CONSOL Energy")
NYSE: CNX
Greenlight
Capital
(in millions except for per unit amounts)
Total LP Units held by CONSOL Energy 12.7
Unit Price (as of close on 1.22.2016) $6.76
CNXC Units Equity Value to CONSOL Energy $85.6
CONSOL Energy's Ownership Interest in CNX Coal
Resources LP (CNXC:NYSE)
$4
$7
$10 $9 $8$9
$13
$0
$4
$8
$12
$16
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15
CONE Midstream's and Gathering's Pro Rata Net Income Contribution to CNX
CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's Net Income
$5
$8
$11$10
$13
$15
$19
$9$11
$15$4
$4
$4
$0
$4
$8
$12
$16
$20
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15
CONE Midstream's and Gathering's Pro Rata EBITDA Contribution to CNX
CNX Pro Rata Share of CONE Midstream Partners LP's Cash Distributions
CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's EBITDA
CONSOL owns 32.1% of CONE Midstream Partners LP’s
(CNNX:NYSE) LP units and 50% of the General Partner
(“GP”), which has a 2% interest in CNNX (and rights to
IDRs)
CNNX owns interests in 3 development companies
(ownership structure detailed in Appendix)
The remaining un-dropped portion of the development
companies’ interests are held by CONE Gathering LLC
(“CGLLC”), a privately held Joint Venture between
CONSOL Energy (CNX:NYSE) and Noble Energy
(NBL:NYSE)
CNX’s share of CONE Midstream’s Net Income (CNNX &
CGLLC) flows into the E&P segment’s “Equity in Earnings
of Affiliates,” which in CNX’s consolidated financial
statements falls within the “Miscellaneous Other Income”
line item
Distributions run straight through CNX’s cash flow
statement in the “Return on Equity Investment” line item
CNX has seen increasing benefit from CONE’s EBITDA and
cash distributions, on top of which CNNX recently
increased its cash distribution 3.5% from its prior run-rate
44
Financial: CONE’s Growing Cash Contribution
Note: For a reconciliation of CONE’s EBITDA please see the CNNX’s form 10Q’s and 10K’s.
Source: CONE Midstream Partners LP and CONSOL Energy Inc.
Net Income and EBITDA saw slight dips in 4Q14 and 1Q15 due to CNNX
IPO costs and temporary operational impacts from the unusually cold
winter. Subsequently, CONE has resumed its growth trend and action
has been taken operationally to limit weather impact in the future.
(in millions except for per unit amounts)
LP Units held by CONSOL Energy 19.1
Unit Price (as of close on 1.22.2016) $9.97
CNNX Units Equity Value to CONSOL Energy $190.4
CONSOL Energy's Ownership Interest in CONE
Midstream Partners LP (CNNX:NYSE)
45
Financial: Guidance Summary
Note: Guidance as of 1/29/2016.
(1) Represents estimated unutilized firm transportation and processing expense less estimated gathering revenue (resold firm transportation).
E&P Segment Guidance 2016E
Production Volumes:
Natural Gas (Bcf)
NGLs (MBbls)
Oil (MBbls)
Condensate (MBbls)
Total Production (Bcfe)
Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.35) - ($0.45)
NGL Realized Price ($/Bbl) $7.00 - $9.00
Condensate Realized Price % of WTI 43% - 46%
Oil Realized Price % of WTI 93% - 95%
Capital Expenditures:
Drilling and Completion $110 - $210
Midstream 40 - 50
Land and Other 55 - 65
Total E&P and Midstream CapEx $205 - $325
Average per unit operating expenses:
Lease Operating Expenses 0.20 - 0.25
Impact Fees/ Ad Valorem/ Production Taxes 0.06 - 0.08
Gathering, Transportation, Compression & Processing 1.06 - 1.10
Direct Administrative and Selling 0.08 - 0.10
Depreciation, Depletion and Amortization 1.00 - 1.07
Total Production and Gathering Costs 2.40 - 2.60
Other Expenses:
General and Administrative Expense $48.0 - $52.0
Unutilized Firm Transportation Expense, net:(1)$15.0 - $16.0
335
~+15%
6,000
65
1,000
46
Financial: Guidance Summary
Note: Guidance as of 1/29/2016.
Coal Segment 2016E
Total Coal Operations
Estimated Total Coal Sales Volumes 27.0 - 32.0
Total Committed Volumes (Contracted & Priced) 27.8
% Committed 94%
Estimated Total Average Price ($/Ton) $50.00 - $55.00
Capital Expenditures:
Production $140 - $155
Other (Land/Water/Safety/Terminal) 30 - 35
Total Coal CapEx $170 - $190
Average per unit operating expenses:
Total Production Costs (including DD&A) $41.50 - $45.00
Depreciation, Depletion and Amortization $6.50 - $7.00
Other Expenses:
General and Administrative $20 - $25
47
Milestones:
Improving E&P performance from high-grading activities, improving completion techniques, reducing cycle times, and
service deflation
Benefits from recent long-term contracting activities and operating cost reductions
CONE MLP growth – January 25th announced 3.6% increase to quarterly distribution to $0.2362 per unit
Positive initial operated Utica well results (Gaut 4IH, GH9, and Switz 6D)– sets up future stacked pay opportunities
- Continued focus on zero-based budgeting – expecting significantly reduced costs and improved balance sheet
- Improving price realizations – anticipate excess Appalachian firm transportation capacity above production to drive
narrowing basis by year-end 2016. This should help both natural gas and thermal coal prices.
- Use of free cash flow and opportunistic asset sales to de-lever
Our management team is motivated and incentivized long-term to increase return on capital employed and
NAV/share
Plans and Goals Aligned to Drive Increased Valuation
We will continue to be focused on increasing shareholder value while staying within
our core values of safety, compliance, and continuous improvement
Financial: Summary
48
Appendix
49
Non-GAAP Reconciliation: Quarter-over-Quarter EBITDA and Adj. EBITDA
Appendix
Source: Company filings.
Three Months Ended Twelve Months Ended
December 31
($ in thousands) 2015 2014
Net Income $34,325 $73,666
Add: Interest Expense 49,082 53,025
Less: Interest Income (431) (476)
Add: Tax Valuation Allowance 65,395 -
Add: Income Taxes (Benefit) 59,569 6,032
Earnings Before Interest & Taxes (EBIT) from Continuing Operations 207,940 132,247
Add: Depreciation, Depletion & Amortization 159,170 166,841
Earnings Before Interest, Taxes and DD&A (EBITDA) $367,110 $299,088
Adjustments:
OPEB Plan Changes (109,879) -
Unrealized Gain on Commodity Derivative Instruments (62,388) -
Pension Settlement 15,921 3,603
Industrial Supplies Working Capital Settlement 6,258 -
Gain on sale of non-core assets (7,551) (19,830)
Blacksville Fire Settlement - (9,750)
Total Pre-tax Adjustments ($157,639) ($25,977)
Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $209,471 $273,111
Less: Noncontrolling Interest* ($3,920) -
Adjusted EBITDA Attributable to CONSOL Energy Shareholders $205,551 $273,111
50
Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA
Appendix
Source: Company filings.
Three Months Ended Three Months Ended Three Months Ended Three Months Ended Twelve Months Ended
March 31 June 30 September 30 December 31 December 31
($ in thousands) 2015 2015 2015 2015 2015
Net Income / (Loss) $79,031 ($603,301) $125,470 $34,325 ($364,475)
Add: Interest Expense $55,122 $46,507 48,558 49,082 199,269
Less: Interest Income ($1,143) ($364) (361) (431) (2,299)
Add: Income Taxes (Benefit) (25,603) (291,929) 58,143 124,964 (134,425)
Earnings Before Interest & Taxes (EBIT) from Continuing Operations 107,407 (849,087) 231,810 207,940 (301,930)
Add: Depreciation, Depletion & Amortization $161,922 $166,798 $161,711 159,170 649,601
Earnings Before Interest, Taxes and DD&A (EBITDA) $269,329 ($682,289) $393,521 $367,110 $347,671
Adjustments:
OPEB Plan Changes - (33,649) (100,947) (109,879) (244,475)
Impairment of E&P Properties - 828,905 - - 828,905
Unrealized Gain on Commodity Derivative Instruments (60,004) 24,936 (99,138) (62,388) (196,594)
Pension Settlement - - 3,132 15,921 19,053
Industrial Supplies Working Capital Settlement - - - 6,258 6,258
Gain on Sale of Non-core Assets - - (48,468) (7,551) (56,019)
Severance Payments - - 7,683 - 7,683
Loss on Debt Extinguishment 67,734 17 - - 67,751
Backstop Loan Fees - 7,334 - - 7,334
Other Transaction Fees - 4,968 - - 4,968
Total Pre-tax Adjustments 7,730 832,511 (237,738) ($157,639) $444,864
Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $277,059 $150,222 $155,783 $209,471 $792,535
Less: Noncontrolling Interest* - - (6,490) ($3,920) ($10,410)
Adjusted EBITDA Attributable to CONSOL Energy Shareholders $277,059 $150,222 $149,293 $205,551 $782,125
51
Joint Ventures
(1) CONSOL holds ~86,387 net acres outside of the Marcellus JV. As of 12/31/2015.
(2) CONSOL holds ~40,052 net acres outside of the Utica JV, which includes ~13,000 net acres in Monroe County, OH. As of 12/31/2015.
(3) The remaining carry balance on a cash basis is $1.62 billion for Marcellus and $22 million for Utica, respectively. Utica carry has an accrued cash balance of
$21 million as of end of 4Q 2015.
(1) (2)
(3) (3)
Description Marcellus / Noble Energy Inc. Utica / Hess Corporation
Ownership 50/50 50/50
Acreage 349,541 79,266
Zones PA and WV Marcellus, Burkett to Onondaga OH Utica
Carry
Noble to pay 1/3 of CNX 50% share of eligible
charges
Maximum annual payment of $400 million per year
Henry Hub spot price averages over $4.00 per
month for three consecutive months
Hess to pay 50% of CNX 50% share of eligible
charges (i.e. CNX pays 25%)
Total carry amount $1.85 billion, of which $1.62 billion remains as of
end of 4Q15
$335 million, of which ~$2 million remains as of end
of 4Q15
Carry eligible* Capital - D&C, facilities, site construction Capital - D&C, facilities, site construction, seismic
Non-carry eligible
(pay straight WI %) LOE, leases, delay rentals, seismic LOE, leases, delay rentals
Summary of JV Carry Eligible Capital
Appendix
52
~436,000 CONSOL net
acres
─ ~88% NRI
─ ~91% HBP
23.9 Tcfe 3P
Over 8,900 gross potential
wells(1)
Marcellus production grew
at a 71% CAGR from 2013
to 2015
Producing Pads
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
(1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2014.
Marcellus Shale: Overview
Appendix
53
Total Gross Prospective Marcellus Acreage ~785,000
- Gross Acres within JV ~699,000
- Acres outside JV – 100% CONSOL ~86,000
Acreage per well (assumed 750 ft spacing) ~86
Gross Producing wells (JV - YE2014) 384
Gross PDNP and PUD locations (YE2014) 828
Gross prospective unproved locations ~8,000
Producing wells as % of PDNPs, PUDs, and prospective locations 4%
Note: Acreage as of December 31, 2015, locations as of December 31, 2014 unless otherwise noted.
~527 MMcfe/d net being produced from ~4% of net Marcellus acreage
Marcellus Shale Upside Potential
Marcellus Shale: Growth Runway and Depth of Inventory
Appendix
54
Marcellus Shale
SWPA CPA WV Ohio(1) North
Wet
South
Wet Total
Net Acres ~44,000 ~108,000 ~111,000 ~14,000 ~52,000 ~107,000 ~436,000
Approximate
Gross
Locations(2)
800 2,000 2,400 100 1,400 2,200 ~8,900
Avg
EURs/1,000 ft
(Bcfe)
2.1 1.6 1.8 -- 1.8 2.1 --
Marcellus Shale is one of the main growth drivers of the E&P Division
Marcellus Shale: Sub-Regions Summary
Note: Acreage as of December 31, 2015 and locations are as of December 31, 2014, unless otherwise noted.
(1) Non-JV acreage is located in Monroe County, OH.
(2) Based on 5,000 ft laterals with 86-acre spacing.
Appendix
55
Appendix Marcellus Shale: Southwest PA Overview
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
(1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2014.
~44,000 CONSOL net
acres
Over 800 gross locations(1)
─ 189 wells online, as of
12/31/2015
─ 0 wells TIL in Q4 2015
─ 8 wells per pad on
average in 2015
2.1 Bcfe EUR/1,000 ft of
lateral
750 ft inter-lateral spacing
NV36 Pad
7 Wells
5,021’ Avg Lateral Length per well
6,159 Mcfe Avg 30-day IP per well
MOR10 Pad
6 Wells
4,771’ Avg Lateral Length per well
6,341 Mcfe Avg 30-day IP per well
Producing Pads
Competitor Pads
NV56 Pad
6 Wells
8,753’ Avg Lateral Length per well
9,230 Mcfe Avg 30-day IP per well
NV57 Pad
8 Wells
8,914’ Avg Lateral Length per well
10,435 Mcfe Avg 30-day IP per well
56
Appendix Marcellus Shale: North Wet Gas Overview
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
(1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2014.
WFN3 Pad
4 Wells
7,380’ Avg Lateral Length per well
7,079 Mcfe Avg 30-day IP per well
4,800 MMcf/d 60-day IP per well
~52,000 CONSOL net
acres
Over 1,400 gross
locations(1)
─ 136 wells online as of
12/31/2015
─ 0 wells TIL in Q4 2015
─ 6 wells per pad on
average
1.8 Bcfe EUR/1,000 ft of
lateral
Increasing use of
RCS/SSL
750 ft inter-lateral spacing
Condensate yield: 5
Bbls/MMcf
NGLs yield: 49 Bbls/MMcf
WFN6 Pad
8 Wells
6,451’ Avg Lateral Length per well
8.5 MMcf/d Avg 24-hour IP per well
6,800 MMcf/d 60-day IP per well
Producing Pads
Competitor Pads
SHL13 Pad
7 Wells
5,299’ Avg Lateral Length per well
4,039 Mcfe Avg 30-day IP per well
SHL23 Pad
5 Wells
7,245’ Avg Lateral Length per well
6,620 Mcfe Avg 30-day IP per well
57
Appendix
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
(1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2014.
DAVIES (EQT)
7 Wells
3,756’ Avg Lateral Length per well
487 MMcf/well – 1st 6-Month Cum
1562 Bbl/well – 1st 6-Month Cum
HARPER (EQT)
3 Wells
3,684’ Avg Lateral Length per well
448 MMcf/well – 1st 6-Month Cum
472 Bbl/well – 1st 6-Month Cum
WEESE (Triad Hunter)
3 Wells
3,711’ Avg Lateral Length per well
530 MMcf/well – 1st 6-Month Cum
2473 Bbl/well – 1st 6-Month Cum
~107,000 CONSOL net
acres
Over 2,200 gross
locations(1)
─ 31 wells online, as of
12/31/2015
─ 6 wells per pad on
average
2.1 Bcfe EUR/1,000 ft of
lateral
750 ft inter-lateral spacing
Condensate yield: 10
Bbls/MMcf
NGLs yield: 51 Bbls/MMcf
PENS1 Pad
9 Wells
~6,824’ Avg Lateral Length per well
Marcellus Shale: South Wet Gas Overview
SHR1 Pad
6 Wells
~8,741’ Avg Lateral Length per well
10,143 Mcfe Avg 30-day IP per well
PENS2 Pad
12 Wells
Currently under flowback
OXF1 Pad
6 Wells
~6,353 Avg Lateral Length per well
5,517 Mcfe Avg 30-day IP per well
Producing Pads
Competitor Pads
DTI Storage Fields
58
Marcellus Shale: Northern WV Dry Overview
PHL4 Pad
3 Wells
6,533’ Avg Lateral Length per well
5,212 Mcfe Avg 30-day IP per well
720 MMcf/well – 1st 6-month Cum
ANDERSON (PDC Mountaineer)
3 Wells
4,859’ Avg Lateral Length per well
595 MMcf/well – 1st 6-Month Cum
~111,000 CONSOL net
acres
Over 2,400 gross
locations(1)
─ 49 wells online, as of
12/31/2015
─ 0 wells TIL in Q4 2015
1.8 Bcfe EUR/1,000 ft of
lateral
750 ft inter-lateral spacing
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
(1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2014.
AUD3 Pad
1 Well Delineation
8,691’ Avg Lateral Length per well
6,099 Mcfe Avg 30-day IP per well
917 MMcf/well – 1st 6-month Cum
CENT3 Pad
1 Well Delineation
7,470’ Avg Lateral Length per well
4,973’ Mcfe Avg 30-day IP per well
635 MMcf/well – 1st 6-month Cum
PHL13 Pad
6 Wells
7,949’ Avg Lateral Length per well
6,869 Mcfe Avg 30-day IP per well
923 MMcf/well – 1st 6-month Cum
Producing Pads
Competitor Pads
DTI Storage Fields
AUD7 Pad
1 Well Delineation
9,745’ Avg Lateral Length per well
7,120 Mcfe Avg 30-day IP per well
PHL10 Pad
6 Wells
4,636’ Avg Lateral Length per well
3,148 Mcfe Avg 30-day IP per well
Appendix
59
Marcellus Shale: Central PA Overview
GAUT4 Pad
4 Wells
7,941’ Avg Lateral Length per well
6,619 Mcfe Avg 30-day IP per well
759 MMcf/well – 1st 6-month Cum
COOK (Atlas/Chevron)
2 Wells
3,352’ Avg Lateral Length per well
400 MMcf/well – 1st 6-Month Cum
GREENAWALT (Chevron
Appalachia)
3 Wells
3,725’ Avg Lateral Length per well
800 MMcf/well – 1st 6-Month Cum
SMITH (Atlas/Chevron)
2 Wells
2,680’ Avg Lateral Length per well
722 MMcf/well – 1st 6-Month Cum
~108,000 CONSOL net
acres
Over 2,000 gross
locations(1)
─ 56 wells online, as of
12/31/2015
─ 0 wells TIL in Q4 2015
─ 5 wells per pad on
average
1.6 Bcfe EUR/1,000 ft of
lateral
750 ft inter-lateral spacing
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015).
(1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2014.
KUHNS3 Pad
5 Wells
7,237’ Avg Lateral Length per well
7,259 Mcfe Avg 30-day IP per well
937 MMcf/well – 1st 6-month Cum
SHAW Pad
3 Wells
3,965’ Avg Lateral Length per well
7,817 Mcfe Avg 24-hr IP per well
523 MMcf/well – 1st-4-month Cum
MMS Pad
5 Wells
8,040’ Avg Lateral Length per well
6,677 Mcfe Avg 30-day IP per well
636 MMcf/well – 1st-4 month Cum
Producing Pads
Competitor Pads
CRAWFORD 5 Pad
2 Wells
7,305’ Avg Lateral Length per well
13,586 Mcfe Avg 24-hr IP per well
624 Mmcfe/well – 60 day Cum
MARCHAND 3I Well
6,418’ Lateral Length
735 Mmcfe – 150 day Cum
Appendix
60 Notes: PA and WV prospective Utica eastern boundary has yet to be delineated. Acreage is risked 50+% in PA and WV. Acreage in Ohio oil window is excluded after risking.
Acreage as of December 31, 2015, locations as of December 31, 2014 unless otherwise noted.
~1% of net Utica acreage developed to date
Utica Shale Upside Potential
Utica Shale: Growth Runway and Depth of Inventory
Total Gross Prospective Utica Acreage ~701,000
- Gross Acres within JV ~158,000
- Acres outside JV – 100% CONSOL ~543,000
Acreage spacing per well (assumed 750 ft spacing) ~86
Gross Producing wells (JV - YE2014) 44
Gross PDNP and PUD locations (YE2014) 88
Gross prospective unproved locations ~3,000
Producing wells as % of PDNPs, PUDs, and prospective locations ~1%
Appendix
61
Potential resource of ~30 Tcfe
Note: Acreage as of December 31, 2015, locations as of December 31, 2014 unless otherwise noted.
Utica Shale
Ohio Wet Ohio Dry PA/WV Dry Total
Net Acres ~89,000 ~30,000 ~503,000 ~622,000
Approximate Gross
Locations(1) 500 300 2,200 3,000
Avg EURs/1,000 ft
(Bcfe) 2.1 2.4 2.4 --
Utica Shale: Sub-Regions Summary
Appendix
62
~622,000 CONSOL net
acres in Utica
─ ~306,000 net acres in
PA
─ ~197,000 net acres in
WV
─ 30,000 net acres in OH
Dry
~14,000 net acres in
Monroe County, OH
─ 89,000 net acres in OH
Wet
Majority of acreage
offset to peers with
strong results
─ The main area without
offset results was
Westmoreland County
where CNX drilled the
Gaut 4IH which had the
2nd highest IP in the
Utica to date
Utica Shale: Offset Peer Acreage
Appendix
Notes: CNX acreage position as of 12/31/2015. CNX acreage shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres.
Source: Third party acreage positions based on GIS data from Western Land Services.
63 Note: Peer data based on publicly available information. CONSOL wells are 24-hour IP rates. Other producers’ IP rates may be different. Townships shown in yellow where CONSOL holds
3,000 or more acres (as of 12/31/2015).
Utica Shale: CNX Acreage Position in the Core OH Wet Gas Utica
Appendix
CNX - NBL 18
IP GAS: 8,213 Mcf/d per well
IP OIL: 834 Bbl/d per well
CNX - NBL 30
IP GAS: 9,481 Mcf/d per well
IP OIL: 723 Bbl/d per well
GPOR - Boy Scout 33H
IP GAS: 5,300 Mcf/d
IP OIL: 1,560 Bbl/d
CHK - Buell 8H
IP GAS: 9,500 Mcf/d
IP OIL: 1,425 Bbl/d
GPOR - Wagner 1-28H
IP GAS: 14,000 Mcf/d
IP OIL: 432 Bbl/d
AR - Miley 5HA
IP GAS: 7,700 Mcf/d
IP OIL: 1,285 Bbl/d
GPOR - Shugert 1-12H
IP GAS: 28,500 Mcf/d
IP OIL: 300 Bbl/d
HES – Cadiz A
IP GAS: 8,006 Mcf/d
IP OIL: 399 Bbl/d
REXX - Guernsey 2H
IP GAS: 8,082 Mcf/d
IP OIL: 564 Bbl/d
GPOR - Irons 1-4H
IP GAS: 30,200 Mcf/d
IP OIL: 0 Bbl/d
CNX - NBL 16A
IP GAS: 12,000 Mcf/d
IP OIL: 750 Bbl/d
CNX - NBL 19
IP GAS: 13,400 Mcf/d per well
IP OIL: 938 Bbl/d per well
CNX - NBL 16B
IP GAS: 5,630 Mcf/d
IP OIL: 522 Bbl/d
HES – Cadiz B
IP GAS: 10,254 Mcf/d
IP OIL: 191 Bbl/d
HES – Athens A
IP GAS: 7,745 Mcf/d
IP OIL: 330 Bbl/d ~34,000 net core wet acres
17% of liquid hydrocarbon sweet spot controlled by CONSOL JV
~85,000 CONSOL net acres
~34,000 CONSOL net acres
in core
Type curve reflects core
area
Over 500 gross core area
locations(1)
─ 87 wells online, as of
12/31/2015
─ 14 wells online in Q4 2015
─ 8,082 ft average laterals in
Q4 2015
─ 4-5 wells per pad on
average
2.1 Bcfe EUR/1,000 ft of
lateral
RCS/SSL standard for new
drills
750 ft inter-lateral spacing
64
Stacked pays provide a large inventory and rich opportunity set
Wet
Net Acres
Dry
Net Acres
Total
Net Acres
190,000
173,000
89,000
452,000
155,000
263,000
951,000
345,000
436,000
622,000
1,403,000
(1) Dry Utica includes 503,000 net prospective acres in Pennsylvania and West Virginia. As of December 31, 2015.
Stacked Pay Potential: Appalachian Shale Acreage
533,000
Upper
Devonian
Marcellus
Utica(1)
Rhinestreet
Shale
Middlesex
Shale
Burkett Shale
West River
Shale
Formation
Name
P
a
y
Cashaqua
Shale
Tully
Limestone
Hamilton Shale
Marcellus
Shale
Onondaga
Limestone
Utica Shale
Point Pleasant
Shale
Trenton
Limestone 0 GR 400 LITHOLOGY Total
Appendix
65
Appendix
Source: CONE Midstream Partners LP.
CONE Corporate Structure
66
Coal Division: Low-cost, Highly Productive Longwall Mining Operations
The design of the Pennsylvania mining complex is optimized to
produce large quantities of coal on a cost efficient basis.
Pittsburgh No. 8 coal seam is a large, continuous formation of
uniform, high-Btu thermal coal that is ideal for high productivity,
low-cost longwall mining operations.
Highly automated and technologically advanced underground mining operation (1) Includes FELP, ARLP, RNO and WMLP as reported in the respective 10-K filings.
(2) Including transportation costs for FELP.
$25.27
$11.80
$0.00
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
PA Mining Complex Other Coal MLP's (incl. transp. cost)
2014 Average Cash Margin
($ /ton)
(1) (2)
Longwall Mining
CNXC
Other NAPP Other
Coal MLPs
ILB
PRB
8,000
10,000
12,000
14,000
Btu Content
CNXC
Other Coal MLPs
ILB
Other NAPP
0.00%
0.40%
0.80%
1.20%
1.60%
2.00%
2.40%
2.80%
3.20%
3.60%
Sulfur Content
Advantaged Coal Characteristics
(1)
(2)
(2)
(1)
(btu/lb)
(1)
(1)
(1)
During 2014, the PA mining complex generated the
highest cash margin of any of i ts coal peers (1)(2)
Appendix