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Company Presentation Q3 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 the volume of hydrocarbons that are
recoverable from our oil and gas assets; 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.
3
Q3 2015 Overview
Key Takeaways
4
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
Modest levels of asset sales assumed between $75-$125 million (already sold assets for ~$95 million of cash proceeds)
CONSOL Energy has approximately $2 billion of assets available for sale and the proceeds of these sales will be
used to further reduce debt
Not including MLP drop-downs or strategic transactions
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 businesses
5
Net income Attributable to CONSOL Energy Shareholders for the third quarter was $119.0 million
- Includes the following pre-tax items:
$100.9 million benefit related to changes in retiree medical OPEB plan
$99.1 million unrealized gain on commodity derivative instruments
$48.5 million gain on sale of coal assets
$7.7 million in severance payments
$3.1 million related to pension settlement
E&P Division’s third quarter net income was $30.3 million
- Production increased by 33% in the third quarter compared to year-earlier quarter
- Revenue decreased by 22% in the third quarter compared to the prior year due to depressed commodity prices
- Marcellus Shale all-in unit costs were $2.57 per Mcfe in the third quarter, a decrease of $0.12 from $2.69 per Mcfe
in the year-earlier quarter, or (4%)
- Utica Shale production volumes were 15.3 Bcfe in the third quarter, a 128% increase from 6.7 Bcfe in the year-
earlier quarter
- Utica Shale all-in unit costs were $2.14 per Mcfe in the third quarter, a decrease of $0.23 from $2.37 per Mcfe in
the year-earlier quarter, or (10%)
(1) Adjusted EBITDA is a non-GAAP financial measure and a consolidated number, please refer to the reconciliation is provided in the Appendix.
CONSOL Energy: Third Quarter 2015 Results
Q3 2015 Overview
Q3 2015 Summary Y/Y Q-to-Q Seq. Q-to-Q
($ in millions, except per share data) 3Q2015 3Q2014 Change 3Q2015 2Q2015 Change
Net (Loss) Income Attributable to CNX Shareholders $119 ($2) $121 $119 ($603) $722
Earnings per Diluted Share $0.52 ($0.01) $0.53 $0.52 ($2.64) $3.16
Revenue and Other Income $814 $885 ($71) $814 $649 $165
Cash Flow from Operations $110 $293 ($183) $110 $62 $48
Adjusted EBITDA(1) $136 $236 ($100) $136 $138 ($2)
6
E&P Division:
- 2015 production projected to be between 325- 330 Bcfe, up from 320-330 Bcfe
- Production volumes expected to grow approximately 20% in 2016 over 2015
- Capital efficiency improvements, including lean manufacturing, achieve same growth with less capital
2016 E&P capital budget guidance of $400 – $500 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 strong liquidity position
Coal Division:
- Multi-year sales secured to bring Pennsylvania operations to 74% sold for FY 2016
Source: Company filings. Sum of numbers may differ slightly from totals and financial statements due to rounding.
(1) Approximately $180 million of 3Q 2015 Proceeds from LT debt is comprised entirely of CNXC LT revolver debt, consolidated on CNX financial statements per US GAAP accounting rules.
CONSOL Energy: Net (Decrease)/Increase in Cash
Q3 2015 Overview
Cash Flow Summary Y/Y Q-to-Q Seq. Q-to-Q
($ in millions) 3Q2015 3Q2014 Change 3Q2015 2Q2015 Change
Net Cash Provided by Operations $110 $293 ($183) $110 $62 $48
Capital Expenditures ($259) ($355) $96 ($259) ($342) $82
Proceeds From Asset Sales $76 $8 $68 $76 $5 $71
Other Investing ($26) $148 ($174) ($26) ($12) ($15)
Proceeds From /(Payments on) Short-Term Debt & Misc. Borrowings ($149) ($1) ($148) ($149) $296 ($445)
Proceeds From /(Payments on) Long-Term Debt(1) $180 $3 $177 $180 ($3) $183
Dividends Paid ($2) ($14) $12 ($2) ($14) $12
Proceeds from the sale of MLP interest (CNXC IPO) $148 $0 $148 $148 $0 $148
Other Financing ($4) ($3) ($1) ($4) $13 ($17)
Net (Decrease) / Increase in Cash $73 $78 ($6) $73 $5 $68
7
$2 billion Revolving Credit Facility:
5 year credit facility expires June 2019
Gas reserves based lending facility
Obtained the right to separate the coal and gas business subject to a leverage test
Strong Liquidity Position of ~$1 Billion
Q3 2015 Overview
September 30,
Negative Covenants Limit 2015
CONSOL Energy Revolver:
Minimum Interest Coverage Ratio < 2.5 to 1.0 4.9 to 1.0
Minimum Current Ratio < 1.0 to 1.0 2.0 to 1.0
Ample liquidity of over $850 million should continue to improve going forward 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 $83 million as of 9/30/2015, $3 million of which was CNXC’s but consolidated per US GAAP accounting
(2) Revolving credit facility as of 9/30/2015
Amount/ Amount Letters Amount
September 30, 2015 ($ in million) Capacity Drawn of Credit Available
Cash and Cash Equivalents(1) $80 - - $80
Revolving Credit Facility(2) $2,000 $945 $281 $774
Total $2,080 $945 $281 $854
8
Coal Division: Q3 2015 Results Summary
Q3 2015 Overview
Y/Y Q-to-Q Seq. Q-to-Q
Coal Division 3Q2015 3Q2014 Change 3Q2015 2Q2015 Change
Average Sales Price ($ / ton) $56.34 $62.32 ($5.98) $56.34 $56.78 ($0.44)
Average Costs ($ / ton) $43.39 $49.93 ($6.54) $43.39 $45.69 ($2.30)
Coal Production (millions of tons) 7.3 7.8 (0.5) 7.3 7.5 (0.2)
Sales Volumes (millions of tons) 7.2 7.8 (0.6) 7.2 7.3 (0.1)
Sales Per Ton ($ / ton)
Pennsylvania Operations $56.99 $61.35 ($4.36) $56.99 $56.21 $0.78
Virginia Operations $51.82 $70.57 ($18.75) $51.82 $57.76 ($5.94)
Other Operations $57.36 $58.27 ($0.91) $57.36 $60.84 ($3.48)
79%
14%
7%
FY 2015 Sales Tons by Segment
PA Ops VA Ops Other
9
Coal Division: Q4, FY 2015 and 2016 Marketing Update and Forecasts
Q3 2015 Overview
2015 Coal Sales Facts and Goals
Contracted tons for 2015: 98%
- Priced: 97%
~77% of the PA Ops tons are expected to be sold
domestically
~77% of the VA Ops tons are expected to be sold
overseas
100% of the Other tons are expected to be sold
domestically
2016 Coal Sales Facts and Goals
Contracted tons for 2016: 71%
- Priced: 63%
Coal Sales
Guidance(1)
Q4 2015E Q4 2014 2015E 2014 2016E
PA Ops 5.1-5.6 6.5 23.0-23.5 26.1 25.0-27.0
VA Ops 0.7-1.0 1.1 3.9-4.2 4.1 3.7-4.2
Other 0.4-0.6 0.5 2.0-2.2 2.2 1.9-2.2
Total 6.2-7.2 8.1 28.9-29.9 32.4 30.6-33.4
80%
13%
7%
Q4 2015 Sales Tons by Segment
PA Ops VA Ops Other
Note: PA Ops tons reflecting volumes at 100% interest and are not pro rata for CNX ownership of the PA Complex or CNXC
(1) Tons in millions
Y/Y Q-to-Q Seq. Q-to-Q
E&P Division 3Q2015 3Q2014 Change 3Q2015 2Q2015 Change
Average Sales Price(1)
($ / Mcfe) $2.35 $3.97 ($1.62) $2.35 $2.68 ($0.33)
Average Costs(2)
($ / Mcfe) $2.63 $3.12 ($0.49) $2.63 $2.90 ($0.27)
Sales Volumes (Bcfe) 86.1 64.9 21.2 86.1 75.5 10.6
Sales Volumes (Bcfe) by Category
Marcellus 44.9 30.7 14.2 44.9 39.0 5.9
CBM 18.5 20.0 (1.5) 18.5 18.8 (0.3)
Utica 15.3 6.7 8.6 15.3 10.6 4.7
Other 7.4 7.5 (0.1) 7.4 7.1 0.3
10
Marcellus Shale production now largest part of
mix; Utica volumes growing rapidly as part of
production mix
2015E Marcellus Shale production CAGR ~67%
from 2013
“Other” category includes Shallow Oil and Gas,
Chattanooga Shale in Tennessee, and Upper
Devonian Shale production in PA and WV
E&P Division: Q3 2015 Results Summary
Q3 2015 Overview
(1) Average Sales Prices for 3Q2015, 3Q2014 and 2Q2015 include gains/(losses) on hedges of $0.60, $0.36 and $0.64, respectively.
(2) Average Costs for 3Q2015, 3Q2014 and 2Q2015 include DD&A of $1.02, $1.26 and $1.14, respectively.
51%
23%
19%
7%
FY 2015 Production by Category
Marcellus CBM Utica Other
11
E&P Division: Q3 2015 Operations Summary
Sub-
Regions
Horizontal
Rigs Drilled Completed
Turned
In Line
(TIL)
Avg. TIL
Lateral
Length
(ft)
Counties
Southwest
PA 1 3 7 6 7,002
Greene,
Washington,
PA
Central PA ---- ---- ---- ---- ---- Indiana, PA
Northern
WV Dry 1 5 ---- 6 6,787
Barbour,
Doddridge,
Lewis, WV
Ohio ---- ---- ---- ---- ---- Monroe, OH
North Wet
Gas 1 4 4 16 8,038
Greene,
Washington,
PA; Marshall,
WV
South Wet
Gas 1 2 ---- ---- ----
Doddridge,
Tyler,
Ritchie, WV
Total 4 14 11 28 7,276
Sub-
Regions
Horizontal
Rigs Drilled Completed
Turned
In Line
(TIL)
Avg. TIL
Lateral
Length (ft)
Counties
Core Wet ---- ---- ---- ---- ---- Monroe, Noble,
OH
Surrounding
Core Wet 1 5 5 11 7,525
Harrison,
Belmont, OH;
Greene, PA
Dry Utica ---- 1 4 ---- ----
Monroe, OH;
Westmoreland,
PA
Total 1 6 9 11 7,525
Marcellus Shale Quarterly Summary Utica Shale Quarterly Summary
Q3 2015 Overview
Continuous improvement leading to record drilling performance:
─ Cycle time decreased 57% for drilling dry OH Utica in Q3
compared to 2014 One record lateral casing to 10,634’
SWITZ 6D achieved an averaged 24-hour IP of 44.7 MMcf/d at a
pressure of 6,835 psi, well above expectations.
─ Results led increasing the type curve on this area to 2.4 Bcf/1,000’
of lateral from 2.2 bcf/1000’
─ The remaining 3 Utica wells and 1 Marcellus well on the Switz pad
are flowing back at this time.
Strong production response from SWPA gathering system de-
bottlenecking project:
─ De-bottlenecking efforts added ~2.7 BCF in Q3 alone
─ The latest phase in the project occurred in the 2nd week of August, so
have not even seen full quarter impact yet
─ Recent project added ~100 MMdcfd of additional capacity
Completions efficiencies have been dramatically enhanced
through performance incentive contracting:
─ 23% increase in ft./day stimulated through Q3 2015 vs. 2014
─ 29% decrease in completions cost per lateral foot through Q3 2015
vs. 2014 with aggressive cost cutting measures
─ Lean manufacturing driving down cycle times and wells are in-line 8
days earlier on average vs. 2014
128154 156
172
236
325-330
~20%
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 2015E 2016E
Bcfe
Marcellus CBM Utica Other
E&P Division
12
Increasing 2015E production guidance to 325 – 330 Bcfe;
~20% 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
2015E 2016E
Marcellus 51% 50%
CBM 23% 18%
Utica (Wet & Dry) 19% 26%
Other 7% 6%
E&P Division
13
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.
236
-38
8
15
~104
~328
-50
14
15
~83~390
0
50
100
150
200
250
300
350
400
450
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
Average $2.06
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
CNX
$/M
cfe
2012-2014 Drill-bit F&D Cost: 3-Year Average vs. E&P Peers
Average $2.14
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
CNX
$/M
cfe
14
F&D/Mcfe: Continued Operational Efficiency Improvements
E&P Division
Rate of improvement accelerated over the last 3 years; CONSOL’s drilling efficiency
now ranks among the best in its peer group Source: Scotia Howard Weil 2014 F&D Cost Study.
Note: Drill-bit finding and development (F&D) costs including revisions, defined as total drilling and completion costs divided by total reserve additions and revisions.
2010-2014 Drill-bit F&D Cost: 5-Year Average vs. E&P Peers
15
Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth
Financial: E&P Capital Expenditures
Lowering planned capex spend while maintaining 2015 & 2016 growth targets Note: Capital spending is net of carry and excludes capital spent on land & permitting.
$460$90
$550 $500
$80$50
$630
$120
$1,300
$300$80
$380$145
$140
$40$325
$95
$800
($160)($10)
($170)($355)
$60
($10)
($305)
($25)
($500)
$400-$500
($300) - ($400)
($1,000)
($500)
-
$500
$1,000
$1,500
MarcellusWet
Utica Wet Total Wet MarcellusDry
Utica Dry CBM/OtherDry
Total Dry Gathering Total2015E
2016E
$ i
n M
M
CONSOL E&P Capital Spending2014 2015E YoY Change 2016E
High-grading locations, capital efficiency improvements and cost reductions driving further E&P capital spending reductions
2015 E&P capital budget of $800 million a 20% reduction vs. original $1.0 billion budget, and ~38% lower than 2014
- 2015 capital budget lowered to $800 million while production guidance range now 325 – 330 Bcfe, up ~1% at the midpoint from prior 320 - 330 Bcfe
- Spending allocated to highest rate of return wells in Marcellus and Utica and where in-place infrastructure can be leveraged to lower costs
- Benefitting from continued service cost deflation and cycle time improvements
2016 E&P capital budget guidance of $400 million to $500 million
- Maintaining 2016 production guidance of approximately 20% annual growth
- Built-in logistical flexibility to plan to enable smooth transition to accelerate activity should commodity price improve into next year
- Estimated $350 - $450 million allocated to development activity. Approximately $50 million allocated to Midstream.
16
E&P Division
17
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2014).
(1) Comprised of ~118,000 net acres in Ohio Utica (~77,000 in the JV and ~43,000 non-JV) and ~302,000 and ~194,000 net prospective acres in PA and WV respectively..
Utica Shale Overview: A Leading Position in the Utica Shale
Utica Shale
~614,000 CONSOL net
acres(1)
Over 3,000 gross locations
─ 77 wells online, as of
9/30/2015
─ 11 wells TIL in Q3 2015
─ 7,525 ft average TIL
laterals in Q3 2015
─ 4 wells per pad on
average
─ 120-acre spacing
(assuming 7,000 ft lateral)
EURs:
─ Ohio Wet: 2.1 Bcfe
EUR/1,000 ft of lateral
─ Ohio Dry: 2.4 Bcfe
EUR/1,000 ft of lateral
─ PA/WV Dry: 2.4 Bcfe
EUR/1,000 ft of lateral
2016E Utica shale
production 480% above
2014 volumes
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 593066
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 12/31/2014).
*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 496,000 net acres
Noble Energy/CNX – MND6
9,000’ lateral
Frac complete, waiting on flowback
CNX – GH9
Drilled – 6100’ Lateral
Completion in Q4, 2015
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
Drilling
CONSOL has over 110,000 acres of Utica leasehold in
Westmoreland and Indiana Counties, PA 19
CONSOL – GAUT4IH
61.4 MMcf/d 24-hr test rate
~ 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 12/31/2014).
Currently testing the reservoir extent and deliverability potential of the well, which
continues to produce at 20+MMcf/d with minimal pressure drawdown of 25-30 psi/day.
20
Utica Shale: Gaut 4IH Westmoreland County, PA
4000.00
5000.00
6000.00
7000.00
8000.00
9000.00
10000.00
0
5,000
10,000
15,000
20,000
25,000
30,000
9/23/2015 9/28/2015 10/3/2015 10/8/2015 10/13/2015 10/18/2015 10/23/2015 10/28/2015
Flow
ing
Casi
ng P
ress
ure
(psi
g)
Gas
Rat
e (M
scf/
d)
Flow Rate MCf/Day Casing Pressure PSIG
Conducting a Modified
Isochronal Test with planned
extended drawdown and
build-up
Consists of alternating
stages of flowing producing
and then shutting-in to
observe the drawdown in
pressure on production and
re-pressurization on shut-in
Resulting data provides
indication of optimal
operating pressure, future
stabilized production rates
and per well drainage area
21
Range Resources - Claysville Sportsman’s Club #1
IP Gas – 59.0 MMcf/d
CONSOL GH9
Drilled, awaiting
Completion. 6,141’
planned treated interval
100% WI to CONSOL
TVD: 13,400’
Currently waiting for completions
Drilled lateral length of 6,141’
~30 stage frac scheduled for Q4 2015
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 ~85,000 net acres prospective for the Utica in the SWPA operating
area, including ~58,000 net acres in Greene and Washington counties, PA
EQT – Pettit 593066 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 12/31/2014).
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
NBL / CNX MND 6H (Utica):
1 Utica Well
Waiting on flowback
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 12/31/2014).
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 psig
Remaining wells flowing back
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
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
Testing 3 proppant types
350K pounds/stage @ 200’ spacing
Multi-Market availability
TIL planned 4Q 2015
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 12/31/2014).
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
Currently 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
Dry Utica: Monroe County 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
PA Utica: Drilling & Completion Cost Reductions
$12.4
$26.2 (8.2)
(2.2)
(0.4)(1.2) (1.1)
(0.8)
$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 are rounded.
(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 third quarter of 2015, including hedging, was a $(0.43) per MMBtu differential to NYMEX
($2.34 vs. $2.77); excluding hedging, gas price was $(1.00) per MMBtu below NYMEX ($1.77 vs. $2.77)
CONSOL basin exports increased ~100,000 Dth /day in late Q3 as TETCO’s OPEN and U2GC expansion projects
were put into service, increasing realizations by marketing gas to the higher priced Midwest and Gulf Coast
markets
CONSOL entered into ethane, propane, and butane sales agreements under which volumes will be shipped via
Mariner East pipelines to the Marcus Hook Industrial Complex and ultimately exported to Europe
─ The deals, the first of which will commence late this year, are expected to yield price premiums compared with
in-basin pricing and expose a portion of the company’s LPG portfolio to Brent Crude linked pricing.
Q3 2015 natural gas price reconciliation:
28
Gas Marketing E&P Marketing Highlights
2014
Q3 Q2 Q1 Q3
NYMEX natural gas ($/MMBtu) 2.77$ 2.64$ 2.98$ 4.06$
Average differential (1.00) (0.68) 0.03 (0.94)
BTU conversion (MMBtu/Mcf)* 0.09 0.07 0.09 0.12
Hedging impact per Mcf 0.60 0.64 0.48 0.36
Realized gas price per Mcf 2.46$ 2.67$ 3.58$ 3.60$
*Conversion factor 1.05 1.04 1.03 1.04
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 $0.25 to $0.29/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 $0.25 $0.29
$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 $0.36 $0.40
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 2015 Est. CY 2016 Est.
Columbia (TCO) 22% 19%
TETCO (M2) 21% 18%
TETCO (M3) 17% 16%
Dominion (DTI) 18% 16%
East Tennessee 11% 11%
TETCO ELA & WLA 4% 8%
Midwest (Chicago) 7% 12%
100% 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
Updated estimated natural
gas sales mix for FY 2016
reflects an improved expected
realization position, including
a greater percentage of out-
of-basin sales, compared to
the prior estimated sales mix
Contracted capacity meets
current requirements
─ Inlet wet gas volumes to
processing plants were ~145
MMcf/d above CONSOL’s
minimum committed volume
in Q3 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 without
risk of penalty
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
MM
cf/
d
Contracted Capacity at Processing Plants
Minimum Volume with Commitments
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?
$1.1 $1.8 $2.0
$3.6 $4.6 $4.8
$5.5
$16.0
$17.5
Average: $6.3
17%
46%
17%
38%31%
118%
54%
88%
147%
0%
20%
40%
60%
80%
100%
120%
140%
160%
$-
$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
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 10/9/2015
(4) NYMEX futures as of 10/23/2015
Gas Hedges
Gas Marketing: Hedges
4Q15 FY 2015 FY 2016
NYMEX + Basis (1)
Volumes (Bcf) 43.1 123.6 182.9
Average Prices ($/Mcf) $3.42 $3.62 $3.30
NYMEX Only Hedges Exposed to Basis
Volumes (Bcf) 20.2 49.9 41.1
Average Prices ($/Mcf) $3.50 $3.75 $3.58
Total Volumes Hedged (Bcf)(3) 63.3 173.5 224.0
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 57% of total
FY 2016E production
volumes hedged(2)
Approximately 47% of total
FY 2016E production
volumes hedged(3) with fixed
prices (NYMEX + Basis)
more than 18% above FY
2016 NYMEX futures(4)
0
25
50
75
100
125
150
175
200
225
250
4Q15 FY 2015 FY 2016
Gas V
olu
mes H
edged (
Bcf)
NYMEX + Basis (1)
NYMEX Only Hedges Exposed to Basis
Average price realization (per Bbl):
Q3 Q2 Q1
NGLs $4.80 $12.48 $20.40
Oil $54.18 $46.14 $47.82
Condensate $27.84 $31.26 $20.82
2015
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%
3Q15 Actual (~100% Ethane
Rejection)
CONE Gathering and Midstream systems provides 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
Q3 2015 Avg. “NGL Barrel” Composition
Q3 2015 liquids sold: 12.1 Bcfe
─ Assuming maximum ethane recovery scenario
Q3 total production volumes would have been
2.7 Bcfe higher
Liquids composed approximately 14% of Q3
production volumes, 10% of E&P sales revenue and
3% of total Company revenue
35
Coal Division
$33.50 $43.73 $53.48
$23-35 Margin
$8-148 Margin
$4-21 Margin
5-yr Avg Price: $64
5-yr Avg Price: $111
5-yr Avg Price: $72
Bailey Buchanan Miller Creek
Cash Margin per ton ($)
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))
- PA mining complex– 785.6 million tons reserves / 28.5 million tons
annual capacity(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)
Production
(tons) (1)
Bailey 254.5 12,929 2.68% 11.5 12.3
Enlow Fork 322.8 12,942 2.21% 11.5 10.6
Harvey 208.3 13,080 2.24% 5.5 3.2
Total 785.6 12,974 2.37% 28.5 26.1
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)
Source: EIA 923, MSHA; Number of longwalls indicated in parentheses.
Not All NAPP Longwalls Are Created Equal
Coal Division
38
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
30
CN
XC
Assets
(5)
Marion C
ounty
(1)
Monongalia
County
(1)
Em
era
ld (
1)
Federa
l (1
)
Harr
ison C
ounty
(1)
Mounta
in V
iew
(1)
Leer
(1)
Mars
hall
County
(2)
Cum
berland (
1)
Centu
ry (
1)
Ohio
County
(1)
Tunnel R
idge (
1)
Pow
hata
n (
1)
Su
lfu
r (%
as r
eceiv
ed
)
Pro
du
cti
on
(m
illi
on
to
ns)
2014 Production - CNXC Assets 2014 Production - Other Longwalls 2014 Sulfur
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
0
20
40
60
80
100
120
140
Millio
n T
on
s
Minor MATS Impact – Limited Sales Loss, Potential Remaining Customer Gain
Coal Division
Surviving 2014 CNX Customers
(after 2015-2019 retirements)
2014 coal burn
Demonstrated capability (2008)
MATS compliance
deadlines
Only 1.8 million tons of 2014 CONSOL sales affected by retirements in 2015-2016.
In 2014, 50 million tons of coal were consumed by units east of the Mississippi that have
announced plans to retire in 2015-2019. Coal and gas will compete to replace this demand;
our surviving customers have the potential to backfill more than half.
* Includes actual and announced retirements, as well as units converted to natural gas, biomass, or another non-coal fuel
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
2011 2012 2013 2014 2015 2016 2017 2018 2019
Re
tire
d C
ap
ac
ity (
MW
)
Actual andAnnounced U.S. CoalPlant Retirements
39
40
Financial
41
Financial: Focused on Free Cash Flow
Strong and improving liquidity
CNXC and CONE
- CONE Midstream cash flows and EBITDA growing
Asset monetizations
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
42
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) As of 9/30/2015, CNX had approximately $945 million of borrowings and $281 million of outstanding letters of credit under its revolving credit facility, leaving approximately $774 million
of availability. CNXC had $180 million outstanding on its revolving credit facility leaving approximately $220 million of availability.
(3) Net Debt equals Total Debt less Cash and Cash Equivalents
Goal to lower leverage ratio and increase liquidity over the next 18 months
CNX
Consolidated
CNXC:
100%
CNX
Attributable
Capitalization and Liquidity 9/30/2015 9/30/2015 9/30/2015
Capitalization
Cash and Cash Equivalents $83 $3 $80
Revolving Credit Facility Balance 1,125 180 945
Capital Lease Obligations 46 - 46
Total Secured Debt $1,171 $180 $991
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 16 - 16
Total Debt $3,734 $180 $3,554
Net Debt (3) $3,651 $177 $3,474
Stockholders’ Equity $4,888 $155 $4,733
Total Capitalization $8,622 $335 $8,287
Liquidity
Cash and Cash Equivalents $83 $3 $80
Revolving Credit Facility Capacity (2) 994 220 774
Total Liquidity $1,077 $223 $854
CNX
Onwed LP
Units(4)
Unit
Price(4)
Market
Value
CNX Coal Resources LP (CNXC:NYSE) 12.7 $12.19 $154
CONE Midstream Partners LP (CNNX:NYSE) 19.1 $10.17 $194
Total Equity Value of Ownership Interests in Affiliated Public MLPs $349
Liquidity of Affiliated MLPs
Total
Facility
Capacity
Outstanding
Balance
Available
CapacityCash
Total
Liquidity of
Affiliates
CNX Coal Resources LP (5)
$400 $180 $220 $3 $223
CONE Midstream Partners LP (5)
$250 $23 $227 $0 $227
Total Liquidity of Affiliated
Public MLPs $650 $203 $447 $3 $450
Leverage Ratio 9/30/2015
LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (6) $967
LTM Bank Net Debt / Adj. EBITDA (6)
3.8x
Equity Value of Ownership in Affiliated Public MLPs
(4) Number of MLP units owned by CNX as of 9/30/2015 and unit prices as of market close on 10/20/2015.
(5) CNX Coal Resources liquidity data is as of 9/30/2015 and CONE Midstream data is as of 6/30/2015.
(6) 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 $801
million plus gain on sale of assets of $68 million, plus gain related to changes in retiree medical (OPEB)
plan of $135 million, less the $92 million of CNXC EBITDA Attributable to CNX, plus the $53 million of
CNXC cash distributions to CNX and plus $2 million of other net adjustments. Bank net debt equals net
debt of $3.5 billion, less $13 million of advance mining royalties, plus $187 million of net letters of credit
related to firm transportation obligations, mining equipment leases and insurance policies.
43
Proceeds from asset monetization opportunity set would significantly reduce
leverage beyond base plan and allow for ability to separate the coal and E&P
businesses sooner, if appropriate, by means of a spin transaction
Assets available for sale
Financial: Asset Monetizations
Note: Based on CONSOL’s divestiture experience and recent comparable asset transactions.
(1) Coal monetizations reduced for announced $101 million of coal asset related divestitures announced on 10/6/2015.
(2) Potential asset divestiture opportunities are as of 10/27/2015.
Engaged several investment bankers and advisors to assist in the sale process
- In early Oct. announced $101 million of divestitures of non-core coal assets with projected 2016 EBITDA of
$6 million, a nearly 17x multiple
Actively engaged in discussions with prospective buyers on a number of asset packages
Currently running sale processes on approximately 30 asset packages
- Bids are starting to come in for some packages
Asset monetization's do not include MLP drop-downs
Does not assume strategic transaction with coal assets
Asset Type Value Range ($ in millions)
Coal(1) $300 - $500
Gas 1,000 - 1,400
Surface 50 - 100
Midstream 100 - 200
Total(2) $1,450 - $2,200
Legacy liabilities reduced and cash servicing costs reduced by more than 60%
since 2012, with further reductions expected going forward
44
Significant Legacy Liability Reductions Over Past 3 Years
Financial: Legacy Liabilities
(1) Servicing cost associated with 12/31/15 balance represents forecasted cash payments to service the legacy liabilities in 2016. Servicing cost associated with 9/30/15 balance represents
forecasted cash payments to service the legacy liabilities for FY 2015. Servicing cost associated with 12/31/14 balance represents forecasted cash payments to service the legacy liabilities in
2015. Servicing cost associated with 12/31/13 balance represents forecasted cash payments to service the legacy liabilities in 2014. Servicing cost associated with the 12/31/12 balance
represents an estimate of 2013 servicing costs based upon interim fiscal year 2013 payments extrapolated to a full year as though the Murray Sale were not to occur.
Est. Change
As of Period End: 12/31/2012 12/31/2013 12/31/2014 9/30/2015 12/31/2015E FY15E / FY14 %
Legacy Liabilities ($MM)
LTD $39 $20 $22 $21 $20 ($2) (8%)
WC 180 85 90 89 85 (5) (6%)
CWP 184 121 126 126 119 (7) (6%)
OPEB 3,018 1,022 761 696 662 (99) (13%)
Salary Retirement/Pension 225 53 119 95 107 (12) (10%)
Asset Retirement Obligations 699 601 576 576 573 (3) (1%)
Total Legacy Liabilities $4,345 $1,902 $1,694 $1,603 $1,565 ($129) (8%)
Annual Legacy Liabilities Cash Servicing Cost (1) $370 $148 $153 $143 $107 ($10) (30%)
$4,345
$1,902 $1,694 $1,565
$370
$148 $153 $143
$107 $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 12/31/2015E 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
$46MM reduction from the year-
end 2014 run-rate of $153MM
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
45
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 10.20.2015) $12.19
CNXC Units Equity Value to CONSOL Energy $154.3
CONSOL Energy's Ownership Interest in CNX Coal
Resources LP (CNXC:NYSE)
$5
$8
$11
$10
$13
$15
$11$9
$4$4
$0
$4
$8
$12
$16
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15
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
$4
$7
$10$9
$8$9
$0
$4
$8
$12
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15
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
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
46
Financial: CONE’s Growing Cash Contribution
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 10.20.2015) $10.17
CNNX Units Equity Value to CONSOL Energy $194.3
CONSOL Energy's Ownership Interest in CONE
Midstream Partners LP (CNNX:NYSE)
47
Financial: Guidance Summary
Note: Guidance as of 10/27/2015.
(1) 4Q 2015 total production guidance of 92-97 Bcfe.
(2) Excludes land CapEx.
(3) Unutilized firm transportation, net equal to estimated unutilized firm transportation expense less estimated gathering revenue (resold firm transportation).
E&P Segment Guidance 2015E 2016E
Production Volumes:(1)
Natural Gas (Bcf)
NGLs (MBbls) 5,500 - 5,900 6,600 - 7,080
Oil (MBbls) 85 - 95 102 - 114
Condensate (MBbls) 1,150 - 1,450 1,380 - 1,740
Total Production (Bcfe) 325 - 330
Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.55) ($0.40) - ($0.50)
NGL Realized Price ($/Bbl) $12.00 - $13.00 $12.00 - $14.00
Condensate Realized Price % of WTI 45% - 50% 43% - 46%
Oil Realized Price % of WTI 93% - 95% 93% - 95%
Capital Expenditures: ($ in millions)
Drilling and Completion $705 $350 $450
Midstream 95 50
Total E&P and Midstream CapEx (2)$800 $400 - $500
Average per unit operating expenses: ($/Mcfe)
Lease Operating Expenses 0.32 - 0.34 0.27 - 0.32
Impact Fees/ Ad Valorem/ Production Taxes 0.10 - 0.12 0.10 - 0.12
Gathering, Transportation, Compression & Processing 1.09 - 1.11 1.04 - 1.06
Direct Administrative and Selling 0.15 - 0.17 0.13 - 0.15
Depreciation, Depletion and Amortization 1.08 - 1.10 0.98 - 1.00
Total Production and Gathering Costs 2.74 - 2.84 2.52 - 2.65
Other Expenses: ($ in millions)
General and Administrative Expense $60.0 - $60.0 $50.0 - $55.0
Unutilized Firm Transportation Expense, net:(3)$19.0 - $20.0 $15.0 - $16.0
~285 ~20%
~20%
48
Financial: Guidance Summary
Note: Guidance as of 10/27/2015.
Coal Segment 2015E 2016E
Total Coal Operations
(in millions of tons)
Estimated Total Coal Sales Volumes 28.9 - 29.9 30.6 - 33.4
Total Committed Volumes (Contracted & Priced) 28.6 20.2
% Committed 97% 63%
Estimated Total Average Price ($/Ton) $57.00 - $59.00 $50.00 - $55.00
Capital Expenditures:
($ in millions)
Production $130 - $140 $140 - $155
Other (Land/Water/Safety/Terminal) 60 - 70 30 - 35
Total Coal CapEx $190 - $210 $170 - $190
Average per unit operating expenses: ($/Ton)
Total Production Costs (including DD&A) $41.61 - $45.36 $41.44 - $44.98
Depreciation, Depletion and Amortization $6.81 - $7.33 $6.35 - $6.44
Other Expenses: ($ in millions)
General and Administrative $25 - $30 $20 - $25
Other Corporate 2015E 2016E
Divestitures ($MM) $75 - $125
49
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 – July 15th announced 3.5% increase to quarterly distribution to $0.22 per unit
Positive initial operated Utica well results (Guat 4IH and Switz 6D), on target for additional Utica results in 4Q 2015 –
sets up future stacked pay opportunities
Asset monetizations off to strong start, multiple processes still underway
- Continued focus on zero-based budgeting – expecting significantly reduced costs and improved balance sheet
- Improving price realizations – anticipate excess Appalachian firm transportation capacity above production to drive
narrowing basis by year-end 2016. This should help both natural gas and thermal coal prices.
- Use of free cash flow and asset sales to de-lever and buy back debt and stock
Our management team is motivated and incentivized long-term to increase return on capital employed and
NAV/share.
Plans and Goals Aligned to Drive Increased Valuation
We will continue to be focused on increasing shareholder value while staying within
our core values of safety, compliance, and continuous improvement
Financial: Summary
50
Appendix
51
Non-GAAP Reconciliation: Quarter-over-Quarter EBITDA and Adj. EBITDA
Appendix
Source: Company filings.
Three Months Ended Twelve Months Ended
September 30
($ in thousands) 2015 2014
Net Income / (Loss) $125,470 ($1,645)
Add: Interest Expense 48,558 55,397
Less: Interest Income (361) (527)
Add: Income Taxes (Benefit) 58,143 (1,388)
Earnings Before Interest & Taxes (EBIT) from Continuing Operations 231,810 51,837
Add: Depreciation, Depletion & Amortization 152,989 148,673
Earnings Before Interest, Taxes and DD&A (EBITDA) $384,799 $200,510
Adjustments:
OPEB Plan Changes (100,947) -
Unrealized Gain on Commodity Derivative Instruments (99,138) -
Gain on sale of Western Allegheny Energy (48,468) -
Severance Expense 7,683 -
Pension Settlement 3,132 4,785
Loss on Debt Extinguishment - 20,990
Long-term Liability Plan Changes - 10,100
Total Pre-tax Adjustments ($237,738) $35,875
Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $147,061 $236,385
Less: Noncontrolling Interest* ($11,092) -
Adjusted EBITDA Attributable to CONSOL Energy Shareholders $135,969 $236,385
52
Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA
Appendix
Source: Company filings.
Twelve Months Ended
September 30
($ in thousands)
Net Income / (Loss) ($325,135)
Add: Interest Expense 203,212
Less: Interest Income (2,344)
Add: Income Taxes (Benefit) (253,357)
Earnings Before Interest & Taxes (EBIT) from Continuing Operations (377,624)
Add: Depreciation, Depletion & Amortization $613,600
(Loss) Earnings Before Interest, Taxes and DD&A (EBITDA) $235,976
Adjustments:
Impairment of E&P Properties 828,905
OPEB Plan Changes (134,596)
Unrealized gain on Commodity Derivative Instruments (134,206)
Gain on Sale of Non-core Assets (68,298)
Blacksville Fire Settlement (9,750)
Backstop Loan Fees 7,334
Other Transaction Fees 4,968
Severance Expense 7,683
Pension Settlement 6,735
Loss on Debt Extinguishment 67,751
Total Pre-tax Adjustments $576,526
Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $812,502
Less: Noncontrolling Interest* ($11,092)
Adjusted EBITDA Attributable to CONSOL Energy Shareholders $801,410
2015
53
Joint Ventures
(1) CONSOL holds ~89,023 net acres outside of the Marcellus JV. As of 12/31/2014.
(2) CONSOL holds ~40,592 net acres outside of the Utica JV, which includes ~13,000 net acres in Monroe County, OH. As of 12/31/2014.
(3) The remaining carry balance on a cash basis is $1.62 billion for Marcellus and $54 million for Utica, respectively. Utica carry has an accrued cash balance of
$14 million as of end of 3Q 2015.
(1) (2)
(3) (3)
Description Marcellus / Noble Energy Inc. Utica / Hess Corporation
Ownership 50/50 50/50
Acreage 350,904 76,132
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 3Q15
$335 million, of which $40 million remains as of end
of 3Q15
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
54
~441,000 CONSOL net
acres
─ ~88% NRI
─ ~91% HBP
23.9 Tcfe 3P
Over 8,900 gross potential
wells(1)
~93% Marcellus
production growth in 2014
compared to 2013
Liquids growth from 2% in
2013 to 8% of total
production in 2014
Producing Pads
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2014).
(1) Based on 5,000 ft laterals with 86-acre spacing.
Marcellus Shale: Overview
Appendix
55
Marcellus Shale: Offset Peer Acreage
Appendix
Notes: CNX acreage position as of 12/31/2014. 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.
56
Total Gross Prospective Marcellus Acreage ~790,000
- Gross Acres within JV ~701,000
- Acres outside JV – 100% CONSOL ~89,000
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: As of December 31, 2014 unless otherwise noted.
~490 MMcfe/d net being produced from ~4% of net Marcellus acreage
Marcellus Shale Upside Potential
Marcellus Shale: Growth Runway and Depth of Inventory
Appendix
57
Marcellus Shale
SWPA CPA WV Ohio(1) North
Wet
South
Wet Total
Net Acres ~45,000 ~110,000 ~117,000 ~13,000 ~54,000 ~102,000 ~441,000
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 the main growth driver of the E&P Division
Marcellus Shale: Sub-Regions Summary
Note: Acreage 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
58
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 12/31/2014).
(1) Based on 5,000 ft laterals with 86-acre spacing.
~45,000 CONSOL net
acres
Over 800 gross locations(1)
─ 190 wells online, as of
9/30/2015
─ 6 wells TIL in Q3 2015
─ 7,002 ft average TIL
laterals in Q3 2015
─ 8 wells per pad on
average in 2015
─ 152-acre spacing
(assuming 8,800 ft
lateral)
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
59
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 12/31/2014).
(1) Based on 5,000 ft laterals with 86-acre spacing.
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
~54,000 CONSOL net
acres
Over 1,400 gross
locations(1)
─ 139 wells online as of
9/30/2015
─ 16 wells TIL in Q3 2015
─ 8,038 ft average laterals
in Q3 2015
─ 6 wells per pad on
average
─ 136-acre spacing
(assuming 7,900 ft
lateral)
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
60
Appendix
Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2014).
(1) Based on 5,000 ft laterals with 86-acre spacing.
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
~102,000 CONSOL net
acres
Over 2,200 gross
locations(1)
─ 31 wells online, as of
9/30/2015
─ 6 wells per pad on
average
─ 139-acre spacing
(assuming 8,100 ft
lateral)
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
61
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
~117,000 CONSOL net
acres
Over 2,400 gross
locations(1)
─ 49 wells online, as of
9/30/2015
─ 6 wells TIL in Q3 2015
─ 6,787 ft average laterals
in Q3 2015
─ 117-acre spacing
(assuming 6,800 ft
lateral)
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 12/31/2014).
(1) Based on 5,000 ft laterals with 86-acre spacing.
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
62
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
~110,000 CONSOL net
acres
Over 2,000 gross
locations(1)
─ 58 wells online, as of
9/30/2015
─ 5 wells per pad on
average
─ 119-acre spacing
(assuming 6,900 ft
lateral)
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 12/31/2014).
(1) Based on 5,000 ft laterals with 86-acre spacing.
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
63 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.
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 ~690,000
- Gross Acres within JV ~153,000
- Acres outside JV – 100% CONSOL ~537,000
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
64
Potential resource of ~30 Tcfe
Note: Acreage as of December 31, 2014 unless otherwise noted.
(1) Based on 5,000 ft laterals with 86-acre spacing.
Utica Shale
Ohio Wet Ohio Dry PA/WV Dry Total
Net Acres ~88,000 ~30,000 ~496,000 ~614,000
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
65
~614,000 CONSOL net
acres in Utica
─ ~302,000 net acres in
PA
─ ~194,000 net acres in
WV
─ 30,000 net acres in OH
Dry
~13,000 net acres in
Monroe County, OH
─ 88,000 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 12/31/2014. 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.
66 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 12/31/2014).
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
~88,000 CONSOL net acres
~34,000 CONSOL net acres
in core
Type curve reflects core
area
Over 500 gross core area
locations(1)
─ 77 wells online, as of
9/30/2015
─ 11 wells online in Q3 2015
─ 7,525 ft average laterals in
Q3 2015
─ 4-5 wells per pad on
average
─ 120-acre spacing
(assuming 7,000 ft
laterals)
2.1 Bcfe EUR/1,000 ft of
lateral
RCS/SSL standard for new
drills
750 ft inter-lateral spacing
67
Monroe
County/Moundsville
Rhinestreet = 5,930’
Burkett = 6,110’
Marcellus = 6,190’
Utica = 10,680
PIT Airport
Rhinestreet = 5,340’
Burkett = 5,460’
Marcellus = 5,690’
Utica = 10,760’
Southwest PA
Rhinestreet = 6,730’
Burkett = 7,000’
Marcellus = 7,270’
Utica = 12,840’
Dominion Transmission
Rhinestreet = 6,070’
Burkett = 6,250’
Marcellus = 6,360’
Utica = 10,890’
Stacked pay provides CONSOL with substantial contiguous acres for
capital-efficient development
Stacked Pay Potential: CONSOL’s Shale Fairway
Appendix
Note: Townships shown in yellow where CONSOL holds 3,000 or more acres (as of 12/31/2014).
68
Stacked pays provide a large inventory and rich opportunity set
Wet
Net Acres
Dry
Net Acres
Total
Net Acres
190,000
176,000
88,000
454,000
155,000
265,000
946,000
345,000
441,000
614,000
1,400,000
(1) Dry Utica includes 496,000 net prospective acres in Pennsylvania and West Virginia.
Stacked Pay Potential: Appalachian Shale Acreage
526,000
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
69
Proved Estimated Potential Locations (Gross)
Tcfe Proved(2) Unproven Total
Marcellus Shale 4.2 1,633 8,000 9,633
Utica Shale(1) 0.5 171 3,000 3,171
Upper Devonian 0.02 11 2,700 2,711
CBM 1.5 3,833 5,200 9,033
Conventional 0.5 11,672 66,000 77,672
Total 6.8 17,320 84,900 102,220
40+ year organic drilling inventory in Appalachian Shale
Note: All reserves and counts are as of YE2014 and exclude Huron, Chattanooga, and New Albany shales. Locations are based on acreage prospective to each reservoir/play
considering culture and geography and allocated based on expected drainage areas. Drilling inventory assumes 300 wells drilled per year.
(1) Utica shale includes prospective acreage in West Virginia, Pennsylvania, and Ohio.
(2) Proved includes PDPs, PDNPs, and PUDs.
E&P Division: Resource and Opportunity Rich Portfolio
Appendix
70
Appendix
Source: CONE Midstream Partners LP.
CONE Corporate Structure
71
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 our coal peers (1)(2)
Appendix
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