Barclays CEO Energy & Power Conference September 9-10, 2015
Barclays CEO Energy & Power Conference
September 9-10, 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 complete
the anticipated drop downs of assets into CNX Coal Resources LP and CONE Midstream LP 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
Modest levels of asset sales assumed between $75-$125 million
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 by means of a spin transaction
Agenda
4
E&P division
Increasing 2015E gas production to 320-330 Bcfe, up from 300-310 Bcfe; 20% gas production growth expected in 2016E
Waterfall chart that details bridge to 2015 and 2016 production growth forecast
Marcellus and Utica overview
Emerging dry gas Utica play’s “game changing” potential
Gas marketing strategy
Diversity of sales-points and end-markets
Discipline when signing up for FT, weighing pricing uplift vs. burdening company with off-balance sheet liability/commitment
Hedging update – locked in additional NYMEX and basis hedges for 2H15 and 2016 to be about 2/3 hedged on gas
Coal division
Premier US coal assets, lowest cost per Btu, highest margin, well capitalized
Positive free cash flow generation with stable production even in current low price environment
Minimized volume and price risk with aggressive contracting program; now entering prime contracting season
Financial
Focused on positive free cash flow generation through production growth, operating cost reductions and capex efficiency
Active asset monetization in full gear to supplement free cash flow to go on offense
Providing streamlined 2015 and 2016 operational and financial guidance to model both sides of CONSOL’s business
5
Company Overview Transformative Journey
Eleven years ago – traditional coal producer, the largest underground
producer in the world
Ten years ago – created CNX Gas
Five years ago – acquired Dominion Resources’ Appalachian E&P
business and became a coal company with a growing natural gas
business
Late 2013 – transaction with Murray Energy Corp. that transitioned half of
coal assets and related assets
April 19, 2014 – CONSOL Energy 150th Anniversary
June 12, 2014 – Analyst Day to roll out growing Appalachian E&P Division
with best in class coal assets
September 25, 2014 – IPO of CONE Midstream Partners LP (NYSE:
CNNX)
December 10, 2014 – Announced intention to pursue the Initial Public
Offerings of a Thermal Coal MLP and Metallurgical Coal Subsidiary, in
addition to a $250 Million stock repurchase program
June 30, 2015 – IPO of CNX Coal Resources LP (NYSE: CNXC)
We are a growing E&P company focused on developing the Appalachian shale
with the benefit of fully capitalized, premier coal assets to help fund E&P growth
6
E&P Division
128154 156
172
236
320-330
+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
7
Increasing 2015E production guidance by 20 – 30 Bcfe to 320 – 330 Bcfe;
+20% year-over-year growth target for 2016E
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
8
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
325
-50
14
15
86390
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
Average $2.14
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
CNX
$/M
cfe
9
F&D/Mcfe: Continued Operational Efficiency Improvements
E&P Division
Rate of improvement has 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
2012-2014 Drill-bit F&D Cost: 3-Year Average vs. E&P Peers
10
~441,000 CONSOL net
acres
─ ~88% NRI
─ ~91% HBP
─ ~85,000 net fee acres
23.9 Tcfe 3P
Over 8,900 gross potential
wells(1)
2015 YTD drilled wells: 60
Marcellus production grew
93% in 2014 over 2013
Liquids grew from 2% of
total production in 2013 to
8% 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
E&P Division
11
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 ~41,000 non-JV) and ~302,000 and ~194,000 net prospective acres in PA and WV respectively.
Utica Shale: Overview
E&P Division
~614,000 CONSOL net
acres(1)
─ Includes ~70,000 net fee
acres in Ohio Utica
Over 3,000 gross locations
─ 66 wells online, as of
6/30/2015
─ 9 wells TIL in Q2 2015
─ 6,983 ft average TIL
laterals in Q2 2015
─ 4 wells per pad on
average in 2015
─ 120-acre spacing
(assuming 7,000 ft lateral)
EURs:
─ Ohio Wet: 2.1 Bcfe
EUR/1,000 ft of lateral
─ Ohio Dry: 2.2 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
12
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 Sportmans Club
IP Gas: 59 MMcf/d
IP Oil: 0 Bbl/d
EQT – Hopkins #590030
Well completed; no reported production
CVX – Conner 6H
IP Gas: 25,000 Mcf/d
IP Oil: 0 Bbl/d
Permits submitted for 2 additional
laterals
HES – Poterfield 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 6
4 Utica Wells & 1 Marcellus
Frac complete, waiting on pipe
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
CHK – Messenger WTZ 3UH
IP Gas: ~30 MMcf/d
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 pipeline /
production set-up”
CNX – GH9
Currently drilling 1 Utica Well
<4 Miles from EQT’s Scotts Run
CNX – Gaut 4IH
61.4 MMcf/d @ 7,968 psig
24-hr test rate
EQT – Scotts Run
24 Hour Prod 72.9 MMcf/d
CONSOL has over 110,000 acres of Utica leasehold in
Westmoreland and Indiana Counties, PA
13
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
TIL planned 3Q 2015
Utica Shale: Gaut 4IH Westmoreland County, PA
Gaut 4IH Utica well’s flow and pressure data showing positive indications
for production volumes and EUR 14
Utica Shale: Gaut 4IH Westmoreland County, PA
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
0 10 20 30 40 50 60 70 80
psi
g
mcfd
Hours
Gas Rate, mcfd Avg Gas Rate for 24 Hr Test Period, mcfd
Casing Pressure, psig Avg Flowing Casing Pressure for 24 Hr Test Period, mcfd
61.4 MMcf/d 24 hour flowtest to sales at an average flowing casing pressure of 7,968 psig
Strong pressure and flow data bode well for production and
EUR. With the well temporarilyshut-in for the installation of
permanent production equipment, surface casing pressure has increased to nearly 10,000 psig
15
Range Resources - Claysville Sportsman’s Club #1
IP Gas – 59.0 MMcf/d
CONSOL GH9
Drilling underway
100% WI to CONSOL
Expected TVD: 13,500’
Currently drilling 8.5” curve section
at 13,000’+
Planned lateral length of 6,800’
~30 stage frac scheduled for Q3 2015
Situated in existing Marcellus field
Ready supply of water
Production facilities and gathering
system with available capacity
TIL planned by YE 2015
EQT – Scotts Run
24 hr IP – 72.9
MMcf/d
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
16
Gas Marketing
Targeting pipeline projects that
access favorable markets at
favorable rates
Will supplement direct FT with
firm sales to customers that
have matching firm capacity
Near term, will optimize and/or
release FT to enhance revenues
Will acquire third-party released
firm capacity if needed
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
17
Gas Marketing Firm Transportation
Firm transportation capacity to support an 18% production CAGR through 2018;
low average demand costs of $0.25/Dth reflects a well balanced portfolio for in-
basin/out-of-basin markets; minimum relative long-term balance sheet risk
* Charts also include transportation under precedent agreements
TETCO
Dominion (DTI)
East Tennesse
Columbia (TCO)
ANR
NEXUS
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1/1/2015 1/1/2016 1/1/2017 1/1/2018M
MB
tu/d
ay
CNX's Firm Transportation and Sales*
TETCO Dominion (DTI) East Tennesse Columbia (TCO) ANR NEXUS
$0.25 $0.25 $0.25 $0.28
$0.11 $0.11 $0.11 $0.11
$-
$0.10
$0.20
$0.30
$0.40
$0.50
2015 2016 2017 2018
$/D
th
CNX's Firm Transportation Costs*
Avg. Demand Avg. Variable
$0.36 $0.36 $0.36 $0.39
FT Capacities
Pipeline (MMcf/d) YE 2015 YE 2018
ANR Pipeline 47 47
Columbia (TCO) 204 304
Dominion (DTI) 245 342
East Tennessee 282 282
Nexus - 150
TETCO 127 127
TETCO (via firm sales) 285 225
1,190 1,477
18
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) 24% 19%
TETCO (M2) 19% 25%
TETCO (M3) 20% 15%
Dominion (DTI) 19% 18%
East Tennessee 13% 10%
TETCO ELA & WLA 4% 8%
Midwest (Chicago) 1% 5%
100% 100%
Natural Gas Sales
Current sales portfolio of 100 active customers priced in seven index markets;
actively negotiating with major Midwest, Gulf Coast and LNG customers
Source: SNL Financial.
TETCO WLA
Short-term uplift in realizations can come at the expense of over-committing to
expensive FT incurring long term off-balance sheet liabilities
19
Notes: Peers include RRC, RICE, COG, AR, SWN, GPOR, CHK EQT.
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
Hedged an additional 34 Bcf in 2H15 and an additional 114 Bcf in FY 2016, with
approximately 65% of 2H 2015 production hedged(2) and nearly 60% of FY 2016 at
prices 16% above NYMEX futures(3)
20 (1) Includes the impact of basis-only hedges.
(2) At the midpoint of production guidance.
(3) As of 8/31/2015.
Gas 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
Gas Marketing: Hedges
$2.80
$3.00
$3.20
$3.40
$3.60
$3.80
$4.00
$4.20
0
25
50
75
100
125
150
175
200
225
250
FY 2015 Prior FY 2015 NEW FY 2016 Prior FY 2016 NEW
Ave
rage
Pri
ce
Ga
s V
olu
mes
(B
cf)
NYMEX Hedges(1) NYMEX + TCO
NYMEX + TETCO Weighted Average Price ($/Mcf)
3Q15 4Q15 FY 2016
Volumes (Bcf)
NYMEX Hedges(1)35.3 50.9 149.0
NYMEX + TCO 12.5 12.5 76.3
NYMEX + TETCO 0.9 0.9 -
Total 48.7 64.3 225.3
Average Prices ($/Mcf)
NYMEX Hedges(1)3.52$ 3.32$ 3.42$
NYMEX + TCO 3.84 3.84 3.69
NYMEX + TETCO 3.93 3.93 -
Weighted Average 3.61$ 3.43$ 3.51$
21
Coal Division
22
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
2
$36.85 $40.15 $52.26
$19-32 Margin
$18-152 Margin
$8-22 Margin
$64 5-yr Avg Price
$120 5-yr Avg Price
$68 5-yr Avg Price
Bailey Buchanan Miller Creek
Cash Margin per ton ($)
Q2 2015 Cash Cost per Ton ($)
(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.
79%
14%
7%
2015 Sales Tons by Segment
PA Ops VA Ops Other
23
Coal Division: Q3 and FY 2015 and 2016 Marketing Update and Forecasts
Coal Division
2015 Coal Sales Facts and Goals
Contracted tons for 2015: 96%
- Priced: 94%
Approximately 82% of the PA Ops tons are expected
to be sold domestically
Approximately 78% of the VA Ops tons are expected
to be sold overseas
100% of the Other tons are expected to be sold
domestically
Coal Sales
Guidance(1)
Q3 2015E Q3 2014 2015E 2014 2016E
PA Ops 5.4-5.6 6.2 22.5-23.5 26.1 25.0-27.0
VA Ops 0.8-1.0 1.0 3.9-4.2 4.1 3.7-4.2
Other 0.4-0.5 0.6 2.0-2.2 2.2 1.9-2.2
Total 6.6-7.1 7.8 28.4-29.9 32.4 30.6-33.4
80%
13%
7%
Q3 2015 Sales Tons by Segment
PA Ops VA Ops Other
Notes: Coal sales guidance in gross tons. Following the recent CNX Coal Resources LP (CNXC) IPO, CONSOL expects to modify its reporting and guidance process for the PA
Operations, with CNXC taking a primary role as the operator of these assets.
(1) Tons in millions.
Source: EIA 923, MSHA; Number of longwalls indicated in parentheses.
Not All NAPP Longwalls Are Created Equal
Coal Division
24
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
25
26
Financial
27
Financial: Focused on Free Cash Flow
CNXC IPO
Strong liquidity position
Growing revenue and income
- CONE Midstream cash flows and EBITDA growing
- E&P production volume growth
- Steady coal production with lower cost base
Reductions to operating and overhead costs
Reductions in 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)
Reduction in legacy liabilities
Asset monetizations
On track for positive free cash flow growth for the next 18 months
28
CNXC: Organizational Structure
Financial: CNX Coal Resources LP (CNXC) 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
CNXC owns a 20% undivided interest(1) in, and
operational control over, CONSOL Energy’s
Pennsylvania mining complex
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
CONSOL Energy granted CNXC a right of first offer
to acquire the remaining 80% undivided interest in
the PA complex
CNXC has ROFOs on (1) Buchanan Mine,
(2) Cardinal States Gathering System, and
(3) Baltimore Marine Terminal
CNXC: 20% Undivided interest in 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.
CONSOL strategically aligned with CNXC, with future drop downs supporting CNXC’s growth
and CONSOL’s transition to a pure play Appalachian Shale 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
29
CNXC Roadmap to Growing Value and Unitholder Returns
Financial: CNX Coal Resources LP (CNXC)
Optimize Cost Structure
Increase Volumes with Solid
Cash Margins
Pursue Opportunistic
Acquisitions
Stable Cash Flows
Reduced Cost of Capital
Distribution Growth
Flexible Drop-downs
Coal Contracting for 2016-19
Broaden Institutional Appeal
CONSOL owns 32.1% of CONE Midstream Partners’ (CNNX)
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, a
private Joint Venture between CONSOL and Noble Energy
CONSOL’s share of CONE Midstream’s Net Income flows
through “Equity in earnings of Affiliates,” which falls
within the “Miscellaneous Other Income” line item;
distributions run straight through the cash flow statement,
in “Return on Equity Investment”
CNNX’s EBITDA and cash distributions have been growing
strongly, with CNNX recently increasing its quarterly cash
distribution 3.5% from its prior run-rate
30
Financial: CONE Midstream & Gathering Growing
(in millions except for per share amounts)
Total LP Units held by CONSOL Energy 19.1
Unit Price (as of close on 9.2.2015) $11.52
CNNX Equity Value to CONSOL Energy $220.0
CONSOL Energy's Ownership Interest in CONE
Midstream Partners, LP
Source: CONE Midstream Partners LP and CONSOL Energy Inc.
$0$2$4$6$8
$10$12$14$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
$0
$2
$4
$6
$8
$10
$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
31
Debt and Liquidity Profile, Pro Forma CNXC Offering
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 June 30, 2015, we had $39 million of borrowings and $49 million of outstanding letters of credit under our accounts receivable securitization facility, leaving approximately $1 million of availability. The
accounts receivable securitization facility terminated as July 7, 2015 upon the completion of the CNXC initial public offering.
(3) As of June 30, 2015, we had $1,058 million of borrowings and $237 million of outstanding letters of credit under our revolving credit facility, leaving approximately $705 million of availability.
(4) Net Debt equals Total Debt less Cash and Cash Equivalents
(5) The thermal term loan commitment was terminated as July 7, 2015 upon the completion of the CNXC initial public offering.
(6) Adjusted EBITDA is a non-GAAP financial measure and the reconciliation is provided in the Appendix. Bank methodology EBITDA equals Adjusted EBITDA of $902 million plus gain on sale of non-core Assets
of $19 million, plus gain related to changes in retiree medical OPEB plan of $34 million; pro forma excluding the $48 million non-controlling interest share of EBITDA associated with the 20% undivided interest
of the PA Coal Complex owned by CNXC.
Leverage expected to decline over the next 18 months with free cash flow positive
operating plan and an assumed $75 to $125 million of asset sales
Sources of Funds ($MM)Actual CNXC
PF CNXC
IPO
CNXC Initial Public Offering $150 6/30/2015 IPO 6/30/2015
CNXC Revolver Borrowing 200 Cash and Cash Equivalents $10 $10
CNXC Initial Public Offering - Greenshoe 8
Thermal Term Loan Commitment Fees Rebate 5 Accounts Receivable Facility $39 ($39) -
Revolving Credit Facility 1,058 (309) 749
Total Sources of Funds $363 Term Loan Commitment - -
Capital Lease Obligations 47 47
Total Secured Debt $1,144 ($348) $796
Uses of Funds ($MM) 8.25% Senior Notes due 2020 $74 $74
Revolver Repayment $309 6.375% Senior Notes due 2021 21 21
Accounts Receivable Facility Repayment 39 5.875% Senior Notes due 2022 (1) 1,856 1,856
CNXC Transaction Fees 8 8.0% Senior Notes due 2023 (1) 493 493
CNXC Cash on Hand 7 Baltimore 5.75% Revenue Bonds due 2025 103 103
Miscellaneous Debt 17 17
Total Uses of Funds $363 Total Debt $3,708 ($348) $3,360
Net Debt (4) $3,698 ($348) $3,350
Stockholders’ Equity $4,682 - $4,682
Total Capitalization $8,390 ($348) $8,042
Cash and Cash Equivalents $10 $10
Accounts Receivable Facility Capacity (2)
$1 ($1) $0
Revolving Credit Facility Capacity (3)
$705 $260 $965
Thermal Term Loan Commitment (5)
$600 ($600) $0
Total Liquidity $1,316 ($341) $975
Actual
PF CNXC
IPO
Leverage Ratio 6/30/2015 6/30/2015
LTM CONSOL Adjusted EBITDA (6) $955 $907
LTM Total Debt / Adj EBITDA 3.9x 3.7x
LTM Net Debt / Adj EBITDA 3.9x 3.7x
32
Proceeds from asset monetization opportunity set would significantly reduce
leverage beyond base plan and allow for ability to separate the coal and E&P
businesses sooner, if appropriate, by means of a spin transaction
Assets available for sale
Financial: Asset Monetizations
Note: Based on CONSOL’s divestiture experience and recent comparable asset transactions.
(1) Potential asset divestiture opportunities are as of 8/31/2015.
Engaged several investment bankers and advisors to assist in the sale process
Actively engaged in discussions with prospective buyers on a number of asset packages
Currently running sale processes on approximately 30 asset packages
- Bids are starting to come in for some packages
Asset monetization's do not include MLP drop-downs
Does not assume strategic transaction with coal assets
Asset Type Value Range ($ in millions)
Coal $400 - $600
Gas 1,000 - 1,400
Surface 50 - 100
Midstream 100 - 200
Total $1,550 - $2,300
33
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 lowered by $120 million to $800 million, a 13% reduction vs. prior budget, a 20% reduction vs. original
$1.0 billion budget, and ~38% lower than 2014
- 2015 capital budget lowered to $800 million but increasing production guidance to range of 320 – 330 Bcfe from 300 - 310 Bcfe, a nearly 7% increase
- 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
Introduction of 2016 E&P capital budget guidance of $400 million to $500 million
- Maintaining 2016 production guidance of 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, almost entirely completions. Approximately $50 million allocated to Midstream.
Legacy liabilities reduced by 60% and cash servicing costs reduced by 65% from
2012 through 1H 2015, with further reductions expected going forward
34
Significant Legacy Liability Reductions Over Past 3 Years
Financial: Legacy Liabilities
(1) Servicing cost associated with 12/31/15 balance represents forecasted cash payments to service the legacy liabilities in 2016. Servicing cost associated with 6/30/15 balance represents
forecasted cash payments to service the legacy liabilities in 2H 2015. Servicing cost associated with 12/31/14 balance represents forecasted cash payments to service the legacy liabilities in
2015. Servicing cost associated with 12/31/13 balance represents forecasted cash payments to service the legacy liabilities in 2014. Servicing cost associated with the 12/31/12 balance
represents an estimate of 2013 servicing costs based upon interim fiscal year 2013 payments extrapolated to a full year as though the Murray Sale were not to occur.
Est. Change
As of Period End: 12/31/2012 12/31/2013 12/31/2014 6/30/2015 12/31/2015E FY15E / FY14 %
Legacy Liabilities ($MM)
LTD $39 $20 $22 $21 $20 ($2) (9%)
WC 180 85 90 89 91 1 1%
CWP 184 121 126 127 125 (1) (1%)
OPEB 3,018 1,022 761 703 682 (79) (10%)
Salary Retirement/Pension 225 53 119 113 107 (12) (10%)
Asset Retirement Obligations 699 601 576 579 619 43 7%
Total Legacy Liabilities $4,345 $1,902 $1,694 $1,632 $1,644 ($50) (3%)
Annual Legacy Liabilities Cash Servicing Cost (1) $370 $148 $153 $129 $122 ($31) (20%)
$4,345
$1,902 $1,694 $1,644
$370
$148 $153
$122
$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
An
nu
al C
ash
Se
rvic
ing
Co
st
Lega
cy L
iab
iliti
es
Projected:
• $50MM Reduction in Legacy Liabilities
• and $31MM Reduction in Annual Cash
Servicing Cost by year-end 2015
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
35
Financial: Guidance Summary
Note: Guidance as of 9/9/2015.
(1) 3Q 2015 production guidance also revised to 79-83 Bcfe.
(2) Excludes land CapEx.
(3) Unutilized firm transportation expense of approximately $26.5 and $18.0 million at the midpoint in 2015 and 2016 respectively, less approximately $12.0 and $5.5 million of
gathering revenue (resold firm transportation) at the midpoint in 2015 and 2016, respectively.
E&P Segment Guidance 2015E 2016E
Production Volumes:(1)
Natural Gas (Bcf) 280 - 285 336 - 342
NGLs (MBbls) 5,500 - 5,900 6,600 - 7,080
Oil (MBbls) 85 - 95 102 - 114
Condensate (MBbls) 1,150 - 1,450 1380 - 1740
Total Production (Bcfe) 320 - 330 384 - 396
Natural Gas Basis Differential to NYMEX ($/Mcf) -$0.55 -$0.50 - -$0.60
NGL Realized Price ($/Bbl) $15.00 - $16.00 $16.00 - $17.00
Condensate Realized Price % of WTI 45% - 50% 43% - 46%
Oil Realized Price % of WTI 93% - 95% 93% - 95%
Capital Expenditures: ($ 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 $60.0 - $65.0 $50.0 - $57.0
Unutilized Firm Transporation, net:(3)$14.0 - $15.0 $12.0 - $13.0
36
Financial: Guidance Summary
Note: Guidance as of 7/28/2015.
Coal Segment 2015E 2016E
Total Operations
(in millions of tons)
Estimated Total Coal Sales 28.4 - 29.9 30.6 - 33.4
Total Committed (Priced) 27.5 15.6
% Committed 94% 49%
Capital Expenditures:
Production ($/Ton) $5.00 $5.00
($ in millions)
Production $142 - $150 $153 - $167
Other (Land/Water/Safety/Terminal) $30 - $35 $60 - $70
Total Coal CapEx $172 - $185 $213 - $237
Average per unit operating expenses: ($/Ton)
Total Production Costs (including DD&A) $42.34 - $45.36 $41.44 - $44.98
Depreciation, Depletion and Amortization $6.93 - $7.33 $6.35 - $6.44
Other Expenses: ($ in millions)
General and Administrative $20 - $25 $20 - $23
Other Corporate 2015E 2016E
Divestitures ($MM) $75 - $125
37
Milestones:
Coal MLP – executed
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), on target for additional Utica results in 2H 2015 – sets up future
stacked pay opportunities
- Continued focus on zero-based budgeting – expecting significantly reduced costs and improved balance sheet
- MetCo IPO on hold for now due to met coal price declines; currently evaluating multiple possibilities, including a future
drop-down into CNXC, partnering with a 3rd party to grow the assets through opportunistic consolidations, and others;
decision expected by year-end 2015
- 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.
- Asset Monetizations – multiple asset packages under active processes
- 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 stock
price. We will do so within our core values of safety, compliance, and continuous improvement
Plans and Goals Aligned to Drive Increased Valuation
We expect to see rising NAV and continue to focus on increasing shareholder value
Financial: Summary
Key Takeaways
38
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
CONSOL Energy has approximately $2 billion of assets available for sale and the proceeds of these sales will be
used to further reduce debt
Not including MLP drop-downs or strategic transactions
CONSOL Energy’s base plan, coupled with additional asset sales, will result in
significant flexibility, including the ability, if appropriate, to separate its coal and
E&P businesses by means of a spin transaction
39
Questions
40
Appendix
41
Non-GAAP Reconciliation: Quarter-over-Quarter EBITDA and Adj. EBITDA
Appendix
Three Months Ended Twelve Months Ended
June 30
($ in thousands) 2015 2014
Net Income / (Loss) ($603,301) ($24,935)
Add: Interest Expense 46,507 64,211
Less: Interest Income (364) (676)
Add: Income Taxes (291,929) 1,214
(Loss) Earnings Before Interest & Taxes (EBIT) (849,087) 39,814
Add: Depreciation, Depletion & Amortization 154,497 137,899
(Loss) Earnings Before Interest, Taxes and DD&A (EBITDA) ($694,590) $177,713
Adjustments:
Impairment of E&P Properties 828,905 --
Unrealized loss on Commodity Derivative Instruments 24,936 --
Backstop Loan Fees 7,334 --
Other Transaction Fees 4,968 --
Loss on Debt Extinguishment 17 74,277
OPEB Plan Changes (33,649) --
Pension Settlement -- 20,707
Revolver Modification -- 2,989
Coal Contract Buyout -- (30,000)
Total Pre-tax Adjustments $832,511 67,973
Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $137,921 $245,686
Source: Company filings.
42
Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA
Appendix
Source: Company filings.
Twelve Months Ended
June 30
($ in thousands)
Net Income / (Loss) ($452,250)
Add: Interest Expense 210,051
Less: Interest Income (2,510)
Add: Income Taxes (312,888)
(Loss) Earnings Before Interest & Taxes (EBIT) (557,597)
Add: Depreciation, Depletion & Amortization 609,276
(Loss) Earnings Before Interest, Taxes and DD&A (EBITDA) $51,679
Adjustments:
Impairment of E&P Properties 828,905
Unrealized gain on Commodity Derivative Instruments (35,068)
Backstop Loan Fees 7,334
Other Transaction Fees 4,968
Loss on Debt Extinguishment 88,741
OPEB Plan Changes (33,649)
Long-Term Liability Plan Changes 10,100
Pension Settlement 8,388
Gain on Sale of Non-Core Assets (19,830)
Blacksville Fire Settlement (9,750)
Total Pre-tax Adjustments 850,139
Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $901,818
2015
43
Non-GAAP Reconciliation: Adjusted Net Cash Provided by Continuing Operations
Appendix
Source: Company filings.
Three Months Ended
June 30
($ in thousands)
Net Cash Provided by Continuing Operations $61,742
Addback: Revolver Amendment (2,302)
Addback: Thermco and Metco Transaction Fees (2,078)
Changes in Working Capital:
Changes in Operating Assets:
Accounts and Notes Receivable 63,861
Inventories (6,450)
Prepaid Expenses 45,084
Changes in Other Assets 10,222
Changes in Operating Liabilities:
Accounts Payable (79,882)
Accrued Interest (16,570)
Other Operating Liabilities (28,267)
Changes in Other Liabilities (36,090)
Addback: Net Changes in Working Capital (48,092)
Adjusted Net Cash Provided by Continuing Operations $114,214
2015
Average gas price for the second quarter of 2015, including hedging, was $(0.06) per MMBtu below NYMEX
($2.58 vs. $2.64); excluding hedging, gas price was $(0.68) per MMBtu below NYMEX ($1.96 vs. $2.64)
CONSOL entered into ethane, propane, and butane sales agreements under which volumes will be shipped
via Mariner East pipelines to the Marcus Hook Industrial Complex and ultimately exported to Europe
─ The deals, which commence late next year, are expected to yield price premiums compared with in-basin pricing
and expose a portion of the company’s LPG portfolio to Brent Crude pricing.
Q2 2015 natural gas price reconciliation:
44
Appendix Second Quarter Highlights
2014
Q2 Q1 Q2
NYMEX natural gas ($/MMBtu) 2.64$ 2.98$ 4.67$
Average basis (0.68) 0.03 (0.59)
BTU conversion (MMBtu/Mcf)* 0.07 0.09 0.15
Hedging impact per Mcf 0.64 0.48 (0.13)
Realized gas price per Mcf 2.67$ 3.58$ 4.10$
*Conversion factor 1.035 1.031 1.036
2015
45
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%
2Q15 Actual (~100% Ethane
Rejection)
CONE Gathering and Midstream systems provide CONSOL unique flexibility to
blend in ethane to meet specifications, allowing for nearly 100% ethane rejection
and maximizing economics when fractionation is unattractive
Appendix Natural Gas Liquids, Oil, and Condensate
Q2 2015 Avg. “NGL Barrel” Composition
Q2 liquids revenue composed 4% of total
Company revenue and 12% of E&P sales revenue
Q2 liquids sold: 9.1 Bcfe
Average price realization (per Bbl):
Q1 Q2
NGLs $20.40 $12.48
Oil $47.82 $46.14
Condensate $20.82 $31.26
2015
46
Appendix
Source: CONE Midstream Partners LP.
Appendix
47
Utica Shale: Ohio Dry Gas
GPOR Irons 1-4H (Utica):
30.3 MMcf/d – Avg 24-hr rate
NBL / CNX MND 6H (Utica):
1 Utica Well
Frac complete, waiting on
pipeline / production set-up
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 (Utica) :
4 Utica Wells & 1 Marcellus
Currently drilling-out
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
48
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
Central PA
Marcellus = 7,370’
Utica = 13,110’
49
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
449,000
155,000
265,000
913,000
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
50
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 6.7 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
(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
Appendix
51
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
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PA Mining
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Active Complex
Port/Dock
CNXC Customers
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TW
h
Year
Coal
Natural Gas
Nuclear
Renewable
Petroleum
Other
Source: EIA AEO 2015. 52
Coal Continues to be the Low-Cost Choice for Electricity Generation
U.S. power generation will remain highly dependent on thermal coal for the foreseeable future
Coal generation maintains a market share of 37-39% through 2030
Coal increases its advantage over natural gas on a delivered price basis, assuring that coal will be “in the money”
Delivered Cost of Fuel to U.S. Electric Power Sector, $/mmBtu
(EIA Data)
2012 2014 2016 2020 2030
Natural Gas $3.59 $5.17 $4.53 $5.52 $6.38
Coal $2.41 $2.27 $2.25 $2.38 $2.67
Spread $1.18 $2.90 $2.28 $3.14 $3.71
U.S. Electricity Generation by Fuel
Widening
Cost
spread
Appendix