EARNINGS RESULTS - CNX Resources Corporationinvestors.cnx.com/.../first-quarter-2017-earnings-call-slides.pdf · This presentation contains statements, ... Adjusted earnings before
Post on 19-Jul-2020
0 Views
Preview:
Transcript
EARNINGS RESULTS
FIRST QUARTER 2017
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, natural gas liquids, and coal, including due to oversupply relative to the demand available for our products; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately estimate the volume of hydrocarbons that are recoverable from our oil and natural gas assets; we may encounter unexpected operational issues or disruptions when we drill and mine, including equipment failures, geological conditions, and higher than expected costs for equipment, supplies, services and labor, including with respect to third-party contractors; we may not achieve the efficiencies we expect to realize in our drilling and completion operations, and as a result, our projected cost savings may not be fully realized; our participation in joint ventures may restrict our operational and corporate flexibility, and actions taken by a joint venture partner may impact our financial position and operational results; we may not be able to sell non-core assets on acceptable terms; acquisitions and divestitures that we anticipate making or have made may not occur or produce anticipated benefits, or may cause disruptions to our business operations; we may be subject to environmental and other government regulations that adversely impact our operating costs and the market for our natural gas and coal; failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its obligations under various arrangements, which we guaranteed, could materially or adversely affect our results of operations, financial position, and cash flows; we may be unable to incur indebtedness on reasonable terms; provisions in our multi-year coal sales contracts may provide limited protection and may result in economic penalties to us or permit the customer to terminate the contract; the majority of our common units in CNX Coal Resources LP are subordinated, and we may not receive related distributions; there is no assurance that the potential dropdowns, spin-off or sale of the coal business will occur, or if it does occur that we will be able to negotiate favorable 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, 2016 filed with the Securities and Exchange Commission (SEC), as updated by any subsequent quarterly reports on Form 10-Qs. The forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly.
Currently, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations.
We may use certain terms in this presentation, such as EUR (estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these estimates may be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is customary in the gas industry, prior to the commencement of natural gas drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. As a result of our title review or otherwise, we may be required to acquire property rights from third parties at our expense in order to effectively drill and produce the gas rights we control and third parties may participate in the wells we drill, thereby reducing our working interest in those wells.
This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CONSOL Energy Inc. or CNX Coal Resources LP.
Q1 2017 Highlights
Free Cash Flow Continue to expect annual production growth and free cash flow generation
Production Raising 2017 and 2018 production guidance based on improved cycle times and optimized type curves
EBITDA Raising 2017 EBITDA guidance by 7%
Debt Repurchased approximately $100 million of debt in Q1 2017; have paid down ~$1.3 billion since 2015 when total debt peaked at ~$3.7 billion
Leverage Ratio Expect to reach our target leverage ratios quicker than our 4Q16 forecast
3
Operations: E&P Results Summary
4
(3) Adjusted earnings before income tax for the E&P Division of $19.9 million for the three months ended March 31, 2017 is calculated as GAAP loss before income tax of $93.5 million plus total pre-tax adjustments of $113.4 million. The $113.4 million adjustment is a $24.6 million pre-tax gain related to the unrealized gain on commodity derivative instruments, a pre-tax loss of $137.9 million related to the impairment of exploration and production assets and a pre-tax loss of $0.1 million related to severance expense.
• Adjusted earnings before income tax for E&P Division of $19.9 million(3)
• Marcellus Shale total production costs were $2.18 per Mcfe in the first quarter, a decrease of $0.27 from $2.45 per Mcfe in the year-earlier quarter, or an 11% improvement
- Driven primarily by reductions to lease operating expense and DD&A rates
• Utica Shale total production costs were $2.16 per Mcfe in the first quarter, an increase of $0.37 from $1.79 per Mcfe in the year-earlier quarter, or a 21% impairment
- Driven by an increase in firm transportation and processing costs, property taxes, and DD&A rates
(1) Average Sales Prices for 1Q2017, 1Q2016, and 4Q2016 include gains/(loss) on commodity derivative instruments (cash settlements) of ($0.55), $0.98, and $0.46, respectively. (2) Average Costs for 1Q2017, 1Q2016, and 4Q2016 include DD&A of $1.01, $1.08, and $1.05, respectively.
1Q 2017(1)1Q 2016
Y/Y
Change 1Q 2017(1)4Q 2016
Q/Q
Change
Average Sales Price(1) ($/Mcfe) $2.85 $2.73 $0.12 $2.85 $2.77 $0.08
Total Production Costs(2)
($/Mcfe) $2.32 $2.41 ($0.09) $2.32 $2.27 $0.05
Sales Volumes (Bcfe) 95.0 97.5 (2.5) 95.0 101.3 (6.3)
Sales Volumes (Bcfe) by Category
Marcellus 58.0 51.2 6.8 58.0 56.5 1.5
Utica 15.3 22.9 (7.6) 15.3 22.2 (6.9)
CBM 16.7 17.6 (0.9) 16.7 17.4 (0.7)
Other 5.0 5.8 (0.8) 5.0 5.2 (0.2)
Operations: Operations Summary
5
Production Efficiency Highlights
• OPEX Efficiencies: Reduced Q1 2017 LOE by $6.1 million, improving unit costs by $0.05/Mcfe Y/Y
• Production Surveillance: Improved production surveillance yielded a 72% Y/Y reduction in lost volume due to downtime, driving production improvements of ~1.2 Bcfe and incremental revenue of $3.8 million
• Production Facilities: Additional focus on production facilities optimization resulted in a ~3% reduction in CAPEX and a five-day reduction in installation cycle time
SWPA SWPA WV OH
Marcellus Upper Devonian Marcellus Dry Utica TOTAL
Horizontal Rigs 1 - - 1 2
Drilled 2 - - 7 9
Completed 5 - 2 4 11
Turned In Line (TIL) 5 1 - - 6
Avg. TIL Lateral Length (ft) 9,417 10,663 - - 9,625
Q1 2017 Summary
TD TIL TD TIL
Marcellus 8 31 33-41 15-20
Utica 17 26 26-31 21-25
Upper Devonian - 3 - -
CBM 63 63 20-25 25-30
TOTAL ex. CBM 25 60 59-72 36-45
2017 2018
Two-Year TIL Schedule
• Total E&P and Midstream CapEx guidance remains unchanged:
- 2017E: $555 million
- 2018E: $600 million
Operations: Drilling Cycle Time Efficiencies
6
Utica
• Q1 2017 drilling days/1,000’ lateral length improved 23% compared to 2016 helping to reduce cost per lateral foot by 11%
• The increase in efficiency and reduction in non-productive time was driven by:
- New incentives for on-site drilling consultants
- Drilling motor and bit optimization - More efficient casing designs - Enhanced solids control
Marcellus
• Drilled two laterals using existing top holes with an average lateral length of 9,141 ft in SWPA in 5.85 days each
• Achieved an Appalachian Marcellus drilling record of 7,380’ drilled in a 24 hour period
Monroe County Drilling Cost Savings
1.3
1.0
$392
$347
$250
$270
$290
$310
$330
$350
$370
$390
$410
$430
$450
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
FY2016 1Q2017
$/L
ater
al F
oo
t
Day
s/1
00
0’ L
L D
rille
d
Days/1000' LL Monroe $/Lateral Foot
Operations: Completions Cycle Time Efficiencies
7
Marcellus
Efficiency • Q1 2017 lateral feet/day stimulated increased
56% compared to 2016
• Faster total completion activities: 27% improvement in Q1 2017 compared to 2016
- 1.9 days/1000’ vs 2.6 days/1000’
• The increased efficiency and reduced cycle times were driven by:
- Higher volume water and sand logistics - Improved vendor selection based on
KPIs rather than lowest cost - Preventive maintenance technology
Cost • The ACAA1 pad was recently completed for a
cost of $348/lateral foot, which was flat with 2016 as operational efficiencies offset increased vendor costs
Marcellus Frac Efficiency
800
1,245
0
200
400
600
800
1,000
1,200
1,400
1Q16 1Q17
Feet
per
Day
Lateral Feet/Day - Stimulated
Operations: Revised Type Curves
8
Monroe County, OH – Dry Utica
• Better-than-expected reservoir performance driving accelerated production forecast, but EUR unchanged
• Accelerated production driven by: - Optimized inter-lateral
spacing - Optimized stage length and
proppant type, size, and loading
Morris Field, SWPA – Marcellus
• Shape of type curve changed due to accelerated production, but EUR remains the same
• Production protocol used to enhance flowback and early time production
• Accelerated production driven by: - Optimized stage length,
diversion techniques, and proppant loading
Revised Type Curve Shape vs. Prior Plan
Revised Type Curve Shape vs. Prior Plan
• Two wells are currently being drilled as an offset to the Gaut
Operations: Gaut 4IH Update – as of Q1 2017 End
9
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
0
5,000
10,000
15,000
20,000
25,000
30,000
9/23/15 1/1/16 4/10/16 7/19/16 10/27/16 2/4/17 5/15/17
Cas
ing
Pre
ssu
re (
psi
)
Flo
w R
ate
(Mcf
/d)
Flow Rate MCf/Day Casing Pressure
Hit line pressure: 2/6/2017 Tubing installed: 2/22/2017
Testing period
Gaut 4IH IP: 61.4 MMcf/d Initial SICP: 9,921 psig Lateral Length: 5,808’ EUR: 3.5 Bcf/1,000’ lateral Cum. Production as of 3/31/2017: 8.4 Bcf
Initial SICP: 9,921 psig EUR: 3.5 Bcf/1,000’ lateral
Marketing: Q1 2017 E&P Marketing Highlights
10
• Executed two long-term physical sales with customers on East Tennessee
- Allows CONSOL to forego 80,000 Dth/day of FT renewals
• Permanently released 52,500 Dth/d of unutilized TCO firm transportation capacity
• Directly-marketed ethane volumes were 367,000 barrels in Q1 and, on an equivalent basis, yielded a $1.15 per MMBtu premium over CONSOL’s residue natural gas alternative
- Directly-marketed ethane gross realization is up 30% from Q4 2016
• $0.22/Mcfe uplift from liquids, including the impact of hedging
Natural Gas Price Reconciliation
2017 2016
Q1 Q1
NYMEX Natural Gas ($/MMBtu) $3.32 $2.09
Average Differential (0.30) (0.36)
BTU Conversion (MMBtu/Mcf)* 0.16 0.10
(Loss)/Gain on Commodity Instruments-Cash Settlement (0.55) 0.98
Realized Gas Price per Mcf $2.63 $2.81
* Conversion Factor 1.05 1.06
Marketing: Gas Hedges
11
(1) Hedge positions as of 4/18/2017. 2017 includes actual settlements of 97.8 Bcf. 2021 excludes 2.6 Bcf of physical basis sales not matched with NYMEX hedges. (2) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements. (3) Based on midpoint of total production guidance of 420-440 Bcfe in 2017E.
• Approximately 73% of total 2017E production volumes hedged(3)
• NYMEX hedges added during Q1: 147 Bcf (2018-2021)
• Basis hedges added during Q1: 254 Bcf (2017-2021)
Hedge Volumes and Pricing Q2 2017 2017 2018 2019 2020 2021
NYMEX Only Hedges
Volumes (Bcf) 68.0 279.9 276.4 194.9 117.2 17.2
Average Prices ($/Mcf) $3.18 $3.17 $3.17 $3.07 $3.11 $3.03
Index Hedges and Contracts
Volumes (Bcf) 8.1 32.5 6.8 12.8 7.7 7.8
Average Prices ($/Mcf) $3.19 $3.18 $2.61 $2.51 $2.46 $2.41
Total Volumes Hedged (Bcf)(1) 76.1 312.4 283.2 207.7 124.9 25.0
NYMEX + Basis (fully-covered volumes)(2)
Volumes (Bcf) 71.1 307.2 253.8 170.0 109.8 25.0
Average Prices ($/Mcf) $2.59 $2.61 $2.86 $2.81 $2.85 $2.63
NYMEX Only Hedges Exposed to Basis
Volumes (Bcf) 5.0 5.2 29.4 37.7 15.1 -
Average Prices ($/Mcf) $3.18 $3.17 $3.17 $3.07 $3.11 -
Total Volumes Hedged (Bcf)(1) 76.1 312.4 283.2 207.7 124.9 25.0
Gas Hedges 2017-2021
307.2
253.8
170.0
109.8
25.0
5.2
29.4
37.7
15.1
-
50.0
100.0
150.0
200.0
250.0
300.0
350.0
2017 2018 2019 2020 2021
Gas
Vo
lum
es H
edge
d (
Bcf
)
NYMEX + Basis (2) NYMEX Only Hedges Exposed to Basis
Marketing: Gas Hedges – Continued
12
(1) Hedge positions as of 4/18/2017.
Physical Fixed Basis and Fixed Price Sales(1) Q2 2017 2017 2018 2019 2020 2021
Physical Fixed Basis Sales
Volumes (Bcf) 13.1 58.7 88.5 69.8 41.0 9.5
Average Basis Prices ($/Mcf) ($0.11) $0.01 $0.15 $0.10 $0.06 $(0.28)
Physical Fixed Price Sales
Volumes (Bcf) 0.9 3.4 6.8 12.8 7.7 7.8
Average Prices ($/Mcf):
NYMEX portion $3.70 $3.68 $3.22 $3.09 $3.06 $3.01
Basis portion $(1.13) $(1.13) $(0.61) $(0.58) $(0.60) $(0.60)
$2.57 $2.55 $2.61 $2.51 $2.46 $2.41
2017 2018
Hedge Position (Outer ring = NYMEX; Inner ring = Basis)
• Physical fixed basis sales provide opportunities to lock in revenue in illiquid markets
• Systematic hedging of both NYMEX and basis fully covers the majority of 2017 and 2018 expected production
Marketing: Natural Gas Sales Market Mix
13
MIDWEST TETCO M3
TETCO M2
EAST TENNESEE
TETCO ELA
TETCO WLA
TCO POOL
DOMINION SOUTH
Natural Gas Sales Market Mix 2017E 2018E
Columbia (TCO) 11% 9%
TETCO (M2) 42% 44%
TETCO (M3) 11% 8%
Dominion (DTI) 12% 11%
East Tennessee 12% 14%
TETCO ELA & WLA 8% 6%
Midwest (Michcon) 4% 8%
100% 100%
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
Q1 2017
Eth
ane
$/g
al
Mt. Belvieu Ethane CNX Netback Appalachian Gas Alternative
Q1 2017 Direct Ethane Sales Comparison
Marketing: Liquids Realizations
14
Natural Gas Liquids, Oil, and Condensate
• Q1 2017 liquids sold: 8.9 Bcfe
• Total weighted average price of all liquids increased 39% to $29.72 per Bbl in Q1 2017, from $21.34 per Bbl in Q4 2016(1) (+133% Y/Y)
• Liquids comprised approximately 9% of Q1 2017 production volumes, 16% of E&P revenue, and 6% of total company revenue(1)
Average Price Realization ($ per Bbl)(1)
Gas $ High
Gas $ Low
NGL $ Low NGL $ High
Avoid Processing
Optimize Send to Processing
Optimize
22 Bcf
Wet Gas Flexibility
(1) Excludes propane hedging impact. (2) Net of basis and de-ethanization fees.
2017 2016
Q1 Q1
NGLs $29.16 $12.30
Oil 44.40 30.84
Condensate 33.84 14.64
(2)
Marketing: Market Currently Undersupplied
15
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
Po
pu
lati
on
Wei
ghte
d H
DD
s (t
ho
usa
nd
s)
Week
Cumulative Nationwide Population Weighted Heating Degree Days
10-11
11-12
12-13
13-14
14-15
15-16
16-17
Avg
-3000.00
-2500.00
-2000.00
-1500.00
-1000.00
-500.00
0.00
500.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20C
um
ula
tive
Wit
hd
raw
al (
Bcf
)
Week
Cumulative Lower 48 Storage Withdrawal
10-11
11-12
12-13
13-14
14-15
15-16
16-17
AvgYet, storage
withdrawals near average levels
• Despite a warmer-than-average winter, storage withdrawals have been trending along the five-year average - This implies that the market is currently undersupplied
One of the lowest levels of heating demand recently
observed
Source: NOAA National Weather Service – Climate Prediction Center Source: EIA
Nov.-Mar. Nov.-Mar.
Marketing: Pipeline Projects will Make a Difference
16
02468
101214161820
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Reg
ion
al E
xpo
rt C
apac
ity
(Bcf
/d)
Year End
Regional Export by Delivery Market
Southwest
Midwest
Southeast
Canada
ACP Atlantic Sunrise Atlantic Sunrise
MVP NEXUS
NEXUS Rover
Rover
0
5
10
15
20
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Reg
ion
al E
xpo
rt C
apac
ity
(Bcf
/d)
Year End
Regional Export by Project
Forecast
Forecast
• The first wave of pipeline projects is expected to start coming online this year and will materially improve export capacity away from Appalachia
Source: EIA
Source: EIA
New Pipeline Projects Changing the Landscape
Marketing: But When Will Supply Respond?
17
0
1
2
3
4
5
6
7
8
9
-
100
200
300
400
500
600
Pro
du
ctio
n (
Bcf
/d)
Rig
Co
un
t
Permian Region Production and Rig Count
Rig count Total production
0
2
4
6
8
10
12
14
16
18
20
-
20
40
60
80
100
120
140
160
Pro
du
ctio
n (
Bcf
/d)
Rig
Co
un
t
Marcellus Region Production and Rig Count
Rig count Actuals Prediction
• Even after the completion of several pipeline projects, it appears there are too few rigs running today to fill the additional capacity and balance the market
Source: EIA Source: EIA, CNX analysis
Historically, it appears 300+ rigs were required to grow
Permian gas production
We’ve not yet seen this dip in rig numbers manifest itself in
slowed production growth
Despite recent efficiency gains, Marcellus production will not be ready to fill the new pipelines due to the
recent low rig counts
Finance: Q1 2017 Results
18
• Adjusted net income attributable to CONSOL Energy Shareholders in the 2017 first quarter of $38 million, or $0.17 per diluted share(1); on a GAAP basis, a net loss attributable to CONSOL Energy shareholders of $39 million or ($0.17) per diluted share
- Adjusted net income excludes the following pre-tax items: $138 million impairment on Knox Energy and Coalfield Pipeline, which was recorded as Held
for Sale $25 million unrealized gain on commodity derivative instruments $5 million in various other nonrecurring items
• Total company adjusted EBITDA attributable to continuing operations in the first quarter of $217 million
(1) Income tax effect of Total Pre-tax Adjustments was $40,884 and $10,310 for the three months ended March 31, 2017 and March 31, 2016, respectively. Adjusted net income attributable to CONSOL Energy Shareholders for the three months ended March 31, 2017 is calculated as GAAP net loss attributable to CONSOL Energy Shareholders of $38,966 plus total pre-tax adjustments from the table on slide 36 of $117,949, less the associated tax expense of $40,884 equals the adjusted net income attributable to CONSOL Energy Shareholders of $38,099.
Note: The terms "adjusted net income attributable to CONSOL Energy Shareholders," "EBITDA from continuing operations," and "adjusted EBITDA from continuing operations" are non-GAAP financial measures, which are defined and reconciled to the GAAP net income below, under the caption “Non-GAAP Reconciliation."
Q1 2017 Summary
($ in millions, except per share data) 1Q 2017 1Q 2016
Y/Y
Change 1Q 2017 4Q 2016
Q/Q
Change
Net (Loss) Income Attributable to CNX Shareholders ($39) ($98) $59 ($39) ($306) $267
(Loss) Earnings per Diluted Share ($0.17) ($0.43) $0.26 ($0.17) ($1.33) $1.16
Revenue and Other Income from Continuing Operations $699 $533 $166 $699 $462 $237
Net Cash Provided by Continuing Operating Activities $205 $124 $81 $205 $87 $118Adjusted EBITDA Attributable to Continuing Operations $217 $181 $36 $217 $205 $12
Finance: Q1 2017 Review
19
Source: Company filings. Note: Numbers may not sum and may differ slightly from totals and financial statements due to rounding. The terms "adjusted net income attributable to CONSOL Energy Shareholders," "EBITDA from continuing operations," and "adjusted EBITDA from continuing operations" are non-GAAP financial measures, which are defined and reconciled to the GAAP net income below, under the caption “Non-GAAP Reconciliation."
Net Increase/(Decrease) in Cash
• Generated positive free cash flow
- Organic free cash flow from continuing operations in Q1 2017 of $98 million compared to $40 million in Q1 2016
- Total free cash flow in Q1 2017 of $117 million compared to $451 million in Q1 2016 (Buchanan sale) - Purchased approximately $100 million of long-term debt at a discount
Used free cash flow generated during the quarter, plus cash on hand Have paid down ~$1.3 billion since 2015 when total debt peaked at ~$3.7 billion
• Total capital expenditures in Q1 2017 of $113 million compared to $78 million in Q1 2016
Q1 2017 Cash Flow Summary (including Discontinued Operations)
($ in millions) 1Q 2017 1Q 2016
Y/Y
Change 1Q 2017 4Q 2016
Q/Q
Change
Net Cash Provided by Operating Activities $205 $130 $75 $205 $83 $122
Capital Expenditures ($113) ($78) ($35) ($113) ($47) ($66)
Proceeds from Asset Sales $19 $404 ($385) $19 $21 (2)
Other Investing $6 ($6) $12 $6 $79 ($73)
Proceeds from Noble Exchange Agreement - - - - $213 ($213)
(Payments on) / Proceeds from Short-Term Debt & Misc. Borrowings ($3) ($103) $100 ($3) ($356) $353
(Payments on) / Proceeds from Long-Term Notes ($98) - ($98) ($98) - (98)
Dividends Paid - ($2) $2 - - -
Other Financing ($15) $9 ($24) ($15) ($13) ($2)
Net (Decrease) / Increase in Cash $1 $354 ($353) $1 ($20) $21
Finance: Strong Liquidity Position of ~$1.7 Billion
20
$2.0 billion Revolving Credit Facility
• 5 year credit facility expires June 2019
• Paid down nearly $1 billion of revolving debt on the credit facility in 2016
• Gas reserves based lending facility borrowing base reaffirmed at $2 billion in Q4 2016
- Includes the right to separate the coal and gas business subject to a leverage test
(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $61 million as of 3/31/2017, $6 million of which was CNXC’s and consolidated in CNX’s financial statements per US GAAP accounting.
(2) Revolving credit facility as of 3/31/2017.
March 31, 2017 ($ in millions)Amount/
Capacity
Amount
Drawn
Letters
of Credit
Amount
Available
Cash and Cash Equivalents (1) $55 - - $55
Revolving Credit Facility(2) $2,000 $0 $333 $1,667
Total $2,055 $0 $333 $1,722
Maintenance Covenants LimitMar. 31,
2017
CONSOL Energy Revolver:
Minimum Interest Coverage Ratio < 2.5 to 1.0 3.9 to 1.0
Minimum Current Ratio < 1.0 to 1.0 2.4 to 1.0
Finance: Debt and Liquidity Profile
21
Note: Some numbers may not match exactly to financial statements due to rounding. (1) The 2022 and 2023 senior notes includes $4 million and $5 million of
unamortized bond premium / discount, which will be amortized over the life of the notes, respectively.
(5) Number of MLP units owned by CNX as of 3/31/2017 and unit prices as of market close on 4/21/2017. (6) CNX Coal Resources liquidity data is as of 3/31/2017 and CONE Midstream data is as of 12/31/2016. (7) Adjusted EBITDA Attributable to CNX Shareholders is a non-GAAP financial measure and the reconciliation is provided in the Appendix. Bank methodology LTM EBITDA equals LTM Adjusted EBITDA of $727 million less the $57 million of CNXC EBITDA net of cash distributions attributable to CNX, plus coal contract buyout of $6 million, less $3 million of severance payments, plus $10 million of other net adjustments. For a reconciliation of CNXC’s EBITDA please see the Company’s form 10Q’s and 10K’s. Bank net debt of $2.688 billion equals debt of $2.695 billion, less $55 million cash on hand excluding CNXC’s cash, less $197 million of CNXC revolver debt, less $3 million of advance mining royalties, plus $248 million of net letters of credit related to firm transportation obligations, mining equipment leases, and insurance policies.
(2) Total Debt of $2.695 billion excludes total unamortized debt issuance costs of $25 million. (3) Net Debt equals Total Debt less Cash and Cash Equivalents. (4) As of 3/31/2017, CNX had approximately $333 million of outstanding letters of credit under its revolving credit facility, leaving approximately $1,667 million of availability. CNXC
had $197 million outstanding on its revolving credit facility leaving approximately $203 million of availability.
CNX
Owned
LP Units(5)
Unit
Price(5)
Market
Value
CNX Coal Resources LP (CNXC:NYSE) 16.6 $15.20 $252
CONE Midstream Partners LP (CNNX:NYSE) 21.7 $21.25 $461
Total Equity Value of Ownership Interests in Affiliated Public MLPs $713
Liquidity of Affiliated MLPs
Total
Facility
Capacity
Outstanding
Balance
Available
CapacityCash
Total
Liquidity
CNX Coal Resources LP (6)
$400 $197 $203 $6 $209
CONE Midstream Partners LP (6) $250 $167 $83 $6 $89
Leverage Ratio 3/31/2017
LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7)
$683
LTM Bank Net Debt / Adj. EBITDA (7)
3.9x
Equity Value of Ownership in Affiliated Public MLPs
CNX
Consolidated
CNXC:
100%
CNX
Attributable
Capitalization and Liquidity 3/31/2017 3/31/2017 3/31/2017
Capitalization
Cash and Cash Equiva lents $61 $6 $55
Revolving Credit Faci l i ty Balance 197 197 -
Capita l Lease Obl igations 47 - 47
Total Secured Debt $244 $197 $47
8.25% Senior Notes due 2020 $74 - $74
6.375% Senior Notes due 2021 21 - 21
5.875% Senior Notes due 2022 (1) 1,754 - 1,754
8.0% Senior Notes due 2023 (1) 495 - 495
Baltimore 5.75% Revenue Bonds due 2025 103 - 103
Miscel laneous Debt 4 - 4
Total Debt (2) $2,695 $197 $2,498
Net Debt (3) $2,634 $191 $2,443
Stockholders ’ Equity $3,906 $142 $3,764
Total Capitalization $6,601 $339 $6,262
Liquidity
Cash and Cash Equiva lents $61 $6 $55
Revolving Credit Faci l i ty Capacity (4)
1,870 203 1,667
Total Liquidity $1,931 $209 $1,722
2.2
1.4
4.4
2.0
1.2
0.0
1.0
2.0
3.0
4.0
5.0
2016 2017E 2018E
4Q16 Forecast Current Forecast
Finance: Leverage Ratio and Liquidity Projection
22
(1) Leverage ratio equals expected year-end net debt divided by expected EBITDA. CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.
(2) Excludes letters of credit of $333 million. Note: Assumes $400-$600 million in asset sales in 2017 and a base case 20% CNXC drop in 2018. Forecasts based on strip pricing for open volumes as of 4/4/2017.
• Reduced 2017 and 2018 expected leverage ratio targets by an additional 0.2x each since the end of 4Q16
• Path to reaching and maintaining a sub-2.5x leverage ratio
• Liquidity rises by estimated $1 billion in free cash flow by 2018
• Plan Upside: - Increased efficiencies - Rising commodity prices - Accelerated drops - Additional asset sales
Leverage Ratio 2016-2018E(1)
Liquidity 2016-2018E
Asset Sales Organic
FCF Sources 2017E-2018E
1.7
2.2
2.6
0.0
0.5
1.0
1.5
2.0
2.5
3.0
2016 2017E 2018E
$ in
bill
ion
s
(2) (2)
Finance: Legacy Liabilities
23
Significant legacy liability reductions over
past three years: • Miller Creek/Fola transaction drove
substantial reduction in legacy liabilities in 2016
• Continue to actively manage the reduction of legacy liabilities
Balance Sheet Liability Long-Term Liability Guidance
3/31/2017 FY 2017E FY 2018E
LTD $19
WC 79 CWP 118
OPEB 698
Salary Retirement/Pension 111
Asset Retirement Obligations 238
Total Legacy Liabilities $1,263
Total Cash Servicing Cost $19 $74 - $79 $70 - $75
EBITDA Impact ($12) ($57 - $62) ($57 - $62)
Note: 3/31/17 liability balance includes approximately $22 million and $38 million in employee-related and environmental liabilities associated with Pennsylvania Mining Operation (PAMC), respectively. Future EBITDA loss and cash servicing costs related to these liabilities will run through the PAMC segment financial detail and therefore the cash servicing costs and EBITDA loss related to these liabilities are excluded from the 2017 & 2018 forecast presented above. For FY 2017, the cash servicing costs associated with PAMC long-term liabilities are forecasted to approximate $8 million, while the EBITDA loss associated thereto is forecasted to approximate $12 million. Excludes gas well closing.
$4,187
$1,703 $1,497 $1,362 $1,267 $1,263 $1,258
$365
$144 $139 $133
$92 $77 $77 $0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
2012 2013 2014 2015 2016 Q1 2017 2017E
An
nu
al C
ash
Ser
vici
ng
Co
sts
($ in
Mill
ion
s)
Lega
cy L
iab
iliti
es (
$ in
mill
ion
s)
Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost
Finance: Segment Guidance
24
Note: Guidance as of 5/2/2017, based on strip pricing as of 4/4/2017. (1) Excludes stock-based compensation. (2) Includes Idle Rig Charges, Unutilized Firm Transportation Expense (Net Of 3rd Party Revenue), Land Rentals, Lease Expiration Costs, Misc. Gas, and Exploration Expense.
E&P Segment Guidance 2017E 2018E
Production Volumes:
Natural Gas (Bcf) 380-400 NGLs (MBbls) 6,000-7,000 Oil (MBbls) 45-50 Condensate (MBbls) 600-700
Total Production (Bcfe) 420-440 490-520 % Liquids 9%-11% 7%-12%
Open Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.31) ($0.27) NGL Realized Price ($/Bbl) $20.40 $17.60 Condensate Realized Price % of WTI 70% 70% Oil Realized Price % of WTI 90% 90%
Capital Expenditures ($ in millions):
Drilling and Completions $465 Midstream $40 Land, Permitting and Other $50
Total E&P and Midstream CapEx $555 $600 Average per unit operating expenses ($/Mcfe):
Lease Operating Expense $0.17-$0.21 Production, Ad Valorem, and Other Fees $0.07-$0.08 Transportation, Gathering and Compression $0.85-$0.90
Total Cash Production and Gathering Costs $1.09-$1.19 $0.98-$1.11
Other Expenses ($ in millions):
Selling, General, and Administrative Costs(1) $70-$75 $65-$75
Other Corporate Expenses(2) $75-$80 $50-$60
PA Mining Operations – Consolidated 100% Basis 2017E
Coal Sales Volumes:
Total Coal Sales Volumes (millions of tons) 25.6-27.6
Total Committed Volumes (contracted and priced) 25.4 % Committed ~95%
Capital Expenditures ($ in millions): Total Coal Capital Expenditures ($ in millions) $120-$136
• Coal capital expenditures expected to be approximately $5 per ton in 2017 and beyond
Finance: Raising 2017E EBITDA Guidance
25
(1) Includes forecasted Earnings of Equity Affiliates of $40 million in 2017 associated with CNX's proportionate share of ownership in CONE Midstream. This income is reflected within Miscellaneous Other Income in the CNX Income Statement.
Base plan assumes NYMEX as of 4/4/2017 of $3.40 per MMBtu + weighted average basis of ($0.29) per MMBtu on open volumes. Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.
EBITDA Guidance by Segment – 2017E
($ in millions) E&P(1) PA Mining
Operations Other
Current Total
(5/2/17)
Prior Total
(1/31/17)
Earnings Before Interest, Taxes and DD&A (EBITDA)
$705 $410 ($20) $1,095 $1,080
Adjustments:
Unrealized (Gain)/Loss on Commodity Derivative Instruments
(150) - - (150) (200)
Stock-Based Compensation 20 10 - 30 30
Adjusted EBITDA $575 $420 ($20) $975 $910
Noncontrolling Interest - (50) - (50) (45)
Adjusted EBITDA Attributable to CNX $575 $370 ($20) $925 $865
APPENDIX
26
Operations: Acreage Position
27
Note: Acreage numbers as of 2016 10-K ; PDPs as of 3/31/2017 (1) Approx. Net Locations calculated with corresponding lateral lengths and spacing for each respective asset region and formation found on modeling input slides; based on total
undeveloped acreage, including both type curve guidance area and surrounding acreage.
SWPA WV CPA OH Total
Upper Devonian Net Acres 111,500 157,000 35,500 - 304,000
Net Acres 103,000 62,000 234,500 13,500 413,000
Fee Acres 41,000 2,000 19,000 3,000 65,000
Approx. Net Locations (1)
572 411 1,472 85 2,540
Net Producing Wells (PDPs) 196 34 60 1 291
Net Acres 151,500 181,000 229,000 121,500 683,000
Fee Acres 48,000 13,000 16,000 38,000 115,000
Approx. Net Locations (1) 855 1,104 1,294 483 3,736
Gross Producing Wells (PDPs) 1 - 1 98 100
Utica
Marcellus
Acreage Position and PDPs by Asset Region and Formation
Asset Region 1: Southwest Pennsylvania Overview
28
Upper Devonian Shale
• Total net acres: 112,000
Marcellus Shale
• Average EUR/1,000’ of 2.7 Bcf(1)
• Total net acres: 103,000
• Total NRI: 89%
• Sizable capital expenditure in the next two years
Utica Shale
• Average EUR/1,000’ of 3.1 Bcf(1)
• Total net acres: 152,000
• Total NRI: 89%
• Continue to delineate through drilling and participation
(1) Average EUR represents the type curve guidance area depicted on the map. Note: Asset region type curve data and modeling inputs available at http://investors.consolenergy.com/events-and-presentations/events/2017.
64% Utica/Marcellus core over core acreage overlap
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
7000' LL
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
8500' LL
Southwest Pennsylvania Modeling Inputs and Economics
29
SWPA Marcellus Type Curve (2.7 Bcfe/1000')
SWPA Utica Type Curve (3.1 Bcf/1000')
BTAX ROR % (3)
Realized Price 8,500'
$2.00 39%
$2.50 71%
$3.00 109%
BTAX ROR % (3)
Realized Price 7,000'
$2.00 19%
$2.50 34%
$3.00 52%
(1) Assuming 8,500 ft lateral @ 750 ft inter-lateral spacing, total undeveloped net locations in region (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing, total undeveloped net locations in region (3) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.
Assumptions
IP (MMcfe/d) 19.0
Decline 69%
B-factor 1.65
EUR/1000’ (Bcfe) 2.7
Lateral Length 8,500’
Wells Per Pad 6
Capital ($ millions) $7.1
Fixed Cost ($/mo./well) $730
LOE ($/Mcfe) $0.12
Gathering ($/Mcfe) $0.48
Reserves Detail
Gross EUR (Bcfe) 22.6
BTU 1,130
Assumptions
IP (MMcf/d) 23.1
Decline 67%
B-factor 1.20
EUR/1000’ (Bcf) 3.1
Lateral Length 7,000’
Wells Per Pad 5
Capital ($ millions) $13.2
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Gathering ($/Mcf) $0.23
Interest / Net Locations
WI / NRI (%) 100% / 89%
Net Locations(1) ~572
Wells Online (3/31/17) 196
Avg. PDP Acres/Well 104
Reserves Detail
Gross EUR (Bcf) 21.4
BTU 1,010
Interest / Net Locations
WI / NRI (%) 100% / 89%
Net Locations(2) ~855
Wells Online (3/31/17) 1
Asset Region 2: West Virginia Overview
30
Marcellus Shale
• Average EUR/1,000’ of 2.9 Bcf(1)
• Total net acres: 62,000
• Total NRI: 86%
• Focus on completing DUC inventory: sunk capital results in improved IRR
Utica Shale
• Average EUR/1,000’ of 2.8 Bcf(1)
• Total net acres: 181,000
• Total NRI: 88%
• Delineation through participation
(1) Average EUR represents the type curve guidance area depicted on the map Note: “CNX Utica Resource Potential” as depicted on the map represents an additional 220,000 acres of Utica resource potential in WV not included in company totals Note: Asset region type curve data and modeling inputs available at http://investors.consolenergy.com/events-and-presentations/events/2017.
30% Utica/Marcellus acreage overlap
0
10,000
20,000
30,000
40,000
50,000
0
100,000
200,000
300,000
400,000
0 12 24 36 48
NG
L/C
ND
Pro
du
ctio
n (
BB
L/m
on
th)
Gro
ss G
as P
rod
uct
ion
(M
cf/m
on
th)
Months After TIL
Gas
NGL
CND
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
6500' LL
BTAX ROR % (4)
Realized Price 6,500'
$2.00 10%
$2.50 20%
$3.00 31%
West Virginia Modeling Inputs and Economics
31
WV Marcellus Type Curve (2.9 Bcfe/1000')
BTAX ROR % (4)
Realized Price 8,000'
$2.00 37%
$2.50 56%
$3.00 76%
(1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing, total undeveloped net locations in TC guidance area (2) Assuming 6,500 ft lateral @ 1,100 ft inter-lateral spacing, total undeveloped net locations in region (3) See NGL and CND assumptions on type curve data file located at www.consolenergy.com (4) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.
WV Utica Type Curve (2.8 Bcf/1000')
Assumptions
IP (MMcf/d) 14.0
Decline 69%
B-factor 1.65
EUR/1000’ (Bcfe) 2.9
Lateral Length 8,000'
Wells Per Pad 6
NGL Yield (Bbl/MMcf)(3) 74.1
CND Yield (Bbl/MMcf)(3) 12.8
Capital ($ millions) $6.6
Fixed Cost ($/mo./well) $730
LOE ($/Mcf) $0.12
Gathering/Processing
($/Mcf) $0.93
NGL OpEx ($/Bbl) $5.00
CND OpEx ($/Bbl) $5.00
Reserves Detail
Gross EUR (Bcfe) 22.8
BTU 1,260
Assumptions
IP (MMcf/d) 15.3
Decline 58%
B-factor 1.10
EUR/1000’ (Bcf) 2.8
Lateral Length 6,500'
Wells Per Pad 3
Capital ($ millions) $12.7
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Gathering ($/Mcf) $0.23
Reserves Detail
Gross EUR (Bcf) 17.9
BTU 1,015
Interest / Net Locations
WI / NRI (%) 100% / 88%
Net Locations(2) ~1,104
Wells Online (3/31/17) -
Interest / Net Locations
WI / NRI (%) 100% / 86%
Net Locations(1) ~151
Wells Online (3/31/17) 34
Avg. PDP Acres/Well 156
Asset Region 3: Central Pennsylvania Overview
32
Marcellus Shale
• Average EUR/1,000’ of 1.8 Bcf(1)
• Total net acres: 234,000
• Total NRI: 88%
• Weighted average EUR/1000’ for the entire region is 1.5 Bcf
• Evaluate Marcellus development in conjunction with Utica
Utica Shale
• Average EUR/1,000’ of 3.5 Bcf(1)
• Total net acres: 229,000
• Total NRI: 89%
• Continued drilling expected in 2017 and 2018
• Non-operated participation opportunities
(1) Average EUR represents the type curve guidance area depicted on the map, which is approximately 111,000 acres in CPA Note: “CNX Utica Resource Potential” as depicted on the map represents an additional 22,000 Utica resource potential in CPA not included in company totals Note: Asset region type curve data and modeling inputs available at http://investors.consolenergy.com/events-and-presentations/events/2017.
96% Utica/Marcellus acreage overlap
0
100,000
200,000
300,000
400,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
9000' LL
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
1,000,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
7000' LL
Central Pennsylvania Modeling Inputs and Economics
33
CPA Marcellus Type Curve (1.8 Bcf/1000')
BTAX ROR % (3)
Realized Price 9,000'
$2.00 23%
$2.50 39%
$3.00 62%
CPA Utica Type Curve (3.5 Bcf/1000')
(1) Assuming 9,000 ft lateral @ 750 ft inter-lateral spacing, total undeveloped net locations in region (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing, total undeveloped net locations in region (3) Escalation not applied to gas pricing, capex, and opex (4) IP held flat for 14 months at 21.6 MMcf/d Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.
BTAX ROR % (3)
Realized Price 7,000'
$2.00 63%
$2.50 107%
$3.00 152%
Assumptions
IP (MMcf/d) 13.3
Decline 69%
B-factor 1.65
EUR/1000’ (Bcf) 1.8
Lateral Length 9,000'
Wells Per Pad 6
Capital ($ millions) $6.2
Fixed Cost ($/mo./well) $730
LOE ($/Mcf) $0.12
Gathering ($/Mcf) $0.32
Assumptions
IP (MMcf/d)(4) 21.6
Decline 74%
B-factor 1.20
EUR/1000’ (Bcf) 3.5
Lateral Length 7,000'
Wells Per Pad 6
Capital ($ millions) $12.6
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Gathering ($/Mcf) $0.23
Reserves Detail
Gross EUR (Bcf) 24.8
BTU 1,010
Interest / Net Locations
WI / NRI (%) 100% / 89%
Net Locations(2) ~1,294
Wells Online (3/31/17) 1
Reserves Detail
Gross EUR (Bcf) 15.8
BTU 1,000
Interest / Net Locations
WI / NRI (%) 100% / 88%
Net Locations(1) ~1,472
Wells Online (3/31/17) 60
Avg. PDP Acres/Well 130
Asset Region 4: Ohio Overview
34
Total Ohio Utica:
• Total net acres: 121,000
• Total NRI: 89%
Utica Dry:
• Average EUR/1,000’ of 2.8 Bcfe(1)
• 23,000 net undeveloped acres
• Continued development of Monroe County
• 100 net locations
Utica Wet:
• Average EUR/1,000’ of 2.1 Bcfe(2)
• 42,000 net undeveloped acres
• Continue to monitor pricing for continued development
• 159 net locations
(1) Average EUR represents the type curve guidance area depicted on the map by a solid blue line (Utica Dry) (2) Average EUR represents the type curve guidance area depicted on the map by a dotted blue line (Utica Wet) Note: Asset region type curve data and modeling inputs available at http://investors.consolenergy.com/events-and-presentations/events/2017.
0
5,000
10,000
15,000
20,000
25,000
30,000
0
100,000
200,000
300,000
400,000
500,000
0 12 24 36 48
NG
L/C
ND
Pro
du
ctio
n (
BB
L/m
on
th)
Gro
ss G
as P
rod
uct
ion
(M
cf/m
on
th)
Months After TIL
Gas
NGL
CND
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Gas
Pro
du
ctio
n (
Mcf
/mo
nth
)
Months After TIL
9000' LL
Ohio Modeling Inputs and Economics
35
OH Wet Utica Type Curve (2.1 Bcfe/1000')
OH Dry Utica Type Curve (2.8 Bcf/1000')
BTAX ROR % (4)
Realized Price 8,000'
$2.00 13%
$2.50 27%
$3.00 47%
BTAX ROR % (4)
Realized Price 9,000'
$2.00 55%
$2.50 90%
$3.00 127%
Assumptions
IP (MMcf/d) 16.3
Decline 71%
B-factor 1.40
EUR/1000’ (Bcfe) 2.1
Lateral Length 8,000’
Wells Per Pad 5
NGL Yield (Bbl/MMcf)(3) 32.6
CND Yield (Bbl/MMcf)(3) 4.0
Capital ($ millions) $7.6
Fixed Cost ($/mo./well) $1,371
LOE ($/Mcf) $0.29
Gathering/Processing
($/Mcf) $0.78
NGL OpEx ($/Bbl) $6.78
CND OpEx ($/Bbl) $6.25
Assumptions
IP (MMcf/d) 20.4
Decline 56%
B-factor 1.10
EUR/1000’ (Bcf) 2.8
Lateral Length 9,000’
Wells Per Pad 4
Capital ($ millions) $9.4
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Gathering ($/Mcf) $0.21
(1) Assuming average 8,500 ft lateral @1,100’ spacing, total undeveloped net locations in region (2) Assuming 8,000 ft and 9,000 ft lateral @ 1,100’ spacing for Ohio Wet and Ohio Dry, respectively, total undeveloped net locations in TC guidance area (3) See NGL and CND assumptions on type curve data file located at www.consolenergy.com (4) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.
OH Utica Total
Net Locations(1) ~483
Wells Online (3/31/17) 98
Ohio Dry - Reserves Detail
Gross EUR (Bcf) 25.0
BTU 1,060
Ohio Dry - Interest / Net Locations
WI / NRI (%) 100% / 89%
Net Locations(2) ~100
Wells Online (3/31/17) 4
Avg. PDP Acres/Well 187
Ohio Wet - Reserves Detail
Gross EUR (Bcfe) 16.9
BTU 1,150
Ohio Wet - Interest / Net Locations
WI / NRI (%) 50% / 45%
Net Locations(2) ~159
Wells Online (3/31/17) 94
Avg. PDP Acres/Well 187
Non-GAAP Reconciliation: EBITDA and Adjusted EBITDA
36
Source: Company filings. Note: Income tax effect of Total Pre-tax Adjustments was $40,884 and $10,310 for the three months ended March 31, 2017 and March 31, 2016, respectively. Adjusted net income attributable to CONSOL Energy Shareholders for the three months ended March 31, 2017 is calculated as GAAP net loss attributable to CONSOL Energy Shareholders of $38,966 plus total pre-tax adjustments from the above table of $117,949, less the associated tax expense of $40,884 equals the adjusted net income attributable to CONSOL Energy Shareholders of $38,099. (1) CONSOL Energy's Other Division includes expenses from various other corporate and diversified business unit activities including legacy liabilities costs and income tax
expense that are not allocated to E&P or PA Mining Operations Divisions.
Three Months Ended
March 31,
2017 2017 2017 2017 2016
($ in thousands)
E&P Division
PA Mining
Operations
DivisionOther
(1) Total Company Total Company
Net (Loss) Income ($93,502) $61,015 ($1,015) ($33,502) ($96,458)
Less: Loss from Discontinued Operations - - - - 53,167
Add: Interest Expense 621 2,297 41,515 44,433 49,865
Less: Interest Income - - (1,543) (1,543) (214)
Add: Income Taxes - - (53,789) (53,789) (23,800)
(Loss)/Earnings Before Interest & Taxes (EBIT) from Continuing Operations (92,881) 63,312 (14,832) (44,401) (17,440)
Add: Depreciation, Depletion & Amortization 95,348 42,301 11,104 148,753 154,988
Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from
Continuing Operations $2,467 $105,613 ($3,728) $104,352 $137,548
Adjustments:
Unrealized (Gain)/Loss on Commodity Derivative Instruments (24,640) - - ($24,640) 29,271
Impairment of E&P Properties 137,865 - - $137,865 -
Loss on Sale of Gathering Pipeline - - - - 12,636
Severance Expense 162 - 68 $230 2,918
Other Transaction Fees - - 5,316 5,316 -
Gain on Debt Extinguishment - - (822) (822) -
Total Pre-tax Adjustments $113,387 - $4,562 $117,949 $44,825
Adjusted EBITDA from Contiuing Operations $115,854 $105,613 $834 $222,301 $182,373
Less: Net Income Attributable to Noncontrolling Interest - 5,464 - 5,464 1,114
Adjusted EBITDA Attributable to Continuing Operations $115,854 $100,149 $834 $216,837 $181,259
Non-GAAP Reconciliation: TTM EBIT, EBITDA and Adjusted EBITDA
37
Source: Company filings.
Three Months
Ended
Three Months
Ended
Three Months
Ended
Three Months
Ended
Twelve Months
Ended
June 30, September 30, December 31, March 31, March 31,
($ in thousands) 2016 2016 2016 2017 2017
Net (Loss)/Income ($468,649) $27,593 ($301,634) ($33,502) ($776,192)
Less: Loss from Discontinued Operations 234,605 34,975 (19,564) - 250,016
Add: Interest Expense 47,427 47,317 46,867 44,433 186,044
Less: Interest Income (547) (214) (532) (1,543) (2,836)
Add: Tax Valuation Allowance - - 166,798 - 166,798
Add: Income Taxes (100,856) 52,858 (84,990) (53,789) (186,777)
(Loss)/Earnings Before Interest & Taxes (EBIT) from Continuing Operations (288,020) 162,529 (193,055) (44,401) (362,947)
Add: Depreciation, Depletion & Amortization 135,220 151,712 156,583 148,753 592,268
Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from
Continuing Operations ($152,800) $314,241 ($36,472) $104,352 $229,321
Adjustments:
Unrealized Loss/(Gain) on Commodity Derivative Instruments 279,715 (159,555) 236,802 (24,640) 332,322
Impairment of E&P Properties - - - 137,865 137,865
Severance Expense 1,451 952 424 230 3,057
Pension Settlement 13,696 3,652 4,848 - 22,196
Other Transaction Fees - - 3,752 5,316 9,068
Coal Contract Buyout (6,288) - - - (6,288)
Gain on Debt Extinguishment - - - (822) (822)
Total Pre-tax Adjustments $288,574 ($154,951) $245,826 $117,949 $497,398
Adjusted EBITDA from Continuing Operations $135,774 $159,290 $209,354 $222,301 $726,719
Less: Net Income Attributable to Noncontrolling Interest $1,179 $2,248 $4,413 $5,464 $13,304
Adjusted EBITDA Attributable to Continuing Operations $134,595 $157,042 $204,941 $216,837 $713,415
Free Cash Flow Reconciliation
38
Source: Company filings.
Three Months Ended Three Months Ended
March 31, March 31,
($ in thousands) 2017 2016
Net Cash provided by Continuing Operations $205,194 $119,808
Capital Expenditures (112,978) (78,968)
Net Distributions from Equity Affiliates 5,909 (5,578)
Organic Free Cash Flow From Continuing Operations $98,125 $35,262
Net Cash Provided By Operating Activities $205,119 $128,442
Capital Expenditures (112,978) (78,968)
Capital Expenditures of Discontinued Operations - (5,737)
Net Distributions from Equity Affiliates 5,909 (5,578)
Proceeds from Sales of Assets 19,427 411,259
Free Cash Flow $117,477 $449,418
top related