BARCLAYS CEO ENERGY-POWER CONFERENCEinvestors.cnx.com/~/media/Files/C/Consol-Energy-IR/... ·...
Transcript of BARCLAYS CEO ENERGY-POWER CONFERENCEinvestors.cnx.com/~/media/Files/C/Consol-Energy-IR/... ·...
BARCLAYS CEO ENERGY-POWER
CONFERENCE SEPTEMBER 5, 2017
Cautionary Language
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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 (including the timing and success of the potential separation); 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: uncertainties as to the timing and manner of the separation (whether by sale or spin-off) and whether it will be completed (including any dropdowns of the coal business); the possibility that various closing conditions for the separation may not be satisfied; the impact of the separation on our business; the expected tax treatment of the separation; the risk that the coal and natural gas exploration and production businesses will not be separated successfully or such separation may be more difficult, time-consuming or costly than expected, which could result in additional demands on our resources, systems, procedures and controls, disruption of our ongoing business and diversion of management's attention from other business concerns; competitive responses to the separation; 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; 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 as well as the factors described under the caption “Risk Factors” in the Form 10 filed with the SEC by the CONSOL Mining Corporation, on July 11, 2017, as amended from time to time. 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.
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Agenda
Executive Summary
Company Update • Overview • FY2017 Activity Summary • Marcellus Operations • Utica Operations • Marketing Overview • Guidance Updates
Strategic Initiatives • Asset Sale Update • Coal Separation Overview
Q&A
Executive Summary
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Current Q2 2017 Δ DRIVERS
GUIDANCE
Production – 2017E (Bcfe)
405-415 420-440 -20
Completion design optimization in Monroe County resulting in longer cycle times, greater water flowback, and increased equipment maintenance
Surface and downhole issues that required intervention
Tightening in the availability of field services
Total Company EBITDA – 2017E ($ millions)
$815 $870 -$55 Decline in production relative to prior expectation Weaker than expected coal realizations
Leverage Ratio – YE2017 (Net Debt / TTM Adj. EBITDA)
2.8x 2.6x +0.2x Reduction in YE2017E TTM adjusted EBITDA
Asset Sales ($ millions)
$410 $345 +$65 Additional asset sales closed in Q3 2017 and one
expected to close in Q4 2017
Note: The terms “EBITDA,” “net debt,” and “TTM adjusted EBITDA" are non-GAAP financial measures, which are defined and reconciled to the relevant GAAP measure below, under the caption “Non-GAAP Reconciliation.”
• Reducing 2017 E&P Division production guidance to approximately 405-415 Bcfe, compared to the previously stated guidance of 420-440 Bcfe
- Reaffirming capital guidance for FY2017 of $620-$645 million - Reaffirming FY2018 production guidance of 520-550 Bcfe
• Q3 2017 production expected to be approximately 100 Bcfe with Q/Q spike in Q4 2017 as TIL schedule ramps
• Total asset sales, including signed agreements, have reached approximately $410 million - Forward leverage ratio estimate assumes low-end of $400-$600 million asset sale guidance
• Coal segment spin targeted in Q4 2017
• One-year $200 million share repurchase program authorized by Board of Directors
COMPANY UPDATE
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6
CONSOL Energy’s Evolution
Acquisition of Dominion Resources E&P assets tripling Marcellus Shale acreage position
2014-2015 CONE Midstream Partners LP formed with Noble Energy to provide gathering services in the Marcellus Shale and CNX Coal Resources LP formed to house and manage CONSOL’s PA coal assets
2010 2013 2016 2016
Announces sale of five thermal coal mines in West Virginia to Murray Energy
With the sale of the Buchanan mine and other remaining legacy coal assets, CONSOL’s transformation into a premier natural gas Company is completed
2017+ CONSOL and Noble Energy announce separation of Marcellus JV, providing CONSOL with additional operational flexibility and the ability to reach leverage targets more rapidly
Looking to the future – working towards complete separation from coal; monetizing assets where possible; continuous operational improvement
Jan 2016 Today
Restarted Drilling
NBL JV
Resolution
Buchanan
Sale
Miller Creek &
Fola Sale
Turned DUC Inventory
Online
Cash
Stabilization
CNXC/
CNNX Drops CONSOL Mining
Form 10 Awaiting Final Reviews and
Approval from BOD, IRS, and SEC
Planned Spin Execution in Q4 2017
Acreage Position
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Note: Acreage numbers as of 2016 10-K ; PDPs as of 6/30/2017 (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) 197 39 60 1 297
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
FY2017 Activity Focus
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OH – Dry Utica Switz
• Eight pads • Drilling began Q3 2016 • TILs began July 2017
WV – Marcellus Shirley/Pennsboro
• Four pads • Remaining DUC inventory • TILs began May 2017
SWPA – Marcellus Morris/Green Hill/Richhill • Three pads • Drilling began Q1 2017 • TILs began Q3 2017
CPA – Deep Dry Utica Aikens/Marchand
• Two Aikens wells offsetting Gaut 4IH - Drilling began Q1 2017 - TILs scheduled Q4 2017
• Marchand well to start drilling in late Q3 2017
0
10
20
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40
50
60
70
80
0
20
40
60
80
100
120
140
160
180
200
2014 2015 2016 2017E
Incr
emen
tal W
ells
On
line
Net
Op
erat
ed P
rod
uct
ion
(B
cfe)
TIL Year
Marcellus Utica Net Production New wells
Operational Evolution
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Key Performance Metrics(1) 2014 2017E
Average EUR (Bcfe/1,000’) 1.4 2.8
Lease operating expense (LOE) ($/Mcfe) 0.49 0.19
Average Marcellus drilling days on well 27 14
Completion efficiency (ft/day) 575 1,040
Completion stage spacing (ft) 300 200-225
Completion proppant volume (lbs/ft) 1,300 2,500-3,500
Improved operational performance:
• Lean manufacturing
• Supply chain management
• Zero-based budgeting
Sustained growth at lower $/EUR
(1) Combined Marcellus and Utica key performance metrics unless otherwise noted
Cumulative Net Operated Production vs. Incremental Wells TIL by Year
Operational Evolution: Richhill Type Curve and EUR Increase
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Richhill, SWPA – Marcellus
• EUR increasing 20%, from 1.9 BCF/1000’, to 2.2 BCF/1000’
• RHL-23D and 23E compared to proposed type curve
• Actual production exceeding expectations with lower than forecasted decline
• Production facility capacity optimized to production protocol methodology
• Wells drilled up-dip yielding improved performance, RHL field re-design complete with up-dip approach
1
10
100
1,000
10,000
100,000
0 200 400 600 800 1,000 1,200 1,400
Gas
Rat
e (M
CFD
)
Days
ACTUAL PRODUCTION Proposed Curve Current Plan TC
Richhill-23D and 23E: Actual Production vs. Decline Curve
Operational Evolution: Additional Revised Type Curves
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Monroe County, OH – Dry Utica
• Better-than-expected reservoir performance, 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
CPA Deep Dry Utica: Aikens Drilling Update
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0
5000
10000
15000
20000
25000
0 20 40 60 80 100 120
Dep
th (
fee
t)
Days
Aikens wells offsetting Gaut 4IH show 173% improvement in feet drilled/day
• Aikens 5J drilled in 43 days and 5M drilled in 34 days with an average 7,500 foot lateral compared to 99 days for the Gaut 4IH with a 7,000 foot lateral
- Operational efficiency through intermediate section of well bore drove majority of the improvement
• Drilling costs for the Aikens 5J and 5M were $5.5 million and $4.6 million, respectively
- Represents a 71% decline for the Aikens 5M vs. the Gaut 4IH
• Total D&C capital for each Aikens well is expected to be about $15 million compared to approximately $27 million for the Gaut 4IH
• Both Aikens wells are scheduled to be completed and turned-in-line in 4Q17
Aikens 5J and 5M vs. Gaut 4IH: Days vs. Depth Drilled
Gaut 4IH Aikens 5J Aikens 5M
Marketing: Natural Gas Sales Market Mix
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MIDWEST TETCO M3
TETCO M2
EAST TENNESEE
TETCO ELA
TETCO WLA
TCO POOL
DOMINION SOUTH
Natural Gas Sales Market Mix 2017E 2018E
Columbia (TCO) 10% 10%
TETCO (M2) 50% 52%
TETCO (M3) 10% 6%
Dominion (DTI) 8% 9%
East Tennessee 13% 10%
TETCO ELA & WLA 6% 5%
Midwest (Michcon) 3% 8%
100% 100%
Marketing: Gas Hedges
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(1) Hedge positions as of 7/12/2017. 2017 includes actual settlements of 177.3 Bcf. 2021 excludes 11.9 Bcf of physical basis sales not matched with NYMEX hedges. (2) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements. (3) Based on midpoint of total production guidance of 405-415 Bcfe in 2017E.
• Approximately 77% of total 2017E production volumes hedged(3)
• NYMEX hedges added during Q2: 88 Bcf (2018-2020)
• Basis hedges added during Q2: 101 Bcf (2018-2021)
Gas Hedges 2017-2021
309.8 308.0
200.0
120.2
25.3
5.4 21.1
30.6
21.7
- 0
50
100
150
200
250
300
350
2017 2018 2019 2020 2021
Gas
Vo
lum
es H
edge
d (
Bcf
)
NYMEX Only Hedges Exposed to Basis NYMEX + Basis (2)
Hedge Volumes and Pricing Q3 2017 2017 2018 2019 2020 2021
NYMEX Only Hedges
Volumes (Bcf) 73.5 282.4 311.9 217.6 134.1 17.4
Average Prices ($/Mcf) $3.15 $3.14 $3.14 $3.02 $3.05 $2.99
Index Hedges and Contracts
Volumes (Bcf) 8.2 32.8
17.2 13.0 7.8 7.9
Average Prices ($/Mcf) $3.17 $3.15 $2.62 $2.47 $2.41 $2.39
Total Volumes Hedged (Bcf)(1) 81.7 315.2 329.1 230.6 141.9 25.3
NYMEX + Basis (fully-covered volumes)(2)
Volumes (Bcf) 77.7 309.8 308.0 200.0 120.2 25.3
Average Prices ($/Mcf) $2.54 $2.59 $2.81 $2.73 $2.78 $2.67
NYMEX Only Hedges Exposed to Basis
Volumes (Bcf) 4.0 5.4 21.1 30.6 21.7 -
Average Prices ($/Mcf) $3.15 $3.14 $3.14 $3.02 $3.05 -
Total Volumes Hedged (Bcf)(1) 81.7 315.2 329.1 230.6 141.9 25.3
Updated 2017E EBITDA Guidance
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Note: Base plan assumes NYMEX as of 6/30/2017 of $3.17 per MMBtu + weighted average basis of ($0.51) per MMBtu on open volumes. CONSOL Energy is unable to provide a reconciliation of projected EBITDA and Adjusted 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. (1) Includes forecasted Earnings of Equity Affiliates of $40 million in 2017 associated with CNX's proportionate share of ownership in CONE Midstream Partners. This income is
reflected within Miscellaneous Other Income in the CNX Income Statement.
($ in millions) E&P(1) PA Mining
Operations Other
Current Total
(as of 9/5/17)
Prior Total
(as of 8/1/17)
Earnings Before Interest, Taxes and DD&A (EBITDA)
$675 $380 ($20) $1,035 $1,055
Adjustments:
Unrealized (Gain) on Commodity Derivative Instruments
(205) - - (205) (165)
Stock-Based Compensation 20 10 - 30 30
Adjusted EBITDA $490 $390 ($20) $860 $920
Noncontrolling Interest - (45) - (45) (50)
Adjusted EBITDA Attributable to CNX $490 $345 ($20) $815 $870
2017 TD TIL
Marcellus 10 31
Utica 24 26
Upper Devonian - 3
CBM 63 63
TOTAL ex. CBM 34 60
FY2017 Development Plan Unchanged
Segment Guidance
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Note: Guidance as of 9/5/2017, based on strip pricing as of 6/30/2017 of $3.17 per MMBtu + weighted average basis of ($0.51) per MMBtu on open volumes. (1) Excludes stock-based compensation. (2) Includes Idle Rig Charges, Unutilized Firm Transportation Expense (Net Of 3rd Party Revenue), Land Rentals, Lease Expiration Costs, Misc. Gas, and Exploration Expense. (3) As of end of 2Q17.
E&P Segment Guidance 2017E
Production Volumes: Natural Gas (Bcf) 360-370 NGLs (MBbls) 6,800-7,000 Oil (MBbls) 60-65 Condensate (MBbls) 540-550
Total Production (Bcfe) 405-415 % Liquids 9%-11%
Open Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.35)-($0.43) NGL Realized Price ($/Bbl) $19.00-$20.00 Condensate Realized Price % of WTI 70% Oil Realized Price % of WTI 90%
Capital Expenditures ($ in millions):
Total E&P and Midstream CapEx $620-$645 Average per unit operating expenses ($/Mcfe):
Lease Operating Expense $0.17-$0.21 Production, Ad Valorem, and Other Fees $0.07-$0.08 Transportation, Gathering and Compression $0.90-$0.95
Total Cash Production and Gathering Costs $1.14-$1.24
Other Expenses ($ in millions): Selling, General, and Administrative Costs(1) $70-$75 Other Corporate Expenses(2) $75-$80
PA Mining Operations – Consolidated 100% Basis 2017E
Coal Sales Volumes:
Total Coal Sales Volumes (millions of tons) 25.6-27.6
Total Committed Volumes (contracted and priced) 25.4 % Committed ~95%(3)
Capital Expenditures ($ in millions): Total Coal Capital Expenditures ($ in millions) $112-$120
• Coal capital expenditures expected to be approximately $5 per ton in 2018 and beyond
STRATEGIC INITIATIVES
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Asset Sale Update
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Analyst Day December 2016
• Announced plan to sell $400-$600 million of assets in 2017
Q4 2016
Q3 2017 Q1 2017
Q1 2017 Earnings Call May 2017
• Closed on $108 million of sales YTD ‐ 6,300 Utica/Point Pleasant acres
in Ohio for $77 million ‐ Two transactions consisting of
non-core oil and gas assets, pipelines and surface properties worth combined $31 million
• Stated expectation to reach ~$300 million in sales by end of Q2 2017
Q2 2017 Earnings Call August 2017
• Announced $245 million of asset sales in the quarter for YTD total of $345 million ‐ $130 million for 12 PDPs, 15 DUCs, and
~11,000 acres in WV ‐ Three other transactions for total of
11,500 undeveloped acres in PA for $85 million
‐ Non-core acreage sale of ~$30 million to close in Q3 2017
• Stated expectation to reach ~$400 million in sales by year end
Q2 2017
Q3 2017 • Closed on $385 million in asset
sales YTD • Reached signed sales agreement on
additional $25 million sale expected to close late September or early October ‐ Total of $410 million closed or
signed sales YTD • Current year-end leverage ratio
forecast based on asset sales already completed YTD
SpinCo Structure: Material Components
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Pennsylvania Mining Complex
(PAMC)
Premier U.S. thermal coal assets ~90% owned by CNX when combining direct ownership (75%) with ownership in CNXC MLP
Interest in CNXC MLP MLP owns 25% of PAMC; CONSOL Energy owns ~62% of MLP through outstanding LP and GP units
Baltimore Terminal Provides access to seaborne markets and is expected to generate $29-$32 million of EBITDA in FY2017; 15 million ton per year capacity
Legacy Coal Liabilities Legacy liabilities associated with the coal assets including OPEB, asset retirement obligations, and pension costs set to spin off with the segment
Note: For complete details and pro forma financial statements, see Form 10 filed by CONSOL Mining Corp., July 11, 2017, as amended from time to time.
Pennsylvania Mining Complex: Overview
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Mine
Total Recoverable
Reserves (tons)
Avg. AR Gross Heat
Content (Btu/lb)
Average AR Sulfur Content
Annual Production
Capacity (tons)
2016 Production
(tons)
Bailey(1) 259.7 12,920 2.64% 11.5 12.1
Enlow Fork(1) 306.5 13,030 2.25% 11.5 9.6
Harvey(1) 200.5 12,970 2.25% 5.5 3.0
Total 766.7 12,970 2.38% 28.5 24.7
Illinois Basin(2) 11,356 2.94%
Other NAPP(2) 12,293 3.24%
Other Coal MLPs(2,3) 11,881 2.74%
(1) For the period ending December 31, 2016. (2) Source: EIA. Represents average power plant deliveries for the twelve months ending October 31, 2016. (3) Includes Northern Appalachian and Illinois Basin production from ARLP, FELP, RHNO, and WMLP.
• Pennsylvania Mining Complex (PAMC) consists of three like-new underground mines and related infrastructure with high-Btu bituminous coal - PAMC – 766.7 million tons reserves(1) / 28.5 million tons annual
capacity
• 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 2.4% average sulfur content over the life of the reserves
• Five longwalls and 15-17 continuous mining sections
• Access to seaborne markets through CONSOL-owned Baltimore Marine Terminal for exporting thermal and metallurgical coal
• Over $2.0 billion invested in Harvey Mine, new slopes, overland conveyor belts, equipment, and plant upgrades since 2008
2016 PA Mining Complex Domestic Customers
PA Mining Complex
Baltimore Terminal
Pennsylvania Mining Complex: Longwall Productivity
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24.7
4.4 3.9 1.5
10.5
7.0 6.6 6.3 5.0
6.6
2.0 3.6
7.3
4.9
6.4
2.2
6.4
4.8
6.9
6.0
6.5
7.3
4.4
3.6
–
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0
5
10
15
20
25
30
PA
MC
(5)
Ma
rion
Cou
nty
(1)
Mo
non
galia
Cou
nty
(1)
Fed
era
l (1
)
Ma
rsh
all
Co
unty
(2)
Cu
mbe
rlan
d (
1)
Tun
nel R
idge
(1)
Ohio
Co
unty
(1)
Ce
ntu
ry (
1)
Ha
rris
on C
ounty
(1)
Mo
unta
in V
iew
(1
)
Le
er
(1)
Pro
ductiv
ity (tons / e
mplo
yee h
our)
Pro
duction (
mill
ion t
ons)
2016 production 2016 productivity
Higher sulfur Near end of reserve life
Mine mouth operations
Primarily met coal producer
Serve river markets
Source: EIA 923, MSHA. Note: Number of longwalls indicated in parentheses.
Pennsylvania Mining Complex: Transportation Advantage
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• PAMC has best-in-U.S. access to export infrastructure
• Logistics infrastructure and proximity to coal-fired power plants allow operational and marketing flexibility
• Norfolk Southern and CSX rail lines enable direct access to domestic customers and Baltimore Terminal - Baltimore Terminal provides valuable
options to access international markets
• Transportation advantage: - NAPP has a $4-8/ton advantage vs. ILB in
the Carolinas, and an even greater advantage in the Mid-Atlantic states
- NAPP has a $3-8/ton advantage vs. ILB to Europe / India(1)
- These values do not account for Btu differences (9%-18% higher than ILB’s), which give NAPP an even greater advantage
Transportation Overview
Source: CONSOL and CNXC Management, ABB Velocity Suite. (1) Includes vessel differential. Assumes NAPP exported through Baltimore and ILB exported through Gulf.
Pennsylvania Mining Complex: Marketing
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PAMC has capitalized on reliable production, world-class quality, and excellent access to rail and port infrastructure to strategically build a highly diversified portfolio, providing volume stability and multiple paths to upside.
PAMC Marketing Strategy 2016 Coal Sales Portfolio by Market Segment
In 2016, PAMC sold coal to 38 domestic power plants located in 18 states, and to thermal and metallurgical end-users located across four
continents.
Maximize sales to established customer base of rail-served power plants in the Eastern U.S., with a focus on top-performing environmentally-controlled plants
Place approximately 5-10% per annum in the crossover met coal market
2
1
Selectively place remaining tonnage in opportunities (domestic or export) that maximize FOB mine
realizations 3
Capitalize on innovative marketing tactics and strategies to grow opportunities and realizations in all
of the Company’s market areas 4
37%
28%
10%
7%
7%
5% 3% 3%
Domestic - PJM
Domestic - Southeast
Domestic - Miso
Europe Terminal
Asia Terminal
Asia Metallurgical
0
10
20
30
40
50
60
70
2012 2013 2014 2015 2016
Ton
s (M
illio
ns)
12%
31%
37%
11%
9%
PAMC
Other NAPP
CAPP
ILB
PRB
Pennsylvania Mining Complex: Marketing (Cont’d)
24
Top 15 PAMC Customer Plants(1) Share of Tons Delivered Top 15 PAMC Customer Plants Annual Coal Burn
2011
Top 15 PAMC Customer Plants
• Provide steady demand for >50 mm tons of coal per year
• Accounted for 82% of our domestic power plant shipments in 2016
• All have been in the portfolio for 3+ years
• Average size = 1.8 GW
• All are equipped with state-of-the-art emission controls, including scrubbers
• None have announced plans to retire
• Operated at a 15 percentage point higher weighted-average capacity factor than other NAPP rail-served plants in 2016
2016
32%
21% 14%
17%
16%
Top customer plants are top performers. PAMC achieved a 20 percentage point increase in market share at these plants since 2011, largely by displacing other NAPP and CAPP producers, with more room still to grow.
(1) Represent the 15 largest U.S. power plant customers of PAMC in 2016, based on total tons sold
2017ERetained EBITDA LP Units Cash Distributions
CNXC: Value of CNX Passive Ownership in PAMC
75% ownership of PA Mining Complex
16.6 million total LP units held by CNX(2)
CNX % LP Units' share 60.1%
CNX % GP Units' share 1.7%
CNX Total % Interest in
CNXC 61.8%
Option to drop remaining ownership over time
CNXC Value Representation(1)
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. (1) Graph not indicative of actual CNXC valuation to CNX. (2) LP units of various classes, on an as-converted basis. (3) Unit price as of market close 8/29/2017.
CNX Coal Resources LP value to CNX is comprised of four main drivers:
Retained EBITDA Cash Distributions Drop Downs Ownership of LP and GP/IDR
CNXC Value Streams to CNX(units and $ in millions, except per share data)
2017E Cash Distributions (LP&GP)
Common Units 9.7$
Subordinated Units 23.8$
GP Units 1.2$
Total 2017E Cash Distributions 34.7$
LP Units
Unit Price(3) 15.25$
Units Held 16.6
LP Unit Value 253.4$
CNXC EBITDA Contribution to CNX
2017E Retained EBITDA 345.0$
Total combined interest in PA Mining Ops: 90%
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Baltimore Terminal: Overview
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Overview:
• Coal export terminal
• 15 million tons per year capacity throughput; 1.1 million tons coal storage yard capacity
• Strategically located: able to access the attractive seaborne markets supplying both Europe and Asia
• The only coal export terminal on the East Coast served by two railroads: Norfolk Southern and CSX Corporation
Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.
2016 achievements:
• Opened the terminal up for throughput capacity from third party shippers: Signed 3 million tons for 2017 (with take or pay provisions) from third party shipping contracts in addition to legacy contracts of 12 million tons reserve (not take or pay)
• Achieved significant service and operating cost efficiencies in 2016
2017 performance:
• Strong met and stronger thermal export market indications provide reasonable expectation of 12-14 million ton throughput providing $29-$32 million of EBITDA
• Cost savings of at least $1 million from scheduling and supply chain optimization
$4,187
$1,703 $1,497 $1,362 $1,267 $1,232 $1,226
$975
$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
$4,500
2012 2013 2014 2015 2016 Q2 2017 2017E 2017E
An
nu
al C
ash
Ser
vici
ng
Co
sts
($
in M
illio
ns)
Lega
cy L
iab
iliti
es (
$ in
mill
ion
s)
Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost
Coal Legacy Liabilities
27
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
• Qualified pension plan almost completely funded
Balance Sheet Liability Long-Term Liability Guidance
6/30/2017 FY 2017E FY 2018E
LTD $18
WC 78 CWP 117
OPEB 695
Unfunded Retirement Obligations 107
Asset Retirement Obligations 217
Total Legacy Liabilities $1,232
Total Quarterly Cash Servicing Cost $21 $74 - $79 $70 - $75
EBITDA Impact ($14) ($57 - $62) ($57 - $62)
Note: 6/30/17 liability balance includes approximately $24 million and $37 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 plugging and abandonment (or P&A) expense.
At current ~4% discount rate
Assuming 6.3% discount rate
3.0x 2.8x
$-
$500
$1,000
$1,500
$2,000
$2,500
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
6.0x
YE2015 YE2016 Q1 2017 Q2 2017 2017E Tota
l Liq
uid
ity
($ m
illio
ns)
Net
Deb
t /
TTM
Ad
j. EB
ITD
A
Leverage Ratio Total Liquidity
Spin Process: Leverage Ratio and Restricted Payments Bucket
28
Source: Company filings. Note: The terms “net debt” and “TTM adjusted EBITDA“ non-GAAP financial measures, which are defined and reconciled to the relevant GAAP measures below, under the caption “Non-GAAP Reconciliation.“ (1) Assumes $400 million completed of the $400-$600 million asset sale guidance range for FY2017. (2) See Indentures in Form 8K, Sept. 30, 2015.
Leverage ratio down nearly 40% since end of 2015
(1)
• Rolling aggregated sum equal to 50% of Consolidated Net Income beginning in FY2010 plus net cash proceeds of any equity issuances since that time(2)
• Value as of 6/30/2017: ~$2.7 billion
• Not subject to leverage ratio covenants
• CoalCo value deducted from RP basket
• Intended to be tax-free
Indentures identify two different mechanisms that can be used to execute the CoalCo spin:
Qualified Spin Restricted Payments Basket OR
• Requires gross leverage ratio of <2.75x for pro forma E&P company
• Intended to be tax-free
Summary
29
NAV/SHARE DRIVEN
Free cash flow
Optimized completion design
Disciplined spending rather than chasing production
UNIQUE ASSET BASE
Multiple decades of high NRI inventory
Capacity to monetize or high-grade non-core acres
Large stacked pay opportunity
Premier thermal coal assets
COAL SEPARATION
Management teams and internal processes in place now
Focus on creating two strong separate entities
Plan to execute spin-off in Q4 2017
TWO
PR
EMIE
R S
TAN
DA
LON
E C
OM
PAN
IES
E&P RemainCo
CoalCo
Q&A
30
APPENDIX
31
Non-GAAP Reconciliation: EBITDA and Adjusted EBITDA
32
Source: Company filings. (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. (2) Adjusted EBITDA Attributable to Noncontrolling Interest for the three months ended June 30,2017 is Net Income Attributable to Noncontrolling interest of $4,313 plus
Depreciation, Depletion and Amortization of $4,606, plus Interest Expense of $1,074, plus Stock-based compensation of $309. Adjusted EBITDA Attributable to Noncontrolling Interest for the three months ended June 30,2016 is Net Income Attributable to Noncontrolling interest of $1,179 plus Depreciation, Depletion and Amortization of $4,646, plus Interest Expense of $925 plus Stock-based compensation of $192.
Three Months Ended
June 30,
2017 2017 2017 2017 2016
($ in thousands)
E&P Division
PA Mining
Operations
DivisionOther(1) Total Company Total Company
Net Income (Loss) $227,413 $51,876 ($105,466) $173,823 ($468,649)
Less: Loss from Discontinued Operations - - - - 234,605
Add: Interest Expense 598 2,233 40,601 43,432 47,428
Less: Interest Income - - (6,533) (6,533) (547)
Add: Income Taxes - - 66,993 66,993 (100,856)
Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 228,011 54,109 (4,405) 277,715 (288,019)
Add: Depreciation, Depletion & Amortization 91,287 41,402 (15,620) 117,069 135,220
Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from Continuing Operations $319,298 $95,511 ($20,025) $394,784 ($152,799)
Adjustments:
Unrealized (Gain)/Loss on Commodity Derivative Instruments (116,073) - - (116,073) 279,715
Gain on Asset Sales (126,707) - - (126,707) -
Severance Expense 10 - 103 113 1,451
Other Transaction Fees - - 8,411 8,411 -
Loss on Debt Extinguishment - - 36 36 -
Stock-Based Compensation 4,148 5,332 495 9,975 10,430
Pension Settlement - - - - 13,696
Lease Expirations 16,861 - - 16,861 -
Coal Contract Buyout - - - - (6,288)
Total Pre-tax Adjustments ($221,761) $5,332 $9,045 ($207,384) $299,004
Adjusted EBITDA from Continuing Operations $97,537 $100,843 ($10,980) $187,400 $146,205
Less: Adjusted EBITDA Attributable to Noncontrolling Interest(2) - 10,302 - 10,302 6,942
Adjusted EBITDA Attributable to Continuing Operations $97,537 $90,541 ($10,980) $177,098 $139,263
Non-GAAP Reconciliation: TTM EBIT, EBITDA, and Adj. EBITDA
33
Source: Company filings.
Three Months
Ended
Three Months
Ended
Three Months
Ended
Three Months
Ended
Twelve Months
Ended
Three Months
Ended
Twelve Months
Ended
June 30, September 30, December 31, March 31, March 31, June 30, June 30,
($ in thousands) 2016 2016 2016 2017 2017 2017 2017
Net (Loss)/Income ($468,649) $27,598 ($301,634) ($33,502) ($776,187) $173,823 ($133,715)
Less: Loss/(Income) from Discontinued Operations 234,605 34,975 (19,564) - 250,016 - 15,411
Add: Interest Expense 47,428 47,316 46,867 44,433 186,044 43,432 182,048
Less: Interest Income (547) (214) (532) (1,543) (2,836) (6,533) (8,822)
Add: Tax Valuation Allowance - - 166,798 - 166,798 - 166,798
Add: Income Taxes (100,856) 52,858 (84,990) (53,789) (186,777) 66,993 (18,928)
(Loss)/Earnings Before Interest & Taxes (EBIT)
from Continuing Operations (288,019) 162,533 (193,055) (44,401) (362,942) 277,715 202,792
Add: Depreciation, Depletion & Amortization 135,220 151,712 156,583 148,770 592,285 117,069 574,134
Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA)
from Continuing Operations ($152,799) $314,245 ($36,472) $104,369 $229,343 $394,784 $776,926
Adjustments:
Unrealized Loss/(Gain) on Commodity Derivative Instruments 279,715 (159,555) 236,802 (24,640) 332,322 (116,073) (63,466)
Gain on Asset Sales - - - - - (126,707) (126,707)
Impairment on E&P Properties - - - 137,865 137,865 - 137,865
Severance Expense 1,451 952 424 230 3,057 113 1,719
Pension Settlement 13,696 3,652 4,848 - 22,196 - 8,500
Noble Transaction Fees - - 3,752 - 3,752 - 3,752
Other Transaction Fees - - - 5,316 5,316 8,411 13,727
Stock-Based Compensation 10,430 7,771 7,658 6,702 32,561 9,975 32,106
Lease Expirations - - - - - 16,861 16,861
Coal Contract Buyout (6,288) - - - (6,288) - -
(Gain)/Loss on Debt Extinguishment - - - (822) (822) 36 (786)
Total Pre-tax Adjustments $299,004 ($147,180) $253,484 $124,651 $529,959 ($207,384) $23,571
Adjusted Earnings Before Interest, Taxes and DD&A
(Adjusted EBITDA) $146,205 $167,065 $217,012 $229,020 $759,302 $187,400 $800,497
Less: Adjusted EBITDA Attributable to Noncontrolling Interest $6,942 $8,173 $10,465 $11,578 $37,158 $10,302 $40,518
Adjusted EBITDA Attributable to Continuing Operations $139,263 $158,892 $206,547 $217,442 $722,144 $177,098 $759,979
Non-GAAP Reconciliation: Noncontrolling Interest and Net Debt
34
Source: Company filings.
Three Months Ended Three Months Ended
June 30, March 31,
($ in millions) 2017 2017
CNX Total Long-Term Debt including Current Portion $2,641 $2,669
Less: Noncontrolling Interest (38.4%) in CNXC Revolver 72 75
Less: CNX Cash and Cash Equivalents 299 61
Add: CNXC Cash and Cash Equivalents 6 7
CNX Net Debt $2,276 $2,540
Three Months
Ended
Three Months
Ended
Three Months
Ended
Three Months
Ended
Twelve Months
Ended
Three Months
Ended
Twelve Months
Ended
June 30, September 30, December 31, March 31, March 31, June 30, June 30,
($ in thousands) 2016 2016 2016 2017 2017 2017 2017
Net Income Attributable to Noncontrolling Interest $1,179 $2,248 $4,413 $5,464 $13,304 $4,313 $16,438
Add: Interest Expense 925 991 1,089 1,099 4,104 1,074 4,253
Earnings Before Interest & Taxes (EBIT) Attributable to
Noncontrolling Interest 2,104 3,239 5,502 6,563 17,408 5,387 20,691
Add: Depreciation, Depletion & Amortization 4,646 4,723 4,753 4,706 18,828 4,606 18,788
Earnings Before Interest, Taxes and DD&A (EBITDA)
Attributable to Noncontrolling Interest $6,750 $7,962 $10,255 $11,269 $36,236 $9,993 $39,479
Adjustments:
Stock Based Compensation 192 211 210 309 922 309 1,039
Total Pre-tax Adjustments $192 $211 $210 $309 $922 $309 $1,039
Adjusted EBITDA Attibutable to Noncontrolling Interest $6,942 $8,173 $10,465 $11,578 $37,158 $10,302 $40,518
Non-GAAP Reconciliation: Free Cash Flow
35
Source: Company filings.
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
($ in thousands) 2017 2016 2017 2016
Net Cash provided by Continuing Operations $88,977 $82,901 $294,171 $206,345
Capital Expenditures (160,348) (37,601) (273,326) (115,257)
Net Distributions from/(Investments in) Equity Affiliates 18,791 - 24,700 (5,578)
Organic Free Cash Flow From Continuing Operations ($52,580) $45,300 $45,545 $85,510
Net Cash Provided By Operating Activities $88,777 $95,446 $293,896 $225,398
Capital Expenditures (160,348) (37,601) (273,326) (115,257)
Capital Expenditures of Discontinued Operations - (1,246) - 394,511
Net Distributions from/(Investments in) Equity Affiliates 18,791 - 24,700 (5,578)
Proceeds from Sales of Assets 325,724 9,831 345,151 18,284
Free Cash Flow $272,944 $66,430 $390,421 $517,358
Appendix: Strong Liquidity Position of ~$2 Billion
36
$2.0 billion Revolving Credit Facility
• 5 year credit facility expires June 2019
• Gas reserves based lending facility borrowing base reaffirmed at $2 billion in Q2 2017
- 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 $299 million as of 6/30/2017, $6 million of which was CNXC’s and consolidated in CNX’s financial statements per US GAAP accounting.
(2) Revolving credit facility as of 6/30/2017.
June 30, 2017 ($ in millions)
Amount/
Capacity
Amount
Drawn
Letters
of Credit
Amount
Available
Cash and Cash Equivalents (1) $293 - - $293
Revolving Credit Facility(2) $2,000 $0 $314 $1,686
Total $2,293 $0 $314 $1,979
Maintenance Covenants Limit
June 30,
2017
CONSOL Energy Revolver:
Minimum Interest Coverage Ratio < 2.5 to 1.0 5.0 to 1.0
Minimum Current Ratio < 1.0 to 1.0 3.3 to 1.0