EARNINGS RESULTS
THIRD QUARTER 2017
EARNINGS RESULTS THIRD QUARTER 2017 Cautionary Language This - - PowerPoint PPT Presentation
EARNINGS RESULTS THIRD QUARTER 2017 Cautionary Language 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).
THIRD QUARTER 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; 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 of the separation and whether it will be completed; 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. 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.
Post-Spin Company Names and Stock Trading Symbols
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Effective November 28, 2017, the company known as CONSOL Energy Inc. (NYSE: CNX) expects to separate its gas business (GasCo or RemainCo) and its coal business (CoalCo or SpinCo) into two independent, publicly traded companies by means of a separation of CoalCo from RemainCo.
listed on the New York Stock Exchange (NYSE), retaining the ticker symbol “CNX”. After the spin-off occurs, information regarding CNX and its natural gas business will be available at www.cnx.com.
under a new ticker symbol: “CEIX”. CoalCo will own, operate and develop all of the company’s coal assets, including the Pennsylvania Mining Complex, the Baltimore Marine Terminal, and approximately 1.6 billion tons of greenfield coal reserves. After the spin-off occurs, information regarding the new CONSOL Energy and its coal business will be available at www.consolenergy.com.
CONSOL Coal Resources LP and will trade on the NYSE under a new ticker symbol: “CCR”. CoalCo will own 100 percent of the general partner of CONSOL Coal Resources LP (representing a 1.7 percent general partner interest), as well as all of the incentive distribution rights and the subordinated partnership units in CNX Coal Resources LP, which are currently owned by CONSOL Energy Inc. After the spin-off occurs, information regarding CONSOL Coal Resources will be available at www.ccrlp.com
Executive Summary
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Q3 2017 EXPECTATION STRATEGIC INITIATIVE
Operational Execution
generation completion designs and positive early production results
heading into FY2018
Non-Core Asset Sales
including Virginia coalbed methane project area and scattered Marcellus and Utica acres
Leverage Ratio – YE2017
(Net Debt / TTM Adj. EBITDA)
completion of the spin transaction
Production Guidance
production of ~120 Bcfe
520-550 Bcfe
Share Repurchase
~$81 million worth of shares through market close on October 30, 2017
and will be executed opportunistically as market conditions allow
Spin Transaction
announced on Tuesday, October 31
Regular Way trading expected to commence November 29
Note: The terms “net debt” and “TTM adjusted EBITDA" are non-GAAP financial measures, which are defined and reconciled to the relevant GAAP measure below, under the caption “Non-GAAP Reconciliation."
Spin Transaction: Process Overview
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SpinCo (to be renamed “CONSOL Energy Inc.” following completion of the spin)
Rebranding Ticker CEIX Exchange NYSE Distribution Ratio 1 share of CEIX for every 8 shares of CNX outstanding as of the record date Number of Outstanding SpinCo Shares ~28.75 million(1) “When Issued” Trading Commences November 14, 2017 Record Date November 15, 2017 Distribution Date November 28, 2017 “Regular Way” Trading Begins November 29, 2017
Note: Anticipated dates; all dates remain subject to change. (1) Based on CNX shares outstanding as of 3Q17 end of about 230 million.
Spin Transaction: Expected Capital Structure
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SpinCo Capital Raise Expected Sources and Uses
Amount
($ in thousands)
New Term Loan A Facility $100,000 New Term Loan B Facility 400,000 New Second Lien Secured Notes 300,000 Total Sources $800,000 Amount
($ in thousands)
Refinancing of CNXC Revolver $190,000 Cash transfer to ParentCo, net of fees 425,000 Cash to balance sheet 146,000 Transaction fees and expenses 39,000 Total Uses $800,000
Sources Uses
RemainCo Pro Forma Net Debt
(1) Estimated pro forma values are approximate as of 3Q 2017 end.
Amount
($ in thousands)
Q3 2017 consolidated LTD plus current portion $2,543,283 Less: Baltimore Terminal bonds 102,865 Less: CNXC Revolver 188,000 Less: SpinCo related other debt obligations 15,352 Less: Cash transfer from SpinCo (net of fees) 425,000 Less: Q3 2017 end cash and cash equivalents 282,096 RemainCo Pro Forma Net Debt $1,529,970
RemainCo Pro Forma Estimates(1)
Q3 2017 Results
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quarter or ($0.11) per diluted share; Adjusted Net Loss Attributable to CONSOL Energy Shareholders of $36 million, or ($0.15) per diluted share(1); Adjusted Net Loss excludes the following pre-tax items:
Note: The terms “Adjusted Net Income Attributable to CONSOL Energy Shareholders," and “Adjusted EBITDA Attributable to Continuing Operations" are non-GAAP financial measures, which are defined and reconciled to the GAAP net income below, under the caption “Non-GAAP Reconciliation." (1) Income tax effect of Total Pre-tax Adjustments was $5,530 for the three months ended September 30, 2017. Adjusted net loss attributable to CONSOL Energy Shareholders for the three months ended September 30, 2017 is calculated as GAAP net loss attributable to CONSOL Energy Shareholders of $26,441 less total pre-tax adjustments of $14,943, plus the associated tax expense of $5,530 equals the adjusted net loss attributable to CONSOL Energy Shareholders of $35,854.
Q3 2017 Summary ($ in millions, except per share data) 3Q 2017 3Q 2016 Y/Y Change 3Q 2017 2Q 2017 Q/Q Change Net (Loss) / Income Attributable to CNX Shareholders ($26) $25 ($51) ($26) $170 ($196) (Loss) / Earnings per Diluted Share ($0.11) $0.11 ($0.22) ($0.11) $0.73 ($0.84) Revenue and Other Income from Continuing Operations $671 $746 ($75) $671 $866 ($195) Net Cash Provided by Continuing Operating Activities $179 $168 $11 $179 $89 $90 Adjusted EBITDA Attributable to Continuing Operations $168 $158 $10 $168 $177 ($9)
Q3 2017 Results (Cont’d)
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Source: Company filings. Note: Numbers may not sum and may differ slightly from totals and financial statements due to rounding. The term “free cash flow" is a non-GAAP financial measure, which is defined and reconciled to the GAAP Net Cash Provided by Operating Activities below, under the caption “Non-GAAP Reconciliation."
Net (Decrease) / Increase in Cash
close on October 30, 2017
Q3 2017 Cash Flow Summary ($ in millions) 3Q 2017 3Q 2016 Y/Y Change 3Q 2017 2Q 2017 Q/Q Change Net Cash Provided by Operating Activities $178 $163 ($6) $178 $89 $89 Capital Expenditures ($177) ($64) ($122) ($177) ($160) ($17) Proceeds from Asset Sales $82 $21 $61 $82 $326 ($244) Other Investing $11 (27) $38 $11 $19 ($8) (Payments on) / Proceeds from Short-Term Debt & Misc. Borrowings ($5) ($104) $99 ($5) ($3) ($2) (Payments on) / Proceeds from Long-Term Notes ($97)
($97) ($19) ($78) Other Financing ($5) ($6) $1 ($5) ($14) $9 Net (Decrease) / Increase in Cash ($13) ($18) $5 ($13) $238 ($251)
3.0x 2.8x
$- $500 $1,000 $1,500 $2,000 $2,500 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x YE2015 YE2016 Q2 2017 Q3 2017 Total Liquidity ($ millions) Net Debt / TTM Adj. EBITDA Leverage Ratio Total Liquidity
Deleveraging Progress
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Source: Company filings. Note: The terms “net debt,” “TTM adjusted EBITDA,“ and “free cash flow” are non-GAAP financial measures, which are defined and reconciled to the relevant GAAP measures under the caption “Non-GAAP Reconciliation.“
Leverage ratio down more than 40% since 2015 peak
and scattered Marcellus and Utica acres
Marketing: Gas Hedges
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(1) Hedge positions as of 10/17/2017 includes actual settlements of 258.2 Bcf. 2018 excludes 9.1 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.
production volumes hedged(3)
127 Bcf (2018-2021)
169 Bcf (2017-2021)
Gas Hedges 2017-2021
311.3 333.3 239.1 166.2 94.8 5.3 0.3 7.3 31.7 50 100 150 200 250 300 350 2017 2018 2019 2020 2021 Gas Volumes Hedged (Bcf) NYMEX Only Hedges Exposed to Basis NYMEX + Basis (2) 0.0
Hedge Volumes and Pricing Q4 2017 2017 2018 2019 2020 2021 NYMEX Only Hedges Volumes (Bcf) 73.5 282.4 316.1 226.3 161.6 113.8 Average Prices ($/Mcf) $3.16 $3.14 $3.14 $2.99 $2.89 $2.59 Index Hedges and Contracts Volumes (Bcf) 9.6 34.2 17.2 13.1 11.9 12.7 Average Prices ($/Mcf) $3.01 $3.11 $2.62 $2.44 $2.27 $2.09 Total Volumes Hedged (Bcf)(1) 83.1 316.6 333.3 239.4 173.5 126.5 NYMEX + Basis (fully-covered volumes)(2) Volumes (Bcf) 81.7 311.3 333.3 239.1 166.2 94.8 Average Prices ($/Mcf) $2.62 $2.59 $2.78 $2.69 $2.59 $2.25 NYMEX Only Hedges Exposed to Basis Volumes (Bcf) 1.4 5.3
Average Prices ($/Mcf) $3.16 $3.14
$2.89 $2.59 Total Volumes Hedged (Bcf)(1) 83.1 316.6 333.3 239.4 173.5 126.5
Segment Guidance
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E&P Segment Guidance 2017E Production Volumes: Natural Gas (Bcf) 360-370 NGLs (MBbls) 6,800-7,000 Oil (MBbls) 60-65 Condensate (MBbls) 540-550 Total Production (Bcfe) 405-415 % Liquids 9%-11% Open Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.40)-($0.50) NGL Realized Price ($/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
Note: Guidance as of 10/31/2017, based on NYMEX as of 9/29/2017 of $3.14 per MMBtu + weighted average basis of ($0.61) 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.
Updated 2017E EBITDA Guidance
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Note: Base plan assumes NYMEX as of 9/29/2017 of $3.14 per MMBtu + weighted average basis of ($0.61) per MMBtu on open volumes. CONSOL Energy is unable to provide a reconciliation of projected 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 (10/31/17) Prior Total (9/5/17) Earnings Before Interest, Taxes and DD&A (EBITDA) $615 $365 ($20) $960 $1,035 Adjustments: Unrealized (Gain) on Commodity Derivative Instruments (140)
(205) Stock-Based Compensation 20 15
30 Adjusted EBITDA $495 $380 ($20) $855 $860 Noncontrolling Interest
(45) Adjusted EBITDA Attributable to CONSOL Energy Shareholders $495 $340 ($20) $815 $815
Operations: E&P Activity Summary
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Development Plan
SWPA SWPA WV OH Q3 2017 YTD 2017 Marcellus Upper Devonian Marcellus Dry Utica TOTAL TOTAL Horizontal Rigs 1
Drilled 6
Completed
Turned In Line (TIL) 5 1 11 12 29 41
Q3 2017 Summary 2017 TD TIL TD TIL TD TIL Marcellus 14 31 10 31 4 Utica 21 23 24 26 (3) (3) Upper Devonian 2 3
CBM 63 63 63 63
35 56 34 60 1 (4) Δ New Guide Prior Guide
schedule for the end of the year shifted certain TILs into 2018
production guidance, which have both been reaffirmed
Operations: E&P Results Summary
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(3) Adjusted earnings before income tax for the E&P Division of $12.3 million for the three months ended September 30, 2017 is calculated as GAAP earnings before income tax of $20.2 million less total pre-tax adjustments of $7.9 million. The $7.9 million of adjustments are $1.5 million of pre-tax gain related to the unrealized gain on commodity derivative instruments, $11.6 million of pre-tax gains on asset sales, a pre-tax charge of $4.8 million related to stock-based compensation and a pre-tax charge of $0.4 million related to severance expense. (1) Average Sales Prices for 3Q2017, 3Q2016, and 2Q2017 include gains/(loss) on commodity derivative instruments (cash settlements) of $0.20, $0.47, and ($0.39), respectively. (2) Average Costs for 3Q2017, 3Q2016, and 2Q2017 include DD&A of $1.00, $1.05, and $0.98, respectively.
$2.33 per Mcfe in the year-earlier quarter, or a 6% improvement
per Mcfe in the year-earlier quarter, or a 6% impairment
depreciation associated with higher capital costs in the PA deep dry Utica delineation wells
primarily to an increase in capital associated with additional completions activity
3Q 2017 3Q 2016 Y/Y Change 3Q 2017 2Q 2017 Q/Q Change Average Sales Price(1) ($/Mcfe) $2.50 $2.54 ($0.04) $2.50 $2.47 $0.03 Total Production Costs(2) ($/Mcfe) $2.26 $2.36 ($0.10) $2.26 $2.20 $0.06 Sales Volumes (Bcfe) 101.0 96.4 4.6 101.0 92.2 8.8 Sales Volumes (Bcfe) by Category Marcellus 60.4 51.8 8.6 60.4 56.9 3.5 Utica 20.1 22.4 (2.3) 20.1 13.8 6.3 CBM 16.2 17.0 (0.8) 16.2 16.5 (0.3) Other 4.3 5.2 (0.9) 4.3 5.0 (0.7)
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SWPA Marcellus: Morris Field Development Update
100 200 300 400 500 600 700 10 20 30 40 50 10000' Normalized Production (MMcf/M) Months
Legacy Morris Morris-30 Current Production
Morris Production – Legacy vs. Now
(1) Legacy Morris comprised of 21 wells TIL March 2012-June 2013; Morris 30 comprised of 5 wells TIL mid-2017.
Morris Capital Efficiency – Legacy vs. Now
Morris wells(1)
stimulated reservoir design
proppant loading, min/max stress
diversion testing program is driving increased reservoir performance
going forward
200% on average from legacy PDPs to Morris-30
is being designed for future stacked pay development
Legacy Now
0.00 0.50 1.00 1.50 2.00 2.50 3.00 Capital Efficiency (Mcfe/$)
Legacy average: 0.78 Mcfe/$ MOR30 average: 2.43 Mcfe/$
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Ohio Dry Utica: SWITZ Field Development Update
50 100 150 200 250 300 350 400 450 500 5 10 15 20 25 30 MMCF/Day Well Count Online Well Count Daily Production (actuals and forecast)
2 3 4 5 5 10 15 20 25 30 Drilling Days / 1000' MD Wells Drilled
SWITZ Wells and Production FY2017 SWITZ Drilling Efficiency
production expected to continue meaningful growth through the end of 2017
total production, total operating costs are forecasted to fall due to favorable gathering rates and LOE efficiencies:
impact on EBITDA growth through 2018
rates will increase 800% over 1H2017
394 MMcf/d compared to January 2017 exit rate of 20 MMcf/d
as the field has moved to full development
between 0.80-1.42 days/1000’
cost savings for each additional well in a field
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Ohio Dry Utica: SWITZ Field Development Update (Cont’d)
1.00 1.50 2.00 2.50 3.00 Capital Efficiency (MCF/$)
100 150 200 250 300 350 400 450 500 10 20 30 40 50 7500' Normalized Production (MMCF/M) Months SWITZ 6 (2015) SWITZ 5 (2017) Current Production
SWITZ Productivity Improvements 2015-2017
new technique was TIL’ed in mid-2017 and is showing a 38% increase in EUR compared to the SWITZ 6, completed in 2015
ceramic optimization
drive accretive NAV for the asset
specific drilling and completion designs SWITZ Capital Efficiency 2015-2017
completion designs, capital efficiency (Mcfe/$)
constant while achieving a 43% increase in sand loading
SWITZ 6 average: 0.90 Mcfe/$ SWITZ 5 average: 2.37 Mcfe/$
2015 2017
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Appendix: Liquids Realizations
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Natural Gas Liquids, Oil, and Condensate
increased 34% to $20.77 per Bbl in Q3 2017 from $15.48 per Bbl in Q3 2016(1) and increased 17% from $17.81 per Bbl in Q2
2017 production volumes, 16% of E&P sales, and about 6% of total company revenue and income
Average Price Realization ($ per Bbl)(1)
(1) Excludes propane hedging impact. (2) Price at Mont Belvieu hub in Texas.
2017 2016 Q3 Q2 Q1 Q3 Q2 Q1 NGLs $19.32 $15.96 $29.16 $13.14 $12.84 $12.30 Oil $41.94 $48.18 $44.40 $42.06 $33.72 $30.84 Condensate $41.34 $34.14 $33.84 $37.26 $31.68 $14.64
$0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 Ethane $/gal
CNX Price Appalachian Gas Alternative
Q3 2017 Direct Ethane Sales Comparison
Appendix: Q3 2017 E&P Marketing Highlights
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637,000 barrels in Q3 and, on an equivalent basis, yielded a $1.52 per MMBtu premium over CONSOL’s residue natural gas alternative
average realization of $2.50 per Mcfe in Q3 2017
Natural Gas Price Reconciliation
2017 2016 Q3 Q3 NYMEX Natural Gas ($/MMBtu) $3.00 $2.81 Average Differential (0.94) (0.86) BTU Conversion (MMBtu/Mcf)* 0.12 0.11 Gain on Commodity Derivative Instruments-Cash Settlement 0.20 0.47 Realized Gas Price per Mcf $2.38 $2.53 * Conversion Factor 1.06 1.06
(1) Calculation includes the impact of gas hedging cash settlements.
Appendix: Gas Hedges (Cont’d)
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(1) Hedge positions as of 10/17/2017.
Physical Fixed Basis and Fixed Price Sales(1) Q4 2017 2017 2018 2019 2020 2021 Physical Fixed Basis Sales Volumes (Bcf) 16.8 59.1 89.4 90.8 53.1 30.4 Average Basis Prices ($/Mcf) $0.12 $0.01 $0.14 ($0.04) ($0.07) $(0.37) Physical Fixed Price Sales Volumes (Bcf) 2.3 4.9 17.2 13.1 11.9 12.7 Average Prices ($/Mcf): NYMEX portion $3.33 $3.50 $3.18 $3.01 $2.83 $2.61 Basis portion $(1.05) $(1.09) $(0.56) $(0.57) $(0.56) $(0.52) $2.28 $2.41 $2.62 $2.44 $2.27 $2.09
Hedge Position
(Outer ring = NYMEX; Inner ring = Basis)
in illiquid markets
basis fully covers the majority of 2017 and 2018 expected production
2018 2017
Appendix: 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%
Appendix: Strong Liquidity Position of ~$2 Billion
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$2.0 billion Revolving Credit Facility
(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $286 million as of 9/30/2017, $4 million of which was CNXC’s and consolidated in CNX’s financial statements per US GAAP accounting. (2) Revolving credit facility as of 9/30/2017.
September 30, 2017 ($ in millions) Amount/ Capacity Amount Drawn Letters
Amount Available Cash and Cash Equivalents(1) $282
Revolving Credit Facility(2) $2,000 $0 $314 $1,686 Total $2,282 $0 $314 $1,968 Maintenance Covenants Limit September 30, 2017 CONSOL Energy Revolver: Minimum Interest Coverage Ratio < 2.5 to 1.0 5.5 to 1.0 Minimum Current Ratio < 1.0 to 1.0 3.1 to 1.0
Non-GAAP Reconciliation: EBITDA and Adjusted EBITDA
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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) Income tax effect of Total Pre-tax Adjustments was $5,530 and $48,784 for the three months ended September 30, 2017 and September 30, 2016, respectively. Adjusted net income attributable to CONSOL Energy Shareholders for the three months ended September 30, 2017 is calculated as GAAP net loss attributable to CONSOL Energy Shareholders of $26,441 less total pre-tax adjustments from the above table of $14,943, plus the associated tax expense of $5,530 equals the adjusted net loss attributable to CONSOL Energy Shareholders of $35,854. Three Months Ended September 30, 2017 2017 2017 2017 2016 ($ in thousands) E&P Division PA Mining Operations Division Other(1) Total Company Total Company Net Income (Loss) $20,226 $21,011 ($66,888) ($25,651) $27,593 Less: Loss from Discontinued Operations
Add: Interest Expense 575 2,164 38,763 41,502 47,317 Less: Interest Income (3)
(1,306) (214) Add: Income Taxes
26,758 52,858 Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 20,798 23,175 (2,670) 41,303 162,529 Add: Depreciation, Depletion & Amortization 101,585 41,638 5,545 148,768 151,712 Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from Continuing Operations $122,383 $64,813 $2,875 $190,071 $314,241 Adjustments: Unrealized (Gain)/Loss on Commodity Derivative Instruments (1,512)
(159,555) Gain on Asset Sales (11,557)
(30,315)
348 4,563 509 5,420 229 Other Transaction Fees
6,387
2,019
4,788 5,882 798 11,468 7,771 Pension Settlement
Lease Expirations
($7,933) $2,035 ($9,045) ($14,943) ($147,904) Adjusted EBITDA from Continuing Operations $114,450 $66,848 ($6,170) $175,128 $166,337 Less: Adjusted EBITDA Attributable to Noncontrolling Interest(2)
8,812 Adjusted EBITDA Attributable to Continuing Operations $114,450 $59,783 ($6,170) $168,063 $157,525
Non-GAAP Reconciliation: TTM EBIT, EBITDA, and Adj. EBITDA
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Source: Company filings.
Three Months Ended Three Months Ended Three Months Ended Three Months Ended Twelve Months Ended Three Months Ended Twelve Months Ended September 30, December 31, March 31, June 30, June 30, September 30, September 30, ($ in thousands) 2016 2016 2017 2017 2017 2017 2017 Net Income / (Loss) $27,593 ($301,634) ($33,502) $173,823 ($133,720) ($25,651) ($186,964) Less: Loss/(Income) from Discontinued Operations 34,975 (19,564)
Add: Interest Expense 47,317 46,867 44,433 43,432 182,049 41,502 176,234 Less: Interest Income (214) (532) (1,543) (6,533) (8,822) (1,306) (9,914) Add: Tax Valuation Allowance
Add: Income Taxes 52,858 (84,990) (53,789) 66,993 (18,928) 26,758 (45,028) Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 162,529 (193,055) (44,401) 277,715 202,788 41,303 81,562 Add: Depreciation, Depletion & Amortization 151,712 156,583 148,770 117,069 574,134 148,768 571,190 Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from Continuing Operations $314,241 ($36,472) $104,369 $394,784 $776,922 $190,071 $652,752 Adjustments: Unrealized (Gain)/Loss on Commodity Derivative Instruments (159,555) 236,802 (24,640) (116,073) (63,466) (1,512) 94,577 (Gain) on Asset Sales
(126,707) (30,315) (157,022) Impairment on E&P Properties
Severance Expense 229 424 230 113 996 5,420 6,187 Pension Settlement 3,651 4,848
Noble Transaction Fees
Other Transaction Fees
8,411 13,727 6,387 20,114 Stock Based Compensation 7,771 7,658 6,702 9,975 32,106 11,468 35,803 Lease Expirations
16,861
Coal Contract Buyout
(8,410) (Gain)/Loss on Debt Extinguishment
36 (786) 2,019 1,233 Total Pre-tax Adjustments ($147,904) $253,484 $124,651 ($207,384) $22,847 ($14,943) $155,808 Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $166,337 $217,012 $229,020 $187,400 $799,769 $175,128 $808,560 Less: Adjusted EBITDA Attribuatable to Noncontrolling Interest $8,812 $10,465 $11,578 $10,302 $41,157 $7,065 $39,410 Adjusted EBITDA Attributable to Continuing Operations $157,525 $206,547 $217,442 $177,098 $758,612 $168,063 $769,150
Non-GAAP Reconciliation: Noncontrolling Interest and Net Debt
26
Source: Company filings. Three Months Ended Three Months Ended Three Months Ended Three Months Ended Twelve Months Ended Three Months Ended Twelve Months Ended September 30, December 31, March 31, June 30, June 30, September 30, September 30, ($ in thousands) 2016 2016 2017 2017 2017 2017 2017 Net Income Attributable to Noncontrolling Interest $2,248 $4,413 $5,464 $4,313 $16,438 $790 $14,980 Add: Interest Expense 1,098 1,089 1,099 1,074 4,360 1,077 4,339 Earnings Before Interest & Taxes (EBIT) Attributable to Noncontrolling Interest 3,346 5,502 6,563 5,387 20,798 1,867 19,319 Add: Depreciation, Depletion & Amortization 5,233 4,753 4,706 4,606 19,298 4,640 18,705 Earnings Before Interest, Taxes and DD&A (EBITDA) Attributable to Noncontrolling Interest $8,579 $10,255 $11,269 $9,993 $40,096 $6,507 $38,024 Adjustments: Stock Based Compensation 233 210 309 309 1,061 558 1,386 Total Pre-tax Adjustments $233 $210 $309 $309 $1,061 $558 $1,386 Adjusted EBITDA Attibutable to Noncontrolling Interest $8,812 $10,465 $11,578 $10,302 $41,157 $7,065 $39,410
Three Months Ended Three Months Ended September 30, June 30, ($ in millions) 2017 2017 CNX Total Long-Term Debt including Current Portion $2,543 $2,641 Less: Noncontrolling Interest (38.4%) in CNXC Revolver 72 72 Less: CNX Cash and Cash Equivalents 286 299 Add: CNXC Cash and Cash Equivalents 4 6 CNX Net Debt $2,189 $2,276
Non-GAAP Reconciliation: Free Cash Flow
27
Source: Company filings.
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended September 30, September 30, September 30, September 30, ($ in thousands) 2017 2016 2017 2016 Net Cash provided by Continuing Operations $178,667 $167,535 $472,838 $373,880 Capital Expenditures (177,294) (64,132) (450,620) (179,389) Net Distributions from/(Investments in) Equity Affiliates 10,920 1,023 35,620 (4,555) Organic Free Cash Flow From Continuing Operations $12,293 $104,426 $57,838 $189,936 Net Cash Provided By Operating Activities $178,328 $162,909 $472,224 $388,307 Capital Expenditures (177,294) (64,132) (450,620) (179,389) Capital Expenditures of Discontinued Operations
Net Distributions from/(Investments in) Equity Affiliates 10,920 1,023 35,620 (4,555) Proceeds from Sales of Assets 81,727 20,693 426,878 441,794 Payment on Sale of Miller Creek and Fola Complexes
Free Cash Flow $93,681 $92,233 $484,102 $609,591