Company Presentation
Q3 2016
Company Presentation Q3 2016 Cautionary Language This presentation - - PowerPoint PPT Presentation
Company Presentation Q3 2016 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). Statements
Q3 2016
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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 are included in our earnings release, and include risks, contingencies and uncertainties that relate to, among other matters, the following: we may not receive the prices we expect to receive for our natural gas and coal; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately estimate our economically recoverable natural gas, oil and condensate; we may encounter unexpected operational issues when we drill and mine, including equipment failures, geological conditions and higher than expected costs for equipment, supplies, services and labor; we may not achieve the efficiencies we expect to realize in our drilling and completion operations, and as a result, our projected cost savings may not be fully realized; our joint venture partners, who operate assets in which we have a significant interest, may not perform as we expect; we may not be able to sell non-core assets on acceptable terms; we may be unable to incur indebtedness on reasonable terms; failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its
flows; with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC - disruption to our business, including customer, employee and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating results; with respect to the proposed termination of the joint venture with Noble, risks that the conditions to closing may not be satisfied and the transaction may not occur, including our ability to obtain regulatory approvals on the proposed terms and schedule, disruption to our business, including customer and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating and financial results and liquidity 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, 2015 filed with the Securities and Exchange Commission (SEC), as updated by any subsequent quarterly reports on Form 10-Qs. The forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We may use certain terms in this presentation, such as EUR (estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these estimates may be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is customary in the gas industry, prior to the commencement of gas drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. As a result of our title review or
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.
Coal-E&P Revenue Split, 2012
E&P Revenues Coal Revenues
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December 5, 2013 – Transaction with Murray Energy Corp. in which we sold half of coal assets and related assets
April 19, 2014 – CONSOL Energy 150th Anniversary
September 25, 2014 – IPO of CONE Midstream Partners LP (NYSE: CNNX)
July 1, 2015 – IPO of CNX Coal Resources (NYSE: CNXC)
July 28, 2015 – Announced first PA Dry Utica well result in Westmoreland County
March 31, 2016 – Sold Buchanan Mine and associated met reserves
August 2, 2016 – Divested Miller Creek and Fola Complexes in Central Appalachia
September 30, 2016 – Dropped down an additional 5% interest in PA Mining Complex to CNXC for total consideration of $88.8 million
October 31, 2016 – Announced agreement to separate Marcellus Shale joint venture with Noble Energy
Coal-E&P Revenue Split, 2014
E&P Revenues Coal Revenues
Coal-E&P Revenue Split, 2015, excl. Buchanan
E&P Revenues Coal Revenues
Journey Towards Becoming a Top Tier Appalachian E&P Company Complete
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1.
Exchange agreement of jointly owned Oil & Gas properties, consisting of:
Developed properties with associated current production of
1,070 MMcfe/d, net to the JV. CNX and NBL to receive net production of ~620 and ~450 MMcfe/d, respectively
Undeveloped properties, including 75 drilled but uncompleted
locations (DUCs), and ~669,000 Marcellus Shale acres, net to the JV
CONSOL will receive a disproportionately greater value in the
property exchange, with the difference equal to ~$275 million
2.
Cash payment from NBL to CNX equal to ~$205 million
3.
Cancellation of remaining drilling “carry” obligation due from NBL to CNX equal to $1.6 billion; “carry” was only to be paid when Henry Hub natural gas price was equal to or greater than $4/MMBtu for 3 consecutive months, with an annual limit of $400 million
4.
Anticipate closing in Q4 2016; effective as of October 1, 2016 Firm Transportation (FT) and Processing Commitments:
NBL and CNX have agreed to work with the pipelines to reallocate
firm transportation to better align with the upstream assets
The targeted reallocation between CNX and NBL attempts to be
value neutral to both parties, while optimizing firm capacity to post- alignment production expectations
No material changes to previous financial FT and processing
commitments
Post-Exchange Acreage Map
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(1) The 2016E production increase is a result of 85 MMcfe/d of additional production associated with the exchange agreement, as well as continued productivity improvements. (2) 7,000' laterals x 750' spacing.
Impact on Marcellus Shale Operations
CONSOL Energy Before JV Exchange Agreement After JV Exchange Agreement 2016E Production(1) (Bcfe) 380-385 390-395 2016E Average per Unit Operating Expenses ($/Mcfe) $2.27 - $2.49 $2.27 - $2.49 Net Marcellus DUC Inventory (Wells) 37.5 53.0 Marcellus Joint Venture Assets CONSOL Interest in Total JV Assets Before Exchange Agreement JV Assets Held by CONSOL After Exchange Agreement Working Interest 50% 100% Net Undeveloped Acres 335,000 306,000 Net Future Locations(2) 2,790 2,550 Net PDPs (Wells) 258 280 Net PDP Flowing Production (MMcfe/D) 535 620
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Agreement to Separate Marcellus Shale Joint Venture
Full autonomy to develop, operate, or divest assets
Increases interest in the highest return acreage
Further strengthens the balance sheet
Top-tier Appalachian E&P company
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The exchange agreement provides CONSOL Energy the ability to drive NAV per share higher through:
Greater flexibility in our capital allocation strategy and long-term development plan
Better control and flexibility to monetize E&P assets that were previously part of the JV Pulls forward value for the JV “carry” Quicker balance sheet de-levering and improves liquidity without issuing equity
Joint Venture Separation Drives Long-Term Value Growth
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Before and After the Joint Venture Exchange Agreement with Noble Energy
(1) 7,000' laterals x 750' spacing.
JV Marcellus Footprint: Before-Exchange CNX Marcellus Footprint: Post-Exchange
9 WI (%) 50 Net Undeveloped Acres 335,000 Net Future Locations(1) (Count) 2,790 Net PDP (Wells) 258 PDP Flowing Production (MMcfe/D) 535 Marcellus Shale Before Exchange Agreement WI (%) 100 Net Undeveloped Acres 306,000 Net Future Locations(1) (Count) 2,550 Net PDP (Wells) 280 PDP Flowing Production (MMcfe/D) 620 Marcellus Shale After Exchange Agreement
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E&P Division: Q3 2016 Operations Summary
Sub- Regions Horizontal Rigs Drilled Completed Turned In Line (TIL)
Lateral Length (ft) Counties Southwest PA
1 7,206 Greene, Washington, Allegheny, PA Central PA
Westmoreland, PA Northern WV Dry
Doddridge, Lewis, WV Ohio
North Wet Gas
10,571 Greene, Washington, PA; Marshall, WV South Wet Gas
Tyler, Ritchie, WV Total 6 7 10,090 Sub- Regions Horizontal Rigs Drilled Completed Turned In Line (TIL)
Lateral Length (ft) Counties Core Wet
Surrounding Core Wet
Belmont, OH Dry Utica 2 2
Marshall, WV Westmoreland, Greene, PA Total 2 2
Utica Shale Quarterly Summary
─
Dual Fuel: D&C set up for Monroe County Utica – realized $122k in savings on GH58 completion
─
Drilling Capital Efficiencies: Reduced drilling capital by 70%
─
Plugless Completions: Currently flowing back the second plugless completion test on GH58 pad
─
Lifting Efficiencies: Lifting costs further declined to $0.234/mcfe for 3Q16, which yielded an ~$1.05 million reduction from 2Q16
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Utica Production Capital Efficiencies: Monroe County facility design and installation costs reduced from ~$900k/well on the 1st pad to ~$535k/well on the 2nd pad (~41% reduction)
─
Marcellus Production Optimization: Tubing installs, plunger lift systems, and soap injection - Implementation yielded a total uplift
days
─
Production Control Room Efficiency: Average downtime per incident was reduced in our SWPA District by ~20% which resulted in an increased production of ~2.1mmcf/d
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Operational Efficiency: Electric Demand Response Audit – completed the 1 hour test which generated ~$812k in annual savings
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2016 Activity Overview and 2017 Drilled and Uncompleted Opportunity Set
E&P Activity Summary – 2016 Plan
Note: Plan as of 9/30/2016.
Expected New Wells Drilled in H2 2016 Drilled Uncompleted Inventory Drilled Completed Inventory 2016 TIL's Remaining Implied 2017 Inventory 2016 Completions Remaining Marcellus SW PA Operated
8 6 14
8 6 55
SW PA Operated
9 1
9 6
Wells 9 59 8 6 70
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Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth
Deferring activity, increasing capital efficiency
improvements and identification of additional de-bottlenecking activities
2016 E&P capital budget of $190-$205 million
activity
$22 million associated with CONE Midstream capital contributions)
development): $17-$22 million
2016 E&P Capital Budget: $190-$205 Million
D&C 72% Midstream 18% Other 10%
$0.23 $0.38 $0.24 $0.16 $1.10 $1.02 $1.04 $0.93 $0.17 $0.17 $0.09 $0.09 $0.84 $0.59 $0.37 $0.26 $1.17 $1.11 $0.82 $0.48 $3.51 $3.27 $2.56 $1.92 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2013 2014 2015 2016E² SG&A¹ Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE
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Full-cycle Breakeven Operating Metrics Declined from $3.51 to $1.92 per Mcfe, a 45% Projected Decline
Cash OpEx (plus SG&A) of $1.28/Mcfe, plus PUD-to- PDP CapEx of $0.48/Mcfe, equals total full cycle cash costs of $1.92/Mcfe
As of YE 2015 A B C D E F G
CNX E&P Per Unit Future PUD F&D ($/Mcfe) $0.60 $0.75 $0.91 $0.41 $0.48 $0.69 $1.33 $0.79 $0.48
(1) SG&A does not include short-term or long-term incentive compensation (2) 2016E reflects midpoint of guidance range. Numbers may differ slightly due to rounding. Source: Company filings and presentations. Peers include AR, COG, EQT, GPOR, RICE, RRC and SWN.
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Realized ~60+% Reduction in Days to Drill
Expect Additional ~16% Reduction
Met previously stated goal of drilling a Monroe County Dry Utica well in 26 days
Improvement of 76% over the first well drilled and a 38% improvement over last well drilled in 2015
New goal of 20 days to drill Monroe County Dry Utica wells
0.0 5,000.0 10,000.0 15,000.0 20,000.0 25,000.0 0.00 20.00 40.00 60.00 80.00 100.00 120.00 Depth (ft.) Days
Days vs. Depth
(Wells in order of Horizontal TD Date)
SWITZ6B SWITZ6D SWITZ6F SWITZ6H SWITZ16J SWITZ16D SWITZ5J SWITZ16B
Utica Shale: Days vs. Depth
(Wells in order of Horizontal TD Date)
$1,740 $1,810 $1,380 $1,340 $1,150 $1,060 $1,040 $1,040 $950
$800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000
Switz 6B Switz 6D Switz 6H Switz 6F Switz 16J Switz 16D Q2 Switz 16D Act Switz 5J Switz 16B
Drilling Cost ($/lateral ft)
(Wells in order of Tophole TD) 15
Expected cost from Q2 Actual costs
Improvement of 26% in drilling costs over first 3 wells drilled and a 39% improvement over last well drilled in 2015
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CONSOL basin exports are projected to
increase approximately 73,000 Dth/day for FY 2016 over FY 2015 as TETCO’s U2GC and TEAM OPEN projects were put into service in late 2015, increasing expected realizations by marketing gas to the higher priced Midwest and Gulf Coast markets.
Directly-marketed ethane volumes were
612,000 barrels in Q3 -- an increase of 132% from Q2 and, on an equivalent basis, yielded a premium price over the Texas Eastern M2 gas market.
─ An additional ethane contract with
favorable terms commenced October 1, 2016.
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Q3 2016 Gas Realization and Marketing Highlights
2016 2015 Q3 Q2 Q1 Q3 NYMEX Natural Gas ($/MMBtu) 2.81 $ 1.95 $ 2.09 $ 2.77 $ Average Differential (0.86) (0.46) (0.36) (1.00) BTU Conversion (MMBtu/Mcf)* 0.11 0.09 0.10 0.09 Gain on Commodity Derivative Instruments-Cash Settlements 0.47 0.91 0.98 0.60 Realized Gas Price per Mcf 2.53 $ 2.49 $ 2.81 $ 2.46 $ *Conversion Factor 1.06 1.06 1.06 1.05
Q3 2016 Natural Gas Price Reconciliation
In addition to the upstream deal, CNX and NBL have agreed to work with the pipelines to reallocate firm transportation to better align with the upstream assets
The targeted reallocation attempts to be value neutral to both parties, while
post-alignment production expectations
Remains subject to FERC and pipeline approvals
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Firm Transportation
$0.24 $0.25 $0.29 $0.30 $0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 2016 2017 2018 2019
Expected Avg. Demand per MMBtu: 2016E-2019E After Reallocation Expected Firm Capacity by Pipeline After FT Reallocation
Charts also include transportation under precedent agreements
Pipeline YE 2016 YE 2018 ANR Pipeline 47 47 Columbia (TCO) 212 562 Dominion (DTI) 345 317 East Tennessee 282 202 Nexus
TETCO 174 174 TETCO (via firm sales) 285 125
(1000s MMBtu/day)
1,345 1,542
Expected FT Capacities After Reallocation
TETCO
TETCO (via firm sales)
Dominion East Tennessee Columbia ANR NEXUS 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Jan 16 Jan 17 Jan 18 Jan 19 1000s MMBtu/day
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Natural Gas Sales: Expected Market Mix
MIDWEST TETCO M3 TETCO M2 EAST TENNESEE TETCO ELA TETCO WLA TCO POOL DOMINION SOUTH Gas Sales 2016E 2017E Columbia (TCO) 17% 17% TETCO (M2) 29% 28% TETCO (M3) 16% 15% Dominion (DTI) 15% 15% East Tennessee 10% 10% TETCO ELA & WLA 8% 8% Midwest (Chicago) 5% 7% 100% 100%
100 200 300 400 500 600 Jan 16 Jan 17 Jan 18 Jan 19 MMcf/day MVC
CNX and NBL have also agreed to work with processing counterparties to realign processing capacity with the upstream assets
After the swap of capacity, CNX’s volume of firm processing capacity and minimum volume commitment will be roughly unchanged
CNX will retain the flexibility to bypass processing with certain “damp” gas to continue facilitating
No NGL sales commitments were impacted by the NBL transaction
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Natural Gas Processing and NGLs
Note: CONSOL Energy had processing capacity expansion rights of 110,000 Mcf/d.
CNX Expected Contracted Processing Capacity
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Ethane 64% Propane 22% I-Butane 3% N-Butane 6% Natural gasoline 5% Maximum Ethane Recovery* Potential Scenario
* Assumes 85% ethane recovery level
Ethane 36% Propane 37% I-Butane 5% N-Butane 11% Natural gasoline 11% 3Q16 Est NGL Sales Comp
Natural Gas Liquids, Oil, and Condensate
Q3 2016 Avg. “NGL Barrel” Composition
Q3 2016 liquids sold: 13.6 Bcfe, up 29% from Q2 2016
Total weighted average price of all liquids decreased 1.6% to $15.48 per Bbl in Q3 2016 from $15.73 per Bbl in Q2 2016. Excluding ethane, average sales price was up 8.8% from Q2.
Directly-marketed ethane volumes were 612,000 barrels in Q3 -- an increase of 132% from Q2 and, on an equivalent basis, yielded a premium price over the Texas Eastern M2 gas market
Liquids comprised approximately 14% of Q3 2016 production volumes, 14% of E&P sales revenue and 5%
17.5 million gallons of propane hedged from April of 2016 through March of 2017 at an average price of $0.48 per gallon
Average Price Realization (per Bbl) 2016 2015 Q3 Q2 Q1 Q3 Q2 Q1 NGLs 13.14 $ 12.84 $ 12.30 $ 4.80 $ 12.48 $ 20.40 $ Oil 42.06 33.72 30.84 54.18 46.14 47.82 Condensate 37.26 31.68 14.64 27.84 31.26 20.82
22 (1) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements. (2) At the midpoint of production guidance of 390-395 Bcfe. (3) Hedge positions as of 10/13/2016. FY 2016 includes actual settlements of 225.3 Bcf.
Gas Hedges
E&P Hedge Program:
monitored hedges
─ Program Hedge - protect
margins on up to 90% of
Production
─ Active Hedge Process -
supplements program hedges up to 80% of our total production including proved undeveloped production
172 Bcf of basis hedges through 2020, further protecting downside
FY 2016E production volumes hedged2
CNX Gas Volumes Hedged 2016-2020 Hedge Volume and Pricing 2016-2020 Q4 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 NYMEX + Basis¹ Volumes (Bcf) 61.8 264.5 207.5 151.6 75.2 40.5 Average Prices ($/Mcf) 3.16 $ 3.03 $ 2.61 $ 2.64 $ 2.53 $ 2.77 $ NYMEX Only Hedges Exposed to Basis Volumes (Bcf) 1.8
11.8 25.2 2.6 Average Prices ($/Mcf) 3.41 $
3.02 $ 3.10 $ 3.04 $ 3.18 $ Physical Sales With Fixed Basis Exposed to NYMEX Volumes (Bcf)
(0.06) $
Total Volumes Hedged (Bcf)3 63.6 271.8 237.8 163.4 100.4 43.1 50 100 150 200 250 300 Q4 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 Gas Volumes Hedged (Bcf)
Physical Sales With Fixed Basis Exposed to NYMEX NYMEX Only Hedges Exposed to Basis NYMEX + Basis¹
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Net earnings attributable to continuing operations(1) in the 2016 third quarter of $62.6 million, or $0.26 per diluted share
Adjusted net loss attributable to continuing operations(1) in the 2016 third quarter of $35.5 million, or ($0.15) per diluted share
Q3 2016 production of 96.4 Bcfe, up approximately 10.3 Bcfe from Q3 2015, a 12% increase
Production volumes expected to grow to approximately 390-395 Bcfe in 2016
(1) Q3 2016 net income includes a net loss of ($35) million from discontinued operations, net of tax. Note: The terms "adjusted net loss attributable to continuing operations," "adjusted EBITDA," “adjusted EBITDA attributable to continuing operations,” "free cash flow," and "organic free cash flow from continuing operations" are non-GAAP financial measures, which are defined and reconciled to GAAP net (loss)/income and net cash provided by continuing
Third Quarter 2016 Results
Q3 2016 Summary Y/Y Q-to-Q
($ in millions, except per share data) 3Q2016 3Q2015 Change 3Q2016 2Q2016 Change Net Income (Loss) Attributable to CNX Shareholders $25 $119 ($94) $25 ($470) $495 Earnings (Loss) per Diluted Share $0.11 $0.52 ($0.41) $0.11 ($2.05) $2.16 Revenue and Other Income $746 $721 $25 $746 $286 $460 Net Cash Provided by Continuing Operations $166 $147 $19 $166 $82 $84 Adjusted EBITDA Attributable to Continuing Operations $156 $146 $10 $156 $135 $21
(1) (1)
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Generated positive free cash flow
FCF of $188 million
Reduced outstanding borrowings on the revolving credit facility by approximately $112 million, which increased liquidity and de-levered the balance sheet
Total capital expenditures in Q3 2016 of $64 million: First nine months 2016 total capital expenditures of $179 million
Source: Company filings. Note: Numbers may not sum and may differ slightly from totals and financial statements due to rounding.
Net (Decrease)/Increase in Cash
Q3 2016 Cash Flow Summary (including Discontinued Operations) Y/Y Q-to-Q
($ in millions) 3Q2016 3Q2015 Change 3Q2016 2Q2016 Change Net Cash Provided by Operating Activities $163 $110 $53 $163 $95 $68 Capital Expenditures ($64) ($248) $184 ($64) ($38) ($26) Proceeds From Asset Sales $21 $76 ($55) $21 $10 $11 Other Investing ($27) ($38) $11 ($27) ($1) ($26) (Payments on)/Proceeds From Short-Term Debt & Misc. Borrowings ($114) ($110) ($4) ($114) ($388) $274 Dividends Paid
$2
4 $285 ($281) $4 ($7) $11 Net (Decrease) / Increase in Cash ($17) $73 ($90) ($17) ($329) $312
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E&P Division: Results Summary
(1) Average Sales Prices for 3Q2016, 3Q2015 and 2Q2016 include gains on commodity derivative instruments (cash settlements) of $0.47, $0.60 and $0.91, respectively. (2) Average Costs for 3Q2016, 3Q2015 and 2Q2016 include DD&A of $1.05, $1.05 and $1.04, respectively.
Adjusted earnings before income tax for E&P Division of $1.7 million(1)
Production increased by 12% in third quarter 2016, compared to year-earlier quarter
Marcellus Shale all-in unit costs were $2.33 per Mcfe in the third quarter, a decrease of $0.13 from $2.46 per Mcfe in the year-earlier quarter, or a 5% improvement
Utica Shale all-in unit costs were $1.81 per Mcfe in the third quarter, a decrease of $0.29 from $2.10 per Mcfe in the year-earlier quarter, or a 14% improvement
CBM all-in unit costs were $2.84 per Mcfe in the third quarter, an increase of $0.04 from $2.80 per Mcfe in the year-earlier quarter, or a 1% increase
Other Gas all-in unit costs were $3.37 per Mcfe in the third quarter, a decrease of $0.02 from $3.39 per Mcfe in the year-earlier quarter
(1) Adjusted earnings before income tax for the E&P Division of $1.6 million for the three months ended September 30, 2016 is calculated as GAAP earnings before income tax of $161.1 million less total pre-tax adjustments of $159.5 million. The $159.5 million adjustment is the $159.6 million pre-tax gain related to the unrealized gain on commodity derivative instruments and a pre-tax loss of $0.1 million related to severance expense.
Y/Y Q-to-Q
E&P Division 3Q2016 3Q2015 Change 3Q2016 2Q2016 Change Average Sales Price(1) ($ / Mcfe) $2.54 $2.35 $0.19 $2.54 $2.50 $0.04 Average Costs(2) ($ / Mcfe) $2.36 $2.54 ($0.18) $2.36 $2.27 $0.09 Sales Volumes (Bcfe) 96.4 86.1 10.3 96.4 99.3 (2.9) Sales Volumes (Bcfe) by Category Marcellus 51.8 45.9 5.9 51.8 53.1 (1.3) Utica 22.5 15.3 7.2 22.5 23.3 (0.8) CBM 17.0 18.5 (1.5) 17.0 17.1 (0.1) Other 5.1 6.4 (1.3) 5.1 5.8 (0.7)
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$2.0 billion Revolving Credit Facility:
5 year credit facility expires June 2019
Paid down approximately $600 million of revolving debt on the credit facility year-to-date
Gas reserves based lending facility: fall redetermination process expected to be completed in November
Includes the right to separate the coal and gas business subject to a leverage test
Strong Liquidity Position of ~$1.4 Billion
(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $80 million as of 9/30/2016, $6 million of which was CNXC’s and consolidated in CNX’s financial statements per US GAAP accounting. (2) Revolving credit facility as of 9/30/2016.
Maintenance Covenants Limit 2016 CONSOL Energy Revolver: Minimum Interest Coverage Ratio < 2.5 to 1.0 4.0 to 1.0 Minimum Current Ratio < 1.0 to 1.0 2.7 to 1.0
Amount/ Amount Letters Amount September 30, 2016 ($ in million) Capacity Drawn
Available Cash and Cash Equivalents(1) $74
Revolving Credit Facility(2) $2,000 $354 $324 $1,322 Total $2,074 $354 $324 $1,396
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Debt and Liquidity Profile
Note: Some numbers may not match exactly to financial statements due to rounding. (1) The 2022 and 2023 senior notes includes $5 million and $6 million of unamortized bond premium / discount, which will be amortized over the life of the notes, respectively. (2) Total Debt of $3.151 billion excludes total unamortized debt issuance costs of $29 million. (3) Net Debt equals Total Debt less Cash and Cash Equivalents. (4) As of 9/30/2016, CNX had approximately $354 million of borrowings and $324 million of outstanding letters of credit under its revolving credit facility, leaving approximately $1,322 million of
(5) Number of MLP units owned by CNX as of 9/30/2016 and unit prices as of market close on 10/21/2016. (6) CNX Coal Resources liquidity data is as of 9/30/2016 and CONE Midstream data is as of 6/30/2016. (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 $680 million less a loss on sale of assets of $6 million, plus gain related to changes in retiree medical (OPEB) plan of $110 million, less the $50 million of CNXC EBITDA net of cash distributions attributable to CNX, less $3 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 equals debt of $3.151 billion, less $74 million cash on hand excluding CNXC’s cash, less $208 million of CNXC revolver debt, less $3 million of advance mining royalties, plus $240 million of net letters of credit related to firm transportation obligations, mining equipment leases, and insurance policies.
CNX Consolidated CNXC: 100% CNX Attributable Capitalization and Liquidity 9/30/2016 9/30/2016 9/30/2016 Capitalization Cash and Cash Equivalents $80 $6 $74 Revolving Credit Facility Balance 562 208 354 Capital Lease Obligations 37
Total Secured Debt $599 $208 $391 8.25% Senior Notes due 2020 $74
6.375% Senior Notes due 2021 21
5.875% Senior Notes due 2022 (1) 1,855
8.0% Senior Notes due 2023 (1) 494
Baltimore 5.75% Revenue Bonds due 2025 103
Miscellaneous Debt 5
Total Debt (2) $3,151 $208 $2,943 Net Debt (3) $3,071 $202 $2,869 Stockholders’ Equity $4,290 $143 $4,147 Total Capitalization $7,441 $351 $7,090 Liquidity Cash and Cash Equivalents $80 $6 $74 Revolving Credit Facility Capacity (4) 1,514 192 1,322 Total Liquidity $1,594 $198 $1,396
Equity Value of Ownership in Affiliated Public MLPs CNX Owned LP Units(5) Unit Price(5) Market Value CNX Coal Resources LP (CNXC:NYSE) 16.6 $17.50 $291 CONE Midstream Partners LP (CNNX:NYSE) 19.1 $20.80 $397 Total Equity Value of Ownership Interests in Affiliated Public MLPs $688 Liquidity of Affiliated MLPs Total Facility Capacity Outstanding Balance Available Capacity Cash Total Liquidity of Affiliates CNX Coal Resources LP (6) $400 $208 $192 $6 $198 CONE Midstream Partners LP (6) $250 $47 $203 $5 $208 Total Liquidity of Affiliated Public MLPs $650 $255 $395 $11 $406 Leverage Ratio 9/30/2016 LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7) $731 LTM Bank Net Debt / Adj. EBITDA (7) 4.3x
$4,345 $1,902 $1,694 $1,542 $1,385 $1,374 $370 $148 $153 $137 $100 $100 $0 $50 $100 $150 $200 $250 $300 $350 $400 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 FY 2012 FY 2013 FY 2014 FY 2015 Q3 2016 FY 2016E
Annual Cash Servicing Costs ($ in Millions) Legacy Liabilities ($ in millions)
Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost As of Period End: 12/31/2012 12/31/2013 12/31/2014 12/31/2015 9/30/2016 12/31/2016E Legacy Liabilities ($MM) LTD $39 $20 $22 $20 $18 $17 WC 180 85 90 83 82 82 CWP 184 121 126 123 126 125 OPEB 3,018 1,022 761 672 655 655 Salary Retirement/Pension 225 53 119 94 92 89 Asset Retirement Obligations 699 601 576 550 412 406 Total Legacy Liabilities $4,345 $1,902 $1,694 $1,542 $1,385 $1,374 FY 2012 FY 2013 FY 2014 FY 2015 Q3 2016 FY 2016E Total Annual Legacy Liabilities Cash Servicing Cost $370 $148 $153 $137 $100 $100
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Significant Legacy Liability Reductions Over Past 3 Years
Flows through P&L in operating costs (impact reflected in operating cost guidance) Flows through P&L within DD&A Flows through Other Segment in “Miscellaneous Operating Expense”
Projected $100MM Annual Cash Servicing Cost for FY 2016, a $37MM reduction from the year- end 2015 run-rate of $137MM
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Organizational Structure and CNX Ownership
In July 2015 IPO, sold 10.6 million LP units, or 44.6%, raising approximately $158 million in gross proceeds; CNXC also distributed $197 million in cash to CONSOL related to the revolver drawdown
In September 2016, CNXC acquired an additional 5% undivided interest in the PA Mining Complex for total consideration of $88.8 million ($21.5 million in cash and preferred units valued at $67.3 million) implying total complex value of $1.8 billion
CONSOL Energy retains a 75% undivided interest in the Pennsylvania mining complex and owns 100% of CNXC’s general partner, as well as the incentive distribution rights CNXC owns a 25% undivided interest(1) in, and
mining complex (Bailey, Enlow Fork and Harvey mines)
(1) Unless otherwise specified, all figures relating to reserves and production of the Pennsylvania mining complex in this presentation are on a 100% basis.
75% undivided
CNX Coal Resources LP NYSE: CNXC CNX Coal Resources GP LLC Pennsylvania Mining Complex 100% ownership interest 60% limited partner interest 2% general partner interest and IDRs 25% undivided
management and control rights limited partner interest CONSOL Energy Inc. ("CONSOL Energy") NYSE: CNX Public Greenlight Capital
(in millions except for per unit amounts)
Total LP Units held by CONSOL Energy 16.6 Unit Price (as of close on 10.21.2016) $17.50 CNXC Units Equity Value to CONSOL Energy $290.8 CONSOL Energy's Ownership Interest in CNX Coal Resources LP (CNXC:NYSE)
CONSOL owns 32.1% of CONE Midstream Partners LP’s
(NYSE: CNNX) LP units and 50% of the General Partner (“GP”), which has a 2% interest in CNNX (and rights to IDRs)
CNNX owns interests in 3 development companies The remaining un-dropped portion of the development
companies’ interests are held by CONE Gathering LLC (“CGLLC”), a privately held Joint Venture between CONSOL Energy (NYSE: CNX) and Noble Energy (NYSE: NBL)
CNX’s share of CONE Midstream’s Net Income (CNNX &
CGLLC) flows into the E&P segment’s “Equity in Earnings of Affiliates,” which in CNX’s consolidated financial statements falls within the “Miscellaneous Other Income” line item
Distributions run straight through CNX’s cash flow statement in
the “Return on Equity Investment” line item
CNX has seen increasing benefit from CONE’s EBITDA and
cash distributions, on top of which CNNX recently increased its cash distribution 3.7% from 2Q16
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Note: For a reconciliation of CONE’s EBITDA please see the CNNX’s form 10Q’s and 10K’s. Source: CONE Midstream Partners LP and CONSOL Energy Inc.
CNNX: CNX Ownership and Cash Contribution
$10 $15 $29 $44 $57 $0 $10 $20 $30 $40 $50 $60 FY 2012 FY 2013 FY 2014 FY 2015 3Q16 Annualized
CONE Midstream's and Gathering's Pro Rata Net Income Contribution to CNX
CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's Net Income $10 $15 $34 $50 $62 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 FY 2012 FY 2013 FY 2014 FY 2015 3Q16 Annualized
CONE Midstream's and Gathering's Pro Rata EBITDA Contribution to CNX
CNX Pro Rata Share of CONE Midstream Partners LP's Cash Distributions CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's EBITDA $68 $82 $18 $20 (in millions except for per unit amounts)
Total LP Units held by CONSOL Energy 19.1 Unit Price (as of close on 10.21.2016) $20.80 CNNX Units Equity Value to CONSOL Energy $397.3 CONSOL Energy's Ownership Interest in CONE Midstream Partners LP (CNNX:NYSE)
($ in millions) ($ in millions)
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Note: Guidance as of 11/1/2016. (1) Represents estimated unutilized firm transportation and processing expense less estimated gathering revenue (resold firm transportation).
E&P Segment Guidance 2016E Production Volumes: Natural Gas (Bcf) 346 - 349 NGLs (MBbls) 6,500 - 6,750 Oil (MBbls) 62 - 68 Condensate (MBbls) 800 - 850 Total Production (Bcfe) 390 - 395 Natural Gas Basis Differential to NYMEX ($Mcf) ($0.65) - ($0.75) NGL Realized Prices ($Bbl) $13.00 - $15.00 Condensate Realized Prices % of WTI 65% - 70% Oil Realized Prices % of WTI 85% - 90% Capital Expenditures ($ in millions): Drilling and Completion $160 - $165 Midstream $25 - $30 Land and Other $5 - $10 Total E&P and Midstream CapEx $190 - $205 Average per unit operating expenses ($/Mcfe): Lifting (including Direct Admin.) $0.24 - $0.28 Impact Fees/Ad Valorem/Production Taxes $0.08 - $0.10 Gathering, Transportation, Compression & Processing $0.91 - $0.95 Depreciation, Depletion and Amortization $1.04 - $1.07 Total Production and Gathering Cost $2.27 - $2.40 Other Expenses ($ in millions): Selling, General and Administrative Costs $58 - $62 Unutilized Firm Transportation Expense, net:(1) $15 - $16
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Note: Guidance as of 11/1/2016. CONSOL Energy is unable to provide a reconciliation of projected CNXC Adjusted EBITDA, CONSOL's Other Coal Division EBITDA, and CONSOL's Other Miscellaneous Coal 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 estimated contribution from Miller Creek and Other Coal Operations for fiscal year 2016 and 1Q16 for Buchanan, and excludes Loss on Sale of Buchanan and the Loss on Sale for the Miller Creek and Fola mines. (2) Includes miscellaneous other income (net of applicable expenses) associated with the company's Terminal Operations, Rental Income, Water Operations, Coal Royalty Income, and other miscellaneous land income. (3) Includes Legacy Liability Costs of approximately $80-85 million; Other Coal-Related Corporate Expenses, and other miscellaneous items. Excludes stock-based compensation and pension settlement charges.
Coal Segment Guidance 2016E Estimated Total PA Mining Operations Sales Volumes (in millions of tons) 23.6 - 24.4 Sales Volumes Attributed to Discontinued Operations (in millions of tons) 2.1 % PA Mining Operations Tonnage Sold 100% Total Consolidated Coal Segment Capital Expenditures ($ in millions): Production $60 - $76 Other (Land/Water/Safety/Terminal) $15 - $24 Total Coal Capital Expenditures $75 - $100 Adjusted EBITDA Guidance CNXC EBITDA $74 - $82 4x 100% PA Mining Operations Operating EBITDA $296 - $328 Less: Noncontrolling Interest ($26) - ($30) Plus: Other Coal Operating EBITDA(1) $15 - $16 Plus: Other Coal Misc. EBITDA(2) $24 - $30 Less: Misc. Other Expenses (including Legacy Liabilities' Cash Costs)(3) ($104) - ($109) CNX Pro Rata Coal and Other Segment Adjusted EBITDA $205 - $235
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cycle times, and service cost deflation
the 5th consecutive increase since July 2015
stacked pay opportunities
consistent with the metrics used in the short and long term incentive programs for 2016 Plans and Goals Aligned to Drive Increased Valuation
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Non-GAAP Reconciliation: EBITDA and Adj. EBITDA
Source: Company filings. Note: Income tax effect of Total Pre-tax Adjustments was ($57,599) and ($54,680) for the three months ended September 30, 2016 and September 30, 2015, respectively. Adjusted net income attributable to CONSOL Energy shareholders for the three months ended September 30, 2016 is calculated as GAAP net income from continuing operations of $62,568 less total pre-tax adjustments of $155,675, plus the tax expense of $57,599, equals the adjusted net loss from continuing operations of $35,508. (1) CONSOL Energy's Other Division includes expenses from various other corporate and diversified business unit activities including legacy liabilities costs and income tax expense that are not allocated to E&P or PA Mining Operations Divisions.
Three Months Ended September 30, 2016 2016 2016 2016 2015 ($ in thousands) E&P Division PA Mining Operations Division Other1 Total Company Total Company Net Income/(Loss) $161,075 $34,741 ($168,223) $27,593 $125,470 Less: Loss from Discontinued Operations
34,975 3,842 Add: Interest Expense 669 2,309 44,339 47,317 48,558 Less: Interest Income
(214) (361) Add: Income Taxes Benefit
52,858 65,868 Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 161,744 37,050 (36,265) 162,529 243,377 Add: Depreciation, Depletion & Amortization 101,257 42,370 8,085 151,712 146,844 Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from Continuing Operations $263,001 $79,420 ($28,180) $314,241 $390,221 Adjustments: Unrealized Gain on Commodity Derivative Instruments (159,555)
(99,138) Severance Expense 129 14 86 229 7,683 Pension Settlement
3,651 3,132 Gain on Sale of Western Allegheny
OPEB Plan Changes
Total Pre-tax Adjustments ($159,426) $14 $3,737 ($155,675) ($237,738) Adjusted EBITDA $103,575 $79,434 ($24,443) $158,566 $152,483 Less: Noncontrolling Interest
(6,490) Adjusted EBITDA Attributable to Continuing Operations $103,575 $77,186 ($24,443) $156,318 $145,993
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Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA
Source: Company filings. Three Months Ended Three Months Ended Three Months Ended Three Months Ended Twelve Months Ended December 31, March 31, June 30, September 30, September 30, ($ in thousands) 2015 2016 2016 2016 2016 Net Income / (Loss) $34,326 ($96,458) ($468,649) $27,593 ($503,188) Less: Income from Discontinued Operations 11,017 53,167 234,605 34,975 333,764 Add: Interest Expense 49,081 49,865 47,427 47,317 193,690 Less: Interest Income (431) (214) (547) (214) (1,406) Add: Income Taxes 125,742 (23,800) (100,856) 52,858 53,944 Earnings Before Interest & Taxes (EBIT) from Continuing Operations 219,735 (17,440) (288,020) 162,529 76,804 Add: Depreciation, Depletion & Amortization 139,988 154,988 135,220 151,712 581,908 Earnings Before Interest, Taxes and DD&A (EBITDA) from Continuing Operations $359,723 $137,548 ($152,800) $314,241 $658,712 Adjustments: OPEB Plan Changes (109,879)
Unrealized (Gain)/Loss on Commodity Derivative Instruments (62,388) 29,271 279,715 (159,555) 87,043 Pension Settlement 15,921
3,651 33,268 Industrial Supplies Working Capital Settlement 6,258
Gain on Sale of Non-core Assets (7,551) 13,735
Severance Expense
1,451 229 4,598 Coal Contract Buyout
Total Pre-tax Adjustments ($157,639) $45,924 $288,574 ($155,675) $21,184 Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $202,084 $183,472 $135,774 $158,566 $679,896 Less: Noncontrolling Interest ($3,920) ($1,114) ($1,179) ($2,248) ($8,461) Adjusted EBITDA Attributable to Continuing Operations $198,164 $182,358 $134,595 $156,318 $671,435
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Free Cash Flow Reconciliation
Source: Company filings.
Three Months Ended Nine Months Ended September 30, September 30, ($ in thousands) 2016 2016 Net Cash provided by Continuing Operations 166,064 $ 372,211 $ Capital Expenditures (64,132) (179,389) Net Investment in Equity Affiliates 1,023 (4,555) Organic Free Cash Flow From Continuing Operations 102,955 $ 188,267 $ Net Cash Provided By Operating Activities 162,897 $ 386,638 $ Capital Expenditures (64,132) (179,389) Capital Expenditures of Discontinued Operations 11 (8,284) Net Investment in Equity Affiliates 1,023 (4,555) Proceeds From Sales of Assets 20,693 38,977 Payments on Sale of Miller Creek and Fola Complexes (28,271) (28,271) Proceeds From Sales of Buchanan Mine
Total Free Cash Flow 92,221 $ 607,922 $