Slide 1: Company Presentation Q2 2014
Company Presentation Q2 2014
Slide 2: Cautionary Language
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 that are not historical, are forward-looking, and include our operational and strategic
Slide 3: Summary of Updates Since June 12th Analyst Day
Summary of Updates Since June 12th Analyst Day Company Overview Gas Marketing - Slides 10-18: New additions for Q2 2014 earnings - Slide 113 and 114: Updated firm transportation results and firm sales portfolio/capacity - Slide 117 and 119: Updated to reflect more E&P Division current basis di
Slide 4: Agenda
Agenda Company Overview E&P Division ─ Marcellus Shale ─ Utica Shale ─ Upper Devonian ─ Stacked Pay Potential ─ Other Gas Reserves and Resources ─ Gas Marketing Coal Division Monetization of Non-Core Assets Financial Overview Appendix 4
Slide 5: Transformative Journey
Company Overview Transformative Journey Ten years ago – traditional coal producer, the largest underground producer in the world Eight years ago – created CNX Gas Four years ago – acquired Dominion Resources’ Appalachian E&P business and became a coal company with a growing natural gas busines
Slide 6: CONSOL Energy Core Values
Company Overview CONSOL Energy Core Values Unwavering focus on Core Values of safety, compliance, and continuous improvement 6
Slide 7: Strategic Evolution
Company Overview Strategic Evolution CONSOL’s E&P Division represents the greatest portion of EBITDA Natural gas is the de facto choice for new MWh demand as well as for backfilling market share ceded by nuclear and coal, which is a bullish indicator for natural gas Capitalized, low cost coal
Slide 8: Oil and Gas Acreage Ownership
Company Overview Oil and Gas Acreage Ownership CONSOL % of Legacy Ownership by State and Horizon State Marcellus Utica Burkett Rhinestreet PA 50% 100% 50% 100% WV 50% 100% 50% 100% OH 100% 50% 100% 100% Note: CONSOL’s percentage of ownership is per the original 2011 JV agreements. Noble and Hess wil
Slide 9: Summary
Company Overview Summary We have tier-one assets across our entire Appalachian-centric portfolio, in both E&P and Coal: - Sweet spots in both the wet and dry portions of the Marcellus and Utica shales - Multiple stack pay opportunities - In thermal coal, one of the highest Btu coals in the U.S. in
Slide 10: Second Quarter 2014 Results
Company Overview Second Quarter 2014 Results Net loss for the second quarter was ($25) million - Includes four pre-tax items related to recent transactions completed by the company: $74.3 million expense related to early extinguishment of debt $3.0 million non-cash charge associated with enter
Slide 11: E&P Division: Summary
Company Overview E&P Division: Summary Q-to-Q Q-to-Q E&P Division 2Q2014 2Q2013 Change 2Q2014 1Q2014 Change Average Sales Price ($ / Mcfe) $4.44 $4.46 ($0.02) $4.44 $5.52 ($1.08) Average Costs ($ / Mcfe) $3.44 $3.77 ($0.33) $3.44 $3.63 ($0.19) Sales Volumes (Bcfe) 51.9 38.6 13.3 51.9 48.4 3.5 Sales
Slide 12: Coal Division: Summary
Company Overview Coal Division: Summary Q-to-Q Q-to-Q Coal Division 2Q2014 2Q2013 Change 2Q2014 1Q2014 Change Average Sales Price ($ / ton) $62.43 $69.93 ($7.50) $62.43 $66.20 ($3.77) Average Costs ($ / ton) $47.63 $51.24 ($3.61) $47.63 $45.15 $2.48 Coal Production (millions of tons) 8.3 7.1 1.2 8.3
Slide 13: CONSOL Cost Metrics
Company Overview CONSOL Cost Metrics Gas: Operating Costs per Mcfe $6 $5 $ / Mcfe $4 $3 $2 1Q2012 2Q2012 3Q2012 4Q2012 1Q2013 2Q2013 3Q2013 4Q2013 1Q2014 2Q2014 CBM Marcellus Shallow Oil & Gas Coal: Cost per Ton Sold $86 $76 $ / Ton $66 $56 $46 $36 1Q2012 2Q2012 3Q2012 4Q2012 1Q2013 2Q2013 3Q2013 4Q
Slide 14: Strong Liquidity Position of $1.9 Billion
Company Overview Strong Liquidity Position of $1.9 Billion Cash on hand of $147 million Accounts receivable securitization and revolving credit facility of $1.8 billion Amount/ Amount Letters Amount June 30, 2014 ($ in million) Capacity Drawn of Credit Available Cash and Cash Equivalents $147 $0
Slide 15: Net (Decrease)/Increase in Cash
Company Overview CONSOL Energy: Net (Decrease)/Increase in Cash Goal is to maintain our strong liquidity position Cash Flow Summary Q-to-Q Q-to-Q ($ in millions) 2Q2014 2Q2013 Change 2Q2014 1Q2014 Change Net Cash Provided by Operations $221 $125 $96 $221 $336 ($115) Capital Expenditures ($368) ($3
Slide 16: Q1 2014 to Q2 2014 Cash Reconciliation
Company Overview Q1 2014 to Q2 2014 Cash Reconciliation 600 $221 ($368) 500 ($ in millions) 400 $314 300 $8 ($10) ($14) ($4) 200 $147 100 - (1) Cash Balance Net Cash Capital Proceeds Proceeds Dividends Other Cash Balance as of Q1 2014 Provided by Expenditures From Asset From Paid as of Q2 2014 Opera
Slide 17: Marketing 3Q14 and 2014 Forecasts
Company Overview Marketing 3Q14 and 2014 Forecasts 2014 Coal Sales Facts and Goals Contracted tons for 2014: 98% Sales Tons by Product Year 2014 - Priced: 96% 5% Approximately 78% of the Low-Vol & High-Vol met 11% coal tons are forecasted to be shipped overseas Approximately 94% of the thermal
Slide 18: Our Domestic Coal Market Remains Solid
Company Overview Our Domestic Coal Market Remains Solid PJM Coal Inventory Trailing 12 Months 5 Year Average 30 25 20 Tons (MM) 15 10 5 - May 13 Aug 13 Nov 13 Feb 14 Source: EIA, PIRA, and CONSOL analysis. 18
Slide 19: E&P Division
(= CONSOL ENERGY AMERICA’S ENERGY STARTS HERE. E&P Division 19
Slide 20: Tim Dugan, COO–E&P: Background and Vision
E&P Division Tim Dugan, COO–E&P: Background and Vision Over 30 years of experience across the nation’s major natural gas fields including: - Marcellus, Utica, Upper Devonian, Barnett, and Haynesville Most recently served as Vice President of Chesapeake Energy’s Appalachia South Business Unit: -
Slide 21: Continuous Improvement in the Marcellus Shale
E&P Division Continuous Improvement in the Marcellus Shale Average Completed Lateral Length Average Max IP and Average 30-Day Rate 9,000 14,000 8,000 8,000 11,555 12,000 7,000 10,000 9,297 6,000 5,483 8,298 5,137 8,000 7,394 Mcf/d 5,000 Feet 4,000 3,366 6,000 5,033 5,227 4,593 3,000 3,780 3,499 2,04
Slide 22: CONSOL Energy is a Low Cost Leader
E&P Division CONSOL Energy is a Low Cost Leader 2011-2013 All Sources Reserve Replacement: 3-Year Average vs. E&P Peers 2,000% 1,500% Average: 316% 1,000% 515% 500% 0% CONSOL Energy 2011-2013 All Sources F&D Cost: 3-Year Average vs. E&P Peers $10 $8 $6 Average: $3.85 $/Mcfe $4 $2 $0.88 $0 CONSOL Ene
Slide 23: Large and Growing E&P Reserves
E&P Division Large and Growing E&P Reserves YE 2013 Proved Reserves Proved Reserves Growth 6,000 172 105 (172) 1,633 5,731 6,000 5,731 5,000 5,000 3,993 4,000 3,993 4,000 3,732 3,480 3,000 44% increase in proved Bcfe Bcfe reserves 3,000 87% increase in Marcellus Shale proved reserves 2,000 1,911
Slide 24: Resource and Opportunity Rich Portfolio
E&P Division Resource and Opportunity Rich Portfolio Proved Estimated Potential Locations (Gross) Tcfe Proved(2) Unproven Total Marcellus Shale 3.4 1,414 8,024 9,438 Utica Shale(1) 0.1 45 3,030 3,075 Upper Devonian 0.0 5 2,884 2,889 CBM 1.5 3,806 5,603 9,409 Conventional 0.6 9,997 71,871 81,868 Tota
Slide 25: E&P Division Summary
E&P Division Summary Marcellus Shale Utica Shale Future Development / Potential Growth engine over next 3-5 Growing portion of Stacked pay potential years of development production mix over next 3 ─ Pittsburgh Airport years ─ Over 60% CAGR ─ Southwest PA expected through 2016 ─ ~270% CAGR of U
Slide 26: 2014E Drill Schedule and Activity Overview
E&P Division 2014E Drill Schedule and Activity Overview Marcellus Shale Utica Shale Upper Devonian PA/W North South Ohio Ohio SWPA CPA WV Ohio(1) Total V Total SWPA WV Total Wet Wet Wet Dry Dry Drilled 46 12 25 1 68 30 182 32 1 -- 33 7 1 8 Completed 43 14 17 1 77 25 177 16 1 -- 17 -- -- -- TIL 19 14
Slide 27: Gas Division Production Growth
E&P Division Gas Division Production Growth Gas Production 400 +30% 300 +30% 225-235 Bcfe 200 172.4 153.5 156.3 127.9 +60% 94.4 100 76.6 56.1 58.2 +44% 44.5 48.6 48.4 +87% 0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014E 2015E 2016E Marcellus CBM Utica Conventional & Other Total 2014 M
Slide 28: 2014E E&P Capex: $1,110 million
E&P Division 2014E E&P Capex: $1,110 million Land capex Other E&P Capex Coal 2014E E&P Capex Potential Marcellus JV Carry 26% $1,200 $1,110 $953 $1,000 $ in millions $800 $600 $528 E&P $400 74% $200 $0 2012 2013 2014E E&P Division Capex: ($ in millions) 2014E Capex % of total Land and Permitting $70
Slide 29: 2014E E&P Capex: $1,110 million
E&P Division 2014E E&P Capex: $1,110 million Marcellus Wet $410 million Marcellus Dry $415 million Utica Wet $105 million Wet Dry Oil Wet Dry Utica Dry $10 million Source: Company filings. 29
Slide 30: Joint Ventures Overview
E&P Division Joint Ventures Overview Summary of JV Carry Eligible Capital Description Marcellus / Noble Utica / Hess Ownership 50/50 50/50 Net acreage 345,151(1) 68,488(2) Zones PA and WV Marcellus, Burkett to Onondaga OH Utica -Noble to pay 1/3 of CNX 50% share of eligible charges Hess to pay 50% o
Slide 31: Declining E&P Unit Costs
E&P Division Declining E&P Unit Costs Driving Down Weighted Average Cost: Consolidated Cost per Mcfe Property & Other Taxes Direct Admin, Selling & Other Total operating cost per Mcfe expected to decline LOE Gathering and Transportation 5% to 10% over the next three years DD&A $1.50 Mix shift to
Slide 32: Asset Teams: Overview
E&P Division Asset Teams: Overview Ensuring locations are drill-ready ─ Build teams and alignment 4 Teams: ─ Northern Marcellus: Pennsylvania ─ Deliver on IRR and PVR ─ Southern Marcellus: West Virginia Focused on capital efficiency ─ Utica ─ Continuous measurement of KPIs and improvement ─ Ex
Slide 33: Enhanced Production Techniques: Pure Upside
E&P Division Enhanced Production Techniques: Pure Upside Eliminating chokes and bottlenecks Pad production increases around 34% EUR could increase as much as 29% Kuhns 3B Actual Gas Production vs Projected Production w/o Annular Flow 12,000 Gas Production (Mcfd) 10,000 8,000 6,000 4,000 2,000
Slide 34: Marcellus Recompletions
E&P Division Marcellus Recompletions GH15 recomplete added production and reserves ─ Original EUR: 3.9 Bcfe ─ Recomplete EUR: 6.0 Bcfe ─ Incremental EUR: 2.1 Bcfe 6 additional recompletes planned for 2014 GH 15 Production History and Recomplete 3,000 Recomplete at Recomplete at 2,500 time zero r
Slide 35: Marcellus Completions: Line Pressure Reduction
E&P Division Marcellus Completions: Line Pressure Reduction 120,000 1,400 10 MMcfd Increase 1,200 100,000 1,000 80,000 PSIG Mcfd 800 60,000 600 40,000 400 20,000 200 NV41 Pad N NV Field N NV Field (PSIG) NV41 (PSIG) 10 MMcfd Increase 0 - 3/1 3/8 3/15 3/22 3/29 4/5 4/12 4/19 4/26 5/3 Field pressure o
Slide 36: Marcellus Shale
(= CONSOL ENERGY AMERICA’S ENERGY STARTS HERE. Marcellus Shale 36
Slide 37: Marcellus Shale Overview
Marcellus Shale Overview ~436,000 CONSOL net acres ─ ~88% NRI ─ ~87% HBP 21.9 Tcfe 3P Over 8,900 gross potential wells(1) 2014E drilled wells: 182(2) ~87% Marcellus production growth expected in 2014E Liquids expected to grow from 2% in 2013 to 5%-8% in 2014E 10 horizontal rigs current
Slide 38: New Project Areas: Marcellus EUR/Ft
Marcellus Shale New Project Areas: Marcellus EUR/Ft 38
Slide 39: Growth Runway and Depth of Inventory
Marcellus Shale Growth Runway and Depth of Inventory Marcellus Shale Upside Potential Total Prospective Marcellus Acreage ~790,000 - Acres within JV ~690,000 - Acres outside JV – 100% CONSOL ~100,000 Acreage per well (assumed 750 ft spacing) ~86 Producing wells (YE2013) 259 PDNP and PUD loca
Slide 40: Continuous Improvement
Marcellus Shale Continuous Improvement Average Daily Well Production Grouped by TIL Year Focus on prioritization and optimization of assets Improved drilling and completions result in 10,000 better wells 2008-2011 Actuals Normalized to 5,000 ft 2012-2013 Actuals 2008-2011 includes 1 RCS/SSL
Slide 41: Actual Well Costs vs. Lateral Length
Marcellus Shale Actual Well Costs vs. Lateral Length 2012 and 2013 Combined Well Costs RCS/SSL Well Costs $12,000,000 $12,000,000 Actual RCS/SSL well costs $10,000,000 $10,000,000 $8,000,000 $8,000,000 $6,000,000 $6,000,000 $4,000,000 Targeted well costs $4,000,000 $2,000,000 $2,000,000 $0 $0 0 2,00
Slide 42: Increasing Economics By Drilling Longer Laterals
Marcellus Shale Increasing Economics By Drilling Longer Laterals IRR w/Carry IRR w/Eff IRR Hist. CONSOL has consistently 160% 154% increased drilled lateral 145% lengths each year 136% ─ 2011: 3,853 ft 126% 115% ─ 2012: 5,514 ft 120% 111% 105% 104% ─ 2013: 7,970 ft 98% 91% ─ 2014E: ~8,000 ft ATAX
Slide 43: Marcellus Shale: Drilling
Marcellus Shale: Drilling 43
Slide 44: CONSOL-Operated Summary
Marcellus Shale: Drilling CONSOL-Operated Summary Drilling Summary 2011 2012 2013 YTD 2014 Wells TD’d 78 64 46 40 Lateral ft 300,466 328,428 366,615 301,367 Total MD ft 92,264 794,098 730,316 617,138 Average Lateral ft 3,853 5,514 7,970 7,159 Average TMD ft 11,824 13,280 15,876 15,110 Average Drill
Slide 45: Cost Efficiencies and Improvements
Marcellus Shale: Drilling Cost Efficiencies and Improvements Air Directional: Expect a two-day reduction in horizontal cycle times Technological Advances: One-run RSS tools; drilling optimization, and evaluating 7-7/8” production hole Rig Move Improvements: Expect 20% reduction in rig move tim
Slide 46: Air Directional
Marcellus Shale: Drilling Air Directional NV34B – Without Air Directional Air Directional Top Hole Horizontal Comparison NV58E NV34B Air Directional Work Yes No Kick-Off Point ft 6,700 5,600 o o Starting Inclination 24 0 Total MD ft 15,843 17,201 Drilled Curve Length ft 782 2,074 NV58E – With Air Di
Slide 47: Marcellus Shale: Completions
Marcellus Shale: Completions 47
Slide 48: CONSOL-Operated Summary
Marcellus Shale: Completions CONSOL-Operated Summary Completions Summary 2011 2012 2013 YTD 2014 Wells Completed 57 51 59 29 Lateral Completed ft 188,800 270,256 333,895 223,825 Total Stages 684 940 1,527 1,474 Average Stage/Well 12 18 26 51 Average Stage Cost $205k $184k $193k $118k(1) Evolving Sti
Slide 49: Cost Efficiencies and Improvements
Marcellus Shale: Completions Cost Efficiencies and Improvements Completions Pricing Reduction: Renegotiating contracts Efficiency Increases: Increases the number of stages per day Stimulation Design Optimization: Pump rates, sand schedules, additives, etc. Completions Per 150 ft Stage Cost Sav
Slide 50: Cost Efficiencies and Improvements
Marcellus Shale: Completions Cost Efficiencies and Improvements Entire pad average stages per day Increasing from 4 to 8 stages per day equates to capital savings of $430,000 and reduces cycle time by ~7 days Capital Savings vs. Stages per Day $116,000 $600,000 Capital Savings per well $114,000
Slide 51: RCS/SSL Overview
Marcellus Shale: Completions RCS/SSL Overview 30’ 30’ 30’ 30’ 30’ 30’ 30’ 30’ 30’ 60’ 60’ 60’ 60’ Cluster Spacing reduced from 60’ to 30’ Stage Length Standard 300’ Stage SSL 150’ SSL 150’ reduced from 300’ to 150’ Length Stage Stage RCS/SSL ensures a better distribution of the fracture treatment
Slide 52: RCS/SSL Activity Overview
Marcellus Shale: Completions RCS/SSL Activity Overview 12 RCS/SSL wells to date 29 RCS/SSL wells to date 12 RCS/SSL wells to date Producing Pads Note: Townships are shown in yellow where CONSOL holds 3,000 or more acres (as of 5/1/2014). 52
Slide 53: Marcellus Shale: Sub-Regions
Marcellus Shale: Sub-Regions 53
Slide 54: Marcellus Sub-Regions Summary
Marcellus Shale: Sub-Regions Summary Marcellus Shale North South SWPA CPA WV Ohio(1) Total Wet Wet Net Acres ~45,000 ~110,000 ~105,000 ~11,000 ~60,000 ~105,000 ~436,000 Approximate Gross 700 2,000 2,300 100 1,600 2,200 ~8,900 Locations(2) Avg EURs/1,000 ft 2.1 1.6 1.8 1.3 1.7 1.4 -- (Bcfe) Targeted
Slide 55: Southwest PA Overview
Marcellus Shale: Southwest PA Southwest PA Overview ~45,000 CONSOL net acres NV56 Pad Over 700 gross locations(1) 2 Wells 7,171’ Avg Lateral Length per well 9,365 Mcfe Avg 30-day IP per well ─ 138 wells online, as of 7/1/2014 ─ 19 wells online in NV36 Pad 2014E 7 Wells 5,021’ Avg Lateral Length
Slide 56: Southwest PA 5,000 ft Type Curve and Economics
Marcellus Shale: Southwest PA Southwest PA 5,000 ft Type Curve and Economics 1,000 100 MMcfe/Mo 10 1 0 50 100 150 200 Months IRR w/Carry IRR w/Eff IRR Hist. 160% 159% 131% Southwest PA Assumptions Type Curve 2014E 120% 105% 115% Lateral Length (ft) 5,000 8,800 ATAX IRR(1) 95% EUR (Bcfe) 10.5 18.5 76
Slide 57: Southwest PA Production vs. 5,000 ft Type Curve
Marcellus Shale: Southwest PA Southwest PA Production vs. 5,000 ft Type Curve 8.5 Bcfe Type Curve 7.2 Bcfe Type Curve Projecting 18% improvement in EURs utilizing RCS/SSL 57
Slide 58: Southwest PA Production vs. 5,000 ft Type Curve
Marcellus Shale: Southwest PA Southwest PA Production vs. 5,000 ft Type Curve 11.6 Bcfe Type Curve 9.6 Bcfe Type Curve We expect to drill 16, 53, and 19 horizontal wells in 2014, 2015, and 2016, respectively 58
Slide 59: Northern WV Overview
Marcellus Shale: Northern WV Dry Northern WV Overview ~105,000 CONSOL net acres Over 2,300 gross PHL13 Pad locations(1) ANDERSON (PDC Mountaineer) 6 Wells 3 Wells 7,949’ Avg Lateral Length per well ─ 25 wells online, as of 4,859’ Avg Lateral Length per well 6,869 Mcfe Avg 30-day IP per well 595
Slide 60: Northern WV 5,000 ft Type Curve and Economics
Marcellus Shale: Northern WV Dry Northern WV 5,000 ft Type Curve and Economics 1,000 100 MMcfe/Mo 10 1 0 50 100 150 200 Months IRR w/Carry IRR w/Eff IRR Hist. 100% Northern WV Dry 85% Assumptions Type Curve 2014E 80% 69% Lateral Length (ft) 5,000 6,800 62% ATAX IRR(1) 60% 54% EUR (Bcfe) 8.8 12.0 50%
Slide 61: Northern WV Production vs. 5,000 ft Type Curve
Marcellus Shale: Northern WV Dry Northern WV Production vs. 5,000 ft Type Curve 7.9 Bcfe Type Curve 6.6 Bcfe Type Curve Early constraints masking results but expect improved production with RCS/SSL 61
Slide 62: Northern WV - Dominion Transmission Storage Field
Marcellus Shale: Northern WV Dry Northern WV - Dominion Transmission Storage Field Antero Activity(1) Within 2 miles of DTI northern border Average EURs: 1.7 Bcfe/1,000’ lateral utilizing RCS/SSL AUD3 Pad 1 Well 8,691’ Avg Lateral Length per well 6,099 Mcfe Avg 30-day IP per wel 917 MMcf/well – 1st
Slide 63: Central PA Overview
Marcellus Shale: Central PA Central PA Overview ~110,000 CONSOL net acres Over 2,000 gross GAUT4 Pad locations(1) 4 Wells 7,941’ Avg Lateral Length per well ─ 51 wells online, as of 6,619 Mcfe Avg 30-day IP per well 759 MMcf/well – 1st 6-month Cum 7/1/2014 SHAW Pad 3 Wells ─ 14 wells online in 3
Slide 64: Central PA 5,000 ft Type Curve and Economics
Marcellus Shale: Central PA Central PA 5,000 ft Type Curve and Economics 1,000 100 MMcfe/Mo 10 1 0 50 100 150 200 Months IRR w/Carry IRR w/Eff IRR Hist. 80% 78% 63% Central PA 60% 57% Assumptions Type Curve 2014E 50% ATAX IRR(1) Lateral Length (ft) 5,000 6,900 46% EUR (Bcfe) 8.0 11.0 40% 36% 43% EUR
Slide 65: Central PA Production vs. 5,000 ft Type Curve
Marcellus Shale: Central PA Central PA Production vs. 5,000 ft Type Curve 8.0 Bcfe Type Curve 6.8 Bcfe Type Curve Flowback underway on first five RCS/SSL wells 65
Slide 66: New Project Areas – Pittsburgh Airport
Marcellus Shale: North Wet Gas New Project Areas – Pittsburgh Airport 45 planned Marcellus laterals 45 potential Upper Devonian laterals 15 planned 30 potential 45 potential Utica Shale laterals ~9,000 contiguous acres have resource potential in excess of 1.6 Tcfe 66
Slide 67: North Wet Gas Overview
Marcellus Shale: North Wet Gas North Wet Gas Overview ~60,000 CONSOL net acres Over 1,600 gross locations(1) ─ 70 wells online, as of 7/1/2014 IMPERIAL LAND (Range ─ 63 wells online in Resources) 2014E 4 Wells BARE WARREN (Range 3,182’ Avg Lateral Length per well Resources) 373 MMcf/well – 1st 6
Slide 68: North Wet Gas 5,000 ft Type Curve and Economics
Marcellus Shale: North Wet Gas North Wet Gas 5,000 ft Type Curve and Economics 1,000 5 Wellhead Sold Gas 4 100 Condensate MMcf/Mo MBbl/Mo NGL 3 2 10 1 1 0 0 50 100 150 200 Months IRR w/Carry IRR w/Eff IRR Hist. 100% 91% North Wet Gas 80% 74% Assumptions Type Curve 2014E 66% ATAX IRR(1) Lateral Lengt
Slide 69: North Wet Gas Production vs. Type Curve
Marcellus Shale: North Wet Gas North Wet Gas Production vs. 5,000 ft Non-RCS/SSL Type Curve Increasing productivity Limited use of RCS/SSL First 12 wells of 2014 ─ 2 of 12 wells utilized RCS/SSL in 2014 ─ 2014 IP rates significantly above 2012 and 2013 levels with limited use of RCS/SSL 15-20%
Slide 70: Liquids Production Growth
Marcellus Shale: North Wet Gas Liquids Production Growth Price Uplift from Wet Gas Increases Value ~60% to Liquids Volume Growth Over $8 per Mcf of Wellhead Gas Gas NGL Condensate $/Mcf 9 $8.57 5 Bbl/MMcf $0.46 condensate at 85% WTI 43 Bbl/MMcf $2.95 NGLs at 69% WTI 6 $5.23 3 1,057 MMBtu 1,070 $5.16
Slide 71: South Wet Gas Overview
Marcellus Shale: South Wet Gas South Wet Gas Overview SHR1 Pad ~105,000 CONSOL net 6 Wells ~8,741’ Avg Lateral Length per well WEESE (Triad Hunter) 3 Wells acres PEN1 Pad Completions underway 9 Wells 3,711’ Avg Lateral Length per well Over 2,200 gross ~6,824’ Avg Lateral Length per well Completi
Slide 72: South Wet Gas 5,000 ft Type Curve and Economics
Marcellus Shale: South Wet Gas South Wet Gas 5,000 ft Type Curve and Economics 1,000 5 Wellhead Sold Gas 4 100 Condensate MMcf/Mo MBbl/Mo NGL 3 2 10 1 1 0 0 50 100 150 200 Months IRR w/Carry IRR w/Eff IRR Hist. 60% 51% South Wet Gas Assumptions Type Curve 2014E 41% 40% 37% ATAX IRR(1) Lateral Length
Slide 73: Utica Shale
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Slide 74: A Leading Position in the Utica Shale
Utica Shale Overview: A Leading Position in the Utica Shale ~581,000 CONSOL net acres(1) Over 3,000 gross locations ─ 20 wells online, as of 7/1/2014 ─ 43 wells online in 2014E ─ 7,000 ft average laterals in 2014E ─ 4-5 wells per pad on average in 2014E ─ 120-acre spacing (assuming 7,000 ft late
Slide 75: Growth Runway and Depth of Inventory
Utica Shale Growth Runway and Depth of Inventory Utica Shale Upside Potential Total Prospective Utica Acreage ~650,000 - Acres within JV ~137,000 - Acres outside JV – 100% CONSOL ~513,000 Acreage per well (assumed 750 ft spacing) ~86 Producing wells (YE2013) 9 PDNP and PUD locations (YE2013)
Slide 76: Utica Production Growth
Utica Shale Utica Production Growth Production 50 40.4 40 37.8 30 Bcfe 20 13.5 10 0.8 0 2013 2014E 2015E 2016E Utica Net Production Utica shale production expected to become greater part of mix 76
Slide 77: Utica Shale: Drilling
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Slide 78: CONSOL-Operated Summary
Utica Shale: Drilling CONSOL-Operated Summary Drilling Summary 2013 YTD 2014 Wells TD’d 9 9 Lateral ft 63,167 47,972 Total MD ft 137,769 121,412 Average Lateral ft 7,019 5,330 Average TMD ft 15,308 13,490 Average Drill Cost/ft $366 $350 Average Lateral Cost/ft $798 $886 33 Utica wells to be drilled
Slide 79: Cost Efficiencies and Improvements
Utica Shale: Drilling Cost Efficiencies and Improvements Shortened Intermediate Casing: Potential to reduce cycle times by 8 days with revised casing program; could result in reduction in cost of $900k per well Technological Advances: One-run RSS tools, drilling optimization, and evaluating 7-7/
Slide 80: Utica Shale: Completions
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Slide 81: CONSOL-Operated Summary
Utica Shale: Completions CONSOL-Operated Summary Completions Summary 2012 2013 YTD 2014 Wells Completed 4 10 6 Lateral Completed ft 18,160 50,916 42,923 Total Stages 63 200 290 Average Stg/Well 16 20 48 Average Stage Cost $310k $224k $148k(1) Evolving Stimulation Design 2012 2013 Today Stage Length
Slide 82: Cost Efficiencies and Improvements
Utica Shale: Completions Cost Efficiencies and Improvements Completions Pricing Reduction: Renegotiating contracts Efficiency Increases: Increases the number of stages per day Stimulation Design Optimization: Pump rates, sand schedules, additives, etc. $180,000 $155,000 ($8,000) $160,000 ($5,0
Slide 83: Utica Shale: Sub-Regions
(= CONSOL ENERGY AMERICA’S ENERGY STARTS HERE. Utica Shale: Sub-Regions 83
Slide 84: 2014E Activity Overview
Utica Shale: Sub-Regions 2014E Activity Overview Utica Shale Ohio Wet Ohio Dry PA/WV Dry Total Net Acres ~84,000 ~25,000 ~472,000 ~581,000 Approximate Gross 500 300 2,200 3,000 Locations(1) Avg EURs/1,000 ft 1.9 2.4 1.8 -- (Bcfe) Targeted Avg Lateral 7,000 8.000 5,000 -- Length ft Avg EURs/well 13.3
Slide 85: The Utica Sweet Spot Evolves
Utica Shale: Ohio Wet Gas The Utica Sweet Spot Evolves GPOR - Wagner 1-28H CHK - Buell 8H IP GAS: 14,000 Mcf/d IP GAS: 9,500 Mcf/d IP OIL: 432 Bbl/d IP OIL: 1,425 Bbl/d GPOR - Shugert 1-12H ~36,000 net core wet acres IP GAS: 28,500 Mcf/d GPOR - Boy Scout 33H IP OIL: 300 Bbl/d IP GAS: 5,300 Mcf/d IP
Slide 86: CONSOL’s Historic Core
Utica Shale: Ohio Wet Gas CONSOL’s Historic Core: Noble, Harrison, Belmont, Guernsey, and Jefferson Counties ~84,000 CONSOL net acres ~36,000 CONSOL net acres in core Type curve reflects core area Over 500 gross core area locations(1) ─ 16 wells online, as of 7/1/2014 ─ 41 wells online in 20
Slide 87: Recent IP Rates In and Around Monroe County, OH
Utica Shale: Ohio Dry Gas Recent IP Rates In and Around Monroe County, OH CVX Conner well (Utica): 25.0 MMcf/d – Avg 24-hr rate GPOR Irons 1-4H (Utica): 30.3 MMcf/d – Avg 24-hr rate MHR 3-UH (Utica): 32.5 MMcf/d – Avg 24-hr rate MHR 2-MH (Marcellus): 3.7 MMcf/d of gas and 312 Bbls of condensate per
Slide 88: Ohio Dry Gas Area Production vs. Type Curve
Utica Shale: Ohio Dry Gas Ohio Dry Gas Area Production vs. 5,000 ft Type Curve ~25,000 CONSOL net acres ─ ~11,000 net acres in Monroe County, OH ─ ~14,000 net acres in eastern portion of Jefferson, Belmont and Harrison counties Over 300 gross locations(1) ─ First well (SWITZ 6B) drilling underwa
Slide 89: Utica PA/WV Dry Gas Area Overview
Utica Shale: PA/WV Dry Gas Utica PA/WV Dry Gas Area Overview REXX – Cheeseman 1 IP Gas: 9,200 mcfd RRC– Zahn #1 IP Oil: 0 Bbld IP Gas: ~4,500 mcfd IP Oil: 0 Bbld CHK – Thompson 3H CHK– Hubbard 3H IP Gas: 6,400 mcfd IP Gas: 11,00 mcfd IP Oil: 0 Bbld IP Oil: 0 Bbld CHK – Brown 10H IP Gas: 9,500 mcfd R
Slide 90: Utica PA/WV Dry Gas Production vs. Type Curve
Utica Shale: PA/WV Dry Gas Utica PA/WV Dry Gas Production vs. 5,000 ft Type Curve ~472,000 CONSOL net acres ─ ~300,000 prospective net acres in PA (~80,000 net acres located within Greene and Washington counties) ─ ~172,000 prospective net acres in WV Well count Over 2,200 gross locations(1) 1
Slide 91: Upper Devonian
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Slide 92: Burkett Shale Sweet Spot
Upper Devonian Burkett Shale Sweet Spot CONSOL is well situated in the best part of the Burkett fairway, with an estimated 345,000 net acres of potential across the entire Upper Devonian 92
Slide 93: NV39F Upper Devonian Exploration Well
Upper Devonian NV39F Upper Devonian Exploration Well Drilled in Southwest PA 5 underlying Marcellus wells on pad Washington County, PA ─ Drilled lateral length of 4,889 ft ─ Frac’d 17 stages in Burkett Shale ─ Tested 3.0 MMcf/d, TIL 6/21/13 ─ Currently producing 2.7 MMcf/d ─ Produced 1.0 Bcf in
Slide 94: Upper Devonian Production vs. 5,000 ft Type Curve
Upper Devonian Upper Devonian Production vs. 5,000 ft Type Curve First Upper Devonian well demonstrating very shallow decline compared to type curve Currently producing above type curve: Forecasted EUR 9 Bcfe Planning 6+ Burkett Shale and at least two Rhinestreet Shale wells in 2014 Within t
Slide 95: Stacked Pay Potential
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Slide 96: Appalachian Shale Acreage
Stacked Pay Potential Appalachian Shale Acreage P a y Formation Name Wet Dry Total Net Acres Net Acres Net Acres Rhinestreet Shale Upper Cashaqua Shale Devonian 190,000 155,000 345,000 Middlesex Shale West River Shale Burkett Shale Tully Limestone Hamilton Shale Marcellus Marcellus 175,000 261,000 4
Slide 97: CONSOL’s Shale Fairway
Stacked Pay Potential CONSOL’s Shale Fairway PIT Airport Rhinestreet = 5,340’ Burkett = 5,460’ Marcellus = 5,690’ Utica = 10,760’ Monroe County/Moundsville Rhinestreet = 5,930’ Burkett = 6,110’ Southwest PA Marcellus = 6,190’ Rhinestreet = 6,730’ Utica = 10,680 Burkett = 7,000’ Marcellus = 7,270’ Ut
Slide 98: Gas Factory Development
Stacked Pay Potential Gas Factory Development Stacked laterals provide economies of scale to access up to 4 pays from 1 pad 98
Slide 99: Southwest PA Stack Pay Potential
Stacked Pay Potential Southwest PA Stack Pay Potential: ~9.0 Tcfe Resource Potential Potential Lateral Spacing Well CapEx EUR Liquids Resource Pay Wells Length (ft) (acre) ($MM) (Bcfe) (%) (Bcfe) Burkett 235 ~6,400 110 7.6 9.5 - 2,226 Rhinestreet 165 ~6,100 105 7.4 4.5 - 745 Marcellus 249 ~6,400 110
Slide 100: Pittsburgh Airport Stack Pay Potential
Stacked Pay Potential Pittsburgh Airport Stack Pay Potential: ~1.6 Tcfe Resource Potential Potential Lateral Spacing Well CapEx EUR Liquids Resource Pay Wells Length (ft) (acre) ($MM) (Bcfe) (%) (Bcfe) Upper Devonian (Burkett) 45 ~8,000 138 8.8 9.3 16% 418 Marcellus 45 ~8,000 138 8.8 13.3 16% 598 Ut
Slide 101: Other Gas Reserves and Resources
Other Gas Reserves and Resources 101
Slide 102: Virginia Coalbed Methane (CBM)
Other Gas Reserves and Resources Virginia Coalbed Methane (CBM) 350,000 net acres(1) Origin of CNX Gas Associated with mining at Buchanan mine Advantageous gas marketing location for basis Over 2,700 gross locations ─ ~3,000 wells online, as of 5/1/2014 ─ 60 wells online in 2014E 0.5 Bcf
Slide 103: Conventional Wells
Other Gas Reserves and Resources Conventional Wells 2,294,000 net acres(1) HBP position creates substantial flexibility to explore and develop other pays Mostly acquired with Dominion E&P acquisition in 2010 ~70,000 gross locations ─ ~10,000 wells online, as of 5/1/2014 0.250 Bcfe/well $
Slide 104: Chattanooga Shale, Monteagle SOG, and Conasauga Shale
Other Gas Reserves and Resources Chattanooga Shale, Monteagle SOG, and Conasauga Shale 243,000 CONSOL net acres 2,170 gross locations ─ ~74 wells online as of 5/1/2014 ─ 5 wells online in 2014E Chattanooga: $1.5 million/Hz well 1.0 Bcfe/well (4,200 ft) Currently producing 7.6 MMcf/d Annu
Slide 105: Illinois Basin
Other Gas Reserves and Resources Illinois Basin 277,000 net acres(1) ~1,400 gross locations Stacked pay potential ─ Mississippian and Devonian sandstones and carbonate ─ New Albany shale ─ Maquoketa shale Currently producing: ~0.2 MMcf/d Annual decline rate of ~12% Producing Wells (1) Incl
Slide 106: E&P Division Summary
E&P Division Summary 30% gas production growth Implemented asset teams Driving costs down with efficiencies and lean manufacturing Stacked pay potential Solid production with conventional assets Joint ventures with established partners CONSOL has the team and the assets to drive value 10
Slide 107: Gas Marketing
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Slide 108: Appalachia Energy Basin - Stacked Reserves
Gas Marketing Appalachia Energy Basin - Stacked Reserves Upper Devonian Utica Shale Marcellus Shale Pittsburgh 8 Coalbed Methane Conventional SOG Reserves Pocahontas Coalbed Methane CONSOL Energy is located in the middle of a world-class natural gas and coal reserve area that has decades of growth p
Slide 109: CONSOL Energy Assets
Gas Marketing CONSOL Energy Assets CNX Assets Marcellus Shale Utica Shale Upper Devonian Conventional SOG Upper Coalbed Methane Devonian Utica Coal Reserves Shale Marcellus Shale Bailey Complex Conventional SOG CNX Reserves • ~5.7 Tcfe of proved gas reserves Coalbed Methane • ~436,000 Marcellus net
Slide 110: Market Opportunities - Stacked Customers
Gas Marketing Market Opportunities - “Stacked Customers” Power Plants Natural Gas Plants Coal Plants Our ability to produce both natural gas and coal allows us the flexibility to provide an energy solution to utilities that burn either fuel Source: SNL Financial. 110
Slide 111: Shared Value Opportunities
Gas Marketing Shared Value Opportunities Land Thermal Coal Gathering NGL Sales Processing Export Ethane Met Coal Pipelines Domestic Ethane Power Purchases Export Coal Dry Gas Sales Export LNG Actively pursuing opportunities with customers for gas sales, coal sales, pipeline project development, land
Slide 112: Gas Marketing Summary
Gas Marketing Summary Natural Gas Sales - Current NYMEX hedges cover 74% of total volumes for CY2014 - Sales portfolio of 80 customers in five index markets (34% basin exports) Firm Transportation - Total company FT capacity exceeds plan production for the next two years - Near-term regional req
Slide 113: Firm Transportation
Gas Marketing Firm Transportation Total company FT capacity exceeds plan production for two years Targeting pipeline projects that access favorable markets Will supplement direct FT with firm sales to customers that have matching firm capacity Will acquire third-party released firm capacity
Slide 114: Firm Transportation - Current Portfolio
Gas Marketing Firm Transportation - Current Portfolio ANR Pipeline Dominion (DTI) Columbia (TCO) East Tennessee Pipeline (MMcf/d) 2014 2016 Dominion (DTI) 255 370 East Tennessee 282 282 Texas Eastern (TETCO) Columbia (TCO) 225 240 TETCO (Firm Sales) 285 235 TETCO (Firm Capacity) 30 127 ANR Pipeline
Slide 115: Firm Transportation - Recent Projects
Gas Marketing Firm Transportation - Recent Projects ANR Capacity Volume: 47,000 Mcf/d Start Date: November 2015 Market: Michcon/Chicago TETCO - Gas City Project Volume: 47,000 Mcf/d Start Date: November 2015 Michcon Market: ANR Markets Gas City SWPA / Ohio Production Areas Short-Haul FT Capacity (12
Slide 116: Natural Gas Sales
Gas Marketing Natural Gas Sales Gas Sales 2014 2016* Midwest In-Basin 66% 50% TETCO M3 Exports 34% 50% Dominion South 100% 100% * CY2016 Targets TCO Pool TETCO M2 East Tennessee Gas Sales 2014 Columbia (TCO) 30% Dominion (DTI) 18% TETCO (M2) 18% TETCO East LA TETCO (M3) 17% East Tennessee 17% Midwes
Slide 117: Natural Gas Sales - Basis Risk
Gas Marketing Natural Gas Sales - Basis Risk Chicago Dawn CY 2014: $0.89 CY 2014: $1.02 CY 2016: - $0.07 CY 2016: $0.26 TETCO M3 Dominion South CY 2014: $0.22 CY 2014: - $1.01 CY 2016: $0.02 CY 2016: - $0.98 TCO Pool Basis TETCO M2 CY 2014: - $0.09 CY 2014: - $1.02 CY 2016: - $0.47 CY 2016: - $1.03
Slide 118: Natural Gas Sales - Volatile Prices
Gas Marketing Natural Gas Sales - Volatile Prices Natural gas prices and basis values are expected to remain volatile over time Manage price risk by adding program, supplemental, and basis hedges Manage basis risk by developing a diversified portfolio of sales locations Target additional fir
Slide 119: Natural Gas Sales - Pipeline Projects
Gas Marketing Natural Gas Sales - Pipeline Projects Dawn CY 2014: $1.02 CY 2016: $0.26 Dominion South CY 2014: - $1.01 Dawn Pipeline Projects CY 2016: - $0.98 TETCO M2 CY 2014: - $1.02 CY 2016: - $1.03 Southeast Pipeline Projects TCO Pool Basis East LA CY 2014: - $0.09 CY 2014: - $0.07 CY 2016: - $0
Slide 120: Natural Gas Processing
Gas Marketing Natural Gas Processing Contracted capacity exceeds current requirements by 45% Processing Contracted Capacity - Gross Inlet Gas Volumes MCF/d Options for additional volumes under our existing *CY2016 capacity = 415,000 Mcf/day ** contracts Maximize realizations by taking advantag
Slide 121: Natural Gas Processing - Majorsville
Gas Marketing Natural Gas Processing - Majorsville 4,500 4.0 Million Gallons 4,000 Normal Pentane ISO-Pentane 3,500 Hexane (000 Gallons Per Month) ISO-Butane 3,000 Normal Butane 2,500 2,000 1,500 1,000 846,000 Gallons Propane 500 0 Propane Normal Butane Iso-Butane Hexane Iso-Pentane Normal Pentane M
Slide 122: Ethane Sales - Market Options
Gas Marketing Ethane Sales - Market Options Shell Cracker MW Majorsville CNX McQuay Braskem Cracker INEOS Exports ATEX to Mont Belvieu Northeast ethane production has a number of sales alternatives including exports to Europe, two major cracker projects, and the ATEX pipeline to the Gulf markets Sou
Slide 123: Plan Forward
Gas Marketing Plan Forward Diversified Transportation - Selectively target pipeline projects that serve our production areas - Add new sales with matching firm transportation - Pursue third-party released capacity opportunities Diversified NGL Processing - Sell through midstream partners with th
Slide 124: Coal Division
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Slide 125: Best in Class Operations
Coal Division Best in Class Operations Industry AverageSafety CONSOL Energy Environmental CONSOL Energy 112 2011 2012 2013 Industry Average CONSOL Energy 5.29 79 3.42 42 1.97 1.22 Incident Rate S&S Industry Rate CNX Coal NOV Number of Recordable Injuries * 200,000 hours National Industry Rate for Si
Slide 126: Mining Complex Locations
Coal Division Mining Complex Locations Bailey Complex Buchanan Miller Creek Complex Southern West Virginia / Location Southwestern Pennsylvania Southwestern Virginia Mingo County 5 Longwalls and 1 Longwall System and Stripping Shovels and Method Continuous Mining Machines Continuous Mining Machines
Slide 127: Bailey Complex
Coal Division Bailey Complex Location: West Finley, PA Mine life: 25+ years Reserves: over 625 million tons Thermal & high-vol met coal Production units: - 5 longwalls - 18 miner sections Annual production capacity: 28 million tons Union free operations Upgrades: - 3 new coal silos -
Slide 128: Square Miles Mine Size Comparison
Coal Division Square Miles Mine Size Comparison Enlow Fork Total Mine Area = 33.5 sq. mi. Island of Manhattan = 33.8 sq. mi. Total Sealed Area by end of 2014 = 28.5 sq. mi. 128
Slide 129: Bailey Distribution
Coal Division Bailey Distribution Around-the-clock reliability Strong relationships and service with both railroads Delivered record-breaking Q1 performance despite the most Ability to load up to 10 trains per day severe winter in several years 1 new side track built (total of 3 at the compl
Slide 130: Buchanan
Coal Division Buchanan Location: Buchanan County, VA Mine life: 20+ years Reserves: 98 million tons Low-vol met coal Production units: - 1 longwall - 5 miner sections - 2 mains - 3 longwall developments - Super-sections Annual production capacity: 5.2 million tons Lower cost than most
Slide 131: Miller Creek – Surface & Underground
Coal Division Miller Creek – Surface & Underground Location: Mingo County, WV Mine life: 9 Years on current permit - 15+ additional years on western expansion area High-Quality Reserves - 13 million tons current permit - 20+ million tons additional on western expansion area - Owned in fee - Hi
Slide 132: Appalachia Powerhouse
Coal Division Appalachia Powerhouse Coal fleet generates strong cash flow - We divested our low-margin, high-maintenance operations - Remaining mines have been recapitalized and are brand new and running well - It’s not a matter of if we make money, but how much money we make. Bailey’s future is
Slide 133: Best-in-Class Assets
Coal Division Best-in-Class Assets Historic Sales Price per Ton Weighted average sales price per ton from 2009 – June YTD 2014 $200 $150 $132 $100 $69 $64 $50 2014 June YTD 2014 June YTD 2014 June YTD 2009 2010 2011 2012 2013 2009 2010 2011 2012 2013 2009 2010 2011 2012 2013 $- Bailey Buchanan Mille
Slide 134: Best-in-Class Operations
Coal Division Best-in-Class Operations Cash Cost & Cash Margin Cash margin per ton Q2 Cash Cost per Ton Cash cost per ton $200 $200 $150 $150 $132 5-yr Avg Price $100 $100 $69 5-yr Avg Price $64 5-yr Avg Price $23-141 Incremental Margin $6-19 Incremental Margin $50 $20.82 $50 $21-29 Incremental Marg
Slide 135: Strong Cash Margins
Coal Division Strong Cash Margins 1,800 1,600 1,400 1,200 Total $ in millions 1,000 Miller Creek 800 Bailey 600 400 Buchanan 200 Thermal Met Total Total annual potential cash margin range $0.7-$1.7 billion (20+ years of reserves) Note: Low Range = Internal estimate production and cost, minimum 5-yea
Slide 136: Distribution and Logistics Extend Our Market Reach
Coal Division Distribution and Logistics Extend Our Market Reach Europe Asia South America CNX Marine Terminal • 16 million TPY throughput capacity • Ships to 22 countries • Flexibility to sell into thermal and met markets CNX Mines CNX Marine Terminal NS Railroad System CSX Railroad System Transpor
Slide 137: Diversified Sales Portfolio
Coal Division Diversified Sales Portfolio Our core customers have: Large plants Low heat rates Environmental controls to exist post-MATS Mid-Atlantic MM Tons Logistically-favorable plants Total Tons Burned 39 Quality requirements conducive to our coal 13 CNX Customer Plants 21 CNX 2014E Sa
Slide 138: Protecting Our Turf and Expanding Our Markets
Coal Division Protecting Our Turf and Expanding Our Markets CNX Mines CNX Marine Terminal $13-15 NAPP vs IB Mid- Atlantic Transportation $/Ton Advantage $16-17 NAPP vs IB Europe Transportation $/Ton Advantage $9-10 NAPP vs IB Southeast Transportation $/Ton Advantage Transportation and distribution a
Slide 139: Minor MATS Impact
s Coal Division Minor MATS Impact: Tonnage Reduction Due to MATS 2014-2019 10 GW 2 GW 40 GW 1 MMT 16 MMT 4 MMT 95 MMT Projected 2014 Mid-Atlantic Total burn Total U.S. Impact CNX Customers CNX shipments & Southeast Gas captures much of the retiring 40 GW; MATS has small impact on CONSOL demand and w
Slide 140: U.S. Coal and Gas Inventory/Storage Levels
Coal Division U.S. Coal and Gas Inventory/Storage Levels U.S. Total Coal Inventory Lower 48 Working Gas Underground Storage Current 5 Year Average 5 yr Range 2014 5 Yr Average 220 3.75 200 3.25 180 Tcf 2.75 Tons (MM) 160 2.25 2.22 TCF 140 1.75 128 MM Tons 120 1.25 100 0.75 Jan 14 Apr 14 Jul 14 Oct 1
Slide 141: Power Dispatch Curve
Coal Division Power Dispatch Curve Power dispatch curve/low gas price environment/pre-MATS MATS impact Gas price uplift $/MWH Hourly Demand Swing Cumulative Capacity (MW) Signs point to increased power prices, coal prices, gas prices, and volatility 141
Slide 142: Buchanan – A Sleeping Giant
Coal Division Buchanan – A Sleeping Giant Low-cost, high-quality low-vol met product Customers in U.S., Europe, Brazil, Korea, India, and China Diversifying portfolio away from China CNX financial strength permits disciplined pricing Huge free option as cash generating machine Well-capital
Slide 143: Strong Cash Margins
Coal Division Strong Cash Margins 1,800 1,600 1,400 1,200 Total $ in millions 1,000 Miller Creek 800 Bailey 600 400 Buchanan 200 Thermal Met Total Total annual potential cash margin range $0.7-$1.7 billion (20+ years of reserves) Note: Low Range = Internal estimate production and cost, minimum 5-yea
Slide 144: Appalachia Powerhouse
Coal Division Appalachia Powerhouse Coal fleet generates strong cash flow - We divested our low-margin, high-maintenance operations - Remaining mines have been recapitalized and are brand new and running well - It’s not a matter of if we make money, but how much money we make. Bailey’s future is
Slide 145: Monetization of Non-Core Assets
Monetization of Non-Core Assets 145
Slide 146: Completed Divestitures and JVs Since 2012
Monetization of Non-Core Assets Completed Divestitures and JVs Since 2012 $450 $1,000 $400 $900 $800 $350 Cumulative Transaction Value ($MM) $700 $300 Transaction Value ($MM) $600 $250 $500 $200 $400 $150 $300 $100 170 $200 $50 103 $100 3 13 25 26 7 25 $0 15 $0 Routt County Burning Star Crows Nest E
Slide 147: Sale of West Virginia Mines to Murray Energy
Monetization of Non-Core Assets Sale of West Virginia Mines to Murray Energy Divested 5 West Virginia thermal longwall coal mines, select reserves, and river division - Total coal reserves of 1.1 billion tons, and production of approximately 30 million tons CONSOL received $3.5 billion in value
Slide 148: Future Asset Divestiture Opportunities
Monetization of Non-Core Assets Future Asset Divestiture Opportunities Key Future Asset Divestiture Opportunities Asset Type Potential Illinois Basin reserves/resources Thermal 1,082 MM tons Fola/Birch/Canfield coal mines/reserves Met/Thermal 230 MM tons Itmann coal mines/reserves Metallurgical 30 M
Slide 149: Illinois Basin Divestiture
Monetization of Non-Core Assets Illinois Basin Divestiture 8 coal blocks consisting of 1,082 MM tons of reserves and resources 149
Slide 150: Cardinal States Gathering
Monetization of Non-Core Assets Cardinal States Gathering CSG is a premier gathering system located in Virginia, Kentucky and West Virginia Consists of four interconnected pipelines, a treating/compressor station (Grant Station) and a downstream pipeline connected to a Columbia Pipeline and East
Slide 151: CNX Baltimore Terminal
Monetization of Non-Core Assets CNX Baltimore Terminal Located on 200 acres in the Port of Baltimore Only east coast terminal served by two rail lines (NS & CSX) Operational 24/7, 363 days a year Exported 35.8 million tons to 21 countries in the past three years 10.2 million tons exported
Slide 152: WV JV Development/Land Sales
Monetization of Non-Core Assets WV JV Development/Land Sales Mon-View project expected to generate >$30 million for CONSOL 152
Slide 153: Financial Overview
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Slide 154: Driving Down Our Cost of Capital
Financial Overview Driving Down Our Cost of Capital Sound investment philosophy: - Within our geographic footprint - Focus on strengthening our asset base for the long term - Improve efficiencies, lower capital intensity, and raise project rates of returns Managing our growth profile and risks a
Slide 155: Capital and Cash Flows
Financial Overview Capital and Cash Flows Cash Flow and Capital Ranges CF Range Capex Range Series7 CF CAGR $2,400 $2,200 $2,000 $1,800 $MM $1,600 Cash Flow CAGR: 11% $1,400 $1,200 $1,000 2014E 2015E 2016E Cash flow range projection based on assumptions and sensitivities to forecasted sales volumes,
Slide 156: Disciplined Investment Approach
Financial Overview Disciplined Investment Approach Coal: Shifted into maintenance mode after strong historical investment Invested $2.1 billion over the past 8 years - Organic coal capacity vs. acquisitions (BMX, Amonate, WAE) - Efficiency projects improve safety with expected 25% IRR Average ma
Slide 157: Historical F&D Costs
Financial Overview Historical F&D Costs Net Sales Volume Produced (in Bcf) 200 172.4 153.5 156.3 150 127.9 94.4 100 50 - 2009 2010 2011* 2012 2013 Proved Reserves (in Bcfe) 5,731 6,000 3,732 3,993 4,000 3,480 1,911 2,000 - 2009 2010 2011* 2012 2013 Drill Bit F&D Costs (in $/Mcfe) $1.00 $0.75 $0.47 $
Slide 158: Positive Capital Efficiency Trends
Financial Overview Positive Capital Efficiency Trends Improving Recycle Ratios Recycle Ratio 6.00 Investment cycle shifting to cash generation Liquids uplift 4.20 4.13 3.95 4.00 Improving economics through RCS/SSL and declining capital costs Carry impacts Midstream potential 2.00 1.42 - Hi
Slide 159: Ample Funding Tools
Financial Overview Ample Funding Tools Coal production stream: fully-capitalized and 25-year life Two JV-carried interests: Marcellus = $1.8B and Utica = $0.2B Non-core asset sales: estimated between $0.1-$0.3B/Year Infrastructure assets: 2 midstream assets, processing plants, and coal termi
Slide 160: MLP Formation Rationale
Financial Overview MLP Formation Rationale Premium valuation: assets within the MLP structure typically trade at higher valuations than those of their publicly-traded parent Broad and efficient access to capital: public trading allows the MLP to raise funds from a broader range of investors; MLP
Slide 161: CONE Asset Overview
Financial Overview CONE Asset Overview Over $400 million capital investment in gathering and processing systems Rapid organic volume growth through existing systems Ongoing development of new systems to support E&P’s projected growth Systems located on stacked pays with close proximity to pr
Slide 162: Joint Ventures
Financial Overview Joint Ventures Summary of JV Carry Eligible Capital Description Marcellus / Noble Energy Inc. Utica / Hess Corporation Ownership 50/50 50/50 (1) (2) Acreage 345,151 68,488 Zones PA and WV Marcellus, Burkett to Onondaga OH Utica Noble to pay 1/3 of CNX 50% share of eligible charges
Slide 163: Financial Overview: Cost of Equity
Financial Overview: Cost of Equity 163
Slide 164: Beta Declining While Stock Recovering
Financial Overview: Cost of Equity Beta Declining While Stock Recovering 1 Yr Beta (Daily Returns) Index Stock Price Index Indexed to Oct 28 2009-Oct 27 2010 Time Period Indexed to Oct 28 2009-Oct 27 2010 Time Period CNX Coal Peer Avg Gas Peer Avg CNX Coal Peer Avg Gas Peer Avg 1.4 2.0 1.2 1.5 1.0 I
Slide 165: Meeting or Exceeding Guidance
Financial Overview: Cost of Equity Meeting or Exceeding Guidance Gas Guidance and Production With the sale of the 5 mines, CONSOL increased Guidance Range Actual Production 60 its focus on growing our E&P production 55 Our lean manufacturing concept will improve our 50 cycle times and provide mo
Slide 166: Declining E&P Unit Costs
Financial Overview: Cost of Equity Declining E&P Unit Costs Driving Down Weighted Average Cost: Consolidated Cost per Mcfe Property & Other Taxes Direct Admin, Selling & Other Total operating cost per Mcfe expected to decline LOE Gathering and Transportation 5% to 10% over the next three years DD&
Slide 167: Ability to Maintain Low Unit Costs
Financial Overview: Cost of Equity Ability to Maintain Low Unit Costs Reducing Bailey Complex Average Cost: Bailey Complex Production Cost Ranges per Ton Cash Cost Range Total Cost Range Fully loaded and cash costs per ton $50 in 2014 improved to $43.68 and $34.95, respectively $45 Overall steam
Slide 168: Commodity Risks and Market Analysis
Financial Overview: Cost of Equity Commodity Risks and Market Analysis Market Definition Market Drivers Scope: The natural gas, thermal and metallurgical coal markets Supply: Domestic production are analyzed in the context of general economic drivers as well as and net imports those specific to thei
Slide 169: Commodity Interrelationships
Financial Overview: Cost of Equity Commodity Interrelationships Residential Domestic and Domestic and Global Commercial Global Power Steel Markets Industrial Markets Natural Gas Thermal Coal Metallurgical Coal CNX EBITDA Shifting Fast Towards E&P 2013 2014E 2016E E&P 32% Coal 37% Coal 47% E&P 53% E&
Slide 170: U.S. Electric Generation Mix
Financial Overview: Cost of Equity U.S. Electric Generation Mix Net Generation Mix United States Coal Natural Gas Uranium Other 50% 40% As gas prices rise above historic lows, coal generation ramps up in the near-term 30% 20% 10% - 2010 2014 2015 2019 2020 2011 2012 2013 2016 2017 2018 Natural Gas D
Slide 171: Managing Commodity Price Risk
Financial Overview: Cost of Equity Managing Commodity Price Risk Revenue and Cash Flow Risks: Value at Risk (VaR): CONSOL’s revenues and cash flows are derived from • Statistical risk management tool that calculates: three main products with price volatility 1. An asset’s greatest expected price l
Slide 172: VaR, Company Portfolio
Financial Overview: Cost of Equity VaR, Company Portfolio One month Value at Risk, 95% Confidence Interval Natural Gas Thermal Coal Metallurgical Coal Nat Gas VaR Thermal VaR Met Coal VaR CNX Unhedged Portfolio VaR CNX Hedged Portfolio VaR CNX Hedged Portfolio (2.4%) Risk reduction achieved through
Slide 173: Hedge and Coal Contract Program
Financial Overview: Cost of Equity Hedge and Coal Contract Program Hedge Program: Program Hedge: Program and actively monitored hedges Protect margins on 90% of our Proved Developed Production Reducing the total portfolio VaR including coal Use a program approach to layering on - Protect cas
Slide 174: Hedge Program
Financial Overview: Cost of Equity Hedge Program Actively Monitored Hedge: 2014 Competitor and CNX Hedge Positions Swaps Collars Priced Coal 100% 91% Actively monitor the market to add hedges 88% that meet margin goals 78% 74% 80% 72% Use swaps and collars 7% 60% 53% 75% Add basis hedges when
Slide 175: Financial Overview: Cost of Debt
Financial Overview: Cost of Debt 175
Slide 176: Legacy Liability Outlook
Financial Overview: Cost of Debt Legacy Liability Outlook Annual employee legacy liabilities cash servicing cost expected to decrease over time at approximately 5.5% per annum 0.25% increase in discount rate affects liability balance by ($36) and annual expenses incurred by ($5) 0.25% decrease
Slide 177: Debt Profile
Financial Overview: Cost of Debt Debt Profile Refinanced $1.5B of Senior Notes: Recently lowered cost of debt capital on ~49% of total long-term-debt by over 2%, from 8.000% to 5.875% Lowered cost of publicly traded debt by over 1%, to 6.837% from 7.895% Pushed out maturity from 2017 until 202
Slide 178: Debt Capacity and Philosophy
Financial Overview: Cost of Debt Debt Capacity and Philosophy CNX Forecasted Debt/EBITDA Debt/EBITDA Consolidated 6x CNX Debt/EBITDA High & Low Range Moody's Ratio From the Moody’s report dated February 14, 2014: 4x “The negative outlook reflects our expectation that Target Zone (2.0x – 3.0x) the
Slide 179: Finance Summary
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Slide 180: Reducing the Total Cost of Capital
Financial Summary Reducing the Total Cost of Capital Coal Business WACC Gas Business WACC Consolidated WACC 13% 2013 Cost of Capital Reduction Sale of Northern WV Thermal Mines Released $2.05B employee benefit/pension obligation Received $825MM net cash proceeds 12% Increased weighting of lowe
Slide 181: Reducing Risk and Increasing Valuation
Financial Summary Reducing Risk and Increasing Valuation We have a strong asset base and powerful planning and investing processes to manage our growth, reduce risk, and ultimately drive improving value for both our debt and equity stakeholders We are prepared to drive margin expansion and profi
Slide 182: Appendix
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Slide 183: Non-GAAP Reconciliation
Appendix Non-GAAP Reconciliation Three Months Ended June 30 ($ in thousands) 2014 2013 Net Income Attributable to CONSOL Energy Inc. Shareholders ($24,935) ($12,526) Less: Net (Income)/Loss Attributable to Discontinued Operations, net of tax -- 21,375 Add: Interest Expense 64,211 54,517 Less: Intere
Slide 184: Non-GAAP Reconciliation
Appendix Non-GAAP Reconciliation CONSOL Energy Continuing Ops ($ in millions) 2011 2012 2013 2013 Net Income Attributable to CONSOL Energy Inc. Shareholders $632 $388 $660 $81 Add: Interest Expense $248 $220 $219 $219 Less: Interest Income (9) (29) (16) (16) Add: Income Taxes 155 109 357 (33) Add: L
Slide 185: Standardized Measure of Discounted Future Net Cash Flows
Appendix Standardized Measure of Discounted Future Net Cash Flows: CONSOL Energy December 31, December 31, ($ in thousands) (1) 2013 2012 2011 2013 Future cash inflows $24,169,530 $21,602,594 $11,777,550 $14,804,398 Future production costs (7,275,402) (7,105,962) (4,823,670) (5,262,635) Future devel