Company Presentation Q4 2015

Transcription

1 Company Presentation Q4 2015

2 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 plans; estimates of coal and gas reserves and resources; the projected timing and rates of return of future investments; and projections and estimates of future production, revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially from those statements, plans, estimates and projections. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of future actual results. Factors that could cause future actual results to differ materially from the forward-looking statements include risks, contingencies and uncertainties that relate to, among other matters, the following: we may not receive the prices we expect to receive for our natural gas 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 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; 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, 2014 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 otherwise, we may be required to acquire property rights from third parties at our expense in order to effectively drill and produce the oil and gas rights we control and third parties may participate in the wells we drill, thereby reducing our working interest in those wells. This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CONSOL Energy Inc. or CNX Coal Resources LP. 2

3 Key Takeaways CONSOL Energy s E&P Division has demonstrated that it can stand on its own as a premier Appalachian Basin producer: Gas production has grown significantly Capital intensity and costs are down dramatically Dry Utica has opened up a new opportunity set Our base plan is achievable and will help us to more easily reach our free cash flow targets due to conservative plan assumptions: NYMEX strip gas pricing with conservative basis differentials Conservative thermal and met pricing CONSOL Energy s gas hedges and coal contract position significantly de-risk the business and support the company s organic FCF plan in 2016 CONSOL Energy s base plan, coupled with additional asset sales, will result in significant flexibility, including the ability, if appropriate, to separate its Coal and E&P divisions 3

4 Q Overview 4

5 Q Overview CONSOL Energy: Fourth Quarter 2015 Results Net income Attributable to CONSOL Energy Shareholders for the fourth quarter was $30.4 million - Includes the following pre-tax items: $109.9 million benefit related to changes in retiree medical OPEB plan $62.4 million unrealized gain on commodity derivative instruments 15.9 million in pension settlement expense $6.3 million in expenses for adjustment settlements related to the prior sale of CONSOL's industrial supply subsidiary, which closed during the fourth quarter of 2014 $7.6 million gain on the sale of non-core assets Q Summary Y/Y Q-to-Q Seq. Q-to-Q ($ in millions, except per share data) 4Q2015 4Q2014 Change 4Q2015 3Q2015 Change Net (Loss) Income Attributable to CNX Shareholders $30 $74 ($44) $30 $119 ($89) Earnings per Diluted Share $0.13 $0.32 ($0.19) $0.13 $0.52 ($0.39) Revenue and Other Income $762 $936 ($174) $762 $814 ($52) Net Cash Provided by Continuing Operations $102 $100 $2 $102 $110 ($8) Adjusted EBITDA Attributable to CNX Shareholders (1) $206 $273 ($67) $206 $136 $70 (1) Adjusted EBITDA is a non-gaap financial measure and a consolidated number, please refer to the reconciliation is provided in the Appendix. 5

6 Q Overview CONSOL Energy: Net (Decrease)/Increase in Cash E&P Division: production of Bcfe, up approximately 93.0 Bcfe from 2014, a 39.5% increase - Production volumes expected to grow approximately 15% in 2016 over Capital efficiency improvements, including lean manufacturing, enable grow with less capital 2016 E&P capital budget guidance of $205 $325 million - Continued implementation of zero-based budgeting reducing operating and overhead costs - Improvements in Appalachia takeaway infrastructure to lower basin differentials and improve realized prices - Goal is to maintain and improve our solid liquidity position Coal Division: - Pennsylvania Operations sales secured by agreements, with approximately 100% of projected volumes sold for FY 2016, based on the midpoint of the guidance range of million tons Cash Flow Summary Y/Y Q-to-Q Seq. Q-to-Q ($ in millions) 4Q2015 4Q2014 Change 4Q2015 3Q2015 Change Net Cash Provided by Operating Activities $102 $87 $15 $102 $110 ($8) Capital Expenditures ($127) ($319) $191 ($127) ($259) $132 Proceeds From Asset Sales $28 $216 ($188) $28 $76 ($49) Other Investing ($14) ($13) ($1) ($14) ($26) $12 Proceeds From /(Payments on) Short-Term Debt & Misc. Borrowings $9 ($6) $15 $9 ($149) $158 Proceeds From /(Payments on) Long-Term Debt (1) $180 ($180) Dividends Paid ($2) ($14) $12 ($2) ($2) ($0) Proceeds from the sale of MLP interest (CNXC IPO) $148 ($148) Other Financing ($5) $2 ($7) ($5) ($4) ($1) Net (Decrease) / Increase in Cash ($10) ($49) $39 ($10) $73 ($83) Source: Company filings. Sum of numbers may differ slightly from totals and financial statements due to rounding. (1) Approximately $180 million of 3Q 2015 Proceeds from LT debt is comprised entirely of CNXC LT revolver debt, consolidated on CNX financial statements per US GAAP accounting rules. 6

7 Q Overview Solid Liquidity Position of ~$856 Million Amount/ Amount Letters Amount December 31, 2015 ($ in million) Capacity Drawn of Credit Available Cash and Cash Equivalents (1) $ $66 Revolving Credit Facility (2) $2,000 $952 $258 $790 Total $2,066 $952 $258 $856 (1) Cash and cash equivalents on CNX s consolidated balance sheet was $73 million as of 12/31/2015, $7 million of which was CNXC s and consolidated in CNX s financial statements per US GAAP accounting (2) Revolving credit facility as of 12/31/2015 $2 billion Revolving Credit Facility: 5 year credit facility expires June 2019 Gas reserves based lending facility: Lending group reaffirmed CONSOL's $2 billion borrowing base in November Borrowing base is redetermined semi-annually in the Spring and Fall Obtained the right to separate the coal and gas business subject to a leverage test December 31, Negative Covenants Limit 2015 CONSOL Energy Revolver: Minimum Interest Coverage Ratio < 2.5 to to 1.0 Minimum Current Ratio < 1.0 to to 1.0 Ample liquidity of $856 million with business plans focused on positive free cash flow generation through 2016 and deleveraging the balance sheet 7

8 Q Overview E&P Division: Q Results Summary Y/Y Q-to-Q Seq. Q-to-Q E&P Division 4Q2015 4Q2014 Change 4Q2015 3Q2015 Change Average Sales Price (1) ($ / Mcfe) $2.78 $3.90 ($1.12) $2.78 $2.35 $0.43 Average Costs (2) ($ / Mcfe) $2.45 $3.19 ($0.74) $2.45 $2.63 ($0.18) Sales Volumes (Bcfe) Sales Volumes (Bcfe) by Category Marcellus CBM (1.3) Utica Other (1) Average Sales Prices for 4Q2015, 4Q2014 and 3Q2015 include gains on commodity derivative instruments (cash settlements) of $0.95, $0.39 and $0.60, respectively. (2) Average Costs for 4Q2015, 4Q2014 and 3Q2015 include DD&A of $1.05, $1.28 and $1.05, respectively. E&P Division s fourth quarter net income was $57.1 million - Production increased by 35% in the fourth quarter compared to year-earlier quarter - Due to depressed commodity prices, revenue decreased by $10.1 million in the fourth quarter, compared to the year-earlier quarter - Marcellus Shale all-in unit costs were $2.46 per Mcfe in the fourth quarter, a decrease of $0.37 from $2.83 per Mcfe in the year-earlier quarter, or a 13% improvement - Utica Shale production volumes were 20.7 Bcfe in the fourth quarter, a 194% increase from 7.1 Bcfe in the yearearlier quarter - Utica Shale all-in unit costs were $1.91 per Mcfe in the fourth quarter, a decrease of $0.33 from $2.24 per Mcfe in the year-earlier quarter, or a 15% improvement 8

9 Q Overview E&P Division: Q Operations Summary Sub- Regions Southwest PA Horizontal Rigs Drilled Completed Turned In Line (TIL) Avg. TIL Lateral Length (ft) Central PA Northern WV Dry Counties Greene, Washington, PA Indiana, Westmoreland, PA Barbour, Doddridge, Lewis, WV Ohio ,164 Monroe, OH North Wet Gas South Wet Gas Greene, Washington, PA; Marshall, WV Doddridge, Tyler, Ritchie, WV Total ,164 Strong production response from SWPA gathering system de-bottlenecking project: Marcellus Shale Quarterly Summary CONE de-bottlenecking efforts added ~2.7 Bcf in Q4 alone Optimizing high pressure and low pressure gathering systems Recent project added ~100 MMcf/d of additional capacity Optimized system to maximize production and overcome dew point constraints Utilize multiple sales points to optimize production Completion improvements 42% improvement in drillout time year over year Average days per well decreased by 10 days year over year Sub- Regions Horizontal Rigs Drilled Completed Turned In Line (TIL) Avg. TIL Lateral Length (ft) Counties Core Wet ,048 Noble, OH Surrounding Core Wet Utica Shale Quarterly Summary ,152 Harrison, Belmont, OH Dry Utica * Monroe, OH; Marshall, WV 8,375 Westmoreland, Greene, PA Total ,082 *Dry Utica TIL includes one JV well, MND6, located in Marshall County, WV SWITZ 6 Pad (4 Utica Laterals) averaged 109 MMcf/d during a 24 hour flowback period Accelerated Learning Curve PA Utica Completions (GH9 vs Gaut4I) 29% improvement in stimulation efficiencies $1.5 million in savings on equivalent size stages Successfully tested dissolvable plug technology on GH9 Utica, which resulted in a $250,000 savings 9

10 Q Overview Coal Division: Q Results Summary Y/Y Q-to-Q Seq. Q-to-Q Coal Division 4Q2015 4Q2014 Change 4Q2015 3Q2015 Change Average Sales Price ($ / ton) $52.37 $61.19 ($8.82) $52.37 $56.34 ($3.97) Average Costs ($ / ton) $41.97 $44.99 ($3.02) $41.97 $43.39 ($1.42) Coal Production (millions of tons) (1.8) (1.1) Sales Volumes (millions of tons) (1.5) (0.6) Sales Per Ton ($ / ton) Pennsylvania Operations $52.57 $60.10 ($7.53) $52.57 $56.99 ($4.42) Virginia Operations $48.41 $68.58 ($20.17) $48.41 $51.82 ($3.41) Other Operations $60.65 $59.38 $1.27 $60.65 $57.36 $

11 Q Overview Coal Division: FY 2016 and FY 2017 Marketing Forecasts FY 2016E Sales Tons by Segment 2016E Coal Sales Facts and Goals 13% 6% Contracted tons for 2016: 97% - Priced: 94% 81% PA Ops VA Ops Other ~96% of the PA Ops tons are expected to be sold domestically ~60%-65% of the VA Ops tons are expected to be sold overseas 100% of the Other tons are expected to be sold domestically Coal Sales Guidance (1) 2015A 2016E 2017E PA Ops VA Ops E Coal Sales Facts and Goals Contracted tons for 2017: 59% - Priced: 40% Other Total Note: PA Ops tons reflecting volumes at 100% interest and are not pro rata for CNX ownership of the PA Complex or CNXC. (1) Tons in millions. 11

12 E&P Division 12

13 E&P Division 2016 Planned E&P Activity Overview E&P Activity Summary 2016 Plan Drilled Uncompleted Inventory Drilled Completed Inventory 2016 Completions 2016 TIL Marcellus SW PA Operated SW PA Non-Op WV Operated WV Non-Op Total Marcellus Utica SW PA Operated OH Operated OH Non-Op Total Utica CBM CBM Operated Total Gross Wells Note: Average net revenue interest for Marcellus/Utica shales is 43.7%. Table includes two 100% CONSOL-owned wells: one dry Utica Shale well in Monroe County, Ohio; one dry Utica Shale well (GH9) in Greene County, Pennsylvania. Marcellus and Utica wells are horizontal wells, and CBM wells are primarily vertical wells. 13

14 Bcfe E&P Division Gas Division Production Growth E&P Production Volumes Production by Area 2015A 2016E ~15% Marcellus 51% 54% CBM 23% 19% Utica (Wet & Dry) 17% 21% Other 9% 6% E Marcellus CBM Utica Other Production volumes grew ~93 Bcfe in 2015, a 39.5% increase; ~15% year-over-year growth target for Source: Company filings. Note: Acquired ~23 Bcfe of Conventional gas production from Dominion E&P in Divested ~11 Bcfe in

15 Bcfe E&P Division Bridging to Growth 400 ~71 ~ ~104 ~ Total Production 2015 Base decline 2015: Gathering De-bottlenecking 2015: Non-Op (Ex NBL/HES) Prod. Adds 2015: Production Adds 2015 Total Production 2016 Base decline 2016: Gathering De-bottlenecking 2016: Non-Op (Ex NBL/HES) Prod. Adds 2016: Production Adds 2016 Total Production 2016 production growth primarily driven by wells productivity improvements, pipeline infrastructure debottlenecking projects and completion of inventory of drilled but uncompleted wells Note: Production volumes reflect the mid-point of their contribution to the 2015 and 2016 production guidance ranges. Source: Company filings and estimates. 15

16 E&P Division: Capital Expenditures Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth Deferring activity, increasing capital efficiency improvements and identification of additional debottlenecking activities Revised 2016 E&P capital budget of $205-$325 million, $185 million lower than previous guidance of $400-$500 million at the midpoint (a 41% reduction) - Drilling and Completion: $110-$210 million o Includes $10-$15 for coalbed methane (CBM) activity - Midstream of $40-$50 million (including approximately $22 million associated with CONE Midstream capital contributions) - Other activities (land, permitting, and business development): $55-$65 million 2016 E&P Capital Budget: $205-$325 Million 17% 23% 60% D&C Midstream Other Revised planned 2016 E&P capital budget lower by $185 million 16

17 E&P Division Utica Shale Overview: A Leading Position in the Utica Shale ~622,000 CONSOL net acres (1) Over 3,000 gross locations 87 wells online, as of 12/31/ wells TIL in Q ,082 ft average TIL laterals in Q wells per pad on average 120-acre spacing (assuming 7,000 ft lateral) EURs: Ohio Wet: 2.3 Bcfe EUR/1,000 ft of lateral Ohio Dry: 2.8 Bcfe EUR/1,000 ft of lateral PA/WV Dry: 3.0 Bcfe EUR/1,000 ft of lateral Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). Gross locations are as of 12/31/2014. (1) Comprised of ~119,000 net acres in Ohio Utica (~79,000 in the JV and ~40,000 non-jv) and ~306,000 and ~197,000 net prospective acres in PA and WV respectively. 17

18 E&P Division Utica Shale: PA/WV Dry Gas REXX Cheeseman 1 IP Gas: 9,200 Mcf/d IP Oil: 0 Bbl/d CHK Thompson 3H IP Gas: 6,400 Mcf/d IP Oil: 0 Bbl/d CHK Brown 10H IP Gas: 9,500 Mcf/d IP Oil: 0 Bbl/d HES NAC 3H-3* IP Gas: 11,000 Mcf/d IP Oil: 0 Bbl/d HES Potterfield 1H-17* IP Gas: 17,200 Mcf/d IP Oil: 0 Bbl/d RICE Bigfoot 9H IP Gas: 42,000 Mcf/d IP Oil: 0Bbd GPOR Irons 1-4 IP Gas: 30,200 Mcf/d IP Oil: 0 Bbd GPOR Stutzman 1-14 IP Gas: 21,000 Mcf/d IP Oil: 0 Bbd Noble Energy/CNX MND ,126 psig 24-hr test rate Eclipse Tippens 6H IP Gas: 30,000 Mcf/d IP Oil: 0 Bbl/d HGE Whiteacre 2H IP Gas: 9,000 Mcf/d IP Oil: 0 Bbl/d MHR Stalder 3UH IP Gas: 32,500 Mcf/d IP Oil: 0 Bbl/d MHR Winland Pad IP Gas: 46,500 Mcf/d Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). *Subsequently sold to Ascent Resources LLC. RRC Zahn #1 IP Gas: ~4,500 Mcf/d IP Oil: 0 Bbl/d CHK Hubbard 3H IP Gas: 11,00 Mcf/d IP Oil: 0 Bbl/d CNX Gaut 4IH ,968 psig 24-hr test rate RRC Claysville Sportman s Club IP Gas: 59 MMcf/d IP Oil: 0 Bbl/d CVX Conner 6H IP Gas: 25,000 Mcf/d IP Oil: 0 Bbl/d Permits submitted for 2 add. laterals EQT Pettit Spud in Aug ,400 ft. TVD; 4,000-4,500 ft. lateral EQT Scotts Run 24 Hour Prod 72.9 MMcf/d CNX Switz 6D ,835 psig 24-hr test rate CNX GH ,312 psig 24-hr test rate GST Simms Pad 4447' Lateral 1st 48 Hour Prod 29.4 MMcf/d IP psi SGY Pribble 6US IP Gas: 30 MMcf/d IP Oil: 0 Bbl/d CHK Messenger WTZ 3UH IP Gas: ~30 MMcf/d EQT Big 190 Spud in Sept ,700 ft. TVD; 3,500-4,000 ft. lateral Antero Rymer 4HD 20 MMcf/d 20-day avg. rate Dry Utica is being aggressively tested in Northern WV and PA, where CONSOL holds 100% WI in approximately 503,000 net acres 18

19 Utica Shale: Gaut 4IH Westmoreland County, PA CONSOL GAUT4IH 61.4 MMcf/d 24-hr IP 7,968 psi; 5,840 ft. lateral ~ 5,800 single lateral; 100% WI to CONSOL 30 stage completion 200 stages with 500k# proppant: 160k# 100 mesh + 200k # 40/80 ceramic + 140k# 30/50 ceramic Ready supply of water Production facilities and gathering system with available capacity Underutilized FT available Achieved Peak 24-hr rate of 61.4 MMcf/d in July 2015 CONSOL has over 110,000 acres of Utica leasehold in Westmoreland and Indiana Counties, PA Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). 19

20 Gas Rate (Mcf/d) Casing Flowing Pressure (psig) Utica Shale: Gaut 4IH Westmoreland County, PA Flow Rate MCf/Day Casing Pressure PSIG 30,000 25, ,000 15,000 10,000 5, /25/ /15/ /4/ /24/ /14/2015 1/3/2016 Conducted a Modified Isochronal Test with planned extended drawdown and build-up Results of test have provided reliable values for reservoir pressure, height, permeability and extent as well as well-spacing for future wells We are following a managed pressure drawdown where we are currently dropping pressure at psi/day The well has produced 1.26 Bcf in 60 days of operations while average flowing casing pressure is approximately 8,100 psi 20

21 Utica Shale: GH 9 Greene County, PA Range Resources - Claysville Sportsman s Club #1 IP Gas 59.0 MMcf/d EQT Pettit Spud in Aug ,400 ft. TVD 4,000-4,500 ft. lateral 100% WI and 96% NRI to CONSOL TVD: 13,400 Frac d in Q hour IP of 61.9 MMcf/d at 8,312 psi Drilled lateral length of 6,141 ft. Situated in existing Marcellus field Ready supply of water Production facilities and gathering system with available capacity EQT Scotts Run 24 hr IP 72.9 MMcf/d. 3,221 Treated interval. CNX s GH9 Utica well is less than 4 miles away from EQT s Scotts Run well CONSOL GH9 24 hr IP ,312 psig 6,141 ft. lateral CONSOL has ~84,000 net acres prospective for the Utica in the SWPA operating area, including ~58,000 net acres in Greene and Washington counties, PA Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). 21

22 Utica Shale: Ohio Dry Gas CNX Activity and Recent IP Rates In-and-Around Monroe County, OH GPOR Irons 1-4H (Utica): 30.3 MMcf/d Avg 24-hr rate CVX Conner well (Utica): 25.0 MMcf/d Avg 24-hr rate CNX SWITZ 6 Pad (Utica) : 4 Utica Wells & 1 Marcellus CNX Switz 6D: 24-hr test rate ,835 psi 9,761 ft. lateral NBL / CNX MND 6H (Utica): 1 Utica Well 39.1 MMcf/d 24-hr psi 9,345 ft. lateral ECR Shroyer 2-well pad (Utica): 7,819 Avg later length 42.5 MMcf/d Combined 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 day, peak test rates GST Simms: 4,447' Lateral 1st 48 Hour Prod 29.4mm IP psi MHR Stewart Winland Pad: 46.5 MMcf/d Avg 24-hr rate Recent nearby results have surrounded our contiguous Monroe County leasehold, which contains ~2.1 Tcfe of resource Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). 22

23 Utica Shale: Switz 6 Monroe County, OH CONSOL SWITZ 6 Pad (Utica): 4 Utica wells & 1 Marcellus well CNX Switz 6D: 24-hr test rate ,835 psig Remaining wells flowing back 4 Utica Wells and 1 Marcellus Well Avg. Utica Lateral Length = 8,821 Longest Utica Lateral = 10, % WI to CONSOL Tested 3 proppant types 350K 200 spacing Multi-Market availability Offset pad fully permitted with 5 wells CONSOL has over 13,000 contiguous acres of Utica leasehold in Monroe County, OH Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). 23

24 Gas Rate (Mcf/d) Flowing Casing Pressure (psig) Utica Shale: Switz 6D Monroe County, OH 50,000 40,000 The limited decline in flowing casing pressure bodes well for a strong stabilized production rate going forward Gas Rate Casing Pressure , ,000 10,000 Temporarily shut-in to flowback other wells on the SWITZ pad /13/ /14/ /15/ /16/ /17/ /18/ /19/ /20/2015 The Switz 6D well had a peak 24-hr IP of ~45 MMcf/d with an average flowing casing pressure of 6,835 psig, which is the 5 th highest IP in the Utica to date and the best in SE OH 24

25 Drilling Cost ($/ft.) Measured Depth (ft.) Utica Shale: Monroe Cty, OH Cost Improvements 0 Days vs. Depth (Well in order of Horizontal TD Date) 5,000 10,000 15,000 20,000 25,000 $600 $500 $400 $300 $200 $100 $0 Switz-6B-HSU Switz-6F-HSU Switz-6H-HSU Switz-6D-HSU Switz-16J-HSU Days $ Switz Drilling Cost/Ft. (In order by Tophole TD) $ $ ~55% Reduction in Drilling Costs ~60+% Reduction in Days to Drill $ $ Switz-6B-HSU Switz-6D-HSU Switz-6H-HSU Switz-6F-HSU Switz-16J-HSU Accelerating rate of change in CONSOL s efficiency improvements: drilling costs reduced by 55% in the Monroe County, OH between just the 1 st Utica well to the 5 th 25

26 Utica Shale: PA Utica D&C Cost Reduction Plan Waterfall Diagram - PA Dry Utica Drilling and Completion Costs Per Well Assume 7000' lateral on a development 4-well pad ($ in millions) $30.0 $25.0 $26.2 (8.2) $20.0 $15.0 (2.2) (0.4) (0.8) (1.2) (1.1) $12.4 $10.0 $5.0 $0.0 Prior AFE Per Well Drilling Efficiency Drilling Science Cost Casing Design Multi-Well Pad (4) Completion Design Proppant Optimization Development AFE Per PA Dry Utica: Drilling and Completion Cost Reductions Well (2) (3) Waterfall Chart Data (1) ($ in millions) Probability (3) Comments Prior Well Cost (2) $26.2 Initial - Drilling & Completion Cost on Gaut 4I Cost Reductions: Drilling Efficiency (8.2) High Elimination of non-productive time experienced on Gaut 4I; top down drilling saves mobilization/de-mobilization cost and time Drilling Science Cost (2.2) High Elimination of extensive science work conducted on Gaut 4I: geological evaluation - pilot hole, logging, plugback, etc. Casing Design (0.4) Medium Elimination of additional casing string not required by regulation Multi-Well Pad (4) (0.8) Medium Fixed costs shared across wells (ex. pad, mob./de-mob., containment); efficiencies of scale Completion Design (1.2) Medium Hybrid stage spacing; elimination of drill-out phase; utilization of normal dry gas flowback package Proppant Optimization (1.1) High Modification of proppant type (ceramic to resin); 3rd party chemicals; 25% reduction in gel use Total Reductions (3) (13.8) Development Well AFE (3) $12.4 High degree of confidence towards lowering D&C costs in the PA Dry Utica, similar to successful cost reduction efforts in the Marcellus; plans in place targeting more than a 50% reduction in D&C costs per well Notes: Numbers may not sum due to rounding. (1) Data reflects CONSOL Energy Inc. s estimated per well Authorization for Expenditure (AFE) for drilling, completion and associated costs in the Utica Shale and Point Pleasant intervals in SWPA. (2) Actual costs for Gaut 4IH well. Actual costs may vary from AFEs. (3) Estimated, actuals may vary. 26

27 Gas Marketing 27

28 Gas Marketing E&P Marketing Highlights Average gas price for the fourth quarter of 2015, including hedging, was a +$0.36 per MMBtu differential to NYMEX ($2.63 vs. $2.27); excluding hedging, gas price was $(0.54) per MMBtu below NYMEX ($1.73 vs. $2.27) Q saw one of the warmest starts to winter on record and the winter is projected to be 15% warmer than the prior year CONSOL basin exports are projected to increase approximately 73,000 Dth /day for FY 2016 over FY 2015 as TETCO s U2GC and TEAM OPEN projects were put into service in late 2015, increasing expected realizations by marketing gas to the higher priced Midwest and Gulf Coast markets CONSOL entered into ethane, propane, and butane sales agreements under which volumes will be shipped via Mariner East pipelines to the Marcus Hook Industrial Complex and ultimately exported to Europe The deals, the first of which is expected to commence later this quarter, are expected to yield price premiums compared with in-basin pricing and expose a portion of the company s LPG portfolio to Brent Crude linked pricing Q natural gas price reconciliation: Q4 Q3 Q2 Q1 Q4 NYMEX natural gas ($/MMBtu) $ 2.27 $ 2.77 $ 2.64 $ 2.98 $ 4.00 Average differential (0.54) (1.00) (0.68) 0.03 (0.84) BTU conversion (MMBtu/Mcf)* Gain on Commodity Derivative Instruments - Cash Settlements Realized gas price per Mcf $ 2.78 $ 2.46 $ 2.67 $ 3.58 $ 3.70 *Conversion factor

29 $/Dth 1000s MMBtu/day Gas Marketing Firm Transportation 1,600 Targeting pipeline projects that access favorable markets at favorable rates 1,400 1,200 ANR Columbia NEXUS Will supplement direct FT with firm sales to customers that have matching firm capacity 1, East Tennessee Dominion Working with marketing partners to monetize/utilize regionally underutilized capacity Near term, will optimize and/or release FT to enhance revenues Plan to selectively acquire firm capacity while minimizing longterm transportation costs and long-term financial obligations Stacked pay opportunities will help optimize FT portfolio $0.50 $0.40 $0.30 $0.20 $0.10 $- CNX's Firm Transportation Costs $0.36 $0.35 $0.39 $0.11 $0.11 $0.25 $0.24 $0.11 $ Avg. Demand Avg. Variable TETCO - Jan 15 Jan 16 Jan 17 Jan 18 TETCO Dominion East Tennessee Columbia ANR NEXUS (1) FT Capacities Pipeline (MMcf/d) YE 2015 YE 2018 ANR Pipeline Columbia (TCO) Dominion (DTI) East Tennessee Nexus TETCO TETCO (via firm sales) ,201 1,398 (1) Charts also include transportation under precedent agreements Low average demand costs of $0.24 to $0.28/Dth reflect a well balanced portfolio between in-basin/out-of-basin markets; minimum relative long-term financial risk 29

30 Gas Marketing Natural Gas Sales Midwest Dominion South TETCO M3 TCO Pool TETCO M2 East Tennessee TETCO WLA TETCO ELA Gas Sales CY 2016 Est. Columbia (TCO) 21% TETCO (M2) 20% TETCO (M3) 16% Dominion (DTI) 12% East Tennessee 10% TETCO ELA & WLA 8% Midwest (Chicago) 13% 100% Current sales portfolio of 100 active customers priced in seven index markets; actively negotiating with major Midwest, Gulf Coast and LNG customers Source: SNL Financial. 30

31 MMcf/d Gas Marketing Natural Gas Processing Contracted capacity meets current requirements Inlet wet gas volumes to processing plants were ~176 MMcf/d above CONSOL s aggregate minimum committed volume in Q Contracted Capacity at Processing Plants Maintained the flexibility to leave ethane in the residue gas stream Operational and contractual flexibility to potentially convert a portion of currently processed wet gas volumes to be marketed as dry gas volumes, which would lower processing fees and improve netbacks Jan-15 Jan-16 Jan-17 Jan-18 Note: We have processing capacity expansion rights of 110,000 Mcf/d Flexible contracts permit us to optimize the timing and volume of our flows 31

32 $ Billions FT Commitments as % of EV Gas Marketing: Firm Transport Asset or Liability? Total Off Balance Sheet Firm Transportation, Gathering and Processing Commitments $ % 180% $ % 160% $16.0 $14.0 $14.3 $ % 120% $12.0 $10.0 $8.0 71% Average: $6.3 Bn 70% 95% 100% 80% $6.0 $4.0 $2.0 $- 52% 36% $5.5 20% 19% $4.0 $4.6 $4.9 $2.0 $2.4 $1.1 CNX A B C D E F G H 60% 40% 20% 0% Short-term uplift in realizations can come at the expense of over-committing to expensive FT incurring long term off-balance sheet liabilities Notes: Peers include AR, CHK, COG, EQT, GPOR, RICE, RRC and SWN. Commitments are as of most recently provided company financial statements. 32

33 Gas Volumes Hedged (Bcf) Gas Marketing: Hedges Gas Hedges E&P Hedge Program: Program and actively monitored hedges Physical Sales With Fixed Basis Exposed to NYMEX NYMEX Only Hedges Exposed to Basis NYMEX + Basis (1) Program Hedge - protect margins on up to 90% of our Proved Developed Production Active Hedge Process - supplements program hedges up to 80% of our total production including proved undeveloped production Q16 FY 2016 FY 2017 FY 2018 Approximately 60% of total FY 2016E production volumes hedged (2) 1Q16 FY 2016 FY 2017 FY 2018 NYMEX + Basis (1) Volumes (Bcf) Average Prices ($/Mcf) $3.55 $3.28 $3.07 $2.90 NYMEX Only Hedges Exposed to Basis Volumes (Bcf) Average Prices ($/Mcf) - $3.58 $3.08 $3.17 (1) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements. (2) At the midpoint of production guidance. (3) Hedge positions as of 1/15/2016. Physical Sales With Fixed Basis Exposed to NYMEX Volumes (Bcf) Average Hedge Basis Value ($/Mcf) $ Total Volumes Hedged (Bcf) (3)

34 Gas Marketing Natural Gas Liquids, Oil, and Condensate Q Avg. NGL Barrel Composition Q liquids sold: 12.0 Bcfe Total weighted average price of liquids increased ~64% to $16.34 in Q from $9.99 in Q Liquids composed approximately 13% of Q production volumes, 12% of E&P sales revenue and 4% of total Company revenue N- Butane 18% I-Butane 9% Natural gasoline 15% Ethane 0% Propane 58% 4Q15 Actual (~100% Ethane Rejection) Average price realization (per Bbl): 2015 Q4 Q3 Q2 Q1 NGLs $14.16 $4.80 $12.48 $20.40 Oil $39.06 $54.18 $46.14 $47.82 Condensate $25.38 $27.84 $31.26 $20.82 I-Butane 3% N-Butane 6% Propane 22% Natural gasoline 5% Ethane 64% Maximum Ethane Recovery* Potential Scenario * Assumes 85% ethane recovery level CONE Gathering and Midstream systems provide CONSOL unique flexibility to either (a) blend in ethane to meet specifications, allowing for nearly 100% ethane rejection or (b) extract ethane when accretive 34

35 Coal Division 35

36 Coal Division High Quality, Low Cost Assets with Long Mine Life Pennsylvania ( PA ) Operations Virginia ( VA ) Operations Other Type of Coal Primarily Thermal Primarily Met Primarily Thermal Method 5 Longwalls and 1 Longwall System and Stripping Shovels and Continuous Mining Machines Continuous Mining Machines Front-end Loaders Seam Pittsburgh 8 Pocahontas 3 Upper Dorothy (Coalburg), Kittanning, Freeport, Coalburg Rider, Stockton and 5 Block Reserves (1) 785 MT 92 MT 115 MT Mine Life 25+ years 20+ years 20+ years Production Capacity 28 MMT 5.2 MMT 4 MMT 5-yr Avg Price: $111 Cash Margin per ton ($) 2 $ Margin 5-yr Avg Price: $64 $25-37 Margin 5-yr Avg Price: $67 $3-17 Margin $31.58 $35.25 $57.44 Bailey Buchanan Miller Creek 1 Based on end of year 2014 reserve estimate. 2 Cash cost per ton calculated as total cost per ton less DD&A per ton. 36

37 Coal Division Pennsylvania Mining Complex Pennsylvania mining complex consists of three like-new underground mines and related infrastructure with high-btu bituminous coal (785.6 million tons proven and probable (1) ) Train loadout facility (up to 9,000 tons per hour) with dual rail access with Norfolk Southern and CSX High-Btu bituminous thermal coal is primarily sold to utility companies in the eastern United States - 13,000 Btus per pound average gross heat content and 2.37% average sulfur content PA Mining Complex Baltimore Terminal Reserves are mined from the Pittsburgh No. 8 Coal Seam located in the Northern Appalachian Basin Five longwalls and 18 continuous mining sections Active Complex Port/Dock CNXC Customers Access to seaborne markets through CONSOL-owned Baltimore Marine Terminal for exporting thermal and metallurgical coal Mine Total Recoverable Reserves (tons) (1) Average Gross Heat Content (Btu/lb) (1) Average Sulfur Content (1) Annual Production Capacity (tons) (1) 2015 Production (tons) (1) _1.w or (NY0086JT) Bailey , % Enlow Fork , % Harvey , % Total , % (2) Illinois Basin 11, % (2) Other NAPP 12, % We couldn't fine the original artwork _Graphic.ai NY0086JT so we had to ungroup it and make the edits. Other Coal (3) MLPs 11, % (1) For the period ending and as of 12/31/2014. (2) Source: EIA. Represents average power plant deliveries for the twelve months ended 12/31/2014. (3) Source: Company filings from FELP, ARLP, WMLP and RNO. 37

38 CNX/CNXC Assets (5) Marion County (1) Monongalia County (1) Emerald (1) Federal (1) Harrison County (1) Mountain View (1) Leer (1) Marshall County (2) Cumberland (1) Century (1) Ohio County (1) Tunnel Ridge (1) Powhatan (1) Production (million tons) Sulfur (% as received) Coal Division Not All NAPP Longwalls Are Created Equal Production - CNX/CNXC Assets 2015 Production - Other Longwalls 2015 Sulfur Closed in Closed 2015 in Higher Sulfur Near End of Reserve Life Mine Mouth Operations Primarily Met Coal Producer Serve River Markets PA Mining Complex is uniquely positioned among NAPP longwall producers to provide sustained supply of high-quality coal to rail-served power plants in the eastern U.S. Source: EIA 923, MSHA; Number of longwalls indicated in parentheses. 38

39 Financial 39

40 Financial: Focused on Free Cash Flow Solid liquidity position CNXC and CONE Asset monetization program Reduction in legacy liabilities Guidance: Production, price realizations, operating and capital costs - Growing E&P production volumes - Reductions to operating and overhead costs - Reductions in E&P capital intensity Service cost deflation: beating expectations; improves capital spending efficiency Leverage in-place infrastructure Continue to high-grade development plan (Dry Gas Utica potential) - Steady coal production with lower cost base CONSOL remains focused on lowering costs and deleveraging the balance sheet through organic operations and potential asset sales 40

41 Financial: Liquidity Debt and Liquidity Profile CNX Consolidated CNXC: 100% CNX Attributable Capitalization and Liquidity 12/31/ /31/ /31/2015 Capitalization Cash and Cash Equivalents $73 $7 $66 Revolving Credit Facility Balance 1, Capital Lease Obligations Total Secured Debt $1,180 $185 $ % Senior Notes due 2020 $74 - $ % Senior Notes due % Senior Notes due 2022 (1) 1,856-1, % Senior Notes due 2023 (1) Baltimore 5.75% Revenue Bonds due Miscellaneous Debt Total Debt (2) $3,740 $185 $3,555 Net Debt (3) $3,667 $178 $3,489 Stockholders Equity $4,856 $154 $4,702 Total Capitalization $8,596 $339 $8,257 Liquidity Cash and Cash Equivalents $73 $7 $66 Revolving Credit Facility Capacity (4) 1, Total Liquidity $1,078 $222 $856 Equity Value of Ownership in Affiliated Public MLPs CNX Onwed LP Units (5) Unit Price (5) Market Value CNX Coal Resources LP (CNXC:NYSE) 12.7 $6.76 $86 CONE Midstream Partners LP (CNNX:NYSE) 19.1 $9.97 $190 Total Equity Value of Ownership Interests in Affiliated Public MLPs $276 Liquidity of Affiliated MLPs Total Facility Capacity Outstanding Balance Available Capacity Cash Total Liquidity of Affiliates CNX Coal Resources LP (6) $400 $185 $215 $7 $222 CONE Midstream Partners LP (6) $250 $57 $193 $1 $194 Total Liquidity of Affiliated Public MLPs $650 $242 $408 $8 $416 Leverage Ratio 12/31/2015 LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7) $1,028 LTM Bank Net Debt / Adj. EBITDA (7) 3.6x (5) Number of MLP units owned by CNX as of 12/31/2015 and unit prices as of market close on 1/22/2016. (6) CNX Coal Resources liquidity data is as of 12/31/2015 and CONE Midstream data is as of 9/30/2015. (7) Adjusted EBITDA Attributable to CNX Shareholders is a non-gaap financial measure and the reconciliation is provided in the Appendix. Bank methodology EBITDA equals Adjusted EBITDA of $793 million plus gain on sale of assets of $56 million, plus gain related to changes in retiree medical (OPEB) plan of $244 million, less the $94 million of CNXC EBITDA Attributable to CNX, plus the $51 million of CNXC cash distributions to CNX less $21 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 $3.555 billion, less $66 million cash on hand excluding CNXC s cash, $10 million of advance mining royalties, plus $191 million of net letters of credit related to firm transportation obligations, mining equipment leases and insurance policies. Goal to lower leverage ratio and increase liquidity over the next 18 months Note: Some numbers may not match exactly to financial statements due to rounding. (1) The 2022 and 2023 senior notes includes $6 million and $7 million of unamortized bond premium / discount, which will be amortized over the life of the notes, respectively. (2) Total Debt of $3.740 billion excludes total unamortized debt issuance costs of $33 million. (3) Net Debt equals Total Debt less Cash and Cash Equivalents. (4) As of 12/31/2015, CNX had approximately $952 million of borrowings and $258 million of outstanding letters of credit under its revolving credit facility, leaving approximately $790 million of availability. CNXC had $185 million outstanding on its revolving credit facility leaving approximately $215 million of availability. 41

42 Legacy Liabilities Annual Cash Servicing Cost Financial: Legacy Liabilities Significant Legacy Liability Reductions Over Past 3 Years $4,500 $4,000 $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $370 $4,345 $1,902 $1,694 $1,542 $1,537 $148 $153 Projected $107MM Annual Cash Servicing Cost for FY 2016, a $28MM reduction from the yearend 2015 run-rate of $137MM $137 $109 $375 $350 $325 $300 $275 $250 $225 $200 $175 $150 $125 $0 12/31/ /31/ /31/ /31/2015 FY 2016E $100 As of Period End: 12/31/ /31/ /31/ /31/ /31/2016E Legacy Liabilities ($MM) LTD Flows through P&L in operating $39 $20 $22 $20 $18 WC costs (impact reflected in CWP operating cost guidance) OPEB Flows through P&L in Coal 3,018 1, Salary Retirement/Pension Division s Other Costs Asset Retirement Obligations Flows through P&L within: Total Legacy Liabilities E&P Operating Expense $4,345 $1,902 $1,694 $1,542 $1,537 Coal Divisions Other Costs FY 2012 FY 2013 FY 2014 FY 2015 FY 2016E Total Annual Legacy Liabilities Cash Servicing Cost $370 $148 $153 $137 $109 Legacy liabilities reduced and cash servicing costs reduced by more than 60% since 2012, with further reductions expected going forward 42

43 Financial: CNX Coal Resources LP (CNXC:NYSE) CNXC: Organizational Structure and CNX Ownership CNXC owns a 20% undivided interest (1) in, and operational control over, CONSOL Energy s Pennsylvania mining complex (Bailey, Enlow Fork and Harvey mines) 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 CONSOL retained a 53.4% interest in the LP units and owns 100% of the GP, which has a 2% interest CONSOL Energy retained an 80% undivided interest in the Pennsylvania mining complex and owns 100% of CNXC s general partner, as well as the incentive distribution rights 80% undivided ownership interest CONSOL Energy Inc. ("CONSOL Energy") NYSE: CNX limited partner interest 100% ownership interest CNX Coal Resources LP NYSE: CNXC CNX Coal Resources GP LLC 2% general partner interest and IDRs Public limited partner interest CONSOL Energy's Ownership Interest in CNX Coal Resources LP (CNXC:NYSE) (in millions except for per unit amounts) Total LP Units held by CONSOL Energy 12.7 Unit Price (as of close on ) $6.76 CNXC Units Equity Value to CONSOL Energy $ % undivided ownership interest and management and control rights Pennsylvania mining complex Greenlight Capital CNXC is an avenue for CONSOL s transition to a pure play Appalachian Basin E&P Company (1) Unless otherwise specified, all figures relating to reserves and production of the Pennsylvania mining complex in this presentation are on a 100% basis. 43

44 Financial: CONE s Growing Cash Contribution CONSOL owns 32.1% of CONE Midstream Partners LP s (CNNX:NYSE) 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 (ownership structure detailed in Appendix) 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 (CNX:NYSE) and Noble Energy (NBL:NYSE) 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 $16 $12 $8 $4 $0 CONE Midstream's and Gathering's Pro Rata Net Income Contribution to CNX $4 $7 $10 $9 $8 $9 $13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's Net Income Net Income and EBITDA saw slight dips in 4Q14 and 1Q15 due to CNNX IPO costs and temporary operational impacts from the unusually cold winter. Subsequently, CONE has resumed its growth trend and action has been taken operationally to limit weather impact in the future. 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 3.5% from its prior run-rate CONSOL Energy's Ownership Interest in CONE Midstream Partners LP (CNNX:NYSE) (in millions except for per unit amounts) LP Units held by CONSOL Energy 19.1 Unit Price (as of close on ) $9.97 CNNX Units Equity Value to CONSOL Energy $190.4 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. $20 $16 $12 $8 $4 $0 $5 CONE Midstream's and Gathering's Pro Rata EBITDA Contribution to CNX $8 $11 $10 $13 $4 $9 $15 $4 $11 $19 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 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 $4 $15 44

45 Financial: Guidance Summary E&P Segment Guidance Production Volumes: Natural Gas (Bcf) NGLs (MBbls) Oil (MBbls) Condensate (MBbls) Total Production (Bcfe) 2016E 335 6, ,000 ~+15% Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.35) - ($0.45) NGL Realized Price ($/Bbl) $ $9.00 Condensate Realized Price % of WTI 43% - 46% Oil Realized Price % of WTI 93% - 95% Capital Expenditures: Drilling and Completion $110 - $210 Midstream Land and Other Total E&P and Midstream CapEx $205 - $325 Average per unit operating expenses: Lease Operating Expenses Impact Fees/ Ad Valorem/ Production Taxes Gathering, Transportation, Compression & Processing Direct Administrative and Selling Depreciation, Depletion and Amortization Total Production and Gathering Costs Other Expenses: General and Administrative Expense $ $52.0 Unutilized Firm Transportation Expense, net: (1) $ $16.0 Note: Guidance as of 1/29/2016. (1) Represents estimated unutilized firm transportation and processing expense less estimated gathering revenue (resold firm transportation). 45

46 Financial: Guidance Summary Coal Segment 2016E Total Coal Operations Estimated Total Coal Sales Volumes Total Committed Volumes (Contracted & Priced) 27.8 % Committed 94% Estimated Total Average Price ($/Ton) $ $55.00 Capital Expenditures: Production $140 - $155 Other (Land/Water/Safety/Terminal) Total Coal CapEx $170 - $190 Average per unit operating expenses: Total Production Costs (including DD&A) $ $45.00 Depreciation, Depletion and Amortization $ $7.00 Other Expenses: General and Administrative $20 - $25 Note: Guidance as of 1/29/

47 Financial: Summary Plans and Goals Aligned to Drive Increased Valuation Milestones: Improving E&P performance from high-grading activities, improving completion techniques, reducing cycle times, and service deflation Benefits from recent long-term contracting activities and operating cost reductions CONE MLP growth January 25 th announced 3.6% increase to quarterly distribution to $ per unit Positive initial operated Utica well results (Gaut 4IH, GH9, and Switz 6D) sets up future stacked pay opportunities - Continued focus on zero-based budgeting expecting significantly reduced costs and improved balance sheet - Improving price realizations anticipate excess Appalachian firm transportation capacity above production to drive narrowing basis by year-end This should help both natural gas and thermal coal prices. - Use of free cash flow and opportunistic asset sales to de-lever Our management team is motivated and incentivized long-term to increase return on capital employed and NAV/share We will continue to be focused on increasing shareholder value while staying within our core values of safety, compliance, and continuous improvement 47

48 Appendix 48

49 Appendix Non-GAAP Reconciliation: Quarter-over-Quarter EBITDA and Adj. EBITDA Three Months Ended December 31 ($ in thousands) Net Income $34,325 $73,666 Add: Interest Expense 49,082 53,025 Less: Interest Income (431) (476) Add: Tax Valuation Allowance 65,395 - Add: Income Taxes (Benefit) 59,569 6,032 Earnings Before Interest & Taxes (EBIT) from Continuing Operations 207, ,247 Add: Depreciation, Depletion & Amortization 159, ,841 Earnings Before Interest, Taxes and DD&A (EBITDA) $367,110 $299,088 Adjustments: OPEB Plan Changes (109,879) - Unrealized Gain on Commodity Derivative Instruments (62,388) - Pension Settlement 15,921 3,603 Industrial Supplies Working Capital Settlement 6,258 - Gain on sale of non-core assets (7,551) (19,830) Blacksville Fire Settlement - (9,750) Total Pre-tax Adjustments ($157,639) ($25,977) Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $209,471 $273,111 Less: Noncontrolling Interest* ($3,920) - Adjusted EBITDA Attributable to CONSOL Energy Shareholders $205,551 $273,111 Source: Company filings. 49

50 Appendix Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA Three Months Ended Three Months Ended Three Months Ended Three Months Ended Twelve Months Ended March 31 June 30 September 30 December 31 December 31 ($ in thousands) Net Income / (Loss) $79,031 ($603,301) $125,470 $34,325 ($364,475) Add: Interest Expense $55,122 $46,507 48,558 49, ,269 Less: Interest Income ($1,143) ($364) (361) (431) (2,299) Add: Income Taxes (Benefit) (25,603) (291,929) 58, ,964 (134,425) Earnings Before Interest & Taxes (EBIT) from Continuing Operations 107,407 (849,087) 231, ,940 (301,930) Add: Depreciation, Depletion & Amortization $161,922 $166,798 $161, , ,601 Earnings Before Interest, Taxes and DD&A (EBITDA) $269,329 ($682,289) $393,521 $367,110 $347,671 Adjustments: OPEB Plan Changes - (33,649) (100,947) (109,879) (244,475) Impairment of E&P Properties - 828, ,905 Unrealized Gain on Commodity Derivative Instruments (60,004) 24,936 (99,138) (62,388) (196,594) Pension Settlement - - 3,132 15,921 19,053 Industrial Supplies Working Capital Settlement ,258 6,258 Gain on Sale of Non-core Assets - - (48,468) (7,551) (56,019) Severance Payments - - 7,683-7,683 Loss on Debt Extinguishment 67, ,751 Backstop Loan Fees - 7, ,334 Other Transaction Fees - 4, ,968 Total Pre-tax Adjustments 7, ,511 (237,738) ($157,639) $444,864 Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $277,059 $150,222 $155,783 $209,471 $792,535 Less: Noncontrolling Interest* - - (6,490) ($3,920) ($10,410) Adjusted EBITDA Attributable to CONSOL Energy Shareholders $277,059 $150,222 $149,293 $205,551 $782,125 Source: Company filings. 50

51 Appendix Joint Ventures Summary of JV Carry Eligible Capital Description Marcellus / Noble Energy Inc. Utica / Hess Corporation Ownership 50/50 50/50 (1) (2) Acreage 349,541 79,266 Zones PA and WV Marcellus, Burkett to Onondaga OH Utica Carry Noble to pay 1/3 of CNX 50% share of eligible charges Maximum annual payment of $400 million per year Henry Hub spot price averages over $4.00 per month for three consecutive months Hess to pay 50% of CNX 50% share of eligible charges (i.e. CNX pays 25%) Total carry amount $1.85 billion, of which $1.62 billion remains as of end of 4Q15 (3) (3) $335 million, of which ~$2 million remains as of end of 4Q15 Carry eligible* Capital - D&C, facilities, site construction Capital - D&C, facilities, site construction, seismic Non-carry eligible (pay straight WI %) LOE, leases, delay rentals, seismic LOE, leases, delay rentals (1) CONSOL holds ~86,387 net acres outside of the Marcellus JV. As of 12/31/2015. (2) CONSOL holds ~40,052 net acres outside of the Utica JV, which includes ~13,000 net acres in Monroe County, OH. As of 12/31/2015. (3) The remaining carry balance on a cash basis is $1.62 billion for Marcellus and $22 million for Utica, respectively. Utica carry has an accrued cash balance of $21 million as of end of 4Q

52 Appendix Marcellus Shale: Overview ~436,000 CONSOL net acres ~88% NRI ~91% HBP 23.9 Tcfe 3P Over 8,900 gross potential wells (1) Marcellus production grew at a 71% CAGR from 2013 to 2015 Producing Pads Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/

53 Appendix Marcellus Shale: Growth Runway and Depth of Inventory Marcellus Shale Upside Potential Total Gross Prospective Marcellus Acreage ~785,000 - Gross Acres within JV ~699,000 - Acres outside JV 100% CONSOL ~86,000 Acreage per well (assumed 750 ft spacing) ~86 Gross Producing wells (JV - YE2014) 384 Gross PDNP and PUD locations (YE2014) 828 Gross prospective unproved locations ~8,000 Producing wells as % of PDNPs, PUDs, and prospective locations 4% ~527 MMcfe/d net being produced from ~4% of net Marcellus acreage Note: Acreage as of December 31, 2015, locations as of December 31, 2014 unless otherwise noted. 53

54 Appendix Marcellus Shale: Sub-Regions Summary Marcellus Shale SWPA CPA WV Ohio (1) North Wet South Wet Total Net Acres ~44,000 ~108,000 ~111,000 ~14,000 ~52,000 ~107,000 ~436,000 Approximate Gross 800 2,000 2, ,400 2,200 ~8,900 Locations (2) Avg EURs/1,000 ft (Bcfe) Marcellus Shale is one of the main growth drivers of the E&P Division Note: Acreage as of December 31, 2015 and locations are as of December 31, 2014, unless otherwise noted. (1) Non-JV acreage is located in Monroe County, OH. (2) Based on 5,000 ft laterals with 86-acre spacing. 54

55 Appendix Marcellus Shale: Southwest PA Overview ~44,000 CONSOL net acres Over 800 gross locations (1) 189 wells online, as of 12/31/ wells TIL in Q wells per pad on average in Bcfe EUR/1,000 ft of lateral 750 ft inter-lateral spacing NV57 Pad 8 Wells 8,914 Avg Lateral Length per well 10,435 Mcfe Avg 30-day IP per well NV56 Pad 6 Wells 8,753 Avg Lateral Length per well 9,230 Mcfe Avg 30-day IP per well NV36 Pad 7 Wells 5,021 Avg Lateral Length per well 6,159 Mcfe Avg 30-day IP per well MOR10 Pad 6 Wells 4,771 Avg Lateral Length per well 6,341 Mcfe Avg 30-day IP per well Producing Pads Competitor Pads Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/

56 Appendix Marcellus Shale: North Wet Gas Overview ~52,000 CONSOL net acres Over 1,400 gross locations (1) 136 wells online as of 12/31/ wells TIL in Q wells per pad on average 1.8 Bcfe EUR/1,000 ft of lateral Increasing use of RCS/SSL 750 ft inter-lateral spacing Condensate yield: 5 Bbls/MMcf NGLs yield: 49 Bbls/MMcf SHL13 Pad 7 Wells 5,299 Avg Lateral Length per well 4,039 Mcfe Avg 30-day IP per well SHL23 Pad 5 Wells 7,245 Avg Lateral Length per well 6,620 Mcfe Avg 30-day IP per well WFN6 Pad 8 Wells 6,451 Avg Lateral Length per well 8.5 MMcf/d Avg 24-hour IP per well 6,800 MMcf/d 60-day IP per well WFN3 Pad 4 Wells 7,380 Avg Lateral Length per well 7,079 Mcfe Avg 30-day IP per well 4,800 MMcf/d 60-day IP per well Producing Pads Competitor Pads Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/

57 Appendix Marcellus Shale: South Wet Gas Overview ~107,000 CONSOL net acres Over 2,200 gross locations (1) 31 wells online, as of 12/31/ wells per pad on average 2.1 Bcfe EUR/1,000 ft of lateral 750 ft inter-lateral spacing Condensate yield: 10 Bbls/MMcf NGLs yield: 51 Bbls/MMcf PENS1 Pad 9 Wells ~6,824 Avg Lateral Length per well PENS2 Pad 12 Wells Currently under flowback OXF1 Pad 6 Wells ~6,353 Avg Lateral Length per well 5,517 Mcfe Avg 30-day IP per well SHR1 Pad 6 Wells ~8,741 Avg Lateral Length per well 10,143 Mcfe Avg 30-day IP per well WEESE (Triad Hunter) 3 Wells 3,711 Avg Lateral Length per well 530 MMcf/well 1st 6-Month Cum 2473 Bbl/well 1st 6-Month Cum DAVIES (EQT) 7 Wells 3,756 Avg Lateral Length per well 487 MMcf/well 1st 6-Month Cum 1562 Bbl/well 1st 6-Month Cum HARPER (EQT) 3 Wells 3,684 Avg Lateral Length per well 448 MMcf/well 1st 6-Month Cum 472 Bbl/well 1st 6-Month Cum Producing Pads Competitor Pads DTI Storage Fields Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/

58 Appendix Marcellus Shale: Northern WV Dry Overview ~111,000 CONSOL net acres Over 2,400 gross locations (1) 49 wells online, as of 12/31/ wells TIL in Q Bcfe EUR/1,000 ft of lateral 750 ft inter-lateral spacing AUD7 Pad 1 Well Delineation 9,745 Avg Lateral Length per well 7,120 Mcfe Avg 30-day IP per well ANDERSON (PDC Mountaineer) 3 Wells 4,859 Avg Lateral Length per well 595 MMcf/well 1st 6-Month Cum PHL10 Pad 6 Wells 4,636 Avg Lateral Length per well 3,148 Mcfe Avg 30-day IP per well PHL13 Pad 6 Wells 7,949 Avg Lateral Length per well 6,869 Mcfe Avg 30-day IP per well 923 MMcf/well 1st 6-month Cum AUD3 Pad 1 Well Delineation 8,691 Avg Lateral Length per well 6,099 Mcfe Avg 30-day IP per well 917 MMcf/well 1st 6-month Cum PHL4 Pad 3 Wells 6,533 Avg Lateral Length per well 5,212 Mcfe Avg 30-day IP per well 720 MMcf/well 1st 6-month Cum CENT3 Pad 1 Well Delineation 7,470 Avg Lateral Length per well 4,973 Mcfe Avg 30-day IP per well 635 MMcf/well 1st 6-month Cum Producing Pads Competitor Pads DTI Storage Fields Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/

59 Appendix Marcellus Shale: Central PA Overview ~108,000 CONSOL net acres Over 2,000 gross locations (1) 56 wells online, as of 12/31/ wells TIL in Q wells per pad on average 1.6 Bcfe EUR/1,000 ft of lateral 750 ft inter-lateral spacing SHAW Pad 3 Wells 3,965 Avg Lateral Length per well 7,817 Mcfe Avg 24-hr IP per well 523 MMcf/well 1st-4-month Cum COOK (Atlas/Chevron) 2 Wells 3,352 Avg Lateral Length per well 400 MMcf/well 1st 6-Month Cum CRAWFORD 5 Pad 2 Wells 7,305 Avg Lateral Length per well 13,586 Mcfe Avg 24-hr IP per well 624 Mmcfe/well 60 day Cum MARCHAND 3I Well 6,418 Lateral Length 735 Mmcfe 150 day Cum GAUT4 Pad 4 Wells 7,941 Avg Lateral Length per well 6,619 Mcfe Avg 30-day IP per well 759 MMcf/well 1st 6-month Cum KUHNS3 Pad 5 Wells 7,237 Avg Lateral Length per well 7,259 Mcfe Avg 30-day IP per well 937 MMcf/well 1st 6-month Cum MMS Pad 5 Wells 8,040 Avg Lateral Length per well 6,677 Mcfe Avg 30-day IP per well 636 MMcf/well 1st-4 month Cum SMITH (Atlas/Chevron) 2 Wells 2,680 Avg Lateral Length per well 722 MMcf/well 1st 6-Month Cum GREENAWALT (Chevron Appalachia) 3 Wells 3,725 Avg Lateral Length per well 800 MMcf/well 1st 6-Month Cum Producing Pads Competitor Pads Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/

60 Appendix Utica Shale: Growth Runway and Depth of Inventory Utica Shale Upside Potential Total Gross Prospective Utica Acreage ~701,000 - Gross Acres within JV ~158,000 - Acres outside JV 100% CONSOL ~543,000 Acreage spacing per well (assumed 750 ft spacing) ~86 Gross Producing wells (JV - YE2014) 44 Gross PDNP and PUD locations (YE2014) 88 Gross prospective unproved locations ~3,000 Producing wells as % of PDNPs, PUDs, and prospective locations ~1% ~1% of net Utica acreage developed to date Notes: PA and WV prospective Utica eastern boundary has yet to be delineated. Acreage is risked 50+% in PA and WV. Acreage in Ohio oil window is excluded after risking. Acreage as of December 31, 2015, locations as of December 31, 2014 unless otherwise noted. 60

61 Appendix Utica Shale: Sub-Regions Summary Utica Shale Ohio Wet Ohio Dry PA/WV Dry Total Net Acres ~89,000 ~30,000 ~503,000 ~622,000 Approximate Gross Locations (1) ,200 3,000 Avg EURs/1,000 ft (Bcfe) Potential resource of ~30 Tcfe Note: Acreage as of December 31, 2015, locations as of December 31, 2014 unless otherwise noted. 61

62 Appendix Utica Shale: Offset Peer Acreage ~622,000 CONSOL net acres in Utica ~306,000 net acres in PA ~197,000 net acres in WV 30,000 net acres in OH Dry ~14,000 net acres in Monroe County, OH 89,000 net acres in OH Wet Majority of acreage offset to peers with strong results The main area without offset results was Westmoreland County where CNX drilled the Gaut 4IH which had the 2 nd highest IP in the Utica to date Notes: CNX acreage position as of 12/31/2015. CNX acreage shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres. Source: Third party acreage positions based on GIS data from Western Land Services. 62

63 Appendix Utica Shale: CNX Acreage Position in the Core OH Wet Gas Utica ~85,000 CONSOL net acres ~34,000 CONSOL net acres in core Type curve reflects core area GPOR - Boy Scout 33H IP GAS: 5,300 Mcf/d IP OIL: 1,560 Bbl/d CHK - Buell 8H IP GAS: 9,500 Mcf/d IP OIL: 1,425 Bbl/d HES Cadiz A IP GAS: 8,006 Mcf/d IP OIL: 399 Bbl/d ~34,000 net core wet acres HES Cadiz B IP GAS: 10,254 Mcf/d IP OIL: 191 Bbl/d HES Athens A IP GAS: 7,745 Mcf/d IP OIL: 330 Bbl/d Over 500 gross core area locations (1) 87 wells online, as of 12/31/2015 GPOR - Wagner 1-28H IP GAS: 14,000 Mcf/d IP OIL: 432 Bbl/d GPOR - Shugert 1-12H IP GAS: 28,500 Mcf/d IP OIL: 300 Bbl/d 14 wells online in Q ,082 ft average laterals in Q wells per pad on average 2.1 Bcfe EUR/1,000 ft of lateral RCS/SSL standard for new drills 750 ft inter-lateral spacing AR - Miley 5HA IP GAS: 7,700 Mcf/d IP OIL: 1,285 Bbl/d REXX - Guernsey 2H IP GAS: 8,082 Mcf/d IP OIL: 564 Bbl/d GPOR - Irons 1-4H IP GAS: 30,200 Mcf/d IP OIL: 0 Bbl/d CNX - NBL 16A IP GAS: 12,000 Mcf/d IP OIL: 750 Bbl/d CNX - NBL 18 IP GAS: 8,213 Mcf/d per well IP OIL: 834 Bbl/d per well CNX - NBL 30 IP GAS: 9,481 Mcf/d per well IP OIL: 723 Bbl/d per well CNX - NBL 19 IP GAS: 13,400 Mcf/d per well IP OIL: 938 Bbl/d per well CNX - NBL 16B IP GAS: 5,630 Mcf/d IP OIL: 522 Bbl/d 17% of liquid hydrocarbon sweet spot controlled by CONSOL JV Note: Peer data based on publicly available information. CONSOL wells are 24-hour IP rates. Other producers IP rates may be different. Townships shown in yellow where CONSOL holds 63 3,000 or more acres (as of 12/31/2015).

64 Appendix Stacked Pay Potential: Appalachian Shale Acreage P a y Formation Name Rhinestreet Shale Wet Net Acres Dry Net Acres Total Net Acres Cashaqua Shale Upper Devonian 190, , ,000 Middlesex Shale West River Shale Burkett Shale Tully Limestone Hamilton Shale Marcellus Shale Onondaga Limestone Marcellus 173, , ,000 Utica Shale Utica (1) 89, , ,000 Point Pleasant Shale Trenton Total 0 GR 400 LITHOLOGY Limestone 452, ,000 1,403,000 Stacked pays provide a large inventory and rich opportunity set (1) Dry Utica includes 503,000 net prospective acres in Pennsylvania and West Virginia. As of December 31,

65 Appendix CONE Corporate Structure Source: CONE Midstream Partners LP. 65

66 Appendix Coal Division: Low-cost, Highly Productive Longwall Mining Operations The design of the Pennsylvania mining complex is optimized to produce large quantities of coal on a cost efficient basis. Pittsburgh No. 8 coal seam is a large, continuous formation of uniform, high-btu thermal coal that is ideal for high productivity, low-cost longwall mining operations Average Cash Margin ($ /ton) $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 During 2014, the PA mining complex generated the highest cash margin of any of its coal peers (1)(2) $25.27 $11.80 Advantaged Coal Characteristics (btu/lb) 14,000 12,000 CNXC (1) Other (2) NAPP Other Coal MLPs (1) ILB CNXC (2) Other Coal MLPs (1) ILB (1) Other NAPP 3.60% 3.20% 2.80% 2.40% 2.00% $0.00 Longwall Mining PA Mining Complex Other Coal MLP's (incl. transp. cost) (1)(2) 1.60% 10, % (1) PRB 0.80% 0.40% 8,000 Btu Content Sulfur Content 0.00% Highly automated and technologically advanced underground mining operation (1) Includes FELP, ARLP, RNO and WMLP as reported in the respective 10-K filings. (2) Including transportation costs for FELP. 66