Scotia Howard Weil 2016 Energy Conference March 21-23, 2016 - - PowerPoint PPT Presentation

scotia howard weil 2016 energy conference
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Scotia Howard Weil 2016 Energy Conference March 21-23, 2016 - - PowerPoint PPT Presentation

Scotia Howard Weil 2016 Energy Conference March 21-23, 2016 Cautionary Language This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of


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Scotia Howard Weil 2016 Energy Conference

March 21-23, 2016

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Cautionary Language

2

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

  • perations, 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, 2015 filed with the Securities and Exchange Commission (SEC), as updated by any subsequent quarterly reports on Form 10-Qs. The forward-looking statements in this presentation speak

  • nly 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

  • therwise, 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.

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3

Company Overview

Transformative Journey

Twelve years ago – traditional coal producer, the largest underground producer in the world

Ten years ago – created CNX Gas

Six years ago – acquired Dominion Resources’ Appalachian E&P business and became a coal company with a growing natural gas business

Late 2013 – transaction with Murray Energy Corp. that transitioned half of coal assets and related assets

April 19, 2014 – CONSOL Energy 150th Anniversary

June 12, 2014 – Analyst Day to roll out growing Appalachian E&P Division with best in class coal assets

September 25, 2014 – IPO of CONE Midstream Partners LP (NYSE: CNNX)

July 1, 2015 – IPO of CNX Coal Resources (NYSE: CNXC)

July 28, 2015 – Announced first PA Dry Utica well (Gaut 4I) result in Westmoreland County

February 29, 2016 – Announced agreement to sell Buchanan Mine and associated met reserves

We are a growing E&P company focused on developing the Appalachian shale with the benefit of fully capitalized, premier coal assets to help fund E&P growth

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Key Takeaways

4

  • 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

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5

  • ~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 12/31/2014.

Marcellus Shale

Overview: E&P Division

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SLIDE 6

6 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.

Utica Shale Overview: A Leading Position in the Utica Shale

Overview: E&P Division

  • ~622,000 CONSOL net

acres(1)

  • Over 3,000 gross locations

─ 8,082 ft average TIL

laterals in Q4 2015

─ 4 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

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SLIDE 7

$10 $15 $29 $44 $56 $0 $10 $20 $30 $40 $50 $60 FY 2012 FY 2013 FY 2014 FY 2015 Last Qtr Annualized

CONE Midstream's and Gathering's Pro Rata Net Income Contribution to CNX

CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's Net Income $50 $61 $17 $18

$10 $15 $34 $68 $79 $0 $20 $40 $60 $80 $100 FY 2012 FY 2013 FY 2014 FY 2015 Last Qtr Annualized

CONE Midstream's and Gathering's Pro Rata EBITDA Contribution to CNX

CNX Pro Rata Share of CONE Midstream Partners LP's Cash Distributions CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's EBITDA

 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

  • f Affiliates,” which in CNX’s consolidated financial

statements falls within the “Miscellaneous Other Income” line item

 Distributions run straight through CNX’s cash flow

statement in the “Return on Equity Investment” line item

 CNX has seen increasing benefit from CONE’s EBITDA and

cash distributions, on top of which CNNX recently increased its cash distribution 3.5% from 4Q15 run-rate

7

Overview: CONE’s Growing Cash Contribution

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. (in millions except for per unit amounts)

LP Units held by CONSOL Energy 19.1 Unit Price (as of close on 2.24.2016) $10.22 CNNX Units Equity Value to CONSOL Energy $195.2 CONSOL Energy's Ownership Interest in CONE Midstream Partners LP (CNNX:NYSE)

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E&P Division

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128 154 156 172 236 329 ~15% 50 100 150 200 250 300 350 400 450 2010 2011 2012 2013 2014 2015 2016E Bcfe Marcellus CBM Utica Other

E&P Division

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Production volumes CAGR of ~30% from 2013-2016 while operating expenses (excluding DD&A) declined 36% by 4Q15 from 4Q13

E&P Production Volumes

Gas Division Production Growth

Source: Company filings. Note: Acquired ~23 Bcfe of Conventional gas production from Dominion E&P in 2010. Divested ~11 Bcfe in 2011.

Production by Area 2015A 2016E Marcellus 51% 54% CBM 23% 19% Utica (Wet & Dry) 17% 21% Other 9% 6%

~$1,310 ~$1,240 ~$1,140 ~$850 2013 2014 2015 2016E

Marcellus CapEx ($) / Lateral Ft E&P Operating Expenses

100 120 140 160 180 200 220 240 260 2012 2013 2014 2015 2016E Peers CNX

$- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 Peer Average CNX CNX 2016E 2013 2014 YTD 2015

Indexed Production Growth

Source: Company filings. Note: Peers include AR, COG, EQT and RRC. 2016E per guidance as of 2/19/2016 Source: Company filings. Note: Operating Expenses excluding DD&A. Peers include AR, COG, EQT, RICE, RRC and SWN.

Note: Guidance as of 1/29/2016.

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10

2016 Planned E&P Activity Overview

E&P Activity Summary – 2016 Plan

E&P Division

Note: Guidance as of 1/29/2016. 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.

Drilled Uncompleted Inventory Drilled Completed Inventory 2016 Completions 2016 TIL Marcellus SW PA Operated 29 23 25 42 SW PA Non-Op 5 10

  • 10

WV Operated 7

  • WV Non-Op

49

  • Total Marcellus

90 33 25 52 Utica SW PA Operated

  • 1
  • 1

OH Operated 1 4

  • 4

OH Non-Op 11 4 6 10 Total Utica 12 9 6 15 CBM CBM Operated

  • 4

43 47 Total Gross Wells 102 46 74 114

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  • 50

23 5 71 ~378 329 50 100 150 200 250 300 350 400

2015 Production 2016 Base decline 2016: Gathering De- bottlenecking 2016: Non-Op (Ex NBL/HES)

  • Prod. Adds

2016: Production Adds 2016 Total Production

Bcfe

E&P Division

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2016 production growth primarily driven by wells’ productivity improvements, pipeline infrastructure debottlenecking projects and completion of inventory of drilled but uncompleted wells

Bridging to Growth

Note: Guidance as of 1/29/2016. Production volumes reflect the mid-point of their contribution to the 2016 production guidance ranges. Source: Company filings and estimates.

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12

Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth

E&P Division: Capital Expenditures

Revised planned 2016 E&P capital budget lower by $185 million

 Deferring activity, increasing capital efficiency

improvements and identification of additional de- bottlenecking activities

 Revised 2016 E&P capital budget of $205-$325

million, $185 million lower than previous guidance

  • f $400-$500 million at the midpoint (a 41%

reduction)

  • Drilling and Completion: $110-$210 million
  • 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

60% 17% 23% D&C Midstream Other

2016 E&P Capital Budget: $205-$325 Million

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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 RRC– Zahn #1 IP Gas: ~4,500 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 CHK– Hubbard 3H IP Gas: 11,00 Mcf/d IP Oil: 0 Bbl/d RRC Claysville Sportman’s Club IP Gas: 59 MMcf/d IP Oil: 0 Bbl/d EQT – Pettit Spud in Aug. 2015 13,400 ft. TVD; 4,000-4,500 ft. lateral CVX – Conner 6H IP Gas: 25,000 Mcf/d IP Oil: 0 Bbl/d Permits submitted for 2 add. laterals 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 – Stutzman 1-14 IP Gas: 21,000 Mcf/d IP Oil: 0 Bbd GPOR – Irons 1-4 IP Gas: 30,200 Mcf/d IP Oil: 0 Bbd CNX – Switz 6D 44.7 MMcf/d @ 6,835 psig 24-hr test rate MHR – Stalder 3UH IP Gas: 32,500 Mcf/d IP Oil: 0 Bbl/d MHR – Winland Pad IP Gas: 46,500 Mcf/d HGE – Whiteacre 2H IP Gas: 9,000 Mcf/d IP Oil: 0 Bbl/d Eclipse – Tippens 6H IP Gas: 30,000 Mcf/d IP Oil: 0 Bbl/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. GST – Simms Pad 4447' Lateral 1st 48 Hour Prod 29.4 MMcf/d IP 33 MMcf/d @ 9000psi SGY – Pribble 6US IP Gas: 30 MMcf/d IP Oil: 0 Bbl/d

Dry Utica is being aggressively tested in Northern WV and PA, where CONSOL holds 100% WI in approximately 503,000 net acres

Noble Energy/CNX – MND6 39.1 MMcf/d @ 7,126 psig 24-hr test rate CNX – GH9 61.9 MMcf/d @ 8,312 psig 24-hr test rate CNX – Gaut 4IH 61.4 MMcf/d @ 7,968 psig 24-hr test rate EQT – Scotts Run 24 Hour Prod 72.9 MMcf/d CHK – Messenger WTZ 3UH IP Gas: ~30 MMcf/d EQT – Big 190 Spud in Sept. 2015 12,700 ft. TVD; 3,500-4,000 ft. lateral Antero – Rymer 4HD 20 MMcf/d 20-day avg. rate

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14 Range Resources - Claysville Sportsman’s Club #1 IP Gas – 59.0 MMcf/d CONSOL GH9 24 hr IP – 61.9 MMcf/d @ 8,312 psig 6,141 ft. lateral

  • 100% WI and 96% NRI to CONSOL
  • TVD: 13,400’
  • Frac’d in Q4 2015
  • 24-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

Utica Shale: GH 9 Greene County, PA

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

EQT – Pettit Spud in Aug. 2015 13,400 ft. TVD 4,000-4,500 ft. 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).

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SLIDE 15

Utica Shale: Ohio Dry Gas

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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 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 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).

Recent nearby results have surrounded our contiguous Monroe County leasehold, which contains ~2.1 Tcfe of resource

MHR Stewart Winland Pad: 46.5 MMcf/d – Avg 24-hr rate ECR Shroyer 2-well pad (Utica): 7,819 – Avg later length 42.5 MMcf/d – Combined Rate CNX SWITZ 6 Pad (Utica) : 4 Utica Wells & 1 Marcellus CNX – Switz 6D: 24-hr test rate 44.7 MMcf/d @ 6,835 psi 9,761 ft. lateral CVX Conner well (Utica): 25.0 MMcf/d – Avg 24-hr rate GST Simms: 4,447' Lateral 1st 48 Hour Prod 29.4mm IP 33 MMcf/d @ 9000psi NBL / CNX MND 6H (Utica): 1 Utica Well 39.1 MMcf/d 24-hr IP @7,126 psi 9,345 ft. lateral

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5,000 10,000 15,000 20,000 25,000 20 40 60 80 100 120 Measured Depth (ft.) Days

Days vs. Depth

(Well in order of Horizontal TD Date)

Switz-6B-HSU Switz-6F-HSU Switz-6H-HSU Switz-6D-HSU Switz-16J-HSU $509.76 $540.17 $321.59 $344.98 $231.80 $0 $100 $200 $300 $400 $500 $600 Switz-6B-HSU Switz-6D-HSU Switz-6H-HSU Switz-6F-HSU Switz-16J-HSU Drilling Cost ($/ft.)

Switz Drilling Cost/Ft.

(In order by Tophole TD)

~55% Reduction in Drilling Costs

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Utica Shale: Monroe Cty, OH Cost Improvements

Accelerating rate of change in CONSOL’s efficiency improvements: drilling costs reduced by 55% in the Monroe County, OH between just the 1st Utica well to the 5th

~60+% Reduction in Days to Drill

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Targeting pipeline projects that access favorable markets at favorable rates

Will supplement direct FT with firm sales to customers that have matching firm capacity

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 long- term transportation costs and long-term financial obligations

Stacked pay opportunities will help optimize FT portfolio

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Gas Marketing

Firm Transportation

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

(1) Charts also include transportation under precedent agreements $0.25 $0.24 $0.28 $0.11 $0.11 $0.11 $- $0.10 $0.20 $0.30 $0.40 $0.50 2016 2017 2018 $/Dth

CNX's Firm Transportation Costs

  • Avg. Demand
  • Avg. Variable

$0.36 $0.35 $0.39

TETCO Dominion East Tennessee Columbia ANR NEXUS

  • 200

400 600 800 1,000 1,200 1,400 1,600 Jan 15 Jan 16 Jan 17 Jan 18 1000s MMBtu/day TETCO Dominion East Tennessee Columbia ANR NEXUS FT Capacities Pipeline (MMcf/d) YE 2015 YE 2018 ANR Pipeline 47 47 Columbia (TCO) 215 305 Dominion (DTI) 245 342 East Tennessee 282 202 Nexus

  • 150

TETCO 127 127 TETCO (via firm sales) 285 225 1,201 1,398

(1)

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18 (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.

Gas Hedges

Gas Marketing: Hedges

E&P Hedge Program:

  • Program and actively

monitored hedges

─ 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

  • Approximately 60% of total

FY 2016E production volumes hedged(2)

25 50 75 100 125 150 175 200 225 250 1Q16 FY 2016 FY 2017 FY 2018 Gas Volumes Hedged (Bcf) Physical Sales With Fixed Basis Exposed to NYMEX NYMEX Only Hedges Exposed to Basis NYMEX + Basis (1)

1Q16 FY 2016 FY 2017 FY 2018 NYMEX + Basis (1) Volumes (Bcf) 55.6 223.3 67.6 31.6 Average Prices ($/Mcf) $3.55 $3.28 $3.07 $2.90 NYMEX Only Hedges Exposed to Basis Volumes (Bcf)

  • 0.4

89.0 40.8 Average Prices ($/Mcf)

  • $3.58

$3.08 $3.17 Physical Sales With Fixed Basis Exposed to NYMEX Volumes (Bcf) 3.3

  • Average Hedge Basis Value ($/Mcf)

$0.31

  • Total Volumes Hedged (Bcf)(3)

58.9 223.7 156.6 72.4

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19

Coal Division

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81% 13% 6%

FY 2016E Sales Tons by Segment

PA Ops VA Ops Other

20

Coal Division: FY 2016 and FY 2017 Marketing Forecasts

Coal Division: Marketing Overview

2016E Coal Sales Facts and Goals

Contracted tons for 2016: 97%

  • Priced: 94%

~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

2017E Coal Sales Facts and Goals

Contracted tons for 2017: 59%

  • Priced: 40%

Note: PA Ops tons reflecting volumes at 100% interest and are not pro rata for CNX ownership of the PA Complex or CNXC. Coal sales guidance as of 1/29/2015. (1) Tons in millions.

Coal Sales Guidance(1) 2015A 2016E 2017E

PA Ops 22.9 22.0-26.0 25.0-27.0 VA Ops 4.4 3.5-4.2 3.7-4.2 Other 1.9 1.5-1.8 1.8-2.2

Total 29.2 27.0-32.0 30.5-33.4

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0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5 10 15 20 25

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) Sulfur (% as received) Production (million tons) 2015 Production - CNX/CNXC Assets 2015 Production - Other Longwalls 2015 Sulfur

Source: EIA 923, MSHA; Number of longwalls indicated in parentheses.

Not All NAPP Longwalls Are Created Equal

Coal Division

21

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.

Closed in 2015

Serve River Markets Primarily Met Coal Producer Mine Mouth Operations Near End of Reserve Life Higher Sulfur

Closed in 2015

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22

Financial

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23

Financial: Focused on Free Cash Flow

Solid liquidity position

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

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24

Debt and Liquidity Profile

Financial: Liquidity

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.

Goal to lower leverage ratio and increase liquidity over the next 18 months

CNX Consolidated CNXC: 100% CNX Attributable Capitalization and Liquidity 12/31/2015 12/31/2015 12/31/2015 Capitalization Cash and Cash Equivalents $73 $7 $66 Revolving Credit Facility Balance 1,137 185 952 Capital Lease Obligations 43

  • 43

Total Secured Debt $1,180 $185 $995 8.25% Senior Notes due 2020 $74

  • $74

6.375% Senior Notes due 2021 21

  • 21

5.875% Senior Notes due 2022 (1) 1,856

  • 1,856

8.0% Senior Notes due 2023 (1) 493

  • 493

Baltimore 5.75% Revenue Bonds due 2025 103

  • 103

Miscellaneous Debt 13

  • 13

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) 1,005 215 790 Total Liquidity $1,078 $222 $856

(5) Number of MLP units owned by CNX as of 12/31/2015 and unit prices as of market close on 2/18/2016. (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

  • f net letters of credit related to firm transportation obligations, mining equipment leases and insurance

policies.

CNX Onwed LP Units(5) Unit Price(5) Market Value CNX Coal Resources LP (CNXC:NYSE) 12.7 $6.69 $85 CONE Midstream Partners LP (CNNX:NYSE) 19.1 $10.28 $196 Total Equity Value of Ownership Interests in Affiliated Public MLPs $281 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 Equity Value of Ownership in Affiliated Public MLPs

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SLIDE 25

As of Period End: 12/31/2012 12/31/2013 12/31/2014 12/31/2015 12/31/2016E Legacy Liabilities ($MM) LTD $39 $20 $22 $20 $18 WC 180 85 90 83 86 CWP 184 121 126 123 120 OPEB 3,018 1,022 761 672 678 Salary Retirement/Pension 225 53 119 94 85 Asset Retirement Obligations 699 601 576 550 550 Total Legacy Liabilities $4,345 $1,902 $1,694 $1,542 $1,537 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

25

Significant Legacy Liability Reductions Over Past 3 Years

Financial: Legacy Liabilities

$4,345 $1,902 $1,694 $1,542 $1,537 $370 $148 $153 $137 $109 $100 $125 $150 $175 $200 $225 $250 $275 $300 $325 $350 $375 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 12/31/2012 12/31/2013 12/31/2014 12/31/2015 FY 2016E Annual Cash Servicing Cost Legacy Liabilities Projected $109MM Annual Cash Servicing Cost for FY 2016, a $28MM reduction from the year- end 2015 run-rate of $137MM

Flows through P&L in operating costs (impact reflected in

  • perating cost guidance)

Flows through P&L in Coal Division’s “Other Costs” Flows through P&L within: E&P–Operating Expense Coal Divisions–Other Costs

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SLIDE 26

26

  • 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 25th announced 3.6% increase to quarterly distribution to $0.2362 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 2016. 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

Plans and Goals Aligned to Drive Increased Valuation

We will continue to be focused on increasing shareholder value while staying within

  • ur core values of safety, compliance, and continuous improvement

Summary

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SLIDE 27

27

Appendix

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SLIDE 28

28

Appendix: Financial Guidance Summary

Note: Guidance as of 1/29/2016. (1) Represents estimated unutilized firm transportation and processing expense less estimated gathering revenue (resold firm transportation).

E&P Segment Guidance

Production Volumes: Natural Gas (Bcf) NGLs (MBbls) Oil (MBbls) Condensate (MBbls) Total Production (Bcfe) Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.35) - ($0.45) NGL Realized Price ($/Bbl) $7.00 - $9.00 Condensate Realized Price % of WTI 43%

  • 46%

Oil Realized Price % of WTI 93%

  • 95%

Capital Expenditures: Drilling and Completion $110

  • $210

Midstream 40

  • 50

Land and Other 55

  • 65

Total E&P and Midstream CapEx $205

  • $325

Average per unit operating expenses: Lease Operating Expenses 0.20

  • 0.25

Impact Fees/ Ad Valorem/ Production Taxes 0.06

  • 0.08

Gathering, Transportation, Compression & Processing 1.06

  • 1.10

Direct Administrative and Selling 0.08

  • 0.10

Depreciation, Depletion and Amortization 1.00

  • 1.07

Total Production and Gathering Costs 2.40

  • 2.60

Other Expenses: General and Administrative Expense $48.0 - $52.0 Unutilized Firm Transportation Expense, net:(1) $15.0 - $16.0

($ in millions) ($ in millions) ($/Mcfe)

2016E

335 6,000 65 1,000 ~+15%

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29

Appendix: Financial Guidance Summary

Note: Guidance as of 1/29/2016.

Coal Segment 2016E 2017E

Estimated Total Coal Sales Volumes 27.0

  • 32.0

30.5

  • 33.4

Total Committed Volumes (Contracted & Priced) 27.8 12.7 % Committed (Contracted & Priced) 94% 40% Estimated Total Average Price ($/Ton) $50.00 - $55.00 $50.00 - $55.00 Capital Expenditures: Production $140

  • $155

Other (Land/Water/Safety/Terminal) 30

  • 35

Total Coal CapEx $170

  • $190

Average per unit operating expenses: Total Production Costs (including DD&A) $41.50 - $45.00 Depreciation, Depletion and Amortization $6.50 - $7.00 Other Expenses: General and Administrative $20

  • $25

Total Coal Operations

(in millions of tons) ($ in millions) ($/Ton) ($ in millions)

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30

Non-GAAP Reconciliation: Quarter-over-Quarter EBITDA and Adj. EBITDA

Appendix

Source: Company filings.

Three Months Ended December 31 ($ in thousands) 2015 2014 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 207,940 132,247 Add: Depreciation, Depletion & Amortization 159,170 166,841 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

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31

Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA

Appendix

Source: Company filings.

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) 2015 2015 2015 2015 2015 Net Income / (Loss) $79,031 ($603,301) $125,470 $34,325 ($364,475) Add: Interest Expense $55,122 $46,507 48,558 49,082 199,269 Less: Interest Income ($1,143) ($364) (361) (431) (2,299) Add: Income Taxes (Benefit) (25,603) (291,929) 58,143 124,964 (134,425) Earnings Before Interest & Taxes (EBIT) from Continuing Operations 107,407 (849,087) 231,810 207,940 (301,930) Add: Depreciation, Depletion & Amortization $161,922 $166,798 $161,711 159,170 649,601 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
  • 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

  • 6,258

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 67,734 17

  • 67,751

Backstop Loan Fees

  • 7,334
  • 7,334

Other Transaction Fees

  • 4,968
  • 4,968

Total Pre-tax Adjustments 7,730 832,511 (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