Company Presentation
Q1 2016
Company Presentation Q1 2016 Cautionary Language This presentation - - PowerPoint PPT Presentation
Company Presentation Q1 2016 Cautionary Language This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended). Statements
Q1 2016
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This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended). Statements that are not historical, are forward-looking, and include our operational and strategic plans; estimates of coal and gas reserves and resources; the projected timing and rates of return of future investments; and projections and estimates of future production, revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially from those statements, plans, estimates and projections. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of future actual results. Factors that could cause future actual results to differ materially from the forward-looking statements 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
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; with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC - disruption to our business, including customer, employee and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating results; and
Factors" in CONSOL Energy Inc.’s annual report on Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission (SEC), as updated by any subsequent quarterly reports on Form 10-Qs. The forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We may use certain terms in this presentation, such as EUR (estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these estimates may be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is customary in the gas industry, prior to the commencement of gas drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. As a result of our title review or
control and third parties may participate in the wells we drill, thereby reducing our working interest in those wells. This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CONSOL Energy Inc. or CNX Coal Resources LP.
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In 2013 – CONSOL set out to shift focus to being a pure play E&P company
The results as of year-end 2015 – creating free cash flow for 2016
Coal-E&P Revenue Split, 2012
E&P Revenues Coal Revenues
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Transformative Journey Towards a Pure Play E&P Company
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
March 31, 2016 – Sold Buchanan Mine and associated met reserves
Coal-E&P Revenue Split, 2014
E&P Revenues Coal Revenues
Coal-E&P Revenue Split, 2015, excl. Buchanan
E&P Revenues Coal Revenues
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E&P Division: Q1 2016 Operations Summary
Sub- Regions Horizontal Rigs Drilled Completed Turned In Line (TIL)
Lateral Length (ft) Counties Southwest PA
17 5,839 Greene, Washington, PA Central PA
Westmoreland, PA Northern WV Dry
Doddridge, Lewis, WV Ohio
North Wet Gas
10,763 Greene, Washington, PA; Marshall, WV South Wet Gas
Tyler, Ritchie, WV Total
25 7,415 Sub- Regions Horizontal Rigs Drilled Completed Turned In Line (TIL)
Lateral Length (ft) Counties Core Wet
9,220 Noble, OH Surrounding Core Wet
4 5 8,579 Harrison, Belmont, OH Dry Utica
5,964 Monroe, OH; Marshall, WV Westmoreland, Greene, PA Total
4 10 8,574
Marcellus Shale Quarterly Summary Utica Shale Quarterly Summary
*Dry Utica TIL is GH9A
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Operational Improvement: Utilized permanent production equipment for flowback operations – respective capital savings of $86k/well in the Marcellus and $112k/well in the Utica.
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Lease Operation Strategy: Implementation of company well tenders instead of contractors and rebidding contracts will yield $2.7 million in annual savings against LOE
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Production Optimization: Workovers, tubing installs, artificial lift, and compression opportunities.
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Production Highlights:
with an impressive 21 psi/day managed pressure decline
totaled 2.92 BCF while averaging an 18 psi/day pressure decline in Q1 only
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Quality Focus: Completed 10 well pad 35% faster and 10% cheaper than Q4 2015.
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Water Chemistry Success: 2 consecutive quarters fracturing with 100% reused water. Decreasing operating costs while fostering environmental stewardship.
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Forward Approach: Continued to make significant strides toward plugless completions and eliminating post frac
risk.
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2016 Planned E&P Activity Overview
E&P Activity Summary – 2016 Plan
Note: Plan as of 4/26/2016. 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 and 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 Remaining 2016 TIL's Remaining Marcellus SW PA Operated 18 17 6 23 SW PA Non-Op 5 2
WV Operated 7
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79 19 6 25 Utica SW PA Operated
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8 2 3 5 Total Utica 9 2 3 5 CBM CBM Operated 2 1 24 25 Total Gross Wells 90 22 33 55
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Bridging to Growth
Note: Guidance as of 4/26/2016. Production volumes reflect the mid-point of their contribution to the 2016 production guidance ranges. Source: Company filings and estimates. 329
23 5 71 378 50 100 150 200 250 300 350 400
2015 Total Production 2016 Base decline 2016: Gathering De- bottlenecking 2016: Non-Op (Ex NBL/HES)
2016: Production Adds 2016 Total Production
Bcfe
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Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth
Deferring activity, increasing capital efficiency
improvements and identification of additional de- bottlenecking activities
2016 E&P capital budget of $205-$325 million
million associated with CONE Midstream capital contributions)
$55-$65 million
60% 17% 23% D&C Midstream Other
2016 E&P Capital Budget: $205-$325 Million
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Average Completed Lateral Length Average Stage Length Average EUR/ 1000’ FT
1.55 1.32 1.45 1.45 2.13 0.0 0.5 1.0 1.5 2.0 2.5
2011 2012 2013 2014 2015-Present
Bcfe 3,366 5,137 5,483 7,004 7,118 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000
2011 2012 2013 2014 2015-Present
Feet 282.9 279.2 252.7 168.7 194.7 50 100 150 200 250 300
2011 2012 2013 2014 2015-Present
Feet
CONSOL’s Operational Experience Transformation Combining science with operational excellence . . .
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
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E&P Production Volumes
Beginning to outperform peers on growth and unit cost performance
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 2013 2014 2015 2016E
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.
$0.23 $0.38 $0.24 $0.16 $1.10 $1.02 $1.04 $1.00 $0.17 $0.17 $0.09 $0.07 $0.84 $0.59 $0.37 $0.29 $1.17 $1.11 $0.82 $0.48 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2013 2014 2015 2016E SG&A Direct Admin Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE
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Full-cycle Breakeven Operating Metrics Declined from $3.51 To $2.00 Per Mcfe, a 43% decline
Cash OpEx (plus G&A) of $1.52/Mcfe, plus PUD-to- PDP CapEx of $0.48/Mcfe, equals total full cycle cash costs of $2.00/Mcfe
Hired Tim Dugan to run E&P operations As of YE 2015 A B C D E F G
CNX E&P Per Unit Future PUD F&D ($/Mcfe) $0.60 $0.75 $0.91 $0.41 $0.48 $0.69 $1.33 $0.79 $0.48
Note: 2016E reflects midpoint of guidance range. Numbers may differ slightly due to rounding. Source: Company filings and presentations. Peers include AR, COG, EQT, GPOR, RICE, RRC and SWN.
13 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 12/31/2015. (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
acres(1)
─ 97 wells online, as of
3/31/2016
─ 10 wells TIL in Q1 2016 ─ 8,574 ft average TIL
laterals in Q1 2016
─ 4 wells per pad on
average
─ 180-acre spacing (1,100
assuming 7,000 ft lateral
─ 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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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
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
15 CONSOL – GAUT4IH 61.4 MMcf/d 24-hr IP rate @ 7,968 psi; 5,840 ft. lateral
CONSOL
160k# 100 mesh + 200k # 40/80 ceramic + 140k# 30/50 ceramic
system with available capacity
MMcf/d in July 2015
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).
1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 5,000 10,000 15,000 20,000 25,000 30,000 9/25/2015 10/25/2015 11/25/2015 12/25/2015 1/25/2016 2/25/2016 3/25/2016 Flow Rate Mcf/Day Casing Pressure
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Note: Production data has been normalized for temporary/short-term draw-downs and shut-ins due to maintenance.
17 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
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
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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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).
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
19 CONSOL – SWITZ 6 Pad (Utica): 4 Utica wells & 1 Marcellus well CNX – Switz 6D: 24-hr test rate 44.7 MMcf/d @ 6,835 psig
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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5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 10/13/2015 11/13/2015 12/13/2015 1/13/2016 2/13/2016 3/13/2016 4/13/2016
6D Gas Rate (Mcf/d) 6D Casing Pressure (psig) 6F Gas Rate (Mcf/d) 6F Casing Pressure (psig) 6H Gas Rate (Mcf/d) 6H Casing Pressure (psig)
Production Casing Pressure
5,000 10,000 15,000 20,000 25,000 20 40 60 80 100 120 Measured Depth (ft.) Days
(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.)
(In order by Tophole TD)
~55% Reduction in Drilling Costs
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~60+% Reduction in Days to Drill
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$12.4
(0.8)
$26.2
(8.2) (2.2) (0.4) (1.2) (1.1) $0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 Prior AFE Per Well Drilling Efficiency Drilling Science Cost Casing Design Multi-Well Pad (4) Completion Design Proppant Optimization Development AFE Per Well
Waterfall Diagram - PA Dry Utica Drilling and Completion Costs Per Well
Assume 7000' lateral on a development 4-well pad
($ in millions)
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 may vary from AFEs. (3) Estimated, actuals may vary.
(2) (3)
PA Dry Utica: Drilling and Completion Cost Reductions
Waterfall Chart Data(1) ($ in millions) Probability(3) Comments
Prior Well Cost/AFE (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) $12.4
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CONSOL basin exports are projected to increase approximately 73,000 Dth /day for FY 2016 over FY 2015 as TETCO’s U2GC and TEAM OPEN projects were put into service in late 2015, increasing expected realizations by marketing gas to the higher priced Midwest and Gulf Coast markets
CONSOL entered into ethane, propane, and butane sales agreements under which volumes will be shipped via Mariner East pipelines to the Marcus Hook Industrial Complex and ultimately exported to Europe
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The deals, the first of which commenced in April, are expected to yield price premiums compared with in-basin pricing and expose a portion of the company’s LPG portfolio to Brent Crude linked pricing
Q1 2016 natural gas price reconciliation:
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Q1 2016 Gas Realization and Marketing Highlights
2016 2015 NYMEX natural gas ($/MMBtu) 2.09 $ 2.98 $ Average differential (0.36) 0.03 Btu conversion (MMBtu/Mcf)* 0.10 0.09 Gain on Commodity Derivative Instruments-Cash Settlements 0.98 0.48 Realized gas price per Mcf 2.81 $ 3.58 $
*Conversion factor 1.06 1.03
First Quarter
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TETCO M2 TETCO M3 TCO Pool Dominion South East Tennessee TETCO ELA Midwest
Gas Sales CY 2016 Est. Columbia (TCO) 20% TETCO (M2) 26% TETCO (M3) 16% Dominion (DTI) 14% East Tennessee 10% TETCO ELA & WLA 8% Midwest (Chicago) 6% 100%
Natural Gas Sales
Source: SNL Financial.
TETCO WLA
Targeting FT opportunities 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
Stacked pay opportunities will help optimize FT portfolio
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Firm Transportation
Charts also include transportation under precedent agreements
FT Capacities Pipeline (MMcf/d) YE 2016 YE 2018 ANR Pipeline 47 47 Columbia (TCO) 195 494 Dominion (DTI) 370 342 East Tennessee 282 202 Nexus
TETCO 174 174 TETCO (via firm sales) 285 125 1,353 1,534
0.24 0.24 0.28 0.29 $0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 2016 2017 2018 2019
TETCO TETCO (via firm sales) Dominion East Tennessee Columbia ANR NEXUS 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Jan 16 Jan 17 Jan 18 Jan 19 1000S MMBtu/day
($8) ($6) ($4) ($2)
$4 $6 $8 $10 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 $/MMBtu
Colorado Interstate Gas Mainline Basis
excess supply out of the region
Over 22 Bcf/d of pipeline capacity is planned to be built in Appalachia
in 2016-2018
Historically, we have seen basis improve in other regions (see
Colorado basis chart below) as pipelines are built out
Some of these projects will be delayed or sized lower The debate is how much will basis improve and by when
REX pipeline became fully
2009
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ProjectID Markets Year Mo. Status MMcf/d Leidy Southeast NorthEast 2016 1 Construction 395 Capacity enhancement Midwest 2016 10 Committed 800 AIM Algonquin NorthEast 2016 11 Committed 342 Lebanon West II Midwest 2016 11 Announced 130 Gulf Markets Expansion 1 Gulf 2016 11 Committed 250 Total 2016 1,917 Rover phase 1 Midwest, Canada 2017 6 Delayed to 2Q2017 1,200 Rayne express Gulf 2017 6 Committed 1,000 Rover Canada Midwest, Canada 2017 11 Delayed to 2H2017 1,100 Rover phase 2 Midwest 2017 11 Delayed to 2H2017 825 Atlantic Sunrise South 2017 7 Committed 1,700 Constitution NorthEast 2016 7 DELAYED 650 Gulf Markets Expansion 2 Gulf 2017 8 Committed 100 Leidy South Mid-Atlantic 2017 10 Committed 155 Atlantic Bridge Northeast 2017 11 Open Season 132 SoNo (South to North) Northeast, Canada 2017 11 Open Season 650 Nexus Project Midwest, Canada 2017 11 Committed 1,200 Broad Run Expansion II Gulf 2017 11 DELAYED TO 2018 200 Access South Gulf 2017 11 Committed 320 Adair SW South 2017 11 Committed 320 Lebanon Extension Midwest 2017 11 Open Season 102 Northern Access 2016 Canada 2017 11 DELAYED TO 2017 497 Total 2017 10,151 LDC NorthEast 2018 1 Announced 200 Access Northeast NorthEast 2018 11 Announced 925 SW LA Supply - Cameron Gulf 2018 11 Announced 100 WB Express West Midwest 2018 6 Announced 800 Marcellus to Milford Northeast 2018 6 Announced 135 PennEast South 2018 7 8 month delay 1,000 Mountaineer Express TCO Pool 2018 11 Open Season 1,500 WB Express East South 2018 11 Announced 1,200 Atlantic Coast Pipeline South 2018 11 Announced 1,500 Northeast Energy Direct Northeast 2018 11 CANCELED
South 2018 12 Committed 2,000 Total 2018 9,360 Grand Total 21,428 Northeast Pipeline Projects
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Dawn Pipeline Projects
Dawn CY 2016: $0.07 CY 2019: $0.08
Southeast Pipeline Projects
Transco Zone 5 CY 2016: $0.04 CY 2019: $0.81 TCO Pool Basis CY 2016: - $0.14 CY 2019: - $0.20 East LA CY 2016: - $0.08 CY 2019: - $0.07
Gulf Market Pipelines
Source: SNL Financial, Velocity, CME Prices as of 4/04/16
TETCO M2 CY 2016: - $0.83 CY 2019: - $0.55 TETCO M3 CY 2016: -$0.52 CY 2019: -$0.04 Dominion South CY 2016: -$0.83 CY 2019: -$0.54 Chicago CY 2016: - $0.02 CY 2019: $0.04 Leidy CY 2016: -$0.90 CY 2019: -$0.72
Northeast Pipeline Projects
$1.2 $2.0 $2.4 $4.0 $4.6 $4.9 $5.5 $14.3 $17.5 Average: $6.3 Bn 20% 19% 71% 52% 36% 167% 70% 95% 152% 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% $- $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 $16.0 $18.0 $20.0 CNX A B C D E F G H FT Commitments as % of EV $ Billions
29 Notes: As of 12/31/2015. Peers include AR, CHK, COG, EQT, GPOR, RICE, RRC and SWN. Commitments are as of most recently provided company financial statements.
Total Off Balance Sheet Firm Transportation, Gathering and Processing Commitments
Contracted capacity meets current requirements
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Inlet wet gas volumes to processing plants were ~115 MMcf/d above CONSOL’s aggregate minimum committed volume in Q1 2016
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
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Natural Gas Processing
Note: We have processing capacity expansion rights of 110,000 Mcf/d
50 100 150 200 250 300 350 400 450 500 Jan 16 Jan 17 Jan 18 Jan 19 MMcf/day MVC
31 (1) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements. (2) Hedge positions as of 4/14/2016.
Gas Hedges
E&P Hedge Program:
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
Bcf of additional gas hedges through 2019, further protecting downside
FY 2016E production volumes hedged
2Q16 FY 2016 FY 2017 FY 2018 FY 2019 NYMEX + Basis (1) Volumes (Bcf) 67.3 259.7 122.5 65.4
$2.87 $3.07 $2.67 $2.68
Volumes (Bcf)
47.9 54.9 Average Prices ($/Mcf)
$3.08 $2.96 Physical Sales With Fixed Basis Exposed to NYMEX Volumes (Bcf) 3.4 2.9
($0.20) ($0.04)
70.7 262.6 210.8 113.3 54.9
20 40 60 80 100 120 140 160 180 200 220 240 260 280 2Q16 FY 2016 FY 2017 FY 2018 FY 2019 Gas Volumes Hedged (Bcf) Physical Sales With Fixed Basis Exposed to NYMEX NYMEX Only Hedges Exposed to Basis NYMEX + Basis (1)
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Ethane 64% Propane 22% I-Butane 3% N-Butane 6% Natural gasoline 5% Maximum Ethane Recovery* Potential Scenario
* Assumes 85% ethane recovery level
Ethane 14% Propane 49% I-Butane 8% N-Butane 15% Natural gasoline 14% 1Q16 Est NGL Sales Comp
Natural Gas Liquids, Oil, and Condensate
Q1 2016 Avg. “NGL Barrel” Composition
Q1 2016 liquids sold: 11.4 Bcfe
Total weighted average price of liquids decreased ~22% to $12.78 per Bbl in Q1 2016 from $16.34 per Bbl in Q4 2015
Liquids comprised approximately 12% of Q1 2016 production volumes, 9% of E&P sales revenue and 4% of total Company revenue
Added 7.5 million gallons of propane hedges from April of 2016 through March of 2017 at an average price of $0.43 per gallon
Average price realization (per Bbl): 2016 Q1 Q4 Q1 NGLs $12.30 $14.16 $20.40 Oil $30.84 $39.06 $47.82 Condensate $14.64 $25.38 $20.82 2015
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Strong liquidity position
CNXC and CONE
Asset monetization program
Reduction in legacy liabilities
Guidance: Production, price realizations, operating and capital costs
107 90 80 85 90 95 100 105 110 2015 2016E
($ in Millions)
35
Zero-Based Budgeting Includes key SG&A line items such as:
Wages and Salaries Payroll Taxes Employee Benefits Professional/Consulting Telephone & Internet
Communications
Travel & Entertainment Advertising & Promotion Rent: Buildings and Equipment Trade Association Dues
Notes: 2015 G&A adjusted to reflect 1Q16 accounting change removing direct admin. line item and reallocating expense to operating costs and G&A as appropriate
36
Debt and Liquidity Profile
Note: Some numbers may not match exactly to financial statements due to rounding. (1) The 2022 and 2023 senior notes includes $5 million and $6 million of unamortized bond premium / discount, which will be amortized over the life of the notes, respectively. (2) Total Debt of $3.648 billion excludes total unamortized debt issuance costs of $32 million. (3) Net Debt equals Total Debt less Cash and Cash Equivalents. (4) As of 3/31/2016, CNX had approximately $852 million of borrowings and $286 million of outstanding letters of credit under its revolving credit facility, leaving approximately $862 million of availability. CNXC had $200 million outstanding on its revolving credit facility leaving approximately $200 million of availability.
(5) Number of MLP units owned by CNX as of 3/31/2016 and unit prices as of market close on 4/22/2016. (6) CNX Coal Resources liquidity data is as of 3/31/2016 and CONE Midstream data is as of 12/31/2015. (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 $669 million plus gain on sale of assets of $42 million, plus gain related to changes in retiree medical (OPEB) plan of $244 million, less the $78 million of CNXC EBITDA Attributable to CNX, plus the $43 million of CNXC cash distributions to CNX, less $31 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 $3.648 billion, less $418 million cash on hand excluding CNXC’s cash, less $6 million of advance mining royalties, plus $224 million of net letters of credit related to firm transportation obligations, mining equipment leases and insurance policies.
CNX Consolidated CNXC: 100% CNX Attributable Capitalization and Liquidity 3/31/2016 3/31/2016 3/31/2016 Capitalization Cash and Cash Equivalents $427 $9 $418 Revolving Credit Facility Balance 1,052 200 852 Capital Lease Obligations 41
Total Secured Debt $1,093 $200 $893 8.25% Senior Notes due 2020 $74
6.375% Senior Notes due 2021 21
5.875% Senior Notes due 2022 (1) 1,855
8.0% Senior Notes due 2023 (1) 494
Baltimore 5.75% Revenue Bonds due 2025 103
Miscellaneous Debt 8
Total Debt (2) $3,648 $200 $3,448 Net Debt (3) $3,221 $191 $3,030 Stockholders’ Equity $4,739 $150 $4,589 Total Capitalization $8,387 $350 $8,037 Liquidity Cash and Cash Equivalents $427 $9 $418 Revolving Credit Facility Capacity (4) 1,062 200 862 Total Liquidity $1,489 $209 $1,280 CNX Owned LP Units(5) Unit Price(5) Market Value CNX Coal Resources LP (CNXC:NYSE) 12.7 $9.10 $115 CONE Midstream Partners LP (CNNX:NYSE) 19.1 $14.25 $272 Total Equity Value of Ownership Interests in Affiliated Public MLPs $387 Liquidity of Affiliated MLPs Total Facility Capacity Outstanding Balance Available Capacity Cash Total Liquidity of Affiliates CNX Coal Resources LP (6) $400 $200 $200 $9 $209 CONE Midstream Partners LP (6) $250 $74 $176 $0 $176 Total Liquidity of Affiliated Public MLPs $650 $274 $376 $9 $385 Leverage Ratio 3/31/2016 LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7) $889 LTM Bank Net Debt / Adj. EBITDA (7) 3.7x Equity Value of Ownership in Affiliated Public MLPs
$4,345 $1,902 $1,694 $1,542 $1,522 $1,508 $370 $148 $153 $137 $109 $0 $50 $100 $150 $200 $250 $300 $350 $400 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 FY 2012 FY 2013 FY 2014 FY 2015 Q1 2016 FY 2016E Annual Cash Servicing Cost ($ in Millions) Legacy Liabilities ($ in Millions) Total Legacy Liabilities (left axis) Annual Legacy Liabilities Cash Servicing Cost (right axis) As of Period End: 12/31/2012 12/31/2013 12/31/2014 12/31/2015 3/31/2016 12/31/2016E Legacy Liabilities ($ in Millions) LTD $39 $20 $22 $20 $19 $18 WC 180 85 90 83 82 81 CWP 184 121 126 123 127 126 OPEB 3,018 1,022 761 672 665 667 Salary Retirement/Pension 225 53 119 94 89 79 Asset Retirement Obligations 699 601 576 550 540 537 Total Legacy Liabilities $4,345 $1,902 $1,694 $1,542 $1,522 $1,508 FY 2012 FY 2013 FY 2014 FY 2015 Q1 2016 FY 2016E Total Annual Legacy Liabilities Cash Servicing Cost $370 $148 $153 $137 $137 $109
37
Significant Legacy Liability Reductions Over Past 3 Years
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 operating cost guidance) Flows through P&L in Coal Division’s “Other Costs” Flows through P&L within DD&A Flows through Other Segment in “Miscellaneous Operating Expense”
38
CNXC: Organizational Structure and CNX Ownership
In July 2015 IPO, sold 10.6 million LP units, or 44.6%, raising approximately $158 million in gross proceeds; CNXC also distributed $197 million in cash to CONSOL related to the revolver drawdown
CONSOL retained a 53.4% interest in the LP units and
CONSOL Energy retained an 80% undivided interest in the Pennsylvania mining complex and owns 100%
distribution rights CNXC owns a 20% undivided interest(1) in, and
mining complex (Bailey, Enlow Fork and Harvey mines)
(1) Unless otherwise specified, all figures relating to reserves and production of the Pennsylvania mining complex in this presentation are on a 100% basis.
CNXC is an avenue for CONSOL’s transition to a pure play Appalachian Basin E&P Company
80% undivided
CNX Coal Resources LP NYSE: CNXC CNX Coal Resources GP LLC Pennsylvania mining complex Public 100% ownership interest limited partner interest 2% general partner interest and IDRs 20% undivided
management and control rights limited partner interest CONSOL Energy Inc. ("CONSOL Energy") NYSE: CNX Greenlight Capital
(in millions except for per unit amounts)
Total LP Units held by CONSOL Energy 12.7 Unit Price (as of close on 4.22.2016) $9.10 CNXC Units Equity Value to CONSOL Energy $115.2 CONSOL Energy's Ownership Interest in CNX Coal Resources LP (CNXC:NYSE)
$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
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
39
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 4.22.2016) $14.25 CNNX Units Equity Value to CONSOL Energy $272.2 CONSOL Energy's Ownership Interest in CONE Midstream Partners LP (CNNX:NYSE)
40
Note: Guidance as of 4/26/2016. (1) Represents estimated unutilized firm transportation and processing expense less estimated gathering revenue (resold firm transportation).
E&P Segment Guidance
Production Volumes: Natural Gas (Bcf) NGLs (MBbls) Oil (MBbls) Condensate (MBbls) Total Production (Bcfe) Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.35) - ($0.45) NGL Realized Price ($/Bbl) $8.00 - $10.00 Condensate Realized Price % of WTI 43%
Oil Realized Price % of WTI 93%
Capital Expenditures ($ in millions): Drilling and Completion $110
Midstream $40
Land and Other $55
Total E&P and Midstream CapEx $205
Average per unit operating expenses ($/Mcfe): Lifting (including Direct Admin.) $0.27 - $0.30 Impact Fees/ Ad Valorem/ Production Taxes 0.06
Gathering, Transportation, Compression & Processing 0.98
Depreciation, Depletion and Amortization 1.00
Total Production and Gathering Costs $2.31 - $2.47 Other Expenses ($ in millions): General and Administrative Expense $58.0 - $62.0 Unutilized Firm Transportation Expense, net:(1) $15.0 - $16.0
2016E
335 6,000 65 1,000 ~+15%
41
Note: Guidance as of 4/26/2016. * Includes FY 2016 for Miller Creek and Other Coal Operations and 1Q16 for Buchanan, excludes Loss on Sale of Buchanan Complex ** Includes Other Income (net of applicable expense) associated with the Company's Terminal Operations, Coal Royalty Income, and other miscellaneous land income *** Includes Legacy Liability Costs approximating $90-95M; Other Coal-Related Corporate Expenses (STIC, stock-based compensation), and other miscellaneous items (coal reserve holding costs)
Coal Segment Guidance
Estimated Total Consolidated Coal Division Sales Volumes (in millions of tons) 23.9
Total Volumes Sold % Committed Total Consolidated Coal Division Capital Expenditures ($ in millions): Production $85
Other (Land/Water/Safety/Terminal) $20
Total Coal Capital Expenditures $105
Adjusted EBITDA Guidance ($ in millions): CNX Coal Resources LP ("CNXC") Adjusted EBITDA (20% undivided interest of PA Operations) $59
x5 (@ 100% interest) $295
Less: Noncontrolling Interest ($26)
Plus: CONSOL's Other Coal Division EBITDA* $22 $27 Plus: CONSOL's Other Miscellaneous Coal EBITDA** $15
Less: CONSOL's Other Coal Division Costs and Expenses (including legacy liabilities' costs)*** ($126) - ($131) CONSOL Energy's Pro Rata Coal Division Adjusted EBITDA $180
98% 25.0
2016E
42
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 – April 21st announced 3.7% increase to quarterly distribution to $0.245 per unit, the 4th increase since the IPO in October 2014
Positive initial well results from operated dry Utica (Gaut 4IH, GH9, and Switz 6D)– sets up future stacked pay
narrowing basis differential by year-end 2016. This should help both natural gas and thermal coal prices.
NAV/share
Plans and Goals Aligned to Drive Increased Valuation
43
44
Non-GAAP Reconciliation: Quarter-over-Quarter EBITDA and Adj. EBITDA
Source: Company filings.
Three Months Ended March 31 2016 2016 2016 2016 2015 ($ in thousands) E&P Division Coal Division Other Total Company Total Company Net (Loss)/Income ($23,541) ($49,015) ($23,902) ($96,458) $79,030 Less: Net Loss/(Income) Attributable to Discontinued Operations, net of tax
(244,317) Add: Interest Expense 653 1,733 47,480 49,866 55,122 Less: Interest Income
(214) (1,143) Add: Income Taxes (Benefit)/Expense
(26,847) 195,898 Earnings Before Interest & Taxes (EBIT) from Continuing Operations (22,888) (1,110) (3,483) (27,481) 84,590 Add: Depreciation, Depletion & Amortization 105,715 54,352
149,709 Earnings Before Interest, Taxes and DD&A (EBITDA) $82,827 $53,242 ($3,483) $132,586 $234,299 Adjustments: Unrealized Loss/(Gain) on Commodity Derivative Instruments 29,271
(60,004) Loss on sale of sale of gathering pipeline 12,636
667 2,918
Total Pre-tax Adjustments $41,907 $2,251 $667 $44,825 $7,730 Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $124,734 $55,493 ($2,816) $177,411 $242,029 Less: Noncontrolling Interest*
$124,734 $54,379 ($2,816) $176,297 $242,029
45
Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA
Source: Company filings.
Three Months Ended Three Months Ended Three Months Ended Three Months Ended Twelve Months Ended June 30 September 30 December 31 March 31 March 31 ($ in thousands) 2015 2015 2015 2016 2016 Net (Loss)/Income ($603,301) $125,470 $34,325 ($96,458) ($539,964) Less: Net Loss Attributable to Discontinued Operations, net of tax $229,466 2,044 2,139 46,172 279,821 Add: Interest Expense $46,507 48,558 49,082 49,866 194,013 Less: Interest Income (364) (361) (431) (214) (1,370) Add: Income Taxes (520,666) 64,758 125,806 (26,847) (356,949) Earnings Before Interest & Taxes (EBIT) from Continuing Operations (848,358) 240,469 210,921 (27,481) (424,449) Add: Depreciation, Depletion & Amortization $154,764 $149,790 145,783 160,067 $610,404 Earnings Before Interest, Taxes and DD&A (EBITDA) ($693,594) $390,259 $356,704 $132,586 $185,955 Adjustments: OPEB Plan Changes (33,649) (100,947) (109,879)
Impairment of E&P Properties 828,905
Unrealized Gain on Commodity Derivative Instruments 24,936 (99,138) (62,388) 29,271 (107,319) Pension Settlement
15,921
Industrial Supplies Working Capital Settlement
Gain on Sale of Non-core Assets
(7,551) 12,636 (43,383) Severance Payments
10,601 Loss on Debt Extinguishment 17
Backstop Loan Fees 7,334
Other Transaction Fees 4,968
Total Pre-tax Adjustments $832,511 (237,738) ($157,639) $44,825 $481,959 Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $138,917 $152,521 $199,065 $177,411 $667,914 Less: Noncontrolling Interest*
($3,920) ($1,114) ($11,524) Adjusted EBITDA Attributable to CONSOL Energy Shareholders $138,917 $146,031 $195,145 $176,297 $656,390
46
Free Cash Flow Reconciliation
Source: Company filings.
Three Months Ended March 31 2016 Organic Free Cash Flow From Continuing Operations:
Net Cash provided by Continuing Operations
119,806 $ Capital Expenditures (78,968) Net Investment in Equity Affiliates (5,578) Organic Free Cash Flow From Continuing Operations
35,260 $
Free Cash Flow:
Net Cash Provided By Operating Activities
128,442 $ Capital Expenditures (78,968) Capital Expenditures of Discontinued Operations (5,737) Net Investment in Equity Affiliates (5,578) Proceeds From Sales of Assets 8,453
Proceeds From Sale of Buchanan Mine 402,806 Total Free Cash Flow 449,418 $
47
Joint Ventures
(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 $15 million for Utica, respectively. Utica carry has an accrued cash balance of $7.5 million as of end of 1Q 2016.
(1) (2) (3) (3)
Description Marcellus / Noble Energy Inc. Utica / Hess Corporation Ownership 50/50 50/50 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 $335 million, of which ~$7.5 million remains as of end
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 Summary of JV Carry Eligible Capital
48
acres
─ ~88% NRI ─ ~91% HBP
wells(1)
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 12/31/2015.
Marcellus Shale: Overview
49
Total Gross Prospective Marcellus Acreage
~785,000
~699,000
~86,000
Acreage per well (assumed 750 ft spacing)
~86
Gross Producing wells (JV - YE2015)
448
Gross PDNP and PUD locations (YE2015)
146
Gross prospective unproved locations
~8,000
Producing wells as % of PDNPs, PUDs, and prospective locations
5%
Note: Acreage and locations as of December 31, 2015 unless otherwise noted.
Marcellus Shale Upside Potential
Marcellus Shale: Growth Runway and Depth of Inventory
50
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 Locations(2) 900 2,200 2,250 150 1,000 2,200 ~8,700 Avg EURs/1,000 ft (Bcfe) 2.1 1.6 1.8
2.1
Marcellus Shale: Sub-Regions Summary
Note: Acreage and locations as of December 31, 2015 unless otherwise noted. (1) Non-JV acreage is located in Monroe County, OH. (2) Based on 5,000 ft laterals with 86-acre spacing.
51
Marcellus Shale: Southwest PA Overview
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 12/31/2015.
acres
─ 206 wells online, as of
3/31/2016
─ 17 wells TIL in Q1 2016 ─ 8 wells per pad on
average in 2016
lateral
Producing Pads Competitor Pads
52
Marcellus Shale: North Wet Gas Overview
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 12/31/2015.
acres
locations(1)
─ 144 wells online as of
3/31/2016
─ 8 wells TIL in Q1 2016 ─ 8 wells per pad on
average
lateral
RCS/SSL
Bbls/MMcf
Producing Pads Competitor Pads
53
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 12/31/2015.
acres
locations(1)
─ 31 wells online, as of
3/31/2016
─ 6 wells per pad on
average
lateral
Bbls/MMcf
Marcellus Shale: South Wet Gas Overview
Producing Pads Competitor Pads DTI Storage Fields
54
Marcellus Shale: Northern WV Dry Overview
acres
locations(1)
─ 49 wells online, as of
3/31/2016
─ 0 wells TIL in Q1 2016
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). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2015.
Producing Pads Competitor Pads DTI Storage Fields
55
Marcellus Shale: Central PA Overview
acres
locations(1)
─ 56 wells online, as of
3/31/2016
─ 0 wells TIL in Q1 2016 ─ 5 wells per pad on
average
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). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2015.
Producing Pads Competitor Pads
56 Notes: PA and WV prospective Utica eastern boundary has yet to be delineated. Acreage is risked 40+% in PA and WV. Acreage in Ohio oil window is excluded. Acreage and locations as of December 31, 2015 unless otherwise noted.
Utica Shale Upside Potential
Utica Shale: Growth Runway and Depth of Inventory
Total Gross Prospective Utica Acreage
~701,000
~158,000
~543,000
Acreage spacing per well (assumed 1,100 ft spacing)
~126
Gross Producing wells (JV - YE2015)
83
Gross PDNP and PUD locations (YE2015)
106
Gross prospective unproved locations
~3,500
Producing wells as % of PDNPs, PUDs, and prospective locations
~2%
57
Note: Acreage and locations as of December 31, 2015 unless otherwise noted.
Utica Shale Ohio Wet Ohio Dry PA/WV Dry Total Net Acres ~89,000 ~30,000 ~503,000 ~622,000 Approximate Gross Locations(1) 1,050 350 2,400 3,800 Avg EURs/1,000 ft (Bcfe) 2.3 2.8 3.0
58
acres in Utica
─ ~306,000 net acres in
PA
─ ~197,000 net acres in
WV
─ 30,000 net acres in OH
Dry
Monroe County, OH
─ 89,000 net acres in OH
Wet
strong results
─ The main area without
Westmoreland County where CNX drilled the Gaut 4IH which had the 2nd highest IP in the Utica to date
Utica Shale: Offset Peer Acreage
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.
59 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 3,000 or more acres (as of 12/31/2015).
Utica Shale: CNX Acreage Position in the Core OH Wet Gas Utica
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 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 GPOR - Wagner 1-28H IP GAS: 14,000 Mcf/d IP OIL: 432 Bbl/d AR - Miley 5HA IP GAS: 7,700 Mcf/d IP OIL: 1,285 Bbl/d GPOR - Shugert 1-12H IP GAS: 28,500 Mcf/d IP OIL: 300 Bbl/d HES – Cadiz A IP GAS: 8,006 Mcf/d IP OIL: 399 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 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 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
~34,000 net core wet acres
in core
area
locations(1)
─ 90 wells online, as of
3/31/2016
─ 9 wells online in Q1 2016 ─ 8,082 ft average laterals in
Q4 2015
─ 4-5 wells per pad on
average
lateral
drills
60
Wet Net Acres Dry Net Acres Total Net Acres 190,000 173,000 89,000 452,000 155,000 263,000 951,000 345,000 436,000 622,000 1,403,000
(1) Dry Utica includes 503,000 net prospective acres in Pennsylvania and West Virginia. As of December 31, 2015.
Stacked Pay Potential: Appalachian Shale Acreage
533,000 Upper Devonian Marcellus Utica(1)
Rhinestreet Shale Middlesex Shale Burkett Shale West River Shale
Formation Name
P a y
Cashaqua Shale Tully Limestone Hamilton Shale Marcellus Shale Onondaga Limestone Utica Shale Point Pleasant Shale Trenton Limestone
0 GR 400 LITHOLOGY
Total
61
CONSOL Energy
E&P Other Operations CONE MLP PA Complex
Marcellus Utica CBM SOG and Other*
CNXC (MLP)
* Includes Other Midstream
62
Source: CONE Midstream Partners LP.
CONE Corporate Structure
(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.
Pennsylvania Mining Complex
63
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
Reserves are mined from the Pittsburgh No. 8 Coal Seam located in the Northern Appalachian Basin
Five longwalls and 18 continuous mining sections
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) Bailey 254.5 12,929 2.68% 11.5 10.2 Enlow Fork 322.8 12,942 2.21% 11.5 9.0 Harvey 208.3 13,080 2.25% 5.5 3.6 Total 785.6 12,974 2.37% 28.5 22.8 Illinois Basin 11,396 2.94% Other NAPP 12,134 3.19% Other Coal MLPs 11,619 2.74%
(2) (3)
Baltimore Terminal PA Mining Complex
Active Complex Port/Dock CNXC Customers
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(2)
64
65