Newest Investor Presentation from Magnum Hunter Resources, Issued Oct 2014

MAGNUM HUNTER RESOURCES CORPORATION
Investor Presentation
October 2014

Who We Are
Magnum Hunter Resources is an exploration and production company focused in three of the most
prolific unconventional resource shale plays in North America; the Marcellus, Utica and
Williston/Bakken Shale
Current management team assumed leadership of the Company 5 years ago in May 2009 and has
decades of combined energy industry experience
Diversified asset base provides the Company with the flexibility to allocate capital to the highest
growth properties within the portfolio
Achieved “Shale Scale” with significant acreage positions in the Bakken, Marcellus and Utica Plays that
Current Market Capitalization ~$1,200 MM
Current Enterprise Value ~$2,250 MM
Target 2014 Exit Rate Production(1) 32.5 MBoepd
2013 Stock Price Appreciation(2) ~83%
Proved Reserves(3) 79.8 MMBoe
3P Reserves(4) 132.9 MMBoe
Contingent Resources(5) 891.1 MMBoe
is ~300,000 net acres
Significant insider ownership of management aligns with shareholder interest
1
Key Metrics
(1) Post planned non-core asset sales
(2) Stock price appreciation from December 31,2012 to December 31, 2013
(3) Consists of total proved reserves as of June 30, 2014
(4) 3P Reserves consist of proved, probable and possible reserves as of June 30, 2014
(5) The contingent resource estimate is an internal estimate prepared by Magnum Hunter that includes its Utica Shale potential on its vast lease acreage holdings as of June 30, 2014

2
Where We Operate
A well-balanced and concentrated asset base in large shale plays
Secure footholds inWest Virginia, Ohio, Kentucky, and North Dakota
~88,600 Net Acres
North Dakota
~80,300 Net
Marcellus Acres
~118,000 Net Utica
Acres
~278,800 Net Southern
Appalachia Acres
Mid-Year 2014 Proved Reserves
% Oil/ Gross Drilling
(MMBoe) % PDP Liquids Locations(1)
Appalachian Basin
Marcellus / Utica / Huron / Weir
Appalachia 64.1 46.8% 24.3% 1,438
Williston Basin 15.5 48.1% 93.4% 1,530
South Texas/Other 0.2 2.7% 12.0% 0
Total 79.8 47.0% 37.7% 2,968
Williston Basin
Bakken / Three Forks Sanish
(1) Represents total potential drilling locations reflecting current acreage position and reserve report as of June 30, 2014

Production Growth
3
2013 Production increased 92% to 14,831 Boepd(1) compared to 7,739 Boepd in 2012
Year-end 2014 exit rate guidance of 32,500 Boepd(2)
(1)
Note: The production numbers referenced above include production from continuing operations (excludes Eagle Ford assets and other discontinued operations)
(1) Includes, on a pro forma basis, 2,925 Boe/d of actual production from discontinued operations, and estimated shut-in production volumes of 2,061 Boe/d
(2) Post planned non-core asset sales
(2)
1,276
4,895
7,739
14,831
32,500
2010 2011 2012 2013 2014 Target Exit Rate
Oil / Liquids Natural Gas
(2)

Proved Reserve Growth Consistency
0.16
0.20
0.35
0.40
0.42
0.40
0.78
0.67
(C) (C)
2009 2010 2011 2012 2013 2014
Proved Reserves (MMBoe) Probable Possible (MMBoe)
6.2
12.8
39.6
61.6
72.1
79.8
61.5
53.2
2009 2010 2011 2012 2013 2014
Proved Reserves (MMBoe) Probable Possible (MMBoe)
4
Track record of proved reserve growth since inception
• Approximately 79.8 MMBoe of proved reserves at June 30, 2014 (37.7% oil/liquids)
• Expect to significantly increase proved reserves in the Utica Shale during the remainder of 2014
(successfully booked YTD 2 PDNP and 2 PUDs in the Utica Shale)
• The Company’s reserve life (R/P ratio) of its proved reserves based on current production is
approximately 12.0 years
Proved Reserves (MMBoe)(A) Proved/3P Reserves (Boe) / Share(B)
(A) 3P Reserves as of 6/30/13 and 6/30/14 were 133.6 MMBoe and 133.0 MMBoe, respectively
(B) Calculation based on weighted average of common shares outstanding on annual basis
(C) As of June 30, 2014

Reserves Summary
5
3P reserves and contingent resource potential of 1,024 MMBoe
Extensive inventory of low-risk development drilling locations in the Marcellus Shale and Williston Basin
Significant exploration potential in the wet/dry gas window of the Utica Shale in Ohio and West Virginia
Reserves Summary
Net Reserves as of June 30, 2014 (SEC PRICING)
Liquids Gas Total % PV-10
Category (MMBbls) (Bcf) (MMBoe) of total ($MM)
PDP 14.7 136.5 37.5 28.2% $548
PDNP 2.7 61.7 13.1 9.8% 150
PUD 12.6 99.9 29.2 22.0% 218
Total Proved Reserves 30.1 298.1 79.8 60.0% $916
Probable / Possible 31.9 127.4 53.2 40.0% 250
Total 3P Reserves 62.0 425.5 133.0 100% $1166
Contingent Resources 140.3 4,505.0 891.1
Total Contingent Resources 202.3 4,930.5 1,024.1
Proved Reserve Allocation Proved Reserves by Region
Other
0.1%
Williston Basin
19.5%
Appalachia
80.4%
Oil / Liquids
37.7%
Gas 62.3%

6
Growth Plan Continues
4.2
50.4
76.2
112.4
$450
$400
$350
$300
$250
$200
$150
$100
$50
Note: This information constitutes forward-looking statements and is subject to the qualifications on the last page of this investor presentation
* See Appendix of this presentation for a non-GAAP reconciliation table
Current management team started in May 2009
185.0
28.6
66.5
140.4
280.4
410.0
$0
2010 2011 2012 2013 2014
($ MM)
EBITDAX Revenue

Breakdown of Capital Expenditure Budgets
7
2013 Drilling and Completion Capital Expenditures 2014 Capital Budget
Appalachia Williston Eureka Hunter Eagle Ford/Other
34%
34%
22%
10%
65%
13%
Appalachia Williston Eureka Hunter
23%
Total: $389 Million(1) Total: $400 Million
(1) Excludes leasehold acquisitions of $144.3 million for the twelve months ended December 31, 2013

8
Substantial Leasehold Inventory
As of June 30, 2014
Developed
Acreage (1)
Undeveloped
Acreage (2) Total Acreage
Gross Net Gross Net Gross Net
Appalachian Basin (3)
Marcellus Shale 58,334 57,908 27,642 22,381 85,976 80,289
Utica Shale 68,887 64,991 59,660 53,505 128,547 118,497
Magnum Hunter Production 145,085 109,568 167,140 146,736 312,225 256,304
Other 22,473 22,473 40 17 22,513 22,489
Total 294,779 254,940 254,482 222,639 549,261 477,579
South Texas
Other(4) 1,777 825 764 609 2,541 1,434
Total 1,777 825 764 609 2,541 1,434
Williston Basin - USA
North Dakota(5) 167,998 45,884 100,335 42,723 268,333 88,607
Total 167,998 45,884 100,335 42,723 268,333 88,607
MHR TOTAL 464,555 301,649 355,581 265,971 820,136 567,620
(1) Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production
(2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas,
regardless of whether such acreage includes proved reserves
(3) Approximately 47,049 Gross Acres and 42,418 Net Acres overlap in our Utica Shale and Marcellus Shale
(4) Pertains to certain miscellaneous properties in Texas and Louisiana
(5) Excludes the acreage associated with the divestiture of non-core assets in Divide County, North Dakota for $23.0 million

Williston Basin Overview
10
Areas of Operation Overview
Proved Reserves and PV-10
• Total proved reserves of 15.5 MMBoe as
of 6/30/14
• Proved producing reserves of 7.5 MMBoe
as of 6/30/14
• 1P PV-10 of $292.5 million as of 6/30/14
• PDP PV-10 of $225.7 million as of
6/30/14
Acreage
• ~88,600 net acres in the Williston Basin
in Divide County
– All acres located in North Dakota
Drilling Opportunities
• Drilling locations target the Middle
Bakken/Three Forks Sanish
• 271 gross producing wells in Divide
County, North Dakota
2 - 3 Active Drilling Rigs
• Two non-operated drilling rigs are
currently drilling in Divide County, North
Dakota

Ambrose/Divide County 2014 Activity
11
Areas of Operation Overview
2014 Ambrose Field Drilling Program
• 15-20 gross (6-8 net) wells
• Targeting Three Forks Sanish and Middle
Bakken
Prolific Two-mile Lateral Wells
• IP 24-hour rates - 500 – 1,000 Boepd
• IP 30-day rates - 300 – 650 Boepd
Reserve Growth Compounding
• EUR 350 – 550 Mboe
• ~500 gross locations in Ambrose sweet
spot
IRR Continuing to Improve
• Low cost eco-pad drilling reduces per
well capital costs to $5.7M – $6.3M
per well
• Finding costs forecast range $12 -
$17/Bbl MBOE
• ONEOK gas gathering at 90% efficiency
• 600 Boepd
• Revenue $500K/month

Williston Basin Recent Well Results
12
Williston (North DDaakkoottaa)) MMHHRR rreessuullttss
4th Quarter 2013 1st / 2nd Quarter 2014
684
736
803
874
906
968
791
558
822
876
806
423
526 536
443
581
411
595
495
392
653
677
568
317
40
36
25 25
32
24 26 26
30 30
25 25
1200
1000
800
600
400
200
0
Almos Farms
0112
Thomte 0508 Charger 0706 Coronet 2314 Twin Butte
17-20
Bel Air 2314 Tomlinson 3-
1HN
Orlynne 2-3H Kathlyn Hall
3DN
Les Hall 2DM Bel Air 2314-
7H
Comet 2635-
7H
Crude Oil Production (Boe/)d
24-Hour IP Rates 30-Day IP Rates # of Frac Stages

Bakken Hunter Fracture Stimulation Trends
13
100,000
90,000
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
Plug Perf vs Sleeves
Fluid Rate vs Time
0 10 20 30 40 50 60 70 80 90
Total Fluid Rate,Bpd
Days
Bernie A 20-17-162-98H 2XC
Bernie B 20-17-162-98H 3XB
Comet 2635-7H (26-35-163-99)
Bel Air 2314-7H (23-14-163-99)
Les Hall 18-19-162-99H 2DM
Kathlyn Hall 18-19-162-99H 3DN
Nelson 18-19-161-98H 1BP
Comet 2635-2H (26-35-163-99)
Bel Air 2314-1H (23-14-163-99)
Bel Air 2314-2H (23-14-163-99)
Comet 2635-5H (26-35-163-99)
Comet 2635-1H (26-35-163-99)
Bel Air 2314-5H (23-14-163-99)
Marilyn Nelson 29-32-162-98H 1BP
Marilyn Nelson 20-17-162-98H 1XB
Stingray 18-19-162-98
Randy Olson 17-20-161-98
Thompson 2-11-161-99
Hansen 18-19-162-99
Edna 14-23-162-100
Twin Butte 17-20-162-99H 1BP
Dahl 13-24-162-100H
PP Average
Sleeve Average
PP + 30%
More Fluid

ONEOK Net Production Revenue
14
2,500
2,000
1,500
1,000
500
0
BpdMmcfd or M$/mo
Williston Basin
Net Gas NGL Production Revenue
Gas, mcfd
NGL, bpd
Gas NGL Revenue, M$
Est. Gas, mcfd
Est. NGL, bpd
Est. Gas NGL Rev, M$
~ 600 Boe/d

Williston Basin Economics – Sensitivity
15
North Dakota – West (High Case)
CAPEX: $6.0 million per well
EUR: 550 MBOE
Differential: ($8)
North Dakota – West (Base Case)
EUR: 350 MBOE
Differential: ($8)
IRR: 11%
$12
$10
$8
$6
$4
$2
North Dakota - West (High Case) North Dakota - West (Base Case)
(1) NYMEX crude oil (WTI) spot pricing as of 9/9/2014 was $92.75 per Bbl
IRR: 19%
IRR: 33%
IRR: 29%
$0
$75 $80 $85 $90 $95 $100 $105 $110
Single Well NPV10 ($MM)
Realized Oil Price(1), $/Bbl
IRR: 14%
IRR: 16%
IRR: 9%
IRR: 21%
IRR: 24%
IRR: 26%
IRR: 37%
IRR: 42%
IRR: 46%
IRR: 50%
IRR: 55%
IRR: 59%

Appalachian Division Overview
Proved Reserves and PV-10
• Total proved reserves of 64.1 MMBoe as
of 6/30/14
• Proved producing reserves of 30.0
MMBoe as of 6/30/14
• PV-10 of $622.9 million as of 6/30/14
Acreage Position
• ~477,600 net acres in the Appalachian
Basin
• 80,300 net acres located in the Marcellus
Shale
– 387 gross remaining Marcellus well
locations(1)
• 118,500 net acres prospective for the
Utica Shale
– 464 gross remaining Utica well
locations(1)
17
Overview Areas of Operation
Utica and Marcellus Shale Overview
• 52 gross wells have been drilled and placed on production to-date
with 16 gross (15 net) shut-in on existing pads
– 18 wells in Tyler County, WV (10 wells shut-in)
– 28 wells in Wetzel County, WV (3 wells shut-in)
– 5 wells in Monroe County, OH (2 wells shut-in)
– 1 well in Washington County, OH (1 well shut-in)
• Current Completion Operations
– 0 gross (0 net) wells drilled, and completing
• Current Drilling Operations
– 5 gross (3.6 net) wells drilling
(1) Marcellus/Utica well locations only contemplate locations with a working interest 70%

Marcellus Shale Recent Well Results
18
Marcellus Operated WWeellll RReessuullttss
24-Hour IP Rates 30-Day IP Rates # of Frac Stages
12,854 Recently Completed Wells
12,421
12,832 12,670
3,972
10,013
8,412
9,677
14,000
12,000
10,000
8,000
6,000
4,000
2,000
Please note that the Ormet and WVDNR wells reflect peak production rates (Ormet 1-9H initially tested and completed in 2011 at a restricted rate)
9,316
10,119
9,543
10,340
8,842
8,560
3,502
3,697
6,980
18
21 21
24
12
14
19
20 20 19
0
Collins Unit
#1116H
Collins Unit
#1117H
Collins Unit
#1118H
Collins Unit
#1119H
Ormet 1-9H Ormet 2-9H Ormet 3-9H WVDNR #1207 WVDNR #1208 WVDNR #1209

NGL Uplift in Appalachia
19
Following the startup of the Mobley Processing Plant in December 2012, Magnum Hunter
has realized an uplift in NGLs on a per wellheadMcf basis between $0.50 - $1.00
The Company has 200 MMcf/d of dedicated processing capacity at the Mobley Plant
Wellhead Gas
1 Mcf
Btu = ~1,270
Cryo
Processing
1.64 Gal / Mcf
Methane
0.85 – 0.89 Mcf
(1) All values shown are versus wellhead production in Mcf.
Ethane
3.0 – 3.5 Gal / Mcf
Residue Nat. Gas and
Ethane
Btu = ~1,060
NGLs
Liquids
Fractionation
(C3+)
Per Wellhead Mcf (1)
$0.50 - $1.00
+ $3.50 - $4.00
$4.00 - $5.00

Economic Sensitivity of Marcellus “Magnum
Rich”
$18
$16
$14
$12
$10
$8
$6
$4
$2
$0
High Case Base Case
IRR: 28%
IRR: 38%
IRR: 49%
IRR: 60%
IRR: 72%
$2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50
20
High Case:
EUR: 11.7 Bcfe (includes NGL)
IRR: 10%
IRR: 16%
IRR: 23%
IRR: 29%
IRR: 37%
IRR: 44%
IRR: 52%
Realized Natural Gas Price(1), $/MMBtu
Single Well NPV-10 ($ MM)
Note: Assumes realized oil price of $90.00/Bbl and realized NGL price of $45.00/Bbl (50% of realized oil price)
(1) NYMEX natural gas (HH) spot pricing as of 9/9/2014 was $3.98 per MMBtu
IRR: 83%
IRR: 94%
Base Case:
EUR: 7.8 Bcfe (includes NGLs)
IRR: 105%
IRR: 59%

Marcellus Shale
NOBLE MONROE
WASHINGTON
MHR/Eclipse - McIntire Pad
Mark West –Mobley
WETZEL
Fractionation Facility
Eureka - Carbide
Compression Facility
MHR / Stone JV Pads
MHR - WVDNR Pad
MHR - Everest-Weese Pad
DODDRIDGE
MHR - Ormet #9 Pad
MHR - Ormet #15 Pad
MHR/Eclipse - Stalder Pad
Eclipse/MHR - Herrick Pad
MHR - Meckley-Wells Pad
MHR - Stewart-Winland Pad
PLEASANTS
MHR - Collins Pad
MHR - Spencer Pad
RITCHIE
WIRT
TYLER
WOOD
Magnum Hunter Acreage
Eureka Hunter Pipelines
MHR - Stevens Pad
Note: MHR owns approximately 80,300 net acres in the Marcellus Shale. 21

Utica Shale Overview
22
The Utica Shale extends approximately 170,000 square miles throughout the
Appalachia Basin in the United States and Canada
• Ordovician-aged organic rich black shale with interbedded limestone with
target intervals ~150 feet thick at depths between 7,500 feet and 9,500 feet
• Similar to the Eagle Ford Shale with three distinct windows: oil, wet
gas/condensate, and dry gas with the majority of the activity focused on
the wet gas and condensate window
The “Sweet Spot” for liquids-rich gas occurs in eastern Ohio along a narrow
band which generally follows geologic structure
• Optimum thermal history
• Depth, pressure and hydrocarbon composition result in excellent recoveries
Total Organic Carbon (“TOC”) is a measure of organic content and is indicative
of the quantity of kerogen in the rock, which is the source material for oil and
gas
• TOC is derived from core analysis; however, it can also be inferred from
open hole log resistivity measurements where sufficient data exists for a
good correlation
• There is a general correlation between higher gross interval thickness and
larger TOC values
• East of the Ohio River, the Utica/Point Pleasant is sufficiently deep for the
formations to produce dry gas; these areas of high TOC also correspond to
high Ro values
Acreage owned by the Company exhibits good thickness and is highly
prospective with a large portion of the acreage in the wet gas and condensate
window
Total Organic Carbon
IsopachMap of Utica/Point Pleasant

Potentially Best Shale Play in US
23
Shale Play Comparison Chart
Ohio/West Va./Penn. Wyoming/Colorado Texas N. Dakota
Utica Shale /
Parameter Point Pleasant DJ Basin Niobrara Eagle Ford Bakken
Lithology Calcareous Shale Chalk/marl Calcareous Shale Silty Dolomite
Shale with carbonate
Lithology Descriptor stringers Like Limestone Like Limestone More Dolomitic
Storage Capacity
Formation Thickness 100'-300' 150'-300' 75'-300' 150'
Porosity 3-16% 6-10% 4-15% 8-12%
Water Saturation (Sw) 5-10% 35-90% 15-45% 15-25%
OOIP per section (MMBOE) 20-35 30+ 30-50 10-15
Productive Capacity
Clay Content ~10-25% 10-40% 8-11% 5-10%
Total Organic Carbon (TOC) 2-6% 2-6% 5% 9%
Brittleness varies, Brittle, fracs easy, 500' Brittle, fracs easy,
Ability to Fracture Stimulate na 250' frac length frac length 500+' frac length
Permeability 0.1 mD 0.1 mD 0.1 mD 0.1 mD
Reservoir Pressure (psi/ft) ~0.5-0.85 0.4-0.6 0.5-0.8 0.5-0.7
Gas-Oil-Ratio (GOR) ~3,000 0-10,000+ 500-2,000 500-1,000
Development Parameters
Depth 7,000'-11,000' 6,000'-8,000' 6,000'-8,000' 7,000'-11,000'
Well Cost ($MM) 8.0-10.0 4.0-6.0 9.0 10.0
Spacing (acres/well) 80-160 ~160 80-160 100-200
EUR (MBOE/well) 600+ 175-350 450-700 300-1,000

24
Major Players in the Utica: Who They Are
Company Ticker Net Acres EV ($MM) Acres/EV
Chesapeake Energy CHK 1,000,000 34,063 29
Chevron CVX 600,000 233,468 3
Anadarko Petroleum APC 267,000 57,360 5
Devon Energy DVN 195,000 30,153 6
Range Resources RRC 190,000 15,451 12
Hess Corporation HES 185,000 33,068 6
EV Energy EVEP 177,000 2,746 64
Gulfport Energy GPOR 147,350 4,996 29
Halcon Resources HK 142,000 4,953 29
Antero Resources AR 104,000 17,013 6
Magnum Hunter MHR 118,000 2,250 52
BP BP 84,000 164,525 1
Consol Energy CNX 80,000 11,590 7
ExxonMobil XOM 75,000 427,308 0
PDC Energy PDCE 48,000 2,496 19
Carrizo Oil Gas CRZO 21,700 2,922 7
Rex Energy REXX 21,000 1,369 15
EQT Resources EQT 13,600 15,469 1
Source: Company presentations, Bloomberg, state data, Baird

25
Utica Asset Transactions
Announced
Date Buyer(s) Seller(s) Acreage
Feb-14 GPOR Rhino $185 8,200 $22,561
Jan-14 American Energy Partners, LP Paloma Partners $442 26,000 $17,000
Jan-14 American Energy Partners, LP XOM $600 30,000 $20,000
Jan-14 American Energy Partners, LP Hess Corporation $924 74,000 $12,486
Aug-13 Magnum Hunter Resources; Triad Hunter MNW Energy, LLC $142 32,000 4,441
Aug-13 Undisclosed company(ies) EnerVest, Ltd. $228 18,190 $12,551
Aug-13 Undisclosed company(ies) EV Energy Parnters, L.P. $56 4,345 12,888
Feb-13 Gulfport Energy Corporation Wexford Capital LP $220 22,000 10,000
Jan-13 Carrizo Oil Gas Incorporated Avista Capital Partners LLC $63 11,200 5,634
Dec-12 Gulfport Energy Corporation Wexford Capital LLC $372 37,000 10,054
Sep-12 Undisclosed Chesapeake $600 NA NA
Jun-12 Halcon Resources Undisclosed $194 31,809 6,099
Feb-12 Magnum Hunter Resources; Triad Hunter Undisclosed $25 12,186 2,035
Feb-12 Antero Resources Undisclosed $112 19,000 5,895
Sep-11 Hess Corporation Marquette Exploration $750 85,000 8,800
Sep-11 Hess Corporation CONSOL Energy $593 100,000 6,000
Mean $344 34,062 $10,430
Median $224 26,000 $10,000
Source: IHS Herold, Raymond James, Deutsche Bank and Company(ies) press releases.
Total Transaction
Value ($MM)
Implied
$ / Acre

Farley Pad Drilling Locations
26
First Utica horizontal well in Washington
County spud April 10, 2013
• Farley Pad is designed to handle 10
horizontal wells
• A vertical pilot, and subsequent
horizontal well was drilled, logged,
cored, and cased
• Due to complications during the
drilling of the 6,500’ lateral that
resulted in poor integrity with the
cement bond behind the 5½”
casing, only ten stages (about 1/3rd)
have been fracture stimulated
The second and third Utica horizontal
wells in Washington County have been
drilled and cased. The Company will begin
fracture stimulation on these two wells
next year since there is currently no
pipeline connection.
Washington County
Noble County
MHR - Farley Pad
Ten Planned Laterals
0 2000’ 4000’
Completed Well

Stalder Pad Drilling Locations
27
Magnum Hunter announced the
initial production results from the
first Utica horizontal well on the
Stalder Pad on 2/14/14
• Tested at a peak rate of 32.5
MMCF of natural gas per day
• Drilled to a true vertical depth
of 10,653 feet with a 5,050
foot horizontal lateral
• Successfully fracked with 20
stages
The first Marcellus horizontal well
on the Stalder Pad has been
completed and tested
• Drilled to a true vertical depth
of 6,070 feet with a 5,474 foot
horizontal lateral
Currently drilling three additional
horizontal Utica wells (Stalder
#6UH, Stalder #7UH and Stalder
#8UH)
All five wells will be placed on
production prior to YE 2014
MHR - Stalder Pad
Eighteen Planned Laterals
0 2000’
Magnum Hunter/Eclipse JV Acreage
Marcellus Horizontal Well
Utica Horizontal Well
MHR - Stalder #3UH
32.5 MMCF | 97% Methane

Stewart-Winland Pad Drilling Locations
29
The Stewart-Winland Pad located in
Tyler County, WV has seven planned
laterals
• Four wells have been drilled and
completed on the North Unit (3
Marcellus and 1 Utica)
• Three wells will be drilled on the
South Unit (3 Marcellus)
Utica Well was fracture stimulated
(22 stages) and tested at a peak rate
of 46.5 MMCF
Three Marcellus wells have been
drilled and fracture simulated (27, 29
and 29 stages) and presently waiting
on an Air Permit
Magnum Hunter has immediate take-away
capacity on the Eureka Hunter
0 2,000
0 2,000
FEET
FEET
Pipeline system Tyler County, West Virginia
Marcellus Horizontal Well
Utica Horizontal Test Well
MHR - Stewart-Winland Pad
Seven Planned Laterals
MHR / JV Partner Acreage
Stewart-Winland #1300U
Peak Test Rate: 46.5 mmcf/d

Ormet Pad Drilling Locations
31
The Ormet Pad located in Monroe
County, Ohio has twelve additional
laterals
• Three Marcellus wells have been
drilled and are flowing to sales
on the 9H Pad
• Three Utica wells have been
drilled to the intermediate kickoff
point with the first Utica well in
the lateral section (average
~4,700 feet)
• Nine wells will be drilled on the
South Unit (4 Utica)
The three Marcellus wells tested at a
combined rate of 11.7 MMcf/d of
natural gas and 1,788 Bbls/d of
condensate (~3,738 Boe/d)
Acquired ~1,700 mineral acres for
$22.7 million and increased our NRI to
~95%
Magnum Hunter has immediate take-away
capacity on the Eureka Hunter
Pipeline system

Utica Shale – Recent Well Results
Note: MHR currently owns approximately 118,000 net acres in the Utica Shale; following the MNW acquisition, MHR’s acreage position will be in excess of 130,000 net acres. 32

“Best in Class” – Dry Gas Utica
33
Peak Peak
Rate Rate Lateral
Well Name County Operator (MMcfe/d) (Boe/d) % Gas Length Stages
Stewart Winland 1300U Tyler, WV MHR 46.5 7,750 100% 5,289 22
Bigfoot 9H Belmont, OH RICE 41.7 6,948 100% 6,957 40
Stalder #3UH Monroe, OH MHR 32.5 5,417 100% 5,050 20
Irons 1-4H Belmont, OH GPOR 30.3 5,050 100% 6,629 23
Simms U5H Marshall, WV GST 29.4 4,900 100% 4,447 25
Connor 6H Marshall, WV CVN 25.0 4,167 100% 6,451 N/A
Shroyer Monroe, OH ECR 21.3 3,550 100% 7,819 N/A
Tippens #6H Monroe, OH ECR 19.4 3,233 100% 4,424 23
Brown 10H Jefferson, OH CHK 8.7 1,445 100% 4,424 N/A
Average 28.3 4,718 100% 5,721 25.5

34
Marcellus/Utica Wells on Production YTD
(2)
MHR Working MHR Net Estimated Gross Production
Estimated Net Production
(1) Wells are currently flowing back, shut-in and/or producing to sales
(2) Based on estimated IP-30 day rate (average daily amount of production during the first 30 days of production)
(3) Includes NGLs and condensate
(*) Shut-In as a result of pad drilling or awaiting issuance of air permits
(2)
Formation Interest Revenue Interest Boe/d(3) Mcfe/d Boe/d(3) Mcfe/d Status
Stalder #3UH Monroe County, Ohio Utica 47% 39% 2,750 16,500 1,081 6,486 Shut-in (2/22/14)*
Stalder #2MH Monroe County, Ohio Marcel lus 47% 39% 1,160 6,960 456 2,736 Shut-in (2/22/14)*
Ormet #1-9H Monroe County, Ohio Marcel lus 100% 95% 755 4,531 717 4,304 Producing
WVDNR #1207 Wetzel County, West Virginia Marcel lus 100% 80% 717 4,302 574 3,442 Shut-in (5/31/14)*
Mi l ls Wetzel 16H Wetzel County, West Virginia Marcel lus 50% 42% 485 2,910 204 1,222 Producing
Herrick C 8H Monroe County, Ohio Utica 2% 2% - - - - Producing
E Weese 1107 Tyler County, West Virginia Marcel lus 100% 87% 553 3,318 482 2,893 Shut-in (7/16/14)*
R Weese 1001 Tyler County, West Virginia Marcel lus 100% 85% 209 1,254 178 1,071 Shut-in (9/2/14)*
Stewart Winland 1301M Tyler County, West Virginia Marcel lus 100% 87% 1,937 11,622 1,685 10,111 Shut-in (9/19/14)*
Stewart Winland 1300U Tyler County, West Virginia Utica 100% 87% 4,167 25,000 3,625 21,750 Shut-in (9/29/14)*
24,391 146,345 17,479 104,875
Well Name(1)
Location

35
New Marcellus/Utica Production
MHR Working MHR Net Estimated Gross Production
(2)
Estimated Net Production
(1) Wells are currently in the process of drilling, completing, and/or waiting on sales
(2) Based on estimated IP-30 day rate (average daily amount of production during the first 30 days of production)
(3) Includes NGLs and condensate
(2)
Anticipated
Interest Revenue Interest Boe/d(3) Mcfe/d Boe/d(3) Mcfe/d Timing
Stalder #6UH Monroe County, Ohio 47% 39% 3,750 22,500 1,474 8,845 12/31/14
Ormet #8-15UH Monroe County, Ohio 100% 95% 3,333 19,998 3,166 18,998 12/15/14
WVDNR #1410 Wetzel County, West Virginia 100% 80% 970 5,820 776 4,656 12/31/14
E Weese 1414 Tyler County, West Virginia 100% 87% 970 5,820 844 5,063 12/31/14
E Weese 1415 Tyler County, West Virginia 100% 87% 970 5,820 844 5,063 12/31/14
Stephens Uni t Ri tchie County, West Virginia 100% 87% 755 4,530 657 3,941 4/1/15
Farley #1306H Washington County, Ohio 100% 85% 1,667 10,000 1,417 8,502 6/30/15
Farley #1304H Washington County, Ohio 100% 85% 1,667 10,000 1,417 8,502 6/30/15
Farley #1305H Washington County, Ohio 100% 85% 500 3,000 425 2,550 6/30/15
Merl in #10 PPH Washington County, Ohio 14% 10% 1,667 10,000 172 1,033 6/30/15
Haynes Unit 5MH Washington County, Ohio 89% 77% 1,667 10,000 1,286 7,714 7/1/15
Haynes Unit 4UH Washington County, Ohio 89% 77% 3,333 19,998 2,571 15,426 7/1/15
38,324 229,942 26,658 159,947
Well Name(1)
Location

Eureka Hunter Highlights
37
Location
• Strategically located asset base
• NorthernWest Virginia (Primary: Tyler, Ritchie, Wetzel, Pleasants, Doddridge
Secondary: Marion, Harrison, Lewis, Monongalia)
• Southeastern Ohio (Monroe, Washington)
Basins
• Marcellus (wet gas window); ~50% of 2017 volumes
• Dry Utica; ~50% of 2017 volumes
Length
• Currently 105 miles – 170 miles by year end 2014
• Total pipe laid by year-end 2015 ~205 miles
Capacity • 1.5 Bcf/d +
Interconnects
• Processing plants: 2 (4 additional prospective)
• Transmission: 2 (5 additional prospective)
Services
• Provides network of wellhead gas gathering and delivery to specified delivery points
(interstate pipeline for dry gas, processing plant for rich gas)
Customers
• 9 producers
• Top 2 account for majority of expected volumes (including MHR)
Contracts
• Mix of reservation fees and volumetric fees
• Long-term contracts – 10 year minimum
• Volumetric fees with acreage dedication
• Potential compression fees (per stage, as needed)

New Strategic Partner
38
On September 16, 2014, the Company entered into an new partnership with
Morgan Stanley Infrastructure Inc. (“MSI”)
MSI purchased all convertible preferred and common equity interests in Eureka
Hunter Holdings, LLC, previously owned by ArcLight Capital, with a final closing in
early October 2014
In a second closing, expected to occur in January 2015, Magnum Hunter will sell
MSI an additional ~6.5% common equity interest in Eureka Hunter for ~$65
million
This represents an implied equity value of Eureka Hunter of $1.0 billion
Magnum Hunter will have the right to defer a portion of its required future
capital contributions to Eureka
Capital contribution deferral subject to a maximum of $40 million for each 180-day period
Magnum Hunter will have the right to make capital contributions within 180-days that will return
ownership interest back to the level prior to the capital call
This catch-up feature will be at no cost to Magnum Hunter

Contracted vs. Gathered Volumes
39
Eureka Hunter Pipeline 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014
High Pressure Reservation Volume (MMBtu/d)
Magnum Hunter 87,950 92,339 75,000 75,000 83,500 96,000
Third-Parties 35,000 47,000 88,000 88,000 88,000 88,000
Total 122,950 139,339 163,000 163,000 171,500 184,000
High Pressure Throughput Volume (MMBtu/d)
Magnum Hunter 21,880 29,276 39,421 54,306 69,426 84,697
Third-Parties 29,350 37,011 44,120 63,713 83,033 138,875
Total 51,230 66,287 83,541 118,019 152,459 223,572
Current throughput of 275,000 - 290,000 MMBtu/d
Peak throughput rate of 316,500 MMBtu/d in September 2014
Year-End 2014 throughput target of 400,000 MMBtu/d (65% third-party)

Eureka Volume Forecast 2014-2015
40
1,000,000
900,000
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000
0
Mmbtu/d
Third-Party #7
Third-Party #6
Third-Party #5
Third-Party #4
Third-Party #3
Third-Party #2
Third-Party #1
Triad

Eureka Hunter Utica Exposure
41
MONROE
MORGAN
NOBLE
WASHINGTON
DODDRIDGE
LEWIS
MARSHALL
PLEASANTS
RITCHIE
WETZEL
WIRT
TYLER
WOOD
PENN
W.V.
HARRISON
OHIO
W.V.
MarkWest
Mobley
MarkWest
Sherwood
Dominion
Eureka Hastings
Carbide
MarkWest
Seneca
Blue Racer
Natrium
Blue Racer
Berne
Stalder Units
Collins Unit
Farley Units
Eureka Hunter Pipelines
Processing Facilities
Ormet Wells
Clairington
Hub

43
How Do We Measure Up
Gathering Capacity Marcellus / Utica Operations
Eureka Hunter mcf/d, 1500
EQT Midstream mcf/d, 1940
Crestwood Midstream mcf/d,
Markwest Midstream mcf/d,
1000
700
Summit Midstream mcf/d,
1050
Eureka Hunter mcf/d EQT Midstream mcf/d Markwest Midstream mcf/d Crestwood Midstream mcf/d Summit Midstream mcf/d

Eureka Hunter Pipeline - Construction
44
Challenging Terrain Welding Up Pipeline
Connection
Strung Pipe Before
Being Lowered

TransTex Hunter
45
TransTex Hunter, LLC (“TransTex”) founded in 2006; acquired by Eureka Hunter in
April 2012
Design and fabricate gas treating plants for natural gas production
Assets for gas treating, processing, dehydration and separation equipment
Significant market position in treating plants 60 GPM and smaller
38 units currently on location and in operation with 19 customers
Majority of the plants located in Texas – in both conventional and unconventional oil / gas fields
Building new units in Hallettsville fabrication shop to meet increased demand
Operations team - Design, build, install and operate all sizes of gas treating plants
Over 90% of revenue from operating lease agreements; 24 - 36 months
Majority of plants remain in place beyond the term of original agreement

TransTex Hunter Amine Plants
46

Drilling Fleet Overview
Current fleet of six (6) drilling rigs with one (1) Schramm TXD 500 on order
• One (1) – Schramm TXD 500 (new rig on order)
– Rig #7
o Spud first well (Stalder Pad) on July 1, 2013
o Contract Rate of $21,500/day
o Two (2) year term with Triad Hunter
• Five (5) – Schramm TXD 200
– Rig #4
o Contracted with EQT through December 2015
– Rig #5
– Rig #6
– Rig #8
– Rig #9
o Contracted with Eclipse through October 2014
48

$35
$30
$25
$20
$15
$10
$5
$0
2010 2011 2012 2013 2014
Revenues ($ in millions)
Revenues
49
Alpha Hunter Growth Continues

Alpha Hunter Experience
50
Company # of Wells Drilled
Bretagne 1
CNX Gas 8
Consol 3
CentralWV Oil Gas 1
Dominion 34
Eagle Ford Hunter 15
Eclipse 32
EQT 246
EXCO Resources 57
Green Hunter Water 4
Hildreth 7
PetroEdge 1
Rex Energy 2
Rogers Son 1
Rouzer Oil 5
Triad Hunter 21
Virco 1
TOTAL WELLS DRILLED(1) 439
Year # of Wells Drilled
2010 51
2011 64
2012 69
2013 148
2014(1) 107
TOTAL 439
(1) Wells drilled through June 2014

Financial Strategy
Capital spending driven by rates of return across all operating areas
Focus on development of existing acreage in our core areas
2014 capital budget will focus predominately on high return areas in the Appalachian Basin
Margins and EBITDAX projected to substantially increase throughout the next two years
Limited overhead expansion required to meet growth objectives
Emphasis on GA reductions with non-core assets sales coupled with a decreased reliance on third-party
consultants
Maintain manageable credit ratios and liquidity while managing growth
Continue to increase Senior Credit Facility borrowing base through reserves additions from organic growth to
maximize liquidity
Raised a total of $180 million of new equity in 2014
Aggressively pursuing additional non-core asset divestitures
Monetize midstream assets with MLP IPO in early 2015
The Company became shelf eligible in August 2014
Goal is to further simplify balance sheet
Maintain an active hedging program to support economic returns and ensure strong coverage
metrics
Target rolling 50% hedging program one to two years forward – will hedge further opportunistically
Current natural gas hedges in place provide ~$4.23/MMBtu on ~50% of estimated 2014 production
52

53
Adjusted EBITDAX Reconciliation
(1)
FYE 2010 FYE 2011 FYE 2012 FYE 2013 FYE 2014
Net income (loss) from continuing operations ( 22.3) ( 76.7) ( 119.7) ( 204.1)
Unrealized (gain) loss on derivatives 3.1 4.2 ( 10.9) 17.1
Net interest expense 3.6 12.0 51.6 72.4
Income taxes expense (benefit) - ( 0.7) ( 19.3) ( 70.3)
Impairment of oil and gas properties 0.3 22.9 3.8 10.0
Depreciation, depletion and amortization 8.9 49.1 59.7 99.2
Non-Cash stock compensation expense 6.3 25.1 15.7 13.6
Non-Cash 401K matching expense - - 1.4 1.9
Exploration expense 0.9 1.5 78.2 97.3
(Gain) loss on sale of assets ( 0.1) ( 0.2) 0.6 44.7
Unrealized (gain) loss on investments - - - 0.8
Non-recurring transaction and other expense 3.4 13.2 15.1 29.8
Total Adjusted EBITDAX $4.2 $50.4 $76.2 $112.4 $185.0
Please note Adjusted EBITDAX includes net income from continuing operations (excludes net income from discontinued operations)
(1) Estimated full year consolidated EBITDAX

54
MHR Non-Core Divestiture Summary
Asset Sales Value ($MM)
Completed in 2013
Eagle Ford Sale $401.0
Gain on Sale of PVA Stock $10.6
Burke County, North Dakota - Non-Operated Properties $32.5
North Dakota - Madison Waterfloods - Operated Properties $45.0
Red Star Gold $1.5
Subtotal for 2013 $490.6
Completed in 2014 YTD
Other Eagle Ford Shale Properties - Atascosa County(1) $24.5
Alberta Properties $8.7
Williston Hunter Canada, Inc. - Saskatchewan, Canada $67.5
Vadis Field - West Virginia $0.5
Non-Core North Dakota Non-Op $23.0
Subtotal for 2014 $124.2
In Process (Est.)
Non-Core Oil/ WV Waterfloods $1.0 - $2.0 (Est.)
Bakken Non-Op (Baytex) $75.0 - $90.0 (Est.)
Bakken Non-Op (Samson) $325.0 - $425.0 (Est.)
Bakken Operated $11.0 - $13.0 (Est.)
Subtotal for 2014 $412.0 - $530.0 (Est.)
Total 2014 Non-Core Assets $536.2 - $654.2 (Est.)
(1) Includes $15.0 million of cash and $9.5 million of stock

55
Crude Oil and Natural Gas Hedges
Crude Oil 2014 2015 2016
NYMEX Average (1) $94.03 $90.56 $88.08
Weighted-Average Hedge Price With Ceilings $100.90 $115.93 -
Weighted-Average Hedge Price With Floors $85.00 $85.00 -
Weighted-Average Swap Price - - -
Hedge Volumes (2)(3) 4,663 259 -
Natural Gas 2014 2015 2016
NYMEX Average (1) $4.19 $4.03 $4.11
Weighted-Average Hedge Price With Ceilings $5.23 - -
Weighted-Average Hedge Price With Floors $4.23 - -
Weighted-Average Swap Price $4.21 $4.12 -
Hedge Volumes (2)(3) 56,000 30,000 -
(1) NYMEX strip pricing as of 9/30/2014
(2) Includes three-way oil collars: Floors sold (put) by year are as follows: 2014: 4,663 bbls/d at $64.95 ; 2015: 259 bbls/d at $70.00
(3) Does not include 1,570 bbls/d at $120.00 of sold calls in 2015

56
MHR Net Asset Value*
Assumptions Valuation
($ in thousands) Low High Low High
Total Proved Reserves PV-10 (6/30/2014) (1) 916,253 916,253
$/acre
Undeveloped Acreage (2) Low High
Williston Basin U.S. 42,700 $3,000 $5,000 $128,100 $213,500
Marcellus 49,800 $5,000 $7,000 $249,000 $348,600
Utica - Wet 47,200 $10,000 $13,000 $472,000 $613,600
Utica - Dry 70,800 $12,500 $15,000 $885,000 $1,062,000
Other Appalachia 200,000 $50 $100 $10,000 $20,000
Total $1,744,100 $2,257,700
Certain Other Assets (6/30/2014)
Eureka Hunter Pipeline - MHR Share of Estimated Total Market Value (3) $515,000 $660,000
Alpha Hunter Drilling (4) $20,000 $40,000
Total $535,000 $700,000
Total Asset Value $3,195,353 $3,873,953
Less (6/30/2014):
. Series C Preferred $100,000 $100,000
Series D Preferred $221,244 $221,244
Series E Preferred $95,069 $95,069
Senior Revolver Outstanding, net of cash (5) $223,400 $223,400
Senior Notes $600,000 $600,000
Other Debt $25,609 $25,609
Total $1,265,322 $1,265,322
Net Asset Value $1,930,031 $2,608,631
Shares Outstanding (6) 199.4 199.4
Net Asset Value per Share $9.68 $13.08
* See Appendix for information regarding NAV, PV-10 and Standardized Measure
(1) Includes the proved reserves associated with the divestiture of the non-core assets in Divide County, North Dakota for $23.0 million
(2) Approximate amount of undeveloped acreage as of June 30, 2014
(3) Based on MHR’s estimated total market valuation of Eureka Hunter Pipeline of between $1.0 billion and $1.25 and MHR’s approximate 58% equity ownership of Eureka Hunter Pipeline
(4) MHR’s estimated FMV of Alpha Hunter Drilling
(5) As of July 31, 2014, there was ~$265.5 million of debt outstanding under our senior revolving credit facility and ~$42.1 million of cash on hand
(6) As of August 7, 2014 there were ~199.4 million shares outstanding

A Focused Company on the Right Path
57
Proven management and technical team in place committed to proper
capital allocation for future growth
Geographically diversified asset base in three of the most prolific
shale plays in the US (Utica, Marcellus and Bakken)
Successful proven track record in all aspects of the development of
key resource plays in the US
Improved balance sheet ($180 MM of new Equity) with liquidity
options to provide operational flexibility in funding capital
expenditures for future growth
Continued focus on operational efficiency and net margin expansion
Commitment to best practices regarding financial and operational
procedures

Equity Research Coverage / Contact Information
Equity Research Analyst Coverage:
BMO Capital Markets Maxim Group
Canaccord Genuity MLV Partners
Capital One Southcoast RBC Capital Markets
Citigroup Global Markets Robert W. Baird Co.
Credit Suisse Securities Stephens
Deutsche Bank Securities Stifel Nicolaus
GMP Securities SunTrust Robinson Humphrey
Imperial Capital Topeka Capital Markets
KeyBanc Capital Markets UBS Securities
KLR Group Wunderlich Securities
Website: www.magnumhunterresources.com
Headquarters: 777 Post Oak Blvd., Suite 650
Houston, TX 77056
(832) 369-6986
Contact: Investor Relations
(832) 203-4539
ir@magnumhunterresources.com
58
Magnum Hunter Resources (NYSE: MHR)

Appendix
59
Net Asset Value
Although Magnum Hunter does not consider “Net Asset Value” and “Net Asset Value Per Share” to be “non-GAAP financial measures,” as defined in SEC rules, Magnum Hunter uses
Net Asset Value as an estimate of fair value. Net Asset Value and Net Asset Value Per Share should not be considered as alternatives to PV-10, GAAP Stockholders Equity or GAAP per
share net income (loss) amounts. Magnum Hunter’s NAV calculation is based on numerous assumptions that may change as a result of future activities or circumstances.
PV-10
PV-10 is the present value of the estimated future cash flows from estimated total proved reserves after deducting estimated production and ad valorem taxes, future capital costs and
operating expenses, but before deducting any estimates of future income taxes. The estimated future cash flows are discounted at an annual rate of 10% to determine their present
value. We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure
of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique
factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the
Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. However, PV-10 should not be
considered as an alternative to the standardized measure as computed under GAAP.
The standardized measure of discounted future net cash flows relating to Magnum Hunter's total proved oil and natural gas reserves is as follows:
Unaudi ted
30-Jun-14
Future cash inflows $ 3,629,151
Future production costs (1,456,377)
Future development costs (369,976)
Future income tax expense (95,808)
Future net cash flows 1,706,990
10% annual discount for estimated
timing of cash flows (838,595)
Standardized measure of discounted future
net cash flows related to proved reserves $ 8 68,395
Reconci l iation of Non-GAAP Measure
PV-10 $ 916,253
Less: Income taxes
Undiscounted future income taxes (95,808)
10% discount factor 47,950
Future discounted income taxes (47,858)
Standardized measure of discounted future net cash flows $ 868,395

Forward-Looking Statements
60
The statements and information contained in this presentation that are not statements of historical fact, including any estimates and assumptions contained herein, are forward looking statements as defined in Section 27A of the
Securities Act of 1933, as amended, referred to as the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, referred to as the Exchange Act. These forward-looking statements include, among others,
statements, estimates and assumptions relating to our business and growth strategies, our oil and gas reserve estimates, estimates of oil and natural gas resource potential, our ability to successfully and economically explore for and
develop oil and gas resources, our exploration and development prospects, future inventories, projects and programs, expectations relating to availability and costs of drilling rigs and field services, anticipated trends in our business or
industry, our future results of operations, our liquidity and ability to finance our exploration and development activities and our midstream activities, market conditions in the oil and gas industry and the impact of environmental and
other governmental regulation. In addition, with respect to any pending transactions described herein, forward-looking statements include, but are not limited to, statements regarding the expected timing of the completion of
proposed transactions; the ability to complete proposed transactions considering various closing conditions; the benefits of any such transactions and their impact on the Company's business; and any statements of assumptions
underlying any of the foregoing. In addition, if and when any proposed transaction is consummated, there will be risks and uncertainties related to the Company's ability to successfully integrate the operations and employees of the
Company and the acquired business. Forward-looking statements generally can be identified by the use of forward-looking terminology such as may, will, could, should, expect, intend, estimate, anticipate, believe,
project, pursue, plan or continue or the negative thereof or variations thereon or similar terminology.
These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking
statements include, among others, the following: adverse economic conditions in the United States and globally; difficult and adverse conditions in the domestic and global capital and credit markets; changes in domestic and
global demand for oil and natural gas; volatility in the prices we receive for our oil, natural gas and natural gas liquids; the effects of government regulation, permitting and other legal requirements; future developments with respect to
the quality of our properties, including, among other things, the existence of reserves in economic quantities; uncertainties about the estimates of our oil and natural gas reserves; our ability to increase our production and therefore
our oil and natural gas income through exploration and development; our ability to successfully apply horizontal drilling techniques; the effects of increased federal and state regulation, including regulation of the environmental
aspects, of hydraulic fracturing; the number of well locations to be drilled, the cost to drill and the time frame within which they will be drilled; drilling and operating risks; the availability of equipment, such as drilling rigs and
transportation pipelines; changes in our drilling plans and related budgets; regulatory, environmental and land management issues, and demand for gas gathering services, relating to our midstream operations; and the adequacy of our
capital resources and liquidity including, but not limited to, access to additional borrowing capacity.
These factors are in addition to the risks described in the Risk Factors and Management's Discussion and Analysis of Financial Condition and Results of Operations sections of the Company's 2013 annual report on Form 10-K, as
amended, filed with the Securities and Exchange Commission, which we refer to as the SEC, and subsequently filed quarterly reports on Form 10-Q. Most of these factors are difficult to anticipate and beyond our control. Because
forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements
contained herein, which speak only as of the date of this document. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Unless otherwise
required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. We urge readers to review and consider disclosures we
make in our reports that discuss factors germane to our business. See in particular our reports on Forms 10-K, 10-Q and 8-K subsequently filed from time to time with the SEC. All forward-looking statements attributable to us are
expressly qualified in their entirety by these cautionary statements.
The SEC requires oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with
reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as
likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities
recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain,
even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in
communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of
exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus
possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas
where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a
greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a
reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the
Company believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in
communication with the proved reservoir. Where direct observation has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher
portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned
as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
The term “contingent resources” is a broader description of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. In this presentation disclosure of “contingent resources” represents a high
estimate scenario, rather than a middle or low estimate scenario. Estimates of contingent resources are by their nature more speculative than estimates of proved, probable, or possible reserves and accordingly are subject to
substantially greater risk of actually being realized by the Company. We believe our estimates of contingent resources and future drill sites are reasonable, but such estimates have not been reviewed by independent engineers.
Estimates of contingent resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.
Note Regarding Non-GAAP Measures
This presentation includes certain non-GAAP measures, including Adjusted EBITDAX and PV-10, which are described in greater detail in this presentation. Management believes that these non-GAAP measures, which may be defined
differently by other companies, better explain the Company's results of operations in a manner that allows for a more complete understanding of the underlying trends in the Company's business, and are also measures that are
important to the Company’s lenders. However, these measures should not be viewed as a substitute for those determined in accordance with GAAP.

Newest Investor Presentation from Magnum Hunter Resources, Issued Oct 2014

Recommended

Recommended

More Related Content

What's hot

What's hot (19)

Similar to Newest Investor Presentation from Magnum Hunter Resources, Issued Oct 2014

Similar to Newest Investor Presentation from Magnum Hunter Resources, Issued Oct 2014 (20)

More from Marcellus Drilling News

More from Marcellus Drilling News (20)

Recently uploaded

Recently uploaded (20)

Newest Investor Presentation from Magnum Hunter Resources, Issued Oct 2014