Newest Investor Presentation from Magnum Hunter Resources, Issued Oct 2014

MAGNUM HUNTER RESOURCES CORPORATION

Investor PresentationOctober 2014

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

� 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

is ~300,000 net acres

� Significant insider ownership of management aligns with shareholder interest

Who We Are

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

~88,600 Net Acres

North Dakota

~278,800 Net Southern

Appalachia Acres

~80,300 Net

Marcellus Acres

~118,000 Net Utica

Acres

Mid-Year 2014 Proved Reserves

% Oil/ Gross Drilling

(MMBoe) % PDP Liquids Locations(1)

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

� A well-balanced and concentrated asset base in large shale plays

� Secure footholds in West Virginia, Ohio, Kentucky, and North Dakota

(1) Represents total potential drilling locations reflecting current acreage position and reserve report as of June 30, 2014

Williston BasinBakken / Three Forks Sanish

Appalachian BasinMarcellus / Utica / Huron / Weir

Production Growth

3

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

�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)

(2)

1,276

4,895

7,739

14,831

32,500

2010 2011 2012 2013 2014 Target Exit Rate

Oil / Liquids Natural Gas

(2)

0.160.20

0.35

0.400.42

0.40

0.78

0.67

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)

Proved Reserve Growth Consistency

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

(C) (C)

Reserves Summary

5

Reserves Summary

Proved Reserve Allocation Proved Reserves by Region

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

Other

0.1%

Williston Basin

19.5%

Appalachia

80.4%Oil / Liquids

37.7%

Gas 62.3%

� 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

6

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

Growth Plan Continues

4.2

50.4

76.2

112.4

185.0

28.6

66.5

140.4

280.4

410.0

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

2010 2011 2012 2013 2014

($ M

M)

EBITDAX Revenue

Breakdown of Capital Expenditure Budgets

7

2013 Drilling and Completion Capital Expenditures 2014 Capital Budget

34%

34%

22%

10%

Appalachia Williston Eureka Hunter Eagle Ford/Other

65%

13%

23%

Appalachia Williston Eureka Hunter

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

(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

As of June 30, 2014

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

Developed

Acreage (1)

Undeveloped

Acreage (2)

Total Acreage

9

Williston Basin Division

Williston Basin Overview

10

OverviewAreas of Operation

� 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

OverviewAreas of Operation

� 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 Dakota) MHR resultsWilliston (North Dakota) MHR results

1st / 2nd Quarter 20144th Quarter 2013

684

736

803

874906

968

791

558

822

876

806

423

526 536

443

581

411

595

495

392

653677

568

317

4036

25 2532

24 26 2630 30

25 25

0

200

400

600

800

1000

1200

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

Cru

de

Oil

Pro

du

ctio

n (

Bo

e/)

d

24-Hour IP Rates 30-Day IP Rates # of Frac Stages

Bakken Hunter Fracture Stimulation Trends

13

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

0 10 20 30 40 50 60 70 80 90

To

tal

Flu

id R

ate

,Bp

d

Days

Plug & Perf vs Sleeves

Fluid Rate vs Time

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

P&P Average

Sleeve Average

P&P + 30%

More Fluid

ONEOK Net Production & Revenue

14

0

500

1,000

1,500

2,000

2,500

Bp

dM

mcf

do

r M

$/m

o

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)

(1) NYMEX crude oil (WTI) spot pricing as of 9/9/2014 was $92.75 per Bbl

IRR: 11%

IRR: 19%

IRR: 33%

IRR: 29%

$0

$2

$4

$6

$8

$10

$12

$75 $80 $85 $90 $95 $100 $105 $110

Sin

gle

We

ll N

PV

10

($

MM

)

Realized Oil Price(1), $/Bbl

North Dakota - West (High Case) North Dakota - West (Base Case)

IRR: 14%

IRR: 16%

IRR: 9%

IRR: 21%

IRR: 24%

IRR: 26%

IRR: 37%

IRR: 42%

IRR: 46%

IRR: 50%

IRR: 55%

IRR: 59%

16

Appalachian Division

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 Well ResultsMarcellus Operated Well Results

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)

Recently Completed Wells12,85412,421

12,832 12,670

3,972

10,013

8,412

9,6779,316

10,119

9,543

10,340

8,8428,560

3,5023,697

6,980

1821 21

24

1214

1920 20 19

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

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

24-Hour IP Rates 30-Day IP Rates # of Frac Stages

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 wellhead Mcf basis between $0.50 - $1.00

� The Company has 200 MMcf/d of dedicated processing capacity at the Mobley Plant

(1) All values shown are versus wellhead production in Mcf.

Wellhead Gas

1 Mcf

Btu = ~1,270

Cryo

Processing

1.64 Gal / Mcf

Methane

0.85 – 0.89 Mcf

Ethane

3.0 – 3.5 Gal / Mcf

Residue Nat. Gas and

Ethane

Btu = ~1,060

NGLs

Liquids

Fractionation

(C3+)$0.50 - $1.00

+ $3.50 - $4.00

$4.00 - $5.00

Per Wellhead Mcf (1)

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50

High Case Base Case

Economic Sensitivity of Marcellus “Magnum

Rich”

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

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

Sin

gle

We

ll N

PV

-10

($

MM

)

IRR: 28%

IRR: 38%

IRR: 49%

IRR: 60%

IRR: 72%

IRR: 83%

IRR: 94%

Base Case:


EUR: 7.8 Bcfe (includes NGLs)

IRR: 105%

IRR: 59%

Marcellus Shale

21Note: MHR owns approximately 80,300 net acres in the Marcellus Shale.

MONROENOBLE

WASHINGTON

DODDRIDGE

PLEASANTS

RITCHIE

WETZEL

WIRT

TYLER

WOOD

Magnum Hunter Acreage

Eureka Hunter Pipelines

MHR - Ormet #15 Pad

MHR/Eclipse - Stalder Pad

Eclipse/MHR - Herrick Pad

Mark West – Mobley

Fractionation Facility

Eureka - Carbide

Compression Facility

MHR / Stone JV Pads

MHR - Spencer PadMHR - WVDNR Pad

MHR - Collins Pad

MHR - Ormet #9 Pad

MHR/Eclipse - McIntire Pad

MHR - Meckley-Wells Pad

MHR - Stewart-Winland Pad

MHR - Everest-Weese Pad

MHR - Stevens Pad

Utica Shale Overview

22

� The Utica Shale extends approximately 170,000 square miles throughout theAppalachia Basin in the United States and Canada

• Ordovician-aged organic rich black shale with interbedded limestone withtarget 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, wetgas/condensate, and dry gas with the majority of the activity focused onthe wet gas and condensate window

� The “Sweet Spot” for liquids-rich gas occurs in eastern Ohio along a narrowband 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 indicativeof the quantity of kerogen in the rock, which is the source material for oil andgas

• TOC is derived from core analysis; however, it can also be inferred fromopen hole log resistivity measurements where sufficient data exists for agood correlation

• There is a general correlation between higher gross interval thickness andlarger TOC values

• East of the Ohio River, the Utica/Point Pleasant is sufficiently deep for theformations to produce dry gas; these areas of high TOC also correspond tohigh Ro values

� Acreage owned by the Company exhibits good thickness and is highlyprospective with a large portion of the acreage in the wet gas and condensatewindow

Isopach Map of Utica/Point Pleasant

Total Organic Carbon

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

Source: Company presentations, Bloomberg, state data, Baird

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

25

Utica Asset Transactions

Source: IHS Herold, Raymond James, Deutsche Bank and Company(ies) press releases.

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

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.

Wa

shin

gto

n C

ou

nty

No

ble

Co

un

ty

0 2000’ 4000’


MHR - Farley Pad

Ten Planned Laterals

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’


Marcellus Horizontal Well

Utica Horizontal Well

Magnum Hunter/Eclipse JV Acreage

MHR - Stalder #3UH

32.5 MMCF | 97% Methane

Pad Drilling

28

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

Pipeline systemFEET

0 2,000

FEET

0 2,000

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

Fracing Operations

30

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

32Note: 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.

“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


(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

MHR Working MHR Net Estimated Gross Production(2)

Estimated Net Production(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 Marcellus 47% 39% 1,160 6,960 456 2,736 Shut-in (2/22/14)*

Ormet #1-9H Monroe County, Ohio Marcellus 100% 95% 755 4,531 717 4,304 Producing



WVDNR #1207 Wetzel County, West Virginia Marcellus 100% 80% 717 4,302 574 3,442 Shut-in (5/31/14)*



Mil ls Wetzel 16H Wetzel County, West Virginia Marcellus 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 Marcellus 100% 87% 553 3,318 482 2,893 Shut-in (7/16/14)*



R Weese 1001 Tyler County, West Virginia Marcellus 100% 85% 209 1,254 178 1,071 Shut-in (9/2/14)*



Stewart Winland 1301M Tyler County, West Virginia Marcellus 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


(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

MHR Working MHR Net Estimated Gross Production(2)

Estimated Net Production(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 Unit Ritchie 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

Merlin #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

36

Eureka Hunter Midstream

Eureka Hunter Highlights

37

Location

• Strategically located asset base

• Northern West 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

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 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

Eureka Volume Forecast 2014-2015

40Note: This information constitutes forward-looking statements and is subject to the qualifications on the last page of this investor presentation

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

Mm

btu

/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

HARRISON

PENN

W.V.

W.V.

OHIO

MarkWestMobley

MarkWestSherwood

Dominion HastingsEureka

Carbide

MarkWestSeneca

Blue Racer Natrium

Blue Racer Berne

Stalder Units

Collins Unit

Farley Units

Eureka Hunter Pipelines

Processing Facilities


Ormet Wells

ClairingtonHub

2015-2016 Update

42

43

How Do We Measure Up

Eureka Hunter mcf/d, 1500

EQT Midstream mcf/d, 1940

Markwest Midstream mcf/d,

1000

Crestwood Midstream mcf/d,

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

Gathering Capacity Marcellus / Utica Operations

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

47

Alpha Hunter Drilling

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 #7o 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 #5o Contracted with EQT through December 2015






– Rig #9o Contracted with Eclipse through October 2014


48

$0

$5

$10

$15

$20

$25

$30

$35

2010 2011 2012 2013 2014

Re

ve

nu

es

($ i

n m

illi

on

s)

Revenues

49

Alpha Hunter Growth Continues


Alpha Hunter Experience

50

Company # of Wells Drilled

Bretagne 1

CNX Gas 8

Consol 3

Central WV 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

51

Financial Overview

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 G&A 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

FYE 2010 FYE 2011 FYE 2012 FYE 2013 FYE 2014(1)

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

(1) Includes $15.0 million of cash and $9.5 million of stock

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.)

55

Crude Oil and Natural Gas Hedges

(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

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 -

56

MHR Net Asset Value*

* 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

Assumptions Valuation

($ in thousands) Low High Low High

Total Proved Reserves PV-10 (6/30/2014) (1)

916,253 916,253

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

$/acre

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 Analyst Coverage:

Website: www.magnumhunterresources.com

Headquarters: 777 Post Oak Blvd., Suite 650

Houston, TX 77056

(832) 369-6986

Contact: Investor Relations

(832) 203-4539

[email protected]

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

Equity Research Coverage / Contact Information

58

Magnum Hunter Resources (NYSE: MHR)

Appendix

59

Net Asset ValueAlthough 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 usesNet 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 pershare 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-10PV-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 andoperating 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 "presentvalue." 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 measureof 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 uniquefactors 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 theCompany. 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 beconsidered 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:

Unaudited

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 868,395$

Reconciliation 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 orindustry, 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 ofproposed 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 theCompany 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 tothe 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 environmentalaspects, 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 ourcapital 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. Becauseforward-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 otherwiserequired 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 areexpressly 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 aslikely 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 ofexceeding 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 areaswhere 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 areservoir 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 incommunication 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 assignedas 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 tosubstantially 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 defineddifferently 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.

News & Politics

Newest Investor Presentation from Magnum Hunter Resources, Issued Oct 2014