1. business and industrial
2. energy
3. natural gas

MAGNUM HUNTER RESOURCES CORPORATION
Investor Presentation
December 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
is ~300,000 net acres
Significant insider ownership of management aligns with shareholder interest
Key Metrics
Current Market Capitalization
~$1,000 MM
Current Enterprise Value
~$2,350 MM
Target 2014 Exit Rate Production(1) 32.5 MBoepd
2013 Stock Price Appreciation(2)
Proved Reserves(3)
~83%
79.8 MMBoe
3P Reserves(4)
132.9 MMBoe
Contingent Resources(5)
891.1 MMBoe
(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
1
Where We Operate
A well-balanced and concentrated asset base in large shale plays
Secure footholds in West Virginia, Ohio, Kentucky, and North Dakota
~88,600 Net Acres
North Dakota
~80,500 Net
Marcellus Acres
Williston Basin
Bakken / Three Forks Sanish
Appalachian Basin
Marcellus / Utica / Huron / Weir
~118,000 Net Utica
Acres
~278,800 Net Southern
Appalachia Acres
Appalachia
Williston Basin
South Texas/Other
Total
(1) Represents total potential drilling locations reflecting current acreage position and reserve report as of June 30, 2014
Mid-Year 2014 Proved Reserves
% Oil/
(MMBoe)
% PDP
Liquids
64.1
46.8%
24.3%
15.5
48.1%
93.4%
0.2
2.7%
12.0%
79.8
47.0%
37.7%
Gross Drilling
Locations(1)
1,438
1,530
0
2,968
2
Production Growth
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)
(2)
32,500
14,831
7,739
4,895
1,276
2010
2011
2013 (1)
2012
Oil / Liquids
2014 Target Exit Rate (2)
Natural Gas
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
3
2014 Production Profile
34,409
33,938
35,000
29,677
30,067
30,000
25,000
19,970
20,086
Boe/D
20,000
20,673
20,041
20,925
21,369
17,925
14,566
15,000
10,000
5,000
January
February
March
April
May
June
Actual Procuction (BOE)
July
August
September
October
November December
Estimated Shut-In (BOE)
(1) Includes, on a pro forma basis, reported production and previously reported production from discontinued operations
(2) Based upon estimated shut –in volume at the end of each month
Note: October, November and December actual production are projections and this information constitutes forward-looking statements and is subject to the qualifications on the last page of
this investor presentation
4
Proved Reserve Growth Consistency
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/3P Reserves (Boe) / Share(B)
Proved Reserves (MMBoe)(A)
79.8
0.78
72.1
0.67
61.6
61.5
53.2
0.40
39.6
0.42
0.40
0.35
0.20
0.16
12.8
6.2
2009
2010
2011
Proved Reserves (MMBoe)
2012
2013
2014
(C)
Probable & Possible (MMBoe)
(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
2009
2010
2011
Proved Reserves (MMBoe)
2012
2013
2014 (C)
Probable & Possible (MMBoe)
5
Reserves Summary
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
(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%
$1,166
Contingent Resources
140.3
4,505.0
891.1
Total Contingent Resources
202.3
4,930.5
1,024.1
Category
Proved Reserve Allocation
Proved Reserves by Region
Appalachia
80.4%
Oil / Liquids
37.7%
Gas 62.3%
Williston Basin
19.5%
Other
0.1%
6
Growth Plan Continues
EBITDAX
Revenue
$450
410.0
$400
$350
($ MM)
$300
280.4
$250
$200
185.0
140.4
$150
112.4
$100
66.5
76.2
50.4
$50
28.6
4.2
$0
2010
2011
2012
2013
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
2014
7
Breakdown of Capital Expenditure Budgets
2013 Drilling and Completion Capital Expenditures
Appalachia
Williston
Eureka Hunter
2014 Capital Budget
Appalachia
Eagle Ford/Other
Williston
Eureka Hunter
10%
23%
34%
22%
13%
65%
34%
Total: $389 Million(1)
(1) Excludes leasehold acquisitions of $144.3 million for the twelve months ended December 31, 2013
Total: $400 Million
8
Substantial Leasehold Inventory
Developed
As of September 30, 2014
Acreage
Gross
Undeveloped
(1)
Net
Acreage
Gross
(2)
Net
Total Acreage
Gross
Net
(3)
Appalachian Basin
Marcellus Shale
Utica Shale
Magnum Hunter Production
Other
Total
58,334
68,887
145,086
24,620
296,928
57,908
64,991
109,568
24,620
257,087
28,066
59,251
167,139
40
254,496
22,651
52,925
146,736
17
222,329
86,400
128,139
312,225
24,660
551,424
80,559
117,916
256,305
24,637
479,416
1,777
1,777
880
880
618
618
546
546
2,395
2,395
1,426
1,426
North Dakota
Total
174,456
174,456
47,124
47,124
88,973
88,973
38,783
38,783
263,428
263,428
85,907
85,907
MHR TOTAL
473,161
305,091
344,087
261,658
817,248
566,749
South Texas
(4)
Other
Total
Williston Basin - USA
(5)
(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 48,578 Gross Acres and 43,273 Net Acres overlap in our Utica Shale and Marcellus Shale
(4) Pertains to certain miscellaneous properties in Texas and Louisiana
(5) Includes the acreage associated with the recent divestitures of non-core assets in Divide County, North Dakota
9
Williston Basin Division
10
Williston Basin Overview
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
11
Ambrose/Divide County 2014 Activity
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 $500K/month
12
Bakken Hunter Fracture Stimulation Trends
Plug & Perf vs Sleeves
Fluid Rate vs Time
Bernie A 20-17-162-98H 2XC
Bernie B 20-17-162-98H 3XB
Comet 2635-7H (26-35-163-99)
Bel Air 2314-7H (23-14-163-99)
100,000
Les Hall 18-19-162-99H 2DM
Kathlyn Hall 18-19-162-99H 3DN
90,000
Nelson 18-19-161-98H 1BP
Comet 2635-2H (26-35-163-99)
80,000
Total Fluid Rate,Bpd
Bel Air 2314-1H (23-14-163-99)
70,000
Bel Air 2314-2H (23-14-163-99)
P&P + 30%
More Fluid
60,000
Comet 2635-5H (26-35-163-99)
Comet 2635-1H (26-35-163-99)
Bel Air 2314-5H (23-14-163-99)
50,000
Marilyn Nelson 29-32-162-98H 1BP
Marilyn Nelson 20-17-162-98H 1XB
40,000
Stingray 18-19-162-98
Randy Olson 17-20-161-98
30,000
Thompson 2-11-161-99
Hansen 18-19-162-99
20,000
Edna 14-23-162-100
10,000
Twin Butte 17-20-162-99H 1BP
Dahl 13-24-162-100H
0
P&P Average
0
10
20
30
40
50
60
70
80
90
Sleeve Average
Days
13
ONEOK Net Production & Revenue
Williston Basin
Net Gas & NGL Production & Revenue
2,500
Gas, mcfd
BpdMmcfd or M$/mo
2,000
NGL, bpd
Gas & NGL Revenue, M$
1,500
Est. Gas, mcfd
Est. NGL, bpd
Est. Gas & NGL Rev, M$
1,000
500
~ 600 Boe/d
0
14
Williston Basin Economics – Sensitivity
North Dakota – West (High Case)
CAPEX: $6.0 million per well
EUR: 550 MBOE
Differential: ($8)
North Dakota – West (Base Case)
CAPEX: $6.0 million per well
EUR: 350 MBOE
Differential: ($8)
North Dakota - West (High Case)
North Dakota - West (Base Case)
$12
IRR: 59%
IRR: 55%
$10
IRR: 50%
Single Well NPV10 ($MM)
IRR: 46%
$8
IRR: 42%
IRR: 37%
IRR: 33%
$6
IRR: 29%
IRR: 26%
$4
IRR: 24%
IRR: 21%
IRR: 19%
IRR: 16%
$2
IRR: 14%
IRR: 11%
IRR: 9%
$0
$75
$80
$85
$90
$95
$100
$105
$110
Realized Oil Price(1), $/Bbl
(1) NYMEX crude oil (WTI) spot pricing as of 9/9/2014 was $92.75 per Bbl
15
Appalachian Division
16
Appalachian Division Overview
Overview
Areas of Operation
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)
(1) Marcellus/Utica well locations only contemplate locations with a working interest > 70%
Utica and Marcellus Shale Overview
• 52 gross wells have been drilled and placed on production todate 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: 9 gross (7.5 net)
– 3 gross (1.5 net) wells in Monroe County, OH
– 4 gross (4 net) wells in Wetzel County, WV
– 2 gross (2 net) wells in Tyler County, WV
17
Marcellus Shale Recent Well Results
Marcellus Operated Well Results
IP 30-day avg. rate (Mcfe/d)
IP 24-hr avg. rate (Mcfe/d)
Frac Stages (#)
Recently Completed Wells
18,000
17,028
17,116
16,847
29
29
16,000
14,000
12,854
12,421
12,832
12,670
12,000
10,340
10,000
10,013
9,543
8,842
9,677
10,119
9,316
8,412
8,560
8,000
6,980
6,000
3,972
4,000
2,000
3,697
3,502
18
21
21
27
24
12
14
19
20
20
19
0
Collins Unit Collins Unit Collins Unit Collins Unit Ormet 1-9H Ormet 2-9H Ormet 3-9H
#1116H
#1117H
#1118H
#1119H
WVDNR
#1207
WVDNR
#1208
WVDNR
#1209
Stewart
Winland
1301
Stewart
Winland
1302
Please note that the Ormet, WVDNR and Stewart Winland wells reflect peak production rates (Ormet 1-9H initially tested and completed in 2011 at a restricted rate)
Stewart
Winland
1303
18
NGL Uplift in Appalachia
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
Per Wellhead Mcf (1)
Liquids
Fractionation
(C3+)
Wellhead Gas
1 Mcf
Btu = ~1,270
NGLs
$0.50 - $1.00
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
(1) All values shown are versus wellhead production in Mcf.
+ $3.50 - $4.00
$4.00 - $5.00
19
Economic Sensitivity of Marcellus “Magnum
Rich”
Base Case:
CAPEX: $6.5 million per well
EUR: 7.8 Bcfe (includes NGLs)
High Case:
CAPEX: $6.5 million per well
EUR: 11.7 Bcfe (includes NGL)
High Case
Base Case
$18
IRR: 105%
$16
IRR: 94%
$14
Single Well NPV-10 ($ MM)
IRR: 83%
$12
IRR: 72%
$10
IRR: 60%
$8
IRR: 59%
IRR: 52%
IRR: 49%
IRR: 44%
$6
$4
IRR: 38%
IRR: 37%
IRR: 29%
IRR: 28%
IRR: 23%
IRR: 16%
$2
IRR: 10%
$0
$2.00
$2.50
$3.00
$3.50
Realized Natural Gas
$4.00
Price(1),
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
$4.50
$5.00
$5.50
$/MMBtu
20
Marcellus Shale
NOBLE
MONROE
MHR - Ormet
#9 Pad
MHR/Eclipse - McIntire Pad
MHR - Ormet #15 Pad
Mark West – Mobley
WETZEL Facility
Fractionation
MHR/Eclipse - Stalder Pad
Eureka - Carbide
Compression Facility
Eclipse/MHR - Herrick Pad
MHR - Meckley-Wells Pad
MHR - Stewart-Winland Pad
TYLER
MHR / Stone JV Pads
MHR - Collins Pad
WASHINGTON
MHR - WVDNR Pad
MHR - Spencer Pad
MHR - Everest-Weese Pad
PLEASANTS
DODDRIDGE
WOOD
MHR - Stevens Pad
RITCHIE
Magnum Hunter Acreage
Eureka Hunter Pipelines
WIRT
Note: MHR owns approximately 80,300 net acres in the Marcellus Shale.
21
Utica Shale Overview
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
Total Organic Carbon
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
Isopach Map of Utica/Point Pleasant
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
22
Results Indicate Best Shale Play in US
Shale Play Comparison Chart
Ohio/West Va./Penn.
Wyoming/Colorado
Texas
N. Dakota
Point Pleasant
DJ Basin Niobrara
Eagle Ford
Bakken
Calcareous Shale
Chalk/marl
Calcareous Shale
Silty Dolomite
Shale with carbonate
stringers
Like Limestone
Like Limestone
More Dolomitic
100'-300'
3-16%
150'-300'
6-10%
75'-300'
4-15%
< 150'
8-12%
5-10%
20-35
35-90%
30+
15-45%
30-50
15-25%
10-15
~10-25%
10-40%
8-11%
5-10%
2-6%
2-6%
5%
9%
na
Brittleness varies,
250' frac length
Brittle, fracs easy, 500'
frac length
Brittle, fracs easy,
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)
Development Parameters
~3,000
0-10,000+
500-2,000
500-1,000
7,000'-11,000'
6,000'-8,000'
6,000'-8,000'
7,000'-11,000'
8.0-10.0
80-160
4.0-6.0
~160
9.0
80-160
10.0
100-200
600+
175-350
450-700
300-1,000
Utica Shale /
Parameter
Lithology
Lithology Descriptor
Storage Capacity
Formation Thickness
Porosity
Water Saturation (Sw)
OOIP per section (MMBOE)
Productive Capacity
Clay Content
Total Organic Carbon (TOC)
Ability to Fracture Stimulate
Depth
Well Cost ($MM)
Spacing (acres/well)
EUR (MBOE/well)
23
Major Players in the Utica: Who They Are
Company
Ticker
Net Acres
EV ($MM)
Acres/EV
Chesapeake Energy
Chevron
Anadarko Petroleum
Devon Energy
Range Resources
Hess Corporation
EV Energy
Gulfport Energy
Halcon Resources
Antero Resources
CHK
CVX
APC
DVN
RRC
HES
EVEP
GPOR
HK
AR
1,000,000
600,000
267,000
195,000
190,000
185,000
177,000
147,350
142,000
104,000
34,063
233,468
57,360
30,153
15,451
33,068
2,746
4,996
4,953
17,013
29
3
5
6
12
6
64
29
29
6
Magnum Hunter
MHR
118,000
2,250
52
BP
Consol Energy
ExxonMobil
PDC Energy
Carrizo Oil & Gas
Rex Energy
EQT Resources
BP
CNX
XOM
PDCE
CRZO
REXX
EQT
84,000
80,000
75,000
48,000
21,700
21,000
13,600
164,525
11,590
427,308
2,496
2,922
1,369
15,469
1
7
0
19
7
15
1
Source: Company presentations, Bloomberg, state data, Baird
24
Utica Asset Transactions
Announced
Date
Buyer(s)
Seller(s)
Feb-14
GPOR
Rhino
$185
8,200
$22,561
Jan-14
American Energy Partners, LP
Paloma Partners
$442
26,000
$17,000
Jan-14
Jan-14
American Energy Partners, LP
American Energy Partners, LP
XOM
Hess Corporation
$600
$924
30,000
74,000
$20,000
$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
Jun-12
Undisclosed
Halcon Resources
Chesapeake
Undisclosed
$600
$194
NA
31,809
NA
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)
Acreage
Implied
$ / Acre
25
Farley Pad Drilling Locations
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
Noble County
Washington County
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.
MHR - Farley Pad
Ten Planned Laterals
0
2000’
4000’
Magnum Hunter Acreage
Completed Well
26
Stalder Pad Drilling Locations
MHR - Stalder #3UH
32.5 MMCF | 97% Methane
MHR - Stalder Pad
Eighteen Planned Laterals
0
2000’
Magnum Hunter Acreage
Magnum Hunter/Eclipse JV Acreage
Marcellus Horizontal Well
Utica Horizontal Well
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 completing the three
additional horizontal Utica wells
(Stalder #6UH, Stalder #7UH and
Stalder #8UH)
All five wells will be placed on
production prior to YE 2014
27
Pad Drilling
28
Stewart-Winland Pad Drilling Locations
Tyler County, West Virginia
Magnum Hunter Acreage
MHR / JV Partner Acreage
Marcellus Horizontal Well
Utica Horizontal Test Well
MHR - Stewart-Winland Pad
Seven Planned Laterals
Stewart-Winland #1300U
Peak Test Rate: 46.5 mmcf/d
00
2,000
2,000
FEET
FEET
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
The three Marcellus wells tested at
peak rates of 17.0 MMCFE, 17.1
MMCFE and 16.8 MMCFE, respectively
Immediate take-away capacity exist on
the Eureka Hunter Pipeline system and
all wells are tied in
Final air permit approval anticipated in
early December
29
Fracing Operations
30
Ormet Pad Drilling Locations
The Ormet Pad located in Monroe
County, Ohio has twelve additional
potential 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
• The first Utica well on the 15H Pad
naturally completed in open fracture
(no stimulation)
• Nine wells planned to be drilled on
the South Unit (4 Utica and 5
Marcellus)
The three Marcellus wells are currently
producing
Recently acquired ~1,700 mineral acres
for $22.7 million and increased our NRI
on all Ormet Pads to ~95%
Magnum Hunter has immediate takeaway capacity on the Eureka Hunter
31
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
Well Name
Stewart Winland 1300U
Bigfoot 9H
Stalder #3UH
Irons 1-4H
Simms U5H
Connor 6H
Shroyer
Tippens #6H
Brown 10H
Average
County
Operator
Peak
Rate
(MMcfe/d)
Peak
Rate
(Boe/d)
Tyler, WV
Belmont, OH
Monroe, OH
Belmont, OH
Marshall, WV
Marshall, WV
Monroe, OH
Monroe, OH
Jefferson, OH
MHR
RICE
MHR
GPOR
GST
CVN
ECR
ECR
CHK
46.5
41.7
32.5
30.3
29.4
25.0
21.3
19.4
8.7
7,750
6,948
5,417
5,050
4,900
4,167
3,550
3,233
1,445
100%
100%
100%
100%
100%
100%
100%
100%
100%
5,289
6,957
5,050
6,629
4,447
6,451
7,819
4,424
4,424
22
40
20
23
25
N/A
N/A
23
N/A
28.3
4,718
100%
5,721
25.5
% Gas
Lateral
Length
Stages
33
Marcellus/Utica Wells on Production YTD
Well Name
(1)
Location
Formation
MHR Working
MHR Net
Interest
Revenue Interest
(2)
Estimated Gross Production
(3)
Boe/d
Mcfe/d
(2)
Estimated Net Production
(3)
Boe/d
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
Ormet #2-9H
Monroe County, Ohio
Marcellus
100%
95%
755
4,531
717
4,304
Producing
Ormet #3-9H
Monroe County, Ohio
Marcellus
90%
75%
755
4,531
566
3,398
Producing
WVDNR #1207
Wetzel County, West Virginia
Marcellus
100%
80%
717
4,302
574
3,442
Shut-in (5/31/14)*
WVDNR #1208
Wetzel County, West Virginia
Marcellus
100%
80%
717
4,302
574
3,442
Shut-in (5/31/14)*
WVDNR #1209
Mills Wetzel 16H
Wetzel County, West Virginia
Marcellus
100%
80%
717
4,302
574
3,442
Shut-in (5/31/14)*
Wetzel County, West Virginia
Marcellus
50%
42%
485
2,910
204
1,222
Producing
Mills Wetzel 17H
Wetzel County, West Virginia
Marcellus
50%
42%
485
2,910
204
1,222
Producing
Mills Wetzel 18H
Wetzel County, West Virginia
Marcellus
50%
42%
485
2,910
204
1,222
Producing
Mills Wetzel 19H
Wetzel County, West Virginia
Marcellus
50%
42%
485
2,910
204
1,222
Producing
Mills Wetzel 20H
Wetzel County, West Virginia
Marcellus
50%
42%
485
2,910
204
1,222
Producing
Mills Wetzel 21H
Wetzel County, West Virginia
Marcellus
50%
42%
485
2,910
204
1,222
Producing
Mills Wetzel 22H
Wetzel County, West Virginia
Marcellus
50%
42%
485
2,910
204
1,222
Producing
Mills Wetzel 23H
Wetzel County, West Virginia
Marcellus
50%
42%
485
2,910
204
1,222
Producing
Herrick C 8H
Monroe County, Ohio
Utica
2%
2%
-
-
-
-
E Weese 1107
Tyler County, West Virginia
Marcellus
100%
87%
553
3,318
482
2,893
Shut-in (7/16/14)*
E Weese 1108
Tyler County, West Virginia
Marcellus
100%
87%
429
2,574
374
2,244
Shut-in (7/16/14)*
E Weese 1109
Tyler County, West Virginia
Marcellus
100%
87%
477
2,862
416
2,495
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)*
R Weese 1003
Tyler County, West Virginia
Marcellus
100%
85%
237
1,422
202
1,214
Shut-in (9/2/14)*
R Weese 1010
Stewart Winland 1301M
Tyler County, West Virginia
Marcellus
100%
85%
301
1,806
257
1,542
Shut-in (9/2/14)*
Tyler County, West Virginia
Marcellus
100%
87%
1,937
11,622
1,685
10,111
Shut-in (9/19/14)*
Stewart Winland 1302M
Tyler County, West Virginia
Marcellus
100%
87%
1,937
11,622
1,685
10,111
Shut-in (9/19/14)*
Stewart Winland 1303M
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
Note: This information constitutes forward-looking statements and is subject to the qualifications on the last page of this investor presentation
(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
Producing
34
New Marcellus/Utica Production
MHR Working
Well Name
(1)
MHR Net
Location
Interest
Revenue Interest
Stalder #6UH
Monroe County, Ohio
47%
Stalder #7UH
Monroe County, Ohio
Stalder #8UH
Monroe County, Ohio
Ormet #8-15UH
Estimated Gross Production
(3)
(2)
(2)
Estimated Net Production
(3)
Boe/d
Mcfe/d
Boe/d
39%
3,750
22,500
47%
39%
3,750
47%
39%
3,750
Monroe County, Ohio
100%
95%
Ormet #9-15UH
Monroe County, Ohio
100%
Ormet #10-15UH
Monroe County, Ohio
100%
WVDNR #1410
Wetzel County, West Virginia
WVDNR #1411
Wetzel County, West Virginia
WVDNR #1412
Anticipated
Mcfe/d
Timing
1,474
8,845
12/31/14
22,500
1,474
8,845
12/31/14
22,500
1,474
8,845
12/31/14
3,333
19,998
3,166
18,998
12/15/14
95%
3,333
19,998
3,166
18,998
2/15/15
95%
3,333
19,998
3,166
18,998
2/15/15
100%
80%
970
5,820
776
4,656
12/31/14
100%
80%
970
5,820
776
4,656
12/31/14
Wetzel County, West Virginia
100%
80%
970
5,820
776
4,656
1/15/15
WVDNR #1414
Wetzel County, West Virginia
100%
80%
970
5,820
776
4,656
1/15/15
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
Note: This information constitutes forward-looking statements and is subject to the qualifications on the last page of this investor presentation
(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
35
Rapidly Increasing Production
(MBoe / d)(1)
Stewart Winland 1300U well in
3.6
Tyler Co, WV recently tested at
a peak rate of 46.5 MMcf/d
(~7,750 Boe/d)
40.7
3.3
3.2
3 Marcellus wells tested at an
6.0
average peak rate of 17.0
MMcf/d (2,833 Boe/d)
8.7
Additional 14 Marcellus and 5
Utica wells expected to come
online in Q4 2014 reaching
~32.5 MBoe/d exit rate
16.0
Current (2) Stewart
Stalder
Ormet
WVDNR
Weese (3) YE 2014
Production Winland Pad Wells Pad Wells Pad Wells Pad Wells
Pad Wells
2015 +
Note: This information constitutes forward-looking statements and is subject to the qualifications on the first page of this investor presentation
(1) Based on estimated IP-30 day rate (average daily amount of production during the first 30 days of production)
(2) Estimate from Q2 2014 MHR Earnings Call (August 8, 2014)
(3) E Weese and R Weese Pad Wells
36
Eureka Hunter Midstream
37
Eureka Hunter Highlights
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)
38
New Strategic Partner
In early October 2014, an affiliate of Morgan Stanley Infrastructure Inc. (“MSI”)
purchased all convertible preferred and common equity interests in Eureka
Hunter Holdings, LLC, previously owned by ArcLight Capital
MSI and the Company are currently common equity interest members in Eureka
Hunter Holdings, LLC (no preferred equity outstanding any more)
In a second closing, expected to occur in mid-December 2014, Magnum Hunter
will sell MSI an additional common equity interest in Eureka Hunter Holdings, LLC
for ~$55 million
This represents an implied equity value of Eureka Hunter Holdings, LLC of ~$1.0 billion
Magnum Hunter will have the right to defer a portion of certain of its required
future capital contributions to Eureka
Capital contribution deferral subject to a maximum of $60 million for a specified period
Magnum Hunter will have the right to make capital contributions within such specified periods
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
39
Contracted vs. Gathered Volumes
Eureka Hunter Pipeline
1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014
High Pressure Reservation Volume (MMBtu/d)
Magnum Hunter
Third-Parties
Total
87,950
35,000
122,950
92,339
47,000
139,339
75,000
88,000
163,000
75,000
88,000
163,000
83,500
88,000
171,500
96,000
88,000
184,000
111,400
85,400
196,800
High Pressure Throughput Volume (MMBtu/d)
Magnum Hunter
Third-Parties
Total
21,880
29,350
51,230
29,276
37,011
66,287
39,421
44,120
83,541
54,306
63,713
118,019
69,426
83,033
152,459
84,697
138,875
223,572
67,298
174,081
241,379
Current throughput of 275,000 - 290,000 MMBtu/d
Peak throughput rate of 325,000 MMBtu/d in September 2014
Year-End 2014 throughput target of 400,000 MMBtu/d (65% third-party)
Note: This information constitutes forward-looking statements and is subject to the qualifications on the last page of this investor presentation
40
Eureka Volume Forecast 2014-2015
1,000,000
900,000
800,000
700,000
Mmbtu/d
Third-Party #7
600,000
500,000
Third-Party #6
Third-Party #5
Third-Party #4
400,000
Third-Party #3
Third-Party #2
300,000
Third-Party #1
Triad
200,000
100,000
0
Note: This information constitutes forward-looking statements and is subject to the qualifications on the last page of this investor presentation
41
Eureka Hunter Utica Exposure
MARSHALL
MarkWest
Seneca
Clairington
Hub
Blue Racer
Berne
Blue Racer
Natrium
Ormet Wells
NOBLE
PENN
MONROE
W.V.
Farley Units
Stalder Units
WETZEL
MORGAN
Dominion
Eureka Hastings
Carbide
MarkWest
Mobley
Collins Unit
TYLER
WASHINGTON
PLEASANTS
MarkWest
Sherwood
OHIO
HARRISON
W.V.
DODDRIDGE
WOOD
RITCHIE
Magnum Hunter Acreage
Eureka Hunter Pipelines
Processing Facilities
WIRT
LEWIS
42
Eureka Hunter Utica Exposure
43
How Do We Measure Up
Gathering Capacity Marcellus / Utica Operations
Summit Midstream mcf/d,
1050
Eureka Hunter mcf/d, 1500
Crestwood Midstream mcf/d,
700
Markwest Midstream mcf/d,
1000
EQT Midstream mcf/d, 1940
Eureka Hunter mcf/d
EQT Midstream mcf/d
Markwest Midstream mcf/d
Crestwood Midstream mcf/d
Summit Midstream mcf/d
44
Appalachia Differentials
Appalachia Net Demand
Overview
12.0
Seasonal winter demand to drive better pricing in
Q4 2014 and Q1 2015
Bcf /d
10.0
8.0
Pricing improvements in 2015+ expected as yearover-year demand is positive
6.0
New Interconnects will reduce differential volatility:
•
Dominion Transmission Interconnect
(completed)
•
Columbia Interconnect (December 5)
•
Spectra Interconnect (December 15)
•
Blue Racer Interconnect (December 15)
•
REXX Interconnect (December 19)
•
Dominion-East Ohio Interconnect (1Q2015)
4.0
2.0
–
(2.0)
4Q16
3Q16
2Q16
1Q16
4Q15
3Q15
2Q15
1Q15
4Q14
3Q14
2Q14
(6.0)
1Q14
(4.0)
Net demand (supply) after interstate exports
Y-o-Y change in net demand (supply) after interstate exports
Source: Wall Street Research
45
Midstream Outlook – Proposed Interstates
Pipeline
Project
Receipt Area
Delivery Area Capacity
Rate
In Service
Domion Transmission
Lebanon West
Cadiz Plant-Harlem Springs
Lebanon
350,000
Tariff
Nov-13
ANR
2014 Lebanon Reversal
Lebanon
Glenn Karn
350,000
Tariff
Mar-14
ANR
2015 Lebanon Reversal
Lebanon
Glenn Karn
350,000
Tariff
Nov-15
TETCO
U2GC
Uniontown
Lebanon-Gas City
425,000
Tariff
Nov-15
Rockies Express
East to West
Clarington
Lebanon-REX Z3
1,800,000
$0.50
Jun-16
Texas Gas Transmission
Ohio Louisiana Access
Lebanon
TGT Z1-SL
450,000
$0.15
Jun-16
Texas Gas Transmission
Southern Indian Market Lateral
Lebanon
TGT Zone 3
150,000
$0.32
Jul-16
Columbia Gas
Leach Xpress
Clarington, other OH & WV
Leach
1,500,000
$0.55
Nov-16
Columbia Gulf
Rayne Xpress
Leach
Mainline, Rayne
1,200,000
$0.30
Nov-16
Rockies Express
Clarington West
Clarington
Lebanon and Pts West
2,400,000
$0.40-$0.45
Jan-17
Texas Gas
Northern Supply Access
Lebanon
Perryville and LA
584,000
$0.32-$0.35
Apr-17
Energy Transfer
Rover
Clarington
Defiance/Dawn
2,750,000
$0.80
Jun-17
ANR
East
Clarington
Michcon
2,000,000
$0.77
Nov-17
East
Clarington
Dawn (2nd del option)
$1.26
Nov-17
Columbia Gas
WB Xpress
Broadrun, WV
Loudoun, VA
1,200,000
$0.75
Jun-18
EQT
Mountain Valley
Mobley, EQT Sunrise
Transco Zone 5
2,000,000
$0.65-$0.75
Oct-18
46
Eureka Hunter Pipeline - Construction
Challenging Terrain
Welding Up Pipeline
Connection
Strung Pipe Before
Being Lowered
47
TransTex Hunter
TransTex Hunter, LLC (“TransTex”) founded in 2006; acquired by Eureka Hunter in
April 2012
Designs and fabricates gas treating plants out of its 10-acre fabrication yard
Assets for gas treating, processing, dehydration and separation equipment
Significant market position in treating plants 60 GPM and smaller
Approximately 45 units currently deployed and in operation with 22 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 80% of revenue from facilities TransTex provides operations; 24 - 36 months
Majority of plants remain in place beyond the term of original agreement
48
TransTex Hunter Amine Plants
49
Alpha Hunter Drilling
50
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
o
o
Spud first well (Stalder Pad) on July 1, 2013
Contract Rate of $24,000/day
Two (2) year term with Triad Hunter
• Five (5) – Schramm TXD 200
– Rig #4
o
o
Contracted with EQT through December 2015
Contract Rate of $12,500/day
– Rig #5
o
o
Contracted with EQT through December 2015
Contract Rate of $12,500/day
– Rig #6
o
o
Contracted with EQT through December 2015
Contract Rate of $12,500/day
– Rig #8
o
o
Contracted with EQT through December 2015
Contract Rate of $12,500/day
– Rig #9
o
o
Contracted with Eclipse through October 2014
Contract Rate of $12,500/day
51
Alpha Hunter Growth Continues
$35
Revenues ($ in millions)
$30
$25
$20
$15
$10
$5
$0
2010
2011
2012
2013
2014
(1)
Revenues
Note: This information constitutes forward-looking statements and is subject to the qualifications on the last page of this investor presentation
(1) Estimated annual revenue for Alpha Hunter Drilling
52
Alpha Hunter Experience
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 September 2014
53
Financial Overview
54
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 2015
Limited overhead expansion required to meet growth objectives
Closing Calgary, Denver and Houston offices in the first quarter of 2015
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
Closed on over $210 million of non-core asset divestitures in 2014
Aggressively pursuing additional non-core asset divestitures
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
55
Adjusted EBITDAX Reconciliation
Net income (loss) from continuing operations
Unrealized (gain) loss on derivatives
Net interest expense
Income taxes expense (benefit)
Impairment of oil and gas properties
Depreciation, depletion and amortization
Non-Cash stock compensation expense
Non-Cash 401K matching expense
Exploration expense
(Gain) loss on sale of assets
Unrealized (gain) loss on investments
Non-recurring transaction and other expense
Total Adjusted EBITDAX
(1)
FYE 2010
FYE 2011
FYE 2012
FYE 2013
FYE 2014
( 22.3)
3.1
3.6
0.3
8.9
6.3
0.9
( 0.1)
3.4
$4.2
( 76.7)
4.2
12.0
( 0.7)
22.9
49.1
25.1
1.5
( 0.2)
13.2
$50.4
( 119.7)
( 10.9)
51.6
( 19.3)
3.8
59.7
15.7
1.4
78.2
0.6
15.1
$76.2
( 204.1)
17.1
72.4
( 70.3)
10.0
99.2
13.6
1.9
97.3
44.7
0.8
29.8
$112.4
$185.0
Average Annual Increase of Adjusted EBITDAX of ~316%
Please note Adjusted EBITDAX includes net income from continuing operations (excludes net income from discontinued operations)
(1) Estimated full year consolidated EBITDAX
56
Non-Core Divestiture Overview
Focused on divesting non-core assets to redeploy capital into Utica / Marcellus
Over $700 million raised since beginning of 2013
Asset Sales
Value ($MM)
Completed in 2013
Eagle Ford Sale
Gain on Sale of PVA Stock
Burke County, North Dakota - Non-Operated Properties
North Dakota - Madison Waterfloods - Operated Properties
Red Star Gold
Subtotal for 2013
$401.0
$10.6
$32.5
$45.0
$1.5
$490.6
Completed in 2014 YTD
(1)
Other Eagle Ford Shale Properties - Atascosa County
Alberta Properties
Williston Hunter Canada, Inc. - Saskatchewan, Canada
Vadis Field - West Virginia
Non-Core North Dakota Non-Op
Bakken Non-Op (Baytex)
Richardson & Rock Creek Fields (WV Waterfloods)
Subtotal for 2014
In Process (Est.)
Non-Core Oil/ WV Waterfloods
Bakken Non-Op (Samson)
Bakken Operated
Kentucky Gas Properties
Subtotal for 2014
Total 2014 Non-Core Assets
(1) Includes $15.0 million of cash and $9.5 million of stock
$24.5
$8.7
$67.5
$0.5
$23.0
$84.8
$1.1
$210.1
$8.0 - $9.0
$325.0 - $425.0
$11.0 - $13.0
$65.0 - $95.0
$409.0 - $542.0
(Est.)
(Est.)
(Est.)
(Est.)
(Est.)
$619.1 - $752.1 (Est.)
57
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
-
-
-
-
4,663
259
-
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
$4.09
-
56,000
40,000
-
Weighted-Average Swap Price
Hedge Volumes
(2)(3)
Natural Gas
Hedge Volumes
(1)
(2)
(3)
(2)(3)
NYMEX strip pricing as of 9/30/2014
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
Does not include 1,570 bbls/d at $120.00 of sold calls in 2015
58
MHR Net Asset Value*
Low
($ in thousands)
Total Proved Reserves PV-10 (6/30/2014)
Assumptions
High
(1)
Valuation
Low
High
916,253
916,253
$128,100
$249,000
$472,000
$885,000
$10,000
$1,744,100
$213,500
$348,600
$613,600
$1,062,000
$20,000
$2,257,700
$515,000
$20,000
$535,000
$660,000
$40,000
$700,000
Total Asset Value
$3,195,353
$3,873,953
Less (6/30/2014):
. Series C Preferred
Series D Preferred
Series E Preferred
(5)
Senior Revolver Outstanding, net of cash
Senior Notes
Other Debt
Total
$100,000
$221,244
$95,069
$223,400
$600,000
$25,609
$1,265,322
$100,000
$221,244
$95,069
$223,400
$600,000
$25,609
$1,265,322
Net Asset Value
$1,930,031
$2,608,631
199.4
199.4
$9.68
$13.08
$/acre
Undeveloped Acreage
Williston Basin U.S.
Marcellus
Utica - Wet
Utica - Dry
Other Appalachia
Total
(2)
Certain Other Assets (6/30/2014)
(3)
Eureka Hunter Pipeline - MHR Share of Estimated Total Market Value
(4)
Alpha Hunter Drilling
Total
Shares Outstanding
(6)
Net Asset Value per Share
42,700
49,800
47,200
70,800
200,000
Low
$3,000
$5,000
$10,000
$12,500
$50
High
$5,000
$7,000
$13,000
$15,000
$100
* 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
59
A Focused Company on the Right Path
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) and over $210 MM
of non-core divestitures in 2014
Substantial decrease in G&A due to Appalachia focus
Continued focus on operational efficiency and net margin expansion
Commitment to best practices regarding financial and operational
procedures
60
Equity Research Coverage / Contact Information
Magnum Hunter Resources (NYSE: MHR)
Equity Research Analyst Coverage:
BMO Capital Markets
Canaccord Genuity
Capital One Southcoast
Citigroup Global Markets
Credit Suisse Securities
Deutsche Bank Securities
GMP Securities
Imperial Capital
KeyBanc Capital Markets
KLR Group
Website:
Maxim Group
MLV Partners
RBC Capital Markets
Robert W. Baird & Co.
Stephens
Stifel Nicolaus
SunTrust Robinson Humphrey
Topeka Capital Markets
UBS Securities
Wunderlich Securities
www.magnumhunterresources.com
Headquarters:
777 Post Oak Blvd., Suite 650
Houston, TX 77056
(832) 369-6986
Contact:
Investor Relations
(832) 203-4539
[email protected]
61
Appendix
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:
Unaudited
30-Jun-14
Future cash inflows
$
Future production costs
Future development costs
Future income tax expense
(369,976)
(95,808)
Future net cash flows
1,706,990
10% annual discount for estimated
timing of cash flows
Standardized measure of discounted future
net cash flows related to proved reserves
3,629,151
(1,456,377)
(838,595)
$
868,395
$
916,253
Reconciliation of Non-GAAP Measure
PV-10
Less: Income taxes
Undiscounted future income taxes
10% discount factor
(95,808)
47,950
Future discounted income taxes
(47,858)
Standardized measure of discounted future net cash flows
$
868,395
62
Forward-Looking Statements
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 forwardlooking 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.
63