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2. energy
3. oil

CALLON PETROLEUM COMPANY
Investor Presentation
May 2015
CALLON OVERVIEW
Overview
Midland Basin Presence
ANDREWS
Central
Acreage
MARTIN
HOWARD
Market Capitalization(a)(d)
$545 MM
Enterprise Value(a)(d)
$961 MM
Proved Reserves(b)
32.8 MMBOE
% Oil
78%
% PDP
55%
Daily Average Production(c)
2014A
5,648 BOE/d (82% oil)
2015E
9,050 BOE/d (80% oil)
Net “Effective” Acreage
Southern
Acreage
100,136
Pro Forma Financial Position(d)
Borrowing base / utilization
Earliest debt maturity
$250MM / 15%
2019
CPE Acreage
Concentrated Asset Base in Core
Areas of Permian Basin
a)
b)
c)
d)
As of May 15, 2015, based on common stock price of $8.24 per share.
As of December 31, 2014.
Based on guidance midpoints.
As March 31 ,2015.
2
KEY INVESTMENT CONSIDERATIONS
 Consolidated footprint in the “core” of the Midland Basin
 High-quality acreage portfolio with well economics that
continue to add shareholder value in the current environment
 Improving EURs over time
 Significant well cost reductions achieved to date
 High degree of operational flexibility
 Long-lived drilling inventory for sustained production growth
with a near-term focus on “de-risked” zones
 Solid financial flexibility, long-term capital position and no nearterm debt maturities
 Accomplished Permian operator with track record of successful
acquisitions
3
OPERATIONS
STRONG FOUNDATION
Key Highlights
Proved Reserves
Horizontal Acreage Potential
Well Locations
Oil
30.0
20.0
15.0
5.0
Producing /
In Process
Year-end
PUDs(a)
Inventory
+
PUDs
Clearfork
-
-
66
6,230
3,868
Middle Spraberry
-
-
101
10,007
6,589
Jo Mill
-
-
159
20,086
14,219
Lower Spraberry
5
2
191
22,006
16,139
Wolfcamp A
3
5
157
22,290
16,386
30.0
Upper Wolfcamp B
31
30
145
22,290
16,386
25.0
Lower Wolfcamp B
21
10
38
10,363
7,877
Wolfcamp C
-
-
58
10,363
7,877
Wolfcamp D / Cline
-
-
131
15,125
10,794
60
47
1,046
138,760
100,136
22,757
18,062
Totals
Total Surface Acreage
Net
7.1
25.0
10.0
“Effective” Acreage
3.0
11.9
2013
PD
Our 53 PUD locations as of December 31, 2014 have been adjusted for 6 wells drilled/In Process.
2014
PUD
35.0
53 Hz /
1 Vt
20.0
15.0
55%
10.0
5.0
50%
0.0
2013
a)
25.7
-
MMBOE
Gross
Natural Gas/NGLs
35.0
MMBOE
 Over 100,000 net effective acres
 Oil-rich reserves and production
 Efficient horizontal pad development
2014
5
ASSET BASE GROWTH
Permian Production (BOE/d)
Hz PUD & Well Inventory
10,000
1,000
9,000
60%
8,000
7,000
800
6,000
600
5,000
8,567
4,000
400
7,270
3,000
2,000
9,050
5,280
4,355
5,641
5,648
23
60
38
86
28
-
47
200
-
0
Acquisition of Casselman and Bohannon (“CaBo”) fields acquisition closed on October 7, 2014.
102
PUD
(47)
131
58
159
Prospective
Zones
(515)
101
66
188
108
1,000
a)
Lower Wolfcamp B
Upper Wolfcamp B
Wolfcamp A
Lower Spraberry
Clearfork
Middle Spraberry
Jo Mill
Wolfcamp C
Wolfcamp D / Cline
PUDs
152
86
117
55
27
Total Locations
Total Locations
5/20/14
5/1/15
Nearly 1,050 Hz Well Locations
Current
Producing
Zones
(484)
6
MULTI-ZONE POTENTIAL
Potentialrig
Gross Horizontal Locations & Producing Wells
Replace
Central Midland
PDP(a)
PUD(c)
Carpe
Diem
Pecan
Acres
Kayleigh
CaBo
East
Bloxom
Opal
Garrison
Draw
Taylor
Draw
Well
Inventory
(incl. PUD)
Clearfork
-
-
--
--
--
66
--
--
--
--
66
Middle Spraberry
-
-
21
14
--
66
--
--
--
--
101
Jo Mill
-
-
21
14
--
66
28
--
18
12
159
Lower Spraberry
5
2
23
15
7
75
27
14
18
12
191
Wolfcamp A
3
5
18
12
6
57
24
12
17
11
157
Upr Wolfcamp B
31
30
15
13
7
60
11
13
15
11
145
Lwr Wolfcamp B
21
10
--
--
--
--
24
--
10
4
38
Wolfcamp C
-
-
--
--
--
--
28
--
18
12
58
Wolfcamp D
-
-
21
14
--
66
--
--
18
12
131
Target Zone
Current
Producing
Zones
Southern Midland
Dean
Strawn/Atoka
Evaluating
All Zones
60
47
119
82
20
456
142
39
114
74
1046
Current Producing
Zones(a)
60
47
56
40
20
192
86
39
60
38
531
Horizontal Inventory in Drilling Years(b)
Drilling Rigs
2
3
4
All Zones
40 yrs
27 yrs
20 yrs
Current Producing
Zones(a)
19 yrs
12 yrs
9 yrs
• Average Lateral over 6,500’
• Currently 6 – 8 Wells per Section
a)
b)
c)
Includes wells in process of drilling or completion.
Assumes 13 wells completed per drilling rig per year.
Our 53 PUD locations as of December 31, 2014 have been adjusted for 6 wells drilled/In Process.
7
TYPE CURVE SUMMARY ($55/BBL)
Central Midland Ranges(a)
Southern Midland Ranges(a)
Avg:
912 MBOE
Avg:
639 MBOE
Avg:
595 MBOE
IRR(b)
33%
55%
IRR(b)
31%
35%
NPV10 / I(b)
59%
100%
NPV10 / I(b)
59%
66%
Payout(b)
2.7 yrs
1.8 yrs
 Extended Lower Spraberry production
history encouraging
 Wolfcamp B development started in early
2014 / Lower Spraberry in late 2014
 EUR ranges converging with increasing
development activity
a)
b)
541 MBOE
Payout(b)
2.7 yrs
2.4 yrs
 Well-established Upper Wolfcamp B EURs
 Lower Wolfcamp B demonstrating strong
37%
results
 Lower D&C costs vs Central Midland wells
Normalized to 7,500’ drilled lateral (7,000’ completed lateral). Includes fields with currently planned activity for the remainder of 2015 and 2016.
Based on actual drilled lateral lengths (not normalized), “Target” AFE levels, and $55/Bbl flat realized oil prices and $3.25/Mmbtu flat NYMEX natural gas prices.
8
PEER GROUP ANALYSIS
Midland Basin Horizontal EURs – Oil(a)
Central
Southern
Callon(b)
Peer
1
Peer
2
Peer
3
Peer
4
37%

Adjusts two/three-stream data and facilitates ESP vs gas lift comparisons

High-quality Southern and Central Basin positions in Callon portfolio
a)
b)
Peer group includes Diamondback Energy, Laredo Petroleum, Parsley Energy and RSP Permian. Peer data based on investor presentations available as of April 15, 2015. Peer 1
EURs assume 75% oil content.
Datapoints represent averages of field type curves by region.
9
OPERATIONS UPDATE
Carpe Diem/Pecan
Acres/CaBo(a)
Garrison Draw
REAGAN



1st stacked horizontals (WC B
and LS) at Pecan Acres yielding
strong performance
Completed three-well pad at
Cabo (WC B); Plans for a fourwell pad at Cabo (LS)

Two 10,000’ wells placed on
production (Lower WC B)
Wells continue to flow under
natural pressure pending gas
lift
“Core”
East Bloxom
Taylor Draw
UPTON
REAGAN
Tier I



Three wells placed on
production (2 Upper WC B; 1
LS)
Includes 1st Lower Spraberry
(6,632’) placed on ESP in April
Tier II

Lower Spraberry
Wolfcamp A
a)

CaBo field area includes the Casselman and Bohannon fields.
Two wells placed on
production (Lower WC B)
Increased proppant (Lower
WCB) test in process
1st Wolfcamp A well flowing
back
Upper Wolfcamp B
Lower Wolfcamp B
10
COST REDUCTIONS
KeyAchieved
Achieved Reductions
Key
Reductions
7,500’ Component Breakdown ($MM)
$8.0
 Drilling rig: 40%
$6.0
Completion
$4.0
Drilling
 Drilling mud: 28%
 Tubulars: 15%(a)
 Directional drilling: 40%
$2.0
 Pressure pumping: 35%
$0.0
Baseline
Achieved
Target
Total Well Cost Reductions ($MM)
$12.0
$10.0
Baseline
$9.7
$7.2
$8.0
$6.0
$6.8
$7.5
Achieved
$6.0
$5.1
Target
$6.0
$4.8
$4.0
$4.1
$2.0
$-
10,000'
7,500'
5,000'
Cost Reductions
a)
Effective June 1, 2015.
11
EVOLVING MILESTONES
Central Acreage(a)
Well Name
(Field)
Formation
(County)
Highlight
IP30 per
1000’
Kendra Annie
15SH
Lower Spraberry
(Midland)
Strong Lower Spraberry Results: The well had a peak 24-HR IP of 746 BOE/d (89% oil),
150
Pecan Acres
22 A 3H & 4 SH
(Pecan Acres)
Wolfcamp B
Lower Spraberry
(Midland)
First Stacked Horizontal Wells: The Company has fracture stimulated and placed onto
N/A
Kendra-Annie
1481H
(Carpe Diem)
Wolfcamp B
(Midland)
First Central Midland Horizontal: The well targeting the Wolfcamp B had a peak 24-HR
121
Cassleman
8-1H
(CaBo)
Wolfcamp B
(Midland)
Strong Cumulative Production: The 4,656’ completed lateral well, the second Wolfcamp
169
and a peak 30-Day average rate of 599 BOE/d (89% oil) from a 4,966’ completed lateral.
Cumulatively, the well has produced over 85,000 BOE during its first six months of production.
production its first two 5,000’ stacked laterals targeting the Wolfcamp B and Lower Spraberry
zones. Early flowback results are encouraging.
IP of 1,125 BOE/d (92% oil) and a peak 30-Day average rate of 902 BOE/d (88% oil) from a
7,470’ completed lateral. Cumulative production in the first year exceeded 110 MBOE.
B well brought online in the CaBo area, has produced more than 60,000 BOE during its first five
months online. The well had a peak 24-HR IP of 988 BOE/d (83% oil) and a peak 30-Day
average IP of 788 BOE/d (83% oil).
Median Proppant/ft
+41%
+4%
Southern Acreage(a)
2013
Well Name
(Field)
Formation
(County)
Neal 321H
(East Bloxom)
Wolfcamp B
(Upton)
First Horizontal Well: Callon demonstrated its commitment to efficient resource
Neal
652H & 653H
(East Bloxom)
Wolfcamp B
(Upton)
Gas Lift (“GL”) Analysis: Both wells were placed online within days of each other, and
652H: 106
653H: 72
Neal
653H & 342H
(East Bloxom)
Wolfcamp B
(Upton)
Initial Higher Proppant Levels Test: Callon increased its proppant pumped by ~20%,
653H: 72
342H: 106
Neal 658LH
(East Bloxom)
Wolfcamp B
(Upton)
First Lower Wolfcamp B well in East Bloxom: The 7,099’ completed lateral well
123
University 2 15AH
(Garrison Draw)
Wolfcamp A
(Reagan)
First Wolfcamp A well in Garrison Draw: The 7,472’ completed lateral well reflects
87
University 27-34
1LH, 2LH, 3LH
(Garrison Draw)
Wolfcamp B
Lower
(Reagan)
Higher Proppant Levels Yield Promising Results: After promising results in our East
a)
b)
development by becoming an early adopter of horizontal drilling. The well has produced over
150 MBOE within its first two years.
while the ESP (652H; 24-HR Peak IP of 1395 BOE/d) initially outperformed, cumulative
production from the GL (653H; peak 24-HR IP of 969 BOE/d) well surpassed the ESP at ~150
days and, to date, has produced over 25% higher volumes.
which yielded notably higher well pressures and enhanced production rates.
reflects strong early results with a peak 24-HR IP of 1,027 (80% oil) BOE/d, a peak 30-Day IP
of 872 BOE/d (77% oil) BOE/d and 180-Day cumulative production of 100 MBOE.
strong early results with a peak 24-HR IP of 1,449 BOE/d (93% oil) BOE/d, a peak 30-Day IP of
752 (78% oil) BOE/d and 180-Day cumulative production of 74 MBOE.
Bloxom field, we increased proppant levels in recent Garrison Draw wells. Early indications
show significant increases in wellbore pressure and natural flow tubing pressure.
All well results are on a 2-stream basis.
East Bloxom field example.
IP30 per
1000’
2H14
Early Time Impact(b)
88
Flowing 4
mos. under
natural
pressure
Cumulative Production
Highlight
1H14
Higher Proppant
Baseline
12
ONGOING DE-RISKING
Central Midland Basin (~7,300 Net Surface Acres)
RSP Cross Bar Ranch 3025MS
9172’ IP30 1190 BOEPD
IP30 / 1000’ 130 BOEPD
RSP Cross Bar Ranch 1717WA
7107’ IP30 928 BOEPD
IP30 / 1000’ 131 BOEPD
RSP Cross Bar Ranch 2017MS
7074’ IP30 974 BOEPD
IP30 / 1000’ 138
RSP Cross Bar Ranch 2017WA
7074’ IP30 887 BOEPD
IP30 / 1000’ 125 BOEPD
Oxy Curtis Ranch South 2816AH
6068’ IP30 680 BOEPD
IP30 / 1000’ 112 BOEPD
RSP Sarah Ann 3814H
5041’ IP30 591 BOEPD
IP30 / 1000’ 117 BOEPD
RSP Spanish Trail 4817MS
7352’ IP30 931 BOEPD
IP30 / 1000’ 127 BOEPD
RSP Fendley 404MS
4768’ IP30 353 BOEPD
IP30 / 1000’ 74 BOEPD
Endeavor Industrial 6040H
9354’ IP30 626 BOEPD
IP30 / 1000’ 67 BOEPD
RSP Fendley 405MS
9826’ IP30 900 BOEPD
IP30 / 1000’ 92 BOEPD
RSP Spanish Trail 218MS
9947’ IP30 1082 BOEPD
IP30 / 1000’ 109 BOEPD
CPE Producing
(~14,600 Net Effective Acres)
Wolfcamp B
Lower Spraberry
Source: Public data and Investor presentations.
Other De-risked
(~20,620 Net Effective Acres)
Middle Spraberry
Wolfcamp A
Wolfcamp D / Cline
13
FINANCIAL
FINANCIAL POSITION
Adjusted EBITDA Margins ($/BOE)(a)
Capitalization ($MM)
$1,200
$1,000
Cash G&A
Stockholders'
$215
Equity
$800
$37
Second Lien
$70
Facility
$600
$300
$60
Revolving
$50
Credit Facility
$40
Bank
$30
Availability +
$20
$400
$200
$488
Cash
$0
March 31, 2015
$82.68
LOE
Revenue
$80.95
$75.52
$80
$68.01
$52.83
1Q15 Margin:
$35.49/BOE
$25.67
$21.98
$23.68
$19.38
$17.34
$10
$0
1Q14
Credit Metrics
a)
b)
c)
$90
Production Taxes
Total Debt / Total Capitalization
41%
Net Debt / Adj. EBITDA(b)
2.8x
2Q14
3Q14
4Q14
1Q15
Estimated Apr-Dec 2015 average margin in
excess of $40/BOE based on NYMEX
pricing(c) and midpoint of guidance metrics
See definition of Adjusted EBITDA, a Non-GAAP measure, included in the Appendix. Includes the impact of cash settled derivatives.
Adjusted EBITDA annualized based on 4Q14 and 1Q15 results which include the impacts of the Central Midland Basin acquisition completed on October 8, 2014.
As of May 11, 2015 and assumes 66% of our volumes have been hedged at a weighted-average price of $67.56 for April-Dec 2015.
15
OPERATIONAL PLAN
2015 CapEx Guidance(a)
Estimated Breakdown(a)
(Guidance midpoints; $MM)
Capitalized G&A
Operational
Capex
$70
D&C
$50
Facilities
$150
Capitalized
G&A
D&C
$60
$MM
$12
$13
Facilities
$40
$30
$20
$10
$0
1Q15A
2Q15E
3Q15E
2015E
4Q15E
2016E
Updated operational capex of $160MM - $165MM
•
27.0 vs 23.7 net wells following reconfiguration of drilling plans
• Increased Lower Spraberry capital allocations
• Allowance for “non-consent” capital
• Based on “Achieved” D&C reductions
9.1
1.0
6.2
16.9
15.6
D&C capital heavily weighted to 1H15
•
a)
• Three rig program ended in March 2015
• Impact of cost reductions increasing through 2Q15
Added OBO Lower Spraberry well, replacing OBO well in 3Q15
Capital expenditures presented on a GAAP (accrual) basis excluding capitalized interest expense.
Lower Spraberry
WC B
Wells to be Drilled
WC A
16
2015 GUIDANCE
Production (BOE/d)
9,000
4Q14 (7,270 BOE/d) to 4Q15 (~9,500 BOE/d)
production growth of ~30%
8,800
8,600
9,050
8,950
8,400
Two-rig program provides potential growth of
10+% from 4Q15 to 4Q16
8,567
8,200
8,000
1Q15A
2Q15E
2015E
FY2015 Guidance
2Q15 Guidance
Previous
Updated
8,000 - 8,400
8,800 - 9,300
8,800 - 9,100
79% - 81%
79% - 81%
79% - 81%
63%
66%
61%
$70.89
$69.04
$70.79
LOE, including workovers
$8.75 - $9.50
$8.50 - $9.50
$9.00 - $9.70
Production taxes, including ad valorem
$3.00 - $3.50
$2.75 - $3.25
$2.75 - $3.25
Adjusted G&A(b)
$5.75 - $6.25
$5.50 - $5.75
$5.50 - $5.75
$4.89 - $5.31
$4.00 - $4.75
$4.00 - $4.75
Total Production (BOE/d)
% oil
% oil hedged(a)
Weighted average oil swap price
Expenses (per BOE)
Recurring cash component(c)
a)
b)
c)
Based on the midpoint of guidance.
Excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans. See Non-GAAP disclosures included in the Appendix.
Excludes stock-based compensation and corporate depreciation and amortization.
17
APPENDIX
DEVELOPMENT PHILOSOPHY
Artificial Lift System Evaluation(a)
140,000
ESP (Neal 652H)
Gas Lift (Neal 653H)
4.0
Peer Average: 3.2
3.5
120,000
3.0
MBOE/d of Oil & Water
Cumulative Production
(BOE)
Maximum / Average Flow Rates(b)
100,000
2.5
80,000
60%
Greater
2.0
60,000
1.5
40,000
1.0
20,000
0.5
-
0.0
Callon
Benefits of Gas Lift
•
Less downtime due to mechanical failures &
offsetting fracture stimulations
•
Reduces LOE by eliminating sub pump
replacements
•
Enhances ultimate recovery estimates
a)
b)
Adjusted to exclude downtime.
Peers include PXD and XTO near Callon’s CaBo field area and PE near Callon’s Garrison Draw field.
Peer 1
Peer 2
Peer 3
Flowback Philosophy
•
Reduces likelihood of wellbore damage due to
pulling sand from the fracture stimulation
•
Belief that long-term well performance is
enhanced by preserving the fracture stimulation
•
Reduces facility costs by avoiding overbuild to
handle short-term high fluid flow rates during
early production days
19
2-STREAM VS 3-STREAM EXAMPLE
1000
2-Stream 30-Day IP
800 BOE/d
BOE/d
800
3-Stream 30-Day IP
904 BOE/d
13%
20%
600
400
17%
80%
200
70%
0
2-Stream
NGL
1.4 BTU Gas:
3-Stream
Gas
2-Stream
Conversion
960 Mcf/day
25% SHRinkage Factor
150 Bbl of NGL per MMcf
Oil:
640 Bbl/day
Oil
3-Stream
Dry Gas:
720 Mcf/day
NGL:
158 Bbl/day
Oil:
640 Bbl/day
20
HEDGE PORTFOLIO DETAIL
For the Three Months Ended
OIL CONTRACTS
June 30,
September 30,
December 31,
March 31,
June 30,
September 30,
December 31,
2015
2015
2015
2016
2016
2016
2016
Swap contracts:
Total volume (MBbls)
Weighted average price per Bbl
410
$
520
70.79 $
67.22
442
$
91
64.93 $
63.50
91
$
63.50
92
$
63.50
92
$
63.50
Swap Contracts (Differentials):
Total volume (MBbls)
Weighted average price per Bbl
400
$
382
327
(2.40) $
(2.40) $
—
—
(2.38)
Collar contracts combined with short
puts (three-way collar):
Volume (MBbls)
—
91
91
92
92
Price per Bbl
Ceiling (short call)
$
—
$
—
$
—
$
70
$
70
$
70
$
70
Floor (long put)
$
—
$
—
$
—
$
60
$
60
$
60
$
60
Short put
$
—
$
—
$
—
$
45
$
45
$
45
$
45
For the Three Months Ended
NATURAL GAS CONTRACTS
June 30,
September 30,
December 31,
2015
2015
2015
Collar contracts combined with short
puts (three-way collar):
Volume (BBtu)
228
207
161
Weighted average price per MMBtu
Ceiling (short call)
$
4.32
$
4.32
$
4.32
Floor (long put)
$
3.85
$
3.85
$
3.85
Short put
$
3.25
$
3.50
$
3.25
$
4.04
$
3.98
$
3.98
$
5.00
$
5.00
$
5.00
Swap contracts:
Total volume (BBtu)
Weighted average price per MMBtu
414
248
227
Short Call contracts:
Short call volume (BBtu)
Short call price per MMBtu
109
110
110
21
NON-GAAP RECONCILIATION(a)
Income (loss) available to common stockholders
1Q-2014
2Q-2014
3Q-2014
4Q-2014
1Q-2015
$
$ 2,767
$ 10,227
$ 16,988
$ (12,171)
(111)
Adjustments:
Net loss (gain) on derivatives, net of settlements
1,065
1,975
(6,764)
(14,249)
5,144
-
-
-
-
2,367
Change in the fair value of share-based awards
1,726
2,982
(1,713)
1,676
Early retirement expenses
1,601
-
-
3,034
Rig termination fee
Withdrawn proxy contest expenses
Gain on sale of other property and equipment
Loss (gain) on early redemption of debt
775
85
(702)
-
(974)
65
65
72
-
-
-
-
(2,083)
-
1,985
-
Adjusted income
$ 4,354
$ 5,726
$ 2,554
$ 3,076
$
Net income (loss)
$ 1,863
$ 4,740
$ 12,201
$ 18,962
$ (10,197)
Net loss (gain) on derivatives, net of settlements
1,639
3,039
(10,406)
(21,921)
7,914
Change in the fair value of share-based awards
3,101
3,555
(1,031)
(1,941)
2,059
Early retirement expenses
2,463
-
-
-
4,668
Rig termination fee
-
-
-
-
3,641
Loss (gain) on early redemption of debt
-
(3,205)
-
3,054
-
122
Adjustments:
Withdrawn proxy contest expenses
Acquisition expense
Income tax expense (benefit)
Interest expense
Depreciation, depletion and amortization
Accretion expense
Adjusted EBITDA
a)
1,193
130
100
100
111
-
-
-
668
3
1,341
4,128
7,161
10,504
(5,077)
977
1,825
2,205
4,765
4,858
10,598
12,378
16,517
18,521
18,546
228
173
202
223
209
$ 23,403
$ 26,763
$ 26,949
$ 32,935
$ 26,735
See “Additional Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures.
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NON-GAAP RECONCILIATION(a)
Total G&A expense
1Q-2014
2Q-2014
3Q-2014
4Q-2014
1Q-2015
$ 10,807
$ 9,639
$ 3,261
$ 1,402
$ 12,102
Adjustments:
Change in the fair value of liability share-based awards
(2,655)
(4,587)
1,499
2,635
(2,578)
Early retirement expenses
(2,463)
-
-
-
(4,668)
Threatened proxy contest
(1,193)
Adjusted G&A - Total
Restricted stock share-based compensation
Corporate depreciation & amortization
Adjusted G&A - Cash
a)
(130)
4,496
4,922
(100)
4,660
(100)
(111)
3,937
4,745
(519)
(790)
(735)
(689)
(479)
(60)
(202)
(154)
(342)
(129)
$ 3,917
$ 3,930
See “Additional Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures.
$ 3,771
$ 2,906
$
4,137
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RESERVE INFORMATION
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ADDITIONAL DISCLOSURES
Supplemental Non-GAAP Financial Measures
We believe that the non-GAAP measure of Adjusted income available to common shareholders (“Adjusted Income”) and Adjusted Income per diluted share are
useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot
be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed
in the reconciliation provided below. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted income and Adjusted
income per diluted share below were computed in accordance with GAAP.
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry
analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, depreciation, depletion
and amortization, exploration expense, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and
premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation, asset
retirement obligation accretion expense, other income, gains and losses from the sale of assets and other non-cash operating items. Adjusted EBITDA is not a
measure of net income as determined by United States generally accepted accounting principles (‘‘GAAP’’).
Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our
operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net
income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon
accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be
considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance
or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such
as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our
presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items..
Adjusted general and administrative expense (“Adjusted G&A”) is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses
and non-cash valuation adjustments related to incentive compensation plans. We believe that the non-GAAP measure of Adjusted G&A is useful to investors
because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table
below details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.
Certain Reserve Information
Cautionary Note to U.S. Investors: The Securities and Exchange Commission (“SEC”) prohibits oil and gas companies, in their filings with the SEC, from
disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. This presentation discloses estimates of quantities of oil
and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “resource base,” “estimated ultimate recovery,” “EUR” or other
descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible
reserves, and which the SEC’s guidelines strictly prohibit the Company from including in filings with the SEC. These estimates are by their nature more
speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by the Company. U.S. investors are
urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 1401 Enclave Pkwy, Ste
600, Houston, TX 77077, Attention: Investor Relations, and the Company’s website at www.callon.com. These filings also can be obtained from the SEC by calling
1-800-SEC-0330.
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