CALLON PETROLEUM COMPANY 4Q 2015 Earnings Presentation March 2, 2016

2

IMPORTANT DISCLOSURES

This presentation contains projections and other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance as of this date. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. For a summary of events that may affect the accuracy of these projections and forward-looking statements, see “Risk Factors” in our Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission (the “SEC”).

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms “estimated ultimate recovery” (or “EUR”) that the SEC’s rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves, and accordingly are subject to substantially greater risk of being realized by the Company. EUR estimates and potential horizontal well locations have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interest may differ substantially from the Company’s estimates. There is no commitment by the Company to drill all of the potential horizontal drilling locations. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, commodity price levels, lease expirations, regulatory approval and actual drilling results, as well as geological and mechanical factors. Estimates of type/decline curves and per-well EURs may change significantly as development of the Company’s oil and gas assets provides additional data. Type/decline curves, estimated EURs, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from existing drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, recovery factors and costs prove correct. As a result, such estimates may change significantly as results from more wells are evaluated. Estimates of EURs do not constitute reserves, but constitute estimates of contingent resources that the SEC has determined are too speculative to include in SEC filings. Unless otherwise noted, Internal Rate of Return (or “IRR”) and Net Present Value (or “NPV”) estimates are before taxes and assume Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic, G&A or other corporate level costs. Investors are urged to consider closely the disclosure in our Form 10-K and other reports filed with the SEC, available on our website or by request by contacting Investor Relations: Callon Petroleum Company, 1401 Enclave Parkway, Suite 600, Houston, TX 77077. You may also email the Company at ir@callon.com. You can also obtain our Form 10-K and other reports filed with the SEC by contacting the SEC directly at 1-800-SEC-0330 or by downloading it from the SEC’s web site http://www.sec.gov.

RESERVE-RELATED DISCLOSURES

FORWARD-LOOKING STATEMENTS

3

2015 ACCOMPLISHMENTS

Production and

Resource

Record daily Permian volumes of 9,610 Boe/d (80% oil); up 70% vs. FY14 Grew 1P reserves 65% Y/Y to 54.3 MMBoe at “drill-bit” F&D of $8.98/boe Increased CMB LS type curve by >30% to >1 MMBoe Increased SMB WC “B” type curve by 46% to 871 Mboe

Operating Cost

Structure

Two-stream per unit operating costs of $7.71/Boe in FY15; down ~30% vs. $10.85/Boe in FY14

5 of 6 major producing fields on pipe (~79% of FY15 production) as of YE15; lowered average transportation cost by >$1/bbl

Operational Flexibility

Achieved 100% HBP across all acreage Pivoted to high-grade near-term activity on top-returning asset (CMB LS)

Activity Completed 33 gross horizontal wells in 2015 (1st MS; 11 in LS; 21 in WC) Producing from five horizontal zones

Balance Sheet

Raised over $175mm (net) in equity to finance acquisitions and bolster balance sheet, exiting 2015 at 2.8x Debt/Adjusted EBITDA and over $260 mm of liquidity

4

4Q15/RECENT HIGHLIGHTS

Production Record daily volumes of 10,598 Boe/d (80% oil); up 9% sequentially YTD production trending above 11,700 Boe/d in 2016

Pricing 2 of last 3 major fields placed on pipe, further improving transportation diffs Combined with tightened regional basis, yields realized oil at 93% of NYMEX

OPEX Two-stream per unit operating costs of $6.47/Boe; down 19% sequentially

Well Cost Average CWC per lateral foot of ~$680 (current AFE); down 20% from 3Q15 Leading-edge 7,500’ AFE’s of $5.1mm are down 35% vs. peak (3Q14)

Activity Placed-on-Production 9 gross (6.2 net) horizontal wells in 4Q15 (including

4.3 net in LS, 1st MS well and a SMB well fully HBP’ing acreage) Average 30-day IP/1,000’ lateral in 4Q15 of 126 Boe/d

Financial

Increased Adjusted EBITDA margin to ~73% despite a 40% decrease in average realized pricing since 4Q14

Bolstered hedge portfolio to 64% of FY16e oil ($50.25/bbl, long put/swap) and 36% of FY16e gas ($2.52/mmbtu, swap) at midpoint of guidance

Exchanged 719,000 shares of common stock for $6mm of preferred stock; lowering annual dividend expense at attractive relative valuation

Acquisitions Acquired working interests (933 net acres) in multiple core operating areas

within our existing fields at attractive valuation Actively evaluating several packages

5 0

10

20

30

40

50

60

Well Count

SMB LWC B

SMB UWC B

SMB WC A

CMB WC B

CMB LS

CMB MS

51% 47%

80%

20%

YE15 RESERVES: BREAKDOWN

2015 Proved Reserve Progression

0

10

20

30

40

50

60

YE14 Extensions Production Revisions Purchase YE15

1P

Re

se

rves (

MM

Bo

e)

Drill-Bit F&D: $8.98/Boe

(INCLUDING ALL REVISIONS)

Breakdown: YE15 vs. YE14

78%

22%

Oil Gas

YE14: 32.8 MMBoe YE15: 54.3 MMBoe

• Conservative PUD philosophy, no vertical bookings, operating and capital cost control insulated reserve base

from large downward revisions • Well outperformance and conversion of probables (i.e., Lower Spraberry) to PDP drove strong 2015 reserve growth

Total Reserve Replacement:

711% (INCLUDING ALL REVISIONS) Breakdown: PUDs by Zone

55%

45%

PDP PDNP PUD

PDP ↑ 57%

Total ↑ 65%

6

YE15 RESERVES: METRICS

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

-50%

-40%

-30%

-20%

-10%

0%

CPE Peer 1 Peer 2 Peer 3 YE

15

PV

-10

RC

F C

overa

ge

Ch

an

ge in

PV

-10

(Y

E1

5/ Y

E1

4)

Change in PV-10 (Y/Y) PV-10 as % of RCF Commitment

Strong underlying proved asset value

0%

5%

10%

15%

20%

CPE Peer 1 Peer 2 Peer 3Pri

ce R

evis

ions/T

ota

l 1P

$0

$5

$10

$15

$20

CPE Peer 1 Peer 2 Peer 3

FY

15

All-

Sourc

es F

&D

($

/Bo

e)

Peer-Leading YE15 Unadjusted Reserve Performance (a)

Smallest YE15 Price-Driven Revisions

Best YoY PV-10 Performance

Lowest F&D Cost

0%

200%

400%

600%

CPE Peer 1 Peer 2 Peer 3

Org

an

ic R

ese

rve

Re

pla

cem

ent

Highest Reserve Replacement

a) Peers include FANG, PE, and RSPP; PV-10 is based on YE15 standardized measure; F&D, reserve replacement, price revisions and standardized measure according to peer YE15 10-K filings.

7

OPERATIONS UPDATE

Carpe Diem

a) As of February 22, 2016. b) Includes one Lower WCB well placed on production in our Southern Area Garrison Draw field.

First test of Lwr LS chevron pattern, establishing 2nd productive bench in that zone

Expected on pipe ~MY16

• Successful pivot to Central Area for 2016 Lower Spraberry focus

• Transitioned to a one-rig program in 1Q16 to protect balance sheet and enhance optionality for acquisitions/acceleration

• First Middle Spraberry online in Oct 2015 • Five established Hz zones in portfolio

• 88 Gross Hz Producing Wells (a)

• 6 Gross Wells in Process (a) • 9 Gross Wells Placed on Production (“POP”) in 4Q15 (b)

4Q15 POPs: 3 LS 1 MS

Placed-on-Production two 10,000’ wells joint with RSPP

Strong 180-Day performance; 22A1 #3H with >106K Boe cumulative production (4,709’)

2016 WC A test planned in RSPP partnership

Pecan Acres

Lower Spraberry

Wolfcamp B

Middle Spraberry

4Q15 POPs: 1 LS 1 WC B

4Q15 POPs: 2 LS

CaBo

Strong first Middle Spraberry well with IP-24 of 1,078 Boe

Increased LS type curve to over 1MM BOE with continued outperformance

8

Pressure and production data corroborate efficacy of more

Lower Spraberry wells per section

-

1,000

2,000

3,000

4,000

5,000

1

10

100

1,000

0 10 20 30 40 50 60

Pu

mp

Inta

ke P

ressure

(PS

IG)

Oil

Ra

te (

Bb

l/d

)

Days on Production

Kendra Amanda Oil Rate Kendra Annie Oil Rate

Kendra Amanda PIP Kendra Annie PIP

0 10 20 30 40 50 60

Cu

mu

lative

(M

Bo

e)

Days on Production

Density: 8 per section

Density: 11 per Section

SPRABERRY DENSITY INCREASING Operated Data Reinforces View on Lower Spraberry Location Upside

Proof of concept on 11 wells/section in a chevron pattern, with potential for incremental density upside

Kendra Annie 16SH & 17SH

8 wells per section

Kendra Amanda 29SH & 30SH

11 wells per section

240’

330’ 840’

Comparable Production Performance

Slower Pressure Drawdown on Denser Development Highlights Upside

9

0

200

400

600

800

1,000

1,200

< $30 $40 - $50 $50 - $60 $60 - $70

Gro

ss L

oca

tio

ns

WTI Price Assumption ($/Bbl)

Other

Other

Jo Mill

Jo Mill

WCD/Cline

WCD/Cline

MS

MS

WCA

WCA

WCB

WCB

LS

LS

CMB LS IRRs at Flat WTI Pricing

Central

Southern

a) Assumes 20%+ IRR threshold based on achieved D&C costs to date. Returns are based on a combination of internal data and data publicly available. b) Includes Clearfork and Wolfcamp C.

CURRENT SNAPSHOT: INVENTORY

• Combination of increasing EURs and well costs driving capital efficiency • 143 gross Central Midland Lower Spraberry locations assuming 11-wells per section (potential

upside as more downspacing data is gathered over time) • Significantly broadened growth opportunities in stable $40/Bbl+ environment

Potential to shift more inventory

with further cost

reductions

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

$25/Bbl $35/Bbl $45/Bbl

IRR

at fla

t W

TI P

rice S

ce

na

rios

WTI Flat Assumption ($/Bbl)

New TC / Current CWC

Old TC / 4Q15 CWC

40% ROR at $30/Bbl

70% ROR at $40/Bbl

New TC/Current CWC < 2 yr payout at $35/Bbl

Well Location Breakevens(a)

(b)

(b)

10

CURRENT SNAPSHOT: WELL COSTS

Consistently Delivering CWC Reductions

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

Peak (2H14) 1H15 Savings 2H15 Savings YTD 2016

Savings

Achieved AFEs Near-Term

Initiatives

Leading Edge

AFEs

Pro

pp

ant p

er S

tage

(lbs)

We

ll C

osts

($

MM

)

Well Cost Lbs/Ft

•Rig Day Rate: $25k $15k •Cost/stage: $100k $50k

•Bundling small ticket items •Cycle time improvements

Current leading-edge CWC of $5.1 million for a 7,500’ lateral vs budgeted CWC of $5.4 million

11

CURRENT SNAPSHOT: OPEX Substantial Progress Made in Lowering OpEx versus Both Historicals and Peer Group

a) CPE converted to 3-stream for comparison purposes by assuming a ~12% volumetric uplift from capturing NGL volumes. b) Peer 1 LOE per unit nets out production attributed to non-cost bearing minerals interest.

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

FY14 1Q15 2Q15 3Q15 4Q15

$/B

OE

(3

-str

ea

m b

asis

)

CPE Peer 1 Peer 2 Peer 3

CPE 4Q15E $5.78

Midland Basin Peers 3-Stream LOE

(a) (b)

FY14 Avg: $8.30/Boe

1Q15 Avg: $8.60/Boe

2Q15 Avg: $7.81/Boe

3Q15 Avg: $7.16/Boe

4Q15 Avg: $6.00/Boe

Key 2016 OPEX initiatives: • Focused on achieving incremental savings across entire spectrum of OPEX components • Saltwater Disposal and Chemicals have

greatest potential for meaningful 1H16 savings

Saltwater Disposal

HES

Other

R&M

Equipment Rental

Fuel & Power

Chemicals

Labor

Non-Workover Savings Breakdown

12

OPERATIONAL DRIVERS

2,899

7,270 8,567

9,516 9,739

10,598

0%

20%

40%

60%

80%

100%

0

2,000

4,000

6,000

8,000

10,000

12,000

4Q13 4Q14 1Q15 2Q15 3Q15 4Q15

Oil M

ix B

oe

/d

Gas Oil Oil Mix

Strong Production Growth Momentum

0

1

2

3

$0.0

$20.0

$40.0

$60.0

$80.0

4Q14 1Q15 2Q15 3Q15 4Q15

Op

era

ted H

z R

ig C

ou

nt

D&

C C

ap

ital (

$M

M)

Drilling Completion Rig Count

Consistent Reduction in Cost Structure

$67.0

$52.3

$38.7 $37.8

$32.3

Realized Oil Prices ($/Bbl)

50%

60%

70%

80%

90%

100%

($5)

($3)

($1)

$1

$3

$5

1Q15 2Q15 3Q15 4Q15

Re

aliz

ed a

s %

of W

TI

Ne

tback p

er

Bb

l

Transportation Mid-Cush Diff

Realized as % of WTI

Realized oil price improved significantly in 2015 due to increased gathering system offtake and normalization of regional basis in the Permian

driven by to infrastructure build

13

4Q15: LOE & MARGINS

$19.38 $17.34

$14.85 $14.72 $12.21

$67.99

$52.83 $51.05 $49.22

$44.60

$0

$10

$20

$30

$40

$50

$60

$70

$80

4Q14 1Q15 2Q15 3Q15 4Q15

Cash Adj. G&A Production Taxes LOE Adj. Revenue

4Q14: 71% Margin

4Q15: 73% Margin

Defending EBITDA margins with cash cost

structure reductions

a) See definition of Cash Adjusted EBITDA and Adjusted Revenues, Non-GAAP measures, included in the Appendix. Adjusted Revenues include the impact of cash settled derivatives.

OPEX Savings Easing Margin Pressure

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

FY 2014A FY 2015A 4Q15A

$/B

OE

(2

-str

ea

m b

asis

)

2014 Avg: $10.85/Boe

2015 Avg: $7.71/Boe

4Q15: $6.47/Boe

Adjusted EBITDA Margins ($/Boe)(a)

OpEx ($/BOE) as of 4Q15 is down over 45% since 3Q14 peak

14

0.7

18.2

6.9

0.2

13.9

CURRENT 2016 PLAN

2015

WC B Other Lower Spraberry

Net Wells Placed on Production

2016E

Remain Nimble to Address Potential “Lower for Even Longer” World

• $75MM - $80MM Operational Capital budget

• Unique 100% HBP position

• Prioritize balance sheet to preserve flexibility through periods of volatility

• Now targeting cash flow neutrality in 2Q16 under current strip pricing

“Best in Class” Capital Efficiency(a)

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

0

5

10

15

20

25

30

CPE Peer 1 Peer 2 Peer 3

FY

16

E D

eb

t-Ad

juste

d G

row

th v

s. 4

Q1

5

Ca

pital E

ffic

ien

cy (E

VE

/d g

row

th p

er

$M

M C

AP

EX

)

2016E Growth (EVE/d) per CAPEX $

2016e Debt-Adj Growth over 4Q15

a) CPE converted to 3-stream for comparison purposes by assuming a ~12% volumetric uplift from capturing NGL volumes. Peer group includes: FANG, PE, RSPP. CPE 2016e CAPEX and production growth figures are based on updated CPE guidance as of February 1, 2016; Peer 2016e CAPEX and production based on most recently published guidance.. CPE CFFO and all peer group figures are according to FactSet estimates as of March 1, 2016..

b) EVE = Economic Value Equivalent, which uses a 16:1 ratio for oil vs. gas equivalency and a 3:1 ratio for oil vs. NGL equivalency to reflect economic impact of volumes rather than energy equivalency.

Net Wells: 25.8 Net Wells: 14.1

Peer 1: N/M for Cap. Eff.

(negative growth in

’16e)

(a)

15

2016 GUIDANCE

FY16 Guidance 11,500 - 12,000

77% - 79%

64%

$50.25

$6.75 - $7.25

$2.00 - $2.50

$3.80 - $4.20

$3.30 - $3.70

$75 - $80 a) Based on the midpoint of guidance. b) Excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans. See Non-GAAP disclosures included in the Appendix. c) Excludes stock-based compensation and corporate depreciation and amortization.

7,270

8,567 9,516 9,739

10,598 11,700

5,648

9,610

11,750

0

2,000

4,000

6,000

8,000

10,000

12,000

4Q14A 1Q15A 2Q15A 3Q15A 4Q15A 1Q16E 2014A 2015A 2016E

Pro

du

ctio

n (

BO

E / d

)

1Q16 Guidance Total Production (BOE/d) 11,600 - 11,800

% oil 77% - 79%

% oil hedged(a) 58%

Weighted average downside protection $50.25

Expenses (per BOE)

LOE, including workovers $7.00 - $7.50

Production and ad valorem taxes $2.00 - $2.25

Adjusted G&A(b) $4.35 - $4.65

Recurring cash component(c) $3.85 - $4.15

Operational Capital Expenditures

Accrual basis ($MM)

>60% “Exit to Exit” Growth in ‘15

Quarterly Guidance Annual Guidance

+20% Y/Y in ’16E

+70% Y/Y in ‘15

(a) (a)

16

FINANCIAL PROFILE 2015 Year-End Capitalization ($MM)

$40

$300

$-

$200

$400

2015 2016 2017 2018 2019 2020 2021

Debt Maturity Summary ($MM)

Key Metrics / Credit Stats(b)

Key Debt Metrics

LTM Adj EBITDA (non-GAAP) $121 MM

YE 2015 Total Reserves (MMBOE) 54.3

% Oil 80%

YE 2015 PDP Reserves (MMBOE) 28.6

% Oil 78%

Credit Statistics(a)

Total Debt / LTM Adjusted EBITDA 2.8x

Total Debt / Proved Reserves ($/BOE) $6.26

a) Reserves data as of December 31, 2015. Pro forma for 4Q15 acquisitions. b) See definition of Adjusted EBITDA, a Non-GAAP measure, included in the Appendix. Includes the impact of cash settled derivatives.

Credit Facility Term Loan

$260MM / 87%

Undrawn

$363 $300

$40

$261

$0 $200 $400 $600 $800 $1,000 $1,200

Stockholders' Equity Second Lien Facility

Revolving Credit Facility Bank Availability + Cash

17

0

3,000

6,000

9,000

12,000

15,000

$0

$50

$100

$150

$200

$250

$300

4Q15A 1H16E 2H16E 1H17E 2H17E

Da

ily P

rod

uctio

n (B

oe

/d)

Illu

str

ative C

red

it F

acili

ty B

ala

nce (

$M

M)

Daily Production Balance: NYMEX Strip (2/29/16) Balance: Consensus Pricing

OUTLOOK Illustrative One-Rig Program(a)

Current $300MM Borrowing Base

Free Cash Flow Neutral

Target in 2Q16

a) Assumes “leading-edge” completed well costs. Consensus oil pricing assumes average oil price of $41.50/Bbl for March – December 2016 and $53.00/Bbl in 2017.

• 1Q16 acquisition

• Partial 2 rig impact

• Working capital adj.

APPENDIX

19

0

50

100

150

200

250

0 30 60 90 120 150 180 210 240 270

Cu

mu

lative

Pro

du

ctio

n (

MB

oe

)

Days on Production

Old TC (912 MBoe)

New TC (1,065 MBoe)

Avg Well

LOWER SPRABERRY FOCUS Production Performance Drives Lower Spraberry Type Curve Increase

a) Production normalized to 7,500’.

Lower Spraberry Inventory

Gross Wells 2016 Plan

Area Producing In- Process Current Density Average Drilled Lateral Length

Average Working Interest

Central 11 12 143 6,875’ 68% Southern 1 -- 89 -- --

New 7,500’ TC: 1,065 MBoe

(80% Oil)

Increased CMB LS Type Curve (7,500’)(a) CMB LS Activity – Operated vs. Offset

Carpe Diem

Pecan Acres

CaBo

20

$2.52 $2.52 $2.52 $2.52

$0

$1

$1

$2

$2

$3

$3

0

2,000

4,000

6,000

8,000

10,000

12,000

1Q16 2Q16 3Q16 4Q16

$/M

MB

tu M

MB

tu/d

Hedged Volume (MMBtu/d) Swap ($/MMBtu)

$50.25 $50.25 $50.25 $50.25

$0

$10

$20

$30

$40

$50

$60

0

2,000

4,000

6,000

8,000

10,000

12,000

1Q16 2Q16 3Q16 4Q16

$/B

bl B

bl/d

Hedged Volume (Bbl/d) Swap/Long Put Price ($/Bbl)

RISK MANAGEMENT

Midland Differential ($/Bbl)(a)

Oil Hedges ($/Bbl)

Gas Hedges ($/MMBtu)

($2.50)

($2.00)

($1.50)

($1.00)

($0.50)

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

1Q16 2Q16 3Q16 4Q16

$/B

bl

Mid-Cush Futures - 12m Avg CPE Swap

(a)

a) Midland-Cushing differential futures pricing according to ARM Energy as of March 1, 2016.

4,000 Bbl/d of 2016 Oil Production Hedged at +$0.17/Bbl Differential to WTI Cushing

21

QUARTERLY CASH FLOW STATEMENT Cash flows from operating activities:Net income (loss) $ (10,197) $ (4,967) $ (111,805) $ (113,170) Adjustments to reconcile net income (loss) to cash provided by operating activities: Depreciation, depletion and amortization 18,546 18,011 16,026 17,308 Write-down of oil and natural gas properties - - 87,301 121,134 Accretion expense 209 134 142 175 Amortization of non-cash debt related items 781 780 781 781 Deferred income tax (benefit) expense (5,077) (2,116) 45,667 - Net gain (loss) on derivatives, net of settlements 7,914 13,214 (13,495) (977) Non-cash expense related to equity share-based awards 86 (754) 368 521 Change in the fair value of liability share-based awards 3,088 1,607 64 1,853 Payments to settle asset retirement obligations 258 (2,163) (1,142) (211) Changes in current assets and liabilities: Accounts receivable (2,125) (4,821) (332) 2,517 Other current assets 452 (536) 117 (51) Current liabilities (355) 5,904 906 1,546 Payments to settle vested liability share-based awards related to early retirements (3,538) - - - Payments to settle vested liability share-based awards (3,599) (326) - - Change in other long-term liabilities - 100 - (20) Change in other assets, net (319) (209) 949 (83) Net cash provided by operating activities 6,124 23,858 25,547 31,323 Cash flows from investing activities:Capital expenditures (70,780) (60,067) (47,701) (48,744) Acquisitions - - - (32,245) Proceeds from sales of mineral interest and equipment 272 54 22 29 Net cash used in investing activities (70,508) (60,013) (47,679) (80,960) Cash flows from financing activities:Borrowings on credit facility 60,000 43,000 27,000 51,000 Payments on credit facility (58,000) (5,000) (3,000) (110,000) Payment of deferred financing costs (12) 12 - - Issuance of common stock 65,546 - - 109,913 Payment of preferred stock dividends (1,974) (1,973) (1,974) (1,974) Net cash provided by financing activities 65,560 36,039 22,026 48,939 Net change in cash and cash equivalents 1,176 (116) (106) (698) Balance, beginning of period 968 2,144 2,028 1,922 Balance, end of period $ 2,144 $ 2,028 $ 1,922 $ 1,224

1Q-2015 2Q-2015 3Q-2015 4Q-2015

22

NON-GAAP RECONCILIATION(a)

a) See “Additional Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures. a) See “Additional Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures.

4Q-2014 1Q-2015 2Q-2015 3Q-2015 4Q-2015

Income (loss) available to common stockholders 16,988$ (12,171)$ (6,940)$ (113,779)$ (115,144)$ Adjustments:

Valuation allowance - - - 68,818 40,025 Net loss (gain) on derivatives, net of settlements (14,249) 5,144 8,589 (8,771) (635) Write-down of oil and natural gas properties - - - 56,746 78,737 Rig termination fee - 2,367 - - (368) Change in the fair value of share-based awards (1,713) 1,676 1,045 37 1,197 Early retirement expenses - 3,034 - - - Withdrawn proxy contest expenses 65 72 150 65 - Loss on early redemption of debt 1,985 - - - -

Adjusted Income 3,076$ 122$ 2,844$ 3,116$ 3,812$

Net income (loss) 18,962$ (10,197)$ (4,967)$ (111,805)$ (113,170)$ Adjustments:

Write-down of oil and natural gas properties - - - 87,301 121,134 Net loss (gain) on derivatives, net of settlements (21,921) 7,914 13,214 (13,494) (977) Change in the fair value of share-based awards (1,941) 3,058 2,086 655 2,354 Early retirement expenses - 4,668 - - - Rig termination fee - 3,641 - - (566) Loss on early redemption of debt 3,054 - - - - Withdrawn proxy contest expenses 100 111 230 100 - Acquisition expense 668 3 - (3) 27 Income tax expense (benefit) 10,504 (5,077) (2,116) 45,667 - Interest expense 4,765 4,858 5,106 5,603 5,544 Depreciation, depletion and amortization 18,521 18,546 18,011 16,026 17,308 Accretion expense 223 209 134 142 175

Adjusted EBITDA 32,935$ 27,734$ 31,698$ 30,192$ 31,829$

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NON-GAAP RECONCILIATION(a)

a) See “Additional Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures.

4Q-2014 1Q-2015 2Q-2015 3Q-2015 4Q-2015

Total G&A expense 1,402$ 12,102$ 5,763$ 4,302$ 6,180$ Adjustments:

Change in the fair value of liability share-based awards 2,635 (2,578) (1,607) (57) (1,842) Early retirement expenses - (4,668) - - - Threatened proxy contest (100) (111) (230) (100) -

Adjusted G&A - Total 3,937 4,745 3,926 4,145 4,338 Restricted stock share-based compensation (689) (479) (479) (598) (512) Corporate depreciation & amortization (342) (129) (115) (133) (117)

Adjusted G&A - Cash 2,906$ 4,137$ 3,332$ 3,414$ 3,709$

Oil Revenue 34,409$ 27,909$ 36,093$ 30,582$ 30,582$ Natural gas revenue 4,009 2,482 3,149 3,734 2,981

Total revenue 38,418 30,391 39,242 34,316 33,563 Impact of cash-settled derivatives 7,068 10,343 4,965 9,789 9,918

Adjusted Total Revenue 45,486$ 40,734$ 44,207$ 44,105$ 43,481$

Total Production (MBOE) 669 771 866 896 975 Adjusted Total Revenue per BOE 67.99$ 52.83$ 51.05$ 49.22$ 44.60$

24

F&D CALCULATION(a)

a) See “Additional Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures.

Calculation Parameters

Production (MBOE) (A) $ 3,508

Proved reserves (MBOE) Revisions to previous estimates (including price-related) (B) (820) Purchases, net of sale, of reserves in place (C) 3,377 Extensions and discoveries (D) 22,397 Total additions, net of sale (E) 24,954

Capital costs incurred (in thousands) Property acquisition costs $ 32,246 Operational capital (a) (F) 193,660 Total capital costs incurred (G) $ 225,906

Drill-bit F&D per BOE (F) / (B + D) $ 8.98 All-sources F&D per BOE (G) / (E ) $ 9.05

Organic reserve replacement ratio (B + D) / (A) 615%

All-sources reserve replacement ratio (E) / (A) 711%

2015 Metrics

25

ADDITIONAL DISCLOSURE 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. 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. 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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