CALLON PETROLEUM COMPANY 4Q 2015 Earnings Presentation March 2, - - PowerPoint PPT Presentation

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

• ther 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 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% 51% 47% 47% 80% 80% 20% 20%

YE15 RESERVES: BREAKDOWN

2015 Proved Reserve Progression

10 20 30 40 50 60

YE14 Extensions Production Revisions Purchase YE15

1P Reserves rves (MMBoe) Drill-Bit F&D: $8.9 .98/Boe (INCLUDING ALL REVISIONS)

Breakdown: YE15 vs. YE14

78% 78% 22% 22%

Oil Gas

YE14: 32.8 MMBoe YE15: 54.3 MMBoe

• Conservative PUD philosophy, no vertical bookings,
• perating 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% 55% 45% 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 YE15 PV-10 RCF Covera erage ge Change e in PV-10 (YE15/ / YE14) 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 3 Price e Revisions ns/Tot /Total al 1P $0 $5 $10 $15 $20 CPE Peer 1 Peer 2 Peer 3 FY15 All-Sou

• urces

es F&D ($/Boe)

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 Organ anic Reserve Replacem ement nt

Highest Reserve Replacement

7

OPERATIONS UPDATE

Carpe Diem

• 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

• ptionality 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
• ver 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 10 20 30 40 50 60

Pump Intake e Pressure ure (PSIG)

Oil Rate e (Bbl bl/d) d) Days ys on Produ

• duct

ction

• n

Kendra Amanda Oil Rate Kendra Annie Oil Rate Kendra Amanda PIP Kendra Annie PIP 10 20 30 40 50 60

Cumul ulat ative e (MBoe

• e)

Days ys on Produ

• duct

ction

• n

Density: 8 per section De Density ty: : 11 per S Secti tion

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 w wells per secti tion

Kendra Amanda 29SH & 30SH

11 w wells per secti tion

240’ 330’ 840’ Comparable Production Performance Slower Pressure Drawdown on Denser Development Highlights Upside

9

200 400 600 800 1,000 1,200 < $30 $40 - $50 $50 - $60 $60 - $70

Gross Locati tions

WTI Price e Assump mpti tion n ($/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

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 flat WTI Price e Scenarios

• s

WTI Flat Assump mpti tion n ($/Bbl) Ne New T w TC / C / Curr Curren ent CW t 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)

10

CURRENT SNAPSHOT: WELL COSTS

Consistently Delivering CWC Reductions

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

Proppant t per Stage (lbs) Well Costs ts ($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

$0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 FY14 1Q15 2Q15 3Q15 4Q15

$/BOE OE (3-strea stream basis) sis)

CPE Peer 1 Peer 2 Peer 3

CPE 4Q15E $5.78

Midland Basin Peers 3-Stream LOE

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% 2,000 4,000 6,000 8,000 10,000 12,000 4Q13 4Q14 1Q15 2Q15 3Q15 4Q15

Oil Mix Boe/d /d Gas Oil Oil Mix

Strong Production Growth Momentum

1 2 3 $0.0 $20.0 $40.0 $60.0 $80.0 4Q14 1Q15 2Q15 3Q15 4Q15

Operate rated Hz Rig Count D&C Capita ital ($MM) 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 Realized ed as % of WTI Netbac ack per Bbl 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 4 $14.85 $14.85 $14.72 2 $12.21 1 $67.99 9 $52.83 3 $51.05 5 $49.22 2 $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

OPEX Savings Easing Margin Pressure

$0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 FY 2014A FY 2015A 4Q15A $/BOE OE (2-strea stream basis) sis)

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 7 18.2 .2 6.9

0.2 0.2 13.9 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% 5 10 15 20 25 30 CPE Peer 1 Peer 2 Peer 3 FY16E Debt-Adjust justed Growth wth vs. 4Q15 Capita ital Effici iciency cy (EVE/d /d growth wth per r $MM CAPEX)

2016E Growth (EVE/d) per CAPEX $ 2016e Debt-Adj Growth over 4Q15

Net Wells: 25.8 Net Wells: 14.1 Peer 1: N/M for Cap. Eff. (negative growth in ’16e)

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

7,270 270 8,567 567 9,516 516 9,739 739 10,598 598 11,700 700 5,648 648 9,610 610 11,750 750 2,000 4,000 6,000 8,000 10,000 12,000

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

Productio ction (BOE / 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

16

FINANCIAL PROFILE

2015 Year-End Capitalization ($MM)

$40 $300

$- $200 $400

20 2015 15 20 2016 16 20 2017 17 20 2018 18 20 2019 19 20 2020 20 20 2021 21

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

Credit Facility ty 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 3,000 6,000 9,000 12,000 15,000 $0 $50 $100 $150 $200 $250 $300 4Q15A 1H16E 2H16E 1H17E 2H17E Daily ly Productio ction (Boe/d /d) Illustrat strative ive Credit it Facil ility ity Balan lance ce ($MM) 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

• 1Q16 acquisition
• Partial 2 rig impact
• Working capital adj.

APPENDIX

19

50 100 150 200 250 30 60 90 120 150 180 210 240 270 Cumulati tive Producti tion (MBoe) Days on Producti tion Old TC (912 MBoe) New T New TC (1 C (1,0 ,065 M MBo Boe) Avg Well

LOWER SPRABERRY FOCUS

Production Performance Drives Lower Spraberry Type Curve Increase

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 $2.52 $2.52 $2.52 $2.52

$0 $1 $1 $2 $2 $3 $3 2,000 4,000 6,000 8,000 10,000 12,000 1Q16 2Q16 3Q16 4Q16

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

$50.2 .25 $50.2 .25 $50. 0.25 25 $50. 0.25 25 $0 $10 $20 $30 $40 $50 $60 2,000 4,000 6,000 8,000 10,000 12,000 1Q16 2Q16 3Q16 4Q16

$/Bbl Bbl/d Hedged Volume (Bbl/d) Swap/Long Put Price ($/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 $/Bbl Mid-Cush Futures - 12m Avg CPE Swap

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

21

QUARTERLY CASH FLOW STATEMENT

• 87,301

• Net gain (loss) on derivatives, net of settlements

• Payments to settle vested liability share-based awards

• Change in other long-term liabilities
• 100
• (20)

• (32,245)

• Issuance of common stock

• 109,913

22

NON-GAAP RECONCILIATION(a)

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 $

23

NON-GAAP RECONCILIATION(a)

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)

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.