3Q16 Earnings Presentation November 2, 2016 Cautionary Statements - - PowerPoint PPT Presentation

November 2, 2016

3Q16 Earnings Presentation

Cautionary Statements and Important Disclosures

Forward-Looking Statements

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

• f 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

• f 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”). SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES This presentation includes non-GAAP measures, such as Adjusted EBITDA, Adjusted Income, Adjusted Income per diluted share and Adjusted G&A. 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

• perating 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

• ur 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. 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 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

• f 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. For a reconciliation of non-GAAP measures to their most directly comparable GAAP measure, please see schedules included in the Appendix.

Cautionary Statements and Important Disclosures

Reserve-Related Disclosures

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. 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.

4

Callon Petroleum

1) As of October 27, 2016, based on common stock price of $13.92 per share. 2) As of September 30, 2016, as adjusted for recent acquisitions and related debt and equity financings. See footnote 2 on the “Financial Profile” slide for reconciling items. 3) Net Debt adjusted for acquisitions and related financing transactions. LTM EBITDA, a non-GAAP financial measure, is calculated in conformance with our credit facility covenant and excludes the pro forma contribution from the Plymouth transaction. 4) Excludes 1,966 3Q16 average BOE/d from the Howard County acreage closed on October 20, 2016.

• Significant core footprint with over 40,000 net acres in

Midland Basin, including over 20,000 net acres in our WildHorse area

• Three core operating areas with established horizontal

production from five zones with stacked flow units within thicker zones

• Accomplished Permian operator with track record of

successful acquisitions

• Increasing pace – Added 2nd rig in 3Q16; 3rd rig planned

in Jan17; preparing for 4th rig in 2H17

• Solid credit metrics and ~$500 million of liquidity

Key Statistics

Shares Outstanding (1) 161 MM Market Capitalization (1) $2.2 B Enterprise Value (2) $2.6 B Net Debt (2) $0.3 B Net Debt/LTM EBITDA (3) 1.9x Daily Average Production 3Q16 (4) 16,598 BOE/d 2016E (exit) 20,000+ BOE/d

Monarch WildHorse Ranger

5

Recent Highlights

• Record daily volumes of 16,598 BOE/d (76% oil) in 3Q16, up 23% sequentially (q/q)
• 3Q16 two-stream LOE of $6.52/BOE; Total cash operating costs before interest of

$11.18/BOE

• Completed three DUCs acquired earlier in 2016, including a WCA well (Silver City A1H) in

Howard County and a WCA and UWCB in Reagan County

• Placed on production our first 13-well Lower Spraberry spacing test in Midland County
• Increased 2016 annual production guidance with midpoint of 15,400 BOE/d

Operational

• Refinanced term loan with Unsecured Senior Notes, reducing cost of capital and

establishing a public market benchmark for future financing opportunities

• Exited 3Q16 with pro forma Net Debt/LTM Adjusted EBITDA(1) of 1.9x and $485MM of

liquidity

• Cash margins continue to benefit from cost structure improvements and offtake
• ptimization
• Raised ~$1.1 billion of net debt and equity proceeds in 2016 to finance acquisitions and

bolster balance sheet

Financial

1) Net Debt adjusted for acquisitions and related financing transactions. LTM EBITDA, a non-GAAP financial measure, is calculated in conformance with our credit facility covenant and excludes the pro forma contribution from the Plymouth transaction.

Operational Update

6

Activity Summary Key Initiatives / Highlights Capital Costs Trending Lower (2) Sequential Production Growth Profile (1)

• Placed 7 gross (5.2 net) wells on production in 3Q16 with an

average completed lateral length of 7,900’

• Second rig returned to service in August and drilled our two

longest laterals to-date (LLS pair; ~11,500’) at Carpe Diem

• Expanded activity beyond Monarch area including placing

wells on production (acquired DUCs from April transactions) in WildHorse (WCA) and Ranger (WCA and UWCB)

• Drilled a WCA and LS pair directly offsetting Silver City well in

WildHorse (Sidewinder field); awaiting completion

• Currently drilling a stacked WCA and LS pair in WildHorse

(Maverick field; south of Sidewinder)

9,739 10,598 12,440 13,451 16,598 20,000

0% 20% 40% 60% 80% 100% 5,000 10,000 15,000 20,000 3Q15 4Q15 1Q16 2Q16 3Q16 2016E Exit

Oil Mix BOE/d

1) 2016 Exit represents estimate for the average production in December 2016. 2) Excludes wells with mechanical issues.

• Integrating acquired asset bases and positioning for efficient

future development across the WildHorse focus area

• Continuing to move production onto pipe and renegotiate

lower tariff charges

• Evaluating extended performance from enhanced completion

techniques and tighter stage spacing

• Operational planning for a third horizontal rig in January 2017

and anticipated fourth rig in 2H17

$- $200 $400 $600 $800 $1,000 1 2 3 4 5 6 7 8 9 10 11 1 2 3 4 5 6 1 2 3 4 5 6 7

Drilling & Completion Cost / Foot 2016 Wells Drilled Listed in the Order Drilled by Lateral Length

~10,000' ~9,000’ ~5,000'

7

Operational Update: Monarch Area (1)

• One gross (0.8 net) ~5,000 LS well PoP
• PoP in early 4Q16 our first 13-well spacing test

with a 3-well pad

• Drilled a second 13-well spacing with a 3-well

pad expected to be PoP by year-end

• In early 4Q16, PoP 2-well pad (~9,400’)

including the first WCA well in the Monarch focus area and a LS well (0.4 net wells)

• Drilling a 3-well pad targeting one Upper LS

and two WCB (1.4 net wells)

• Three gross (2.3 net) ~9,600 LS wells PoP
• Drilled longest laterals to-date (2-well pad;

~11,500’) at Carpe Diem; currently completing

• Proven, repeatable returns on capital to navigate oil price volatility
• Continue to evaluate upside potential of tighter well spacing, most recently placing-on-production

(“PoP”) our 13-well spacing test

• PoP the first Wolfcamp A well in Monarch (Pecan Acres), increasing to five producing flow units

Middle Spraberry U/ L Lower Spraberry Wolfcamp B Wolfcamp A

CaBo Pecan Acres Carpe Diem

1) Maps reflect wells drilled (or drilling), completed (or completing) or placed on production in 3Q16 or to date in 4Q16.

Field Map Legend

8

Operational Update: WildHorse and Ranger Areas

• Advancing efforts to establish infrastructure and improve capital efficiency for planned acceleration to

two rigs of activity in 2017

• WildHorse drilling program commenced, initially focused on Wolfcamp A and Lower Spraberry
• Well density tests and delineation of other zones being planned

Sidewinder

Note: PoP = Placed on production.

Field Map Legend

Lower Spraberry Upper / Lower Wolfcamp B Wolfcamp A

• PoP the 7,300’ WCA Silver City well

(1.0 net) with 110-day cum. prod. of 192 Mboe (89% Oil)

• Drilled two-well pad (WCA/LS)

directly offsetting Silver City

• Expect pipe offtake in early 1Q17

reducing transport cost by 50%

• Expect to place a Hz rig on the

eastern-most side of this field in early 2017 and progress activity westward

• Expect to transition production to

pipeline 2H17 reducing transportation costs by ~50%

• PoP a 7,100’ WCA (0.6 net) and a

7,100’ UWCB (0.6 net)

• Evaluating the results of our most

intense frac design applied to- date, including tighter stage spacing and ~2,000 lbs./ft. sand

• Drilling a two-well, stacked pad

(7,500’) targeting the WCA and LS

• Expect to transition production to

pipeline in early 1Q17 reducing transportation costs by ~50%

Maverick Fairway Lonesome Draw WildHorse Ranger

DUCs Completed Silver City well 2-Well pad awaiting completion

Silver City Result Supports Enhanced Completion Value Thesis

9

Sidewinder Field Strongest Early Time Performance in Callon Portfolio to Date

Wolfcamp A IP24 (BOE/d) IP30 (BOE/d) Cumulative 90-Day Prod (MBOE) Drilled Lateral Stages Proppant (lbs./ft) SILVER CITY UNIT A 01H 2,459 2,148 164 7,363’ 37 1,959 CPE WC A Type Curve 992 829 91 7,500’ 30 ~1,350

• Silver City (98% WI) produced 192 Mboe in the first 110 days, which is >80% above the 700 Mboe type curve
• Silver City is CPE’s first operated completion (WCA) in Howard County and one of the first completions in the NW

portion of the county to employ a new generation design (~2,000 lbs./ft. and ~200’/stage)

• Drilled a two-well pad directly offsetting Silver City targeting the WCA and LS that is waiting on completion
• 20,000

40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 50 100 150 200 250

BOE Days

MASTERS UNIT A 01H OPEN UNIT A 02H RYDER UNIT A 02H SILVER CITY UNIT A 01H

LS WCA WCB

Silver City well 2-Well pad awaiting completion

10

1,300 lbs./ft. – 1,500 lbs./ft. 250’ Stage Length 25% - 30%100 mesh; 70%-75% 40/70 (Wolfcamp) or 30/50 (Spraberry) 4 Clusters/Stage 1,500 lbs./ft. – 2,000 lbs./ft. 250’ Stage Length 15%-25% 100 mesh; 75%-85% 40/70 (Wolfcamp) or 30/50 (Spraberry) 5 Clusters/Stage Deep Penetrating Charges 1,900 lbs./ft. – 2,000 lbs./ft. 200’ Stage Length 8% 100 mesh; 40/70 (Wolfcamp) or 30/50 (Spraberry); 7% 30/50 Resin 5 Clusters/Stage Deep Penetrating Charges

Completion Optimization Progression and Near Wellbore Intensity Enhancement

Frac Volume and Conductivity Improvement Measures:

• Increasing proppant loading
• Reducing 100 mesh % when operationally feasible while increasing

40/70 and 30/50 volumes

• Deep penetrating charges for enhanced near wellbore connectivity
• Increasing clusters/stage to generate more fractures
• Reducing stage length and tightening cluster spacing to achieve greater

surface area and stimulate larger rock volume

0% 20% 40% 60% 80% 100% 120% Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Completion Enhancements Implemented along with Tight Cost Control:

Normalized Hydraulic Fracturing Cost Progression (% Change Q4 2014 to date)

Silver City A1H (WA)

• To date, lower Wolfcamp B (“LWCB”) has been the best

performing zone in the Ranger area, carrying an 830 MBOE type curve based on enhanced completion designs

• Callon inherited 2 gross DUCs (1 WCA & 1 Upper WCB)

with the acquisition of the Lonesome Draw area

• Early time results during clean-up are encouraging and

Callon plans to accumulate further data by testing similar concepts on 4 gross (~1.8 net) LWCB wells planned for 2017

Enhanced Completion Testing: Ranger

11

Further Testing Planned for 2017 Upper Wolfcamp B Performance Comparison Wolfcamp A Performance Comparison

Cumulative Oil Production (Bbl) Days on Production Turner Pilot Older Gen Avg

Promising Early Time Data

Cumulative Oil Production (Bbl) Days on Production Turner Pilot Older Gen Avg 2017: Two 2-well LWCB pads planned to be spud at Lonesome Draw in 2Q17 Currently evaluating plans to further test next generation completion designs Despite producing ~20% lower oil in first 30-days online due to longer clean up period, cumulative production through less than 2 months is already 8% above average Less impacted by early time de-watering, Upper WC B next gen pilot outperformed predecessor average by ~27% in first 30 days

Progressing Lower Spraberry Well Density

12

Overview CaBo: Focus Area of 13-Well Density Pilot

• First 13 wells-per-section (“WPS”) density test placed on

production in early October in the Casselman 40 section

• Completed drilling a second 13 WPS, three-well pad in the

Casselman 10 section targeting the same zones; WOC

• Completion designed to enhance near wellbore stimulation

– Proppant loading: ~2,000 lbs./ft. – Stage spacing: Tightened to ~200’; Testing 150’

• Early flowback results are encouraging

13-Well Density Design

Casselman 40 Casselman 10

12-Well Spacing Extended Performance

240’ 330’ 770’

U / L LS MS WCA WCB

100 1,000 10,000 50 100 150 200 250 300

Avg Pump Intake Pressure Days

• 50,000

100,000 150,000 200,000 30 60 90 120 150 180 210 240 270 300 330

Average Cumulative BOE Days 12-Well Spacing 8-Well Spacing Type Curve

Upper Lower Spraberry Lower Lower Spraberry

Note: WOC = Waiting on completion.

• Optimal development density of the Lower Spraberry is

driven by the wellbore configuration that most effectively recovers the resource in place without

• vercapitalizing the zone

– A single zone with tighter spacing; or – Stacked, staggered multi-zone development

• Operated pilot results indicate that dual zone

development of the Lower Spraberry does not degrade performance and that offsetting Upper Lower Spraberry (“ULS”) and Lower Lower Spraberry (“LLS”) wells produce similarly in early time

Proof of Concept on Two Lower Spraberry Landing Zones

13

Kendra Amanda 2-well Pad (1 ULS; 1 LLS) Kendra Kristen 3-well Pad (2 ULS; 1 LLS) Results Reinforce Dual Zone Development

Cumulative Oil Production (Bbl) Days on Production ULS LLS(1) LLS(2)

CaBo 3-well Pad (1 ULS; 2 LLS)

Cumulative Oil Production (Bbl) Days on Production ULS(1) ULS(2) LLS Cumulative Oil Production (Bbl) Days on Production ULS LLS

Ranger L WC B Ranger U WC B Ranger WC A Ranger LS WildHorse WC B WildHorse WC A WildHorse LS Monarch WC B Monarch WC A Monarch LS Monarch MS Payout Period

Premier Asset Quality

1) Flat WTI prices yielding single well IRRs of 25+%. Assumes current capital costs and lease operating expenses. 2) Payouts based on strip NYMEX pricing as of October 26, 2016. Assumes current capital costs and lease operating expenses.

14

Delineated Inventory Economics (Gross) (1)

Delineated Inventory Payout (at Current Costs) (2)

101 Locations ~6 rig years 134 Locations ~8 rig years 86 Locations ~5 rig years 85 Locations ~5 rig years 60 Locations ~4 rig years 125 Locations ~7 rig years 129 Locations ~8 rig years 96 Locations ~6 rig years 75 Locations ~4 rig years 64 Locations ~4 rig years 50 Locations ~3 rig years

200 400 600 800 1,000 1,200 < $35 $35 - $45 $45 - $55 Ranger LWC B Ranger UWC B Ranger WC A Ranger LSBY WildHorse WC B WildHorse WC A WildHorse LSBY Monarch WC B Monarch WC A Monarch MSBY Monarch LSBY

866 locations yield estimated 25+% IRR’s at $45/Bbl (flat) WTI pricing and below Current Focus Zones Payout in < 2 years at Strip Prices

Focus of 3-year Program Payout Period

2017: Accelerating Activity Levels and Bringing Value Forward

15

Infrastructure Build Facilitating Efficient Growth Ramping Rig Count

1 2 3 4 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Monarch Ranger WildHorse

• Callon’s strategic initiatives for 2016 in the A&D market

(inventory expansion) and capital market (balance sheet de-leveraging) focused on laying the groundwork for accelerating activity levels once returns warranted

• Many of Callon’s operational initiatives in 2016 (and

into 1H17) are focused on optimizing the uptime and capital efficiency of its planned 2017 ramp

– Cost reduction – Shortened cycle times – Infrastructure build-out – Firm transport agreements

2016 Work Set the Stage for 2017 Ramp 2016E Avg Rig Count

Monarch WildHorse Ranger

2017E Avg Rig Count

Monarch WildHorse Ranger

1 – 2 Rigs 3 – 4 Rigs

Revenues

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Daily Production (BOE/d) Revenue ($MM) Realized Natural Gas Prices ($/Mcf) Realized Oil Prices ($/Bbl)

$30.6 $40.6 $49.1 $3.7 $4.6 $6.8 $9.8 $4.0 $4.1

$- $10 $20 $30 $40 $50 $60 $70 3Q15 2Q16 3Q16 Oil Natural Gas Settled Hedges

$49.2 $44.1 $60.0 7,489 10,418 12,614 2,250 3,033 3,984

• 5,000

10,000 15,000 20,000 3Q15 2Q16 3Q16 Oil Natural Gas

9,739 13,451 16,598 $3.01 $2.77 $3.04 $0.32 $0.19 $(0.07) 109% NYMEX 142% NYMEX 108% NYMEX

$(0.50) $0.50 $1.50 $2.50 $3.50 $4.50 3Q15 2Q16 3Q16 Unhedged Hedge Impact NYMEX

$44.39 $42.78 $42.58 $13.64 $3.91 $3.69

$- $20.00 $40.00 $60.00 3Q15 2Q16 3Q16 Unhedged Hedge Impact NYMEX

91% NYMEX 92% NYMEX 94% NYMEX

Expenses

1) Adjusted G&A is a Non-GAAP financial measure and is defined and reconciled within the Appendix. Adjusted G&A excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization. The cash component further excludes Non-Cash items related to the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization.

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Total Cash Operating Costs ($/BOE) Adjusted G&A ($/BOE) (1)

$3.81 $2.92 $2.38 $0.82 $0.63 $0.58

$- $2.00 $4.00 $6.00 3Q15 2Q16 3Q16 Cash Non-Cash

Two-Stream LOE ($/BOE)

• Remain focused on optimizing recently acquired

properties

• LOE per BOE down 19% year-over-year vs. 3Q15
• Cash G&A per BOE down 38% year-over-year vs. 3Q15

and 18% sequentially vs. 2Q16

• Total cash operating costs of ~$11/BOE, bolstering cash

margins during periods of commodity price volatility

• Facilities investment and water handling improvements

expected to drive meaningful savings in 2017

Highlights

$8.03 $5.97 $6.09 $0.43

$- $2.00 $4.00 $6.00 $8.00 $10.00 3Q15 2Q16 3Q16 Legacy Acquired

$8.03 $5.97 $6.52 $2.88 $2.01 $2.28 $3.81 $2.92 $2.38

$- $4.00 $8.00 $12.00 $16.00 3Q15 2Q16 3Q16 LOE Production Taxes Cash G&A

Financial Profile

1) 3Q Adjusted Capitalization adjusted for the proceeds from the issuance of $400MM Senior Unsecured Notes ($391 MM, net), repayment of the $300 MM 2nd Lien Term Loan including the call premium ($3 MM) and accrued interest ($7 MM), loss related to the early repayment of the 2nd Lien Term Loan ($14 MM) closing payment on the Element acquisition ($307 MM). 2) Debt Maturity Summary is presented inclusive of the debt-related adjustments noted in footnote 1 above and include the redemption of the 2nd Lien Term Loan due 2021 and issuance of Senior Unsecured Notes due 2024.

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Solid Financial Position for Growth Initiatives Debt Maturity Summary ($MM) (2)

$- $- $- $- $400

$- $75 $150 $225 $300 $375 $450 2016 2017 2018 2019 2020 2021 2022 2023 2024

Recent issuance of senior unsecured notes with a coupon of 6 1/8%

3Q16 Adjusted Capitalization ($MM) (1)

Senior Unsecured Notes No Near-Term Maturities

• Pro forma leverage < 2x EBITDA with
• ver $100 million of cash balances
• Enhanced capital markets access with

Senior Notes issuance

• Opportunistically adding to 2017 hedge

position with planned acceleration of activity

$385MM Undrawn 100% Available

$1,087 $1,101 $400 $300 $485 $711 $- $500 $1,000 $1,500 $2,000 $2,500

9/30/2016 As Adjusted 9/30/2016 As Reported

Stockholders' Equity Senior Notes Term Loan Revolving Credit Facility Bank Availability + Cash

Original FY16 Guidance

(March 2016)

Updated FY16 Guidance

(November 2016)

Total production (BOE/d) 11,500 - 12,000 15,250 - 15,550 % oil 77% - 79% 75% - 77% % oil hedged (1) 64% (FY16) 43% (4Q16) Expenses (per BOE) LOE, including workovers $6.75 - $7.25 $6.00 - $6.50 Production and ad valorem taxes (% of unhedged revenues) 7% 7% Adjusted G&A (2) $3.80 - $4.20 $3.15 - $3.40 Recurring cash component (2) $3.30 - $3.70 $2.50 - $2.75 Operational Capital Expenditures (3) $75MM - $80MM $140MM

Raising 2016 Guidance

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Highlights

• Increased production guidance range to 31% above
• riginal midpoint
• Operating CapEx maintained at $140 MM
• 23.8 net operated completed Hz wells planned in 2016

– Full-year 2016 average lateral length of ~7,000’ – Full-year 2016 average working interest of ~74%

• Improvements in 2016 productivity provide strong

momentum into 2017

YTD 2016 Actuals and Full-Year Guidance Two-Stream Basis (1)

$7.00 $6.25 $2.25 $2.21 $3.50 $2.63 $0 $2 $4 $6 $8 $10 $12 $14 Original FY2016 Guidance Updated FY2016 Guidance $ / BOE

LOE Production Taxes Cash G&A

1) Based on the midpoint of guidance. Production and ad valorem taxes for 4Q16 are based on $45/Bbl and $2.75/MMBtu NYMEX benchmark pricing. 2) Adjusted G&A is a Non-GAAP financial measure and is defined and reconciled within the Appendix. Adjusted G&A excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization. The cash component further excludes non-cash items related to the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization. 3) Excludes capitalized expenses, leasehold costs and seismic.

$140

$- $100 $200 $300 $400 2016E 2017E Range 2018E Range

($MM)

Longer-Term Development Planning

1) Assumes $2.75/MMBtu NYMEX natural gas (flat). 2) Excludes capitalized expenses, leasehold costs and seismic. 3) Estimated net completions and average drilled lateral lengths are based on the present development schedule and anticipated rig count.

20

Highlights Daily Production

15,400

• 5,000

10,000 15,000 20,000 25,000 30,000 35,000 2016E Midpoint 2017E Range 2018E Range

BOE/d

Operational Capital(2)(3)

• Planning for four rig development program by 2H17,

with incremental focus on WildHorse and Monarch areas

• Designed to maintain Total Debt/EBITDA below 2.5x

under downside price scenarios

• Four-rig program starting October 2017 would deliver

free cash flow by mid-2018 at $50/Bbl

• Assumes 10% increase in completed well costs in 2017

and a 15% increase in 2018 for completion design evolution and potential upward pressure on service costs

Estimated Debt / Adjusted EBITDA(1)

$140MM

23.8 net completions ~7,000 avg. lateral

15,250 – 15,550 (75% - 77% oil)

40%+ Target Compound Annual Growth Rate

29,000 – 31,000 (78% - 80% oil) 22,000 – 24,000 (75% - 77% oil)

1.9x 1.4x 1.5x 0.9x

0.0x 0.5x 1.0x 1.5x 2.0x 2017E 2018E

Net Debt / EBITDA

$47.50 (2017) / $50.00 (2018) October 31, 2016 Strip $250 – $270 MM

36.7 net completions ~7,410’ avg. lateral

$320 – $340 MM

54.0 net completions ~7,395’ avg. lateral

Appendix

• Callon takes a pragmatic, empirically-driven

approach to updating our type curves  Uses repeated, operated results to refine recovery projections

• In the instance of the late 2014 acquisition of
• ur CaBo asset in Midland County, Callon’s
• riginal acquisition LS curve (“T+0”) was

derived from risked, offsetting public data

• After having multiple wells online for several

months that were all meaningfully

• utperforming T+0 in early time, IP rate was

adjusted

• After having nearly a dozen operated wells
• nline and roughly a year of production

history, EUR was raised materially

• After performing multiple operated spacing

tests, well density assumptions increased

• Further optimization efforts continue to

refine curve shape and spacing views

Callon Type Curve Progression Philosophy

22 12 24 36 Cumulative Production (MBOE) Months on Production

CaBo Lower Spraberry (“LS”) Case Study

Acquisition (T + 0)

• Operated PDP HZs: 0
• Max Prod History: n/a
• EUR (7,500’): 737 MBOE
• Density: 7 wells/section
• Recoverable OIP: 5.2 MMBOE

T + 6 months

• Operated PDP HZs: 3
• Max Prod History: 4 months
• EUR (7,500’): 812 MBOE
• Density: 7 wells/section
• Recoverable OIP: 5.7 MMBOE

T + 12 months

• Operated PDP HZs: 11
• Max Prod History: 10 months
• EUR (7,500’): 912 MBOE
• Density: 8 wells/section
• Recoverable OIP: 7.3 MMBOE

T + 24 months

• Operated PDP HZs: 31
• Max Prod History: 22 months
• EUR (7,500’): 1+ MMBOE
• Density: 11+ wells/section
• Recoverable OIP: 11+ MMBOE

T + 24 T + 12 T + 6 T + 0 Type Curve increased by 25+% over time, but just as importantly, Recoverable OIP/section projection more than doubled since acquisition

23

Midland Basin Growth

1) Pro forma for the Howard County acquisitions of 5,952 net acres that closed on October 20, 2016. 2) Net production includes 1,966 BOE/d for production from the acquisition described in footnote 1.

September 30, 2015

• Over the past 12 months, despite a

challenging oil price environment, Callon has achieved the following milestones (pro forma for the Plymouth Acquisition):

– Grown quarterly production by ~91% versus same period in 2015 – Increased net acreage position and “delineated” location inventory by 120% and 103%, respectively, in the core of the Midland Basin – Bolstered balance sheet for planned acceleration of development

September 30, 2016 (1)

Net Production (2) 9,739 BOE/d 18,564 BOE/d

(~85% Organic)

Net Acres (1) 18,225 40,151 “Delineated” Hz Locations (Gross) 531 1,076 Gross Hz Producing Wells 74 123

+91% +120% +103% +66%

Quarterly Cash Flow Statement

24

Cash flows from operating activities: Net income (loss) $ (111,805) $ (113,170) $ (41,109) $ (70,097) $ 21,139 Adjustments to reconcile net loss to cash provided by operating activities: Depreciation, depletion and amortization 16,026 17,308 16,129 16,698 17,733 Write-down of oil and natural gas properties 87,301 121,134 34,776 61,012

• Accretion expense

142 175 180 395 187 Amortization of non-cash debt related items 781 781 781 780 810 Deferred income tax (benefit) expense 45,667

• (62)

Net (gain) loss on derivatives, net of settlements (13,494) (977) 8,648 19,501 (1,044) Non-cash expense related to equity share-based awards 368 521 392 (1,253) 608 Change in the fair value of liability share-based awards 64 1,853 709 1,965 3,371 Payments to settle asset retirement obligations (1,142) (211) (161) (158) (576) Changes in current assets and liabilities: Accounts receivable (332) 2,517 5,941 (10,777) (11,608) Other current assets 116 (51) 580 (885) 54 Current liabilities 906 1,546 (717) 4,830 15,702 Acquisition deposit

• (32,700)

Change in other long-term liabilities

• (20)

11 75

• Change in other assets, net

949 (83) (233) (217) (1,221) Payments to settle vested liability share-based awards

• (9,807)

(493)

• Net cash provided by operating activities

25,547 31,323 16,120 21,376 12,393 Cash flows from investing activities: Capital expenditures (46,649) (48,744) (50,775) (24,505) (47,418) Acquisitions (1,052) (32,245) (10,183) (273,841) (18,033) Proceeds from sales of mineral interest and equipment 22 29

• 23,631

(708) Net cash used in investing activities (47,679) (80,960) (60,958) (274,715) (66,159) Cash flows from financing activities: Borrowings on credit facility 27,000 51,000 45,000 98,000 74,000 Payments on credit facility (3,000) (110,000) (85,000) (58,000) (114,000) Payment of deferred financing costs

• (640)

Issuance of common stock

• 109,913

94,949 205,858 421,908 Payment of preferred stock dividends (1,974) (1,974) (1,824) (1,823) (1,824) Net cash provided by financing activities 22,026 48,939 53,125 244,035 379,444 Net change in cash and cash equivalents (106) (698) 8,287 (9,304) 325,678 Balance, beginning of period 2,028 1,922 1,224 9,511 207 Balance, end of period $ 1,922 $ 1,224 $ 9,511 $ 207 $ 325,885 4Q-2015 3Q-2016 1Q-2016 2Q-2016 3Q-2015

Non-GAAP Reconciliation (1)

25

1) See “Important Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures. 2) Pro forma Adjusted EBITDA Acquisitions is used only for the purposes of calculating compliance with covenants, such as Debt/EBITDA calculations. (2)

3Q-2015 4Q-2015 1Q-2016 2Q-2016 3Q-2016 Adjusted Income Reconciliation Income (loss) available to common stockholders (113,779) $ (115,144) $ (42,933) $ (71,920) $ 19,315 $ Adjustments: Change in valuation allowance 68,818 40,025 14,288 24,409 (7,907) Net loss (gain) on derivatives, net of settlements (8,771) (635) 5,621 12,676 (679) Write-down of oil and natural gas properties 56,746 78,737 22,604 39,658

• Rig termination fee
• (368)
• Change in the fair value of share-based awards

37 1,197 461 1,277 2,192 Withdrawn proxy contest expenses 65

• 144

2

• Adjusted Income

3,116 $ 3,812 $ 185 $ 6,102 $ 12,921 $ Adjusted EBITDA Reconciliation Net income (loss) (111,805) $ (113,170) $ (41,109) $ (70,097) $ 21,139 $ Adjustments: Write-down of oil and natural gas properties 87,301 121,134 34,776 61,012

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

(13,494) (977) 8,648 19,501 (1,044) Change in the fair value of share-based awards 655 2,354 1,225 2,628 4,150 Rig termination fee

• (566)
• Withdrawn proxy contest expenses

100

• 221

3

• Acquisition expense

(3) 27 48 1,906 456 Income tax (benefit) expense 45,667

• (62)

Interest expense 5,603 5,544 5,491 4,180 831 Depreciation, depletion and amortization 16,026 17,308 16,129 16,698 17,733 Accretion expense 142 175 180 395 187 Adjusted EBITDA 30,192 $ 31,829 $ 25,609 $ 36,226 $ 43,390 $

Non-GAAP Reconciliation (1)

26

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

3Q-2015 4Q-2015 1Q-2016 2Q-2016 3Q-2016 Adjusted G&A Reconciliation Total G&A expense 4,302 $ 6,180 $ 5,562 $ 6,302 $ 7,891 $ Adjustments: Change in the fair value of liability share-based awards (57) (1,842) (698) (1,954) (3,372) Withdrawn proxy contest expenses (100)

• (221)
• Adjusted G&A - Total

4,145 4,338 4,643 4,348 4,519 Restricted stock share-based compensation (598) (512) (511) (655) (768) Corporate depreciation & amortization (133) (117) (113) (115) (114) Adjusted G&A - Cash 3,414 $ 3,709 $ 4,019 $ 3,578 $ 3,637 $ Adjusted Total Revenue Reconciliation Oil Revenue 30,582 $ 30,582 $ 27,443 $ 40,555 $ 49,095 $ Natural gas revenue 3,734 2,981 3,255 4,590 6,832 Total revenue 34,316 33,563 30,698 45,145 55,927 Impact of cash-settled derivatives 9,789 9,918 7,716 4,017 4,091 Adjusted Total Revenue 44,105 $ 43,481 $ 38,414 $ 49,162 $ 60,018 $ Total Production (MBOE) 896 975 1,132 1,224 1,527 Adjusted Total Revenue per BOE 49.22 $ 44.60 $ 33.93 $ 40.17 $ 39.30 $ Discretionary Cash Flow Reconciliation Net cash provided by operating activities 25,547 31,323 16,120 21,376 12,393 Changes in working capital (1,639) (4,475) (5,582) 6,974 (2,823) Acquisition deposit

• 32,700

Payments to settle asset retirement obligations 1,142 211 161 158 576 Payments to settle vested liability share-based awards

• 9,807

493

• Discretionary cash flow

25,050 $ 27,059 $ 20,506 $ 29,001 $ 42,846 $ Discretionary cash flow per diluted share 0.38 $ 0.37 $ 0.25 $ 0.25 $ 0.31 $

Hedge Portfolio

27

4Q16 1Q17 2Q17 3Q17 4Q17 Crude Oil Swap contracts Volume (Bbl per day) 2,000 2,000 2,000 2,000 2,000 Average NYMEX swap price 58.23 $ 44.50 $ 44.50 $ 44.50 $ 44.50 $ Put contracts Volume (Bbl per day) 2,000 2,000 2,000 2,000 Average NYMEX swap price 30.00 30.00 30.00 30.00 Call contracts Volume (Bbl per day) 1,836 1,836 1,836 1,836 50.00 $ 50.00 $ 50.00 $ 50.00 $ Collar contracts with short puts (“three-way” collar) Volume (BBl per day) 2,000 Average NYMEX price: Ceiling 65.00 $ Floor 55.00 $ Short put 40.33 $ Two-way collar contracts Volume (BBl per day) 2,000 4,200 4,200 4,200 4,200 Average NYMEX price: Ceiling 46.50 $ $58.15 $58.15 $58.15 $58.15 Floor 37.50 $ $47.50 $47.50 $47.50 $47.50 Midland Basin Oil Differential Volume (Bbl per day) 4,000 Swap price spread to NYMEX 0.17 $ Natural Gas Swap contracts Volume (MMBtu per day) 6,000 Average NYMEX swap price 2.52 $ Collar contracts with short puts (“three-way” collar) Volume (MMBtu per day) 4,000 4,000 4,000 4,000 Average NYMEX price: Ceiling 3.71 $ 3.71 $ 3.71 $ 3.71 $ Floor 3.00 $ 3.00 $ 3.00 $ 3.00 $ Short put 2.50 $ 2.50 $ 2.50 $ 2.50 $

Risk Management

1) Short oil calls not included in FY17. 2) 2017 gas hedge swap price represents the $3.00 floor of a 3-way structure that also includes a ceiling of $3.71 and a short-put of $2.50.

28

Oil Hedges ($/Bbl) (1) Gas Hedges ($/MMBtu) (2)

• Added 3,000 Bbl/d oil hedges with 2-way collar ($47.50 x $57.79) in October 2016
• Continue to evaluate additional hedges in 2017 in conjunction with development planning process with the magnitude
• f any outspend influencing the corresponding level of hedging

6,000 4,000 4,000 4,000 4,000 $2.52 $3.00 $3.00 $3.00 $3.00 $2.2 $2.3 $2.4 $2.5 $2.6 $2.7 $2.8 $2.9 $3.0 $3.1

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 4Q16 1Q17 2Q17 3Q17 4Q17

$/MMBtu MMBtu/d Hedged Volume (MMBtu/d) Swap/Long Put Price ($/MMBtu) 6,000 6,200 6,200 6,200 6,200 $50.24 $46.53 $46.53 $46.53 $46.53 $40.0 $42.0 $44.0 $46.0 $48.0 $50.0 $52.0

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 4Q16 1Q17 2Q17 3Q17 4Q17

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