1Q17 Earnings Presentation May 02, 2017 Important Disclosures - - PowerPoint PPT Presentation

May 02, 2017

1Q17 Earnings Presentation

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, 2016 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, Adjusted G&A and other measures identified as non-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

• 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.

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

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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.

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Callon Petroleum

1) Pro forma for pending Ward County acquisition of 2,626 net acres.

4

• Significant core footprint with approximately

60,000 net acres (1)

• Four core operating areas with

demonstrated Wolfcamp and Lower Spraberry performance tracking 1 MMBOE type curves

• 1Q17 highlights

– 11% q/q production growth with 14% q/q growth in oil production – Oil mix of ~80% – 17% reduction in LOE

• Asset performance

– Exceptional repeated Wolfcamp A results in WildHorse, leading to type curve increase – Spur Wolfcamp A flowing under natural pressure into fourth month – Monarch Lower Spraberry solid foundation enhanced with downspacing and Wolfcamp co-development

• Strong credit metrics and liquidity support

acceleration plans and the ability to pursue “bolt-on” acquisitions in core areas

Ranger Spur Monarch Net Surface Acres Gross Delineated Locations Current Hz Flow Units

Midland Basin 39,600 ~1,000 6 Delaware Basin (1) 19,300 ~540 3 Total Permian (1) 58,900 ~1,540 7

Midland Basin Delaware Basin

WildHorse

5

Execution / Path Forward

1Q17

• Added third horizontal rig, increasing

focus on WildHorse

• Closed Spur acquisition mid-quarter

2Q17

• Expand activity to all four core areas
• Refine Spur landing zones/completion

designs

3Q17

• Addition of fourth rig in Delaware at Spur
• WildHorse infrastructure projects

substantially complete

4Q17

• Initial production impact from Spur rig
• WildHorse production benefitting fully

from infrastructure/debottlenecking

2018

• Target exit rate production in excess of

40,000 BOEPD

Production Growth

5 10 15 20 25 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17E

MBOE/d

Oil Natural Gas

Cash Operating Structure

$0 $5 $10 $15 $20 $25 $30 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17E

$/BOE

LOE (incl. gathering) Production Taxes Cash G&A

67% CAGR

50 100 150 200 90 180 270

MBOE

Avg Since 2Q16 1MMBOE

Operational Update

1) Operated wells with first production since June 30, 2016, normalized to 7,000’ of completed lateral (approximately 7,500’ drilled lateral length) based on actual Lower Spraberry average completion length of 6,922’ and Wolfcamp average completion length of 7,250’.

6

Completions: Quarterly Progression Completions: Geographic Breakdown Wolfcamp Well Performance (MBOE) (1) Lower Spraberry Well Performance (MBOE) (1)

50 100 150 200 90 180 270

MBOE

Avg Since 2Q16 1MMBOE

17 wells in two core areas 12 wells in four core areas

3.4 6.9 6.0 6.6 9.4 2 4 6 8 10 12 2Q16 3Q16 4Q16 1Q17 2Q17E (Operated) Net Gross 80% 82% 100% 33% 25% 18% 17% 8% 20% 67% 50% 0% 20% 40% 60% 80% 100% 2Q16 3Q16 4Q16 1Q17 2Q17E Monarch Ranger Spur WildHorse

Operational Performance

7

Howard County Drilling Efficiency LOE ($/BOE)

2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 5 10 15 20 25 Depth Days $0 $2 $4 $6 $8 $10 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17E Midpoint Saltwater disposal Fuel & power Repairs & maintenance Gathering & treating Other LOE Downhole Jobs / Workover

Midland Drilling and Completion Costs ($/Foot)

• Workover activity has normalized
• Infrastructure investments beginning to benefit fuel &

power and saltwater disposal, targeting a decrease in LOE of $0.50 - $0.60 per BOE produced in 2017

• D&C costs tracking forecast; ~15% increase in 2H17

lateral lengths will enhance capital efficiency on a D&C cost-per-foot basis

Median ~15 days

$0 $100 $200 $300 $400 $500 $600 $700 $800 FY2016 Avg 1H17 Avg AFE 2017E Plan

$5.5MM 7,500’ Well

WildHorse: Emerging Growth Driver

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Well Zone Lateral IP30 CPE Operated Completions

Cheek Unit 28-21 09SH LS 9,402’ Flowing Garrett-Reed Unit 37-48 09SH LS 6,562’ Flowing Wright-Adams Unit 31-42 07SH LS 7,926’ Flowing Cheek Unit 28-21 01AH WCA 9,720’ Flowing Wright-Adams Unit 31-42 05AH WCA 6,832’ 1,976 Garrett-Reed Unit 37-48 08AH WCA 6,562’ 1,187 Silver City 01AH WCA 7,363’ 2,148

• Drilling and completion activity

– Three LS/WCA pads completed in 1Q17 in central and northern sections of WildHorse position – Continued outperformance of new generation WCA completions – Five wells, targeting three distinct zones, currently completing

• Infrastructure progress

– Sidewinder field placed on permanent power sources; Maverick field progressing – Fairway water gathering corridor nearing completion – Developing network of owned and third party SWDs – Oil pipeline offtake largely in place

• Multiple bolt-on acquisitions

completed / signed since closing of acquisitions (~600 net acres)

• Several trade discussions in process to

add contiguous acreage

4 7 1 2 3 5 6

Permitted SWD Water pipeline system Existing SWD

1 2 3 4 5 6 7 Fairway Sidewinder Maverick

WildHorse: Well Performance Update

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Wolfcamp A

• 50

100 150 200 250 300 350 90 180 270 MBOE Days

WRIGHT-ADAMS UNIT 31-42 05AH CHEEK UNIT 28-21 01AH SILVER CITY UNIT A 01H GARRETT-REED UNIT 37-48 08AH 1MMBOE 1.3MMBOE GARRETT UNIT 37-48 04AH GARRETT-SNELL UNIT B 36-25 04H GARRETT-SNELL UNIT B 36-25 05H GARRETT-SNELL UNIT B 36-25 08AH MASTERS UNIT A 01H OPEN UNIT A 02H PAPAGIORGIO 40-33 B 11 WA RYDER UNIT A 02H WRIGHT UNIT 41-32 02H WRIGHT-ADAMS UNIT 31-42 08AH WRIGHT UNIT B 41-32 08AH

• Performance enhanced by larger proppant loadings (~50% increase over

legacy) with 90% higher IP30/1000’

• Increasing Sidewinder 7,500’ type curve to 1.3 MMBOE (85% oil) vs. previous

Howard County WCA acquisition type curves of 700 MBOE – 1 MMBOE

Well Name WildHorse Field Completed Lateral 30-day IP/Ft (% oil) Proppant (Lb/Ft) Wright-Adams Unit 31-42 05AH Sidewinder (North Howard) 6,832’ 289 (91%) 2,079 Cheek Unit 28-21 01AH Sidewinder (North Howard) 9,720’ Flowing back 2,023 Silver City 01AH Sidewinder (North Howard) 7,363’ 292 (89%) 1,959 Garrett-Reed Unit 37-48 08AH Maverick (Central Howard) 6,562’ 183 (90%) 2,055 Legacy Average (11 wells within footprint) Various 7,697’ 134 (91%) 1,325

Sidewinder

WildHorse: Well Performance Update

1) Less than 35 days since first oil. 2) Average excludes Garrett-Snell Unit B 36-25 08SH well that was non-operated and data unavailable.

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Lower Spraberry

50 100 150 200 90 180 270 MBOE Days

GARRETT-REED UNIT 37-48 09SH WRIGHT-ADAMS UNIT 31-42 07SH 850 MBOE GARRETT-SNELL UNIT B 36-25 08SH WRIGHT-ADAMS UNIT 31-42 06SH PONDEROSA UNIT L 01H GARRETT UNIT 37-48 03SH GUNSLINGER UNIT L 04H

Well Completed Lateral 30-day IP/Ft (% oil) Proppant (Lb/Ft) Cheek Unit 28-21 09SH (1) 9,402’ Flowing back 1,953 Garrett-Reed Unit 37-48 09SH 6,562’ Flowing back 2,110 Wright-Adams Unit 31-42 07SH 7,926’ Flowing back 1,798 Legacy Average (4 wells within footprint) (2) 7,654’ 100 (90%) 1,393

• In-line performance with legacy wells (7,500’ type curve of ~850 MBOE)
• Larger completions have increased LS dewatering time in Howard County

for industry operators, with longer term production improvements

WildHorse: Execution Plan

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Highlights

• Two-rig program development
• Three zones currently in development
• Completion enhancements

– Near wellbore intensity designs (stage spacing and diverter agents) – Refinement of Lower Spraberry proppant loadings on upcoming completions

• Upcoming milestones

– Key elements of infrastructure buildout on schedule with 3Q17 expected completion – Extended well performance data from Lower Spraberry and Wolfcamp B – Refinement of Lower Spraberry completion designs and Wolfcamp B landing zones – Density spacing assessment and optimal full field development options 2017 Operated Completion Activity

• Total planned completions: 27 gross / 23.2 net
• Average drilled lateral length: ~8,000’

LS/WCA pair WCA/WCB pair WCA pairs LS/WCA LS/WCA/WCB stack

1Q April to Dec

Spur: The Next Catalyst

12

Key Highlights

• Acquisition of Ameredev assets closed on

February 13, 2017

• Subsequent agreements for the acquisition
• f 2,626 net acres for $54.3MM

– Increases working interest in existing inventory – Extends the laterals of 93 gross legacy laterals from a prior blended average of 5,000’ to a new blended average of ~9,200’ – Adds incremental 41 net WCA/WCB locations (90%+ operated) with average lateral of ~7,500’ – Combined acquisition impact of ~67 net locations with an average lateral length of 8,000’+

• Recent operational activity

– Naturally flowing Corbets 34-149 2WA (Lower WCA) under a pressure management program with cumulative production of over 100 MBOE (90% oil) in first 90 days since first oil – Recently started flowback of Saratoga 34-161 1WB (WCB) – Analyzing recently processed core data to

• ptimize landing zones and completion designs

Spur Map

• ~19,300 net surface acres (pro forma)
• Anticipate ~80% to be operated

Pending Acquisitions Saratoga 34-161 1WB Corbets 34-149 2WA 1 1 2 2

Spur: Development Preparation

1) Based on pyrolysis and vitrinite reflectance of whole core.

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Landing Zone Refinement Completion Commentary

• Modified landing zones for Wolfcamp A and

Wolfcamp B compared to previous operator wells

• Natural fracturing combined with over-

pressured reservoir reduce the need for larger completion designs

• Nanosurfactants and diverter agents used
• n both wells recently placed on

production

• Continuing to evaluate Corbets 34-149

#2WA core data and existing well production data

– Refine future completion designs – Maximize resource recovery

Upper WCA ~50’ lower Lower WCA ~60’ lower ~55’ higher

GR Δ Log R

CPE Previous Operators

3rd Bone Spring Sand Lower WCA Lower WCB WCB

Core Data Analysis

14

Spur: Execution Plan

1Q17

• Closed Ameredev on February 13, 2017
• Commenced analysis of Corbets 34-149 2WA

core data

1) Source: IHS. Wells permitted within the last six months as of 4/24/17.

2Q17

• Acquisition of an additional 2,600+ net acres
• First Wolfcamp B completion
• Finalize core analysis and completion designs

for 2H17 drilling program

3Q17

• Add dedicated Delaware Basin rig
• Expected first oil from Callon-operated

program (late 3Q)

4Q17

• Drilling of Upper Wolfcamp A
• Finalize identification of delineation targets

for 2018

2018

• Poised to add second rig early 2018

2H17 Planned Drilling Activity

Pending Acquisitions Permitted Wells (1) Active Rigs Lower Wolfcamp A Upper Wolfcamp A

Well Spud Zone Drilled Lateral Sleeping Indian 01LA 3Q LWCA 10,000’ Saratoga 07LA 3Q LWCA 10,000’ Moran 01LA 4Q LWCA 10,000’ Corbets 01LA 4Q LWCA 10,000’ Corbets 09UA 4Q UWCA 10,000’ 1 2 4 2 1 3 5 3 4 5

Over 1,500 Delineated Locations (1)

1) Pro forma for pending Ward County acquisition. 2) $50.00 WTI / $2.75 Henry Hub flat with assumed well cost inflation of 10%.

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Operating Areas Well Economics: 2017 Plan Averages @ $50/BBL (2) Relevant Incremental Zones Carried by Peers

Midland Delaware Clearfork Avalon Jo Mill 2nd Bone Spring Wolfcamp C 3rd Bone Spring Wolfcamp D/Cline 269 383 347 539

Ranger Monarch WildHorse Spur Zones

100 308 665 465

MS LS WCA WCB

Planned Flow Units

• Avg. Cash

Payback

• Avg. PV 10
• Avg. IRR

Monarch 4 15 months $8.2MM 101% WildHorse 3 19 months $7.6MM 89% Ranger 1 24 months $4.4MM 45% Spur 2 20 months $10.9MM 77% Wtd Avg

• ~18 months

~$7.9MM ~90%

1Q17 Summary Results

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Revenue Drivers Cash Operating Expenses ($/BOE)

$1.96 $2.20 $3.21 $5.97 $7.96 $6.61 $3.55 $2.84 $2.43 $0.18 $0.40 $0.43 $0 $5 $10 $15 1Q16 4Q16 1Q17 Production Taxes LOE Adj Cash G&A Gathering 12.4 18.4 20.4 $27.12 $40.90 $44.27 $0 $20 $40 $60

• 5.0

10.0 15.0 20.0 25.0 1Q16 4Q16 1Q17

$/BOE MBOE/d

Production Unhedged Realized Price

Cash Generation ($/BOE)

$22.27 $28.73 $30.23 $37.82 $31.59 $30.20 $0 $20 $40 1Q16 4Q16 1Q17 Adj EBITDA Margin Cash Operational CAPEX

• Sequential production growth of 11% with 14%

increase in sequential oil volumes

• 78% oil; Realized unhedged prices up 8% q/q
• LOE down 17% q/q as benefits of infrastructure

investments continue to emerge

• Internal operating margins in excess of capital

expenditures

Financial Positioning

1) Net Debt at March 31, 2017 divided by annualized 1Q17 Adjusted EBITDA. See Appendix for the reconciliation of Adjusted EBITDA. 2) Net Debt at March 31, 2017 plus $54 million for funding of pending Ward County acquisitions divided by annualized 1Q17 Adjusted EBITDA inclusive of estimated Pro forma Adjustments. See Appendix for the reconciliation of Adjusted EBITDA inclusive of Pro forma Adjustments. 3) Assumes election of full borrowing base indication.

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Net Debt / Adjusted EBITDA Debt Maturity Summary ($MM) Capitalization ($MM)

1.6x 1.8x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 1Q17 LQA (1) 1Q17 LQA PF (2) $- $- $- $- $400

$- $100 $200 $300 $400 $500 2016 2017 2018 2019 2020 2021 2022 2023 2024

Senior Notes No Near-Term Maturities $385MM Commitments (Undrawn) $500MM Borrowing Base (Under Review)

March 31, 2017 Cash $35 Credit Facility $0 Senior Notes due 2024 $400 Total Debt $400 Stockholders’ Equity $1,780 Total Capitalization $2,180 Total Liquidity (3) $535

• Current three rig program, preparing for transition

to four rigs in July 2017

• Completion activity in all four core operating areas

combined with increasing completion rate with full impact of third rig added in January 2017

• Estimated q/q production growth of 10%+
• Continued reductions in operating cost structure
• Completion of Fairway water gathering system
• Target Net Debt/EBITDA < 2x

Guidance Summary

1) Excludes stock-based compensation and corporate depreciation and amortization. See the Non-GAAP related disclosures in the Appendix. 2) Excludes certain non-recurring expenses and non-cash valuation adjustments. See the non-GAAP related disclosures in the Appendix. 3) All interest expense anticipated to be capitalized. 4) Includes facilities, seismic, land and other items. Excludes capitalized expenses.

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2Q17 and FY17 Guidance

2Q17 Guidance FY17 Guidance

Total production (BOE/d) 21,500 – 23,500 22,500 - 25,500 % oil 76% - 78% 75% - 77% Income Statement Expenses (per BOE) LOE, including workovers $6.25 - $7.00 $6.00 - $6.50 Gathering and treating $0.40 - $0.50 $0.40 - $0.50 Production taxes, including ad valorem (% of unhedged revenues) 7% 7% Adjusted G&A: cash component (1) $2.25 - $2.50 $2.00 - $2.50 Adjusted G&A: non-cash component (2) $0.50 - $0.75 $0.50 - $1.00 Interest expense (3) $0.00 $0.00 Effective income tax rate 0% 0% Capital expenditures ($MM, accrual basis) Drilling and completion (4) $55 - $60 $240 - $255 Facilities and other (4) $35 - $40 $85 - $95 Capitalized expenses (cash component) $10 - $12 $40 - $45 Net operated horizontal well completions Midland Basin 9 – 11 30 – 32 Delaware Basin 1 3 - 4

Key Assumptions 2Q17 Highlights

2Q17

Net Operated Completions 10 – 12 Average Drilled Lateral Length ~7,500’ Average Working Interest 75% - 80%

1Q17 Summary

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• Foundation of repeatable Lower Spraberry

and Wolfcamp wells across all four core areas

– 1 MMBOE average type curve performance – Completion design enhancements expected to drive incremental improvements

• Disciplined growth plan to accelerate

returns from legacy and acquired assets

– Modest cash outspend with near-term visibility of cash flow neutrality – Proper time to build infrastructure to improve capital efficiency and complete technical analyses prior to program development – WildHorse and Spur growth drivers beginning to emerge within Callon portfolio

• Financial strength

– Low leverage combined with strong cash margins to fund growth plans – Undrawn revolver with upcoming redetermination including Spur contribution PRODUCTION

• Early time impact of

WildHorse growth

• Oil cut remains highest

amongst peer group

• Sequential 2017 q/q

growth to increase

1.3 MMBOE WCA Type Curve

WildHorse EURs

• Northern Howard Co.

WCA type curves up

• ver 85% since April

2016

• Central Howard Co. to

be re-evaluated after upcoming results

17% Decrease

LOE/BOE

• Transitory 4Q16 issues

resolved

• Increasing operating

efficiency at acquired properties

11% Increase

Appendix

Risk Management

1) Short oil calls not included in FY17. See the Appendix “Hedge Portfolio – Oil” slide for additional detail. 2) 2017 gas hedge swap price represents the $3.00 floor of a 3-way structure with a ceiling of $3.71 and short-put of $2.50 on 4,000 BBL/day and a 2-way structure with a ceiling of $3.68 on 4,000 BBL/day. See the Appendix “Hedge Portfolio – Gas” slide for additional detail.

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Oil Hedges ($/BBL) (1)

8,450 8,450 8,450 7,500 $47.60 $47.60 $47.60 $50.00 $40.00 $42.00 $44.00 $46.00 $48.00 $50.00 $52.00

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 2Q17 3Q17 4Q17 FY2018

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

Gas Hedges ($/MMBTU) (2)

10,681 12,000 14,652 8,000 $3.10 $3.13 $3.18 $3.40 $2.00 $2.20 $2.40 $2.60 $2.80 $3.00 $3.20 $3.40 $3.60

2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 2Q17 3Q17 4Q17 1Q18

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

Approximately 45% of 2017 oil volumes and 20%+ of 2018 oil volumes hedged based on the midpoint of guidance

Hedge Portfolio - Oil

22

2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Crude Oil Swap contracts combined with short put option Volume (BBL per day) 2,000 2,000 2,000 Average NYMEX swap price 44.50 $ 44.50 $ 44.50 $ Average NYMEX swap option price 30.00 $ 30.00 $ 30.00 $ Deferred premium put option contracts Volume (BBL per day) 2,750 Premium per BBL 2.05 $ Average NYMEX long put price 50.00 $ Deferred premium put spread contracts Volume (BBL per day) 2,750 2,750 Premium per BBL 2.45 $ 2.45 $ Average NYMEX long put price 50.00 $ 50.00 $ Average NYMEX short put price 40.00 $ 40.00 $ Short call contracts Volume (BBL per day) 1,836 1,836 1,836 Average NYMEX short call price 50.00 50.00 50.00 Two-way collar contracts Volume (BBL per day) 3,700 3,700 3,700 Average NYMEX price: Ceiling 58.19 58.19 58.19 Floor 47.50 47.50 47.50 Collar contracts with short puts (“three-way” collar) Volume (BBL per day) 7,500 7,500 7,500 7,500 Average NYMEX price: Ceiling 62.84 62.84 62.84 62.84 Floor 50.00 50.00 50.00 50.00 Short put 40.00 40.00 40.00 40.00 Midland Basin Oil Differential Volume (BBL per day) 6,000 6,000 6,000 5,500 5,500 5,500 5,500 Swap price spread to NYMEX (0.52) $ (0.52) $ (0.52) $ (1.02) (1.02) (1.02) (1.02) 2018 Average Daily Volumes 2017 Average Daily Volumes

Hedge Portfolio - Gas

23

2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Natural Gas Swap contracts Volume (MMBTU per day) 2,681 4,000 1,348 Average NYMEX swap price 3.39 3.39 3.39 Two-way collar contracts Volume (MMBTU per day) 4,000 4,000 9,304 8,000 Average NYMEX price: Ceiling $3.68 $3.68 $3.77 $3.84 Floor $3.00 $3.00 $3.23 $3.40 Collar contracts with short puts (“three-way” collar) Volume (MMBTU per day) 4,000 4,000 4,000 Average NYMEX price: Ceiling 3.71 $ 3.71 $ 3.71 $ Floor 3.00 $ 3.00 $ 3.00 $ Short put 2.50 $ 2.50 $ 2.50 $ 2018 Average Daily Volumes 2017 Average Daily Volumes

Quarterly Cash Flow Statement

24

Cash flows from operating activities: Net income (loss) $ (41,109) $ (70,097) $ 21,139 $ (1,746) $ 47,129 Adjustments to reconcile net income (loss) to cash provided by operating activities: Depreciation, depletion and amortization 16,129 16,698 17,733 22,512 24,932 Write-down of oil and natural gas properties 34,776 61,012

• Accretion expense

180 395 187 196 184 Amortization of non-cash debt related items 781 780 810 744 665 Deferred income tax (benefit) expense

• (62)

48 466 Net gain (loss) on derivatives, net of settlements 8,648 19,501 (1,044) 11,030 (17,794) Non-cash gain for early debt extinguishment

• 9,883
• Non-cash expense related to equity share-based awards

516 665 778 811 930 Change in the fair value of liability share-based awards 709 1,965 3,371 908 (291) Payments to settle asset retirement obligations (161) (158) (576) (576) (765) Changes in current assets and liabilities: Accounts receivable 5,941 (10,777) (11,608) (13,611) (4,066) Other current assets 580 (885) 54 (535) 576 Current liabilities (717) 4,830 15,702 5,473 9,903 Change in other long-term liabilities 11 75

• 10
• Change in other assets, net

(233) (217) (1,221) 831 (523) Payments to settle vested liability share-based awards (9,807) (493)

• (8,662)

Net cash provided by operating activities 16,244 23,294 45,263 35,978 52,684 Cash flows from investing activities: Capital expenditures (50,775) (24,505) (47,418) (67,334) (66,154) Acquisitions (10,183) (273,841) (18,033) (352,622) (648,485) Acquisition deposit

• (32,700)

(13,438) 46,138 Proceeds from sales of mineral interest and equipment

• 23,631

(708) 1,639

• Net cash used in investing activities

(60,958) (274,715) (98,859) (431,755) (668,501) Cash flows from financing activities: Borrowings on credit facility 45,000 98,000 74,000

• Payments on credit facility

(85,000) (58,000) (114,000)

• Payments on term loan
• (300,000)
• Issuance of 6.125% senior unsecured notes due 2024
• 400,000
• Payment of deferred financing costs
• (640)

(10,153)

• Issuance of common stock

94,949 205,858 421,908 634,862

• Payment of preferred stock dividends

(1,824) (1,823) (1,824) (1,824) (1,824) Tax withholdings related to restricted stock units (124) (1,918) (170)

• (79)

Net cash provided by financing activities 53,001 242,117 379,274 722,885 (1,903) Net change in cash and cash equivalents 8,287 (9,304) 325,678 327,108 (617,720) Balance, beginning of period 1,224 9,511 207 325,885 652,993 Balance, end of period $ 9,511 $ 207 $ 325,885 $ 652,993 $ 35,273 3Q16 4Q16 1Q16 2Q16 1Q17

Non-GAAP Reconciliation (1)

25

1) See “Important Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures. 2) Adjusted EBITDA inclusive of Pro forma Adjustments is used primarily for the purpose of calculating compliance with covenants, such as Debt/EBITDA calculations, and includes the impact of acquisitions closed during prior periods as if they were completed at the beginning of the reporting period.

1Q16 2Q16 3Q16 4Q16 1Q17 Adjusted Income Reconciliation Income (loss) available to common stockholders (42,933) $ (71,920) $ 19,315 $ (3,570) $ 45,305 $ Adjustments: Change in valuation allowance 14,288 24,409 (7,907) 559 (13,119) Write-down of oil and natural gas properties 22,604 39,658

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

5,621 12,676 (679) 7,170 (11,566) Change in the fair value of share-based awards 461 1,277 2,192 590 (189) Withdrawn proxy contest expenses 144 2

• Loss on early redemption of debt
• 8,374
• Adjusted Income

185 $ 6,102 $ 12,921 $ 13,123 $ 20,431 $ Adjusted income per fully diluted common share

• $

0.05 $ 0.09 $ 0.08 $ 0.10 $ Adjusted EBITDA Reconciliation Net income (loss) (41,109) $ (70,097) $ 21,139 $ (1,746) $ 47,129 $ Adjustments: Write-down of oil and natural gas properties 34,776 61,012

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

8,648 19,501 (1,044) 11,030 (17,794) Non-cash stock-based compensation expense 1,225 2,628 4,150 1,718 639 Loss on early depemption of debt

• 12,883
• Withdrawn proxy contest expenses

221 3

• Acquisition expense

48 1,906 456 1,263 450 Income tax (benefit) expense

• (62)

48 466 Interest expense 5,491 4,180 831 1,369 665 Depreciation, depletion and amortization 16,129 16,698 17,733 22,512 24,932 Accretion expense 180 395 187 196 184 Adjusted EBITDA 25,609 $ 36,226 $ 43,390 $ 49,273 $ 56,671 $ Adjusted EBITDA inclusive of Pro forma Adjustments (2) 36,983 $ 47,790 $ 52,876 $ 54,030 $ 59,329 $

Non-GAAP Reconciliation (1)

26

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

1Q16 2Q16 3Q16 4Q16 1Q17 Adjusted G&A Reconciliation Total G&A expense 5,562 $ 6,302 $ 7,891 $ 6,562 $ 5,206 $ Adjustments: Change in the fair value of liability share-based awards (698) (1,954) (3,372) (857) (307) Threatened proxy contest (221)

• Adjusted G&A - Total

4,745 4,348 4,519 5,705 5,513 Restricted stock share-based compensation (511) (655) (768) (801) (921) Corporate depreciation & amortization (113) (115) (114) (104) (121) Adjusted G&A - Cash component 4,121 $ 3,578 $ 3,637 $ 4,800 $ 4,471 $ Adjusted Total Revenue Reconciliation Oil revenue 27,443 $ 40,555 $ 49,095 $ 60,559 $ 72,008 $ Natural gas revenue 3,255 4,590 6,832 8,522 9,355 Total revenue 30,698 45,145 55,927 69,081 81,363 Impact of cash-settled derivatives 7,716 4,017 4,091 2,079 (2,491) Adjusted Total Revenue 38,414 $ 49,162 $ 60,018 $ 71,160 $ 78,872 $ Total Production (Mboe) 1,132 1,224 1,527 1,689 1,838 Adjusted Total Revenue per Boe 33.93 $ 40.17 $ 39.30 $ 42.13 $ 42.91 $ Discretionary Cash Flow Reconciliation Net cash provided by operating activities 16,244 23,294 45,263 35,978 52,684 Changes in working capital (5,582) 6,974 (2,927) 7,832 (5,890) Payments to settle asset retirement obligations 161 158 576 576 765 Payments to settle vested liability share-based awards 9,807 493

• 8,662

Discretionary cash flow 20,630 $ 30,919 $ 42,912 $ 44,386 $ 56,221 $ Discretionary cash flow per diluted share 0.25 $ 0.26 $ 0.31 $ 0.27 $ 0.28 $