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CALLON PETROLEUM COMPANY
1Q 2015 Earnings Presentation
May 6, 2015
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 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, 2014 filed with
the Securities and Exchange Commission (the “SEC”).
RESERVE-RELATED DISCLOSURES
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 Companygenerated 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
[email protected].
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.
2
HIGHLIGHTS
 Net daily production of 8,567 BOE (83% oil), an increase of 18%
over 4Q2014
 Capital efficiency continues to improve as additional capital
cost reductions put us on a path to realize a 30% decrease in
total completed well costs in 2H15 compared to 2014 levels
 Increasing type curves across core areas for both Wolfcamp B
and Lower Spraberry
 Plans to capitalize on cost structure with a revised operating
plan that includes reallocation of capital to the Lower Spraberry
zone across our acreage footprint
 Financial flexibility enhanced by recent completion common
equity offering and reaffirmation of $250 MM borrowing base
 Remain focused on achieving cash flow neutrality by 2H16
3
REVENUES
Daily Production (Boepd)
Oil
Revenue ($MM)
Nat Gas/NGLs
Oil
10,000
1,479
$35.0
1,520
6,000
2,000
667
1Q15:
83% oil
7,088
5,750
$15.0
$2.4
$30.9
$7.1
$4.0
$10.3
$2.5
$34.4
$27.9
3,688
($0.9)
0
1Q14
4Q14
($5.0)
1Q15
Realized Oil Prices ($/Bbl)
Unhedged
Hedge Impact
$95.00
NYMEX
$95.00
$13.24
$75.00
$75.00
$15.61
$55.00
$35.00
$35.00
$65.05
$43.74
$15.00
($2.33)
1Q14
4Q14
1Q15
1Q14
$15.00
($5.00)
4Q14
1Q15
Realized Gas Prices ($/Mcf)
Unhedged
Hedge Impact
NYMEX
$6.50
$6.50
$5.50
$3.50
$5.50
$0.07
$4.50
$55.00
$93.10
($5.00)
Settled Hedges
$55.0
8,000
4,000
Nat Gas/NGLs
$0.49
$6.55
$2.50
$4.50
$2.50
$4.78
$1.50
$3.10
$0.50
($0.50)
$3.50
$1.50
$0.50
($0.29)
1Q14
4Q14
1Q15
($0.50)
4
EXPENSES
LOE ($/BOE)
Adjusted G&A ($/BOE)(a)
Cash
$12.00
Non-Cash
$15.00
$10.00
$8.00
$6.00
$10.79
$11.23
$4.00
$9.03
$10.00
$1.48
$5.00
$9.99
$2.00
$4.35
$0.00
4Q14
1Q15
DD&A ($/BOE)
$5.37
1Q14
4Q14
1Q15
Early Retirement Program
 Reduced staff by ~ 20% (Natchez
and Houston)
$30.00
$25.00
 One-time income statement
expense of $4.7MM in 1Q15
$20.00
$26.88
$27.05
$10.00
$23.48
$5.00
$0.00
1Q14
a)
$0.78
$0.00
1Q14
$15.00
$1.54
4Q14
1Q15
 Total cash payments of $7.1MM
(including payout of stock
incentive awards)
 Annualized total cash G&A
savings of ~$5MM
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 Non-Cash component further excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and
amortization.
5
SUMMARY RESULTS
Adjusted EBITDA(a)
Adjusted Income(a)
Line item
GAAP loss available to
common stockholders
Line item
$000s
$(12,171)
Adjustments (after-tax):
Net loss on derivatives,
net of settlements
5,144
Change in the fair value of
share-based awards
1,676
Rig termination fee
2,367
Early retirement expenses
3,034
Withdrawn proxy contest
expenses
72
Adjusted Income
$122
Adjusted Income per share
$0.00
GAAP net loss
$(10,197)
Adjustments (pre-tax):
Net loss on derivatives,
net of settlements
7,914
Change in the fair value of
share-based awards
2,059
Early retirement expense
4,668
Rig termination fee
3,641
Withdrawn proxy contest
expenses
111
Acquisition expense
3
Income tax expense
(5,077)
Interest expense
Depreciation, depletion &
amortization
Accretion expense
Adjusted EBITDA
a)
$000s
4,858
18,546
209
$26,735
Adjusted income available to common shareholders (“Adjusted Income”) and adjusted EBITDA are Non-GAAP financial measures. Definitions and reconciliations related to Non-GAAP
measures are included within the appendix.
6
1Q15 CAPITAL EXPENDITURES(a)
Breakdown By Category ($MM)
D&C Evolution ($MM)
D&C
$4
Operational
Capex
$5
$53
Facilities
Capitalized G&A
$80
D&C
$60
Facilities
$40
Capitalized
$20
$2
$5
$64
$5
$4
$53
G&A
$0
4Q14
Drilled
Completed(b)
Central
2.0
1.3
Southern
5.8
6.8
Total
7.8
8.1
Net Hz Wells
a)
b)
c)
Net Hz Wells(c)
1Q15
4Q14
1Q15
Drilled
4.6
7.8
Completed
7.3
8.1
Presented on an a GAAP (accrual) basis, excluding $2.8 million and $2.6 million of capitalized interest expense in 1Q15 and 4Q14 , respectively. Total cash capital expenditures
were $70.8 million in 1Q15 and $53.4 million in 4Q14, including $2.9 million and $0.2 million of capitalized interest expense, respectively.
Net completed wells exclude 0.4 vertical well completions.
4Q14 excludes 0.5 vertical wells drilled; 1Q15 excludes 0.4 vertical well completions.
7
FINANCIAL POSITION
Adjusted EBITDA Margins ($/BOE)(a)
Capitalization ($MM)
$1,200
Cash G&A
$1,000
Production Taxes
LOE
Stockholders'
$215
$800
$37
$600
$300
Equity
Second Lien
Facility
Revolving
Credit Facility
$400
$90
$82.68
$80.95
$75.52
$80
$68.01
$70
$60
$52.83
$50
1Q15 Margin:
$40
$200
$488
Bank
Availability +
Cash
$0
$30
$35.49/BOE
$25.67
$21.98
$23.68
$19.38
$20
$17.34
$10
March 31, 2015
$0
Credit Metrics
a)
b)
c)
Revenue
1Q14
Total Debt / Total Capitalization
41%
Net Debt / Adj. EBITDA(b)
2.8x
2Q14
3Q14
4Q14
1Q15
37%
Estimated Apr-Dec 2015 average margin in
excess of $40/BOE based on NYMEX
pricing(c) and midpoint of guidance metrics
See definition of Adjusted EBITDA, a Non-GAAP measure, included in the Appendix. Includes the impact of cash settled derivatives.
Adjusted EBITDA annualized based on 4Q14 and 1Q15 results which include the impacts of the Central Midland Basin acquisition completed on October 8, 2014.
As of May 5, 2015 and assumes 64% of our volumes have been hedged at a weighted-average price of $67.55 for April-Dec 2015.
8
OPERATIONS UPDATE
Carpe Diem/Pecan
Acres/CaBo(a)
Garrison Draw
REAGAN



1st stacked horizontals (WC B
and LS) at Pecan Acres yielding
strong performance
Completed three-well pad at
Cabo (WC B); Plans for a fourwell pad at Cabo (LS)

Two 10,000’ wells placed on
production (Lower WC B)
Wells continue to flow under
natural pressure pending gas
lift
“Core”
East Bloxom
Taylor Draw
UPTON
REAGAN
Tier I



Three wells placed on
production (2 Upper WC B; 1
LS)
Includes 1st Lower Spraberry
(6,632’) placed on ESP in April
Tier II

Lower Spraberry
Wolfcamp A
a)

CaBo field area includes the Casselman and Bohannon fields.
Two wells placed on
production (Lower WC B)
Increased proppant (Lower
WCB) test in process
1st Wolfcamp A well flowing
back
Upper Wolfcamp B
Lower Wolfcamp B
9
COST REDUCTIONS
KeyAchieved
Achieved Reductions
Key
Reductions
7,500’ Component Breakdown ($MM)
$8.0
 Drilling rig: 40%
$6.0
Completion
$4.0
Drilling
 Drilling mud: 28%
 Tubulars: 15%(a)
 Directional drilling: 40%
$2.0
 Pressure Pumping: 35%
$0.0
Baseline
Achieved
Target
Total Well Cost Reductions ($MM)
$12.0
$10.0
Baseline
$9.7
$7.2
$8.0
$6.0
$6.8
$7.5
Achieved
$6.0
$5.1
Target
$6.0
$4.8
$4.0
$4.1
$2.0
$-
10,000'
7,500'
5,000'
Cost Reductions
a)
Effective June 1, 2015.
10
TYPE CURVE SUMMARY ($55/BBL)
Central Midland Ranges(a)
Southern Midland Ranges(a)
Avg:
912 BOE
Avg:
639 BOE
Avg:
595 BOE
IRR(b)
33%
55%
IRR(b)
31%
35%
NPV10 / I(b)
59%
100%
NPV10 / I(b)
59%
66%
Payout(b)
2.7 yrs
1.8 yrs
 Extended Lower Spraberry production
history encouraging
 Wolfcamp B development started in early
2014 / Lower Spraberry in late 2014
 EUR ranges converging with increasing
development activity
a)
b)
541 BOE
Payout(b)
2.7 yrs
2.4 yrs
 Well-established Upper Wolfcamp B EURs
 Lower Wolfcamp B demonstrating strong
37%
results
 Lower D&C costs vs Central Midland wells
Normalized to 7,500’ drilled lateral (7,000’ completed lateral). Includes fields with currently planned activity for the remainder of 2015 and 2016.
Based on actual drilled lateral lengths (not normalized), “Target” AFE levels, and $55/Bbl flat realized oil prices and $3.25/Mmbtu flat NYMEX natural gas prices.
11
PEER GROUP ANALYSIS
Midland Basin Horizontal EURs – Oil(a)
Central
Southern
Callon(b)
Peer
1
Peer
2
Peer
3
Peer
4
37%

Adjusts two/three-stream data and facilitates ESP vs gas lift comparisons

High-quality Southern and Central Basin positions in Callon portfolio
a)
b)
Peer group includes Diamondback Energy, Laredo Petroleum, Parsley Energy and RSP Permian. Peer data based on investor presentations available as of April 15, 2015. Peer 1
EURs assume 75% oil content.
Datapoints represent averages of field type curves by region.
12
OPERATIONAL PLAN
2015 CapEx Guidance(a)
Estimated Breakdown(a)
(Guidance midpoints; $MM)
Capitalized G&A
Operational
Capex
$70
D&C
$50
Facilities
$150
Capitalized
G&A
D&C
$60
$MM
$12
$13
Facilities
$40
$30
$20
$10
$0
1Q15A
2Q15E
3Q15E
2015E
4Q15E
2016E
Updated operational capex of $160MM - $165MM
•
27.0 vs 23.7 net wells following reconfiguration of drilling plans
• Increased Lower Spraberry capital allocations
• Allowance for “non-consent” capital
• Based on “Achieved” D&C reductions
9.1
1.0
6.2
16.9
15.6
D&C capital heavily weighted to 1H15
•
a)
• Three rig program ended in March 2015
• Impact of cost reductions increasing through 2Q15
Added OBO Lower Spraberry well, replacing OBO well in 3Q15
Capital expenditures presented on a GAAP (accrual) basis excluding capitalized interest expense.
Lower Spraberry
WC B
Wells to be Drilled
WC A
13
2015 GUIDANCE
Production (BOE/d)
9,000
4Q14 (7,270 BOE/d) to 4Q15 (~9,500 BOE/d)
production growth of ~30%
8,800
8,600
9,050
8,950
8,400
Two-rig program provides potential growth of
10+% from 4Q15 to 4Q16
8,567
8,200
8,000
1Q15A
2Q15E
2015E
FY2015 Guidance
2Q15 Guidance
Previous
Updated
8,000 - 8,400
8,800 - 9,300
8,800 - 9,100
79% - 81%
79% - 81%
79% - 81%
63%
66%
61%
$70.89
$69.04
$70.79
LOE, including workovers
$8.75 - $9.50
$8.50 - $9.50
$9.00 - $9.70
Production taxes, including ad valorem
$3.00 - $3.50
$2.75 - $3.25
$2.75 - $3.25
Adjusted G&A(b)
$5.75 - $6.25
$5.50 - $5.75
$5.50 - $5.75
$4.89 - $5.31
$4.00 - $4.75
$4.00 - $4.75
Total Production (BOE/d)
% oil
% oil hedged(a)
Weighted average oil swap price
Expenses (per BOE)
Recurring cash component(c)
a)
b)
c)
Based on the midpoint of guidance.
Excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans. See Non-GAAP disclosures included in the Appendix.
Excludes stock-based compensation and corporate depreciation and amortization.
14
APPENDIX
NON-GAAP RECONCILIATION(a)
Income (loss) available to common stockholders
1Q-2014
2Q-2014
3Q-2014
4Q-2014
1Q-2015
$
$ 2,767
$ 10,227
$ 16,988
$ (12,171)
(111)
Adjustments:
Net loss (gain) on derivatives, net of settlements
1,065
1,975
(6,764)
(14,249)
5,144
-
-
-
-
2,367
Change in the fair value of share-based awards
1,726
2,982
(1,713)
1,676
Early retirement expenses
1,601
-
-
3,034
Rig termination fee
Withdrawn proxy contest expenses
Gain on sale of other property and equipment
Loss (gain) on early redemption of debt
775
85
(702)
-
(974)
65
65
72
-
-
-
-
(2,083)
-
1,985
-
Adjusted income
$ 4,354
$ 5,726
$ 2,554
$ 3,076
$
Net income (loss)
$ 1,863
$ 4,740
$ 12,201
$ 18,962
$ (10,197)
Net loss (gain) on derivatives, net of settlements
1,639
3,039
(10,406)
(21,921)
7,914
Change in the fair value of share-based awards
3,101
3,555
(1,031)
(1,941)
2,059
Early retirement expenses
2,463
-
-
-
4,668
Rig termination fee
-
-
-
-
3,641
Loss (gain) on early redemption of debt
-
(3,205)
-
3,054
-
122
Adjustments:
Withdrawn proxy contest expenses
Acquisition expense
Income tax expense (benefit)
Interest expense
Depreciation, depletion and amortization
Accretion expense
Adjusted EBITDA
a)
1,193
130
100
100
111
-
-
-
668
3
1,341
4,128
7,161
10,504
(5,077)
977
1,825
2,205
4,765
4,858
10,598
12,378
16,517
18,521
18,546
228
173
202
223
209
$ 23,403
$ 26,763
$ 26,949
$ 32,935
$ 26,735
See “Additional Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures.
16
NON-GAAP RECONCILIATION(a)
Total G&A expense
1Q-2014
2Q-2014
3Q-2014
4Q-2014
1Q-2015
$ 10,807
$ 9,639
$ 3,261
$ 1,402
$ 12,102
Adjustments:
Change in the fair value of liability share-based awards
(2,655)
(4,587)
1,499
2,635
(2,578)
Early retirement expenses
(2,463)
-
-
-
(4,668)
Threatened proxy contest
(1,193)
Adjusted G&A - Total
Restricted stock share-based compensation
Corporate depreciation & amortization
Adjusted G&A - Cash
a)
(130)
4,496
4,922
(100)
4,660
(100)
(111)
3,937
4,745
(519)
(790)
(735)
(689)
(479)
(60)
(202)
(154)
(342)
(129)
$ 3,917
$ 3,930
See “Additional Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures.
$ 3,771
$ 2,906
$
4,137
17
ADDITIONAL DISCLOSURES
Supplemental Non-GAAP Financial Measures
We believe that the non-GAAP measure of Adjusted income available to common shareholders (“Adjusted Income”) and Adjusted Income per diluted share are
useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot
be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed
in the reconciliation provided below. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted income and Adjusted
income per diluted share below were computed in accordance with GAAP.
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry
analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, depreciation, depletion
and amortization, exploration expense, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and
premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation, asset
retirement obligation accretion expense, other income, gains and losses from the sale of assets and other non-cash operating items. Adjusted EBITDA is not a
measure of net income as determined by United States generally accepted accounting principles (‘‘GAAP’’).
Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our
operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net
income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon
accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be
considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance
or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such
as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our
presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items..
Adjusted general and administrative expense (“Adjusted G&A”) is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses
and non-cash valuation adjustments related to incentive compensation plans. We believe that the non-GAAP measure of Adjusted G&A is useful to investors
because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table
below details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.
Certain Reserve Information
Cautionary Note to U.S. Investors: The Securities and Exchange Commission (“SEC”) prohibits oil and gas companies, in their filings with the SEC, from
disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. This presentation discloses estimates of quantities of oil
and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “resource base,” “estimated ultimate recovery,” “EUR” or other
descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible
reserves, and which the SEC’s guidelines strictly prohibit the Company from including in filings with the SEC. These estimates are by their nature more
speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by the Company. U.S. investors are
urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 1401 Enclave Pkwy, Ste
600, Houston, TX 77077, Attention: Investor Relations, and the Company’s website at www.callon.com. These filings also can be obtained from the SEC by calling
1-800-SEC-0330.
18