·

Daily production of 20.4 MBOE/d (78% oil), a sequential quarterly increase of 11% in total daily production and 14% increase in daily oil production

·

Lease operating expense, including workovers, of $6.61 per BOE, a sequential quarterly decrease of 17%

·

Two Wolfcamp A wells in Howard County (WildHorse area) reached average 30-day peak production rates of 237 BOE/d per 1,000 feet of completed lateral (91% oil) with a third continuing to build to peak production rates

·

Increase in northern Howard County Wolfcamp A type curve (7,500’ drilled lateral) to 1.3 MMBOE (85% oil)

·

Closed the Ameredev transaction in mid-February and subsequently signed  purchase and sale agreements for the acquisition of an additional 2,626 net acres in Ward County (Spur area) for $54.3 million, establishing a position of over 19,300 net surface acres in the Delaware Basin





30-Day Average



24-Hour Peak IP

Peak IP



(BOE/d; Two-stream) (a)

(BOE/d; Two-stream)

24-Hour

Peak

Per 1,000'

Peak

Per 1,000'

IP

Area

Completed

24-Hour

Production

Lateral

30-Day

Production

Lateral

Date

Well

(Field / Zone)

Lateral (ft)

IP

(% oil)

Feet

IP

(% oil)

Feet

03/16/2017

Wright-Adams 31-42 #5AH

WildHorse

(Sidewinder/WCA)

6,832

2,333

90%

341

1,976

91%

289

Pending

Cheek 28-21 #1AH

WildHorse

(Sidewinder/WCA)

9,720

Flowing back

Flowing back

03/02/2017

Garrett-Reed 37-48 #8AH

WildHorse

(Maverick/WCA)

6,560

1,530

92%

233

1,211

90%

184

(a)

24-Hour Peak IPs correspond to the rates filed with the Railroad Commission of Texas and are captured using well tests on the specified date, which may result in an understated rate as the production typically varies more widely during the early days of production. The 30-Day Average Peak IP is calculated using well tests on dates taken and allocated production for all other dates.





Three Months Ended March 31, 2017



Operational

Capitalized

Capitalized

Total Capital



Capital

Other (a)

Interest

G&A

Expenditures

Cash basis (b)

$

$

$

$

$

Timing adjustments (c)

—

—

Non-cash items

—

—

—

  Accrual (GAAP) basis

$

$

$

$

$

(a)

Includes seismic, land and other items.

(b)

Cash basis is a non-GAAP measure that we believe helps users of the financial information reconcile amounts to the cash flow statement and to account for timing related operational changes such as our development pace and rig count.

(c)

Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period.



Three Months Ended

March 31, 2017

December 31, 2016

March 31, 2016

Net production:

  Oil (MBbls)

  Natural gas (MMcf)

  Total production (MBOE)

  Average daily production (BOE/d)

    % oil (BOE basis)

Oil and natural gas revenues (in thousands):

  Oil revenue

$

$

$

  Natural gas revenue

     Total revenue

$

$

$

  Impact of cash-settled derivatives

     Adjusted Total Revenue (i)

$

$

$





In Thousands

Per Unit

Oil derivatives

Net loss on settlements

$

$

Net gain on fair value adjustments

  Total gain on oil derivatives

$

Natural gas derivatives

Net gain on settlements

$

$

Net gain on fair value adjustments

  Total gain on natural gas derivatives

$

Total oil & natural gas derivatives

Net loss on settlements

$

$

Net gain on fair value adjustments

  Total gain on total oil & natural gas derivatives

$





Three Months Ended



March 31, 2017

Average realized sales price

  Oil (per Bbl) (excluding impact of cash-settled derivatives)

$

     Impact of cash-settled derivatives

  Oil (per Bbl) (including impact of cash-settled derivatives)

$



  Natural gas (per Mcf) (excluding impact of cash-settled derivatives)

$

     Impact of cash-settled derivatives

  Natural gas (per Mcf) (including impact of cash-settled derivatives)

$



  Total (per BOE) (excluding impact of cash-settled derivatives)

$

     Impact of cash-settled derivatives

  Total (per BOE) (including impact of cash-settled derivatives)

$





Three Months Ended



March 31, 2017

December 31, 2016

March 31, 2016

Additional per BOE data:

  Sales price, excluding impact of cash-settled derivatives

$

$

$

  Sales price, including impact of cash-settled derivatives



  Lease operating expense (excluding gathering and treating

$

$

$

  expense)

  Gathering and treating expense

  Production taxes

  Depletion, depreciation and amortization

  Adjusted G&A (a)

     Cash component (b)

     Non-cash component

(a)

Excludes certain non-recurring expenses and non-cash valuation adjustments. See the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(b)

Excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization.





For the Three Months Ended



March 31, 2017

Total G&A expense

  Less: Change in the fair value of liability share-based awards (non-cash)

$

Adjusted G&A – total

  Restricted stock share-based compensation (non-cash)

  Corporate depreciation & amortization (non-cash)

Adjusted G&A – cash component

$





Second Quarter

Full Year



2017 Guidance

2017 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 (% unhedged revenue)

7%

7%

  Adjusted G&A: cash component (a

$2.25 - $2.50

$2.00 - $2.50

  Adjusted G&A: non-cash component (b)

$0.50 - $0.75

$0.50 - $1.00

  Interest expense (c)

$0.00 - $0.00

$0.00 - $0.00

  Effective income tax rate

0%

0%

Capital expenditures ($MM, accrual basis)

  Drilling and completion

$55 - $60

$240 - $255

  Facilities and other (d)

$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

(a)

Excludes stock-based compensation and corporate depreciation and amortization. See the Non-GAAP related disclosures referenced in the footnote (b) below.

(b)

Excludes certain non-recurring expenses and non-cash valuation adjustments. The reconciliation above provides a reconciliation of first quarter 2017 G&A expense on a GAAP basis to Adjusted G&A expense, a non-GAAP measure. The Company is unable to present a quantitative reconciliation of this forward-looking non-GAAP financial measure without unreasonable effort because of the number of estimated variables that could affect the final value. Accordingly, investors are cautioned not to place undue reliance on this information.

(c)

All interest expense anticipated to be capitalized.

(d)

Includes seismic, land and other items. Excludes capitalized expenses.





For the Remainder of

For the Full Year of

Oil contracts

2017

2018

Swap contracts combined with short puts (WTI, enhanced swaps)

  Total volume (MBbls)

—

  Weighted average price per Bbl

     Swap

$

$

—

     Short put option

$

$

—

Deferred premium put option

  Total volume (MBbls)

—

  Premium per Bbl

$

$

—

  Weighted average price per Bbl

     Long put option

$

$

—

Deferred premium put spread option

  Total volume (MBbls)

—

  Premium per Bbl

$

$

—

  Weighted average price per Bbl

     Long put option

$

$

—

     Short put option

$

$

—

Collar contracts (WTI, two-way collars)

  Total volume (MBbls)

—

  Weighted average price per Bbl

     Ceiling (short call)

$

$

—

     Floor (long put)

$

$

—

Call option contracts (short position)

  Total volume (MBbls)

—

  Weighted average price per Bbl

     Call strike price

$

$

—

Swap contracts (Midland basis differential)

  Volume (MBbls)

  Weighted average price per Bbl

$

$

Collar contracts combined with short puts (WTI, three-way collars)

  Total volume (MBbls)

—

  Weighted average price per Bbl

     Ceiling (short call option)

$

—

$

     Floor (long put option)

$

—

$

     Short put option

$

—

$





For the Remainder of

For the Full Year of

Natural gas contracts

2017

2018

Collar contracts combined with short puts (Henry Hub, three-way collars)

  Total volume (BBtu)

—

  Weighted average price per MMBtu

     Ceiling (short call option)

$

$

—

     Floor (long put option)

$

$

—

     Short put option

$

$

—

Collar contracts (Henry Hub, two-way collars)

  Total volume (BBtu)

  Weighted average price per MMBtu

     Ceiling (short call option)

$

$

     Floor (long put option)

$

$

Swap contracts

  Total volume (BBtu)

—

  Weighted average price per MMBtu

$

$

—





Three Months Ended



March 31, 2017

December 31, 2016

March 31, 2016

Income (loss) available to common stockholders

$

$

$

  Change in valuation allowance

  Write-down of oil and natural gas properties

—

—

  Net (gain) loss on derivatives, net of settlements

  Change in the fair value of share-based awards

  Withdrawn proxy contest expenses

—

—

  Loss on early extinguishment of debt

—

—

Adjusted Income

$

$

$

Adjusted Income per fully diluted common share

$

$

$





Three Months Ended



March 31, 2017

December 31, 2016

March 31, 2016

Net income (loss)

$

$

$

  Write-down of oil and natural gas properties

—

—

  Net (gain) loss on derivatives, net of settlements

  Non-cash stock-based compensation expense

  Loss on early extinguishment of debt

—

—

  Withdrawn proxy contest expenses

—

—

  Acquisition expense

  Income tax (benefit) expense

—

  Interest expense

  Depreciation, depletion and amortization

  Accretion expense

Adjusted EBITDA

$

$

$





Three Months Ended



March 31, 2017

December 31, 2016

March 31, 2016

Cash flows from operating activities:

Net income (loss)

$

$

$

Adjustments to reconcile net income (loss) to cash provided by operating activities:

  Depreciation, depletion and amortization

  Write-down of oil and natural gas properties

—

—

  Accretion expense

  Amortization of non-cash debt related items

  Deferred income tax expense

—

  Net (gain) loss on derivatives, net of settlements

  Loss on early extinguishment of debt

—

—

  Non-cash expense related to equity share-based awards

  Change in the fair value of liability share-based awards

Discretionary cash flow

$

$

$



  Changes in working capital

  Payments to settle asset retirement obligations

  Payments to settle vested liability share-based awards

—

Net cash provided by operating activities

$

$

$



March 31, 2017

December 31, 2016

ASSETS

Unaudited

Current assets:

Cash and cash equivalents

$

$

Accounts receivable

Fair value of derivatives

Other current assets

Total current assets

Oil and natural gas properties, full cost accounting method:

  Evaluated properties

  Less accumulated depreciation, depletion, amortization and impairment

  Net evaluated oil and natural gas properties

  Unevaluated properties

Total oil and natural gas properties

Other property and equipment, net

Restricted investments

Deferred financing costs related to the senior secured revolving credit facility

Fair value of derivatives

—

Acquisition deposit

—

Other assets, net

Total assets

$

$

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable and accrued liabilities

$

$

Accrued interest

Cash-settleable restricted stock unit awards

Asset retirement obligations

Fair value of derivatives

Total current liabilities

Senior secured revolving credit facility

—

—

6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs

Asset retirement obligations

Cash-settleable restricted stock unit awards

Deferred tax liability

Fair value of derivatives

—

Other long-term liabilities

Total liabilities

Commitments and contingencies

Stockholders’ equity:

Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 and 1,458,948 shares outstanding, respectively

Common stock, $0.01 par value, 300,000,000 and 300,000,000 shares authorized; 201,054,884 and 201,041,320 shares outstanding, respectively

Capital in excess of par value

Accumulated deficit

Total stockholders’ equity

Total liabilities and stockholders’ equity

$

$



Three Months Ended March 31,

2017

2016

Operating revenues:

  Oil sales

$

$

  Natural gas sales

Total operating revenues

Operating expenses:

  Lease operating expenses

  Production taxes

  Depreciation, depletion and amortization

  General and administrative

  Accretion expense

  Write-down of oil and natural gas properties

—

  Acquisition expense

Total operating expenses

  Income (loss) from operations

Other (income) expenses:

  Interest expense, net of capitalized amounts

  (Gain) loss on derivative contracts

  Other income

Total other (income) expense

  Income (loss) before income taxes

     Income tax expense

—

     Net income (loss)

     Preferred stock dividends

 Income (loss) available to common stockholders

$

$

 Income (loss) per common share:

  Basic

$

$

  Diluted

$

$

  Shares used in computing income (loss) per common share:

  Basic

  Diluted



Three Months Ended March 31,

2017

2016

Cash flows from operating activities:

Net income (loss)

$

$

Adjustments to reconcile net income to cash provided by operating activities:

  Depreciation, depletion and amortization

  Write-down of oil and natural gas properties

—

  Accretion expense

  Amortization of non-cash debt related items

  Deferred income tax expense

—

  Net (gain) loss on derivatives, net of settlements

  Non-cash expense related to equity share-based awards

  Change in the fair value of liability share-based awards

  Payments to settle asset retirement obligations

  Changes in current assets and liabilities:

     Accounts receivable

     Other current assets

     Current liabilities

     Change in other long-term liabilities

—

     Change in other assets, net

  Payments to settle vested liability share-based awards

     Net cash provided by operating activities

Cash flows from investing activities:

Capital expenditures

Acquisitions

Acquisition deposit

—

    Net cash used in investing activities

Cash flows from financing activities:

Borrowings on senior secured revolving credit facility

—

Payments on senior secured revolving credit facility

—

Issuance of common stock

—

Payment of preferred stock dividends

Tax withholdings related to restricted stock units

     Net cash provided by (used in) financing activities

Net change in cash and cash equivalents

  Balance, beginning of period

  Balance, end of period

$

$

·

Callon believes that the non-GAAP measure of discretionary cash flow is useful as an indicator of an oil and natural gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The Company also has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Discretionary cash flow and discretionary cash flow per diluted share are calculated using net income (loss) adjusted for certain items including depreciation, depletion and amortization, the impact of financial derivatives (including the mark-to-market effects, net of cash settlements and premiums paid or received related to our financial derivatives), remaining asset retirement obligations related to our divested offshore properties, restructuring and other non-recurring costs, deferred income taxes and other non-cash income items.

·

Callon believes 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 above 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 above were computed in accordance with GAAP.

·

We calculate Adjusted Earnings before Interest, Income Taxes, Depreciation, Depletion and Amortization (“Adjusted EBITDA”) as Adjusted Income plus interest expense, income tax expense (benefit) and depreciation, depletion and amortization expense. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, we believe that Adjusted EBITDA provides additional information with respect to our performance or ability to meet its future debt service, capital expenditures and working capital requirements. Because Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the Adjusted EBITDA we present may not be comparable to similarly titled measures of other companies.

·

We believe that the non-GAAP measure of Adjusted Total Revenues is useful to investors because it provides readers with a revenue value more comparable to other companies who account for derivative contracts and hedges and include their effects in revenue. We believe Adjusted Total Revenue is also useful to investors as a measure of the actual cash inflows generated during the period.