Callon Petroleum Company Announces First Quarter 2019 Results

HOUSTON, May 6, 2019 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months ended March 31, 2019.

Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located on the "Presentations" page within the Investors section of the site.

Highlights

  • Increased production to 40.3 Mboe/d (79% oil), an increase of 52% year-over-year
  • Generated an operating margin of $32.57 per Boe
  • Recently completed a five-well pad in the southern portion of WildHorse, developing an entire half section in the Wolfcamp A
  • Initial 2nd Bone Spring shale well placed on production in the Delaware and showing positive early performance
  • Continued strong production from a Middle Spraberry well drilled at Monarch as part of multi-well, co-development of three flow units
  • Improved completion efficiency, measured in stages per day, by more than 25% compared to the same period in 2018
  • Reduced average drilling and completion costs by 15% sequentially, resulting in an average cost per lateral foot below $1,000
  • Announced the pending sale of certain non-core assets in the southern Midland Basin for estimated gross proceeds of $260 million, with potential contingency payments of up to $60 million based upon average annual commodity prices over a three-year period
  • Reaffirmed a borrowing base of $1.1 billion, pro forma for the pending non-core asset sale

"We are ahead of our plan to build out an inventory of drilled, uncompleted wells to extend our usage of a larger pad development model, applying this concept to the Delaware Basin as we continue to build upon our success in the Midland Basin. Capitalizing on the efficiencies of larger development, we delivered a sequential decrease in average drilling and completion cost per lateral foot of 15% in the first quarter. Our drilling plan is quickly progressing to the point where we will decrease to four drilling rigs and start larger Delaware Basin pad completions towards the end of the second quarter." commented Joe Gatto, President and Chief Executive Officer. He continued, "The previously announced sale of our Ranger properties will streamline our operations with a focus on three core operating areas with well-established infrastructure. Since we did not have any planned Ranger activity in 2019, the divestiture will not impact our base 2019 activity levels, but will allow us to optimize our 2020 capital allocation with the removal of Ranger drilling obligations. Upon closing, all cash proceeds will be directed to bolstering our financial position. We remain focused on executing our 2019 plan within our previously announced budget range, with the benefit of incremental cash flow from commodity realizations above our planning case flowing to the bottom line and the benefit our shareholders."

Operations Update

At March 31, 2019, we had 524 gross (395.4 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended March 31, 2019 grew 52% to 40.3 Mboe/d (79% oil) as compared to the same period of 2018.

For the three months ended March 31, 2019, we drilled 21 gross (16.4 net) horizontal wells, and placed a combined 13 gross (11.2 net) horizontal wells on production. Wells placed on production during the quarter were completed in the Lower Spraberry, Middle Spraberry, Wolfcamp A and Wolfcamp B within the Midland Basin and the Lower Wolfcamp A within the Delaware Basin.

Midland Basin

We brought 11 gross (9.2 net) wells on production in the Midland Basin during the first quarter with the majority of activity coming from our Monarch area. Our Middle Spraberry well, the Kendra Amanda PSA 33 MS, an 8,000 foot lateral, which was completed as part of a multi-well pad project, has achieved a 30-day average production rate of approximately 110 Boe per thousand lateral feet (90% oil) and continues to perform well.

Near the end of the quarter, in the WildHorse area in Howard County, we began flowback on a five-well pad that employed half section development in the Wolfcamp A. While not all wells have reached 30 days of production, the combined five-well average for current accumulated production includes an average peak rate of over 1,500 Boe per day (92% oil) or approximately 175 Boe per thousand lateral feet.

The previously disclosed outage at a third party gas processing facility in Martin County has been resolved and we currently do not forecast any impact to second quarter production.

Delaware Basin

At our Spur area in Ward County, we placed on production the Wally World A1 01LA and A2 02LA, both Lower Wolfcamp A wells, which together have achieved cumulative production of over 100,000 Boe (84% oil) during their first 30 days of production. Recently, a two-well pad featuring 2nd Bone Spring shale and Lower Wolfcamp A co-development at Spur, was completed and placed on production. Both wells have performed as expected during their limited time on production and we will continue to monitor and compare to third party offsets in the area.

The field optimization project that was initiated during the first quarter of 2019 is progressing and is expected to be completed near the end of the second quarter.  We currently expect deferred production related to wells shut in for repairs to average 1,600 Boe per day (79% oil) for the second quarter.

Capital Expenditures

For the three months ended March 31, 2019, we incurred $155.2 million in operational capital expenditures (including other items) on an accrual basis as compared to $141.2 million in the fourth quarter of 2018. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):



Three Months Ended March 31, 2019



Operational


Capitalized


Capitalized


Total Capital



Capital (a)


Interest


G&A


Expenditures

Cash basis (b)


$

164,277



$

18,589



$

10,345



$

193,211


Timing adjustments (c)


(9,109)



1,255





(7,854)


Non-cash items






354



354


   Accrual basis


$

155,168



$

19,844



$

10,699



$

185,711




(a)

Includes seismic, land and other items.

(b) 

Cash basis is presented here to help users of financial information reconcile amounts from the cash flow statement to the balance sheet by accounting for timing related changes in working capital that align with 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.

Operating and Financial Results

The following table presents summary information for the periods indicated:



Three Months Ended



March 31, 2019


December 31, 2018


March 31, 2018

Net production







Oil (MBbls)


2,858



3,076



1,851


Natural gas (MMcf)


4,619



4,225



3,240


   Total (Mboe)


3,628



3,780



2,391


Average daily production (Boe/d)


40,311



41,087



26,567


   % oil (Boe basis)


79

%


81

%


77

%

Oil and natural gas revenues (in thousands)







   Oil revenue


$

141,098



$

150,398



$

115,286


   Natural gas revenue


11,949



11,497



12,154


      Total revenue


153,047



161,895



127,440


   Impact of settled derivatives


(290)



(1,594)



(8,459)


      Adjusted Total Revenue (i)


$

152,757



$

160,301



$

118,981


Average realized sales price
(excluding impact of settled derivatives)







   Oil (per Bbl)


$

49.37



$

48.89



$

62.28


   Natural gas (per Mcf)


2.59



2.72



3.75


   Total (per BOE)


42.18



42.83



53.30


Average realized sales price
(including impact of settled derivatives)







   Oil (per Bbl)


$

48.83



$

48.52



$

57.47


   Natural gas (per Mcf)


2.86



2.62



3.89


   Total (per BOE)


42.11



42.41



49.76


Additional per BOE data







   Sales price (a)


$

42.18



$

42.83



$

53.30


      Lease operating expense


6.63



6.47



5.45


      Production taxes


2.98



2.51



3.54


   Operating margin


$

32.57



$

33.85



$

44.31









   Depletion, depreciation and amortization


$

16.47



$

15.74



$

14.81


   Adjusted G&A (b)







      Cash component (c)


$

2.28



$

2.03



$

2.74


      Non-cash component


0.44



0.50



0.51




(a) 

Excludes the impact of settled derivatives.

(b) 

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

(c) 

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

Total Revenue. For the quarter ended March 31, 2019, Callon reported total revenue of $153.0 million and total revenue including settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure(i)) of $152.8 million, including the impact of a $0.3 million loss from the settlement of derivative contracts. The table above reconciles Adjusted Total Revenue to the related GAAP measure of the Company's total operating revenue. Average daily production for the quarter was 40.3 Mboe/d compared to average daily production of 41.1 Mboe/d in the fourth quarter of 2018. Average realized prices, including and excluding the effects of hedging, are detailed above.

Hedging impacts. For the quarter ended March 31, 2019, Callon recognized the following hedging-related items (in thousands, except per unit data):


Three Months Ended March 31, 2019


In Thousands


Per Unit

Oil derivatives




Net loss on settlements

$

(1,542)



$

(0.54)


Net loss on fair value adjustments

(66,826)




   Total loss on oil derivatives

$

(68,368)




Natural gas derivatives




Net gain on settlements

$

1,252



$

0.27


Net loss on fair value adjustments

(144)




   Total gain on natural gas derivatives

$

1,108




Total oil & natural gas derivatives




Net loss on settlements

$

(290)



$

(0.07)


Net loss on fair value adjustments

(66,970)




   Total loss on total oil & natural gas derivatives

$

(67,260)




Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended March 31, 2019 was $6.63 per Boe, compared to LOE of $6.47 per Boe in the fourth quarter of 2018. The increase on a per unit basis was primarily attributed to a 1.9% decrease in daily production.

Production Taxes, including ad valorem taxes. Production taxes were $2.98 per Boe for the three months ended March 31, 2019, representing approximately 7.1% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended March 31, 2019 was $16.47 per Boe compared to $15.74 per Boe in the fourth quarter of 2018. The increase on a per unit basis was primarily attributable to an increase in our depreciable asset base and assumed future development costs related to undeveloped proved reserves relative to our estimated proved reserves as a result of additions made through our horizontal drilling efforts.

General and Administrative ("G&A"). G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A", a non-GAAP measure(i)) was $9.9 million, or $2.72 per Boe, for the three months ended March 31, 2019 compared to $9.6 million, or $2.53 per Boe, for the fourth quarter of 2018. The cash component of Adjusted G&A was $8.3 million, or $2.28 per Boe, for the three months ended March 31, 2019 compared to $7.7 million, or $2.03 per Boe, for the fourth quarter of 2018.

For the three months ended March 31, 2019, G&A and Adjusted G&A, which excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization, are calculated as follows (in thousands):


Three Months Ended
March 31, 2019

Total G&A expense

$

11,753


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

(1,889)


Adjusted G&A – total

9,864


   Restricted stock share-based compensation (non-cash)

(1,500)


   Corporate depreciation & amortization (non-cash)

(88)


Adjusted G&A – cash component

$

8,276


Settled share-based awards. During the first quarter of 2019, the Company settled certain of the outstanding share-based award agreements of two former officers of the Company, resulting in the $3.0 million recorded on the consolidated statements of operations as settled share-based awards.

Income tax expense. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. We recorded an income tax benefit of $5.1 million for the three months ended March 31, 2019, compared to income tax expense of $5.6 million for the three months ended December 31, 2018. The change in income tax is primarily related to the change in our tax position in 2018, when the Company's tax position transitioned from a net deferred tax asset position to a net deferred tax liability position, thereby unwinding the valuation allowance balance to $0 as of December 31, 2018.

2019 Guidance

The Company is maintaining the current full year guidance until the announced sale of non-core assets closes, which is expected to occur during the second quarter. Upon closing, the Company will update applicable guidance categories, but does not expect any changes to the operational capital guidance for the year.



First Quarter


Full Year



2019 Actual


2019 Guidance

Total production (Mboe/d)


40.3


39.5 - 41.5

% oil


79%


77% - 78%

Income statement expenses (per Boe)





LOE, including workovers


$6.63


$5.50 - $6.50

Production taxes, including ad valorem (% unhedged revenue)


7%


7%

   Adjusted G&A: cash component (a)


$2.28


$2.00 - $2.50

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


$0.44


$0.50 - $1.00

   Cash interest expense (c)


$0.00


$0.00

Effective income tax rate


21%


22%

Capital expenditures ($MM, accrual basis)





Total operational (d)


$155


$500 - $525

Capitalized interest and G&A expenses


$31


$100 - $105

Net operated horizontal wells placed on production


11


47 - 49



(a) 

Excludes stock-based compensation and corporate depreciation and amortization. Adjusted G&A is a non-GAAP financial measure; 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 certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(c) 

All interest expense anticipated to be capitalized.

(d) 

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


Hedge Portfolio Summary

The following tables summarize our open derivative positions as of March 31, 2019 for the periods indicated:


For the Remainder


For the Full Year

Oil contracts (WTI)

of 2019


of 2020

Puts




   Total volume (Bbls)

687,500




   Weighted average price per Bbl

$

65.00



$


Put spreads




Total volume (Bbls)

687,500




Weighted average price per Bbl




Floor (long put)

$

65.00



$


Floor (short put)

$

42.50



$


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




Total volume (Bbls)

3,484,000



915,000


Weighted average price per Bbl




Ceiling (short call)

$

67.56



$

65.02


Floor (long put)

$

56.58



$

55.00


Floor (short put)

$

43.62



$

45.00


Collar contracts (two-way collars)




Total volume (Bbls)



732,000


Weighted average price per Bbl




Ceiling (short call)

$



$

64.63


Floor (long put)

$



$

55.00






Oil contracts (Midland basis differential)




Swap contracts




Total volume (Bbls)

5,102,000



4,576,000


Weighted average price per Bbl

$

(3.95)



$

(1.29)






Natural gas contracts (Henry Hub)




Collar contracts (two-way collars)




   Total volume (MMBtu)

2,697,500




   Weighted average price per MMBtu




      Ceiling (short call)

$

3.68



$


      Floor (long put)

$

3.09



$


Swap contracts




   Total volume (MMBtu)

1,852,000




   Weighted average price per MMBtu

$

2.88



$






Natural gas contracts (Waha basis differential)




Swap contracts




   Total volume (MMBtu)

5,961,000



4,758,000


   Weighted average price per MMBtu

$

(1.19)



$

(1.12)


Income (Loss) Available to Common Shareholders. The Company reported net loss available to common shareholders of $21.4 million for the three months ended March 31, 2019 and Adjusted Income available to common shareholders of $35.4 million, or $0.16 per fully diluted share. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income available to common stockholders to reflect our theoretical tax provision for prior period quarters as if the valuation allowance did not exist. The following tables reconcile to the related GAAP measure the Company's income available to common stockholders to Adjusted Income and the Company's net income to Adjusted EBITDA(i), a non-GAAP financial measure, (in thousands):


Three Months Ended


March 31, 2019


December 31, 2018


March 31, 2018

Income (loss) available to common stockholders

$

(21,367)



$

154,370



$

53,937


   (Gain) loss on derivatives, net of settlements

66,970



(105,512)



(3,978)


   Change in the fair value of share-based awards

1,881



(1,053)



1,012


   Settled share-based awards

3,024






Tax effect on adjustments above

(15,094)



22,379



622


Change in valuation allowance



(30,281)



(11,753)


Adjusted Income (i)

$

35,414



$

39,903



$

39,840


Adjusted Income per fully diluted common share (i)

$

0.16



$

0.17



$

0.20







Three Months Ended


March 31, 2019


December 31, 2018


March 31, 2018

Net income (loss)

$

(19,543)



$

156,194



$

55,761


   (Gain) loss on derivatives, net of settlements

66,970



(105,512)



(3,978)


   Non-cash stock-based compensation expense

3,402



770



2,143


   Settled share-based awards

3,024






   Acquisition expense

157



1,333



548


   Income tax (benefit) expense

(5,149)



5,647



495


   Interest expense

738



735



460


   Depreciation, depletion and amortization

60,672



60,301



36,066


   Accretion expense

241



248



218


Adjusted EBITDA (i)

$

110,512



$

119,716



$

91,713


Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the three months ended March 31, 2019 was $110.4 million and is reconciled to operating cash flow in the following table (in thousands):


Three Months Ended


March 31, 2019


December 31, 2018


March 31, 2018

Cash flows from operating activities:






Net income (loss)

$

(19,543)



$

156,194



$

55,761


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






   Depreciation, depletion and amortization

60,672



60,301



36,066


   Accretion expense

241



248



218


   Amortization of non-cash debt related items

738



734



453


   Deferred income tax (benefit) expense

(5,149)



5,647



495


   (Gain) loss on derivatives, net of settlements

66,970



(105,512)



(3,978)


   (Gain) loss on sale of other property and equipment

28



(64)




   Non-cash expense related to equity share-based awards

4,545



1,823



1,131


   Change in the fair value of liability share-based awards

1,881



(1,053)



1,012


Discretionary cash flow (i)

$

110,383



$

118,318



$

91,158


   Changes in working capital

(33,864)



33,710



4,512


   Payments to settle asset retirement obligations

(664)



(389)



(366)


   Payments to settle vested liability share-based awards

(1,296)





(3,089)


Net cash provided by operating activities

$

74,559



$

151,639



$

92,215


 

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and per share data)




March 31, 2019


December 31, 2018

ASSETS


Unaudited



Current assets:





   Cash and cash equivalents


$

10,482



$

16,051


   Accounts receivable


137,110



131,720


   Fair value of derivatives


11,372



65,114


   Other current assets


12,034



9,740


      Total current assets


170,998



222,625


Oil and natural gas properties, full cost accounting method:





   Evaluated properties


4,760,071



4,585,020


   Less accumulated depreciation, depletion, amortization and impairment


(2,333,589)



(2,270,675)


   Evaluated oil and natural gas properties, net


2,426,482



2,314,345


   Unevaluated properties


1,432,118



1,404,513


      Total oil and natural gas properties, net


3,858,600



3,718,858


Operating lease right-of-use assets


40,977




Other property and equipment, net


22,413



21,901


Restricted investments


3,450



3,424


Deferred financing costs


5,742



6,087


Fair value of derivatives


385




Other assets, net


6,269



6,278


   Total assets


$

4,108,834



$

3,979,173


LIABILITIES AND STOCKHOLDERS' EQUITY





Current liabilities:





   Accounts payable and accrued liabilities


$

230,990



$

261,184


   Operating lease liabilities


29,134




   Accrued interest


25,920



24,665


   Cash-settleable restricted stock unit awards


1,060



1,390


   Asset retirement obligations


3,771



3,887


   Fair value of derivatives


24,550



10,480


   Other current liabilities


8,512



13,310


      Total current liabilities


323,937



314,916


Senior secured revolving credit facility


330,000



200,000


6.125% senior unsecured notes due 2024


595,971



595,788


6.375% senior unsecured notes due 2026


393,896



393,685


Operating lease liabilities


11,751




Asset retirement obligations


10,189



10,405


Cash-settleable restricted stock unit awards


2,252



2,067


Deferred tax liability


4,415



9,564


Fair value of derivatives


6,983



7,440


Other long-term liabilities


995



100


   Total liabilities


1,680,389



1,533,965


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 shares outstanding


15



15


   Common stock, $0.01 par value, 300,000,000 shares authorized; 227,884,091 and 227,582,575 shares outstanding, respectively


2,279



2,276


   Capital in excess of par value


2,481,879



2,477,278


   Accumulated deficit


(55,728)



(34,361)


      Total stockholders' equity


2,428,445



2,445,208


Total liabilities and stockholders' equity


$

4,108,834



$

3,979,173


 

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)



Three Months Ended March 31,


2019


2018

Operating revenues:




Oil sales

$

141,098



$

115,286


Natural gas sales

11,949



12,154


Total operating revenues

153,047



127,440


Operating expenses:




Lease operating expenses

24,067



13,039


Production taxes

10,813



8,463


Depreciation, depletion and amortization

59,767



35,417


General and administrative

11,753



8,769


Settled share-based awards

3,024




Accretion expense

241



218


Acquisition expense

157



548


Total operating expenses

109,822



66,454


Income from operations

43,225



60,986


Other (income) expenses:




Interest expense, net of capitalized amounts

738



460


Loss on derivative contracts

67,260



4,481


Other income

(81)



(211)


Total other (income) expense

67,917



4,730


Income (loss) before income taxes

(24,692)



56,256


Income tax (benefit) expense

(5,149)



495


Net income (loss)

(19,543)



55,761


Preferred stock dividends

(1,824)



(1,824)


Income (loss) available to common stockholders

$

(21,367)



$

53,937


Income per common share:




Basic

$

(0.09)



$

0.27


Diluted

$

(0.09)



$

0.27


Weighted average common shares outstanding:




Basic

227,784



201,921


Diluted

227,784



202,588


 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)



Three Months Ended March 31,


2019


2018

Cash flows from operating activities:




Net income (loss)

$

(19,543)



$

55,761


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




   Depreciation, depletion and amortization

60,672



36,066


   Accretion expense

241



218


   Amortization of non-cash debt related items

738



453


   Deferred income tax (benefit) expense

(5,149)



495


   (Gain) loss on derivatives, net of settlements

66,970



(3,978)


   Loss on sale of other property and equipment

28




   Non-cash expense related to equity share-based awards

4,545



1,131


   Change in the fair value of liability share-based awards

1,881



1,012


   Payments to settle asset retirement obligations

(664)



(366)


   Payments for cash-settled restricted stock unit awards

(1,296)



(3,089)


Changes in current assets and liabilities:




   Accounts receivable

(5,390)



(8,067)


   Other current assets

(2,294)



61


   Current liabilities

(26,003)



12,938


   Other

(177)



(420)


Net cash provided by operating activities

74,559



92,215


Cash flows from investing activities:




Capital expenditures

(193,211)



(111,330)


Acquisitions

(27,947)



(38,923)


Acquisition deposit



900


Proceeds from sale of assets

13,879




Net cash used in investing activities

(207,279)



(149,353)


Cash flows from financing activities:




Borrowings on senior secured revolving credit facility

220,000



80,000


Payments on senior secured revolving credit facility

(90,000)



(30,000)


Payment of preferred stock dividends

(1,824)



(1,824)


Tax withholdings related to restricted stock units

(1,025)



(560)


Net cash provided by financing activities

127,151



47,616


Net change in cash and cash equivalents

(5,569)



(9,522)


Balance, beginning of period

16,051



27,995


Balance, end of period

10,482



18,473






Non-GAAP Financial Measures and Reconciliations

This news release refers to non-GAAP financial measures such as "Discretionary Cash Flow," "Adjusted G&A," "Adjusted Income," "Adjusted EBITDA" and "Adjusted Total Revenue." These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

  • Callon believes that the non-GAAP measure of discretionary cash flow is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company's ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and payments to settle asset retirement obligations and vested liability share-based awards. Callon 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 the cash flow effect may not be reflected the period in which the operating activities occurred. Discretionary cash flow is not a measure of a company's financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities (as defined under GAAP), or as a measure of liquidity, or as an alternative to net income.
  • 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, as well as non-cash corporate depreciation and amortization expense. 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 here within details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.
  • Callon believes 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 here within.
  • Callon calculates 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, the Company believes that Adjusted EBITDA provides additional information with respect to our performance or ability to meet our 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 presented may not be comparable to similarly titled measures of other companies.
  • Callon believes that the non-GAAP measure of Adjusted Total Revenue is useful to investors because it provides readers with a revenue value more comparable to other companies who engage in price risk management activities through the use of commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues.

Earnings Call Information

The Company will host a conference call on Tuesday, May 7, 2019, to discuss first quarter 2019 financial and operating results.

Please join Callon Petroleum Company via the Internet for a webcast of the conference call:

Date/Time:

Tuesday, May 7, 2019, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time)

Webcast:

Select "IR Calendar" under the "Investors" section of the website: www.callon.com.

Presentation Slides:

Select "Presentations" under the "Investors" section of the website: www.callon.com.

Alternatively, you may join by telephone using the following numbers:

Toll Free:

1-888-317-6003

Canada Toll Free:

1-866-284-3684

International:

1-412-317-6061

Access code:

3634060

An archive of the conference call webcast will be available at www.callon.com under the "Investors" section of the website.

About Callon Petroleum Company

Callon Petroleum Company is an independent energy company focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin in West Texas.

This news release is posted on the Company's website at www.callon.com and will be archived there for subsequent review under the "News" link on the top of the homepage.

Cautionary Statement Regarding Forward Looking Statements

This news release contains 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. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of drilling activity and associated production and cash flow expectations; Callon's 2019 production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; and the implementation of Callon's business plans and strategy, as well as statements including the words "believe," "expect," "plans," "may," "will," "should," "could," and words of similar meaning. These statements reflect Callon's current views with respect to future events and financial performance based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. 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. Any forward-looking statement speaks only as of the date on which such statement is made and Callon undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect Callon's future results and could cause results to differ materially from those expressed in Callon's forward-looking statements include the volatility of oil and natural gas prices, ability to drill and complete wells, operational, regulatory and environment risks, cost and availability of equipment and labor, Callon's ability to finance Callon's activities and other risks more fully discussed in Callon's filings with the Securities and Exchange Commission, including Callon's Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on Callon's website or the SEC's website at www.sec.gov.

Contact Information

Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
1-281-589-5200

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See "Non-GAAP Financial Measures and Reconciliations" included within this release for related disclosures and calculations  

 

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SOURCE Callon Petroleum Company