CPE
$10.86
Callon Petroleum
($.03)
(.28%)
Earnings Details
1st Quarter March 2018
Wednesday, May 02, 2018 4:15:00 PM
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Summary

Callon Petroleum Reports In-line

Callon Petroleum (CPE) reported 1st Quarter March 2018 earnings of $0.20 per share on revenue of $127.4 million. The consensus earnings estimate was $0.19 per share on revenue of $122.4 million. The Earnings Whisper number was $0.20 per share. Revenue grew 56.6% on a year-over-year basis.

Callon Petroleum Co is engaged in the exploration, development, acquisition and production of oil and natural gas properties.

Results
Reported Earnings
$0.20
Earnings Whisper
$0.20
Consensus Estimate
$0.19
Reported Revenue
$127.4 Mil
Revenue Estimate
$122.4 Mil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

Callon Petroleum Company Announces First Quarter 2018 Results

NATCHEZ, Miss., May 2, 2018 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months ended March 31, 2018.

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.

Financial and operational highlights for the first quarter of 2018 and other recent data points include:

  • Increased production to 26.6 MBoepd (77% oil), an increase of 30% year-over-year
  • Reduced lease operating expense by 18% year-over-year to $5.45 per BOE
  • Generated a first quarter operating margin of $44.31 per BOE, an increase of 30% year-over-year
  • Successful early results from Wolfcamp A down-spacing test in Howard County with 10-well spacing exceeding the performance of offsetting eight-well spacing pads
  • Initial production rates from the first two-well pad targeting the upper and lower Wolfcamp A intervals in Ward County have reached approximately 1,700 Boepd (85% oil) to date from each of the wells within the first 20 days of production
  • Improved drilling efficiency in the Delaware Basin has resulted in a greater than 25% increase in footage per day through the first six operated wells

Joe Gatto, President and Chief Executive Officer, commented, "We are pleased to deliver another solid quarter of execution while positioning ourselves for an increased level of baseline activity. During the first quarter, we added a fifth horizontal drilling rig and made substantial progress completing our Delaware Basin infrastructure initiatives to support the next phase of program development on our Permian footprint. Similar to our proactive past investments in the Midland Basin, our established facilities and takeaway investments in the Spur area will help preserve our leading cash margins for the long-term." He continued, "The first quarter also produced drilling and completion efficiency gains that were ahead of expectations. Combined with strong well productivity across the portfolio and a low-cost operating structure, the stage is set for robust production growth and cash flow generation in the coming quarters."

Operations Update

At March 31, 2018, we had 247 gross (184.5 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended March 31, 2018 grew approximately 30% to 26.6 thousand barrels of oil equivalent per day (77% oil) as compared to the same period of 2017.

For the three months ended March 31, 2018, we drilled 16 gross (13.2 net) horizontal wells in the Spur, WildHorse, and Monarch areas. We placed a combined 15 gross (9.0 net) horizontal wells on production in the quarter.

Midland Basin

During the first quarter, nearly all wells placed on production were located in the Midland Basin, with the majority of this activity split between our Ranger area in Reagan County and our Monarch area in Midland County. Wells placed on production in Reagan County averaged approximately 7,300 feet of completed lateral.  At Monarch, new wells averaged just under 6,000 feet.  During the last week of the quarter, two wells were placed on production in Howard County.

Our initial Wolfcamp A down-spacing test in the Fairway area of WildHorse has yielded encouraging results through the first 120 days of production. Compared to offset two-well pads completed with a similar design, the test wells, the Open A2 #1AH and Open A3 #3AH, have both eclipsed the cumulative oil production of each of the four offset wells. The Company will continue monitoring production from the test wells over the next few months prior to initiating any additional testing of reduced spacing at WildHorse.

Delaware Basin

Our first two-well pad in the Spur area targeting two flow units in the Wolfcamp A was completed and placed on production in April. Each of the wells, the Rendezvous A1 #01LA and A2 #09UA, has achieved a production rate of approximately 1,700 Boepd (85% oil) per well during the first 20 days of production and continue to be optimized.

Callon continues to progress efficiency gains as our activity levels increase in the Delaware Basin. Through our first six operated wells, the Company has continued to improve drilling day cycle times, with our most recent well reflecting an improvement of greater than 25% in daily footage compared to our first well drilled in Spur. Additionally, we have been proactive in our infrastructure build-out to support long-term development efficiency and sustained cash margins, similar to our past efforts in the Midland Basin. We have recently progressed or completed a number of infrastructure projects including: multiple saltwater disposal upgrades, installation of water transfer lines, installation of recycling facilities, build-out of two separate one million barrel recycle pits and installation of numerous tank batteries to accommodate future drilling activity. Additionally, we expect to have new tank batteries tied into Medallion pipeline during the second quarter, increasing our longer-term take-away capacities and providing additional delivery point optionality under our current gathering agreement.

Capital Expenditures

For the three months ended March 31, 2018, we incurred $105.3 million in cash operational capital expenditures (including other items) compared to $128.7 million in the fourth quarter of 2017. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):



Three Months Ended March 31, 2018



Operational


Capitalized


Capitalized


Total Capital



Capital (a)


Interest


G&A


Expenditures

Cash basis (b)


$

105,330



$

813



$

5,187



$

111,330


Timing adjustments (c)


11,472



9,255





20,727


Non-cash items






1,110



1,110


   Accrual (GAAP) basis


$

116,802



$

10,068



$

6,297



$

133,167




(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.

Operating and Financial Results

The following table presents summary information for the periods indicated:



Three Months Ended



March 31, 2018


December 31, 2017


March 31, 2017

Net production







Oil (MBbls)


1,851



1,936



1,434


Natural gas (MMcf)


3,240



3,018



2,422


   Total (MBOE)


2,391



2,439



1,838


Average daily production (BOE/d)


26,567



26,511



20,422


   % oil (BOE basis)


77%



79%



78%


Oil and natural gas revenues (in thousands)







   Oil revenue


$

115,286



$

104,132



$

72,008


   Natural gas revenue (a)


12,154



14,081



9,355


      Total revenue


127,440



118,213



81,363


   Impact of cash-settled derivatives


(8,459)



(4,501)



(2,491)


      Adjusted Total Revenue (i)


$

118,981



$

113,712



$

78,872


Average realized sales price
(excluding impact of cash settled derivatives)







   Oil (Bbl)


$

62.28



$

53.79



$

50.21


   Natural gas (Mcf)


3.75



4.67



3.86


   Total (BOE)


53.30



48.47



44.27


Average realized sales price
(including impact of cash settled derivatives)







   Oil (Bbl)


$

57.47



$

51.28



$

48.45


   Natural gas (Mcf)


3.89



4.78



3.88


   Total (BOE)


49.76



46.62



42.91


Additional per BOE data







   Sales price (b)


$

53.30



$

48.47



$

44.27


      Lease operating expense (c)


5.45



4.84



6.61


      Gathering and treating expense (a)




0.57



0.43


      Production taxes


3.54



2.55



3.21


   Operating margin


$

44.31



$

40.51



$

34.02









   Depletion, depreciation and amortization


$

14.81



$

14.98



$

13.29


   Adjusted G&A (d)







      Cash component (e)


$

2.74



$

2.46



$

2.43


      Non-cash component


0.51



0.54



0.57




(a)

On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the three months ended March 31, 2018 were accounted for as a reduction to revenue.

(b)

Excludes the impact of cash-settled derivatives.

(c)

Excludes gathering and treating expense.

(d)

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.

(e)

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

Total Revenue. For the quarter ended March 31, 2018, Callon reported total revenue of $127.4 million and total revenue including cash-settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure(i)) of $118.9 million, including the impact of an $8.5 million loss from the settlement of derivative contracts. The table above reconciles Adjusted Total Revenue to the related GAAP measure of the Company's revenue. Average daily production for the quarter was 26.6 MBOE/d compared to average daily production of 26.5 MBOE/d in the fourth quarter of 2017. Average realized prices, including and excluding the effects of hedging, are detailed above.

Hedging impacts. For the quarter ended March 31, 2018, Callon recognized the following hedging-related items (in thousands, except per unit data):



In Thousands


Per Unit

Oil derivatives





Net loss on settlements


$

(8,916)



$

(4.81)


Net gain on fair value adjustments


4,067




   Total loss on oil derivatives


$

(4,849)




Natural gas derivatives





Net gain on settlements


$

457



$

0.14


Net loss on fair value adjustments


(89)




   Total gain on natural gas derivatives


$

368




Total oil & natural gas derivatives





Net loss on settlements


$

(8,459)



$

(3.54)


Net gain on fair value adjustments


3,978




   Total loss on total oil & natural gas derivatives


$

(4,481)




Lease Operating Expenses, including workover ("LOE"). LOE per BOE for the three months ended March 31, 2018 was $5.45 per BOE, compared to LOE of $4.84 per BOE in the fourth quarter of 2017. The increase in this metric was primarily related to interim water hauling in Reagan County and certain equipment rental expenses.

Production Taxes, including ad valorem taxes. Production taxes were $3.54 per BOE for the three months ended March 31, 2018, representing approximately 6.6% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended March 31, 2018 was $14.81 per BOE compared to $14.98 per BOE in the fourth quarter of 2017. The decrease is attributable to our increased estimated proved reserves relative to our depreciable base and assumed future development costs related to undeveloped proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions.

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 $7.8 million, or $3.25 per BOE, for the three months ended March 31, 2018 compared to $7.3 million, or $3.00 per BOE, for the fourth quarter of 2017. The cash component of Adjusted G&A was $6.5 million, or $2.74 per BOE, for the three months ended March 31, 2018 compared to $6.0 million, or $2.46 per BOE, for the fourth quarter of 2017.

For the three months ended March 31, 2018, 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, 2018

Total G&A expense

$

8,769


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

(991)


Adjusted G&A – total

7,778


   Less: Restricted stock share-based compensation (non-cash)

(1,105)


   Less: Corporate depreciation & amortization (non-cash)

(124)


Adjusted G&A – cash component

$

6,549


Income tax expense. Callon provides for income taxes at a statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls and shortfalls, and state income taxes. We recorded an income tax expense of $0.5 million for the three months ended March 31, 2018 which relates to deferred State of Texas gross margin tax. At March 31, 2018 we had a valuation allowance of $49.2 million. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income (loss) available to common stockholders to reflect our theoretical tax provision of $11.8 million (or $0.06 per diluted share) for the quarter as if the valuation allowance did not exist.

2018 Guidance Update

The Company adopted the Revenue from Contracts with Customers accounting standard on January 1, 2018. Starting with the first quarter of 2018, certain natural gas gathering and treating expenses were accounted for as a reduction to revenue.



First Quarter


Full Year



2018 Actual


2018 Guidance

Total production (MBOE/d)


26.6


29.5 - 32.0

% oil


77%


77%

Income statement expenses (per BOE)





LOE, including workovers


$5.45


$5.25 - $6.25

Production taxes, including ad valorem (% unhedged revenue)


7%


6%

   Adjusted G&A: cash component (a)


$2.74


$1.75 - $2.50

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


$0.51


$0.50 - $1.00

   Interest expense (c)


$0.00


$0.00

Effective income tax rate


22%


22%

Capital expenditures ($MM, accrual basis)





Operational (d)


$117


$500 - $540

Capitalized expenses


$16


$60 - $70

Net operated horizontal wells placed on production


9


43 - 46



(a)

Excludes stock-based compensation and corporate depreciation and amortization.

(b)

Excludes certain non-recurring expenses and non-cash valuation adjustments.

(c)

All interest expense anticipated to be capitalized.

(d)

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

Hedge Portfolio Summary

The following tables summarize our open derivative positions for the periods indicated:


For the Remainder of


For the Full Year of

Oil contracts (WTI)

2018


2019

Swap contracts




Total volume (MBbls)

1,559




Weighted average price per Bbl

$

51.88



$


Collar contracts (two-way collars)




Total volume (MBbls)

275




Weighted average price per Bbl




Ceiling (short call)

$

60.50



$


Floor (long put)

50.00




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




Total volume (MBbls)

2,612



3,469


Weighted average price per Bbl




  Ceiling (short call option)

$

60.86



$

63.71


  Floor (long put option)

48.95



53.95


  Short put option

39.21



43.95











For the Remainder of


For the Full Year of

Oil contracts (Midland basis differential)

2018


2019

Swap contracts




  Volume (MBbls)

3,895





  Weighted average price per Bbl

$

(0.86)



$



















For the Remainder of


For the Full Year of

Natural gas contracts (Henry Hub)

2018


2019

Swap contracts




  Total volume (BBtu)

4,125





  Weighted average price per MMBtu

$

2.91



$










Income Available to Common Shareholders. The Company reported net income available to common shareholders of $53.9 million for the three months ended March 31, 2018 and Adjusted Income available to common shareholders of $39.8 million, or $0.20 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 the quarter 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 (in thousands):



Three Months Ended



March 31, 2018


December 31, 2017


March 31, 2017

Income available to common stockholders


$

53,937



$

21,001



$

45,305


   Change in valuation allowance


(11,753)



(8,285)



(13,119)


   Net (gain) loss on derivatives, net of settlements


(3,143)



16,924



(11,566)


   Change in the fair value of share-based awards


799



562



(189)


Adjusted Income


$

39,840



$

30,202



$

20,431


Adjusted Income per fully diluted common share


$

0.20



$

0.15



$

0.10


 



Three Months Ended



March 31, 2018


December 31, 2017


March 31, 2017

Net income


$

55,761



$

22,824



$

47,129


   Net gain on derivatives, net of settlements


(3,978)



26,037



(17,794)


   Non-cash stock-based compensation expense


2,143



2,101



639


   Acquisition expense


548



(112)



450


   Income tax expense


495



248



466


   Interest expense


460



461



665


   Depreciation, depletion and amortization


36,066



37,222



24,932


   Accretion expense


218



154



184


Adjusted EBITDA


$

91,713



$

88,935



$

56,671


Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the three months ended March 31, 2018 was $91.2 million and is reconciled to operating cash flow in the following table (in thousands):


Three Months Ended


March 31, 2018


December 31, 2017


March 31, 2017

Cash flows from operating activities:






Net income

$

55,761



$

22,824



$

47,129


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






   Depreciation, depletion and amortization

36,066



37,222



24,932


   Accretion expense

218



154



184


   Amortization of non-cash debt related items

453



455



665


   Deferred income tax expense

495



247



466


   Net (gain) loss on derivatives, net of settlements

(3,978)



26,037



(17,794)


   Non-cash expense related to equity share-based awards

1,131



1,240



930


   Change in the fair value of liability share-based awards

1,012



865



(291)


Discretionary cash flow

$

91,158



$

89,044



$

56,221


   Changes in working capital

4,512



(8,642)




5,890


   Payments to settle asset retirement obligations

(366)



(216)



(765)


   Payments to settle vested liability share-based awards

(3,089)





(8,662)


Net cash provided by operating activities

$

92,215



$

80,186



$

52,684


 

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and per share values and share data)




March 31, 2018


December 31, 2017

ASSETS


Unaudited



Current assets:





Cash and cash equivalents


$

18,473



$

27,995


Accounts receivable


122,411



114,320


Fair value of derivatives


4,210



406


Other current assets


2,078



2,139


Total current assets


147,172



144,860


Oil and natural gas properties, full cost accounting method:





Evaluated properties


3,598,868



3,429,570


Less accumulated depreciation, depletion, amortization and impairment


(2,119,599)



(2,084,095)


Net evaluated oil and natural gas properties


1,479,269



1,345,475


Unevaluated properties


1,174,385



1,168,016


Total oil and natural gas properties


2,653,654



2,513,491


Other property and equipment, net


21,173



20,361


Restricted investments


3,382



3,372


Deferred tax asset


26



52


Deferred financing costs


4,588



4,863


Acquisition deposit




900


Other assets, net


5,524



5,397


Total assets


$

2,835,519



$

2,693,296


LIABILITIES AND STOCKHOLDERS' EQUITY





Current liabilities:





Accounts payable and accrued liabilities


$

187,267



$

162,878


Accrued interest


18,491



9,235


Cash-settleable restricted stock unit awards


4,081



4,621


Asset retirement obligations


2,784



1,295


Fair value of derivatives


25,912



27,744


Total current liabilities


238,535



205,773


Senior secured revolving credit facility


75,000



25,000


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


595,374



595,196


Asset retirement obligations


7,717



4,725


Cash-settleable restricted stock unit awards


2,392



3,490


Deferred tax liability


1,950



1,457


Fair value of derivatives


2,942



1,284


Other long-term liabilities


465



405


Total liabilities


924,375



837,330


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; 201,947,883 and 201,836,172 shares outstanding, respectively


2,019



2,018


Capital in excess of par value


2,182,599



2,181,359


Accumulated deficit


(273,489)



(327,426)


Total stockholders' equity


1,911,144



1,855,966


Total liabilities and stockholders' equity


$

2,835,519



$

2,693,296


 

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)







Three Months Ended March 31,



2018


2017

Operating revenues:





Oil sales


$

115,286



$

72,008


Natural gas sales


12,154



9,355


Total operating revenues


127,440



81,363


Operating expenses:





Lease operating expenses


13,039



12,937


Production taxes


8,463



5,904


Depreciation, depletion and amortization


35,417



24,433


General and administrative


8,769



5,206


Accretion expense


218



184


Acquisition expense


548



450


Total operating expenses


66,454



49,114


Income from operations


60,986



32,249


Other (income) expenses:





Interest expense, net of capitalized amounts


460



665


(Gain) loss on derivative contracts


4,481



(15,303)


Other income


(211)



(708)


Total other (income) expense


4,730



(15,346)


Income before income taxes


56,256



47,595


Income tax expense


495



466


Net income


55,761



47,129


Preferred stock dividends


(1,824)



(1,824)


Income available to common stockholders


$

53,937



$

45,305


Income per common share:





Basic


$

0.27



$

0.23


Diluted


$

0.27



$

0.22


Shares used in computing income per common share:







Basic


201,921



201,054


Diluted


202,588



201,740


 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)







Three Months Ended March 31,



2018


2017

Cash flows from operating activities:





Net income


$

55,761



$

47,129


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





Depreciation, depletion and amortization


36,066



24,932


Accretion expense


218



184


Amortization of non-cash debt related items


453



665


Deferred income tax expense


495



466


Net gain on derivatives, net of settlements


(3,978)



(17,794)


Non-cash expense related to equity share-based awards


1,131



930


Change in the fair value of liability share-based awards


1,012



(291)


Payments to settle asset retirement obligations


(366)



(765)


Changes in current assets and liabilities:





Accounts receivable


(8,067)



(4,066)


Other current assets


61



576


Current liabilities


12,938



9,903


Other long-term liabilities


87




Other assets, net


(507)



(523)


Payments to settle vested liability share-based awards


(3,089)



(8,662)


Net cash provided by operating activities


92,215



52,684


Cash flows from investing activities:





Capital expenditures


(111,330)



(66,154)


Acquisitions


(38,923)



(648,485)


Acquisition deposit


900



46,138


Net cash used in investing activities


(149,353)



(668,501)


Cash flows from financing activities:





Borrowings on senior secured revolving credit facility


80,000




Payments on senior secured revolving credit facility


(30,000)




Payment of preferred stock dividends


(1,824)



(1,824)


Tax withholdings related to restricted stock units


(560)



(79)


Net cash provided by (used in) financing activities


47,616



(1,903)


Net change in cash and cash equivalents


(9,522)



(617,720)


Balance, beginning of period


27,995



652,993


Balance, end of period


$

18,473



$

35,273


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 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 is 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), accretion expense, 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 above. 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 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 we present may not be comparable to similarly titled measures of other companies.
  • We believe 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 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.

Earnings Call Information

The Company will host a conference call on Thursday, May 3, 2018, to discuss first quarter 2018 financial and operating results.

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

Date/Time:

Thursday, May 3, 2018, 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:

4895442

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

About Callon Petroleum

Callon Petroleum Company is an independent energy company focused on the acquisition, development, exploration, and operation of oil and natural gas properties 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; the Company's 2018 guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; and the implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," "plans" and words of similar meaning. These statements reflect the Company's current views with respect to future events and financial performance. 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. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices, ability to drill and complete wells, operational, regulatory and environment risks, our ability to finance our activities and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on our website or the SEC's website at www.sec.gov.

Contact Information

Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
1-281-589-5279

 

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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