November 6, 2018 - 4:15 PM EST
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Callon Petroleum Company Announces Third Quarter 2018 Results

NATCHEZ, Miss., Nov. 6, 2018 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and nine months ended September 30, 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 third quarter of 2018 and other recent data points include:

  • Increased production to 34.9 MBOE/D (78% oil), an increase of 55% year-over-year
  • Generated an operating margin of $41.22 per BOE, an increase of 27% year-over-year
  • Recent multi-well pads at WildHorse outperforming early time type curve expectations by an average of 29%
  • Second "mega-pad" placed on production in October and tracking early time performance of first "mega-pad" that is outperforming offset three-well pads by approximately 30%
  • Extended preferred vendor agreement for completion services providing price certainty for the next five quarters
  • Initiated delivery of disposal volumes to Goodnight Midstream saltwater disposal system within the Spur operating area, complementing recently enhanced recycling and operated saltwater disposal network
  • Completed the previously announced acquisition of properties in the Delaware Basin

"Callon continued to drive strong operational execution in the third quarter as evidenced by sustained operating margins in excess of 80% for a fifth consecutive quarter. I am extremely pleased with our organization's ability to seamlessly integrate our recent bolt-on acquisition in the Delaware Basin while continuing to drive efficiencies across the entire Callon portfolio," commented Joe Gatto, President and Chief Executive Officer. He continued, "We have entered a phase of sustained growth and visibility with the maturing of our business model, characterized by increased efficiencies from larger scale developments, strategic partnerships with leading service providers and tactical development of multiple zones to preserve robust returns in our inventory for the long run. As stated previously, we expect to generate solid positive free cash flows at the field level in the fourth quarter of 2018 as we target corporate level free cash flow generation by the latter portion of 2019."

Operations Update

At September 30, 2018, we had 453 gross (348.2 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended September 30, 2018 grew 55% to 34.9 MBOE/D (78% oil) as compared to the same period of 2017.

For the three months ended September 30, 2018, we drilled 19 gross (15.2 net) horizontal wells and placed a combined 18 gross (13.8 net) horizontal wells on production targeting the Wolfcamp A, Wolfcamp B, and Lower Spraberry intervals.

Midland Basin

During the third quarter, just over 70% of the net wells placed on production were located in the Midland Basin, with all three of our primary areas contributing new production during the quarter. In our WildHorse area, the Wright and Gibson pads were placed on production in late-July and mid-August and have exceeded early time oil type curve expectations by roughly 20% and 38%, respectively.  At Monarch, our first "mega-pad", the Casselman 16 pad, oil production is outperforming offsetting, legacy pads by approximately 30%. We recently placed our second "mega-pad" on production in October, and these six wells produced at an average rate of 183 Boepd per 1,000 lateral feet during the first 22 days online.

Delaware Basin

In the Delaware Basin, wells which have reached peak production during the third quarter achieved an average peak IP30 of approximately 150 Boepd per 1,000 lateral feet with an average oil cut of 82%. Our upper and lower Wolfcamp A pair test at the Rendezvous pad continues to perform extremely well and has now eclipsed approximately 425,000 Boe (combined) through the first 200 days of production. Also during the quarter, the Effie Ponder 33-18 05H well, an upper Wolfcamp A well that landed approximately 100 feet below offsetting 3rd Bone Spring production, was completed by the previous operator and brought on production in the River Tract portion of our newly acquired acreage. The well has achieved an IP24 of 143 Boepd and IP30 of 103 Boepd per 1,000 lateral feet (respectively) with an average oil cut of 91%.

Regional Gas Plant Downtime

Beginning in late September, production from our WildHorse area was disrupted due to a plant outage at a third party gas processing facility in Martin County.  We expect the plant to return to full service by mid-December and have successfully managed to reroute a portion of our base gas and natural gas liquids volumes through other facilities in the interim. We forecast a net loss of approximately 7,500 to 9,000 Mcfepd on average for the 4th quarter due to this outage, but do not expect any impact to our oil volumes.

Infrastructure and Operational Efficiency

We have continued to realize significant benefits from infrastructure investments, most of which have recently been focused on our Spur footprint in the Delaware Basin. The new recycling facilities are online and we were able to recycle over 600,000 barrels of water for use in our frac operations in Ward County during the third quarter. Additionally, the new Goodnight Midstream water disposal system is now operational and has begun servicing our core Spur footprint.  In the Midland Basin, the company was able to utilize more than 900,000 barrels of recycled water for completion operations in the Monarch area during the quarter.  These ongoing initiatives are expected to reduce the future needs for water sourcing and disposal and will drive cost savings from both reduced capital and lease operating expenses.

As we have transitioned to larger pad development concepts, including our recent "mega-pads", our completion efficiency has improved through the broader application of simultaneous operations, which we expect will continue to increase in future periods. Additionally, the Company recently extended its preferred vendor agreement for completion services related to two dedicated crews that will provide price certainty for well completion costs through the 2019 calendar year.

Capital Expenditures

For the nine months ended September 30, 2018, we incurred $418.2 million in cash operational capital expenditures (including other items) including $149.5 million in the third quarter, which represented a $14.0 million decrease from the second quarter. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):



Three Months Ended September 30, 2018



Operational


Capitalized


Capitalized


Total Capital



Capital (a)


Interest


G&A


Expenditures

Cash basis (b)


$

149,454



$

560



$

6,968



$

156,982


Timing adjustments (c)


10,001



15,973





25,974


Non-cash items






1,776



1,776


   Accrual (GAAP) basis


$

159,455



$

16,533



$

8,744



$

184,732




(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



September 30, 2018


June 30, 2018


September 30, 2017

Net production







Oil (MBbls)


2,521



1,995



1,591


Natural gas (MMcf)


4,144



3,839



2,900


   Total (MBOE)


3,212



2,635



2,074


Average daily production (BOE/d)


34,913



28,954



22,543


   % oil (BOE basis)


78

%


76

%


77

%

Oil and natural gas revenues (in thousands)







   Oil revenue


$

142,601



$

122,613



$

73,349


   Natural gas revenue (a)


18,613



14,462



11,265


      Total revenue


161,214



137,075



84,614


   Impact of settled derivatives


(9,239)



(7,980)



(1,214)


      Adjusted Total Revenue (i)


$

151,975



$

129,095



$

83,400


Average realized sales price
(excluding impact of settled derivatives)







   Oil (Bbl)


$

56.57



$

61.46



$

46.10


   Natural gas (Mcf)


4.49



3.77



3.88


   Total (BOE)


50.19



52.02



40.80


Average realized sales price
(including impact of settled derivatives)







   Oil (Bbl)


$

52.87



$

57.38



$

45.24


   Natural gas (Mcf)


4.51



3.81



3.94


   Total (BOE)


47.31



48.99



40.21


Additional per BOE data







   Sales price (b)


$

50.19



$

52.02



$

40.80


      Lease operating expense (c)


5.77



4.99



5.08


      Gathering and treating expense (a)






0.52


      Production taxes


3.20



2.86



2.62


   Operating margin


$

41.22



$

44.17



$

32.58









   Depletion, depreciation and amortization


$

15.02



$

14.70



$

13.75


   Adjusted G&A (d)







      Cash component (e)


$

2.17



$

2.69



$

2.50


      Non-cash component


0.57



0.64



0.65




(a)

On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the three and nine months ended September 30, 2018 were accounted for as a reduction to revenue.

(b) 

Excludes the impact of settled derivatives.

(c)

Excludes gathering and treating expense.

(d)

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.

(e)

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

Total Revenue. For the quarter ended September 30, 2018, Callon reported total revenue of $161.2 million and total revenue including settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure(i)) of $152.0 million, including the impact of an $9.2 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 34.9 MBOE/d compared to average daily production of 29.0 MBOE/d in the second quarter of 2018. Average realized prices, including and excluding the effects of hedging, are detailed above.

Hedging impacts. For the quarter ended September 30, 2018, Callon recognized the following hedging-related items (in thousands, except per unit data):


In Thousands


Per Unit

Oil derivatives




Net loss on settlements

$

(9,306)



$

(3.70)


Net loss on fair value adjustments

(24,476)




   Total loss on oil derivatives

$

(33,782)




Natural gas derivatives




Net gain on settlements

$

67



$

0.02


Net loss on fair value adjustments

(624)




   Total loss on natural gas derivatives

$

(557)




Total oil & natural gas derivatives




Net loss on settlements

$

(9,239)



$

(2.88)


Net loss on fair value adjustments

(25,100)




   Total loss on total oil & natural gas derivatives

$

(34,339)




Lease Operating Expenses, including workover ("LOE"). LOE per BOE for the three months ended September 30, 2018 was $5.77 per BOE, compared to LOE of $4.99 per BOE in the second quarter of 2018. The increase in this metric was primarily related to an increase in costs from workover activity on our properties.

Production Taxes, including ad valorem taxes. Production taxes were $3.20 per BOE for the three months ended September 30, 2018, representing approximately 6.4% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended September 30, 2018 was $15.02 per BOE compared to $14.70 per BOE in the second quarter of 2018. The increase on a per unit basis was primarily attributable to greater increases in our depreciable asset base and assumed future development costs related to undeveloped proved reserves as compared to the estimated total proved reserve base.

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 $8.8 million, or $2.74 per BOE, for the three months ended September 30, 2018 compared to $8.8 million, or $3.33 per BOE, for the second quarter of 2018. The cash component of Adjusted G&A was $7.0 million, or $2.17 per BOE, for the three months ended September 30, 2018 compared to $7.1 million, or $2.69 per BOE, for the second quarter of 2018.

For the three months ended September 30, 2018, G&A and Adjusted G&A, which excludes the change in fair value of liability share-based awards, amortization of equity-settled share-based incentive awards and corporate depreciation and amortization, are calculated as follows (in thousands):


Three Months Ended
September 30, 2018

Total G&A expense

$

9,721


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

(921)


Adjusted G&A – total

8,800


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

(1,730)


   Less: Corporate depreciation & amortization (non-cash)

(102)


Adjusted G&A – cash component

$

6,968


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 $1.5 million for the three months ended September 30, 2018 which relates to deferred state franchise tax. At September 30, 2018 we had a valuation allowance of $30.3 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 $8.3 million (or $0.04 per diluted share) for the quarter as if the valuation allowance did not exist.

2018 Guidance

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. Based upon current levels of operational efficiency, the impact of a temporary gas plant outage on commodity mix, and non-operated activity, the Company is updating full year 2018 guidance as follows:



Third Quarter


Year to Date


Full Year



2018 Actual


2018 Actual


2018 Guidance

Total production (MBOE/d)


34.9


30.2


32.0 - 33.0

% oil


78%


77%


77% - 78%

Income statement expenses (per BOE)







LOE, including workovers


$5.77


$5.43


$5.00 - $6.00

Production taxes, including ad valorem (% unhedged revenue)


6%


6%


7%

   Adjusted G&A: cash component (a)


$2.17


$2.50


$1.75 - $2.50

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


$0.57


$0.58


$0.50 - $1.00

   Cash interest expense (c)


$0.00


$0.00


$0.00

Effective income tax rate


22%


22%


22%

Capital expenditures ($MM, accrual basis)







Operational (d)


$159


$442


$560

Capitalized expenses


$25


$59


$75 - $85

Net operated horizontal wells placed on production


14


37


50 - 52



(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 cash 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


For the Full Year


For the Full Year

Oil contracts (WTI)

of 2018


of 2019


of 2020

Swap contracts






Total volume (Bbls)

552,000






Weighted average price per Bbl

$

52.07



$



$


Collar contracts (two-way collars)






Total volume (Bbls)

92,000



1,095,000




Weighted average price per Bbl






Ceiling (short call)

$

60.50



$

80.00



$


Floor (long put)

$

50.00



$

65.00



$


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






Total volume (Bbls)

874,000



3,469,000




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



$


Puts






Total volume (Bbls)

276,000



1,825,000




   Weighted average price per Bbl

$

65.00



$

65.00



$








Oil contracts (Midland basis differential)






Swap contracts






Total volume (Bbls)

1,518,000



4,746,500



4,024,000


Weighted average price per Bbl

$

(5.30)



$

(4.72)



$

(1.51)








Natural gas contracts (Henry Hub)






Swap contracts






   Total volume (MMBtu)

1,380,000






   Weighted average price per MMBtu

$

2.91



$



$


Collar contracts (two-way collars)






   Total volume (MMBtu)

552,000



3,727,500




   Weighted average price per MMBtu






      Ceiling (short call)

$

3.19



$

3.13



$


      Floor (long put)

$

2.75



$

2.72



$








Natural gas contracts (Waha basis differential)






Swap contracts






   Total volume (MMBtu)

552,000



9,490,000



2,196,000


   Weighted average price per MMBtu

$

(1.14)



$

(1.25)



$

(1.14)


Income Available to Common Shareholders. The Company reported net income available to common shareholders of $36.1 million for the three months ended September 30, 2018 and Adjusted Income available to common shareholders of $48.3 million, or $0.21 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(i), a non-GAAP financial measure, (in thousands):


Three Months Ended

Adjusted Income per fully diluted common share:

September 30, 2018


June 30, 2018


September 30, 2017

Income available to common stockholders

$

36,108



$

48,650



$

15,257


   Net loss on derivatives, net of settlements

25,100



8,572



12,947


   Change in the fair value of share-based awards

879



(463)



732


Tax effect on adjustments above

(5,456)



(1,703)



(4,788)


Change in valuation allowance

(8,323)



(10,562)



(6,064)


Adjusted Income (i)

$

48,308



$

44,494



$

18,084


Adjusted Income per fully diluted common share (i)

$

0.21



$

0.21



$

0.09





Three Months Ended

Adjusted EBITDA:

September 30, 2018


June 30, 2018


September 30, 2017

Net income

$

37,931



$

50,474



$

17,081


   Net loss on derivatives, net of settlements

25,100



8,572



12,947


   Non-cash stock-based compensation expense

2,587



1,164



1,952


   Acquisition expense

1,435



1,767



205


   Income tax expense

1,487



481



237


   Interest expense

711



594



444


   Depreciation, depletion and amortization

48,977



39,387



29,132


   Accretion expense

202



206



131


Adjusted EBITDA (i)

$

118,430



$

102,645



$

62,129


Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the three months ended September 30, 2018 was $116.9 million and is reconciled to operating cash flow in the following table (in thousands):


Three Months Ended


September 30, 2018


June 30, 2018


September 30, 2017

Cash flows from operating activities:






Net income

$

37,931



$

50,474



$

17,081


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






   Depreciation, depletion and amortization

48,977



39,387



29,132


   Accretion expense

202



206



131


   Amortization of non-cash debt related items

708



588



441


   Deferred income tax expense

1,487



481



237


   Net loss on derivatives, net of settlements

25,100



8,572



12,947


   (Gain) loss on sale of other property and equipment

(102)



22




   Non-cash expense related to equity share-based awards

1,708



1,627



1,219


   Change in the fair value of liability share-based awards

879



(463)



732


Discretionary cash flow (i)

$

116,890



$

100,894



$

61,920


   Changes in working capital

(347)



8,978



(7,777)


   Payments to settle asset retirement obligations

(507)



(207)



(250)


   Payments to settle vested liability share-based awards



(1,901)




Net cash provided by operating activities

$

116,036



$

107,764



$

53,893



 

Callon Petroleum Company

Consolidated Balance Sheets

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




September 30, 2018


December 31, 2017

ASSETS


Unaudited



Current assets:





Cash and cash equivalents


$

12,129



$

27,995


Accounts receivable


168,753



114,320


Fair value of derivatives


4,289



406


Other current assets


3,804



2,139


Total current assets


188,975



144,860


Oil and natural gas properties, full cost accounting method:





Evaluated properties


4,305,189



3,429,570


Less accumulated depreciation, depletion, amortization and impairment


(2,208,066)



(2,084,095)


Net evaluated oil and natural gas properties


2,097,123



1,345,475


Unevaluated properties


1,385,529



1,168,016


Total oil and natural gas properties


3,482,652



2,513,491


Other property and equipment, net


21,738



20,361


Restricted investments


3,413



3,372


Deferred tax asset




52


Deferred financing costs


6,406



4,863


Acquisition deposit




900


Other assets, net


5,552



5,397


Total assets


$

3,708,736



$

2,693,296


LIABILITIES AND STOCKHOLDERS' EQUITY





Current liabilities:





Accounts payable and accrued liabilities


$

251,754



$

162,878


Accrued interest


27,325



9,235


Cash-settleable restricted stock unit awards


2,422



4,621


Asset retirement obligations


4,464



1,295


Fair value of derivatives


47,167



27,744


Total current liabilities


333,132



205,773


Senior secured revolving credit facility


65,000



25,000


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


595,729



595,196


6.375% senior unsecured notes due 2026, net of unamortized deferred financing costs


392,799




Asset retirement obligations


5,428



4,725


Cash-settleable restricted stock unit awards


2,818



3,490


Deferred tax liability


3,917



1,457


Fair value of derivatives


15,440



1,284


Other long-term liabilities


6,165



405


Total liabilities


1,420,428



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; 227,567,936 and 201,836,172 shares outstanding, respectively


2,276



2,018


Capital in excess of par value


2,474,748



2,181,359


Accumulated deficit


(188,731)



(327,426)


Total stockholders' equity


2,288,308



1,855,966


Total liabilities and stockholders' equity


$

3,708,736



$

2,693,296


 

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)



Three Months Ended September 30,


Nine Months Ended September 30,


2018


2017


2018


2017

Operating revenues:








Oil sales

$

142,601



$

73,349



$

380,500



$

218,242


Natural gas sales

18,613



11,265



45,229



30,019


Total operating revenues

161,214



84,614



425,729



248,261


Operating expenses:








Lease operating expenses

18,525



11,624



44,705



36,708


Production taxes

10,263



5,444



26,265



16,168


Depreciation, depletion and amortization

48,257



28,525



122,407



79,172


General and administrative

9,721



7,259



26,779



18,894


Settled share-based awards







6,351


Accretion expense

202



131



626



523


Acquisition expense

1,435



205



3,750



3,027


Total operating expenses

88,403



53,188



224,532



160,843


Income from operations

72,811



31,426



201,197



87,418


Other (income) expenses:








Interest expense, net of capitalized amounts

711



444



1,765



1,698


(Gain) loss on derivative contracts

34,339



14,162



55,374



(11,636)


Other income

(1,657)



(498)



(2,571)



(1,270)


Total other (income) expense

33,393



14,108



54,568



(11,208)


Income before income taxes

39,418



17,318



146,629



98,626


Income tax expense

1,487



237



2,463



1,026


Net income

37,931



17,081



144,166



97,600


Preferred stock dividends

(1,823)



(1,824)



(5,471)



(5,471)


Income available to common stockholders

$

36,108



$

15,257



$

138,695



$

92,129


Income per common share:








Basic

$

0.16



$

0.08



$

0.65



$

0.46


Diluted

$

0.16



$

0.08



$

0.65



$

0.46


Shares used in computing income per common share:








Basic

227,564



201,827



213,409



201,422


Diluted

228,140



202,337



214,079



201,995


 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)



Three Months Ended September 30,


Nine Months Ended September 30,


2018


2017


2018


2017

Cash flows from operating activities:








Net income

$

37,931



$

17,081



$

144,166



$

97,600


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








Depreciation, depletion and amortization

48,977



29,132



124,430



80,829


Accretion expense

202



131



626



523


Amortization of non-cash debt related items

708



441



1,749



1,695


Deferred income tax expense

1,487



237



2,463



1,026


Net (gain) loss on derivatives, net of settlements

25,100



12,947



29,696



(15,608)


(Gain) loss on sale of other property and equipment

(102)





(80)



62


Non-cash expense related to equity share-based awards

1,708



1,219



4,466



7,014


Change in the fair value of liability share-based awards

879



732



1,428



2,423


Payments to settle asset retirement obligations

(507)



(250)



(1,080)



(1,831)


Changes in current assets and liabilities:








Accounts receivable

(56,764)



(4,338)



(54,384)



(12,148)


Other current assets

3,885



(38)



(1,665)



(336)


Current liabilities

47,741



1,854



64,801



7,534


Other long-term liabilities

5,500



1



5,787



121


Long-term prepaid



(4,650)





(4,650)


Other assets, net

(709)



(606)



(1,398)



(1,376)


Payments to settle vested liability share-based awards





(4,990)



(13,173)


Net cash provided by operating activities

116,036



53,893



316,015



149,705


Cash flows from investing activities:








Capital expenditures

(156,982)



(121,128)



(455,352)



(267,218)


Acquisitions

(550,592)



(8,015)



(595,984)



(714,504)


Acquisition deposit

27,600







46,138


Proceeds from sale of assets

5,249





8,326




Net cash used in investing activities

(674,725)



(129,143)



(1,043,010)



(935,584)


Cash flows from financing activities:








Borrowings on senior secured revolving credit facility

105,000





270,000




Payments on senior secured revolving credit facility

(40,000)





(230,000)




Issuance of 6.125% senior unsecured notes due 2024







200,000


Premium on the issuance of 6.125% senior unsecured notes due 2024







8,250


Issuance of 6.375% senior unsecured notes due 2026





400,000




Issuance of common stock

7





288,364




Payment of preferred stock dividends

(1,823)



(1,824)



(5,471)



(5,471)


Payment of deferred financing costs

(1,296)



(401)



(9,960)



(7,166)


Tax withholdings related to restricted stock units

(216)



(65)



(1,804)



(1,118)


Net cash provided by financing activities

61,672



(2,290)



711,129



194,495


Net change in cash and cash equivalents

(497,017)



(77,540)



(15,866)



(591,384)


Balance, beginning of period

509,146



139,149



27,995



652,993


Balance, end of period

$

12,129



$

61,609



$

12,129



$

61,609


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 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 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 Wednesday, November 7, 2018, to discuss third quarter 2018 financial and operating results.

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

Date/Time:

Wednesday, November 7, 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:

5488988

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, 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
[email protected]
1-281-589-5200

i)

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

 

Cision View original content:http://www.prnewswire.com/news-releases/callon-petroleum-company-announces-third-quarter-2018-results-300744973.html

SOURCE Callon Petroleum Company


Source: PR Newswire (November 6, 2018 - 4:15 PM EST)

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