Callon Petroleum Company Announces Second Quarter 2020 Results

Updates 2020 Operating Plan and Outlook

HOUSTON, Aug. 4, 2020 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and six months ended June 30, 2020.

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.

Recent Highlights

  • Delivered production of approximately 108.7 Mboe/d (65% oil), above the high end of guidance, for the second quarter of 2020

  • Posted accrued operational capital spending of $85.1 million, 15% below the second quarter target of $100 million

  • Generated net cash from operating activities of $97.8 million and free cash flow1 of $18.0 million for the second quarter

  • Loss available to common stockholders of $1,564.7 million, or $3.94 per fully diluted share, driven by an impairment of evaluated oil and gas properties of $1,276.5 million, adjusted EBITDA1 of $153.4 million, and adjusted income per share1 of $0.01 for the second quarter of 2020

  • Achieved lease operating expense ("LOE") of $50.8 million or $5.14 per Boe for the second quarter of 2020, an improvement of 10% over the comparable three-month period ended March 31, 2020

  • Lowered cost structure with total operating expenses, including full cash G&A costs1, of $9.58/Boe in the quarter, 16% below the prior quarter

  • Reduced Delaware and Midland drilling and completion costs versus the prior quarter by approximately $100 per 1,000 lateral feet, representing incremental savings of 11% and 17% respectively

  • Announced a 1-for-10 reverse stock split effective as of the close of business on August 7, 2020

Joe Gatto, President and Chief Executive Officer commented, "Our operational and financial results for the second quarter reflect Callon's commitment to thoughtful capital allocation and operational execution that we have overlaid on an exceptional, diversified asset base. As oil markets began to erode in March, our team acted quickly to reduce capital activity while maintaining a clear focus on near and long-term operating goals. As a result, our drilling and completion costs are down across the board, second quarter production was well ahead of estimates, and operating costs continue to decline beyond our targeted synergy goals."

He continued, "Our success in reducing our cost structure, combined with leading capital efficiency from strong well productivity and well cost reductions, positioned us to generate free cash flow this quarter. This is just the first step as we have developed a longer-term plan designed to consistently generate free cash flow while maintaining production levels with a reduced reinvestment rate. After moving past the working capital cash impact of expenditures incurred in the first quarter, a meaningful portion of which added to our current inventory of drilled, uncompleted wells, we will be dedicating all of our expected free cash flow to credit facility reductions and forecast our current credit facility balance to decline into year end and continue into 2021."

Mr. Gatto also shared, "Despite tremendous business, social, and personal hurdles resulting from the current pandemic and extreme turbulence in the financial markets, our team has remained focused on synergy realization and the integration of people, systems, and processes. Our operational and financial results highlight our progress as an organization and I applaud the Callon team for persevering through an incredibly difficult past few months. Importantly, we remain committed to their safety and that of our vendors, partners, and communities." 

Operations Update

At June 30, 2020, Callon had 1,471 gross (1,298.0 net) horizontal wells producing from established flow units in the Permian Basin and Eagle Ford Shale. Net daily production for the three months ended June 30, 2020 grew 168% to 108.7 Mboe/d (65% oil), as compared to the same period of 2019.

For the three months ended June 30, 2020, Callon drilled 29 gross (27.0 net) horizontal wells and placed a combined 26 gross (24.9 net) horizontal wells on production. During the course of the quarter, all rigs and completion crews ceased activity upon completion of projects in progress. The Company does not have any active rigs or completion crews at this time but does intend to resume development activity during the third quarter. Near-term operational activity will be focused on completing a drilled, uncompleted inventory of approximately 70 wells in both the Permian Basin and Eagle Ford Shale with one dedicated completion crew. The Company also intends to return two to three drilling rigs to service later in the third quarter for the balance of the year.

During the second quarter in the Delaware Basin, the seven-well Dorothy Sansom project was placed on production in April, consisting of targets in the 3rd Bone Spring Shale, Wolfcamp A (2), Upper Wolfcamp B, Lower Wolfcamp B (2), and Wolfcamp C. Initial results have been positive with cumulative production (adjusted for shut-ins during the quarter) matching or exceeding production from primary zones in the Crowley-St. Clair project which was completed in 2019. Comparable wells in the Wolfcamp A and B zones on the Dorothy Sansom project were drilled and completed offsetting parent wells, unlike the unbounded Crowley-St. Claire wells. The current performance is encouraging for future development of offset wells in the area. 

At the WildHorse area in the Midland Basin, the Company brought online the nine-well Dunkin/Horton/Wright project that had previously been deferred during the early portion of the quarter. The project consists of Wolfcamp A wells (4), Lower Spraberry wells (3), and a Wolfcamp B and Middle Spraberry test. Initial production from the Wolfcamp A and B has exceeded expectations and significantly outperformed 2019 vintage Wolfcamp A offsets in the immediate area through the first fifty days. Early results from the Middle Spraberry are encouraging for potential future development in the area as production currently continues to outpace initial type curve estimates. 

In the Eagle Ford, the Company placed on production the Pena project with a portion of the wells reaching first production at the very end of March and the remainder falling into early April. These wells have produced over 75,000 cumulative Boe (~90% oil) on average (1.2 MMBoe in total) through the first 120 days online, matching type curve expectations.

During the second quarter, Callon saw additional gains in operational efficiency, with average development costs improving. Some of the highlights include:

  • Delaware well costs further reduced to approximately $850 per lateral foot, an 11% improvement versus the previous quarter and a 23% improvement versus our 2019 average of $1,100 per lateral foot; and

  • Midland Basin well costs are now approaching approximately $500 per lateral foot, a 17% improvement over the first quarter and 37% improvement over 2019

Marketing

The Company entered into short-term fixed price contracts in May and June for Eagle Ford Shale production to secure firm transportation and also mitigate the effect of the calendar month average ("CMA") roll calculation on realized pricing. Those fixed price contracts have since returned to our previous MEH linked pricing structure. Callon recently secured incremental firm transportation for production volumes to ensure delivery of barrels produced from the Eagle Ford assets to improve market options for the future.

In addition, the Company has entered into a multi-year agreement with a diverse global player in waterborne oil markets that will be purchasing up to 10,000 barrels per day of oil of Permian Basin production at Brent-linked prices for volumes delivered under our firm transportation agreement to the Houston Ship Channel area on the Echo Pipeline. In April, we began delivering 15,000 barrels per day into the Corpus refinery complex under our firm transportation agreement on Gray Oak pipeline. These barrels are part of multi-year term sales agreements receiving a combination of Brent and MEH based pricing.

Minimal production volumes that were voluntarily shut-in by the Company during the second quarter have been returned to production. The Company is not subject to repayment of volumes or cover cost at second quarter pricing since it met all sales obligations during the quarter. 

Capital Expenditures

For the three months ended June 30, 2020, Callon incurred $85.1 million in operational capital expenditures on an accrual basis. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis:



Three Months Ended June 30, 2020



Operational


Capitalized


Capitalized


Total Capital



Capital (a)


Interest


G&A


Expenditures



(In thousands)

Cash basis (b)


$174,594



$24,787



$6,740



$206,121


Timing adjustments (c)


(90,780)



(3,863)





(94,643)


Non-cash items


1,273





2,162



3,435


   Accrual basis


$85,087



$20,924



$8,902



$114,913




(a)

Includes seismic, land, technology, 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.

Hedging

For the three months ended June 30, 2020, Callon recognized a hedge gain of $84.2 million consisting of settled positions and monetization of certain future oil positions. During the course of the quarter and through July, the Company has continued to add hedge coverage for oil, natural gas, and ethane in 2021, and restructured certain oil swaps for the remaining six months of 2020 into two-way collars providing additional upside for oil prices to as high as $45 per barrel. Average floor prices for the second half of 2020 for WTI NYMEX oil contracts are approximately $40 per barrel covering just over nine million barrels of production, or roughly 80% of projected oil production for the remainder of 2020. 

The Company took advantage of an improved natural gas outlook and entered into a combination of NYMEX Henry Hub swaps and collars for 2021 providing coverage for over 22,000 BBtu or just over 60,000 MMBtu per day at an average floor price $2.61 per MMBtu. Natural gas production is now approximately 70% hedged for the remainder of 2020 and just over 60% hedged for 2021. Details regarding the Company's full hedge positions can be found in the hedge summary within the earnings release or within the appendix of the second quarter 2020 earnings slide deck on the website.

Operating and Financial Results

The following table presents summary information for the periods indicated: 



Three Months Ended



June 30, 2020


March 31, 2020


June 30, 2019

Net production







Oil (MBbls)


6,396



5,847



2,848


Natural gas (MMcf)


11,009



9,793



5,031


NGLs (MBbls)


1,657



1,707




Total barrels of oil equivalent (MBoe)


9,888



9,186



3,687


Total daily production (Boe/d)


108,664



100,955



40,516


Oil as % of total daily production


65

%


64

%


77

%

Average realized sales price

(excluding impact of settled derivatives)







Oil (per Bbl)


$20.41



$45.45



$56.44


Natural gas (per Mcf)


1.11



0.62



1.26


NGLs (per Bbl)


8.74



10.62




Total (per BOE)


15.90



31.56



45.31


Average realized sales price

(including impact of settled derivatives)







Oil (per Bbl)


$33.82



$48.90



$54.87


Natural gas (per Mcf)


0.97



1.13



1.91


NGLs (per Bbl)


8.74



10.62




Total (per Boe)


24.42



34.30



44.99


Revenues (in thousands)







Oil


$130,513



$265,767



$160,728


Natural gas


12,242



6,029



6,324


NGLs


14,479



18,123




Total revenues


157,234



289,919



167,052


Additional per Boe data







Sales price (a)


$15.90



$31.56



$45.31


Lease operating expense


5.14



5.70



6.18


Production taxes


1.05



2.14



3.02


Gathering, transportation and processing


2.03



1.57




Operating margin


$7.68



$22.15



$36.11









   Depletion, depreciation and amortization


$14.05



$14.31



$17.12


   General and administrative (G&A)


$1.01



$0.91



$2.87


   Adjusted G&A (b)







      Cash component (c)


$0.69



$1.20



$2.42


      Non-cash component


0.15



0.41



0.68




(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.

Total Revenue. For the quarter ended June 30, 2020, Callon reported total revenue of $157.2 million and total revenue including the gain or loss from the settlement of derivative contracts ("Adjusted Total Revenue"(1)) of $241.4 million, reflecting the impact of an $84.2 million gain from the settlement of derivative contracts. Average daily production for the quarter was 108.7 Mboe/d, compared to average daily production of 101.0 Mboe/d in the first quarter of 2020. Average realized prices, including and excluding the effects of hedging, are detailed above.

Hedging impacts. For the quarter ended June 30, 2020, the net (gain) loss on commodity derivative contracts includes the following (in thousands):


Three Months Ended
June 30, 2020

(Gain) loss on oil derivatives

$122,369

(Gain) loss on natural gas derivatives

4,695

(Gain) loss on NGL derivatives

(4)

(Gain) loss on commodity derivative contracts

$127,060

For the quarter ended June 30, 2020, the cash (paid) received for commodity derivative settlements includes the following (in thousands):


Three Months Ended
June 30, 2020

Cash (paid) received on oil derivatives

$100,470

Cash (paid) received on natural gas derivatives

(1,782)

Cash received for commodity derivative settlements

$98,688

Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended June 30, 2020 was $5.14 per Boe, compared to LOE of $5.70 per Boe in the first quarter of 2020. The decrease in LOE per Boe was driven by improved field practices and a reduction in workovers during the second quarter of 2020 as compared to the first quarter of 2020.

Production Taxes, including ad valorem taxes. Production taxes were $1.05 per Boe for the three months ended June 30, 2020, representing approximately 6.6% of total revenue before the impact of derivative settlements.

Gathering, Transportation and Processing Expenses. Gathering, transportation and processing costs for the three months ended June 30, 2020 were $20.0 million as compared to $14.4 million in the first quarter of 2020 due to firm transportation contracts that began in the second quarter of 2020. In 2020, the Company began reporting gathering, transportation and processing costs separately due to the assumption of processing agreements in the Carrizo acquisition and certain contract modifications effective January 1, 2020. As such, the Company now records contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, as gathering, transportation and processing expense. These fees were historically recorded as a reduction of revenue depending on when control transferred to the purchaser. 

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended June 30, 2020 was consistent at $14.05 per Boe compared to $14.31 per Boe in the first quarter of 2020.  

Impairment of Evaluated Oil and Gas Properties. Callon recognized an impairment of evaluated oil and gas properties of $1.3 billion for the three months ended June 30, 2020 due primarily to declines in the average realized prices for sales of oil and gas. The decrease in the trailing 12-month average realized price as of June 30, 2020 resulted in a reduction our proved oil and gas reserve volumes of less than 2% of our December 31, 2019 proved oil and gas reserves volumes. The Company did not recognize an impairment of evaluated oil and gas properties during the first quarter of 2020.

G&A. G&A for the three months ended June 30, 2020 was $10.0 million, or $1.01 per Boe, and G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A" 1) was $8.3 million, or $0.84 per Boe, for the three months ended June 30, 2020 compared to $14.8 million, or $1.62 per Boe, for the first quarter of 2020. The cash component of Adjusted G&A was $6.8 million, or $0.69 per Boe, for the three months ended June 30, 2020 compared to $11.1 million, or $1.20 per Boe, for the first quarter of 2020. The reductions in G&A were driven by the realization of post-merger synergies and further reductions to payroll and non-payroll expenses following the pandemic, including compensation reductions for executives and the board of directors.

For the three months ended June 30, 2020 and March 31, 2020, G&A and Adjusted G&A, which excludes the amortization of equity-settled and share-based incentive awards, are calculated as follows (in thousands):


Three Months Ended


June 30, 2020


March 31, 2020

Total G&A expense

$10,024



$8,325


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

(1,720)



6,516


Adjusted G&A – total

8,304



14,841


   Restricted stock share-based compensation (non-cash) and other non-recurring expenses

(1,509)



(3,776)


Adjusted G&A – cash component

$6,795



$11,065






Capitalized cash G&A

$6,740



$7,570


Full Cash G&A Costs

$13,535



$18,635


Income Tax Expense. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. Callon recorded income tax expense of $51.3 million for the three months ended June 30, 2020, compared to income tax expense of $64.0 million for the three months ended March 31, 2020. Primarily as a result of the impairment of evaluated oil and gas properties recognized during the second quarter of 2020, Callon recorded a valuation allowance against its net deferred tax assets reducing the net deferred tax assets to zero.

Loss Available to Common Stockholders. We recorded a loss available to common stockholders for the three months ended June 30, 2020 of $1.6 billion, or $3.94 per diluted share, as compared to income available to common stockholders of $216.6 million, or $0.55 per diluted share, for the first quarter of 2020. The loss was primarily due to the impairment of evaluated oil and gas properties of $1.3 billion as well as a loss on derivative contracts of approximately $127.0 million recorded during the second quarter of 2020.

Adjusted EBITDA1. Adjusted EBITDA for the second quarter of 2020 was $153.4 million as compared to $217.5 million for the first quarter of 2020. The decrease in Adjusted EBITDA from the first quarter of 2020 was primarily due to an approximate 30% decrease in the average realized price of oil. This was partially offset by increased sequential production as well as a decrease in operating expenses as described above.  

Guidance

Callon is reinstating guidance for the full year and updating previous ranges to reflect adjustments to its operational plan and associated expectations.



Full Year



2020 Guidance

Total production (Mboe/d)


99.0 - 101.0

Oil production


64%

Gas production


18%

NGL production


18%

Income statement expenses ($MM)



LOE, including workovers


$205 - $215

Gathering, processing, and transportation


$60 - $65

Production taxes, including ad valorem (% unhedged revenue)


7%

Adjusted G&A: cash component (a)


$30 - $35

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


$5 - $7

Cash interest expense


$90 - $95

Effective income tax rate (%)


22%

Capital expenditures ($MM, accrual basis)



Total operational capital (c)


$500 - $525

Capitalized interest


$80 - $85

Capitalized G&A


$25 - $30

Gross operated wells drilled / completed


87-89 / 80-82



(a)

Excludes the amortization of equity-settled, share-based incentive awards. 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) 

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

In addition to the updated 2020 guidance provided in the previous table, the Company's initial outlook for 2021 for a "maintenance capital" plan will include average daily production of 90 to 95 MBoe per day from an operational capital spending level of approximately $400 million. Management believes that this program at current prices will yield meaningful additional free cash flow.

Reverse Stock Split

Today the Company also announced that its Board of Directors has approved a reverse stock split of the Company's outstanding shares of common stock at a ratio of 1-for-10, which was approved by the Company's shareholders at the Company's annual meeting of shareholders on June 8, 2020. The reverse stock split will become effective as of the close of business on August 7, 2020 and the Company's common stock will begin trading on a split-adjusted basis on the NYSE at market open on August 10, 2020. The par value of the common stock will not be adjusted in connection with the reverse stock split.

The reverse stock split is intended to, among other things, improve the opportunity for institutional ownership. Upon completion of the reverse stock split, each 10 pre-split shares of common stock outstanding will be automatically combined into one issued and outstanding share of common stock. Any fractional shares that result from the reverse stock split will be canceled, and shareholders who would otherwise hold fractional shares as a result of the reverse stock split will be entitled to receive cash (without interest and subject to applicable withholding taxes) in lieu of such fractional shares. The number of outstanding shares of common stock will be reduced from approximately 397,476,674 as of July 31, 2020 to approximately 39,747,667 shares (without giving effect to the liquidation of fractional shares). The Board has also approved a proportionate reduction of the total number of authorized shares of the Company's common stock pursuant to an amendment to the Company's Certificate of Incorporation. The total number of shares of common stock that the Company is authorized to issue will be reduced from 525,000,000 to 52,500,000 shares.

Second Quarter 2020 Earnings Conference Call

The Company's conference call to discuss second quarter results is scheduled for Wednesday, August 5, 2020, at 8:00 am CDT. The presentation slides and associated webcast can both be found at www.callon.com located on the "News/Events" page within the Investors section on the site or by clicking on the link below.

www.callon.com/investors/news-events/ir-calendar

Hedge Portfolio Summary

The following tables summarize Callon's open derivative contracts for the remaining two quarters of 2020 and the full year 2021, updated for changes through July 31, 2020:


For the Remainder



For the Full Year


Oil contracts (WTI)

of 2020



of 2021


   Swap contracts






   Total volume (Bbls)

6,291,880




1,377,000



   Weighted average price per Bbl

$42.08




$42.00



   Collar contracts






   Total volume (Bbls)

2,863,040




3,741,250



   Weighted average price per Bbl






   Ceiling (short call)

$45.00




$45.02



   Floor (long put)

$35.00




$40.00



   Short put contracts






      Total volume (Bbls)

1,104,000






      Weighted average price per Bbl

$42.50




$—



   Long call contracts






    Total volume (Bbls)

920,000






    Weighted average price per Bbl

$67.50




$—



   Short call contracts






   Total volume (Bbls)

920,000


(a)


4,825,300


(a)

   Weighted average price per Bbl

$55.00




$63.62



   Short call swaption contracts






   Total volume (Bbls)




730,000


(b)

   Weighted average price per Bbl

$—




$47.00









Oil contracts (WTI Calendar Month Average Roll)






Swap contracts






Total volume (Bbls)

3,864,000






Weighted average price per Bbl

($2.75)




$—









Oil contracts (Brent ICE)






   Swap contracts






   Total volume (Bbls)

184,000




1,272,450



   Weighted average price per Bbl

$46.15




$38.24









Oil contracts (Midland basis differential)






   Swap contracts






   Total volume (Bbls)

3,094,700




4,015,100



   Weighted average price per Bbl

($1.75)




$0.40









Oil contracts (Argus Houston MEH basis differential)






   Swap contracts






   Total volume (Bbls)

3,256,004






   Weighted average price per Bbl

$0.06




$—



Oil contracts (Argus Houston MEH swaps)






   Swap contracts






   Total volume (Bbls)

368,000




2,969,050



   Weighted average price per Bbl

$57.71




$39.48





(a) 

Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps.

(b) 

The short call swaption contract has an exercise expiration date of October 30, 2020.

 


For the Remainder



For the Full Year

Natural gas contracts (Henry Hub)

of 2020



of 2021

   Swap contracts





      Total volume (MMBtu)

8,566,000




12,923,000


      Weighted average price per MMBtu

$2.07




$2.66


   Collar contracts (three-way collars)





      Total volume (MMBtu)

2,755,000




1,350,000


      Weighted average price per MMBtu





         Ceiling (short call)

$2.73




$2.70


         Floor (long put)

$2.47




$2.42


         Floor (short put)

$2.00




$2.00


Collar contracts (two-way collars)





      Total volume (MMBtu)

1,525,000




7,750,000


      Weighted average price per MMBtu





         Ceiling (short call)

$3.25




$2.93


         Floor (long put)

$2.67




$2.55


   Long call contracts





      Total volume (MMBtu)

3,036,000





      Weighted average price per MMBtu

$3.50




$—


   Short call contracts





      Total volume (MMBtu)

6,072,000




7,300,000


      Weighted average price per MMBtu

$3.50




$3.09







Natural gas contracts (Waha basis differential)





   Swap contracts





      Total volume (MMBtu)

12,885,000




6,387,500


      Weighted average price per MMBtu

($0.92)




($0.58)













For the Remainder



For the Full Year

NGL contracts (OPIS Mont Belvieu Purity Ethane)

of 2020



of 2021

   Swap contracts





      Total volume (Bbls)




1,825,000


      Weighted average price per Bbl

$—




$7.62


Adjusted Income and Adjusted EBITDA. The Company reported loss available to common stockholders of $1,564.7 million, or $3.94 per fully diluted share, for the three months ended June 30, 2020, and adjusted income available to common stockholders of $2.1 million, or $0.01 per fully diluted share. The following tables reconcile the Company's income (loss) available to common stockholders to adjusted income, and the Company's net income (loss) to adjusted EBITDA:


Three Months Ended


June 30, 2020


March 31, 2020


June 30, 2019


(In thousands, except per share data)

Income (loss) available to common stockholders

($1,564,731)



$216,565



$53,357


(Gain) loss on derivative contracts

126,965



(251,969)



(14,036)


Gain (loss) on commodity derivative settlements, net

84,208



25,126



(1,157)


Non-cash stock-based compensation expense (benefit)

2,761



(2,972)



904


Impairment of evaluated oil and gas properties

1,276,518






Merger and integration expense

8,067



15,830




Other (income) expense

6,759



(1,029)



770


Tax effect on adjustments above(a)

(316,108)



45,153



2,839


Change in valuation allowance

377,645






Adjusted Income

$2,084



$46,704



$42,677


Adjusted Income per fully diluted common share

$0.01



$0.12



$0.19








Basic WASO

397,084



396,682



228,051


Diluted WASO (GAAP)

397,084



396,836



228,411


Effective of potentially dilutive instruments

114






Adjusted Diluted WASO

397,198



396,836



228,411




(a) 

Calculated using the federal statutory rate of 21%.

 


Three Months Ended


June 30, 2020


March 31, 2020


June 30, 2019


(In thousands)

Net income (loss)

($1,564,731)



$216,565



$55,180


   (Gain) loss on derivative contracts

126,965



(251,969)



(14,036)


   Gain (loss) on commodity derivative settlements, net

84,208



25,126



(1,157)


   Non-cash stock-based compensation expense (benefit)

2,761



(2,972)



904


 Impairment of evaluated oil and gas properties

1,276,518






   Merger and integration expense

8,067



15,830




   Other (income) expense

6,759



(1,029)



935


   Income tax expense

51,251



64,048



16,691


   Interest expense

22,682



20,478



741


   Depreciation, depletion and amortization

138,930



131,463



64,590


Adjusted EBITDA

$153,410



$217,540



$123,848


Free Cash Flow. Free cash flow was $18.0 million for the three months ended June 30, 2020. Free cash flow is reconciled to operating cash flow in the following table:



Three Months Ended



June 30, 2020



(In thousands)

Net cash provided by operating activities


$97,801


Changes in working capital and other


40,078


Change in accrued hedge settlement


(14,480)


Cash interest expense


21,944


Merger and integration expense


8,067


Adjusted EBITDA


153,410


Less: Operational capital (accrual)


85,087


Less: Capitalized interest


20,924


Less: Interest expense


22,682


Less: Capitalized cash G&A (excludes stock-based compensation)


6,740


Free cash flow


$17,977


Adjusted Discretionary Cash Flow. Operating cash flow was $97.8 million and adjusted discretionary cash flow was $142.7 million for the three months ended June 30, 2020. Adjusted discretionary cash flow is reconciled to operating cash flow in the following table:


Three Months Ended


June 30, 2020


March 31, 2020


June 30, 2019


(In thousands)

Cash flows from operating activities:






Net income (loss)

($1,564,731)



$216,565



$55,180


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






   Depreciation, depletion and amortization

138,930



131,463



64,590


   Impairment of evaluated oil and gas properties

1,276,518






   Amortization of non-cash debt related items

738



407



741


   Deferred income tax expense

51,251



64,048



16,691


   (Gain) loss on derivative contracts

126,965



(251,969)



(14,036)


   Cash (paid) received for commodity derivative settlements, net

98,688



2,613



(1,157)


   (Gain) loss on sale of other property and equipment





21


   Non-cash stock-based compensation expense (benefit)

2,761



(2,972)



904


   Non-cash loss on early extinguishment of debt






   Merger and integration expense

8,067



15,830




   Other, net

3,521



890




Adjusted discretionary cash flow

$142,708



$176,875



$122,934


   Changes in working capital

(36,839)



31,404



27,789


   Payments to settle asset retirement obligations





(107)


   Merger and integration expense

(8,067)



(15,830)




   Payments to settle vested liability share-based awards

(1)



(754)



(129)


Net cash provided by operating activities

$97,801



$191,695



$150,487


Adjusted Total Revenue. Adjusted total revenue for the three months ended June 30, 2020 was $241.4 million and is reconciled to total operating revenues in the following table:



Three Months Ended



June 30, 2020


March 31, 2020


June 30, 2019



(In thousands)

Operating Revenues







Oil


$130,513



$265,767



$160,728


Natural gas


12,242



6,029



6,324


Natural gas liquids


14,479



18,123




Total operating revenues


$157,234



$289,919



$167,052


Gain (loss) on commodity derivative settlements, net


84,208



25,126



(1,157)


Adjusted total revenue


$241,442


$315,045


$165,895


 

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and per share data)

(Unaudited)




June 30, 2020


December 31, 2019

ASSETS





Current assets:





Cash and cash equivalents


$7,500



$13,341


Accounts receivable, net


95,839



209,463


Fair value of derivatives


31,563



26,056


Other current assets


28,828



19,814


Total current assets


163,730



268,674


Oil and natural gas properties, full cost accounting method:





Evaluated properties


3,777,956



4,682,994


Unevaluated properties


1,762,860



1,986,124


Total oil and natural gas properties, net


5,540,816



6,669,118


Operating lease right-of-use assets


35,926



63,908


Other property and equipment, net


32,444



35,253


Deferred tax asset




115,720


Deferred financing costs


25,993



22,233


Other assets, net


11,224



19,932


   Total assets


$5,810,133



$7,194,838


LIABILITIES AND STOCKHOLDERS' EQUITY





Current liabilities:





Accounts payable and accrued liabilities


$405,596



$511,622


Operating lease liabilities


24,355



42,858


Fair value of derivatives


32,683



71,197


Other current liabilities


15,053



26,570


Total current liabilities


477,687



652,247


Long-term debt


3,350,730



3,186,109


Operating lease liabilities


30,729



37,088


Asset retirement obligations


48,765



48,860


Fair value of derivatives


8,678



32,695


Other long-term liabilities


12,160



14,531


Total liabilities


3,928,749



3,971,530


Commitments and contingencies





Stockholders' equity:





Common stock, $0.01 par value, 525,000,000 shares authorized; 397,396,922 and    396,600,022 shares outstanding, respectively


3,974



3,966


Capital in excess of par value


3,204,310



3,198,076


Retained earnings (Accumulated deficit)


(1,326,900)



21,266


Total stockholders' equity


1,881,384



3,223,308


Total liabilities and stockholders' equity


$5,810,133



$7,194,838


 

Callon Petroleum Company

Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)



Three Months Ended
June 30,


Six Months Ended
June 30,


2020


2019


2020


2019

Operating revenues:








Oil

$130,513



$160,728



$396,280



$301,826


Natural gas

12,242



6,324



18,271



18,273


Natural gas liquids

14,479





32,602




Total operating revenues

157,234



167,052



447,153



320,099


Operating Expenses:








Lease operating

50,838



22,776



103,221



46,843


Production and ad valorem taxes

10,361



11,131



30,041



21,944


Gathering, transportation and processing

20,037





34,415




Depreciation, depletion and amortization

138,930



63,137



270,393



123,145


General and administrative

10,024



10,564



18,349



25,341


Impairment of evaluated oil and gas properties

1,276,518





1,276,518




Merger and integration expenses

8,067





23,897




Other operating

4,135



935



4,135



1,092


Total operating expenses

1,518,910



108,543



1,760,969



218,365


Income (Loss) From Operations

(1,361,676)



58,509



(1,313,816)



101,734










Other (Income) Expenses:








Interest expense, net of capitalized amounts

22,682



741



43,160



1,479


(Gain) loss on derivative contracts

126,965



(14,036)



(125,004)



53,224


Other (income) expense

2,157



(67)



895



(148)


Total other (income) expense

151,804



(13,362)



(80,949)



54,555










Income (Loss) Before Income Taxes

(1,513,480)



71,871



(1,232,867)



47,179


Income tax expense

(51,251)



(16,691)



(115,299)



(11,542)


Net Income (Loss)

(1,564,731)



55,180



(1,348,166)



35,637


Preferred stock dividends



(1,823)





(3,647)


Income (Loss) Available to Common Stockholders

($1,564,731)



$53,357



($1,348,166)



$31,990










Income (Loss) Available to Common Stockholders Per Common Share:








Basic

($3.94)



$0.23



($3.40)



$0.14


Diluted

($3.94)



$0.23



($3.40)



$0.14


Weighted Average Common Shares Outstanding:








Basic

397,084



228,051



396,884



227,917


Diluted

397,084



228,411



396,884



228,599


 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)



Three Months Ended June
30,


Six Months Ended June
30,


2020


2019


2020


2019

Cash flows from operating activities:








Net income (loss)

($1,564,731)



$55,180



($1,348,166)



$35,637


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








Depreciation, depletion and amortization

138,930



64,590



270,393



125,503


Impairment of evaluated oil and gas properties

1,276,518





1,276,518




Amortization of non-cash debt related items

738



741



1,145



1,479


Deferred income tax expense

51,251



16,691



115,299



11,542


(Gain) loss on derivative contracts

126,965



(14,036)



(125,004)



53,224


Cash (paid) received for commodity derivative settlements

98,688



(1,157)



101,301



(1,447)


Loss on sale of other property and equipment



21





49


Non-cash expense related to equity share-based awards

1,041



1,754



4,817



6,299


Change in the fair value of liability share-based awards

1,720



(850)



(5,028)



1,031


Payments to settle asset retirement obligations



(107)





(771)


Payments for cash-settled restricted stock unit awards

(1)



(129)



(755)



(1,425)


Other, net

3,521





4,411




Changes in current assets and liabilities:








Accounts receivable

(2,833)



44,071



113,040



38,681


Other current assets

(3,567)



(3,807)



(4,348)



(6,101)


Current liabilities

(30,439)



(10,251)



(114,127)



(36,254)


Other



(2,224)





(2,401)


Net cash provided by operating activities

97,801



150,487



289,496



225,046


Cash flows from investing activities:








Capital expenditures

(206,121)



(166,219)



(430,569)



(359,430)


Acquisitions



(11,423)





(39,370)


Proceeds from sale of assets

(161)



260,417



10,079



274,296


Cash paid for settlements of contingent consideration arrangements, net





(40,000)




Other, net

6,992





6,834




Net cash provided by (used in) investing activities

(199,290)



82,775



(453,656)



(124,504)


Cash flows from financing activities:








Borrowings on senior secured revolving credit facility

484,500



140,000



4,775,500



360,000


Payments on senior secured revolving credit facility

(384,500)



(365,000)



(4,610,500)



(455,000)


Payment of preferred stock dividends



(1,823)





(3,647)


Payment of deferred financing costs

(5,736)



(31)



(6,011)



(31)


Tax withholdings related to restricted stock units

(75)



(833)



(388)



(1,858)


Other, net



(5)



(282)



(5)


Net cash provided by (used in) financing activities

94,189



(227,692)



158,319



(100,541)


Net change in cash and cash equivalents

(7,300)



5,570



(5,841)



1


Balance, beginning of period

14,800



10,482



13,341



16,051


Balance, end of period

$7,500



$16,052



$7,500



$16,052


Non-GAAP Financial Measures

This news release refers to non-GAAP financial measures such as "Free Cash Flow," "Adjusted Discretionary Cash Flow," "Adjusted G&A," "Full Cash G&A Costs," "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.

  • Free Cash Flow is a supplemental non-GAAP measure that is defined by the Company as Adjusted EBITDA less operational capital, capitalized interest, net interest expense and capitalized G&A excluding capitalized expense related to share-based awards. We believe free 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. Free 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, or as a measure of liquidity, or as an alternative to net income (loss).

  • Adjusted Discretionary Cash Flow is a supplemental non-GAAP measure that Callon believes 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. Adjusted Discretionary Cash Flow is defined by Callon as net cash provided by operating activities before changes in working capital, merger and integration expenses, 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. Adjusted 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 non-cash valuation adjustments related to incentive compensation plans. 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 contained within this release details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.

  • Full Cash G&A Costs is a supplemental non-GAAP financial measure that Callon defines as Adjusted G&A – cash component plus capitalized G&A excluding capitalized expense related to share-based awards. Callon believes that the non-GAAP measure of Full Cash G&A Costs is useful because it provides users with a meaningful measure of our total recurring cash G&A costs, whether expensed or capitalized, and provides for greater comparability on a period-over-period basis. See the reconciliation provided above for further details.

  • Adjusted Income available to common stockholders ("Adjusted Income") and Adjusted Income per fully diluted common share are supplemental non-GAAP measures that Callon believes 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.

  • Adjusted diluted weighted average common shares outstanding ("Adjusted Diluted WASO") is a non-GAAP financial measure which includes the effect of potentially dilutive instruments that, under certain circumstances described below, are excluded from diluted weighted average common shares outstanding ("Diluted WASO"), the most directly comparable GAAP financial measure. When a loss available to common stockholders exists, all potentially dilutive instruments are anti-dilutive to the loss available to common stockholders per common share and therefore excluded from the computation of Diluted WASO. The effect of potentially dilutive instruments are included in the computation of Adjusted Diluted WASO for purposes of computing Adjusted Income per fully diluted common share.

  • Callon calculates adjusted earnings before interest, income taxes, depreciation, depletion and amortization ("Adjusted EBITDA") as net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization, (gains) losses on derivative instruments excluding net settled derivative instruments, non-cash stock-based compensation expense, merger and integration expense, loss on extinguishment of debt, and other operating expenses. 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.

About Callon Petroleum Company

Callon Petroleum is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and 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 Information

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 the Company's wells anticipated to be drilled and placed on production; future levels of drilling activity and associated production and cash flow expectations; the Company's production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; anticipated returns and financial position; and the implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," "may," "will," "forecast," "outlook," "plans" and words of similar meaning. These statements reflect the Company'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, as of this date, 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 of which such statement is made and the Company 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 our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil, natural gas and natural gas liquids ("NGLs") prices or a prolonged period of low oil, natural gas or NGLs prices and the effects of actions by, or disputes among or between significant oil and natural gas producing countries, general economic conditions, including the availability of credit and access to existing lines of credit; the effects of excess supply of oil and natural gas resulting from reduced demand caused by the COVID-19 pandemic and the actions of certain oil and natural gas producing countries; our ability to drill and complete wells; operational, regulatory and environment risks; cost and availability of equipment and labor; our ability to finance our activities; the ultimate timing, outcome and results of integrating the operations of Carrizo Oil & Gas, Inc. and Callon; and the ability of the combined company to realize anticipated synergies and other benefits in the timeframe expected or at all; and other risks more fully discussed in our filings with the Securities and Exchange Commission (the "SEC"), including our most recent Annual Report on Form 10-K and Quarterly Report on Form 10-Q and subsequent 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
(281) 589-5200

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

 

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SOURCE Callon Petroleum Company