Callon Petroleum Company Announces First Quarter 2021 Results

HOUSTON, May 5, 2021 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months ended March 31, 2021.

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.

First Quarter 2021 and Recent Highlights

  • Delivered production of approximately 81.0 MBoe/d (64% oil) in the first quarter of 2021
  • Generated net cash provided by operating activities of $137.7 million and adjusted free cash flow1 of $24.2 million
  • Net loss of $80.4 million, or $1.89 per diluted share, driven primarily by a loss on derivative contracts of $214.5 million, adjusted EBITDA1 of $170.6 million, and adjusted income1 of $70.0 million, or $1.49 per diluted share
  • Achieved an operating margin of $33.46 per Boe, a 58% increase from the previous quarter
  • Entered into purchase and sale agreements for certain non-core Delaware Basin properties for aggregate proceeds of approximately $40 million
  • Completed the spring redetermination of Callon's senior secured credit facility with the borrowing base and elected commitment reaffirmed at $1.6 billion with unanimous lender support
  • Executed Callon's first E-frac of a multi-well, multi-zone pad in the Midland Basin powered by field-produced natural gas

Joe Gatto, President and Chief Executive Officer commented, "The first quarter showcased our team's highly efficient resource development model and operating cost management, underpinned by consistent well performance from our multi-zone, life of field development program. We continued to generate positive free cash flow, even with the effects of the extreme winter weather significantly impacting our production for the quarter. In addition to further reducing the outstanding balance on our credit facility, we recently entered into purchase and sale agreements for non-core Western Delaware Basin acreage for estimated proceeds of approximately $40 million as we methodically advance our monetization goals in an improving market environment. We remain steadfast in our commitment to disciplined rates of capital reinvestment and see a clear path to an accelerated pace of absolute debt reduction and credit metric improvements in the coming quarters."

He continued, "We recently issued our annual meeting proxy statement which outlined the extensive realignment of both our short and long-term compensation programs with critical elements of sustainability and corporate level returns. In addition, we outlined a targeted 40% to 50% in greenhouse gas emissions reductions, including the elimination of all routine field flaring, which we expect to achieve by 2025. We will provide valuable additional disclosure regarding our environmental, social and governance performance and initiatives in our 2021 sustainability report which we expect to issue in June."

Sale of Delaware Basin Assets

During April, Callon executed purchase and sale agreements covering certain non-core assets in the Delaware Basin. Aggregate proceeds for the combined transactions are approximately $40 million. The transactions are primarily comprised of natural gas producing properties in the Western Delaware Basin and also include a small undeveloped acreage position. Current production related to the divestitures are approximately 3,400 Boe/d (~25% oil). The pending transactions will result in an improvement in operating margins and have a de minimis impact on forecasted corporate free cash flow generation.

Credit Facility and Liquidity

Callon recently completed the spring redetermination for its senior secured credit facility. The borrowing base and elected commitment were both reaffirmed at $1.6 billion. As of March 31, 2021, the drawn balance on the facility was $950.0 million and cash balances were approximately $25 million.

Operations Update

At March 31, 2021, Callon had 1,510 gross (1,333.9 net) wells producing from established flow units in the Permian and Eagle Ford. Net daily production for the three months ended March 31, 2021 was 81.0 MBoe/d (64% oil) reflecting an estimated 8 MBoe/d impact from winter storm Uri during the quarter.

For the three months ended March 31, 2021, Callon drilled 18 gross (16.4 net) wells and placed a combined 14 gross (13.3 net) wells on production. Wells placed on production during the quarter were completed in the Eagle Ford in South Texas and the Wolfcamp A, B, and C in the Delaware Basin. The Company expects to operate an average of three drilling rigs throughout the remainder of 2021 and will average just over two completion crews through the second quarter before reducing to one completion crew during the third quarter.

During the first quarter, Callon focused early completion activity on the Eagle Ford with ten gross wells completed and placed on production during the quarter, including the Gardendale four-well pad which averaged more than 12,000 feet per lateral. Towards the end of the quarter, the Company initiated its first completion utilizing an all-electric frac fleet. In total, the project deployed more than 160 completion stages across three wells targeting the Lower Spraberry, Wolfcamp A, and Wolfcamp B in the Midland Basin. The fleet was powered using field-produced natural gas from Callon's local gathering system, resulting in the avoidance of more than 270,000 gallons of diesel fuel usage.

Capital Expenditures

For the three months ended March 31, 2021, Callon incurred $95.5 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 March 31, 2021



Operational


Capitalized


Capitalized


Total Capital



Capital (a)


Interest


G&A


Expenditures



(In thousands)

Cash basis (b)


$81,630



$12,798



$6,913



$101,341


Timing adjustments (c)


19,331



9,018





28,349


Non-cash items


(5,416)



2,222



4,308



1,114


   Accrual basis


$95,545



$24,038



$11,221



$130,804




(a)

Includes drilling, completions, facilities, and equipment, but excludes land and seismic.

(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.

Guidance

For the second quarter, including the impact of the pending divestitures expected to close by early June, the Company expects to produce between 88.0 and 89.5 MBoe per day (64% oil). In addition, Callon projects an operational capital spending level of between $135 and $145 million on an accrual basis, resulting in approximately 55% of the 2021 annual capital budget allocated to first half activity. Full year 2021 guidance has been updated below, pending the closing of the announced Delaware asset divestitures.



Full Year 2021 Guidance



Prior


Pending

Total production (MBoe/d)


90.0 - 92.0


89.0 - 91.0

Oil


63%


64%

NGL


18%


19%

Natural gas


19%


17%

Income statement expenses (in millions except where noted)





LOE, including workovers


$190.0 - $210.0


$185.0 - $205.0

Gathering, transportation and processing


$70.0 - $80.0


$67.5 - $77.5

Production and ad valorem taxes (% of total oil, natural gas and NGL revenues)


6.5%


6.5%

Adjusted G&A: cash component (a)


$35.0 - $45.0


$35.0 - $45.0

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


$5.0 - $15.0


$5.0 - $15.0

Cash interest expense, net


$80.0 - $90.0


$80.0 - $90.0

Estimated effective income tax rate


22%


22%

Capital expenditures (in millions, accrual basis)





Total operational capital (c)


$430.0


$430.0

Capitalized interest(d)


$95.0 - $105.0


$95.0 - $105.0

Capitalized G&A


$28.0 - $38.0


$28.0 - $38.0

Gross operated wells drilled / completed


55 - 65 / 90 - 100


55 - 65 / 90 - 100



(a)

Excludes the change in fair value and amortization of share-based incentive awards and other non-recurring expenses.

(b)

Amortization of equity-settled, share-based incentive awards and other non-recurring expenses.

(c)

Includes drilling, completions, facilities, and equipment, but excludes land, seismic, and capitalized expenses.

(d)

Capitalized interest includes both cash and non-cash capitalized items.

Hedge Portfolio Summary

As of April 30, 2021, Callon had the following outstanding oil, natural gas and NGL derivative contracts:


For the Remainder


For the Full Year


Oil contracts (WTI)

of 2021(a)


of 2022(a)


   Swap contracts





   Total volume (Bbls)

1,832,000



225,000



   Weighted average price per Bbl

$43.24



$60.00



   Collar contracts





   Total volume (Bbls)

8,298,800



2,032,500



   Weighted average price per Bbl





   Ceiling (short call)

$48.30



$61.11



   Floor (long put)

$40.24



$47.22



   Short call contracts





   Total volume (Bbls)

2,432,480


(b)



   Weighted average price per Bbl

$63.62



$—



Short call swaption contracts





   Total volume (Bbls)



1,825,000


(c)

   Weighted average price per Bbl

$—



$52.18








Oil contracts (Brent ICE)





   Swap contracts





   Total volume (Bbls)

221,300


(d)



   Weighted average price per Bbl

$37.35



$—



Collar contracts





Total volume (Bbls)

550,000





Weighted average price per Bbl





Ceiling (short call)

$50.00



$—



Floor (long put)

$45.00



$—








Oil contracts (Midland basis differential)





   Swap contracts





   Total volume (Bbls)

2,171,900





   Weighted average price per Bbl

$0.24



$—








Oil contracts (Argus Houston MEH)





   Collar contracts





   Total volume (Bbls)

409,500



452,500



   Weighted average price per Bbl





Ceiling (short call)

$47.00



$63.15



Floor (long put)

$41.00



$51.25



_______________

(a)

The Company has approximately $15.0 million of deferred premiums, of which $12.1 million are associated with contracts that will settle in 2021 and $2.9 million for contracts that will settle in 2022.

(b)

Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.

(c)

The short call swaption contracts have an exercise expiration date of December 31, 2021.

(d)

In February 2021, the Company entered into certain offsetting ICE Brent swaps to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss of approximately $2.9 million, of which $1.6 million will be settled in the third quarter of 2021 with the remaining $1.3 million to be settled in the fourth quarter of 2021.






For the Remainder


For the Full Year


Natural gas contracts (Henry Hub)

of 2021


of 2022


   Swap contracts





      Total volume (MMBtu)

11,123,000





      Weighted average price per MMBtu

$2.60



$—



Collar contracts





      Total volume (MMBtu)

5,500,000



2,700,000



      Weighted average price per MMBtu





         Ceiling (short call)

$2.80



$3.75



         Floor (long put)

$2.50



$2.77



   Short call contracts





      Total volume (MMBtu)

5,500,000


(a)



      Weighted average price per MMBtu

$3.09



$—








Natural gas contracts (Waha basis differential)





   Swap contracts





      Total volume (MMBtu)

12,375,000



5,475,000



      Weighted average price per MMBtu

($0.42)



($0.21)



___________

(a)

Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.






For the Remainder


For the Full Year


NGL contracts (OPIS Mont Belvieu Purity Ethane)

of 2021


of 2022


   Swap contracts





      Total volume (Bbls)

1,375,000





      Weighted average price per Bbl

$7.62



$—



Operating and Financial Results

The following table presents summary information for the periods indicated: 



Three Months Ended




March 31, 2021


December 31, 2020


March 31, 2020


Total production








Oil (MBbls)








Permian


3,088


3,445


3,594


Eagle Ford


1,593


1,980


2,253


Total oil (MBbls)


4,681


5,425


5,847










Natural gas (MMcf)








Permian


6,208


7,474


8,009


Eagle Ford


1,627


2,264


1,784


Total natural gas (MMcf)


7,835


9,738


9,793










NGLs (MBbls)








Permian


1,075


1,331


1,368


Eagle Ford


224


353


339


Total NGLs (MBbls)


1,299


1,684


1,707










Total production (MBoe)








Permian


5,198


6,022


6,297


Eagle Ford


2,088


2,710


2,889


Total barrels of oil equivalent (MBoe)


7,286


8,732


9,186










Total daily production (Boe/d)








Permian


57,758


65,459


69,203


Eagle Ford


23,199


29,455


31,752


Total barrels of oil equivalent (Boe/d)


80,957


94,914


100,955


Oil as % of total daily production


64

%


62

%


64

%









Average realized sales price

(excluding impact of settled derivatives)








Oil (per Bbl)








Permian


$56.66


$41.02


$45.61


Eagle Ford


57.80


41.12


45.21


Total oil (per Bbl)


$57.05


$41.06


$45.45










Natural gas (per Mcf)








Permian


$3.11


$1.68


$0.33


Eagle Ford


3.03


2.65


1.88


Total natural gas (per Mcf)


$3.09


$1.91


$0.62










NGLs (per Bbl)








Permian


$22.68


$15.00


$11.02


Eagle Ford


22.24


16.16


9.00


Total NGLs (per Bbl)


$22.60


$15.24


$10.62










Average realized sales price (per Boe)








Permian


$42.06


$28.87


$28.85


Eagle Ford


48.85


34.36


37.48


Total average realized sales price (per Boe)


$44.01


$30.57


$31.56










Average realized sales price

(including impact of settled derivatives)








Oil (per Bbl)


$44.33


$39.62


$48.90


Natural gas (per Mcf)


2.88


1.89


1.13


NGLs (per Bbl)


21.77


15.24


10.62


Total average realized sales price (per Boe)


$35.46


$29.66


$34.30












Three Months Ended




March 31, 2021


December 31, 2020


March 31, 2020


Revenues (in thousands)(a)








Oil








Permian


$174,967


$141,320


$163,906


Eagle Ford


92,078


81,413


101,861


Total oil


$267,045


$222,733


$265,767










Natural gas








Permian


$19,290


$12,560


$2,675


Eagle Ford


4,930


6,001


3,354


Total natural gas


$24,220


$18,561


$6,029










NGLs








Permian


$24,376


$19,964


$15,072


Eagle Ford


4,981


5,704


3,051


Total NGLs


$29,357


$25,668


$18,123










Total revenues








Permian


$218,633


$173,844


$181,653


Eagle Ford


101,989


93,118


108,266


Total revenues


$320,622


$266,962


$289,919










Additional per Boe data








Sales price (b)








Permian


$42.06


$28.87


$28.85


Eagle Ford


48.85


34.36


37.48


Total sales price


$44.01


$30.57


$31.56










Lease operating








Permian


$4.31


$4.43


$5.00


Eagle Ford


8.65


6.77


7.24


Total lease operating


$5.55


$5.15


$5.70










Production and ad valorem taxes








Permian


$2.32


$1.71


$1.99


Eagle Ford


3.07


2.29


2.47


Total production and ad valorem taxes


$2.53


$1.89


$2.14










Gathering, transportation and processing








Permian


$2.54


$2.42


$1.87


Eagle Ford


2.29


2.25


0.89


Total gathering, transportation and processing


$2.47


$2.37


$1.57










Operating margin








Permian


$32.89


$20.31


$19.99


Eagle Ford


34.84


23.05


26.88


Total operating margin


$33.46


$21.16


$22.15










   Depreciation, depletion and amortization


$9.74


$11.00


$14.31


   General and administrative


$2.31


$1.22


$0.91


   Adjusted G&A 1








      Cash component (c)


$1.26


$0.86


$1.20


      Non-cash component


$0.23


$0.07


$0.41




(a)

Excludes sales of oil and gas purchased from third parties.

(b)

Excludes the impact of settled derivatives.

(c)

Excludes the change in fair value and amortization of share-based incentive awards and other non-recurring expenses.

Revenue. For the quarter ended March 31, 2021, Callon reported revenue of $320.6 million, which excluded revenue from sales of commodities purchased from a third party of $39.3 million. Revenues including the gain or loss from the settlement of derivative contracts ("Adjusted Total Revenue"1) were $258.3 million, reflecting the impact of a $62.3 million loss from the settlement of derivative contracts. Average daily production for the quarter was 81.0 MBoe/d, compared to average daily production of 94.9 MBoe/d in the fourth quarter of 2020. Average realized prices, including and excluding the effects of hedging, are detailed above.

Commodity Derivatives. For the quarter ended March 31, 2021, the net loss on commodity derivative contracts includes the following (in thousands):


Three Months Ended
March 31, 2021

Loss on oil derivatives

$149,561


Loss on natural gas derivatives

2,697


Loss on NGL derivatives

1,138


Loss on commodity derivative contracts

$153,396


For the quarter ended March 31, 2021, the cash paid for commodity derivative settlements includes the following (in thousands):


Three Months Ended
March 31, 2021

Cash paid on oil derivatives

($39,947)


Cash paid on natural gas derivatives

(1,369)


Cash paid on NGL derivatives

(846)


Cash paid for commodity derivative settlements, net

($42,162)


Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended March 31, 2021 was $5.55 per Boe, compared to LOE of $5.15 per Boe in the fourth quarter of 2020. The increase in LOE per Boe was primarily due to increased workover costs as well as the distribution of fixed costs spread over lower production volumes.

Production and Ad Valorem Taxes. Production and ad valorem taxes were $2.53 per Boe for the three months ended March 31, 2021, representing approximately 5.8% of revenue excluding revenue from sales of commodities purchased from a third-party and before the impact of derivative settlements.

Gathering, Transportation and Processing. Gathering, transportation and processing for the three months ended March 31, 2021 was $18.0 million as compared to $20.7 million in the fourth quarter of 2020. This decrease is primarily related to the 17% decrease in production volumes between the two periods.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended March 31, 2021 was $9.74 per Boe compared to $11.00 per Boe in the fourth quarter of 2020. The decrease in DD&A was primarily driven by the impairment of evaluated oil and gas properties recognized in the fourth quarter of 2020.  

General and Administrative Expense ("G&A"). G&A for the three months ended March 31, 2021 and December 31, 2020 was $16.8 million, or $2.31 per Boe, and $10.6 million, or $1.22 per Boe, respectively. G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A" 1) was $10.9 million, or $1.49 per Boe, for the three months ended March 31, 2021 compared to $8.1 million, or $0.93 per Boe, for the fourth quarter of 2020. The cash component of Adjusted G&A increased to $9.2 million, or $1.26 per Boe, for the three months ended March 31, 2021 compared to $7.5 million, or $0.86 per Boe, for the fourth quarter of 2020 primarily as a result of additional personnel costs.

The following table reconciles total G&A to Adjusted G&A - cash component and full cash G&A (in thousands):


Three Months Ended


March 31, 2021


December 31, 2020

Total G&A

$16,799



$10,614


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

(5,943)



(2,500)


Adjusted G&A – total

10,856



8,114


Equity-settled, share-based compensation (non-cash) and other non-recurring expenses

(1,665)



(580)


Adjusted G&A – cash component

$9,191



$7,534






Capitalized cash G&A

$6,913



$6,465


Full cash G&A

$16,104



$13,999


Income Tax. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. We recorded an income tax benefit of $0.9 million for the three months ended March 31, 2021, compared to income tax expense of $6.8 million for the three months ended December 31, 2020. The income tax benefit during the first quarter of 2021 was due to the  valuation allowance against our deferred tax assets while the income tax expense in the fourth quarter of 2020 was due to an increase in the deferred tax assets acquired in the Carrizo Acquisition due to the filing of the final tax returns in the fourth quarter of 2020 which provided the underlying tax basis of Carrizo's assets and liabilities and the subsequent valuation allowance against those deferred tax assets.

Adjusted EBITDA. Adjusted EBITDA for the first quarter of 2021 was $170.6 million as compared to $167.8 million for the fourth quarter of 2020. The increase in adjusted EBITDA from the fourth quarter of 2020 was primarily due to an increase in revenues partially offset by increased payments associated with our commodity derivative settlements.

Adjusted Income and Adjusted EBITDA. The Company reported net loss of $80.4 million, for the three months ended March 31, 2021, or $1.89 per diluted share, and adjusted income of $70.0 million, or $1.49 per diluted share. The following tables reconcile the Company's net income (loss) to adjusted income, and the Company's net income (loss) to adjusted EBITDA:


Three Months Ended


March 31, 2021


December 31, 2020


March 31, 2020


(In thousands, except per share data)

Net income (loss)

($80,407)



($505,071)



$216,565


(Gain) loss on derivative contracts

214,523



125,739



(251,969)


Gain (loss) on commodity derivative settlements, net

(62,280)



(7,938)



25,126


Non-cash stock-based compensation expense (benefit)

7,608



2,968



(2,972)


Impairment of evaluated oil and gas properties



585,767




Merger and integration expense



2,120



15,830


Other (income) expense

(3,306)



5,328



(1,029)


Gain on extinguishment of debt



(170,370)




Tax effect on adjustments above(a)

(32,874)



(114,159)



45,153


Change in valuation allowance

26,724



118,388




Adjusted income

$69,988



$42,772



$46,704


Adjusted income per diluted share

$1.49



$1.00



$1.18








Basic WASO(b)

42,590



39,752



39,667


Diluted WASO (GAAP)(b)

42,590



39,752



39,684


Effect of potentially dilutive instruments(b)

4,354



2,892




Adjusted Diluted WASO(b)

46,944



42,644



39,684




(a)

Calculated using the federal statutory rate of 21%.

(b)

All share and per share amounts have been retroactively adjusted for the Company's 1-for-10 reverse stock split effective August 7, 2020.






Three Months Ended


March 31, 2021


December 31, 2020


March 31, 2020


(In thousands)

Net income (loss)

($80,407)



($505,071)



$216,565


   (Gain) loss on derivative contracts

214,523



125,739



(251,969)


   Gain (loss) on commodity derivative settlements, net

(62,280)



(7,938)



25,126


   Non-cash stock-based compensation expense (benefit)

7,608



2,968



(2,972)


 Impairment of evaluated oil and gas properties



585,767




   Merger and integration expense



2,120



15,830


   Other (income) expense

(3,306)



5,328



(1,029)


   Income tax (benefit) expense

(921)



6,755



64,048


   Interest expense

24,416



26,486



20,478


   Depreciation, depletion and amortization

70,987



96,037



131,463


   Gain on extinguishment of debt



(170,370)




Adjusted EBITDA

$170,620



$167,821



$217,540


Adjusted Free Cash Flow. Adjusted free cash flow for the three months ended March 31, 2021 was $24.2 million. The following table reconciles the Company's net cash provided by operating activities to adjusted EBITDA and adjusted free cash flow:


Three Months Ended


March 31, 2021


December 31, 2020


March 31, 2020


(In thousands)

Net cash provided by operating activities

$137,665



$134,578



$191,695


Changes in working capital and other

30,913



12,011



(32,569)


Change in accrued hedge settlements

(20,117)



(5,055)



22,513


Cash interest expense, net

22,159



24,167



20,071


Merger and integration expense



2,120



15,830


Adjusted EBITDA

170,620



167,821



217,540


Less: Operational capital expenditures (accrual)

95,545



87,488



277,640


Less: Capitalized interest

21,817



23,015



23,985


Less: Interest expense, net of capitalized amounts

22,159



26,486



20,478


Less: Capitalized cash G&A

6,913



6,465



7,371


Adjusted free cash flow (a)

$24,186



$24,367



($111,934)




(a)

Effective January 1, 2021, non-cash interest expense amounts consisting primarily of amortization of debt issuance costs, premiums, and discounts associated with our long-term debt are excluded from our calculation of adjusted free cash flow.

Adjusted Discretionary Cash Flow. For the three months ended March 31, 2021, net cash provided by operating activities was $137.7 million and adjusted discretionary cash flow was $174.0 million. The reconciliation of net cash provided by operating activities to adjusted discretionary cash flow is presented in the following table: 


Three Months Ended


March 31, 2021


December 31, 2020


March 31, 2020


(In thousands)

Cash flows from operating activities:






Net income (loss)

($80,407)



($505,071)



$216,565


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






   Depreciation, depletion and amortization

70,987



96,037



131,463


   Impairment of evaluated oil and gas properties



585,767




   Amortization of non-cash debt related items

2,256



2,319



407


   Deferred income tax expense



3,308



64,048


   (Gain) loss on derivative contracts

214,523



125,739



(251,969)


   Cash (paid) received for commodity derivative settlements, net

(42,162)



(2,884)



2,613


   Non-cash stock-based compensation expense (benefit)

7,608



2,968



(2,972)


   Non-cash loss on early extinguishment of debt



(170,370)




   Merger and integration expense



2,120



15,830


   Other, net

1,217



1,347



890


Adjusted discretionary cash flow

$174,022



$141,280



$176,875


   Changes in working capital

(36,357)



(4,582)



30,650


   Merger and integration expense



(2,120)



(15,830)


Net cash provided by operating activities

$137,665



$134,578



$191,695


Adjusted Total Revenue. Adjusted total revenue for the three months ended March 31, 2021 was $258.3 million and is reconciled to total operating revenues, which excludes revenue from sales of commodities purchased from a third party, in the following table:



Three Months Ended



March 31, 2021


December 31, 2020


March 31, 2020



(In thousands)

Operating revenues







Oil


$267,045



$222,733



$265,767


Natural gas


24,220



18,561



6,029


NGLs


29,357



25,668



18,123


Total operating revenues


$320,622



$266,962



$289,919


Impact of settled derivatives


(62,280)



(7,938)



25,126


Adjusted total revenue


$258,342



$259,024



$315,045


 

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and per share data)

(Unaudited)




March 31, 2021


December 31, 2020

ASSETS





Current assets:





Cash and cash equivalents


$24,350



$20,236


Accounts receivable, net


179,127



133,109


Other current assets


32,878



25,024


Total current assets


236,355



178,369


Oil and natural gas properties, full cost accounting method:





Evaluated properties, net


2,394,339



2,355,710


Unevaluated properties


1,754,768



1,733,250


Total oil and natural gas properties, net


4,149,107



4,088,960


Other property and equipment, net


31,435



31,640


Deferred financing costs


22,177



23,643


Other assets, net


37,792



40,256


Total assets


$4,476,866



$4,362,868


LIABILITIES AND STOCKHOLDERS' EQUITY





Current liabilities:





Accounts payable and accrued liabilities


$374,749



$341,519


Fair value of derivatives


224,446



97,060


Other current liabilities


72,854



58,529


Total current liabilities


672,049



497,108


Long-term debt


2,937,239



2,969,264


Asset retirement obligations


55,935



57,209


Fair value of derivatives


1,400



88,046


Other long-term liabilities


42,221



40,239


Total liabilities


3,708,844



3,651,866


Commitments and contingencies





Stockholders' equity:





Common stock, $0.01 par value, 52,500,000 shares authorized; 46,156,854 and    39,758,817 shares outstanding, respectively


462



398


Capital in excess of par value


3,360,322



3,222,959


Accumulated deficit


(2,592,762)



(2,512,355)


Total stockholders' equity


768,022



711,002


Total liabilities and stockholders' equity


$4,476,866



$4,362,868


 

Callon Petroleum Company

Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)



Three Months Ended
March 31,


2021


2020

Operating Revenues:




Oil

$267,045



$265,767


Natural gas

24,220



6,029


Natural gas liquids

29,357



18,123


  Sales of purchased oil and gas

39,259




  Total operating revenues

359,881



289,919


Operating Expenses:




Lease operating

40,453



52,383


Production and ad valorem taxes

18,439



19,680


Gathering, transportation and processing

17,981



14,378


Cost of purchased oil and gas

40,917




Depreciation, depletion and amortization

70,987



131,463


General and administrative

16,799



8,325


Merger and integration



15,830


Other operating

929




  Total operating expenses

206,505



242,059


Income From Operations

153,376



47,860






Other (Income) Expenses:




Interest expense, net of capitalized amounts

24,416



20,478


(Gain) loss on derivative contracts

214,523



(251,969)


Other (income) expense

(4,235)



(1,262)


  Total other (income) expense

234,704



(232,753)






Income (Loss) Before Income Taxes

(81,328)



280,613


Income tax benefit (expense)

921



(64,048)


Net Income (Loss)

(80,407)



216,565






Net Income (Loss) Per Common Share (a):




Basic

($1.89)



$5.46


Diluted

($1.89)



$5.46


Weighted Average Common Shares Outstanding (a):




Basic

42,590



39,667


Diluted

42,590



39,684


_______________

(a)

All share and per share amounts have been retroactively adjusted for the Company's 1-for-10 reverse stock split effective August 7, 2020.

 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)



Three Months Ended
March 31,


2021


2020

Cash flows from operating activities:




Net income (loss)

($80,407)



$216,565


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




Depreciation, depletion and amortization

70,987



131,463


Amortization of non-cash debt related items, net

2,256



407


Deferred income tax expense



64,048


(Gain) loss on derivative contracts

214,523



(251,969)


Cash received (paid) for commodity derivative settlements, net

(42,162)



2,613


Non-cash expense related to share-based awards

7,608



(2,972)


Other, net

1,217



136


Changes in current assets and liabilities:




Accounts receivable

(45,683)



115,873


Other current assets

(2,856)



(781)


Accounts payable and accrued liabilities

12,182



(83,688)


Net cash provided by operating activities

137,665



191,695


Cash flows from investing activities:




Capital expenditures

(101,341)



(213,459)


Acquisition of oil and gas properties

(768)



(10,989)


Proceeds from sale of assets



10,240


Cash paid for settlements of contingent consideration arrangements, net



(40,000)


Other, net

3,595



(158)


Net cash used in investing activities

(98,514)



(254,366)


Cash flows from financing activities:




Borrowings on Credit Facility

303,000



4,291,000


Payments on Credit Facility

(338,000)



(4,226,000)


Other, net

(37)



(870)


Net cash provided by (used in) financing activities

(35,037)



64,130


Net change in cash and cash equivalents

4,114



1,459


Balance, beginning of period

20,236



13,341


Balance, end of period

$24,350



$14,800


Non-GAAP Financial Measures

This news release refers to non-GAAP financial measures such as "adjusted free cash flow," "adjusted discretionary cash flow," "adjusted G&A," "full cash G&A," "adjusted income," "adjusted income per diluted share," "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 filings with the U.S. Securities and Exchange Commission (the "SEC") and posted on our website.

  • Adjusted free cash flow is a supplemental non-GAAP measure that is defined by the Company as adjusted EBITDA less operational capital, cash capitalized interest, net cash interest expense and capitalized cash G&A (which excludes capitalized expense related to share-based awards). We believe adjusted 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. Adjusted 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 and merger and integration expenses. 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, or as a measure of liquidity, or as an alternative to net income (loss).
  • Adjusted G&A is a supplemental non-GAAP financial measure that excludes certain non-cash incentive share-based compensation valuation adjustments. Callon believes that the non-GAAP measure of adjusted G&A is useful to investors because it provides a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period.
  • Full cash G&A 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 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.
  • Adjusted income and adjusted income per diluted 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 these items and non-cash valuation adjustments, which are detailed in the reconciliation provided. Adjusted income and adjusted income per diluted share are not measures of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), or other income data prepared in accordance with GAAP. However, the Company believes that adjusted income and adjusted income per diluted share provide additional information with respect to our performance. Because adjusted income and adjusted income per diluted share exclude some, but not all, items that affect net income (loss) and may vary among companies, the adjusted income and adjusted income per diluted share presented above may not be comparable to similarly titled measures of other companies.
  • 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 net loss exists, all potentially dilutive instruments are anti-dilutive to the net loss 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 diluted share.
  • Callon calculates 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, impairment of evaluated oil and gas properties, non-cash stock-based compensation expense, merger and integration expense, (gain) 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 above may not be comparable to similarly titled measures of other companies.
  • Callon believes that the non-GAAP measure of adjusted total revenue (which is revenue including the gain or loss from the settlement of derivative contracts) 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. See the reconciliation provided above for further details.

Earnings Call Information

The Company will host a conference call on Thursday, May 6, 2021, to discuss first quarter 2021 financial and operating results, 2021 outlook, and current corporate strategy and initiatives.

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

Date/Time:

Thursday, May 6, 2021, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time)

Webcast:

Select "News and Events" under the "Investors" section of the Company's website: www.callon.com.

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

About Callon Petroleum Company

Callon Petroleum Company 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.

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 wells anticipated to be drilled and placed on production; future levels of development activity and associated production, capital expenditures and cash flow expectations; the Company's 2021 production expense guidance and capital expenditure guidance; 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," "may," "will," "should," "could," 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, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Any forward-looking statement speaks only as of the date on which such statement is made and 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 and natural gas prices; changes in the supply of and demand for oil and natural gas, including as a result of the COVID-19 pandemic and various governmental actions taken to mitigate its impact or actions by, or disputes among members of OPEC and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil; our ability to drill and complete wells; operational, regulatory and environment risks; the cost and availability of equipment and labor; our ability to finance our activities; and other risks more fully discussed in our filings with the SEC, including our most recent Annual Reports on Form 10-K 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" included within this release for related disclosures.

 

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SOURCE Callon Petroleum Company