CPE
$42.70
Callon Petroleum
$2.11
5.20%
Earnings Details
2nd Quarter June 2021
Wednesday, August 4, 2021 1:35:00 AM
Tweet Share Watch
Summary

Callon Petroleum Misses

Callon Petroleum (CPE) reported 2nd Quarter June 2021 earnings of $1.49 per share on revenue of $440.4 million. The consensus earnings estimate was $1.42 per share on revenue of $331.3 million. The Earnings Whisper number was $1.82 per share. Revenue grew 180.1% on a year-over-year basis.

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

Results
Reported Earnings
$1.49
Earnings Whisper
$1.82
Consensus Estimate
$1.42
Reported Revenue
$440.4 Mil
Revenue Estimate
$331.3 Mil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

Callon Petroleum Company Announces Second Quarter 2021 Results

HOUSTON, Aug. 4, 2021 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and six months ended June 30, 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.

Second Quarter 2021 and Recent Highlights

  • Delivered production of approximately 89.0 MBoe/d (63% oil) in the second quarter of 2021
  • Generated net cash provided by operating activities of $175.6 million and adjusted free cash flow1 of $6.9 million
  • Net loss of $11.7 million, or $0.25 per diluted share, driven primarily by a loss on derivative contracts of $190.5 million, adjusted EBITDA1 of $196.8 million, and adjusted income1 of $70.3 million, or $1.49 per diluted share
  • Achieved an operating margin of $37.76 per Boe, a 13% increase from the previous quarter
  • Completed the divestiture of certain non-core assets for aggregate net cash proceeds of $30.7 million
  • Issued $650 million of new 8.00% senior unsecured notes due 2028 and completed the redemption of the 6.25% senior unsecured notes due 2023
  • Received company credit rating upgrades from both Moody's and S&P following successful senior notes offering
  • Reduced the outstanding balance on Callon's senior secured credit facility to approximately $780 million, representing less than 50% utilization of the available capacity2
  • Executed Callon's largest multi-well project in history, the 29-well Irvin West project, driving robust production growth with July volumes estimated to be approximately 10% above second quarter average daily production
  • Issued the company's second annual sustainability report, highlighting meaningful improvement in key categories as well as incremental transparency measures and alignment with both SASB and TCFD reporting standards.

Joe Gatto, President and Chief Executive Officer, commented, "Our team advanced critical priorities during the second quarter, preparing ourselves for a very strong second half of 2021. We generated positive adjusted free cash flow for the fourth consecutive quarter, despite the second quarter being our highest projected capital spending period of the year. We actively managed our nearest maturities and further reduced our credit facility borrowings, both of which support a continued upward trajectory in our credit profile. The third quarter is off to a tremendous start with July production volumes well ahead of our second quarter average and our commodity price realizations are projected to benefit from the reduction in overall hedged production. Our adjusted free cash flow during the third and fourth quarter should further reduce our credit facility borrowings and continue to advance our deleveraging goals with the potential to accelerate that timeline through selective monetizations."

He continued, "We recently issued our 2020 Sustainability report showing meaningful improvement in numerous critical areas including greenhouse gas emissions reductions, flaring, and safety. In addition, we have aligned our disclosure with both the Sustainability Accounting Standards Board ("SASB") and the Task Force on Climate-Related Financial Disclosures ("TCFD") frameworks providing additional clarity and transparency on issues that our shareholders and stakeholders value. This represents another step towards achieving alignment with shareholder expectations."

Issuance of 2028 Senior Unsecured Notes and Redemption of 2023 Senior Unsecured Notes

On June 21, 2021, the Company entered into a Purchase Agreement where it issued $650.0 million in aggregate principal amount of 8.00% senior unsecured notes due 2028 (the "8.00% Senior Notes") through private placement, which closed on July 6, 2021 for net proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs.

Also on June 21, 2021, the Company delivered a redemption notice with respect to all $542.7 million of its outstanding 6.25% senior unsecured notes due 2023 (the "6.25% Senior Notes"), which became redeemable on July 21, 2021. The Company used a portion of the net proceeds from the 8.00% Senior Notes to redeem all of its outstanding 6.25% Senior Notes with the remaining proceeds used to partially repay amounts outstanding under its Credit Facility.

Following the issuance of the new 8.00% Senior Notes, Callon was upgraded by both Moody's and S&P at the corporate level due to improving credit metrics and corporate outlooks. Moody's raised Callon's corporate family ratings to B3 and S&P raised its issuer credit rating to B- with a stable outlook.

Credit Facility and Liquidity

On May 3, 2021, Callon 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 June 30, 2021, the drawn balance on the facility was $875.0 million and cash balances were $3.8 million. Upon completion of the redemption of the 6.25% Senior Notes, the remaining proceeds from the issuance of the 8.00% Senior Notes were used to repay outstanding borrowings on the credit facility further reducing the outstanding balance to approximately $780.0 million2.

Sale of Delaware Basin Assets

During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for aggregate net cash proceeds of $30.7 million, subject to post-closing adjustments. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position.

Operations Update

At June 30, 2021, Callon had 1,536 gross (1,359.2 net) wells producing from established flow units in the Permian and Eagle Ford. Net daily production for the three months ended June 30, 2021 was 89.0 MBoe/d (63% oil).

For the three months ended June 30, 2021, Callon drilled 8 gross (6.5 net) wells and placed a combined 47 gross (44.9 net) wells on production. Wells placed on production during the quarter were completed in the Eagle Ford in South Texas, the Delaware Basin and the Midland Basin.

During the second quarter, Callon placed on production 29 gross wells in the Eagle Ford as part of its Irvin West project, the largest horizontal well development project in Company history. With an average lateral length of approximately 6,200 feet, the project involved the completion of more than 760 unique frac stages and has demonstrated very solid productivity with current rates averaging approximately 400 barrels of oil per day per well.

In the Delaware Basin, the Company turned to production multi-well projects in both Reeves and Ward Counties. In Ward County, the Limber Pine project featured co-development of the Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A and Wolfcamp B. Initial production has been positive and the wells are currently slated to be converted to electric submersible pumps ("ESPs"), which have contributed to strong productivity increases across the Delaware asset base in recent quarters. The Bush Griffin project in Reeves county was placed on production in June and early time results are tracking ahead of estimates.

The only pad placed on production during the second quarter in the Midland Basin was the Chaparral three-well project targeting the Lower Spraberry, Wolfcamp A, and Wolfcamp B. The Chaparral project was a very successful first test of an E-Frac fleet employing a crew from US Well Services. Production from this pad has significantly exceeded production estimates producing an average of more than 90 MBoe per well through the first 75 days online.

Current planned development activity in the second half of 2021 will involve three to four drilling rigs with projects spanning the Eagle Ford, Midland Basin, and Delaware Basin. Completion activity and wells turned to production will focus more heavily on Midland Basin and Delaware Basin projects during the third and fourth quarters.


Capital Expenditures

For the three months ended June 30, 2021, Callon incurred $138.3 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, 2021



Operational


Capitalized


Capitalized


Total Capital



Capital (a)


Interest


G&A


Expenditures



(In thousands)

Cash basis (b)


$111,344



$30,914



$7,404



$149,662


Timing adjustments (c)


28,379



(9,174)





19,205


Non-cash items


(1,402)



2,187



4,647



5,432


   Accrual basis


$138,321



$23,927



$12,051



$174,299




(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 third quarter, the Company expects to produce between 95.5 and 97.5 MBoe per day (64% oil). In addition, Callon projects an operational capital spending level of between $120 and $130 million on an accrual basis.

Hedge Portfolio Summary

As of August 2, 2021, Callon had the following outstanding oil, natural gas and NGL derivative contracts:


For the Remainder


For the Full Year


For the Full Year


Oil contracts (WTI)

of 2021(a)


of 2022(a)


of 2023


   Swap contracts







   Total volume (Bbls)

1,104,000



3,015,000





   Weighted average price per Bbl

$42.10



$63.55



$—



   Collar contracts







   Total volume (Bbls)

5,522,775



7,097,500





   Weighted average price per Bbl







   Ceiling (short call)

$49.16



$67.70



$—



   Floor (long put)

$40.71



$56.15



$—



Long put contracts







Total volume (Bbls)

414,000







Weighted average price per Bbl

$62.50



$—



$—



   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)

1,825,000


(c)

   Weighted average price per Bbl

$—



$52.18



$72.00










Oil contracts (Brent ICE)







   Swap contracts







   Total volume (Bbls)


(d)





   Weighted average price per Bbl

$—



$—



$—



Collar contracts







Total volume (Bbls)

368,000







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)

1,504,400







   Weighted average price per Bbl

$0.25



$—



$—










Oil contracts (Argus Houston MEH)







   Collar contracts







   Total volume (Bbls)



452,500





   Weighted average price per Bbl







Ceiling (short call)

$—



$63.15



$—



Floor (long put)

$—



$51.25



$—














(a)

The Company has approximately $9.4 million of deferred premiums, of which $6.5 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 2022 and 2023 short call swaption contracts have exercise expiration dates of December 31, 2021 and December 30, 2022, respectively.

(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)

7,301,000



7,320,000



      Weighted average price per MMBtu

$2.61



$3.08



Collar contracts





      Total volume (MMBtu)

3,680,000



5,740,000



      Weighted average price per MMBtu





         Ceiling (short call)

$2.80



$3.64



         Floor (long put)

$2.50



$2.83



   Short call contracts





      Total volume (MMBtu)

3,680,000


(a)



      Weighted average price per MMBtu

$3.09



$—








Natural gas contracts (Waha basis differential)





   Swap contracts





      Total volume (MMBtu)

8,280,000



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)

920,000





      Weighted average price per Bbl

$7.62



$—



Operating and Financial Results

The following table presents summary information for the periods indicated:





Three Months Ended




June 30, 2021



March 31, 2021



June 30, 2020


Total production










Oil (MBbls)










Permian


3,232



3,088



3,633


Eagle Ford


1,870



1,593



2,763


Total oil (MBbls)


5,102



4,681



6,396












Natural gas (MMcf)










Permian


7,138



6,208



8,736


Eagle Ford


1,745



1,627



2,273


Total natural gas (MMcf)


8,883



7,835



11,009












NGLs (MBbls)










Permian


1,216



1,075



1,268


Eagle Ford


299



224



389


Total NGLs (MBbls)


1,515



1,299



1,657












Total production (MBoe)










Permian


5,637



5,198



6,357


Eagle Ford


2,460



2,088



3,531


Total barrels of oil equivalent (MBoe)


8,097



7,286



9,888












Total daily production (Boe/d)










Permian


61,948



57,758



69,858


Eagle Ford


27,033



23,199



38,806


Total barrels of oil equivalent (Boe/d)


88,981



80,957



108,664


Oil as % of total daily production


63

%


64

%


65

%











Average realized sales price

(excluding impact of settled derivatives)










Oil (per Bbl)










Permian


$65.08



$56.66



$23.27


Eagle Ford


65.83



57.80



16.64


Total oil (per Bbl)


$65.36



$57.05



$20.41












Natural gas (per Mcf)










Permian


$2.68



$3.11



$0.95


Eagle Ford


2.82



3.03



1.73


Total natural gas (per Mcf)


$2.71



$3.09



$1.11












NGLs (per Bbl)










Permian


$24.71



$22.68



$8.77


Eagle Ford


22.00



22.24



8.65


Total NGLs (per Bbl)


$24.17



$22.60



$8.74












Average realized sales price (per Boe)










Permian


$46.04



$42.06



$16.35


Eagle Ford


54.72



48.85



15.09


Total average realized sales price (per Boe)


$48.68



$44.01



$15.90












Average realized sales price

(including impact of settled derivatives)










Oil (per Bbl)


$46.82



$44.33



$33.82


Natural gas (per Mcf)


2.25



2.88



0.97


NGLs (per Bbl)


23.21



21.77



8.74


Total average realized sales price (per Boe)


$36.31



$35.46



$24.42
















Three Months Ended




June 30, 2021



March 31, 2021



June 30, 2020


Revenues (in thousands)(a)










Oil










Permian


$210,340



$174,967



$84,538


Eagle Ford


123,102



92,078



45,975


Total oil


$333,442



$267,045



$130,513












Natural gas










Permian


$19,152



$19,290



$8,309


Eagle Ford


4,928



4,930



3,933


Total natural gas


$24,080



$24,220



$12,242












NGLs










Permian


$30,047



$24,376



$11,116


Eagle Ford


6,578



4,981



3,363


Total NGLs


$36,625



$29,357



$14,479












Total revenues










Permian


$259,539



$218,633



$103,963


Eagle Ford


134,608



101,989



53,271


Total revenues


$394,147



$320,622



$157,234












Additional per Boe data










Sales price (b)










Permian


$46.04



$42.06



$16.35


Eagle Ford


54.72



48.85



15.09


Total sales price


$48.68



$44.01



$15.90












Lease operating










Permian


$4.60



$4.31



$5.01


Eagle Ford


8.34



8.65



5.38


Total lease operating


$5.74



$5.55



$5.14












Production and ad valorem taxes










Permian


$2.53



$2.32



$1.11


Eagle Ford


3.12



3.07



0.94


Total production and ad valorem taxes


$2.71



$2.53



$1.05












Gathering, transportation and processing










Permian


$2.75



$2.54



$2.31


Eagle Ford


1.84



2.29



1.51


Total gathering, transportation and processing


$2.47



$2.47



$2.03












Operating margin










Permian


$36.16



$32.89



$7.92


Eagle Ford


41.42



34.84



7.26


Total operating margin


$37.76



$33.46



$7.68












   Depreciation, depletion and amortization


$10.27



$9.74



$14.05


   General and administrative


$1.37



$2.31



$1.01


   Adjusted G&A 1










      Cash component (c)


$0.71



$1.26



$0.69


      Non-cash component


$0.21



$0.23



$0.15

















(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 June 30, 2021, Callon reported revenue of $394.1 million, which excluded revenue from sales of commodities purchased from a third party of $46.3 million. Revenues including the gain or loss from the settlement of derivative contracts ("Adjusted Total Revenue"1) were $294.0 million, reflecting the impact of a $100.1 million loss from the settlement of derivative contracts. Average daily production for the quarter was 89.0 MBoe/d, compared to average daily production of 81.0 MBoe/d in the first quarter of 2021. Average realized prices, including and excluding the effects of hedging, are detailed above.

Commodity Derivatives. For the quarter ended June 30, 2021, the net loss on commodity derivative contracts includes the following (in thousands):


Three Months Ended
June 30, 2021

Loss on oil derivatives

$177,033


Loss on natural gas derivatives

12,816


Loss on NGL derivatives

3,734


Loss on commodity derivative contracts

$193,583


For the quarter ended June 30, 2021, the cash paid for commodity derivative settlements includes the following (in thousands):


Three Months Ended
June 30, 2021

Cash paid on oil derivatives

($82,413)


Cash paid on natural gas derivatives

(1,906)


Cash paid on NGL derivatives

(1,090)


Cash paid for commodity derivative settlements, net

($85,409)


Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended June 30, 2021 was $5.74 per Boe, compared to LOE of $5.55 per Boe in the first quarter of 2021. The increase in LOE per Boe was primarily due to increased electrical costs.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended June 30, 2021 represented approximately 5.6% of total 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 June 30, 2021 was $20.0 million, or $2.47 per Boe, as compared to $18.0 million, or $2.47 per Boe in the first quarter of 2021. This increase is related to the 11% increase in production volumes between the two periods.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended June 30, 2021 was $10.27 per Boe compared to $9.74 per Boe in the first quarter of 2021. The increase in DD&A was primarily attributable to a production increase of 11%, higher capital expenditures during the second quarter of 2021 as compared to the first quarter of 2021, and increases in future development cost assumptions. 

General and Administrative Expense ("G&A"). G&A for the three months ended June 30, 2021 and March 31, 2021 was $11.1 million, or $1.37 per Boe, and $16.8 million, or $2.31 per Boe, respectively. G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A" 1) was $7.5 million, or $0.93 per Boe, for the three months ended June 30, 2021 compared to $10.9 million, or $1.49 per Boe, for the first quarter of 2021. The cash component of Adjusted G&A decreased to $5.8 million, or $0.71 per Boe, for the three months ended June 30, 2021 compared to $9.2 million, or $1.26 per Boe, for the first quarter of 2021 primarily as a result of lower compensation costs during the quarter.

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


Three Months Ended


June 30, 2021


March 31, 2021


June 30, 2020

Total G&A

$11,065



$16,799



$10,024


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

(3,555)



(5,943)



(1,720)


Adjusted G&A – total

7,510



10,856



8,304


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

(1,724)



(1,665)



(1,509)


Adjusted G&A – cash component

$5,786



$9,191



$6,795








Capitalized cash G&A

7,404



6,913



6,740


Full cash G&A

$13,190



$16,104



$13,535


Income Tax. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. We recorded income tax benefit of $0.5 million and $0.9 million for the three months ended June 30, 2021 and March 31, 2021, respectively. Since the second quarter of 2020, we have concluded that it is more likely than not that the net deferred tax assets will not be realized and have recorded a full valuation allowance against our deferred tax assets. As long as we continue to conclude that the valuation allowance is necessary, we will not have significant deferred tax expense or benefit.

Adjusted EBITDA. Net loss was $11.7 million and adjusted EBITDA was $196.8 million for the second quarter of 2021 as compared to net loss of $80.4 million and adjusted EBITDA of $170.6 million for the first quarter of 2021. The increase in adjusted EBITDA from the first quarter of 2021 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 following tables reconcile the Company's net loss to adjusted income and adjusted EBITDA:


Three Months Ended


June 30, 2021


March 31, 2021


June 30, 2020


(In thousands, except per share data)

Net loss

($11,695)



($80,407)



($1,564,731)


Loss on derivative contracts

190,463



214,523



126,965


Gain (loss) on commodity derivative settlements, net

(100,128)



(62,280)



84,208


Non-cash stock-based compensation expense

5,279



7,608



2,761


Impairment of evaluated oil and gas properties





1,276,518


Merger and integration expense





8,067


Other (income) expense

5,584



(3,306)



6,759


Tax effect on adjustments above(a)

(21,252)



(32,874)



(316,108)


Change in valuation allowance

2,079



26,724



377,645


Adjusted income

$70,330



$69,988



$2,084


Adjusted income per diluted share

$1.49



$1.49



$0.05








Basic WASO(b)

46,267



42,590



39,707


Diluted WASO (GAAP)(b)

46,267



42,590



39,707


Effect of potentially dilutive instruments(b)

862



4,354



12


Adjusted Diluted WASO(b)

47,129



46,944



39,719




(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


June 30, 2021


March 31, 2021


June 30, 2020


(In thousands)

Net loss

($11,695)



($80,407)



($1,564,731)


   Loss on derivative contracts

190,463



214,523



126,965


   Gain (loss) on commodity derivative settlements, net

(100,128)



(62,280)



84,208


   Non-cash stock-based compensation expense

5,279



7,608



2,761


 Impairment of evaluated oil and gas properties





1,276,518


   Merger and integration expense





8,067


   Other (income) expense

5,584



(3,306)



6,759


   Income tax (benefit) expense

(478)



(921)



51,251


   Interest expense, net

24,634



24,416



22,682


   Depreciation, depletion and amortization

83,128



70,987



138,930


Adjusted EBITDA

$196,787



$170,620



$153,410


Adjusted Free Cash Flow. The following table reconciles the Company's net cash provided by operating activities to adjusted EBITDA and adjusted free cash flow:


Three Months Ended


June 30, 2021


March 31, 2021


June 30, 2020


(In thousands)

Net cash provided by operating activities

$175,603



$137,665



$97,801


Changes in working capital and other

13,520



30,913



40,078


Change in accrued hedge settlements

(14,719)



(20,117)



(14,480)


Cash interest expense, net

22,383



22,159



21,944


Merger and integration expense





8,067


Adjusted EBITDA

196,787



170,620



153,410


Less: Operational capital expenditures (accrual)

138,321



95,545



85,087


Less: Capitalized interest

21,740



21,817



20,924


Less: Interest expense, net of capitalized amounts

22,383



22,159



22,682


Less: Capitalized cash G&A

7,404



6,913



6,740


Adjusted free cash flow (a)

$6,939



$24,186



$17,977




(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. The following table reconciles the Company's net cash provided by operating activities to adjusted discretionary cash flow:


Three Months Ended


June 30, 2021


March 31, 2021


June 30, 2020


(In thousands)

Cash flows from operating activities:






Net loss

($11,695)



($80,407)



($1,564,731)


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






   Depreciation, depletion and amortization

83,128



70,987



138,930


   Impairment of evaluated oil and gas properties





1,276,518


   Amortization of non-cash debt related items

2,252



2,256



738


   Deferred income tax expense





51,251


   Loss on derivative contracts

190,463



214,523



126,965


   Cash (paid) received for commodity derivative settlements, net

(85,409)



(42,162)



98,688


   Non-cash stock-based compensation expense

5,279



7,608



2,761


   Merger and integration expense





8,067


   Other, net

3,294



1,217



3,521


Adjusted discretionary cash flow

$187,312



$174,022



$142,708


   Changes in working capital

(11,709)



(36,357)



(36,840)


   Merger and integration expense





(8,067)


Net cash provided by operating activities

$175,603



$137,665



$97,801


Adjusted Total Revenue. Adjusted total revenue 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



June 30, 2021


March 31, 2021


June 30, 2020



(In thousands)

Operating revenues







Oil


$333,442



$267,045



$130,513


Natural gas


24,080



24,220



12,242


NGLs


36,625



29,357



14,479


Total operating revenues


$394,147



$320,622



$157,234


Impact of settled derivatives


(100,128)



(62,280)



84,208


Adjusted total revenue


$294,019


$258,342


$241,442

 

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and share amounts)

(Unaudited)




June 30, 2021


December 31, 2020

ASSETS





Current assets:





Cash and cash equivalents


$3,800



$20,236


Accounts receivable, net


200,246



133,109


Fair value of derivatives


14,941



921


Other current assets


24,876



24,103


Total current assets


243,863



178,369


Oil and natural gas properties, full cost accounting method:





Evaluated properties, net


2,517,783



2,355,710


Unevaluated properties


1,697,832



1,733,250


Total oil and natural gas properties, net


4,215,615



4,088,960


Other property and equipment, net


32,805



31,640


Deferred financing costs


20,670



23,643


Other assets, net


33,444



40,256


Total assets


$4,546,397



$4,362,868


LIABILITIES AND STOCKHOLDERS' EQUITY





Current liabilities:





Accounts payable and accrued liabilities


$419,434



$341,519


Fair value of derivatives


331,702



97,060


Other current liabilities


62,668



58,529


Total current liabilities


813,804



497,108


Long-term debt


2,865,154



2,969,264


Asset retirement obligations


57,546



57,209


Fair value of derivatives


8,204



88,046


Other long-term liabilities


44,401



40,239


Total liabilities


3,789,109



3,651,866


Commitments and contingencies





Stockholders' equity:





Common stock, $0.01 par value, 78,750,000 and 52,500,000 shares authorized;
46,288,813 and 39,758,817 shares outstanding, respectively


463



398


Capital in excess of par value


3,361,282



3,222,959


Accumulated deficit


(2,604,457)



(2,512,355)


Total stockholders' equity


757,288



711,002


Total liabilities and stockholders' equity


$4,546,397



$4,362,868


 

Callon Petroleum Company

Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)



Three Months Ended

June 30,


Six Months Ended

June 30,


2021


2020


2021


2020

Operating Revenues:








Oil

$333,442



$130,513



$600,487



$396,280


Natural gas

24,080



12,242



48,300



18,271


Natural gas liquids

36,625



14,479



65,982



32,602


Sales of purchased oil and gas

46,252





85,511




Total operating revenues

440,399



157,234



800,280



447,153










Operating Expenses:








Lease operating

46,460



50,838



86,913



103,221


Production and ad valorem taxes

21,958



10,361



40,397



30,041


Gathering, transportation and processing

20,031



20,037



38,012



34,415


Cost of purchased oil and gas

49,249





90,166




Depreciation, depletion and amortization

83,128



138,930



154,115



270,393


General and administrative

11,065



10,024



27,864



18,349


Impairment of evaluated oil and gas properties



1,276,518





1,276,518


Merger and integration



8,067





23,897


Other operating

2,437



4,135



3,366



4,135


Total operating expenses

234,328



1,518,910



440,833



1,760,969


Income (Loss) From Operations

206,071



(1,361,676)



359,447



(1,313,816)










Other (Income) Expenses:








Interest expense, net of capitalized amounts

24,634



22,682



49,050



43,160


(Gain) loss on derivative contracts

190,463



126,965



404,986



(125,004)


Other (income) expense

3,147



2,157



(1,088)



895


Total other (income) expense

218,244



151,804



452,948



(80,949)










Loss Before Income Taxes

(12,173)



(1,513,480)



(93,501)



(1,232,867)


Income tax benefit (expense)

478



(51,251)



1,399



(115,299)


Net Loss

($11,695)



($1,564,731)



($92,102)



($1,348,166)










Net Loss Per Common Share (a):








Basic

($0.25)



($39.41)



($2.07)



($33.97)


Diluted

($0.25)



($39.41)



($2.07)



($33.97)










Weighted Average Common Shares Outstanding (a):








Basic

46,267



39,707



44,439



39,687


Diluted

46,267



39,707



44,439



39,687











(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

June 30,


Six Months Ended June 30,


2021


2020


2021


2020

Cash flows from operating activities:








Net loss

($11,695)



($1,564,731)



($92,102)



($1,348,166)


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








Depreciation, depletion and amortization

83,128



138,930



154,115



270,393


Impairment of evaluated oil and gas properties



1,276,518





1,276,518


Amortization of non-cash debt related items, net

2,252



738



4,508



1,145


Deferred income tax expense



51,251





115,299


(Gain) loss on derivative contracts

190,463



126,965



404,986



(125,004)


Cash received (paid) for commodity derivative settlements, net

(85,409)



98,688



(127,571)



101,301


Non-cash expense (benefit) related to share-based awards

5,279



2,761



12,887



(211)


Other, net

3,294



3,520



4,511



3,656


Changes in current assets and liabilities:








Accounts receivable

(21,674)



(2,833)



(67,357)



113,040


Other current assets

(4,567)



(3,567)



(7,423)



(4,348)


Accounts payable and accrued liabilities

14,532



(30,439)



26,714



(114,127)


Net cash provided by operating activities

175,603



97,801



313,268



289,496


Cash flows from investing activities:








Capital expenditures

(149,662)



(205,229)



(251,003)



(418,688)


Acquisition of oil and gas properties

(1,447)



(892)



(2,215)



(11,881)


Proceeds from sale of assets

31,611



(161)



31,611



10,079


Cash paid for settlements of contingent consideration arrangements, net







(40,000)


Other, net

625



6,992



4,220



6,834


Net cash used in investing activities

(118,873)



(199,290)



(217,387)



(453,656)


Cash flows from financing activities:








Borrowings on Credit Facility

433,500



484,500



736,500



4,775,500


Payments on Credit Facility

(508,500)



(384,500)



(846,500)



(4,610,500)


Payment of deferred financing and debt exchange costs



(5,736)





(6,011)


Tax withholdings related to restricted stock units

(2,280)





(2,280)



(388)


Other, net



(75)



(37)



(282)


Net cash provided by (used in) financing activities

(77,280)



94,189



(112,317)



158,319


Net change in cash and cash equivalents

(20,550)



(7,300)



(16,436)



(5,841)


Balance, beginning of period

24,350



14,800



20,236



13,341


Balance, end of period

$3,800



$7,500



$3,800



$7,500


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 Wednesday, August 4, 2021, to discuss second 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:     Wednesday, August 4, 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.
  2. Pro forma credit facility outstanding balance represents the June 30, 2021 balance of $875.0 million adjusted for the excess proceeds from the issuance of the 8.00% Senior Notes received in July.

 

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SOURCE Callon Petroleum Company