0000928022false00009280222020-08-042020-08-04

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 4, 2020
https://cdn.kscope.io/aaf7e11d7dd0315ba60fcfc04c4d9bb2-cpe-20200804_g1.jpg
Callon Petroleum Company
(Exact name of registrant as specified in its charter)

DE001-1403964-0844345
(State or Other Jurisdiction of Incorporation)(Commission File Number)(I.R.S. Employer Identification Number)

One Briarlake Plaza
2000 W. Sam Houston Parkway S., Suite 2000
Houston, TX 77042
(Address of Principal Executive Offices, and Zip Code)

(281) 589-5200
(Registrant’s Telephone Number, Including Area Code)

(Former Name or Former Address, if Changed Since Last Report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 Written communication pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
 Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
 Pre-commencement communication pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
 Pre-commencement communication pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $0.01 par valueCPENYSE

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR §230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).
 Emerging growth company  
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.



Item 2.02. Results of Operations and Financial Condition

The following information, including the press release attached as Exhibit 99.1, is being furnished pursuant to Item 2.02 “Results of Operations and Financial Condition,” not filed, for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This information shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

On August 4, 2020, Callon Petroleum Company issued the press release attached as Exhibit 99.1 providing information regarding the Company’s second quarter 2020 financial and operating results and updated 2020 operational targets.

Item 7.01 Regulation FD

The information set forth under Item 2.02 is incorporated herein by reference.

Item 9.01. Financial Statements and Exhibits

(d) Exhibits

Exhibit NumberTitle of Document
99.1




SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



Callon Petroleum Company
(Registrant)
August 4, 2020/s/ James P. Ulm, II
James P. Ulm, II
Senior Vice President and Chief Financial Officer



Exhibit 99.1
Callon Petroleum Company Announces Second Quarter 2020 Results
Updates 2020 Operating Plan and Outlook
HOUSTON, TX (August 4, 2020) - 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
OperationalCapitalizedCapitalizedTotal Capital
Capital (a)
InterestG&AExpenditures
(In thousands)
Cash basis (b)
$174,594  $24,787  $6,740  $206,121  
Timing adjustments (c)
(90,780) (3,863) —  (94,643) 
Non-cash items1,273  —  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, 2020March 31, 2020June 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 production65 %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 gas12,242  6,029  6,324  
NGLs14,479  18,123  —  
Total revenues157,234  289,919  167,052  
Additional per Boe data
Sales price (a)
$15.90  $31.56  $45.31  
Lease operating expense5.14  5.70  6.18  
Production taxes1.05  2.14  3.02  
Gathering, transportation and processing2.03  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 component0.15  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 derivatives4,695  
(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, 2020March 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 – total8,304  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 $217.5 million for the first quarter of 2020. The decrease in Adjusted EBITDA from the first quarter of 2020 was primarily due to an approximate 30% decrease in the average realized price of oil. This was partially offset by increased sequential production as well as a decrease in operating expenses as described above.
Guidance
Callon is reinstating guidance for the full year and updating previous ranges to reflect adjustments to its operational plan and associated expectations.
Full Year
2020 Guidance
Total production (Mboe/d)99.0 - 101.0
Oil production64%
Gas production18%
NGL production18%
Income statement expenses ($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 / completed87-89 / 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 RemainderFor the Full Year
Oil contracts (WTI)of 2020of 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 RemainderFor the Full Year
Natural gas contracts (Henry Hub)of 2020of 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 RemainderFor the Full Year
NGL contracts (OPIS Mont Belvieu Purity Ethane)of 2020of 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, 2020March 31, 2020June 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 contracts126,965  (251,969) (14,036) 
Gain (loss) on commodity derivative settlements, net84,208  25,126  (1,157) 
Non-cash stock-based compensation expense (benefit)2,761  (2,972) 904  
Impairment of evaluated oil and gas properties1,276,518  —  —  
Merger and integration expense8,067  15,830  —  
Other (income) expense6,759  (1,029) 770  
Tax effect on adjustments above(a)
(316,108) 45,153  2,839  
Change in valuation allowance377,645  —  —  
Adjusted Income$2,084  $46,704  $42,677  
Adjusted Income per fully diluted common share$0.01  $0.12  $0.19  
Basic WASO397,084  396,682  228,051  
Diluted WASO (GAAP)397,084  396,836  228,411  
Effective of potentially dilutive instruments114  —  —  
Adjusted Diluted WASO397,198  396,836  228,411  
(a) Calculated using the federal statutory rate of 21%.

Three Months Ended
June 30, 2020March 31, 2020June 30, 2019
(In thousands)
Net income (loss)($1,564,731) $216,565  $55,180  
   (Gain) loss on derivative contracts126,965  (251,969) (14,036) 
   Gain (loss) on commodity derivative settlements, net84,208  25,126  (1,157) 
   Non-cash stock-based compensation expense (benefit)2,761  (2,972) 904  
 Impairment of evaluated oil and gas properties1,276,518  —  —  
   Merger and integration expense8,067  15,830  —  
   Other (income) expense6,759  (1,029) 935  
   Income tax expense51,251  64,048  16,691  
   Interest expense22,682  20,478  741  
   Depreciation, depletion and amortization138,930  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 other40,078  
Change in accrued hedge settlement(14,480) 
Cash interest expense21,944  
Merger and integration expense8,067  
Adjusted EBITDA153,410  
Less: Operational capital (accrual)85,087  
Less: Capitalized interest20,924  
Less: Interest expense22,682  
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, 2020March 31, 2020June 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 amortization138,930  131,463  64,590  
   Impairment of evaluated oil and gas properties1,276,518  —  —  
   Amortization of non-cash debt related items738  407  741  
   Deferred income tax expense51,251  64,048  16,691  
   (Gain) loss on derivative contracts126,965  (251,969) (14,036) 
   Cash (paid) received for commodity derivative settlements, net98,688  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 expense8,067  15,830  —  
   Other, net3,521  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, 2020March 31, 2020June 30, 2019
(In thousands)
Operating Revenues
Oil$130,513  $265,767  $160,728  
Natural gas12,242  6,029  6,324  
Natural gas liquids14,479  18,123  —  
Total operating revenues$157,234  $289,919  $167,052  
Gain (loss) on commodity derivative settlements, net84,208  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, 2020December 31, 2019
ASSETS 
Current assets:  
Cash and cash equivalents$7,500  $13,341  
Accounts receivable, net95,839  209,463  
Fair value of derivatives31,563  26,056  
Other current assets28,828  19,814  
Total current assets163,730  268,674  
Oil and natural gas properties, full cost accounting method:  
Evaluated properties3,777,956  4,682,994  
Unevaluated properties1,762,860  1,986,124  
Total oil and natural gas properties, net5,540,816  6,669,118  
Operating lease right-of-use assets35,926  63,908  
Other property and equipment, net32,444  35,253  
Deferred tax asset—  115,720  
Deferred financing costs25,993  22,233  
Other assets, net11,224  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 liabilities24,355  42,858  
Fair value of derivatives32,683  71,197  
Other current liabilities15,053  26,570  
Total current liabilities477,687  652,247  
Long-term debt3,350,730  3,186,109  
Operating lease liabilities30,729  37,088  
Asset retirement obligations48,765  48,860  
Fair value of derivatives8,678  32,695  
Other long-term liabilities12,160  14,531  
Total liabilities3,928,749  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, respectively3,974  3,966  
Capital in excess of par value3,204,310  3,198,076  
Retained earnings (Accumulated deficit)(1,326,900) 21,266  
Total stockholders’ equity1,881,384  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,
 2020201920202019
Operating revenues:  
Oil$130,513  $160,728  $396,280  $301,826  
Natural gas12,242  6,324  18,271  18,273  
Natural gas liquids14,479  —  32,602  —  
Total operating revenues157,234  167,052  447,153  320,099  
Operating Expenses:    
Lease operating50,838  22,776  103,221  46,843  
Production and ad valorem taxes10,361  11,131  30,041  21,944  
Gathering, transportation and processing20,037  —  34,415  —  
Depreciation, depletion and amortization138,930  63,137  270,393  123,145  
General and administrative10,024  10,564  18,349  25,341  
Impairment of evaluated oil and gas properties1,276,518  —  1,276,518  —  
Merger and integration expenses8,067  —  23,897  —  
Other operating4,135  935  4,135  1,092  
Total operating expenses1,518,910  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 amounts22,682  741  43,160  1,479  
(Gain) loss on derivative contracts126,965  (14,036) (125,004) 53,224  
Other (income) expense2,157  (67) 895  (148) 
Total other (income) expense151,804  (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:   
Basic397,084  228,051  396,884  227,917  
Diluted397,084  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,
 2020201920202019
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 amortization138,930  64,590  270,393  125,503  
Impairment of evaluated oil and gas properties1,276,518  —  1,276,518  —  
Amortization of non-cash debt related items738  741  1,145  1,479  
Deferred income tax expense51,251  16,691  115,299  11,542  
(Gain) loss on derivative contracts126,965  (14,036) (125,004) 53,224  
Cash (paid) received for commodity derivative settlements98,688  (1,157) 101,301  (1,447) 
Loss on sale of other property and equipment—  21  —  49  
Non-cash expense related to equity share-based awards1,041  1,754  4,817  6,299  
Change in the fair value of liability share-based awards1,720  (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, net3,521  —  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 activities97,801  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, net6,992  —  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 facility484,500  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 activities94,189  (227,692) 158,319  (100,541) 
Net change in cash and cash equivalents(7,300) 5,570  (5,841)  
Balance, beginning of period14,800  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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