Callon Petroleum Company Announces Fourth Quarter and Full Year 2020 Results and Provides 2021 Plan Focused on Free Cash Flow and Debt Reduction Initiatives

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HOUSTON, Feb. 24, 2021 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months and full-year ended December 31, 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.

2020 Highlights

  • Full-year 2020 production of 101.6 MBoe/d (63% oil), an increase of 146% over 2019 volumes

  • Year-end proved reserves of 475.9 MMBoe (61% oil)

  • Generated net cash provided by operating activities of $559.8 million and adjusted free cash flow1 of $10.7 million, including net cash provided by operating activities of $368.1 million and $122.6 million of adjusted free cash flow1 generation over the last three quarters

  • Loss available to common stockholders of $2.5 billion, or $63.79 per diluted share, driven by impairments of evaluated oil and gas properties of $2.5 billion, adjusted EBITDA1 of $709.7 million, and adjusted income1 of $117.1 million or $2.86 per diluted share

  • Lowered average drilling and completion cost per lateral foot by approximately 35% from 2019 comparable well costs, driving total operational capital expenditures of $488.6 million, meaningfully below budgeted levels

  • Reduced total cash general and administrative expenses by more than 60% from pro forma 20192 levels

  • Lowered annual lease operating expense by more than $30 million from pro forma 20192 levels through effective implementation of field best practices

  • Asset monetization proceeds and debt exchanges reduced total debt balances by approximately $350 million since the second quarter of 2020

Fourth Quarter 2020 Highlights

  • Fourth quarter 2020 production of 94.9 MBoe/d (62% oil), an increase of 103% over fourth quarter 2019 volumes and a sequential decrease of 7% including the impact of completed divestitures

  • Generated $134.6 million of net cash provided by operating activities and adjusted free cash flow1 of $24.4 million

  • Loss available to common stockholders of $505.1 million, or $12.71 per diluted share, driven by an impairment of evaluated oil and gas properties of $585.8 million, adjusted EBITDA1 of $167.8 million, and adjusted income1 of $42.8 million or $1.00 per diluted share

2021 Capital Plan Highlights

  • Operational capital budget of up to $430 million, a 12% reduction relative to 2020 spending, with approximately 70% allocated to Permian activity

  • Annual production guidance of 90 - 92 MBoe/d (63% oil) inclusive of estimated winter storm impacts of approximately 2 MBoe/d for the full year 2021

  • Expected adjusted free cash flow1 generation of approximately $150 million at $50/Bbl oil (WTI benchmark)

Joe Gatto, President and Chief Executive Officer commented, "In a year marked by extraordinary volatility in commodity prices and workplace challenges created by the COVID-19 pandemic, our newly integrated team executed flawlessly on a revamped set of operational and financial initiatives that ultimately delivered over $120 million of adjusted free cash flow since the beginning of the second quarter, dramatically improving our liquidity and absolute debt position. Importantly, these accomplishments were complemented by significant achievements related to employee safety and environmental emissions."

He continued, "Our medium-term development plans are squarely focused on free cash flow generation and absolute debt reduction. Given our leading operating margins and low-cost resource base, the magnitude and pace of improvements in financial strength from organic cash flows are highly differentiated in the sector. Our 2021 capital budget, inclusive of capitalized expenses, implies a reinvestment rate3 of approximately 75% of discretionary cash flow at $50 per barrel WTI price and a free cash flow breakeven price of approximately $40 per barrel. We will continue to manage our future capital reinvestment rate3 within a targeted range of 65% to 75% under a range of pricing environments, which is expected to generate adjusted free cash flow in a range of $500 to $800 million over the next three years assuming WTI oil prices of $50 to $60 per barrel. In addition, we are targeting asset monetizations of approximately $125 to $225 million in 2021 to further our debt reduction goals, meeting our original 2020 total divestiture targets after including transactions completed last year. As divestiture market conditions continue to improve, we are evaluating opportunities for incremental, credit enhancing monetizations above our targeted levels."

Environmental, Social, and Governance ("ESG") Updates

Callon advanced its sustainability initiatives during 2020 with the Company achieving numerous milestones as detailed below:

  • Issued an inaugural SASB aligned sustainability report

  • Reduced flared natural gas volumes by 44%

  • Achieved a 66% reduction in spill volumes

  • Increased recycled water usage by 10%

  • Set a new Callon record for safety with a total recordable incident rate of under 0.55

  • Named a top Houston workplace for the fourth straight year by the Houston Chronicle

  • Supported schools, food banks and first responders in our local communities during the challenges of the global pandemic

  • Enhanced board oversight of ESG by expanding the remit of the Nominating and ESG Committee

Callon continues to advance various sustainability efforts and expects to disclose new long-term targets for GHG emissions reductions and a revamped executive compensation program aligned with investor and corporate priorities in the near future.

Operations Update and Outlook

At December 31, 2020, Callon had 1,496 gross (1,320.6 net) horizontal wells producing from established flow units in the Permian and Eagle Ford. Net daily production for the three months ended December 31, 2020 grew 103% to 94.9 MBoe/d (62% oil) as compared to the same period of 2019. Full year production for 2020 averaged 101.6 MBoe/d (63% oil) reflecting growth of 146% over 2019 volumes.

For the three months ended December 31, 2020, Callon drilled 22 gross (20.0 net) horizontal wells and placed a combined 16 gross (14.3 net) horizontal wells on production. Wells placed on production during the quarter were completed in the Lower Spraberry and Wolfcamp A in the Midland Basin and the Wolfcamp A and Wolfcamp C in the Delaware Basin.

Recently, severe winter storms affected field operations in both the Permian and Eagle Ford resulting in the shut-in of nearly 100% of our operated production. Currently, we have returned nearly all of our Eagle Ford and Midland Basin wells to production and expect to have all of our Delaware well production returned by the end of February. The estimated annualized impact of these deferrals is approximately 2,000 Boe/d. This has been reflected in our updated production guidance for 2021. The impact to our drilling and completion operations were not significant enough to alter our expectations for the full year development schedule and any additional operational costs are currently reflected in our lease operating expense guidance.

Currently, the Company has three active rigs with one each in the Midland, Delaware, and Eagle Ford. The Company recently deployed a second completion crew and has operations taking place in the Delaware and Eagle Ford.

2021 Capital Expenditures Budget

Callon has established an operational capital expenditure budget of $430.0 million for 2021 with approximately 80% of spending directed towards drilling, completion and equipment expenditures. The reduction of approximately $60 million from 2020 levels reflects a decrease in the number of drilled wells as well as a full year of achieved capital synergies. Roughly 70% of this development capital will be spent on Permian activity with the remaining balance allocated to the Eagle Ford. Permian development activity will predominantly feature co-development of the Wolfcamp A and B in the Delaware and the Lower Spraberry and Wolfcamp A in the Midland. The Eagle Ford program remains focused solely on the primary target zone, the Lower Eagle Ford Shale, as technical evaluation continues on Austin Chalk potential for future delineation. In total, the Company expects to drill 55 to 65 gross wells and complete 90 to 100 gross wells.

Our scaled development plan for 2021 will continue to employ our life of field development philosophy and benefit from our balanced capital deployment strategy. We entered the year with a robust backlog of drilled uncompleted wells ("DUCs"), after drilling over 90 wells in 2020, which will allow us to complete approximately 55 wells in the first half of the year. Although at a reduced number from year end 2020, we now plan to maintain a meaningful DUC inventory heading into 2022 to provide operational flexibility to execute across a range of development planning scenarios. The capital expenditures associated with this higher DUC inventory contributed to the majority of the approximate $30 million increase relative to our previous 2021 capital estimates, in addition to selective project size increases to improve capital efficiency and resource recovery. These schedule refinements will position Callon for an improved production trajectory in the medium term, adhering to our reinvestment rate parameters, to increase free cash flow generation potential.

The 2021 capital plan leverages the structural savings and operational efficiencies achieved during 2020 from shared best practices following the integration of Callon and Carrizo. Callon's ability to reduce the average well cost by more than 35% on a lateral foot basis since 2019 has yielded significant improvements in capital efficiency. Lower capital costs paired with an improved operating cost structure and moderated development program are expected to provide a foundation of durable free cash flow generated by a program that optimizes recoverable value while avoiding over-capitalization of the resource base.

The remainder of our full year 2021 outlook is provided later in this release under the section titled "2021 Guidance."

Capital Expenditures

For the year ended December 31, 2020, Callon incurred $488.6 million in operational capital expenditures on an accrual basis as compared to $515.1 million in 2019. For the three months ended December 31, 2020, the Company incurred $87.5 million in operational capital expenditures on an accrual basis, which represented a $49.1 million increase from the third quarter of 2020. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis:




Three Months Ended December 31, 2020



Operational


Capitalized


Capitalized


Total Capital



Capital (a)


Interest


G&A


Expenditures



(In thousands)

Cash basis (b)


$77,742



$25,201



$6,465



$109,408


Timing adjustments (c)


8,317



(2,187)





6,130


Non-cash items


1,429





2,390



3,819


Accrual basis


$87,488



$23,014



$8,855



$119,357




(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.

Operating and Financial Results

The following table presents summary information for the periods indicated:



Three Months Ended



December 31, 2020


September 30, 2020


December 31, 2019

Total production







Oil (MBbls)







Permian


3,445



3,441



2,934


Eagle Ford


1,980



2,434



300


Total oil (MBbls)


5,425



5,875



3,234









Natural gas (MMcf)







Permian


7,474



7,868



5,296


Eagle Ford


2,264



2,393



234


Total natural gas (MMcf)


9,738



10,261



5,530









NGLs (MBbls)







Permian


1,331



1,423



93


Eagle Ford


353



379



42


Total NGLs (MBbls)


1,684



1,802



135









Total production (MBoe)







Permian


6,022



6,175



3,910


Eagle Ford


2,710



3,212



381


Total barrels of oil equivalent (MBoe)


8,732



9,387



4,291









Total daily production (Boe/d)







Permian


65,459



67,117



42,500


Eagle Ford


29,455



34,912



4,141


Total barrels of oil equivalent (Boe/d)


94,914



102,029



46,641


Oil as % of total daily production


62

%


63

%


75

%



Three Months Ended



December 31, 2020


September 30, 2020


December 31, 2019

Average realized sales price (excluding impact of settled derivatives)







Oil (per Bbl)







Permian


$41.02



$39.42



$56.31


Eagle Ford


41.12



39.44



59.57


Total oil (per Bbl)


$41.06



$39.43



$56.61









Natural gas (per Mcf)







Permian


$1.68



$1.31



$1.96


Eagle Ford


2.65



1.99



2.44


Total natural gas (per Mcf)


$1.91



$1.47



$1.98









NGL (per Bbl)







Permian


$15.00



$12.68



$16.58


Eagle Ford


16.16



13.13



12.69


Total NGL (per Bbl)


$15.24



$12.78



$15.37









Average realized sales price (per Boe)







Permian


$28.87



$26.55



$45.30


Eagle Ford


34.36



32.92



49.81


Total average realized sales price (per Boe)


$30.57



$28.73



$45.70









Average realized sales price

(including impact of settled derivatives)







Oil (per Bbl)


$39.62



$39.00



$55.33


Natural gas (per Mcf)


1.89



1.17



2.12


NGLs (per Bbl)


15.24



12.78



15.37


Total average realized sales price (per Boe)


$29.66



$28.14



$44.92









Revenues (in thousands)(a)







Oil







Permian


$141,320



$135,648



$165,199


Eagle Ford


81,413



96,006



17,872


Total oil


222,733



231,654



183,071









Natural gas







Permian


12,560



10,271



10,377


Eagle Ford


6,001



4,763



572


Total natural gas


18,561



15,034



10,949









NGLs







Permian


19,964



18,049



1,542


Eagle Ford


5,704



4,976



533


Total NGLs


25,668



23,025



2,075









Total revenues







Permian


173,844



163,968



177,118


Eagle Ford


93,118



105,745



18,977


Total revenues


$266,962



$269,713



$196,095











Three Months Ended



December 31, 2020


September 30, 2020


December 31, 2019

Additional per Boe data







Sales price (b)







Permian


$28.87



$26.55



$45.30


Eagle Ford


34.36



32.92



49.81


Total sales price


$30.57



$28.73



$45.70









Lease operating expense







Permian


$4.43



$4.38



$5.66


Eagle Ford


6.77



5.86



8.38


Total lease operating expense


$5.15



$4.89



$5.90









Production and ad valorem taxes







Permian


$1.71



$1.57



$2.04


Eagle Ford


2.29



2.00



2.29


Total production and ad valorem taxes


$1.89



$1.72



$2.06









Gathering, transportation and processing







Permian


$2.42



$2.55



$—


Eagle Ford


2.25



2.00




Total gathering, transportation and processing


$2.37



$2.36



$—









Operating margin







Permian


$20.31



$18.05



$37.60


Eagle Ford


23.05



23.06



39.14


Total operating margin


$21.16



$19.76



$37.74









Depletion, depreciation and amortization


...

$11.00



$12.17



$14.30


General and administrative


$1.22



$0.88



$3.18


Adjusted G&A 1







Cash component (c)


$0.86



$0.87



$2.41


Non-cash component


$0.07



$0.18



...

$0.53




(a)

Excludes sales of oil and gas purchased from third parties and sold to our customers.

(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 December 31, 2020, Callon reported total revenue of $267.0 million, which excluded revenue from sales of commodities purchased from a third-party of $29.0 million. Revenues including the gain or loss from the settlement of derivative contracts ("Adjusted Total Revenue"1) were $259.0 million, reflecting the impact of an $8.0 million loss from the settlement of derivative contracts. Average daily production for the quarter was 94.9 MBoe/d compared to average daily production of 102.0 MBoe/d in the third quarter of 2020. Average realized prices, including and excluding the effects of hedging, are detailed above.

Commodity Derivatives. For the quarter ended December 31, 2020, the net (gain) loss on commodity derivative contracts includes the following (in thousands):



Three Months Ended



December 31, 2020

(Gain) loss on oil derivatives


$70,317


(Gain) loss on natural gas derivatives


(3,936)


(Gain) loss on NGL derivatives


8


(Gain) loss on commodity derivative contracts


$66,389


For the quarter ended December 31, 2020, the cash (paid) received for commodity derivative settlements includes the following (in thousands):



Three Months Ended



December 31, 2020

Cash (paid) received on oil derivatives


($2,100)


Cash (paid) received on natural gas derivatives


(784)


Cash (paid) received for commodity derivative settlements


($2,884)


Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended December 31, 2020 was $5.15 per Boe, compared to $4.89 per Boe in the third quarter of 2020. The slight increase in LOE per Boe is primarily from the decrease in sequential production as fixed costs are spread over a lower production base.

Production and Ad Valorem Taxes. Production and ad valorem taxes were $1.89 per Boe for the three months ended December 31, 2020, representing approximately 6% of revenue excluding revenue from sales of commodities purchased from a third-party and before the impact of derivative settlements.

Gathering, Transportation and Processing. Gathering, transportation and processing for the three months ended December 31, 2020 were $20.7 million as compared to $22.2 million in the third quarter of 2020 In 2020, the Company began reporting gathering, transportation and processing 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. 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 December 31, 2020 was $11.00 per Boe compared to $12.17 per Boe in the third quarter of 2020. The decrease in DD&A was primarily driven by the impairment of evaluated oil and gas properties recognized in the third quarter of 2020.

Impairment of Evaluated Oil and Gas Properties. Callon recognized an impairment of evaluated oil and gas properties of $585.8 million for the three months ended December 31, 2020 due primarily to the continued decline in the average realized prices for sales of oil and gas on the first calendar day of each month during the year. For the three months ended September 30, 2020, the Company recognized an impairment of evaluated oil and gas properties of $685.0 million.

General and Administrative Expense ("G&A"). G&A for the three months ended December 31, 2020 and September 30, 2020 was $10.6 million, or $1.22 per Boe, and $8.2 million, or $0.88 per Boe, respectively. G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A1" ) was $8.1 million, or $0.93 per Boe, for the three months ended December 31, 2020 compared to $9.8 million, or $1.04 per Boe, for the third quarter of 2020. The cash component of Adjusted G&A was $7.5 million, or $0.86 per Boe, for the three months ended December 31, 2020 compared to $8.1 million, or $0.87 per Boe, for the third quarter of 2020 primarily as a result of reduced labor expense during the fourth quarter.

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



Three Months Ended


Year Ended



December 31,
2020


September 30,
2020


December 31,
2019


December 31,
2020

Total G&A


$10,614



$8,224



$13,626



$37,187


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


(2,500)



1,582



(1,010)



4,110


Adjusted G&A – total


8,114



9,806



12,616



41,297


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


(580)



(1,674)



(2,294)



(7,771)


Adjusted G&A – cash component


$7,534



$8,132



$10,322



$33,526











Capitalized cash G&A


6,465



6,831



8,782



27,606


Full cash G&A


$13,999



$14,963



$19,104



$61,132


Income Tax. Callon provides for income taxes at a federal statutory rate of 21% adjusted for permanent differences expected to be realized. The Company recorded income tax expense of $6.8 million for the three months ended December 31, 2020, compared to zero income tax expense for the three months ended September 30, 2020 as a result of an increase in the deferred tax assets acquired in the Carrizo Acquisition due to the filing of the final tax returns which provide the underlying tax basis of Carrizo's assets and liabilities and the subsequent valuation allowance against those deferred tax assets.

Loss Available to Common Stockholders. We recorded a loss available to common stockholders for the three months ended December 31, 2020 of $505.1 million, or $12.71 per diluted share, as compared to a loss available to common stockholders of $680.4 million, or $17.12 per diluted share, for the third quarter of 2020. The losses were primarily due to the impairments of evaluated oil and gas properties of $585.8 million and $685.0 million for the three months ended December 31, 2020 and September 30, 2020, respectively.

Adjusted EBITDA. Adjusted EBITDA for the fourth quarter of 2020 was $167.8 million as compared to $170.9 million for the third quarter of 2020. The decrease in adjusted EBITDA from the third quarter of 2020 was primarily due to a decrease in production partially offset by an increase in realized prices.

Proved Reserves

DeGolyer and MacNaughton prepared the estimates of Callon's proved reserves as of December 31, 2020. As of December 31, 2020, Callon's estimated net proved reserves were 475.9 MMBoe and included 289.5 MMBbls of oil, 541.6 Bcf of natural gas, and 96.1 MMBbls of NGLs with a standardized measure of discounted future net cash flows of $2.3 billion using average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year of $37.44/Bbl for oil, $1.02/Mcf for natural gas, and $11.10/Bbl for NGLs. Utilizing the same reserve database and development schedule, management's internal estimate of PV-10 value4 at flat forward price realizations of $49.00/Bbl for oil, $2.40/Mcf for natural gas, and $17.65/Bbl for NGLs is just over $4.6 billion. Both of these valuations assume a more moderated pace of development than previously contemplated and have been adjusted as such for less PUD bookings within the normal five-year window.

Oil constituted approximately 61% of the Company's estimated equivalent proved developed reserves as well as the Company's estimated equivalent total proved reserves. The Company added 41.4 MMBoe of new reserves in extensions and discoveries through development efforts in 2020, with a total of 91 gross (86.0 net) wells drilled and 90 gross (81.4 net) wells completed.

The changes in Callon's estimated net proved reserves are as follows:



Total
(MBoe)

Proved reserves at December 31, 2019


540,012


Extensions and discoveries


41,407


Revisions to previous estimates


(52,227)


Sales of reserves in place


(16,120)


Production


(37,193)


Proved reserves at December 31, 2020


475,879


2020 Full Year Actuals


Full Year


2020 Actual

Total production (MBoe/d)

101.6

Oil

63%

NGL

19%

Natural gas

18%

Income statement expenses (in millions, except where noted)


LOE, including workovers

$194.1

Gathering, transportation and processing

$77.3

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

6.4%

Adjusted G&A - cash component (a)

$33.5

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

$7.8

Cash interest expense, net

$90.4

Capital expenditures (in millions, accrual basis)


Total operational capital (c)

$488.6

Capitalized interest and G&A

$124.0

Gross operated wells drilled / completed

91 / 90



(a)

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

(b)

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

(c)

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

2021 Guidance



Full Year


2021 Guidance

Total production (MBoe/d)

90.0 - 92.0

Oil

63%

NGL

19%

Natural gas

18%

Income statement expenses (in millions except where noted)


LOE, including workovers

$190.0 - $210.0

Gathering, transportation and processing

$70.0 - $80.0

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

6.5%

Adjusted G&A: cash component (a)

$35.0 - $45.0

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

$5.0 - $15.0

Cash interest expense, net

$80.0 - $90.0

Estimated effective income tax rate

22%

Capital expenditures (in millions, accrual basis)


Total operational capital (c)

$430.0

Capitalized interest

$95.0 - $105.0

Capitalized G&A

$28.0 - $38.0

Gross operated wells drilled / completed

55 - 65 / 90 - 100



(a)

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

(b)

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

(c)

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

Hedge Portfolio Summary

As of February 19, 2021, Callon had the following outstanding oil, natural gas and NGL derivative contracts:


For the Full Year of


For the Full Year of


Oil contracts (WTI)

2021


2022


Swap contracts





Total volume (Bbls)

1,827,000





Weighted average price per Bbl

$43.54



$—



Collar contracts





Total volume (Bbls)

11,202,775



1,355,000



Weighted average price per Bbl





Ceiling (short call)

$47.80



$60.00



Floor (long put)

$39.95



$45.00



Short call contracts





Total volume (Bbls)

4,825,300


(a)



Weighted average price per Bbl

$63.62



$—



Short call swaption contracts





Total volume (Bbls)

455,000


(b)

1,825,000


(b)

Weighted average price per Bbl

$47.00



$52.18








Oil contracts (ICE Brent)





Swap contracts





Total volume (Bbls)

505,000


(c)



Weighted average price per Bbl

$37.34



$—



Collar contracts





Total volume (Bbls)

730,000





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)

3,022,900





Weighted average price per Bbl

$0.26



$—








Oil contracts (Argus Houston MEH)





Swap contracts





Total volume (Bbls)

450,000





Weighted average price per Bbl

$46.50



$—



Collar contracts





Total volume (Bbls)

409,500





Weighted average price per Bbl





Ceiling (short call)

$47.00



$—



Floor (long put)

$41.00



$—





(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.

(b)

The short call swaption contracts have exercise expiration dates as follows: 455,000 Bbls expire on March 31, 2021 and 1,825,000 Bbls expire on December 31, 2021.

(c)

In January 2021, we paid approximately $3.1 million to terminate 184,000 Bbls of ICE Brent swaps. Additionally, in February 2021, we executed offsetting ICE Brent swaps on 159,300 Bbls, resulting in a locked-in loss of approximately $2.9 million which we will pay as the applicable contracts settle.


For the Full Year of


For the Full Year of


Natural gas contracts (Henry Hub)

2021


2022


Swap contracts





Total volume (MMBtu)

11,123,000





Weighted average price per MMBtu

$2.60



$—



Collar contracts (three-way collars)





Total volume (MMBtu)

1,350,000





Weighted average price per MMBtu





Ceiling (short call)

$2.70



$—



Floor (long put)

$2.42



$—



Floor (short put)

$2.00



$—



Collar contracts (two-way collars)





Total volume (MMBtu)

9,550,000



1,800,000



Weighted average price per MMBtu





Ceiling (short call)

$3.04



$3.88



Floor (long put)

$2.59



$2.78



Short call contracts





Total volume (MMBtu)

7,300,000


(a)



Weighted average price per MMBtu

$3.09



$—








Natural gas contracts (Waha basis differential)





Swap contracts





Total volume (MMBtu)

16,425,000





Weighted average price per MMBtu

($0.42)



$—





(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 Full Year of

NGL contracts (OPIS Mont Belvieu Purity Ethane)

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 $505.1 million for the three months ended December 31, 2020, or $12.71 per diluted share, and adjusted income of $42.8 million, or $1.00 per diluted share. The following tables reconcile the Company's loss available to common stockholders to adjusted income, and the Company's net loss to adjusted EBITDA:



Three Months Ended


Year Ended



December 31,
2020


September 30,
2020


December 31,
2019


December 31,
2020



(In thousands except per share data)

Loss available to common stockholders


($505,071)



($680,384)



($23,543)



($2,533,621)


(Gain) loss on derivatives contracts


125,739



27,038



30,694



27,773


Gain (loss) on commodity derivative settlements, net


(7,938)



(5,540)



(3,353)



95,856


Non-cash stock-based compensation expense (benefit)


2,968



(94)



1,010



2,663


Impairment of evaluated oil and gas properties


585,767



684,956





2,547,241


Merger and integration expense


2,120



2,465



68,420



28,482


Other expense


5,328



3,567





14,625


(Gain) loss on extinguishment of debt


(170,370)





4,881



(170,370)


Tax effect on adjustments above(a)


(114,159)



(149,602)



(21,347)



(534,717)


Change in valuation allowance


118,388



143,152





639,185


Adjusted income


$42,772



$25,558



$56,762



$117,117


Adjusted income per diluted share


$1.00



$0.64



$2.28



$2.86











Basic WASO(b)


39,752



39,746



24,822



39,718


Diluted WASO (GAAP)(b)


39,752



39,746



24,822



39,718


Effective of potentially dilutive instruments(b)


2,892



35



21



1,196


Adjusted Diluted WASO(b)


42,644



39,781



24,843



40,914




(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


Year Ended



December 31,
2020


September 30,
2020


December 31,
2019


December 31,
2020



(In thousands)

Net loss


($505,071)



($680,384)



($23,543)



($2,533,621)


(Gain) loss on derivatives contracts


125,739



27,038



30,694



27,773


Gain (loss) on commodity derivative settlements, net


(7,938)



(5,540)



(3,353)



95,856


Non-cash stock-based compensation expense (benefit)


2,968



(94)



3,390



2,663


Impairment of evaluated oil and gas properties


585,767



684,956





2,547,241


Merger and integration expense


2,120



2,465



68,420



28,482


Other expense


5,328



3,567



145



14,625


Income tax expense


6,755





5,857



122,054


Interest expense, net of capitalized amounts


26,486



24,683



689



94,329


Depreciation, depletion and amortization


96,037



114,201



63,198



480,631


(Gain) loss on extinguishment of debt


(170,370)





4,881



(170,370)


Adjusted EBITDA


$167,821



$170,892



$150,378



$709,663


Adjusted Free Cash Flow. Adjusted free cash flow for the three months ended December 31, 2020 was $24.4 million. The following table reconciles the Company's net cash provided by operating activities to adjusted EBITDA and adjusted free cash flow:



Three Months Ended



December 31,
2020


September 30,
2020


June 30,
2020


March 31,
2020


December 31,
2019



(In thousands)

Net cash provided by operating activities


$134,578



$135,701



$97,801



$191,695



$137,578


Changes in working capital and other


12,011



14,473



40,078



(32,569)



(55,620)


Changes in accrued hedge settlements


(5,055)



(5,993)



(14,480)



22,513




Cash interest expense, net


24,167



24,246



21,944



20,071




Merger and integration expense


2,120



2,465



8,067



15,830



68,420


Adjusted EBITDA


$167,821



$170,892



$153,410



$217,540



$150,378


Less: Operational capital expenditures (accrual)


87,488



38,408



85,087



277,640



110,021


Less: Capitalized interest


23,015



20,675



20,924



23,985



21,781


Less: Interest expense, net of capitalized amounts


26,486



24,683



22,682



20,478



689


Less: Capitalized cash G&A


6,465



6,831



6,740



7,371



8,780


Adjusted free cash flow


$24,367



$80,295



$17,977



($111,934)



$9,107


Adjusted Discretionary Cash Flow. Adjusted discretionary cash flow for the three months ended December 31, 2020 was $141.3 million and is reconciled to net cash provided by operating activities in the following table:



Three Months Ended



December 31, 2020


September 30, 2020


December 31, 2019



(In thousands)

Net loss


($505,071)



($680,384)



($23,543)


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







Depreciation, depletion and amortization


96,037



114,201



63,198


Impairment of evaluated oil and gas properties


585,767



684,956




Amortization of non-cash debt related items


2,319



437



689


Deferred income tax expense


3,308





5,857


(Gain) loss on derivative contracts


125,739



27,038



30,694


Cash (paid) received for commodity derivative settlements, net


(2,884)



453



(3,353)


Non-cash (gain) loss on early extinguishment of debt


(170,370)





4,881


Non-cash stock-based compensation expense (benefit)


2,968



(94)



3,417


Merger and integration expense


2,120



2,465



68,420


Other, net


1,347



2,099



(126)


Adjusted discretionary cash flow


$141,280



$151,171



$150,134


Changes in working capital


(4,582)



(13,005)



55,864


Merger and integration expense


(2,120)



(2,465)



(68,420)


Net cash provided by operating activities


$134,578



$135,701



$137,578


Adjusted Total Revenue. Adjusted total revenue for the three months ended December 31, 2020 was $259.0 million and is reconciled to total operating revenues, which excludes revenue from sales of commodities purchased from a third-party, in the following table:



Three Months Ended



December 31, 2020


September 30, 2020


December 31, 2019



(In thousands)

Operating Revenues







Oil


$222,733



$231,654



$183,071


Natural gas


18,561



15,034



10,949


Natural gas liquids


25,668



23,025



2,075


Total operating revenues


$266,962



$269,713



$196,095


Impact of settled derivatives


(7,938)



(5,540)



(3,353)


Adjusted total revenue


$259,024



$264,173



$192,742


PV-10. PV-10 as of December 31, 2020 is reconciled below to the standardized measure of discounted future net cash flows:



As of December 31, 2020



(In millions)

Standardized measure of discounted future net cash flows


$2,310.4


Add: present value of future income taxes discounted at 10% per annum


$34.6


Total proved reserves - PV-10


$2,345.0


Total proved developed reserves - PV-10


$1,577.3


Total proved undeveloped reserves - PV-10


$767.7


Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par values and share data)



December 31,


2020


2019

ASSETS




Current assets:




Cash and cash equivalents

$20,236



$13,341


Accounts receivable, net

133,109



209,463


Fair value of derivatives

921



26,056


Other current assets

24,103



19,814


Total current assets

178,369



268,674


Oil and natural gas properties, full cost accounting method:




Evaluated properties, net

2,355,710



4,682,994


Unevaluated properties

1,733,250



1,986,124


Total oil and natural gas properties, net

4,088,960



6,669,118


Operating lease right-of-use assets

22,526



63,908


Other property and equipment, net

31,640



35,253


Deferred tax asset



115,720


Deferred financing costs

23,643



22,233


Other assets, net

17,730



19,932


Total assets

$4,362,868



$7,194,838


LIABILITIES AND STOCKHOLDERS' EQUITY




Current liabilities:




Accounts payable and accrued liabilities

$345,365



$490,442


Operating lease liabilities

13,175



42,858


Fair value of derivatives

97,060



71,197


Other current liabilities

41,508



47,750


Total current liabilities

497,108



652,247


Long-term debt

2,969,264



3,186,109


Operating lease liabilities

27,576



37,088


Asset retirement obligations

57,209



48,860


Fair value of derivatives

88,046



32,695


Other long-term liabilities

12,663



14,531


Total liabilities

3,651,866



3,971,530


Commitments and contingencies




Stockholders' equity:




Common stock, $0.01 par value, 52,500,000 shares authorized, 39,758,817 and 39,659,001 shares outstanding, respectively (a)

398



3,966


Capital in excess of par

3,222,959



3,198,076


Retained earnings (Accumulated deficit)

(2,512,355)



21,266


Total stockholders' equity

711,002



3,223,308


Total liabilities and stockholders' equity

$4,362,868



$7,194,838




(a)

All share amounts (except par value) have been retroactively adjusted for the Company's 1-for-10 reverse stock split effective August 7, 2020.

Callon Petroleum Company

Consolidated Statements of Operations

(in thousands, except per share data)



Three Months Ended December 31,


For the Year Ended December 31,


2020


2019


2020


2019

Operating Revenues:








Oil

$222,733



$183,071



$850,667



$633,107


Natural gas

18,561



10,949



51,866



36,390


Natural gas liquids

25,668



2,075



81,295



2,075


Sales of purchased oil and gas

29,006





49,319




Total operating revenues

295,968



196,095



1,033,147



671,572










Operating Expenses:








Lease operating

45,010



25,316



194,101



91,827


Production and ad valorem taxes

16,487



8,841



62,638



42,651


Gathering, transportation and processing

20,694





77,309




Cost of purchased oil and gas

30,484





51,766




Depreciation, depletion and amortization

96,037



61,367



480,631



240,642


General and administrative

10,614



13,626



37,187



45,331


Impairment of evaluated oil and gas properties

585,767





2,547,241




Merger and integration expenses

2,120



68,420



28,482



74,363


Other operating

2,084



145



10,644



4,100


Total operating expenses

809,297



177,715



3,489,999



498,914


Income (Loss) From Operations

(513,329)



18,380



(2,456,852)



172,658










Other (Income) Expenses:








Interest expense, net of capitalized amounts

26,486



689



94,329



2,907


(Gain) loss on derivative contracts

125,739



30,694



27,773



62,109


(Gain) loss on extinguishment of debt

(170,370)



4,881



(170,370)



4,881


Other (income) expense

3,132



(198)



2,983



(468)


Total other (income) expense

(15,013)



36,066



(45,285)



69,429










Income (Loss) Before Income Taxes

(498,316)



(17,686)



(2,411,567)



103,229


Income tax expense

(6,755)



(5,857)



(122,054)



(35,301)


Net Income (Loss)

($505,071)



($23,543)



($2,533,621)



$67,928


Preferred stock dividends







(3,997)


Loss on redemption of preferred stock







(8,304)


Income (Loss) Available to Common Stockholders

($505,071)



($23,543)



($2,533,621)



$55,627










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








Basic

($12.71)



($0.95)



($63.79)



$2.39


Diluted

($12.71)



($0.95)



($63.79)



$2.38










Weighted Average Common Shares Outstanding (a):








Basic

39,752



24,822



39,718



23,313


Diluted

39,752



24,822



39,718



23,340




(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)



Three Months Ended
December 31,


For the Year Ended
December 31,


2020


2019


2020


2019

Cash flows from operating activities:








Net income (loss)

($505,071)



($23,543)



($2,533,621)



$67,928


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








Depreciation, depletion and amortization

96,037



63,198



480,631



245,936


Impairment of evaluated oil and gas properties

585,767





2,547,241




Amortization of non-cash debt related items

2,319



689



3,901



2,907


Deferred income tax expense

3,308



5,857



118,607



35,301


(Gain) loss on derivative contracts

125,739



30,694



27,773



62,109


Cash received (paid) for commodity derivative settlements, net

(2,884)



(3,353)



98,870



(3,789)


(Gain) loss on early extinguishment of debt

(170,370)



4,881



(170,370)



4,881


Non-cash expense related to equity share-based awards

471



1,899



6,773



9,767


Change in the fair value of liability share-based awards

2,497



1,518



(4,110)



1,624


Payments for cash-settled restricted stock unit awards





(770)



(1,425)


Other, net

1,347



(126)



7,857



(90)


Changes in current assets and liabilities:








Accounts receivable

(20,340)



(52,671)



75,770



(35,071)


Other current assets

6



1,006



(6,550)



(4,166)


Accounts payable and accrued liabilities

15,752



96,753



(92,227)



82,290


Other



10,776





8,114


Net cash provided by operating activities

134,578



137,578



559,775



476,316


Cash flows from investing activities:








Capital expenditures

(109,408)



(137,115)



(677,154)



(640,540)


Acquisitions



(1,478)





(42,266)


Proceeds from sales of assets

29,152



14,465



178,970



294,417


Cash paid for settlements of contingent consideration arrangements, net





(40,000)




Other, net

40





8,301




Net cash used in investing activities

(80,216)



(124,128)



(529,883)



(388,389)


Cash flows from financing activities:








Borrowings on Credit Facility

265,500



1,874,900



5,353,000



2,455,900


Payments on Credit Facility

(305,500)



(314,500)



(5,653,000)



(895,500)


Payment to terminate Prior Credit Facility



(475,400)





(475,400)


Repayment of Carrizo's senior secured revolving credit facility



(853,549)





(853,549)


Repayment of Carrizo's preferred stock



(220,399)





(220,399)


Issuance of 9.00% Second Lien Senior Secured Notes due 2025





300,000




Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025





(35,270)




Issuance of September 2020 Warrants





23,909




Payment of preferred stock dividends







(3,997)


Payment of deferred financing costs and debt exchange costs

(4,499)



(22,449)



(10,811)



(22,480)


Tax withholdings related to restricted stock units

(14)



(21)



(509)



(2,195)


Redemption of preferred stock







(73,017)


Other, net

(113)





(316)




Net cash used in financing activities

(44,626)



(11,418)



(22,997)



(90,637)


Net change in cash and cash equivalents

9,736



2,032



6,895



(2,710)


Balance, beginning of period

10,500



11,309



13,341



16,051


Balance, end of period

$20,236



$13,341



$20,236



$13,341



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", "adjusted total revenue", and "PV-10." 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, capitalized interest, net 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-recurring expenses and 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 a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. See the reconciliation provided above for further details.

  • 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. See the reconciliation provided above for further details.

  • 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 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 diluted 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, 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 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.

  • Callon believes that the presentation of pre-tax PV-10 value is relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account future corporate income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies. The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows. Pre-tax PV-10 is calculated using the standardized measure of discounted future net cash flows before deducting future income taxes, discounted at 10 percent.


Earnings Call Information

The Company will host a conference call on Thursday, February 25, 2021, to discuss fourth quarter 2020 financial and operating results, 2021 outlook, and the durability of our business under various commodity price scenarios.

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

Date/Time:

Thursday, February 25, 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

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 Statements

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of 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
1-281-589-5200

1)

See "Non-GAAP Financial Measures" included within this release for related disclosures.

2)

All references to 2019 pro forma figures assume full year Callon and Carrizo combined financials

3)

Callon defines "reinvestment rate" as (Accrued Operational Capital Expenditures) / (Adjusted Discretionary Cash Flow - Capitalized Expenses)

4)

Management's internal estimate of PV-10 value at flat forward prices set forth above is provided to illustrate reserve sensitivities to expectations of commodity prices and do not comply with SEC pricing assumptions. Actual future prices may vary significantly from the flat forward prices used in management's internal estimate of PV-10; therefore, actual revenue and value generated may be more or less than the PV-10 estimate.

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SOURCE Callon Petroleum Company