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

Rhea-AI Summary

Callon Petroleum Company (CPE) reported significant operational results for 2020, achieving a 146% production increase to 101.6 MBoe/d, with year-end proved reserves of 475.9 MMBoe. The company faced a $2.5 billion loss due to asset impairments but improved net cash from operations to $559.8 million. For 2021, Callon forecasts 90-92 MBoe/d production and projects $150 million adjusted free cash flow at $50/Bbl oil prices. Operational efficiencies yielded a 35% reduction in drilling costs, underpinning robust debt reduction initiatives.

Positive

• Production increased by 146% year-over-year to 101.6 MBoe/d.
• Total proven reserves at year-end were 475.9 MMBoe, indicating strong asset value.
• Operational capital expenditures reduced by 12% for 2021 to $430 million.
• Expected adjusted free cash flow of $150 million at $50/Bbl oil prices.
• Average drilling costs decreased by approximately 35% compared to 2019.

Negative

• Loss available to common stockholders was $2.5 billion, or $63.79 per diluted share, due to asset impairments.
• Impairments of evaluated oil and gas properties amounted to $585.8 million in Q4 2020.
• Fourth-quarter production fell by 7% sequentially due to divestitures and winter storm impacts.

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

FAQ

What were Callon Petroleum's production numbers for 2020?

Callon Petroleum reported a production of 101.6 MBoe/d for the full year 2020.

What is Callon Petroleum's expected production guidance for 2021?

Callon expects production to be between 90 and 92 MBoe/d for 2021.

How much free cash flow is Callon Petroleum projecting for 2021?

Callon anticipates generating approximately $150 million in adjusted free cash flow at $50/Bbl oil prices.

What was the net cash provided by operating activities for Callon Petroleum in 2020?

Callon generated net cash provided by operating activities of $559.8 million for 2020.

What was the loss to common stockholders for Callon Petroleum in Q4 2020?

In Q4 2020, Callon reported a loss available to common stockholders of $505.1 million.