Document

Exhibit 99.1

Callon Petroleum Company Announces Second Quarter 2021 Results

HOUSTON, TX (August 4, 2021) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three and six months ended June 30, 2021.

Presentation slides accompanying this earnings release are available on the Company’s website at www.callon.com located on the “Presentations” page within the Investors section of the site.

Second Quarter 2021 and Recent Highlights

•Delivered production of approximately 89.0 MBoe/d (63% oil) in the second quarter of 2021

•Generated net cash provided by operating activities of $175.6 million and adjusted free cash flow1 of $6.9 million

•Net loss of $11.7 million, or $0.25 per diluted share, driven primarily by a loss on derivative contracts of $190.5 million, adjusted EBITDA1 of $196.8 million, and adjusted income1 of $70.3 million, or $1.49 per diluted share

•Achieved an operating margin of $37.76 per Boe, a 13% increase from the previous quarter

•Completed the divestiture of certain non-core assets for aggregate net cash proceeds of $30.7 million

•Issued $650 million of new 8.00% senior unsecured notes due 2028 and completed the redemption of the 6.25% senior unsecured notes due 2023

•Received company credit rating upgrades from both Moody’s and S&P following successful senior notes offering

•Reduced the outstanding balance on Callon’s senior secured credit facility to approximately $780 million, representing less than 50% utilization of the available capacity2

•Executed Callon’s largest multi-well project in history, the 29-well Irvin West project, driving robust production growth with July volumes estimated to be approximately 10% above second quarter average daily production

•Issued the company’s second annual sustainability report, highlighting meaningful improvement in key categories as well as incremental transparency measures and alignment with both SASB and TCFD reporting standards.

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

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

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

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

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

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

Credit Facility and Liquidity

On May 3, 2021, Callon completed the spring redetermination for its senior secured credit facility. The borrowing base and elected commitment were both reaffirmed at $1.6 billion. As of June 30, 2021, the drawn balance on the facility was $875.0 million and cash balances were $3.8 million. Upon completion of the redemption of the 6.25% Senior Notes, the remaining proceeds from the issuance of the 8.00% Senior Notes were used to repay outstanding borrowings on the credit facility, further reducing the outstanding balance to approximately $780.0 million2.

Sale of Delaware Basin Assets

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

Operations Update

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

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

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

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

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

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

Capital Expenditures

For the three months ended June 30, 2021, Callon incurred $138.3 million in operational capital expenditures on an accrual basis. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis:


	Three Months Ended June 30, 2021
	Operational	Capitalized	Capitalized	Total Capital
	Capital (a)	Interest	G&A	Expenditures
	(In thousands)
Cash basis (b)	$111,344	$30,914	$7,404	$149,662
Timing adjustments (c)	28,379	(9,174)	—	19,205
Non-cash items	(1,402)	2,187	4,647	5,432
Accrual basis	$138,321	$23,927	$12,051	$174,299

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

(b)Cash basis is presented here to help users of financial information reconcile amounts from the cash flow statement to the balance sheet by accounting for timing related changes in working capital that align with our development pace and rig count.

(c)Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period.

Guidance

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

Hedge Portfolio Summary

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


	For the Remainder		For the Full Year		For the Full Year
Oil contracts (WTI)	of 2021(a)		of 2022(a)		of 2023
Swap contracts
Total volume (Bbls)	1,104,000		3,015,000		—
Weighted average price per Bbl	$42.10		$63.55		$—
Collar contracts
Total volume (Bbls)	5,522,775		7,097,500		—
Weighted average price per Bbl
Ceiling (short call)	$49.16		$67.70		$—
Floor (long put)	$40.71		$56.15		$—
Long put contracts
Total volume (Bbls)	414,000		—		—
Weighted average price per Bbl	$62.50		$—		$—



Short call contracts
Total volume (Bbls)	2,432,480	(b)	—		—
Weighted average price per Bbl	$63.62		$—		$—
Short call swaption contracts
Total volume (Bbls)	—		1,825,000	(c)	1,825,000	(c)
Weighted average price per Bbl	$—		$52.18		$72.00

Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls)	—	(d)	—		—
Weighted average price per Bbl	$—		$—		$—
Collar contracts
Total volume (Bbls)	368,000		—		—
Weighted average price per Bbl
Ceiling (short call)	$50.00		$—		$—
Floor (long put)	$45.00		$—		$—

Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	1,504,400		—		—
Weighted average price per Bbl	$0.25		$—		$—





Oil contracts (Argus Houston MEH)
Collar contracts
Total volume (Bbls)	—		452,500		—
Weighted average price per Bbl
Ceiling (short call)	$—		$63.15		$—
Floor (long put)	$—		$51.25		$—

(a) The Company has approximately $9.4 million of deferred premiums, of which $6.5 million are associated with contracts that will settle in 2021 and $2.9 million for contracts that will settle in 2022.

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

(c) The 2022 and 2023 short call swaption contracts have exercise expiration dates of December 31, 2021 and December 30, 2022, respectively.

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


	For the Remainder		For the Full Year
Natural gas contracts (Henry Hub)	of 2021		of 2022
Swap contracts
Total volume (MMBtu)	7,301,000		7,320,000
Weighted average price per MMBtu	$2.61		$3.08






Collar contracts
Total volume (MMBtu)	3,680,000		5,740,000
Weighted average price per MMBtu
Ceiling (short call)	$2.80		$3.64
Floor (long put)	$2.50		$2.83
Short call contracts
Total volume (MMBtu)	3,680,000	(a)	—
Weighted average price per MMBtu	$3.09		$—

Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	8,280,000		5,475,000
Weighted average price per MMBtu	($0.42)		($0.21)

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

For the Remainder

For the Full Year

NGL contracts (OPIS Mont Belvieu Purity Ethane)

of 2021

of 2022

Swap contracts

Total volume (Bbls)

920,000

—

Weighted average price per Bbl

$7.62

$—

Operating and Financial Results

The following table presents summary information for the periods indicated:


	Three Months Ended
	June 30, 2021		March 31, 2021		June 30, 2020
Total production
Oil (MBbls)
Permian	3,232		3,088		3,633
Eagle Ford	1,870		1,593		2,763
Total oil (MBbls)	5,102		4,681		6,396

Natural gas (MMcf)
Permian	7,138		6,208		8,736
Eagle Ford	1,745		1,627		2,273
Total natural gas (MMcf)	8,883		7,835		11,009

NGLs (MBbls)
Permian	1,216		1,075		1,268
Eagle Ford	299		224		389
Total NGLs (MBbls)	1,515		1,299		1,657

Total production (MBoe)
Permian	5,637		5,198		6,357
Eagle Ford	2,460		2,088		3,531
Total barrels of oil equivalent (MBoe)	8,097		7,286		9,888

Total daily production (Boe/d)
Permian	61,948		57,758		69,858
Eagle Ford	27,033		23,199		38,806
Total barrels of oil equivalent (Boe/d)	88,981		80,957		108,664
Oil as % of total daily production	63	%	64	%	65	%

Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)
Permian	$65.08		$56.66		$23.27
Eagle Ford	65.83		57.80		16.64
Total oil (per Bbl)	$65.36		$57.05		$20.41

Natural gas (per Mcf)
Permian	$2.68		$3.11		$0.95
Eagle Ford	2.82		3.03		1.73
Total natural gas (per Mcf)	$2.71		$3.09		$1.11

NGLs (per Bbl)
Permian	$24.71		$22.68		$8.77
Eagle Ford	22.00		22.24		8.65
Total NGLs (per Bbl)	$24.17		$22.60		$8.74

Average realized sales price (per Boe)
Permian	$46.04		$42.06		$16.35
Eagle Ford	54.72		48.85		15.09
Total average realized sales price (per Boe)	$48.68		$44.01		$15.90

Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)	$46.82		$44.33		$33.82
Natural gas (per Mcf)	2.25		2.88		0.97
NGLs (per Bbl)	23.21		21.77		8.74
Total average realized sales price (per Boe)	$36.31		$35.46		$24.42


	Three Months Ended
	June 30, 2021	March 31, 2021	June 30, 2020
Revenues (in thousands)(a)
Oil
Permian	$210,340	$174,967	$84,538
Eagle Ford	123,102	92,078	45,975
Total oil	$333,442	$267,045	$130,513

Natural gas
Permian	$19,152	$19,290	$8,309
Eagle Ford	4,928	4,930	3,933
Total natural gas	$24,080	$24,220	$12,242

NGLs
Permian	$30,047	$24,376	$11,116
Eagle Ford	6,578	4,981	3,363
Total NGLs	$36,625	$29,357	$14,479

Total revenues
Permian	$259,539	$218,633	$103,963
Eagle Ford	134,608	101,989	53,271
Total revenues	$394,147	$320,622	$157,234

Additional per Boe data
Sales price (b)
Permian	$46.04	$42.06	$16.35
Eagle Ford	54.72	48.85	15.09
Total sales price	$48.68	$44.01	$15.90

Lease operating
Permian	$4.60	$4.31	$5.01
Eagle Ford	8.34	8.65	5.38
Total lease operating	$5.74	$5.55	$5.14

Production and ad valorem taxes
Permian	$2.53	$2.32	$1.11
Eagle Ford	3.12	3.07	0.94
Total production and ad valorem taxes	$2.71	$2.53	$1.05

Gathering, transportation and processing
Permian	$2.75	$2.54	$2.31
Eagle Ford	1.84	2.29	1.51
Total gathering, transportation and processing	$2.47	$2.47	$2.03

Operating margin
Permian	$36.16	$32.89	$7.92
Eagle Ford	41.42	34.84	7.26
Total operating margin	$37.76	$33.46	$7.68

Depreciation, depletion and amortization	$10.27	$9.74	$14.05
General and administrative	$1.37	$2.31	$1.01
Adjusted G&A 1
Cash component (c)	$0.71	$1.26	$0.69
Non-cash component	$0.21	$0.23	$0.15

(a)Excludes sales of oil and gas purchased from third parties.

(b)Excludes the impact of settled derivatives.

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

Revenue. For the quarter ended June 30, 2021, Callon reported revenue of $394.1 million, which excluded revenue from sales of commodities purchased from a third party of $46.3 million. Revenues including the gain or loss from the settlement of derivative

contracts (“Adjusted Total Revenue”1) were $294.0 million, reflecting the impact of a $100.1 million loss from the settlement of derivative contracts. Average daily production for the quarter was 89.0 MBoe/d, compared to average daily production of 81.0 MBoe/d in the first quarter of 2021. Average realized prices, including and excluding the effects of hedging, are detailed above.

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


			Three Months Ended June 30, 2021
Loss on oil derivatives			$177,033
Loss on natural gas derivatives			12,816
Loss on NGL derivatives			3,734
Loss on commodity derivative contracts			$193,583

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


			Three Months Ended June 30, 2021
Cash paid on oil derivatives			($82,413)
Cash paid on natural gas derivatives			(1,906)
Cash paid on NGL derivatives			(1,090)
Cash paid for commodity derivative settlements, net			($85,409)

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

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended June 30, 2021 represented approximately 5.6% of total revenue excluding revenue from sales of commodities purchased from a third-party and before the impact of derivative settlements.

Gathering, Transportation and Processing. Gathering, transportation and processing for the three months ended June 30, 2021 was $20.0 million, or $2.47 per Boe, as compared to $18.0 million, or $2.47 per Boe in the first quarter of 2021. This increase is related to the 11% increase in production volumes between the two periods.

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

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

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


	Three Months Ended
	June 30, 2021	March 31, 2021	June 30, 2020
Total G&A	$11,065	$16,799	$10,024
Change in the fair value of liability share-based awards (non-cash)	(3,555)	(5,943)	(1,720)
Adjusted G&A – total	7,510	10,856	8,304
Equity-settled, share-based compensation (non-cash) and other non-recurring expenses	(1,724)	(1,665)	(1,509)
Adjusted G&A – cash component	$5,786	$9,191	$6,795

Capitalized cash G&A	7,404	6,913	6,740
Full cash G&A	$13,190	$16,104	$13,535

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

Adjusted EBITDA. Net loss was $11.7 million and adjusted EBITDA was $196.8 million for the second quarter of 2021 as compared to net loss of $80.4 million and adjusted EBITDA of $170.6 million for the first quarter of 2021. The increase in adjusted EBITDA from the first quarter of 2021 was primarily due to an increase in revenues partially offset by increased payments associated with our commodity derivative settlements.

Adjusted Income and Adjusted EBITDA. The following tables reconcile the Company’s net loss to adjusted income and adjusted EBITDA:


	Three Months Ended
	June 30, 2021	March 31, 2021	June 30, 2020
	(In thousands, except per share data)
Net loss	($11,695)	($80,407)	($1,564,731)
Loss on derivative contracts	190,463	214,523	126,965
Gain (loss) on commodity derivative settlements, net	(100,128)	(62,280)	84,208
Non-cash stock-based compensation expense	5,279	7,608	2,761
Impairment of evaluated oil and gas properties	—	—	1,276,518
Merger and integration expense	—	—	8,067
Other (income) expense	5,584	(3,306)	6,759

Tax effect on adjustments above(a)	(21,252)	(32,874)	(316,108)
Change in valuation allowance	2,079	26,724	377,645
Adjusted income	$70,330	$69,988	$2,084
Adjusted income per diluted share	$1.49	$1.49	$0.05

Basic WASO(b)	46,267	42,590	39,707
Diluted WASO (GAAP)(b)	46,267	42,590	39,707
Effect of potentially dilutive instruments(b)	862	4,354	12
Adjusted Diluted WASO(b)	47,129	46,944	39,719

(a) Calculated using the federal statutory rate of 21%.

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


	Three Months Ended
	June 30, 2021	March 31, 2021	June 30, 2020
	(In thousands)
Net loss	($11,695)	($80,407)	($1,564,731)
Loss on derivative contracts	190,463	214,523	126,965
Gain (loss) on commodity derivative settlements, net	(100,128)	(62,280)	84,208
Non-cash stock-based compensation expense	5,279	7,608	2,761
Impairment of evaluated oil and gas properties	—	—	1,276,518
Merger and integration expense	—	—	8,067
Other (income) expense	5,584	(3,306)	6,759
Income tax (benefit) expense	(478)	(921)	51,251
Interest expense, net	24,634	24,416	22,682
Depreciation, depletion and amortization	83,128	70,987	138,930

Adjusted EBITDA	$196,787	$170,620	$153,410

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


	Three Months Ended
	June 30, 2021	March 31, 2021	June 30, 2020
	(In thousands)
Net cash provided by operating activities	$175,603	$137,665	$97,801
Changes in working capital and other	13,520	30,913	40,078
Change in accrued hedge settlements	(14,719)	(20,117)	(14,480)
Cash interest expense, net	22,383	22,159	21,944
Merger and integration expense	—	—	8,067
Adjusted EBITDA	196,787	170,620	153,410
Less: Operational capital expenditures (accrual)	138,321	95,545	85,087
Less: Capitalized interest	21,740	21,817	20,924
Less: Interest expense, net of capitalized amounts	22,383	22,159	22,682
Less: Capitalized cash G&A	7,404	6,913	6,740
Adjusted free cash flow (a)	$6,939	$24,186	$17,977

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

Adjusted Discretionary Cash Flow. The following table reconciles the Company’s net cash provided by operating activities to adjusted discretionary cash flow:


	Three Months Ended
	June 30, 2021	March 31, 2021	June 30, 2020
	(In thousands)
Cash flows from operating activities:
Net loss	($11,695)	($80,407)	($1,564,731)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization	83,128	70,987	138,930
Impairment of evaluated oil and gas properties	—	—	1,276,518
Amortization of non-cash debt related items	2,252	2,256	738
Deferred income tax expense	—	—	51,251
Loss on derivative contracts	190,463	214,523	126,965
Cash (paid) received for commodity derivative settlements, net	(85,409)	(42,162)	98,688

Non-cash stock-based compensation expense	5,279	7,608	2,761

Merger and integration expense	—	—	8,067
Other, net	3,294	1,217	3,521
Adjusted discretionary cash flow	$187,312	$174,022	$142,708
Changes in working capital	(11,709)	(36,357)	(36,840)

Merger and integration expense	—	—	(8,067)
Net cash provided by operating activities	$175,603	$137,665	$97,801

Adjusted Total Revenue. Adjusted total revenue is reconciled to total operating revenues, which excludes revenue from sales of commodities purchased from a third party, in the following table:


	Three Months Ended
	June 30, 2021	March 31, 2021	June 30, 2020
	(In thousands)
Operating revenues
Oil	$333,442	$267,045	$130,513
Natural gas	24,080	24,220	12,242
NGLs	36,625	29,357	14,479
Total operating revenues	$394,147	$320,622	$157,234
Impact of settled derivatives	(100,128)	(62,280)	84,208
Adjusted total revenue	$294,019	$258,342	$241,442

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and share amounts)

(Unaudited)


	June 30, 2021	December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$3,800	$20,236
Accounts receivable, net	200,246	133,109
Fair value of derivatives	14,941	921
Other current assets	24,876	24,103
Total current assets	243,863	178,369
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net	2,517,783	2,355,710
Unevaluated properties	1,697,832	1,733,250
Total oil and natural gas properties, net	4,215,615	4,088,960

Other property and equipment, net	32,805	31,640

Deferred financing costs	20,670	23,643

Other assets, net	33,444	40,256
Total assets	$4,546,397	$4,362,868
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$419,434	$341,519




Fair value of derivatives	331,702	97,060
Other current liabilities	62,668	58,529
Total current liabilities	813,804	497,108
Long-term debt	2,865,154	2,969,264

Asset retirement obligations	57,546	57,209

Fair value of derivatives	8,204	88,046
Other long-term liabilities	44,401	40,239
Total liabilities	3,789,109	3,651,866
Commitments and contingencies
Stockholders’ equity:

Common stock, $0.01 par value, 78,750,000 and 52,500,000 shares authorized; 46,288,813 and 39,758,817 shares outstanding, respectively	463	398
Capital in excess of par value	3,361,282	3,222,959
Accumulated deficit	(2,604,457)	(2,512,355)
Total stockholders’ equity	757,288	711,002
Total liabilities and stockholders’ equity	$4,546,397	$4,362,868

Callon Petroleum Company

Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)


	Three Months Ended June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
Operating Revenues:
Oil	$333,442	$130,513	$600,487	$396,280
Natural gas	24,080	12,242	48,300	18,271
Natural gas liquids	36,625	14,479	65,982	32,602
Sales of purchased oil and gas	46,252	—	85,511	—
Total operating revenues	440,399	157,234	800,280	447,153

Operating Expenses:
Lease operating	46,460	50,838	86,913	103,221
Production and ad valorem taxes	21,958	10,361	40,397	30,041
Gathering, transportation and processing	20,031	20,037	38,012	34,415
Cost of purchased oil and gas	49,249	—	90,166	—
Depreciation, depletion and amortization	83,128	138,930	154,115	270,393
General and administrative	11,065	10,024	27,864	18,349
Impairment of evaluated oil and gas properties	—	1,276,518	—	1,276,518
Merger and integration	—	8,067	—	23,897

Other operating	2,437	4,135	3,366	4,135
Total operating expenses	234,328	1,518,910	440,833	1,760,969
Income (Loss) From Operations	206,071	(1,361,676)	359,447	(1,313,816)

Other (Income) Expenses:
Interest expense, net of capitalized amounts	24,634	22,682	49,050	43,160
(Gain) loss on derivative contracts	190,463	126,965	404,986	(125,004)
Other (income) expense	3,147	2,157	(1,088)	895
Total other (income) expense	218,244	151,804	452,948	(80,949)

Loss Before Income Taxes	(12,173)	(1,513,480)	(93,501)	(1,232,867)
Income tax benefit (expense)	478	(51,251)	1,399	(115,299)
Net Loss	($11,695)	($1,564,731)	($92,102)	($1,348,166)

Net Loss Per Common Share (a):
Basic	($0.25)	($39.41)	($2.07)	($33.97)
Diluted	($0.25)	($39.41)	($2.07)	($33.97)

Weighted Average Common Shares Outstanding (a):
Basic	46,267	39,707	44,439	39,687
Diluted	46,267	39,707	44,439	39,687

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

Callon Petroleum Company

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)


	Three Months Ended June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
Cash flows from operating activities:
Net loss	($11,695)	($1,564,731)	($92,102)	($1,348,166)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	83,128	138,930	154,115	270,393
Impairment of evaluated oil and gas properties	—	1,276,518	—	1,276,518
Amortization of non-cash debt related items, net	2,252	738	4,508	1,145
Deferred income tax expense	—	51,251	—	115,299
(Gain) loss on derivative contracts	190,463	126,965	404,986	(125,004)
Cash received (paid) for commodity derivative settlements, net	(85,409)	98,688	(127,571)	101,301

Non-cash expense (benefit) related to share-based awards	5,279	2,761	12,887	(211)



Other, net	3,294	3,520	4,511	3,656
Changes in current assets and liabilities:
Accounts receivable	(21,674)	(2,833)	(67,357)	113,040
Other current assets	(4,567)	(3,567)	(7,423)	(4,348)
Accounts payable and accrued liabilities	14,532	(30,439)	26,714	(114,127)

Net cash provided by operating activities	175,603	97,801	313,268	289,496
Cash flows from investing activities:
Capital expenditures	(149,662)	(205,229)	(251,003)	(418,688)
Acquisition of oil and gas properties	(1,447)	(892)	(2,215)	(11,881)
Proceeds from sale of assets	31,611	(161)	31,611	10,079
Cash paid for settlements of contingent consideration arrangements, net	—	—	—	(40,000)

Other, net	625	6,992	4,220	6,834
Net cash used in investing activities	(118,873)	(199,290)	(217,387)	(453,656)
Cash flows from financing activities:
Borrowings on Credit Facility	433,500	484,500	736,500	4,775,500
Payments on Credit Facility	(508,500)	(384,500)	(846,500)	(4,610,500)






Payment of deferred financing and debt exchange costs	—	(5,736)	—	(6,011)
Tax withholdings related to restricted stock units	(2,280)	—	(2,280)	(388)

Other, net	—	(75)	(37)	(282)
Net cash provided by (used in) financing activities	(77,280)	94,189	(112,317)	158,319
Net change in cash and cash equivalents	(20,550)	(7,300)	(16,436)	(5,841)
Balance, beginning of period	24,350	14,800	20,236	13,341
Balance, end of period	$3,800	$7,500	$3,800	$7,500

Non-GAAP Financial Measures

This news release refers to non-GAAP financial measures such as “adjusted free cash flow,” “adjusted discretionary cash flow,” “adjusted G&A,” “full cash G&A,” “adjusted income,” “adjusted income per diluted share,” “adjusted EBITDA,” and “adjusted total revenue.” These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our filings with the U.S. Securities and Exchange Commission (the “SEC”) and posted on our website.

•Adjusted free cash flow is a supplemental non-GAAP measure that is defined by the Company as adjusted EBITDA less operational capital, cash capitalized interest, net cash interest expense and capitalized cash G&A (which excludes capitalized expense related to share-based awards). We believe adjusted free cash flow is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company’s ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted free cash flow is not a measure of a company’s financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).

•Adjusted discretionary cash flow is a supplemental non-GAAP measure that Callon believes is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company’s ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and merger and integration expenses. Callon has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the Company may not control and the cash flow effect may not be reflected the period in which the operating activities occurred. Adjusted discretionary cash flow is not a measure of a company’s financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).

•Adjusted G&A is a supplemental non-GAAP financial measure that excludes certain non-cash incentive share-based compensation valuation adjustments. Callon believes that the non-GAAP measure of adjusted G&A is useful to investors because it provides a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period.

•Full cash G&A is a supplemental non-GAAP financial measure that Callon defines as adjusted G&A – cash component plus capitalized G&A excluding capitalized expense related to share-based awards. Callon believes that the non-GAAP measure of full cash G&A is useful because it provides users with a meaningful measure of our total recurring cash G&A costs, whether expensed or capitalized, and provides for greater comparability on a period-over-period basis.

•Adjusted income and adjusted income per diluted share are supplemental non-GAAP measures that Callon believes are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of these items and non-cash valuation adjustments, which are detailed in the reconciliation provided. Adjusted income and adjusted income per diluted share are not measures of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), or other income data prepared in accordance with GAAP. However, the Company believes that adjusted income and adjusted income per diluted share provide additional information with respect to our performance. Because adjusted income and adjusted income per diluted share exclude some, but not all, items that affect net income (loss) and may vary among companies, the adjusted income and adjusted income per diluted share presented above may not be comparable to similarly titled measures of other companies.

•Adjusted diluted weighted average common shares outstanding (“Adjusted Diluted WASO”) is a non-GAAP financial measure which includes the effect of potentially dilutive instruments that, under certain circumstances described below, are excluded from diluted weighted average common shares outstanding (“Diluted WASO”), the most directly comparable GAAP financial measure. When a net loss exists, all potentially dilutive instruments are anti-dilutive to the net loss per common share and therefore excluded from the computation of Diluted WASO. The effect of potentially dilutive instruments are included in the computation of Adjusted Diluted WASO for purposes of computing adjusted income per diluted share.

•Callon calculates adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of evaluated oil and gas properties, non-cash stock-based compensation expense, merger and integration expense, (gain) loss on extinguishment of debt, and other operating expenses. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, the Company believes that adjusted EBITDA provides additional information with respect to our performance or ability to meet our future debt service, capital expenditures and working capital requirements. Because adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted EBITDA presented above may not be comparable to similarly titled measures of other companies.

•Callon believes that the non-GAAP measure of adjusted total revenue (which is revenue including the gain or loss from the settlement of derivative contracts) is useful to investors because it provides readers with a revenue value more comparable to

other companies who engage in price risk management activities through the use of commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues. See the reconciliation provided above for further details.

Earnings Call Information

The Company will host a conference call on Wednesday, August 4, 2021, to discuss second quarter 2021 financial and operating results, 2021 outlook, and current corporate strategy and initiatives.

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

Date/Time: Wednesday, August 4, 2021, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time)

Webcast: Select “News and Events” under the “Investors” section of the Company’s website: www.callon.com.

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

About Callon Petroleum Company

Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas.

Cautionary Statement Regarding Forward-Looking Information

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of development activity and associated production, capital expenditures and cash flow expectations; the Company’s 2021 production expense guidance and capital expenditure guidance; estimated reserve quantities and the present value thereof; and the implementation of the Company’s business plans and strategy, as well as statements including the words “believe,” “expect,” “plans,” “may,” “will,” “should,” “could,” and words of similar meaning. These statements reflect the Company’s current views with respect to future events and financial performance based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices; changes in the supply of and demand for oil and natural gas, including as a result of the COVID-19 pandemic and various governmental actions taken to mitigate its impact or actions by, or disputes among members of OPEC and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil; our ability to drill and complete wells; operational, regulatory and environment risks; the cost and availability of equipment and labor; our ability to finance our activities; and other risks more fully discussed in our filings with the SEC, including our most recent Annual Reports on Form 10-K and subsequent Quarterly Reports on Form 10-Q, available on our website or the SEC’s website at www.sec.gov.

Contact Information

Mark Brewer

Director of Investor Relations

Callon Petroleum Company

ir@callon.com

(281) 589-5200

1) See “Non-GAAP Financial Measures” included within this release for related disclosures.

2) Pro forma credit facility outstanding balance represents the June 30, 2021 balance of $875.0 million adjusted for the excess proceeds from the issuance of the 8.00% Senior Notes received in July.