HOUSTON, Nov. 3, 2021 /PRNewswire/ -- Callon Petroleum Company (NYSE:CPE) ("Callon" or the "Company") today reported results of operations for the three and nine months ended September 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.

Third Quarter 2021 and Recent Highlights

Delivered production of approximately 99.7 MBoe/d (64% oil) in the third quarter of 2021
Generated net cash provided by operating activities of $294.6 million and adjusted free cash flow¹ of $119.5 million
Net income of $171.9 million, or $3.65 per diluted share, adjusted EBITDA¹ of $292.2 million, and adjusted income¹ of $137.9 million, or $2.93 per diluted share
Achieved an operating margin of $45.16 per Boe, a 20% increase from the previous quarter
Finalized the acquisition of Delaware Basin assets from Primexx, significantly increasing operating cash flow and accelerating the projected timeline for corporate deleveraging
Entered into agreements to divest non-core assets for cash consideration of approximately $170 million, bringing estimated gross asset sales proceeds to approximately $210 million for the year
Completed the fall redetermination for Callon's credit facility with the borrowing base and elected commitment maintained at $1.6 billion
Obtained shareholder approval for the conversion of $197 million of second lien debt into common shares, lowering net debt outstanding and reducing Callon's future interest burden by nearly $20 million annually

Joe Gatto, President and Chief Executive Officer commented, "Our third quarter performance demonstrates Callon's continued commitment to operational excellence, balance sheet strength and delivering on our promises to shareholders. Our development program and financial results reflect both strong well performance and resilient capital efficiency. The team has been able to mitigate the majority of the inflationary pressures we have seen throughout the year which has bolstered our top-tier operating margins. The recent rise in commodity prices has been a welcome surprise and has enhanced our free cash flow generation, increasing our estimates for 2021 to over $250 million. This increase to bottom line cash flow will be dedicated to our deleveraging efforts and provides a clear path for Callon to reach our target debt metrics and absolute debt levels much sooner than originally anticipated, opening the door for meaningful discussions regarding shareholder return strategies in the future."

He continued, "Our acquisition of the Primexx assets, coupled with multiple non-core divestitures, has not only improved our balance sheet, but will also allow us to expand our scaled model of life-of-field development in our core areas that will preserve long-term inventory quality. With an acreage position of over 186,000 net acres, our future development plans will be primarily focused on our Permian asset base, building upon the efficiency of current operations and delivering synergies from deployment of operational best practices. We have made significant progress integrating the acquired assets into our near-term activity and look forward to sharing more details about our 2022 plans for the broader Company in the coming months."

Credit Facility and Liquidity

On November 1, 2021, Callon completed the fall redetermination for its senior secured credit facility. The borrowing base and elected commitment were both reaffirmed at $1.6 billion. As of September 30, 2021, the drawn balance on the facility was $723.0 million and cash balances were $3.7 million. The Company expects to continue applying organic free cash flow and divestiture proceeds towards repayment of the credit facility balance.

Close of Primexx Acquisition, Conversion of Second Lien Notes, and Additional Sale of Non-Core Assets

On October 1, 2021, Callon completed the acquisition of leasehold interests and related infrastructure from Primexx Energy Partners and its affiliates. At closing, Callon paid an adjusted purchase price of $453.7 million in cash and 8.84 million shares of common stock, subject to post-closing adjustments.

On November 3, 2021, shareholders voted to authorize the issuance of approximately 5.5 million shares of common stock to Chambers Investments, LLC, a private investment vehicle managed by Kimmeridge Energy, as part of the conversion of just under $200 million of our second lien notes. This conversion eliminates nearly $20 million of future annual interest payments and is expected to close on November 5, 2021.

The Company recently entered into an agreement to sell certain non-core Midland Basin assets for approximately $38 million. The assets include approximately 1,150 net acres located in central Howard County and a single section in Midland County. Current average daily production for these assets is approximately 900 Boe per day (48% oil).

Additionally, Callon entered into an agreement to divest certain non-core water infrastructure assets for $30 million in upfront cash proceeds and potential earnout payments of up to $18 million. Callon's broader water infrastructure footprint of 14 saltwater disposal wells with approximately 325,000 barrels per day of capacity, associated gathering lines and 140,000 barrels per day of recycling capacity are not impacted by the transaction.

The previously announced divestiture of Eagle Ford properties in northern La Salle and Frio counties for $100 million is expected to close in mid-November.

Scotiabank served as financial advisor to the Company for the water transaction, Wells Fargo Securities LLC for the Eagle Ford sale and TenOaks Energy Advisors, LLC for the Midland divestiture.

Callon Operations Update

At September 30, 2021, Callon had 1,562 gross (1,382.8 net) wells producing from established flow units in the Permian and Eagle Ford. Net daily production for the three months ended September 30, 2021 was 99.7 MBoe/d (64% oil).

For the three months ended September 30, 2021, Callon drilled 15 gross (13.5 net) wells and placed a combined 26 gross (23.6 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.

Third quarter completion activity was focused primarily in the Permian Basin, with approximately 75% of the new wells placed on production coming from larger projects in both the Delaware Basin and Midland Basin. Within the Midland Basin, multi-well projects in Howard County targeted multi-zone development of the Wolfcamp A and Lower Spraberry. In the Delaware Basin, a four-well project targeting Third Bone Spring and Lower Wolfcamp A zones was brought online in September and has exceeded production expectations. As part of the optimization of producing assets, Callon continues to convert gas lift systems to electric submersible pumps, positively impacting the production profile of the existing asset base across the Delaware position.

In the Eagle Ford, Callon turned one two-well pad and a separate four-well project to production in July and August, respectively. All six wells are producing as expected. During the quarter, the Company expanded its electrification efforts in the area, advancing sustainability initiatives and improving productivity. The project has resulted in the removal of another 25 generators, providing a cleaner and more reliable source of energy for field operations. Altogether, these efforts are expected to save approximately $1.5 million annually in lease operating expenses. Additional field electrification efforts are progressing and are expected to be completed by year-end.

Primexx Asset Updates

During the third quarter, Primexx placed 12 gross wells on production with eight wells achieving first production in July and the remaining four wells coming online during late August. These wells have demonstrated a high level of productivity, averaging peak oil rates of more than 1,200 barrels per day. Callon recently placed on production a three-well pad that was drilled and completed by Primexx. Through the first 20 days of production, all three wells are performing ahead of the Callon type curve for the area with peak production yet to be reached. There are no additional wells on the acquired acreage that are expected to be placed on production in the fourth quarter of 2021 as Callon builds an operational well inventory that will facilitate a transition to a larger scale development model going forward.

Fourth Quarter Activity Outlook

Callon is currently running six rigs across the combined acreage position with approximately 1.5 completion crews scheduled for the fourth quarter. Completion activity during the quarter will be spread across the Midland and legacy Delaware positions, moving to the acquired Delaware acreage towards year end. Drilling activity is currently ongoing with four rigs in the Delaware Basin, one rig in the Eagle Ford and one rig in the Midland Basin.

Capital Expenditures

For the three months ended September 30, 2021, Callon incurred $115.0 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 September 30, 2021
	Operational	Capitalized	Capitalized	Total Capital
	Capital ^(a)	Interest	G&A	Expenditures
	(In thousands)
Cash basis ^(b)	$151,086	$16,429	$9,034	$176,549
Timing adjustments ^(c)	(30,160)	7,161	—	($22,999)
Non-cash items	(5,962)	2,500	1,392	($2,070)
Accrual basis	$114,964	$26,090	$10,426	$151,480


(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.

Hedge Portfolio Summary

As of October 29, 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)	2021^(a)		2022^(a)		2023
Swap contracts
Total volume (Bbls)	1,748,000		4,066,000		315,000
Weighted average price per Bbl	$56.87		$65.84		$70.01
Collar contracts
Total volume (Bbls)	2,290,450		7,097,500		—
Weighted average price per Bbl
Ceiling (short call)	$46.97		$67.70		$—
Floor (long put)	$39.37		$56.15		$—
Long put contracts
Total volume (Bbls)	414,000		—		—
Weighted average price per Bbl	$62.50		$—		$—
Short call contracts
Total volume (Bbls)	1,216,240	^(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) ^(d)
Collar contracts
Total volume (Bbls)	184,000		—		—
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)	892,400		—		—
Weighted average price per Bbl	$0.33		$—		$—

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 $6.6 million of deferred premiums, of which $3.7 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 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)	2021		2022
Swap contracts
Total volume (MMBtu)	4,357,000		7,320,000
Weighted average price per MMBtu	$2.96		$3.08
Collar contracts
Total volume (MMBtu)	1,840,000		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)	1,840,000	^(a)	—
Weighted average price per MMBtu	$3.09		$—

Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	4,140,000		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)	2021	2022
Swap contracts
Total volume (Bbls)	460,000	378,000
Weighted average price per Bbl	$7.62	$15.70

NGL contracts (OPIS Mont Belvieu Propane)
Swap contracts
Total volume (Bbls)	266,800	252,000
Weighted average price per Bbl	$52.15	$48.43

NGL contracts (OPIS Mont Belvieu Butane)
Swap contracts
Total volume (Bbls)	101,200	99,000
Weighted average price per Bbl	$59.43	$54.39

NGL contracts (OPIS Mont Belvieu Isobutane)
Swap contracts
Total volume (Bbls)	55,200	54,000
Weighted average price per Bbl	$58.96	$54.29

Operating and Financial Results

The following table presents summary information for the periods indicated:

	Three Months Ended
	September 30, 2021	June 30, 2021	September 30, 2020
Total production
Oil (MBbls)
Permian	3,428	3,232	3,441
Eagle Ford	2,447	1,870	2,434
Total oil (MBbls)	5,875	5,102	5,875

Natural gas (MMcf)
Permian	7,153	7,138	7,868
Eagle Ford	2,242	1,745	2,393
Total natural gas (MMcf)	9,395	8,883	10,261

NGLs (MBbls)
Permian	1,315	1,216	1,423
Eagle Ford	417	299	379
Total NGLs (MBbls)	1,732	1,515	1,802

Total production (MBoe)
Permian	5,936	5,637	6,175
Eagle Ford	3,237	2,460	3,212
Total barrels of oil equivalent (MBoe)	9,173	8,097	9,387

Total daily production (Boe/d)
Permian	64,517	61,948	67,117
Eagle Ford	35,186	27,033	34,912
Total barrels of oil equivalent (Boe/d)	99,703	88,981	102,029
Oil as % of total daily production	64%	63%	63%

Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)
Permian	$69.60	$65.08	$39.42
Eagle Ford	69.76	65.83	39.44
Total oil (per Bbl)	$69.67	$65.36	$39.43

Natural gas (per Mcf)
Permian	$3.78	$2.68	$1.31
Eagle Ford	4.22	2.82	1.99
Total natural gas (per Mcf)	$3.89	$2.71	$1.47

NGLs (per Bbl)
Permian	$34.41	$24.71	$12.68
Eagle Ford	30.81	22.00	13.13
Total NGLs (per Bbl)	$33.54	$24.17	$12.78

Average realized sales price (per Boe)
Permian	$52.37	$46.04	$26.55
Eagle Ford	59.63	54.72	32.92
Total average realized sales price (per Boe)	$54.93	$48.68	$28.73

Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)	$54.00	$46.82	$39.00
Natural gas (per Mcf)	2.21	2.25	1.17
NGLs (per Bbl)	31.71	23.21	12.78
Total average realized sales price (per Boe)	$42.84	$36.31	$28.14

	Three Months Ended
	September 30, 2021	June 30, 2021	September 30, 2020
Revenues (in thousands)^(a)
Oil
Permian	$238,582	$210,340	$135,648
Eagle Ford	170,711	123,102	96,006
Total oil	$409,293	$333,442	$231,654

Natural gas
Permian	$27,065	$19,152	$10,271
Eagle Ford	9,454	4,928	4,763
Total natural gas	$36,519	$24,080	$15,034

NGLs
Permian	$45,249	$30,047	$18,049
Eagle Ford	12,848	6,578	4,976
Total NGLs	$58,097	$36,625	$23,025

Total revenues
Permian	$310,896	$259,539	$163,968
Eagle Ford	193,013	134,608	105,745
Total revenues	$503,909	$394,147	$269,713

Additional per Boe data
Sales price ^(b)
Permian	$52.37	$46.04	$26.55
Eagle Ford	59.63	54.72	32.92
Total sales price	$54.93	$48.68	$28.73

Lease operating
Permian	$4.19	$4.60	$4.38
Eagle Ford	5.51	8.34	5.86
Total lease operating	$4.66	$5.74	$4.89

Production and ad valorem taxes
Permian	$2.80	$2.53	$1.57
Eagle Ford	2.89	3.12	2.00
Total production and ad valorem taxes	$2.84	$2.71	$1.72

Gathering, transportation and processing
Permian	$2.70	$2.75	$2.55
Eagle Ford	1.49	1.84	2.00
Total gathering, transportation and processing	$2.28	$2.47	$2.36

Operating margin
Permian	$42.68	$36.16	$18.05
Eagle Ford	49.74	41.42	23.06
Total operating margin	$45.16	$37.76	$19.76

Depreciation, depletion and amortization	$9.80	$10.27	$12.17
General and administrative	$1.04	$1.37	$0.88
Adjusted G&A ¹
Cash component ^(c)	$1.13	$0.71	$0.87
Non-cash component	$0.17	$0.21	$0.18


(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 September 30, 2021, Callon reported revenue of $503.9 million, which excluded revenue from sales of commodities purchased from a third party of $48.7 million. Revenues including the gain or loss from the settlement of derivative contracts ("Adjusted Total Revenue"¹) were $392.9 million, reflecting the impact of a $111.0 million loss from the settlement of derivative contracts. Average daily production for the quarter was 99.7 MBoe/d, compared to average daily production of 89.0 MBoe/d in the second quarter of 2021. Average realized prices, including and excluding the effects of hedging, are detailed above.

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

	Three Months Ended September 30, 2021
Loss on oil derivatives	$67,198
Loss on natural gas derivatives	33,026
Loss on NGL derivatives	10,242
Loss on commodity derivative contracts	$110,466

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

	Three Months Ended September 30, 2021
Cash paid on oil derivatives	($98,752)
Cash paid on natural gas derivatives	(9,592)
Cash paid on NGL derivatives	(2,463)
Cash paid for commodity derivative settlements, net	($110,807)

Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended September 30, 2021 was $4.66 per Boe, compared to LOE of $5.74 per Boe in the second quarter of 2021. The decrease in LOE per Boe was primarily due to the distribution of fixed costs spread over higher production volumes as well as a reduction in certain operating expenses such as saltwater disposal and compression.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended September 30, 2021 represented approximately 5.2% 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 September 30, 2021 was $20.9 million, or $2.28 per Boe, as compared to $20.0 million, or $2.47 per Boe in the second quarter of 2021. This increase is related to the 13% increase in production volumes between the two periods.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended September 30, 2021 was $9.80 per Boe compared to $10.27 per Boe in the second quarter of 2021. The decrease in DD&A per Boe was primarily attributable to a larger percentage increase in production as compared to the depletion rate of our proved reserves from the second quarter of 2021 to the third quarter of 2021.

General and Administrative Expense ("G&A"). G&A for the three months ended September 30, 2021 and June 30, 2021 was $9.5 million, or $1.04 per Boe, and $11.1 million, or $1.37 per Boe, respectively. G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A"¹) was $12.0 million, or $1.31 per Boe, for the three months ended September 30, 2021 compared to $7.5 million, or $0.93 per Boe, for the second quarter of 2021. The cash component of Adjusted G&A increased to $10.4 million, or $1.13 per Boe, for the three months ended September 30, 2021 compared to $5.8 million, or $0.71 per Boe, for the second quarter of 2021 primarily as a result of higher 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
	September 30, 2021	June 30, 2021	September 30, 2020
Total G&A	$9,503	$11,065	$8,224
Change in the fair value of liability share-based awards (non-cash)	2,492	(3,555)	1,582
Adjusted G&A – total	11,995	7,510	9,806
Equity-settled, share-based compensation (non-cash) and other non-recurring expenses	(1,589)	(1,724)	(1,674)
Adjusted G&A – cash component	$10,406	$5,786	$8,132

Capitalized cash G&A	9,034	7,404	6,831
Full cash G&A	$19,440	$13,190	$14,963

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 expense of $2.4 million compared to income tax benefit of $0.5 million for the three months ended September 30, 2021 and June 30, 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 income was $171.9 million and adjusted EBITDA was $292.2 million for the third quarter of 2021 as compared to net loss of $11.7 million and adjusted EBITDA of $196.8 million for the second quarter of 2021. The increase in adjusted EBITDA from the second quarter of 2021 was primarily due to an increase in revenues.

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

	Three Months Ended
	September 30, 2021	June 30, 2021	September 30, 2020
	(In thousands, except per share data)
Net income (loss)	$171,902	($11,695)	($680,384)
Loss on derivative contracts	107,169	190,463	27,038
Loss on commodity derivative settlements, net	(110,960)	(100,128)	(5,540)
Non-cash expense (benefit) related to share-based awards	(903)	5,279	(94)
Impairment of evaluated oil and gas properties	—	—	684,956
Merger, integration and transaction	3,018	—	2,465
Other (income) expense	4,305	5,584	3,567
Gain on extinguishment of debt	(2,420)	—	—
Tax effect on adjustments above^(a)	(44)	(21,252)	(149,602)
Change in valuation allowance	(34,190)	2,079	143,152
Adjusted income	$137,877	$70,330	$25,558
Adjusted income per diluted share	$2.93	$1.49	$0.64

Basic WASO	46,290	46,267	39,746
Diluted WASO (GAAP)	47,096	46,267	39,746
Effect of potentially dilutive instruments	—	862	35
Adjusted Diluted WASO	47,096	47,129	39,781

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


	Three Months Ended
	September 30, 2021	June 30, 2021	September 30, 2020
	(In thousands)
Net income (loss)	$171,902	($11,695)	($680,384)
Loss on derivative contracts	107,169	190,463	27,038
Loss on commodity derivative settlements, net	(110,960)	(100,128)	(5,540)
Non-cash expense (benefit) related to share-based awards	(903)	5,279	(94)
Impairment of evaluated oil and gas properties	—	—	684,956
Merger, integration and transaction	3,018	—	2,465
Other (income) expense	4,305	5,584	3,567
Income tax (benefit) expense	2,416	(478)	—
Interest expense, net	27,736	24,634	24,683
Depreciation, depletion and amortization	89,890	83,128	114,201
Gain on extinguishment of debt	(2,420)	—	—
Adjusted EBITDA	$292,153	$196,787	$170,892

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
	September 30, 2021	June 30, 2021	September 30, 2020
	(In thousands)
Net cash provided by operating activities	$294,565	$175,603	$135,701
Changes in working capital and other	(30,355)	13,520	14,473
Change in accrued hedge settlements	(153)	(14,719)	(5,993)
Cash interest expense, net	25,078	22,383	24,246
Merger, integration and transaction	3,018	—	2,465
Adjusted EBITDA	292,153	196,787	170,892
Less: Operational capital expenditures (accrual)	114,964	138,321	38,408
Less: Capitalized interest	23,590	21,740	20,675
Less: Interest expense, net of capitalized amounts	25,078	22,383	24,683
Less: Capitalized cash G&A	9,034	7,404	6,831
Adjusted free cash flow ^(a)	$119,487	$6,939	$80,295


(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
	September 30, 2021	June 30, 2021	September 30, 2020
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$171,902	($11,695)	($680,384)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	89,890	83,128	114,201
Impairment of evaluated oil and gas properties	—	—	684,956
Amortization of non-cash debt related items, net	2,658	2,252	437
Deferred income tax expense	—	—	—
Loss on derivative contracts	107,169	190,463	27,038
Cash received (paid) for commodity derivative settlements, net	(110,807)	(85,409)	453
Gain on extinguishment of debt	(2,420)	—	—
Non-cash expense (benefit) related to share-based awards	(903)	5,279	(94)
Merger, integration and transaction	3,018	—	2,465
Other, net	6,495	3,294	2,099
Adjusted discretionary cash flow	$267,002	$187,312	$151,171
Changes in working capital	30,581	(11,709)	(13,005)
Merger, integration and transaction	(3,018)	—	(2,465)
Net cash provided by operating activities	$294,565	$175,603	$135,701

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
	September 30, 2021	June 30, 2021	September 30, 2020
	(In thousands)
Operating revenues
Oil	$409,293	$333,442	$231,654
Natural gas	36,519	24,080	15,034
NGLs	58,097	36,625	23,025
Total operating revenues	$503,909	$394,147	$269,713
Impact of settled derivatives	(110,960)	(100,128)	(5,540)
Adjusted total revenue	$392,949	$294,019	$264,173

Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except par and share amounts)
(Unaudited)

	September 30, 2021	December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$3,699	$20,236
Accounts receivable, net	216,116	133,109
Fair value of derivatives	18,605	921
Other current assets	30,110	24,103
Total current assets	268,530	178,369
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net	2,565,601	2,355,710
Unevaluated properties	1,712,428	1,733,250
Total oil and natural gas properties, net	4,278,029	4,088,960
Other property and equipment, net	30,591	31,640
Deferred financing costs	19,274	23,643
Other assets, net	89,992	40,256
Total assets	$4,686,416	$4,362,868
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$442,053	$341,519
Fair value of derivatives	324,682	97,060
Other current liabilities	61,641	58,529
Total current liabilities	828,376	497,108
Long-term debt	2,809,610	2,969,264
Asset retirement obligations	58,703	57,209
Fair value of derivatives	15,250	88,046
Other long-term liabilities	41,448	40,239
Total liabilities	3,753,387	3,651,866
Commitments and contingencies
Stockholders' equity:
Common stock, $0.01 par value, 78,750,000 and 52,500,000 shares authorized; 46,290,611 and 39,758,817 shares outstanding, respectively	463	398
Capital in excess of par value	3,365,121	3,222,959
Accumulated deficit	(2,432,555)	(2,512,355)
Total stockholders' equity	933,029	711,002
Total liabilities and stockholders' equity	$4,686,416	$4,362,868

Callon Petroleum Company
Consolidated Statements of Operations
(In thousands, except per share data)
(Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
Operating Revenues:
Oil	$409,293	$231,654	$1,009,780	$627,934
Natural gas	36,519	15,034	84,819	33,305
Natural gas liquids	58,097	23,025	124,079	55,627
Sales of purchased oil and gas	48,653	20,313	134,164	21,469
Total operating revenues	552,562	290,026	1,352,842	738,335

Operating Expenses:
Lease operating	42,706	45,870	129,619	149,091
Production and ad valorem taxes	26,070	16,110	66,467	46,151
Gathering, transportation and processing	20,875	22,200	58,887	56,615
Cost of purchased oil and gas	49,392	21,282	139,558	22,450
Depreciation, depletion and amortization	89,890	114,201	244,005	384,594
General and administrative	9,503	8,224	37,367	26,573
Impairment of evaluated oil and gas properties	—	684,956	—	1,961,474
Merger, integration and transaction	3,018	2,465	3,018	26,362
Other operating	—	4,425	3,366	8,548
Total operating expenses	241,454	919,733	682,287	2,681,858
Income (Loss) From Operations	311,108	(629,707)	670,555	(1,943,523)

Other (Income) Expenses:
Interest expense, net of capitalized amounts	27,736	24,683	76,786	67,843
(Gain) loss on derivative contracts	107,169	27,038	512,155	(97,966)
Gain on extinguishment of debt	(2,420)	—	(2,420)	—
Other (income) expense	4,305	(1,044)	3,217	(149)
Total other (income) expense	136,790	50,677	589,738	(30,272)

Income (Loss) Before Income Taxes	174,318	(680,384)	80,817	(1,913,251)
Income tax expense	(2,416)	—	(1,017)	(115,299)
Net Income (Loss)	$171,902	($680,384)	$79,800	($2,028,550)

Net Income (Loss) Per Common Share:
Basic	$3.71	($17.12)	$1.77	($51.09)
Diluted	$3.65	($17.12)	$1.69	($51.09)

Weighted Average Common Shares Outstanding:
Basic	46,290	39,746	45,063	39,707
Diluted	47,096	39,746	47,119	39,707

Callon Petroleum Company
Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
Cash flows from operating activities:
Net income (loss)	$171,902	($680,384)	$79,800	($2,028,550)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	89,890	114,201	244,005	384,594
Impairment of evaluated oil and gas properties	—	684,956	—	1,961,474
Amortization of non-cash debt related items, net	2,658	437	7,166	1,582
Deferred income tax expense	—	—	—	115,299
(Gain) loss on derivative contracts	107,169	27,038	512,155	(97,966)
Cash received (paid) for commodity derivative settlements, net	(110,807)	453	(238,378)	101,754
Gain on extinguishment of debt	(2,420)	—	(2,420)	—
Non-cash expense (benefit) related to share-based awards	(903)	(94)	11,984	(305)
Other, net	6,495	2,084	11,006	5,740
Changes in current assets and liabilities:
Accounts receivable	(15,870)	(16,930)	(83,227)	96,110
Other current assets	(1,278)	(2,208)	(8,701)	(6,556)
Accounts payable and accrued liabilities	47,729	6,148	74,443	(107,979)
Net cash provided by operating activities	294,565	135,701	607,833	425,197
Cash flows from investing activities:
Capital expenditures	(176,549)	(136,534)	(427,552)	(555,222)
Acquisition of oil and gas properties	(4,904)	(643)	(7,119)	(12,524)
Deposit for acquisition of oil and gas properties	(60,117)	—	(60,117)	—
Proceeds from sale of assets	3,804	139,739	35,415	149,818
Cash paid for settlements of contingent consideration arrangements, net	—	—	—	(40,000)
Other, net	(14)	1,427	4,206	8,261
Net cash provided by (used in) investing activities	(237,780)	3,989	(455,167)	(449,667)
Cash flows from financing activities:
Borrowings on Credit Facility	500,000	312,000	1,236,500	5,087,500
Payments on Credit Facility	(652,000)	(737,000)	(1,498,500)	(5,347,500)
Redemption of 6.25% Senior Notes	(542,755)	—	(542,755)	—
Issuance of 8.00% Senior Notes due 2028	650,000	—	650,000	—
Issuance of 9.00% Second Lien Senior Secured Notes due 2025	—	300,000	—	300,000
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025	—	(35,270)	—	(35,270)
Issuance of September 2020 Warrants	—	23,909	—	23,909
Payment of deferred financing costs	(12,131)	(301)	(12,168)	(6,312)
Tax withholdings related to restricted stock units	—	(107)	(2,280)	(495)
Other, net	—	79	—	(203)
Net cash provided by (used in) financing activities	(56,886)	(136,690)	(169,203)	21,629
Net change in cash and cash equivalents	(101)	3,000	(16,537)	(2,841)
Balance, beginning of period	3,800	7,500	20,236	13,341
Balance, end of period	$3,699	$10,500	$3,699	$10,500

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, integration and transaction 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, integration and transaction 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 Thursday, November 4, 2021, to discuss third 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:	Thursday, November 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 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 development activities at expected costs or at expected times or at all; our inability to realize the benefits of recent transactions; currently unknown risks and liabilities relating to the newly acquired assets and operations; adverse actions by third parties involved with the transactions; risks that are not yet known or material to us; 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. 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.

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.

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SOURCE Callon Petroleum Company