Document

Exhibit 99.1

Callon Petroleum Company Announces Third Quarter 2020 Results

Updates 2020 Operating Plan and Outlook

Enters Into Private Debt Exchange Agreement

HOUSTON, TX (November 2, 2020) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three and nine months ended September 30, 2020.

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

Recent Highlights

•Delivered production of approximately 102.0 Mboe/d (63% oil), above expectations, for the third quarter of 2020

•Posted accrued operational capital spending of $38.4 million, below consensus estimates, and lowered the top end of operational capital range to $510 million, a 15% reduction since announcing the modified development program in May 2020

•Generated net cash from operating activities of $135.7 million and free cash flow1 of $80.3 million for the third quarter

•Loss available to common stockholders of $680.4 million, or $17.12 per fully diluted share, driven by an impairment of evaluated oil and gas properties of $685.0 million, adjusted EBITDA1 of $170.9 million, and adjusted income per share1 of $0.64 for the third quarter of 2020

•Achieved lease operating expense (“LOE”) of $45.9 million or $4.89 per Boe for the third quarter of 2020, an improvement of approximately 10%, on an absolute basis, over the comparable three-month period ended June 30, 2020

•Resumed completion and drilling activity with recent well costs for Eagle Ford and Delaware third quarter completions at $460 and $825 per lateral foot, respectively, exceeding previous targets as a result of continued operational efficiency gains

•Increased liquidity to nearly $600 million and reduced total net debt by approximately $160 million after transaction expenses through a series of strategic transactions including the issuance of $300 million of secured second lien notes, an overriding royalty interest (“ORRI”) transaction, and a non-operated working interest sale

•Completed the fall borrowing base redetermination with a reaffirmed borrowing base of $1.7 billion which was subsequently reduced to $1.6 billion, reflecting a minimal reduction to account for the recent ORRI sale and second lien note issuance

•Entered into a privately negotiated debt exchange of $286 million of unsecured senior notes for new second lien notes, reducing net debt by an estimated $128 million, with an option for the counterparties and their affiliates to exchange additional unsecured Senior Notes up to approximately $104 million

Joe Gatto, President and Chief Executive Officer commented, “During the third quarter, our operations team continued to execute on our cost reduction efforts, posting meaningful gains that bolstered our free cash flow generation to approximately $100 million over the last two quarters. These achievements coupled with our recent strategic initiatives to improve liquidity and propel our debt reduction efforts have placed us in a much better position as we look to close out 2020 with the resumption of moderated development across all three of our asset areas.”

He continued, “Well performance from our modified stacking and spacing program has met or exceeded expectations, confirming the merits of our life-of-field development model that will preserve the future value of our inventory while simultaneously delivering near-term economic returns at current strip prices. Moreover, our focus on cost control and operational efficiency through scaled development is pushing us towards even lower cost thresholds that should generate improved cash flow and lower break-even pricing over time.”

Mr. Gatto closed by sharing, “Alongside these operational and strategic achievements, we have continued to focus on operating safely, with a clear vision for reducing our environmental impact, maintaining our social awareness and treatment of our workforce, and strengthening our alignment with the needs of our shareholders. The recent issuance of our inaugural Sustainability report provides a clear and well-documented picture of where we stand and the path to continuously improving in each of these three critical areas. As we finalize the details of our 2021 budget and activity levels, our focus will be on our debt reduction efforts, maintaining a low cost development and operations structure, and creating durable and cogent changes that not only enhance shareholder returns but also positively impact our employees, communities, and our broader stakeholder group.”

Private Debt Exchange

Callon also announced another meaningful step today in the execution of its deleveraging plan. On November 2nd, the Company entered into a privately negotiated agreement with certain holders of its outstanding unsecured debt securities to exchange $286 million of principal of the Company’s existing unsecured senior notes (the “Senior Notes”) for $158 million aggregate principal of new 9.00% Second Lien Notes due 2025, payable semi-annually (the “Second Lien Notes”), to be issued by Callon at a weighted average exchange ratio of approximately $555 per $1,000 of principal exchanged. Over 60% of the existing Senior Notes to be exchanged are due 2023 and 2024. Upon completion of the exchange, Callon’s total net debt will be reduced by approximately $128 million and total cash interest expense by approximately $5 million.

In addition, certain other affiliated parties have the option to exchange up to an additional approximately $104 million of principal of Senior Notes under the same exchange terms. At full participation, the estimated total debt reduction and total cash interest expense reduction would be approximately $175 million and $7 million, respectively.

Participants in the exchange will also receive between 1.16 and 1.76 million warrants, dependent on final participation levels, with a strike price of $5.60 which is consistent with the strike price for the warrants issued recently in relation to the Company’s initial issuance of Second Lien Notes that was announced on October 1st.

The private debt exchange is scheduled to close on November 17th. Callon currently expects the borrowing base under its credit facility to remain unchanged at $1.6 billion, and its next scheduled redetermination will take place in May 2021.

Operations Update

At September 30, 2020, Callon had 1,479 gross (1,305.9 net) horizontal wells producing from established flow units in the Permian Basin and Eagle Ford Shale. Net daily production for the three months ended September 30, 2020 grew 170% to 102.0 Mboe/d (63% oil), as compared to the same period of 2019.

For the three months ended September 30, 2020, Callon drilled zero horizontal wells and placed a combined 12 gross (11.4 net) horizontal wells on production, all of which were turned to production late in the quarter. The Company reactivated two completion crews, one each in the Eagle Ford and Delaware Basin, both of which completed previously drilled multi-well projects during September. Subsequently, one of the two completion crews has been released and three drilling rigs have resumed operations, two restarting operations in the Midland and Delaware Basin during September and the third reactivated in the Eagle Ford during October. The Company expects to operate three drilling rigs and a single completion crew during the fourth quarter.

Recent project costs and well performance reflect a continuation of the operational efficiency levels achieved during the second quarter of 2020 and support the enhanced stacking and spacing efforts. Some of the highlights include:

•The Eagle Ford wells placed on production late in the third quarter averaged over 2,000 feet of completed lateral per day

•The combined six wells came in just below $475 per lateral foot with an average completed lateral length of approximately 7,500 feet

•In the Delaware, the six-well Amphitheater pad was placed on production during the final days of the third quarter and first week of the fourth quarter, with the project averaging a completion pace of just under nine stages per day or nearly 1,800 lateral feet per day

•The Amphitheater project averaged approximately 9,400 feet per well with an average well cost of less than $8 million ($825 per lateral foot)

•Initial production from the six-well Amphitheater pad recently reached a per well average of over 1,200 Boe per day (gross, ~84% oil) with total cumulative production of more than 140,000 Boe (gross, ~84% oil) in just over three weeks of production

•Over 95% of the volumes sourced for the Amphitheater completions utilized recycled produced water volumes sourced from Callon’s own recycling facilities

Capital Expenditures

For the three months ended September 30, 2020, Callon incurred $38.4 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, 2020
	Operational	Capitalized	Capitalized	Total Capital
	Capital (a)	Interest	G&A	Expenditures
	(In thousands)
Cash basis (b)	$110,689	$17,769	$8,719	$137,177
Timing adjustments (c)	(66,596)	2,906	—	(63,690)
Non-cash items	(5,685)	—	1,532	(4,153)
Accrual basis	$38,408	$20,675	$10,251	$69,334

(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. As Callon has resumed a moderated pace of development activity, management expects for a more normalized relationship between accrual and cash-based capex figures in future periods.

Hedging

For the three months ended September 30, 2020, Callon recognized a loss from the settlement of derivative contracts of $5.5 million. Callon has continued to actively manage its hedge portfolio adding nearly 5.7 million barrels or 15,500 barrels per day of WTI NYMEX coverage for 2021. This raises the percentage of NYMEX coverage via collars to nearly 90% and raises the average ceiling price to over $46 per barrel, providing incremental upside while maintaining the price floor within one dollar of the previous weighted average position. In addition, the Company has improved its Brent-based hedges, raising the average floor from approximately $38 per barrel to almost $41 per barrel and increasing coverage by just over 300,000 barrels per year. Additional coverage for natural gas pricing was achieved through the addition of more than 10,000,000 MMBtu of Waha basis swaps, improving the weighted average differential by $0.16 per MMBtu.

Accounting for the Company’s recent adjustments, total hedge coverage for 2021 is now more than 60% of anticipated oil production and just under 60% of anticipated natural gas production. Details regarding the Company's full hedge positions can be found in the hedge summary within the earnings release or within the appendix of the third quarter 2020 earnings slide deck on the website.

Operating and Financial Results

The following table presents summary information for the periods indicated:


	Three Months Ended
	September 30, 2020		June 30, 2020
Net production
Oil (MBbls)	5,875		6,396
Natural gas (MMcf)	10,261		11,009
NGLs (MBbls)	1,802		1,657
Total barrels of oil equivalent (MBoe)	9,387		9,888
Total daily production (Boe/d)	102,029		108,664
Oil as % of total daily production	63	%	65	%
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)	$39.43		$20.41
Natural gas (per Mcf)	1.47		1.11
NGLs (per Bbl)	12.78		8.74
Total (per Boe)	28.73		15.90
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)	$39.00		$33.82
Natural gas (per Mcf)	1.17		0.97
NGLs (per Bbl)	12.78		8.74
Total (per Boe)	28.14		24.42
Revenues (in thousands)
Oil	$231,654		$130,513
Natural gas	15,034		12,242
NGLs	23,025		14,479
Total	$269,713		$157,234
Additional per Boe data
Sales price (a)	$28.73		$15.90
Lease operating expense	4.89		5.14
Production taxes	1.72		1.05
Gathering, transportation and processing	2.36		2.03
Operating margin	$19.76		$7.68

Depletion, depreciation and amortization	$12.17		$14.05
General and administrative (G&A)	$0.88		$1.01
Adjusted G&A 1
Cash component (b)	$0.87		$0.69
Non-cash component	$0.18		$0.15

(a)Excludes the impact of settled derivatives.

(b)Excludes the amortization of equity-settled, share-based incentive awards.

Revenue. For the quarter ended September 30, 2020, Callon reported revenue of $269.7 million, which excluded revenue from the sales of commodities purchased from a third-party of $20.3 million. Revenues including the gain or loss from the settlement of derivative contracts (“Adjusted Total Revenue”1) were $264.2 million, reflecting the impact of a $5.5 million loss from the settlement of derivative contracts. Average daily production for the quarter was 102.0 Mboe/d, compared to average daily production of 108.7 Mboe/d in the second quarter of 2020. Average realized prices, including and excluding the effects of hedging, are detailed above.

Hedging impacts. For the quarter ended September 30, 2020, the net (gain) loss on commodity derivative contracts includes the following (in thousands):


			Three Months Ended September 30, 2020
(Gain) loss on oil derivatives			$16,606
(Gain) loss on natural gas derivatives			7,296
(Gain) loss on NGL derivatives			2,421
(Gain) loss on commodity derivative contracts			$26,323

For the quarter ended September 30, 2020, the cash (paid) received for commodity derivative settlements includes the following (in thousands):


			Three Months Ended September 30, 2020
Cash (paid) received on oil derivatives			$2,130
Cash (paid) received on natural gas derivatives			(1,677)
Cash received for commodity derivative settlements			$453

Lease Operating Expenses, including workover (“LOE”). LOE per Boe for the three months ended September 30, 2020 was $4.89 per Boe, compared to LOE of $5.14 per Boe in the second quarter of 2020. The decrease in LOE per Boe was driven by improved field practices and a reduction in base operating costs in the third quarter of 2020 as compared to the second quarter of 2020.

Production Taxes, including ad valorem taxes. Production taxes were $1.72 per Boe for the three months ended September 30, 2020, representing approximately 6.0% of revenue before the impact of derivative settlements.

Gathering, Transportation and Processing Expenses. Gathering, transportation and processing costs for the three months ended September 30, 2020 were $22.2 million as compared to $20.0 million in the second quarter of 2020. In 2020, the Company began reporting gathering, transportation and processing costs separately due to the assumption of processing agreements in the Carrizo acquisition and certain contract modifications effective January 1, 2020. As such, the Company now records contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, as gathering, transportation and processing expense. These fees were historically recorded as a reduction of revenue depending on when control transferred to the purchaser.

Depreciation, Depletion and Amortization (“DD&A”). DD&A for the three months ended September 30, 2020 was $12.17 per Boe compared to $14.05 per Boe in the second quarter of 2020. The decrease in DD&A is primarily driven by the impairment of evaluated oil and gas properties recognized in the second quarter of 2020.

Impairment of Evaluated Oil and Gas Properties. Callon recognized an impairment of evaluated oil and gas properties of $685.0 million for the three months ended September 30, 2020 due primarily to the continued decline in the average realized prices for sales of oil and gas. The decrease in the trailing 12-month average realized price as of September 30, 2020 resulted in a reduction of proved oil and gas reserve volumes of less than 2% of our December 31, 2019 proved oil and gas reserves volumes. For the three months ended June 30, 2020, the Company recognized an impairment of evaluated oil and gas properties of $1.3 billion.

G&A. G&A for the three months ended September 30, 2020 was $8.2 million, or $0.88 per Boe, and G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, (“Adjusted G&A” 1) was $9.8 million, or $1.04 per Boe, for the three months ended September 30, 2020 compared to $8.3 million, or $0.84 per Boe, for the second quarter of 2020. The cash component of Adjusted G&A was $8.1 million, or $0.87 per Boe, for the three months ended September 30, 2020 compared to $6.8 million, or $0.69 per Boe, for the second quarter of 2020. Adjusted G&A was slightly higher in the third quarter of 2020 as compared to the second quarter of 2020 due to slightly higher contractor and employee relocation expenses.

For the three months ended September 30, 2020 and June 30, 2020, G&A and Adjusted G&A, which excludes the amortization of equity-settled and share-based incentive awards, are calculated as follows (in thousands):


	Three Months Ended
	September 30, 2020	June 30, 2020
Total G&A expense	$8,224	$10,024
Change in the fair value of liability share-based awards (non-cash)	1,582	(1,720)
Adjusted G&A – total	9,806	8,304
Restricted stock share-based compensation (non-cash) and other non-recurring expenses	(1,674)	(1,509)
Adjusted G&A – cash component	$8,132	$6,795

Capitalized cash G&A	$6,831	$6,740
Full Cash G&A Costs	$14,963	$13,535

Income Tax Expense. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. As a result of the valuation allowance that Callon recorded against its net deferred tax assets, we did not have any income tax expense for the three months ended September 30, 2020, compared to income tax expense of $51.3 million for the three months ended June 30, 2020.

Loss Available to Common Stockholders. We recorded a loss available to common stockholders for the three months ended September 30, 2020 of $680.4 million, or $17.12 per diluted share, as compared to a loss available to common stockholders of $1.6 billion, or $39.41 per diluted share, for the second quarter of 2020, retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. The loss was primarily due to the impairment of evaluated oil and gas properties of $685.0 million for the three months ended September 30, 2020.

Adjusted EBITDA. Adjusted EBITDA for the third quarter of 2020 was $170.9 million as compared to $153.4 million for the second quarter of 2020. The increase in Adjusted EBITDA from the second quarter of 2020 was primarily due to an approximate 93% increase in the average realized price of oil. This was partially offset by decreased sequential production.

Guidance

Callon is updating guidance for the full year and updating previous ranges to reflect adjustments related to strong well performance, improved operational efficiency, expanded firm transportation agreements, and the effect of both the non-operated properties sale and the ORRI transaction.


						Full Year
						2020 Guidance
Total production (Mboe/d)						100.0 - 101.0
Oil production						63%
Gas production						19%
NGL production						18%
Income statement expenses ($MM)
LOE, including workovers						$200 - $205
Gathering, processing, and transportation						$73 - $78
Production taxes, including ad valorem (% unhedged revenue)						7%
Adjusted G&A: cash component (a)						$30 - $35
Adjusted G&A: non-cash component (b)						$3 - $5
Cash interest expense						$90 - $95
Effective income tax rate (%)						22%
Capital expenditures ($MM, accrual basis)
Total operational capital (c)						$500 - $510
Capitalized interest						$85 - $90
Capitalized G&A						$30 - $33
Gross operated wells drilled / completed						87 - 89 / 80 - 82

(a)Excludes the amortization of equity-settled, share-based incentive awards.

(b)Excludes certain non-recurring expenses and non-cash valuation adjustments.

(c)Includes facilities, equipment, seismic, land and other items. Excludes capitalized expense.

In August, the Company provided an initial outlook for 2021 which included a “maintenance capital” plan targeting average daily production of 90 to 95 MBoe per day from an operational capital spending level of approximately $400 million. For 2021, the

Company is now expected to achieve average daily production of 90 to 92 MBoe per day, with the reduction resulting from the combined effect of the recent ORRI transaction and non-operated properties sale, offset partly by improved well performance and operational efficiency gains. These improvements are reflected in management’s updated expectations of operational capital spending for 2021 which is now estimated to be in the range of $375 to $400 million. As a result, management estimates that this program at current prices will yield meaningful additional free cash flow.

Third Quarter 2020 Earnings Conference Call

The Company’s conference call to discuss third quarter results is scheduled for Tuesday, November 3, 2020, at 9:00 am CST. The presentation slides and associated webcast can both be found at www.callon.com located on the “News/Events” page within the Investors section on the site or by clicking on the link below.

www.callon.com/investors/news-events/ir-calendar

Hedge Portfolio Summary

The following tables summarize Callon’s open derivative contracts for the remainder of 2020 and the full year 2021, updated for changes through October 29, 2020:


	For the Remainder		For the Full Year
Oil contracts (WTI)	of 2020		of 2021
Swap contracts
Total volume (Bbls)	2,496,880		1,377,000
Weighted average price per Bbl	$42.10		$42.00
Collar contracts
Total volume (Bbls)	1,501,440		9,423,275
Weighted average price per Bbl
Ceiling (short call)	$45.00		$46.78
Floor (long put)	$35.00		$39.21
Short put contracts
Total volume (Bbls)	552,000		—
Weighted average price per Bbl	$42.50		$—
Long call contracts
Total volume (Bbls)	460,000		—
Weighted average price per Bbl	$67.50		$—
Short call contracts
Total volume (Bbls)	460,000	(2)	4,825,300	(2)
Weighted average price per Bbl	$55.00		$63.62

Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls)	—		848,300
Weighted average price per Bbl	$—		$37.36
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)	1,380,000		3,022,900
Weighted average price per Bbl	($1.89)		$0.26

Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	1,435,202		—
Weighted average price per Bbl	$0.03		$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	—		1,060,375
Weighted average price per Bbl	$—		$38.94

(2) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps.


	For the Remainder	For the Full Year
Natural gas contracts (Henry Hub)	of 2020	of 2021
Swap contracts
Total volume (MMBtu)	1,633,000	11,123,000
Weighted average price per MMBtu	$2.05	$2.60
Collar contracts (three-way collars)
Total volume (MMBtu)	1,525,000	1,350,000
Weighted average price per MMBtu
Ceiling (short call)	$2.72	$2.70
Floor (long put)	$2.45	$2.42
Floor (short put)	$2.00	$2.00
Collar contracts (two-way collars)
Total volume (MMBtu)	1,525,000	9,550,000
Weighted average price per MMBtu
Ceiling (short call)	$3.25	$3.04
Floor (long put)	$2.67	$2.59
Short call contracts
Total volume (MMBtu)	2,013,000	7,300,000
Weighted average price per MMBtu	$3.50	$3.09

Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	4,421,000	16,425,000
Weighted average price per MMBtu	($0.91)	($0.42)

For the Remainder

For the Full Year

NGL contracts (OPIS Mont Belvieu Purity Ethane)

of 2020

of 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 $680.4 million, or $17.12 per fully diluted share, for the three months ended September 30, 2020, and adjusted income available to common stockholders of $25.6 million, or $0.64 per fully diluted share. The following tables reconcile the Company’s income (loss) available to common stockholders to adjusted income, and the Company’s net income (loss) to adjusted EBITDA:


	Three Months Ended
	September 30, 2020	June 30, 2020	September 30, 2019
	(In thousands, except per share data)
Income (loss) available to common stockholders	($680,384)	($1,564,731)	$47,180
(Gain) loss on derivative contracts	27,038	126,965	(21,809)
Gain (loss) on commodity derivative settlements, net	(5,540)	84,208	1,011
Non-cash stock-based compensation expense (benefit)	(94)	2,761	644
Impairment of evaluated oil and gas properties	684,956	1,276,518	—
Merger and integration expense	2,465	8,067	5,943
Other (income) expense	3,567	6,759	(175)

Tax effect on adjustments above(a)	(149,602)	(316,108)	3,021
Change in valuation allowance	143,152	377,645	—
Loss on redemption of preferred stock	—	—	8,304
Adjusted Income	$25,558	$2,084	$44,119
Adjusted Income per fully diluted common share	$0.64	$0.05	$1.93

Basic WASO(b)	39,746	39,707	22,831
Diluted WASO (GAAP)(b)	39,746	39,707	22,846
Effective of potentially dilutive instruments(b)	35	12	—
Adjusted Diluted WASO(b)	39,781	39,719	22,846

(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
	September 30, 2020	June 30, 2020	September 30, 2019
	(In thousands)
Net income (loss)	($680,384)	($1,564,731)	$55,834
(Gain) loss on derivative contracts	27,038	126,965	(21,809)
Gain (loss) on commodity derivative settlements, net	(5,540)	84,208	1,011
Non-cash stock-based compensation expense (benefit)	(94)	2,761	644
Impairment of evaluated oil and gas properties	684,956	1,276,518	—
Merger and integration expense	2,465	8,067	5,943
Other (income) expense	3,567	6,759	(161)
Income tax expense	—	51,251	17,902
Interest expense	24,683	22,682	739
Depreciation, depletion and amortization	114,201	138,930	57,235

Adjusted EBITDA	$170,892	$153,410	$117,338

Free Cash Flow. Free cash flow was $80.3 million for the three months ended September 30, 2020. Free cash flow is reconciled to operating cash flow in the following table:


	Three Months Ended
	September 30, 2020	June 30, 2020
	(In thousands)
Net cash provided by operating activities	$135,701	$97,801
Changes in working capital and other	14,473	40,078
Change in accrued hedge settlement	(5,993)	(14,480)
Cash interest expense	24,246	21,944
Merger and integration expense	2,465	8,067
Adjusted EBITDA	170,892	153,410
Less: Operational capital (accrual)	38,408	85,087
Less: Capitalized interest	20,675	20,924
Less: Interest expense	24,683	22,682
Less: Capitalized cash G&A	6,831	6,740
Free cash flow	$80,295	$17,977

Adjusted Discretionary Cash Flow. Operating cash flow was $135.7 million and adjusted discretionary cash flow was $151.2 million for the three months ended September 30, 2020. Adjusted discretionary cash flow is reconciled to operating cash flow in the following table:


	Three Months Ended
	September 30, 2020	June 30, 2020	September 30, 2019
	(In thousands)
Cash flows from operating activities:
Net income (loss)	($680,384)	($1,564,731)	$55,834
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	114,201	138,930	57,235
Impairment of evaluated oil and gas properties	684,956	1,276,518	—
Amortization of non-cash debt related items	437	738	739
Deferred income tax expense	—	51,251	17,902
(Gain) loss on derivative contracts	27,038	126,965	(21,809)
Cash (paid) received for commodity derivative settlements, net	453	98,688	1,011
(Gain) loss on sale of other property and equipment	—	—	(13)
Non-cash stock-based compensation expense (benefit)	(94)	2,761	644

Merger and integration expense	2,465	8,067	—
Other, net	2,099	3,521	—
Adjusted discretionary cash flow	$151,171	$142,708	$111,543
Changes in working capital	(12,990)	(36,839)	2,803
Payments to settle asset retirement obligations	—	—	(654)
Merger and integration expense	(2,465)	(8,067)	—
Payments to settle vested liability share-based awards	(15)	(1)	—
Net cash provided by operating activities	$135,701	$97,801	$113,692

Adjusted Total Revenue. Adjusted total revenue for the three months ended September 30, 2020 was $264.2 million and is reconciled to total operating revenues in the following table:


	Three Months Ended
	September 30, 2020	June 30, 2020	September 30, 2019
	(In thousands)
Operating Revenues
Oil	$231,654	$130,513	$148,210
Natural gas	15,034	12,242	7,168
Natural gas liquids	23,025	14,479	—
Total operating revenues (3)	$269,713	$157,234	$155,378
Gain (loss) on commodity derivative settlements, net	(5,540)	84,208	1,011
Adjusted total revenue	$264,173	$241,442	$156,389

(3) Excludes sales of purchased oil and gas

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and per share data)

(Unaudited)


	September 30, 2020	December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$10,500	$13,341
Accounts receivable, net	112,536	209,463
Fair value of derivatives	9,821	26,056
Other current assets	27,049	19,814
Total current assets	159,906	268,674
Oil and natural gas properties, full cost accounting method:
Evaluated properties	2,916,542	4,682,994
Unevaluated properties	1,758,132	1,986,124
Total oil and natural gas properties, net	4,674,674	6,669,118
Operating lease right-of-use assets	29,519	63,908
Other property and equipment, net	32,920	35,253
Deferred tax asset	—	115,720
Deferred financing costs	24,850	22,233

Other assets, net	15,472	19,932
Total assets	$4,937,341	$7,194,838
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$332,979	$490,442
Operating lease liabilities	19,458	42,858



Fair value of derivatives	34,950	71,197
Other current liabilities	30,013	47,750
Total current liabilities	417,400	652,247
Long-term debt	3,190,273	3,186,109
Operating lease liabilities	28,906	37,088
Asset retirement obligations	49,542	48,860

Fair value of derivatives	35,705	32,695
Other long-term liabilities	11,411	14,531
Total liabilities	3,733,237	3,971,530
Commitments and contingencies
Stockholders’ equity:

Common stock, $0.01 par value, 52,500,000 shares authorized; 39,749,985 and 39,659,001 shares outstanding, respectively(4)	397	3,966
Capital in excess of par value	3,210,991	3,198,076
Retained earnings (Accumulated deficit)	(2,007,284)	21,266
Total stockholders’ equity	1,204,104	3,223,308
Total liabilities and stockholders’ equity	$4,937,341	$7,194,838

(4) 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)

(Unaudited)


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Operating revenues:
Oil	$231,654	$148,210	$627,934	$450,036
Natural gas	15,034	7,168	33,305	25,441
Natural gas liquids	23,025	—	55,627	—
Sales of purchased oil and gas	20,313	—	21,469	—
Total operating revenues	290,026	155,378	738,335	475,477
Operating Expenses:
Lease operating	45,870	19,668	149,091	66,511
Production and ad valorem taxes	16,110	11,866	46,151	33,810
Gathering, transportation and processing	22,200	—	56,615	—
Cost of purchased oil and gas	21,282	—	22,450	—
Depreciation, depletion and amortization	114,201	56,130	384,594	179,275
General and administrative	8,224	9,388	26,573	34,729
Impairment of evaluated oil and gas properties	684,956	—	1,961,474	—
Merger and integration	2,465	5,943	26,362	5,943

Other operating	4,425	(161)	8,548	931
Total operating expenses	919,733	102,834	2,681,858	321,199
Income (Loss) From Operations	(629,707)	52,544	(1,943,523)	154,278

Other (Income) Expenses:
Interest expense, net of capitalized amounts	24,683	739	67,843	2,218
(Gain) loss on derivative contracts	27,038	(21,809)	(97,966)	31,415
Other (income) expense	(1,044)	(122)	(149)	(270)
Total other (income) expense	50,677	(21,192)	(30,272)	33,363

Income (Loss) Before Income Taxes	(680,384)	73,736	(1,913,251)	120,915
Income tax expense	—	(17,902)	(115,299)	(29,444)
Net Income (Loss)	(680,384)	55,834	(2,028,550)	91,471
Preferred stock dividends	—	(350)	—	(3,997)
Loss on redemption of preferred stock	—	(8,304)	—	(8,304)
Income (Loss) Available to Common Stockholders	($680,384)	$47,180	($2,028,550)	$79,170

Income (Loss) Available to Common Stockholders Per Common Share (4):
Basic	($17.12)	$2.07	($51.09)	$3.47
Diluted	($17.12)	$2.07	($51.09)	$3.47
Weighted Average Common Shares Outstanding (4):
Basic	39,746	22,831	39,707	22,805
Diluted	39,746	22,846	39,707	22,841

(4) 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 September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Cash flows from operating activities:
Net income (loss)	($680,384)	$55,834	($2,028,550)	$91,471
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	114,201	57,235	384,594	182,738
Impairment of evaluated oil and gas properties	684,956	—	1,961,474	—
Amortization of non-cash debt related items	437	739	1,582	2,218
Deferred income tax expense	—	17,902	115,299	29,444
(Gain) loss on derivative contracts	27,038	(20,798)	(97,966)	31,415
Cash (paid) received for commodity derivative settlements	453	—	101,754	(436)
Loss on sale of other property and equipment	—	(13)	—	36
Non-cash expense related to equity share-based awards	1,485	1,569	6,302	7,868
Change in the fair value of liability share-based awards	(1,579)	(925)	(6,607)	106
Payments to settle asset retirement obligations	—	(654)	—	(1,425)
Payments for cash-settled restricted stock unit awards	(15)	—	(770)	(1,425)
Other, net	2,099	—	6,510	—
Changes in current assets and liabilities:
Accounts receivable	(16,930)	(21,081)	96,110	17,600
Other current assets	(2,208)	929	(6,556)	(5,172)
Current liabilities	6,148	23,216	(107,979)	(13,038)
Other	—	(261)	—	(2,662)
Net cash provided by operating activities	135,701	113,692	425,197	338,738
Cash flows from investing activities:
Capital expenditures	(137,177)	(143,995)	(567,746)	(503,425)
Acquisitions	—	(1,418)	—	(40,788)
Proceeds from sale of assets	139,739	5,656	149,818	279,952
Cash paid for settlements of contingent consideration arrangements, net	—	—	(40,000)	—

Other, net	1,427	—	8,261	—
Net cash provided by (used in) investing activities	3,989	(139,757)	(449,667)	(264,261)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	312,000	221,000	5,087,500	581,000
Payments on senior secured revolving credit facility	(737,000)	(126,000)	(5,347,500)	(581,000)
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 warrants	23,909	—	23,909	—


Payment of preferred stock dividends	—	(350)	—	(3,997)
Payment of deferred financing costs	(301)	—	(6,312)	(31)
Tax withholdings related to restricted stock units	(107)	(316)	(495)	(2,174)
Redemption of preferred stock	—	(73,012)	—	(73,017)
Other, net	79	—	(203)	—
Net cash provided by (used in) financing activities	(136,690)	21,322	21,629	(79,219)
Net change in cash and cash equivalents	3,000	(4,743)	(2,841)	(4,742)
Balance, beginning of period	7,500	16,052	13,341	16,051
Balance, end of period	$10,500	$11,309	$10,500	$11,309

Non-GAAP Financial Measures

This news release refers to non-GAAP financial measures such as “Free Cash Flow,” “Adjusted Discretionary Cash Flow,” “Adjusted G&A,” “Full Cash G&A Costs,” “Adjusted Income,” “Adjusted EBITDA” and “Adjusted Total Revenue.” These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

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

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

•Adjusted general and administrative expense (“Adjusted G&A”) is a supplemental non-GAAP financial measure that excludes non-cash valuation adjustments related to incentive compensation plans. Callon believes that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table contained within this release details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.

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

•Adjusted Income available to common stockholders (“Adjusted Income”) and Adjusted Income per fully diluted common share are supplemental non-GAAP measures that Callon believes are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of these items and non-cash valuation adjustments, which are detailed in the reconciliation provided.

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

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

•Callon believes that the non-GAAP measure of Adjusted Total Revenue is useful to investors because it provides readers with a revenue value more comparable to other companies who engage in price risk management activities through the use of

commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues.

About Callon Petroleum Company

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

This news release is posted on the Company’s website at www.callon.com and will be archived there for subsequent review under the “News” link on the top of the homepage.

Cautionary Statement Regarding Forward-Looking Information

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding the Company’s wells anticipated to be drilled and placed on production; future levels of drilling activity and associated production and cash flow expectations; the Company’s production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; anticipated returns and financial position; and the implementation of the Company’s business plans and strategy, as well as statements including the words “believe,” “expect,” “may,” "will,” "forecast,” “outlook,” “plans” and words of similar meaning. These statements reflect the Company’s current views with respect to future events and financial performance based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. No assurances can be given, however, as of this date, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil, natural gas and natural gas liquids (“NGLs”) prices or a prolonged period of low oil, natural gas or NGLs prices and the effects of actions by, or disputes among or between significant oil and natural gas producing countries, general economic conditions, including the availability of credit and access to existing lines of credit; the effects of excess supply of oil and natural gas resulting from reduced demand caused by the COVID-19 pandemic and the actions of certain oil and natural gas producing countries; our ability to drill and complete wells; operational, regulatory and environment risks; cost and availability of equipment and labor; our ability to finance our activities; the ultimate timing, outcome and results of integrating the operations of Carrizo Oil & Gas, Inc. and Callon; and the ability of the combined company to realize anticipated synergies and other benefits in the timeframe expected or at all; and other risks more fully discussed in our filings with the Securities and Exchange Commission (the “SEC”), including our most recent Annual Report on Form 10-K and subsequent Quarterly Reports on Form 10-Q, available on our website or the SEC’s website at www.sec.gov.

Contact Information

Mark Brewer

Director of Investor Relations

Callon Petroleum Company

ir@callon.com

(281) 589-5200

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