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HOUSTON, Nov. 2, 2020 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and nine months ended September30, 2020. Presentation slides accompanying this earnings release are available on the Company's website at www.callon.comlocated 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 SeniorNotes (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 September30, 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 September30, 2020 grew 170% to 102.0 Mboe/d (63% oil), as compared to the same period of 2019. For the three months ended September30, 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 September30, 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 September30, 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 September30, 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 September30, 2020, the cash (paid) received for commodity derivative settlements includes the following (in thousands): Three Months EndedSeptember 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 September30, 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 September30, 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 September30, 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 September30, 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 September30, 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 September30, 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 September30, 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 September30, 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 September30, 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 September30, 2020 and June30, 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 of21% 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 September30, 2020, compared to income tax expense of $51.3 million for the three months ended June30, 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 September30, 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 September30, 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 September30, 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 September30, 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 EndedSeptember 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 EndedSeptember 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.comand 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 BrewerDirector of Investor RelationsCallon Petroleum Company[emailprotected](281) 589-5200 1)See "Non-GAAP Financial Measures and Reconciliations" included within this release for related disclosures and calculations. SOURCE Callon Petroleum Company Related Links www.callon.com

Answer: Callon Petroleum Company Announces Third Quarter 2020 Results