Callon Petroleum Company Announces First Quarter 2021 Results
Callon Petroleum Company (CPE) reported Q1 2021 results with production of 81.0 MBoe/d (64% oil) and net cash from operations of $137.7 million.
Despite a net loss of $80.4 million driven by derivative losses of $214.5 million, adjusted EBITDA was $170.6 million and adjusted income was $70.0 million.
Operating margins increased by 58% to $33.46 per Boe. The company expects production to rise to 88.0-89.5 MBoe/d in Q2 and reaffirmed capital spending of $135-$145 million.
- Production of 81.0 MBoe/d (64% oil) for Q1 2021.
- Adjusted EBITDA increased to $170.6 million.
- Operating margin rose by 58% to $33.46 per Boe.
- Generated adjusted free cash flow of $24.2 million.
- Net loss of $80.4 million, primarily due to a $214.5 million loss on derivative contracts.
- Average daily production decreased from 94.9 MBoe/d in Q4 2020.
HOUSTON, May 5, 2021 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months ended March 31, 2021.
Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located on the "Presentations" page within the Investors section of the site.
First Quarter 2021 and Recent Highlights
- Delivered production of approximately 81.0 MBoe/d (
64% oil) in the first quarter of 2021 - Generated net cash provided by operating activities of
$137.7 million and adjusted free cash flow1 of$24.2 million - Net loss of
$80.4 million , or$1.89 per diluted share, driven primarily by a loss on derivative contracts of$214.5 million , adjusted EBITDA1 of$170.6 million , and adjusted income1 of$70.0 million , or$1.49 per diluted share - Achieved an operating margin of
$33.46 per Boe, a58% increase from the previous quarter - Entered into purchase and sale agreements for certain non-core Delaware Basin properties for aggregate proceeds of approximately
$40 million - Completed the spring redetermination of Callon's senior secured credit facility with the borrowing base and elected commitment reaffirmed at
$1.6 billion with unanimous lender support - Executed Callon's first E-frac of a multi-well, multi-zone pad in the Midland Basin powered by field-produced natural gas
Joe Gatto, President and Chief Executive Officer commented, "The first quarter showcased our team's highly efficient resource development model and operating cost management, underpinned by consistent well performance from our multi-zone, life of field development program. We continued to generate positive free cash flow, even with the effects of the extreme winter weather significantly impacting our production for the quarter. In addition to further reducing the outstanding balance on our credit facility, we recently entered into purchase and sale agreements for non-core Western Delaware Basin acreage for estimated proceeds of approximately
He continued, "We recently issued our annual meeting proxy statement which outlined the extensive realignment of both our short and long-term compensation programs with critical elements of sustainability and corporate level returns. In addition, we outlined a targeted
Sale of Delaware Basin Assets
During April, Callon executed purchase and sale agreements covering certain non-core assets in the Delaware Basin. Aggregate proceeds for the combined transactions are approximately
Credit Facility and Liquidity
Callon recently completed the spring redetermination for its senior secured credit facility. The borrowing base and elected commitment were both reaffirmed at
Operations Update
At March 31, 2021, Callon had 1,510 gross (1,333.9 net) wells producing from established flow units in the Permian and Eagle Ford. Net daily production for the three months ended March 31, 2021 was 81.0 MBoe/d (
For the three months ended March 31, 2021, Callon drilled 18 gross (16.4 net) wells and placed a combined 14 gross (13.3 net) wells on production. Wells placed on production during the quarter were completed in the Eagle Ford in South Texas and the Wolfcamp A, B, and C in the Delaware Basin. The Company expects to operate an average of three drilling rigs throughout the remainder of 2021 and will average just over two completion crews through the second quarter before reducing to one completion crew during the third quarter.
During the first quarter, Callon focused early completion activity on the Eagle Ford with ten gross wells completed and placed on production during the quarter, including the Gardendale four-well pad which averaged more than 12,000 feet per lateral. Towards the end of the quarter, the Company initiated its first completion utilizing an all-electric frac fleet. In total, the project deployed more than 160 completion stages across three wells targeting the Lower Spraberry, Wolfcamp A, and Wolfcamp B in the Midland Basin. The fleet was powered using field-produced natural gas from Callon's local gathering system, resulting in the avoidance of more than 270,000 gallons of diesel fuel usage.
Capital Expenditures
For the three months ended March 31, 2021, Callon incurred
Three Months Ended March 31, 2021 | ||||||||||||
Operational | Capitalized | Capitalized | Total Capital | |||||||||
Capital (a) | Interest | G&A | Expenditures | |||||||||
(In thousands) | ||||||||||||
Cash basis (b) | ||||||||||||
Timing adjustments (c) | 19,331 | 9,018 | — | 28,349 | ||||||||
Non-cash items | (5,416) | 2,222 | 4,308 | 1,114 | ||||||||
Accrual basis | ||||||||||||
(a) | Includes drilling, completions, facilities, and equipment, but excludes land and seismic. |
(b) | Cash basis is presented here to help users of financial information reconcile amounts from the cash flow statement to the balance sheet by accounting for timing related changes in working capital that align with our development pace and rig count. |
(c) | Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period. |
Guidance
For the second quarter, including the impact of the pending divestitures expected to close by early June, the Company expects to produce between 88.0 and 89.5 MBoe per day (
Full Year 2021 Guidance | ||||
Prior | Pending | |||
Total production (MBoe/d) | 90.0 - 92.0 | 89.0 - 91.0 | ||
Oil | ||||
NGL | ||||
Natural gas | ||||
Income statement expenses (in millions except where noted) | ||||
LOE, including workovers | ||||
Gathering, transportation and processing | ||||
Production and ad valorem taxes (% of total oil, natural gas and NGL revenues) | ||||
Adjusted G&A: cash component (a) | ||||
Adjusted G&A: non-cash component (b) | ||||
Cash interest expense, net | ||||
Estimated effective income tax rate | ||||
Capital expenditures (in millions, accrual basis) | ||||
Total operational capital (c) | ||||
Capitalized interest(d) | ||||
Capitalized G&A | ||||
Gross operated wells drilled / completed | 55 - 65 / 90 - 100 | 55 - 65 / 90 - 100 | ||
(a) | Excludes the change in fair value and amortization of share-based incentive awards and other non-recurring expenses. |
(b) | Amortization of equity-settled, share-based incentive awards and other non-recurring expenses. |
(c) | Includes drilling, completions, facilities, and equipment, but excludes land, seismic, and capitalized expenses. |
(d) | Capitalized interest includes both cash and non-cash capitalized items. |
Hedge Portfolio Summary
As of April 30, 2021, Callon had the following outstanding oil, natural gas and NGL derivative contracts:
For the Remainder | For the Full Year | |||||
Oil contracts (WTI) | of 2021(a) | of 2022(a) | ||||
Swap contracts | ||||||
Total volume (Bbls) | 1,832,000 | 225,000 | ||||
Weighted average price per Bbl | ||||||
Collar contracts | ||||||
Total volume (Bbls) | 8,298,800 | 2,032,500 | ||||
Weighted average price per Bbl | ||||||
Ceiling (short call) | ||||||
Floor (long put) | ||||||
Short call contracts | ||||||
Total volume (Bbls) | 2,432,480 | (b) | — | |||
Weighted average price per Bbl | $— | |||||
Short call swaption contracts | ||||||
Total volume (Bbls) | — | 1,825,000 | (c) | |||
Weighted average price per Bbl | $— | |||||
Oil contracts (Brent ICE) | ||||||
Swap contracts | ||||||
Total volume (Bbls) | 221,300 | (d) | — | |||
Weighted average price per Bbl | $— | |||||
Collar contracts | ||||||
Total volume (Bbls) | 550,000 | — | ||||
Weighted average price per Bbl | ||||||
Ceiling (short call) | $— | |||||
Floor (long put) | $— | |||||
Oil contracts (Midland basis differential) | ||||||
Swap contracts | ||||||
Total volume (Bbls) | 2,171,900 | — | ||||
Weighted average price per Bbl | $— | |||||
Oil contracts (Argus Houston MEH) | ||||||
Collar contracts | ||||||
Total volume (Bbls) | 409,500 | 452,500 | ||||
Weighted average price per Bbl | ||||||
Ceiling (short call) | ||||||
Floor (long put) | ||||||
_______________ | |
(a) | The Company has approximately |
(b) | Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. |
(c) | The short call swaption contracts have an exercise expiration date of December 31, 2021. |
(d) | In February 2021, the Company entered into certain offsetting ICE Brent swaps to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss of approximately |
For the Remainder | For the Full Year | |||||
Natural gas contracts (Henry Hub) | of 2021 | of 2022 | ||||
Swap contracts | ||||||
Total volume (MMBtu) | 11,123,000 | — | ||||
Weighted average price per MMBtu | $— | |||||
Collar contracts | ||||||
Total volume (MMBtu) | 5,500,000 | 2,700,000 | ||||
Weighted average price per MMBtu | ||||||
Ceiling (short call) | ||||||
Floor (long put) | ||||||
Short call contracts | ||||||
Total volume (MMBtu) | 5,500,000 | (a) | — | |||
Weighted average price per MMBtu | $— | |||||
Natural gas contracts (Waha basis differential) | ||||||
Swap contracts | ||||||
Total volume (MMBtu) | 12,375,000 | 5,475,000 | ||||
Weighted average price per MMBtu | ( | ( | ||||
___________ | |
(a) | Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. |
For the Remainder | For the Full Year | |||||
NGL contracts (OPIS Mont Belvieu Purity Ethane) | of 2021 | of 2022 | ||||
Swap contracts | ||||||
Total volume (Bbls) | 1,375,000 | — | ||||
Weighted average price per Bbl | $— | |||||
Operating and Financial Results
The following table presents summary information for the periods indicated:
Three Months Ended | |||||||||
March 31, 2021 | December 31, 2020 | March 31, 2020 | |||||||
Total production | |||||||||
Oil (MBbls) | |||||||||
Permian | 3,088 | 3,445 | 3,594 | ||||||
Eagle Ford | 1,593 | 1,980 | 2,253 | ||||||
Total oil (MBbls) | 4,681 | 5,425 | 5,847 | ||||||
Natural gas (MMcf) | |||||||||
Permian | 6,208 | 7,474 | 8,009 | ||||||
Eagle Ford | 1,627 | 2,264 | 1,784 | ||||||
Total natural gas (MMcf) | 7,835 | 9,738 | 9,793 | ||||||
NGLs (MBbls) | |||||||||
Permian | 1,075 | 1,331 | 1,368 | ||||||
Eagle Ford | 224 | 353 | 339 | ||||||
Total NGLs (MBbls) | 1,299 | 1,684 | 1,707 | ||||||
Total production (MBoe) | |||||||||
Permian | 5,198 | 6,022 | 6,297 | ||||||
Eagle Ford | 2,088 | 2,710 | 2,889 | ||||||
Total barrels of oil equivalent (MBoe) | 7,286 | 8,732 | 9,186 | ||||||
Total daily production (Boe/d) | |||||||||
Permian | 57,758 | 65,459 | 69,203 | ||||||
Eagle Ford | 23,199 | 29,455 | 31,752 | ||||||
Total barrels of oil equivalent (Boe/d) | 80,957 | 94,914 | 100,955 | ||||||
Oil as % of total daily production | 64 | % | 62 | % | 64 | % | |||
Average realized sales price (excluding impact of settled derivatives) | |||||||||
Oil (per Bbl) | |||||||||
Permian | |||||||||
Eagle Ford | 57.80 | 41.12 | 45.21 | ||||||
Total oil (per Bbl) | |||||||||
Natural gas (per Mcf) | |||||||||
Permian | |||||||||
Eagle Ford | 3.03 | 2.65 | 1.88 | ||||||
Total natural gas (per Mcf) | |||||||||
NGLs (per Bbl) | |||||||||
Permian | |||||||||
Eagle Ford | 22.24 | 16.16 | 9.00 | ||||||
Total NGLs (per Bbl) | |||||||||
Average realized sales price (per Boe) | |||||||||
Permian | |||||||||
Eagle Ford | 48.85 | 34.36 | 37.48 | ||||||
Total average realized sales price (per Boe) | |||||||||
Average realized sales price (including impact of settled derivatives) | |||||||||
Oil (per Bbl) | |||||||||
Natural gas (per Mcf) | 2.88 | 1.89 | 1.13 | ||||||
NGLs (per Bbl) | 21.77 | 15.24 | 10.62 | ||||||
Total average realized sales price (per Boe) | |||||||||
Three Months Ended | |||||||||
March 31, 2021 | December 31, 2020 | March 31, 2020 | |||||||
Revenues (in thousands)(a) | |||||||||
Oil | |||||||||
Permian | |||||||||
Eagle Ford | 92,078 | 81,413 | 101,861 | ||||||
Total oil | |||||||||
Natural gas | |||||||||
Permian | |||||||||
Eagle Ford | 4,930 | 6,001 | 3,354 | ||||||
Total natural gas | |||||||||
NGLs | |||||||||
Permian | |||||||||
Eagle Ford | 4,981 | 5,704 | 3,051 | ||||||
Total NGLs | |||||||||
Total revenues | |||||||||
Permian | |||||||||
Eagle Ford | 101,989 | 93,118 | 108,266 | ||||||
Total revenues | |||||||||
Additional per Boe data | |||||||||
Sales price (b) | |||||||||
Permian | |||||||||
Eagle Ford | 48.85 | 34.36 | 37.48 | ||||||
Total sales price | |||||||||
Lease operating | |||||||||
Permian | |||||||||
Eagle Ford | 8.65 | 6.77 | 7.24 | ||||||
Total lease operating | |||||||||
Production and ad valorem taxes | |||||||||
Permian | |||||||||
Eagle Ford | 3.07 | 2.29 | 2.47 | ||||||
Total production and ad valorem taxes | |||||||||
Gathering, transportation and processing | |||||||||
Permian | |||||||||
Eagle Ford | 2.29 | 2.25 | 0.89 | ||||||
Total gathering, transportation and processing | |||||||||
Operating margin | |||||||||
Permian | |||||||||
Eagle Ford | 34.84 | 23.05 | 26.88 | ||||||
Total operating margin | |||||||||
Depreciation, depletion and amortization | |||||||||
General and administrative | |||||||||
Adjusted G&A 1 | |||||||||
Cash component (c) | |||||||||
Non-cash component | |||||||||
(a) | Excludes sales of oil and gas purchased from third parties. |
(b) | Excludes the impact of settled derivatives. |
(c) | Excludes the change in fair value and amortization of share-based incentive awards and other non-recurring expenses. |
Revenue. For the quarter ended March 31, 2021, Callon reported revenue of
Commodity Derivatives. For the quarter ended March 31, 2021, the net loss on commodity derivative contracts includes the following (in thousands):
Three Months Ended | ||
Loss on oil derivatives | ||
Loss on natural gas derivatives | 2,697 | |
Loss on NGL derivatives | 1,138 | |
Loss on commodity derivative contracts | ||
For the quarter ended March 31, 2021, the cash paid for commodity derivative settlements includes the following (in thousands):
Three Months Ended | ||
Cash paid on oil derivatives | ( | |
Cash paid on natural gas derivatives | (1,369) | |
Cash paid on NGL derivatives | (846) | |
Cash paid for commodity derivative settlements, net | ( | |
Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended March 31, 2021 was
Production and Ad Valorem Taxes. Production and ad valorem taxes were
Gathering, Transportation and Processing. Gathering, transportation and processing for the three months ended March 31, 2021 was
Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended March 31, 2021 was
General and Administrative Expense ("G&A"). G&A for the three months ended March 31, 2021 and December 31, 2020 was
The following table reconciles total G&A to Adjusted G&A - cash component and full cash G&A (in thousands):
Three Months Ended | |||||
March 31, 2021 | December 31, 2020 | ||||
Total G&A | |||||
Change in the fair value of liability share-based awards (non-cash) | (5,943) | (2,500) | |||
Adjusted G&A – total | 10,856 | 8,114 | |||
Equity-settled, share-based compensation (non-cash) and other non-recurring expenses | (1,665) | (580) | |||
Adjusted G&A – cash component | |||||
Capitalized cash G&A | |||||
Full cash G&A | |||||
Income Tax. Callon provides for income taxes at the statutory rate of
Adjusted EBITDA. Adjusted EBITDA for the first quarter of 2021 was
Adjusted Income and Adjusted EBITDA. The Company reported net loss of
Three Months Ended | ||||||||
March 31, 2021 | December 31, 2020 | March 31, 2020 | ||||||
(In thousands, except per share data) | ||||||||
Net income (loss) | ( | ( | ||||||
(Gain) loss on derivative contracts | 214,523 | 125,739 | (251,969) | |||||
Gain (loss) on commodity derivative settlements, net | (62,280) | (7,938) | 25,126 | |||||
Non-cash stock-based compensation expense (benefit) | 7,608 | 2,968 | (2,972) | |||||
Impairment of evaluated oil and gas properties | — | 585,767 | — | |||||
Merger and integration expense | — | 2,120 | 15,830 | |||||
Other (income) expense | (3,306) | 5,328 | (1,029) | |||||
Gain on extinguishment of debt | — | (170,370) | — | |||||
Tax effect on adjustments above(a) | (32,874) | (114,159) | 45,153 | |||||
Change in valuation allowance | 26,724 | 118,388 | — | |||||
Adjusted income | ||||||||
Adjusted income per diluted share | ||||||||
Basic WASO(b) | 42,590 | 39,752 | 39,667 | |||||
Diluted WASO (GAAP)(b) | 42,590 | 39,752 | 39,684 | |||||
Effect of potentially dilutive instruments(b) | 4,354 | 2,892 | — | |||||
Adjusted Diluted WASO(b) | 46,944 | 42,644 | 39,684 | |||||
(a) | Calculated using the federal statutory rate of |
(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 | ||||||||
March 31, 2021 | December 31, 2020 | March 31, 2020 | ||||||
(In thousands) | ||||||||
Net income (loss) | ( | ( | ||||||
(Gain) loss on derivative contracts | 214,523 | 125,739 | (251,969) | |||||
Gain (loss) on commodity derivative settlements, net | (62,280) | (7,938) | 25,126 | |||||
Non-cash stock-based compensation expense (benefit) | 7,608 | 2,968 | (2,972) | |||||
Impairment of evaluated oil and gas properties | — | 585,767 | — | |||||
Merger and integration expense | — | 2,120 | 15,830 | |||||
Other (income) expense | (3,306) | 5,328 | (1,029) | |||||
Income tax (benefit) expense | (921) | 6,755 | 64,048 | |||||
Interest expense | 24,416 | 26,486 | 20,478 | |||||
Depreciation, depletion and amortization | 70,987 | 96,037 | 131,463 | |||||
Gain on extinguishment of debt | — | (170,370) | — | |||||
Adjusted EBITDA | ||||||||
Adjusted Free Cash Flow. Adjusted free cash flow for the three months ended March 31, 2021 was
Three Months Ended | ||||||||
March 31, 2021 | December 31, 2020 | March 31, 2020 | ||||||
(In thousands) | ||||||||
Net cash provided by operating activities | ||||||||
Changes in working capital and other | 30,913 | 12,011 | (32,569) | |||||
Change in accrued hedge settlements | (20,117) | (5,055) | 22,513 | |||||
Cash interest expense, net | 22,159 | 24,167 | 20,071 | |||||
Merger and integration expense | — | 2,120 | 15,830 | |||||
Adjusted EBITDA | 170,620 | 167,821 | 217,540 | |||||
Less: Operational capital expenditures (accrual) | 95,545 | 87,488 | 277,640 | |||||
Less: Capitalized interest | 21,817 | 23,015 | 23,985 | |||||
Less: Interest expense, net of capitalized amounts | 22,159 | 26,486 | 20,478 | |||||
Less: Capitalized cash G&A | 6,913 | 6,465 | 7,371 | |||||
Adjusted free cash flow (a) | ( | |||||||
(a) | Effective January 1, 2021, non-cash interest expense amounts consisting primarily of amortization of debt issuance costs, premiums, and discounts associated with our long-term debt are excluded from our calculation of adjusted free cash flow. |
Adjusted Discretionary Cash Flow. For the three months ended March 31, 2021, net cash provided by operating activities was
Three Months Ended | ||||||||
March 31, 2021 | December 31, 2020 | March 31, 2020 | ||||||
(In thousands) | ||||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | ( | ( | ||||||
Adjustments to reconcile net income (loss) to cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 70,987 | 96,037 | 131,463 | |||||
Impairment of evaluated oil and gas properties | — | 585,767 | — | |||||
Amortization of non-cash debt related items | 2,256 | 2,319 | 407 | |||||
Deferred income tax expense | — | 3,308 | 64,048 | |||||
(Gain) loss on derivative contracts | 214,523 | 125,739 | (251,969) | |||||
Cash (paid) received for commodity derivative settlements, net | (42,162) | (2,884) | 2,613 | |||||
Non-cash stock-based compensation expense (benefit) | 7,608 | 2,968 | (2,972) | |||||
Non-cash loss on early extinguishment of debt | — | (170,370) | — | |||||
Merger and integration expense | — | 2,120 | 15,830 | |||||
Other, net | 1,217 | 1,347 | 890 | |||||
Adjusted discretionary cash flow | ||||||||
Changes in working capital | (36,357) | (4,582) | 30,650 | |||||
Merger and integration expense | — | (2,120) | (15,830) | |||||
Net cash provided by operating activities | ||||||||
Adjusted Total Revenue. Adjusted total revenue for the three months ended March 31, 2021 was
Three Months Ended | |||||||||
March 31, 2021 | December 31, 2020 | March 31, 2020 | |||||||
(In thousands) | |||||||||
Operating revenues | |||||||||
Oil | |||||||||
Natural gas | 24,220 | 18,561 | 6,029 | ||||||
NGLs | 29,357 | 25,668 | 18,123 | ||||||
Total operating revenues | |||||||||
Impact of settled derivatives | (62,280) | (7,938) | 25,126 | ||||||
Adjusted total revenue | |||||||||
Callon Petroleum Company | ||||||
Consolidated Balance Sheets | ||||||
(In thousands, except par and per share data) | ||||||
(Unaudited) | ||||||
March 31, 2021 | December 31, 2020 | |||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | ||||||
Accounts receivable, net | 179,127 | 133,109 | ||||
Other current assets | 32,878 | 25,024 | ||||
Total current assets | 236,355 | 178,369 | ||||
Oil and natural gas properties, full cost accounting method: | ||||||
Evaluated properties, net | 2,394,339 | 2,355,710 | ||||
Unevaluated properties | 1,754,768 | 1,733,250 | ||||
Total oil and natural gas properties, net | 4,149,107 | 4,088,960 | ||||
Other property and equipment, net | 31,435 | 31,640 | ||||
Deferred financing costs | 22,177 | 23,643 | ||||
Other assets, net | 37,792 | 40,256 | ||||
Total assets | ||||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable and accrued liabilities | ||||||
Fair value of derivatives | 224,446 | 97,060 | ||||
Other current liabilities | 72,854 | 58,529 | ||||
Total current liabilities | 672,049 | 497,108 | ||||
Long-term debt | 2,937,239 | 2,969,264 | ||||
Asset retirement obligations | 55,935 | 57,209 | ||||
Fair value of derivatives | 1,400 | 88,046 | ||||
Other long-term liabilities | 42,221 | 40,239 | ||||
Total liabilities | 3,708,844 | 3,651,866 | ||||
Commitments and contingencies | ||||||
Stockholders' equity: | ||||||
Common stock, | 462 | 398 | ||||
Capital in excess of par value | 3,360,322 | 3,222,959 | ||||
Accumulated deficit | (2,592,762) | (2,512,355) | ||||
Total stockholders' equity | 768,022 | 711,002 | ||||
Total liabilities and stockholders' equity | ||||||
Callon Petroleum Company | |||||
Consolidated Statements of Operations | |||||
(In thousands, except per share data) | |||||
(Unaudited) | |||||
Three Months Ended | |||||
2021 | 2020 | ||||
Operating Revenues: | |||||
Oil | |||||
Natural gas | 24,220 | 6,029 | |||
Natural gas liquids | 29,357 | 18,123 | |||
Sales of purchased oil and gas | 39,259 | — | |||
Total operating revenues | 359,881 | 289,919 | |||
Operating Expenses: | |||||
Lease operating | 40,453 | 52,383 | |||
Production and ad valorem taxes | 18,439 | 19,680 | |||
Gathering, transportation and processing | 17,981 | 14,378 | |||
Cost of purchased oil and gas | 40,917 | — | |||
Depreciation, depletion and amortization | 70,987 | 131,463 | |||
General and administrative | 16,799 | 8,325 | |||
Merger and integration | — | 15,830 | |||
Other operating | 929 | — | |||
Total operating expenses | 206,505 | 242,059 | |||
Income From Operations | 153,376 | 47,860 | |||
Other (Income) Expenses: | |||||
Interest expense, net of capitalized amounts | 24,416 | 20,478 | |||
(Gain) loss on derivative contracts | 214,523 | (251,969) | |||
Other (income) expense | (4,235) | (1,262) | |||
Total other (income) expense | 234,704 | (232,753) | |||
Income (Loss) Before Income Taxes | (81,328) | 280,613 | |||
Income tax benefit (expense) | 921 | (64,048) | |||
Net Income (Loss) | (80,407) | 216,565 | |||
Net Income (Loss) Per Common Share (a): | |||||
Basic | ( | ||||
Diluted | ( | ||||
Weighted Average Common Shares Outstanding (a): | |||||
Basic | 42,590 | 39,667 | |||
Diluted | 42,590 | 39,684 | |||
_______________ | |
(a) | All share and per share amounts have been retroactively adjusted for the Company's 1-for-10 reverse stock split effective August 7, 2020. |
Callon Petroleum Company | |||||
Consolidated Statements of Cash Flows | |||||
(In thousands) | |||||
(Unaudited) | |||||
Three Months Ended | |||||
2021 | 2020 | ||||
Cash flows from operating activities: | |||||
Net income (loss) | ( | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||
Depreciation, depletion and amortization | 70,987 | 131,463 | |||
Amortization of non-cash debt related items, net | 2,256 | 407 | |||
Deferred income tax expense | — | 64,048 | |||
(Gain) loss on derivative contracts | 214,523 | (251,969) | |||
Cash received (paid) for commodity derivative settlements, net | (42,162) | 2,613 | |||
Non-cash expense related to share-based awards | 7,608 | (2,972) | |||
Other, net | 1,217 | 136 | |||
Changes in current assets and liabilities: | |||||
Accounts receivable | (45,683) | 115,873 | |||
Other current assets | (2,856) | (781) | |||
Accounts payable and accrued liabilities | 12,182 | (83,688) | |||
Net cash provided by operating activities | 137,665 | 191,695 | |||
Cash flows from investing activities: | |||||
Capital expenditures | (101,341) | (213,459) | |||
Acquisition of oil and gas properties | (768) | (10,989) | |||
Proceeds from sale of assets | — | 10,240 | |||
Cash paid for settlements of contingent consideration arrangements, net | — | (40,000) | |||
Other, net | 3,595 | (158) | |||
Net cash used in investing activities | (98,514) | (254,366) | |||
Cash flows from financing activities: | |||||
Borrowings on Credit Facility | 303,000 | 4,291,000 | |||
Payments on Credit Facility | (338,000) | (4,226,000) | |||
Other, net | (37) | (870) | |||
Net cash provided by (used in) financing activities | (35,037) | 64,130 | |||
Net change in cash and cash equivalents | 4,114 | 1,459 | |||
Balance, beginning of period | 20,236 | 13,341 | |||
Balance, end of period | |||||
Non-GAAP Financial Measures
This news release refers to non-GAAP financial measures such as "adjusted free cash flow," "adjusted discretionary cash flow," "adjusted G&A," "full cash G&A," "adjusted income," "adjusted income per diluted share," "adjusted EBITDA," and "adjusted total revenue." These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our filings with the U.S. Securities and Exchange Commission (the "SEC") and posted on our website.
- Adjusted free cash flow is a supplemental non-GAAP measure that is defined by the Company as adjusted EBITDA less operational capital, cash capitalized interest, net cash interest expense and capitalized cash G&A (which excludes capitalized expense related to share-based awards). We believe adjusted free cash flow is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company's ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted free cash flow is not a measure of a company's financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).
- Adjusted discretionary cash flow is a supplemental non-GAAP measure that Callon believes is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company's ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and merger and integration expenses. Callon has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the Company may not control and the cash flow effect may not be reflected the period in which the operating activities occurred. Adjusted discretionary cash flow is not a measure of a company's financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).
- Adjusted G&A is a supplemental non-GAAP financial measure that excludes certain non-cash incentive share-based compensation valuation adjustments. Callon believes that the non-GAAP measure of adjusted G&A is useful to investors because it provides a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period.
- Full cash G&A is a supplemental non-GAAP financial measure that Callon defines as adjusted G&A – cash component plus capitalized G&A excluding capitalized expense related to share-based awards. Callon believes that the non-GAAP measure of full cash G&A is useful because it provides users with a meaningful measure of our total recurring cash G&A costs, whether expensed or capitalized, and provides for greater comparability on a period-over-period basis.
- Adjusted income and adjusted income per diluted share are supplemental non-GAAP measures that Callon believes are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of these items and non-cash valuation adjustments, which are detailed in the reconciliation provided. Adjusted income and adjusted income per diluted share are not measures of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), or other income data prepared in accordance with GAAP. However, the Company believes that adjusted income and adjusted income per diluted share provide additional information with respect to our performance. Because adjusted income and adjusted income per diluted share exclude some, but not all, items that affect net income (loss) and may vary among companies, the adjusted income and adjusted income per diluted share presented above may not be comparable to similarly titled measures of other companies.
- Adjusted diluted weighted average common shares outstanding ("Adjusted Diluted WASO") is a non-GAAP financial measure which includes the effect of potentially dilutive instruments that, under certain circumstances described below, are excluded from diluted weighted average common shares outstanding ("Diluted WASO"), the most directly comparable GAAP financial measure. When a net loss exists, all potentially dilutive instruments are anti-dilutive to the net loss per common share and therefore excluded from the computation of Diluted WASO. The effect of potentially dilutive instruments are included in the computation of Adjusted Diluted WASO for purposes of computing adjusted income per diluted share.
- Callon calculates adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of evaluated oil and gas properties, non-cash stock-based compensation expense, merger and integration expense, (gain) loss on extinguishment of debt, and other operating expenses. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, the Company believes that adjusted EBITDA provides additional information with respect to our performance or ability to meet our future debt service, capital expenditures and working capital requirements. Because adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted EBITDA presented above may not be comparable to similarly titled measures of other companies.
- Callon believes that the non-GAAP measure of adjusted total revenue (which is revenue including the gain or loss from the settlement of derivative contracts) is useful to investors because it provides readers with a revenue value more comparable to other companies who engage in price risk management activities through the use of commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues. See the reconciliation provided above for further details.
Earnings Call Information
The Company will host a conference call on Thursday, May 6, 2021, to discuss first quarter 2021 financial and operating results, 2021 outlook, and current corporate strategy and initiatives.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: | Thursday, May 6, 2021, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time) |
Webcast: | Select "News and Events" under the "Investors" section of the Company's website: www.callon.com. |
An archive of the conference call webcast will also be available at www.callon.com under the "Investors" section of the website.
About Callon Petroleum Company
Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas.
Cautionary Statement Regarding Forward-Looking Information
This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of development activity and associated production, capital expenditures and cash flow expectations; the Company's 2021 production expense guidance and capital expenditure guidance; estimated reserve quantities and the present value thereof; and the implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," "plans," "may," "will," "should," "could," and words of similar meaning. These statements reflect the Company's current views with respect to future events and financial performance based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices; changes in the supply of and demand for oil and natural gas, including as a result of the COVID-19 pandemic and various governmental actions taken to mitigate its impact or actions by, or disputes among members of OPEC and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil; our ability to drill and complete wells; operational, regulatory and environment risks; the cost and availability of equipment and labor; our ability to finance our activities; and other risks more fully discussed in our filings with the SEC, including our most recent Annual Reports on Form 10-K and subsequent Quarterly Reports on Form 10-Q, available on our website or the SEC's website at www.sec.gov.
Contact Information
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
(281) 589-5200
1) See "Non-GAAP Financial Measures" included within this release for related disclosures. |
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SOURCE Callon Petroleum Company
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